UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
FORM 10-K
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
- ---- EXCHANGE ACT OF 1934
For the fiscal year ended June 30, 1997
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from _______________ to _______________
COMMISSION FILE NUMBER 0-14183
ENERGY WEST INCORPORATED
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(Exact name of registrant as specified in its charter)
Montana 81-0141785
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(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
1 First Avenue South, Great Falls, Mt. 59401
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(Address of principal executive (Zip Code)
offices)
Registrant's telephone number, including area code (406)-791-7500
Securities registered pursuant to Section 12(b) of the Act:
Title of each class Name of Exchange on which registered
Common Stock - Par Value $.15 NASDAQ
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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 (or for such shorter period that the registrant
was required to file such reports), 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 (229.45 of this chapter) 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].
The aggregate market value of the voting stock held by non-affiliates of the
registrant as of September 3, 1997: Common Stock, $.15 Par Value -
$12,920,951
The number of shares outstanding of the issuer's classes of common stock as of
September 3, 1997: Common Stock, $.15 Par Value - 2,362,516 shares
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the proxy statement for the annual shareholders meeting to be held
November 20, 1997 are incorporated by reference into Part III.
1
PART I
Item 1. - Business
ENERGY WEST INCORPORATED ("the Company") is a regulated public utility,
with certain non-utility operations conducted through its subsidiaries. The
Company's regulated utility operations primarily involve the distribution and
sale of natural gas to the public in the Great Falls, Montana and Cody, Wyoming
areas. Since January 1993, the Company's regulated utility operations have also
included the distribution of propane to the public through an underground
propane vapor system in the Payson, Arizona area, and since 1995, the
distribution of natural gas through an underground system in West Yellowstone,
Montana, that is supplied by liquified natural gas ("LNG").
The Company conducts certain non-regulated non-utility operations through
its three wholly-owned subsidiaries, Rocky Mountain Fuels, Inc. ("RMF"), Energy
West Resources, Inc. ("EWR"), and Montana Sun, Inc. ("Montana Sun"). RMF is
engaged in the distribution of bulk propane in Northwestern Wyoming, the Payson,
Arizona area and the Cascade, Montana area. EWR is involved in gas storage and
the marketing of gas in Montana. Montana Sun owns two real estate properties in
Great Falls, Montana.
UTILITY OPERATIONS
The Company's primary business is the distribution and sale of natural gas
and propane to residential, commercial and industrial customers. The natural
gas distribution operations consist of two divisions, the Great Falls division
and the Cody division. The Cody division is also involved in the transportation
of natural gas. In addition, since January 1993 the Company has been involved
in the regulated distribution of propane in Arizona through the Broken Bow
division. Generally, residential customers use natural gas and propane for
space heating and water heating, commercial customers use natural gas and
propane for space heating and cooking, and industrial customers use natural gas
as a fuel in industrial processing and space heating. The Company's revenues
from utility operations are generated under tariffs regulated by the respective
state utility commissions.
GREAT FALLS DIVISION
The Great Falls division provides natural gas service to Great Falls,
Montana and much of suburban Great Falls within approximately 11 miles of the
city limits. The service area has a population base of approximately 65,000.
The Company has a franchise to distribute natural gas within the city of Great
Falls. The franchise was renewed for 50 years by the city of Great Falls in
1971. As of June 30, 1996, the Great Falls division provided service to over
25,000 customers, including approximately 22,000 residential customers,
approximately 3,000 commercial customers, an oil refinery and Malmstrom Air
Force Base ("Malmstrom") through transportation agreements.
2
The following table shows the Great Falls division's revenues by customer class
for the year ended June 30, 1997 and the past two fiscal years:
Gas Revenues
(in thousands)
Years Ended June 30,
--------------------
1997 1996 1995
---- ---- ----
Residential................. $9,267 $8,648 $8,996
Commercial.................. 6,631 6,146 6,350
Malmstrom................... 0 0 1,393
Transportation.............. 431 468 73
----- ----- -----
$16,329 $15,262 $16,812
------- ------- -------
------- ------- -------
Total...............
The following table shows the volumes of natural gas, expressed in millions
of cubic feet ("MMcf") at 13.28 P.S.I.A., sold by the Great Falls division for
the year ended June 30, 1997 and the past two fiscal years:
Gas Volumes
(Mmcf)
Years Ended June 30,
--------------------
1997 1996 1995
---- ---- ----
Residential................. 2,614 2,540 2,297
Commercial.................. 1,881 1,822 1,646
Malmstrom.................... 0 0 464
----- ----- -----
4,495 4,362 4,407
----- ----- ------
----- ----- ------
Total Gas Sales.......
Transportation 1,171 1,294 714
----- ----- -----
----- ----- -----
Malmstrom, now a transportation customer, the Great Falls division's
largest customer, accounted for approximately 2% of the revenues of the
division. Including revenues received by EWR, Malmstrom accounted for
approximately 3% of the consolidated revenues of the Company in fiscal 1997. On
July 1, 1995, Malmstrom became a transport customer of the Great Falls division,
purchasing its gas load from EWR, a wholly-owned subsidiary of ENERGY WEST
INCORPORATED. The Great Falls division experienced no loss of margin in fiscal
1997 and 1996 as a result of this contract. Malmstrom purchases gas for space
heating and water heating for buildings and residential housing, to supplement
its coal-fired central heating system. Malmstrom, which is located near Great
Falls, is an air force base with several wings of intercontinental nuclear
missiles. The base employed approximately 4,400 military personnel and 550
civilian personnel as of June 30, 1997.
3
Beginning in three years, Malmstrom has been selected as the site where 13
of 15 test flight of NASA's X-33 space shuttle will land during 1999. No
assurance can be given as to the future level of activity at Malmstrom.
The Great Falls division's other transport customer is an oil refinery
located in the city. The Company provides gas to the customer for processing
use in its refining business. In fiscal 1997, the refinery accounted for less
than 1% of the consolidated revenues of the Company. Historically, this
customer's gas load has remained relatively constant during the year because the
gas is used in the customer's business and is therefore not weather-sensitive.
On June 1, 1993, the refinery became a transport customer of the Great Falls
division, purchasing its gas load from EWR, a wholly-owned subsidiary of ENERGY
WEST INCORPORATED. The Great Falls division has not experienced a loss of
margin as a result of this contract.
In July, 1996 it was announced that a $20 million pasta plant will be built
in Great Falls. Construction is now complete and it is estimated, that the pasta
plant will use approximately 60,000 Mcf/year of natural gas.
The Great Falls division's gas distribution operations are subject to
regulation by the Montana Public Service Commission ("MPSC"). The MPSC
regulates rates, adequacy of service, accounting, issuance of securities and
other matters.
In November, 1994, the Company filed for a rate increase to recover the
cost of increased operating expenses, increases in financing expenses due to
additional investments in utility plant, and other costs of doing business.
Included with the filing was a new surcharge to recover costs associated with
the environmental assessment and remediation of its service center, which was
formerly a manufactured gas plant site. The Montana Consumer Counsel ("MCC")
intervened in the rate case and in January, 1995, the Company and the MCC filed
a Joint Motion for Suspension of the Procedural Order, in order to allow both
parties to negotiate toward a stipulated settlement. On May 30, 1995, the MPSC
approved the revenue requirement stipulation executed between the Company and
the MCC as filed in March, 1995, which reduced base rates by $250,000 and
allowed a new surcharge associated with the manufactured gas plant site with an
initial balance of approximately $183,000, with the surcharge calculated on a
two-year recovery of the average annual basis. The effective date of the rate
decrease and surcharge was the beginning of fiscal 1996 or July 1, 1995. The
rate decrease reduces earnings per share by approximately 1.8 cents on
normalized volumes.
4
In June, 1996, the Great Falls division filed a rate adjustment application
with the MPSC of approximately $386,000, to recover increased gas supply costs,
as part of an annual filing made by the Great Falls division to balance gas
supply costs against gas revenues. This filing does not increase the Great
Falls division's margins. On November 8, 1996, the MPSC granted interim relief
of approximately $386,000.
On July 8, 1996, the Great Falls division filed a general rate increase
with the MPSC, which reflects increased operating, maintenance and depreciation
costs as well as a change in the cost of capital. The Great Falls division
applied for and received interim relief on November 8, 1996 of approximately
$274,000 to cover increases in operating costs and taxes. The MPSC issued a
final order on April 7, 1997, which granted the Great Falls division
approximately $386,000 to reflect the gas tracking increase to recover wholesale
gas costs and approximately $295,000 for operating costs and taxes, an increase
of $20,000 from the interim, due to the allowance of an overall rate of return
increase.
Historically, the Great Falls division has purchased all of its gas from
Montana Power Company ("MPC"), a publicly owned electric and gas utility serving
much of Montana. In 1991 the MPSC ordered MPC to become an open access
transporter of natural gas over a phase-in period ending on August 31, 1993.
Since the 1991 order, the Company has been able to purchase gas from sources
other than MPC and transport supplies on MPC's system. The Company has
increased its gas purchases from suppliers other than MPC, as open access
transportation has been phased in. The Great Falls division, as of June 30,
1996, purchases approximately forty percent of its gas from a Canadian producer
under a long-term contract expiring in 2007, and approximately twenty percent of
its gas from three Montana producers under long-term contracts expiring between
1998 and 2002 and fifteen percent of its gas from short-term contracts with
Montana producers. The division also makes spot market purchases from time to
time to fill its storage capacity in the spring and summer.
The price of gas under the contract with the Canadian producer is
negotiated annually between the parties. The prices of gas under two of the
contracts with independent producers are fixed prices and the other contract can
be negotiated bi-annually by either party. Gas purchased from the division's
suppliers is transported through pipelines owned by MPC and is delivered to the
division's distribution system at two city gates. The Company pays
transportation tariffs to MPC at rates approved by the MPSC.
5
The Great Falls division contracts for gas storage from MPC in MPC-owned
gas storage areas and pays storage tariffs at rates approved by the MPSC. The
division uses this storage capacity to provide for seasonal peaking needs and to
take advantage of lower priced gas generally available during the summer months.
During fiscal 1996, the Company was a party to gas financial swap
agreements for its regulated operations, including the Great Falls and Cody
divisions. Under these agreements, the Company is required to pay the
counterparty (an entity making a market in gas futures) a cash settlement equal
to the excess of the stated index price over an agreed upon fixed price for gas
purchases. The Company receives cash from the counterparty when the stated
index price falls below the fixed price. These swap agreements are made to
minimize exposure to gas price fluctuations. Any cash settlements or receipts
are included in gas purchased.
CODY DIVISION
The Cody division provides natural gas service in Northwestern Wyoming to
the city of Cody and the towns of Meeteetse and Ralston and the surrounding
areas. The service area has a population base of approximately 12,000. The
Cody division has a certificate of public convenience and necessity granted by
the Wyoming Public Service Commission (the "WPSC") for gas purchasing,
transportation and distribution covering the west side of the Big Horn Basin,
which stretches approximately 70 miles north and south and 40 miles east and
west from Cody. As of June 30, 1997, the Cody division provided service to
approximately 5,400 customers, including 4,600 residential customers, 800
commercial customers and one industrial customer. The division also provides
transportation service to two customers.
The following table shows the Cody division's revenues by customer class
for the year ended June 30, 1997 and the past two fiscal years:
Gas Revenues
(in thousands)
Years Ended June 30,
--------------------
1997 1996 1995
---- ---- ----
Residential................. $2,669 $2,353 $2,176
Commercial.................. 2,242 1,922 1,887
Industrial.................. 1,819 1,360 1,375
Transportation.............. 304 305 172
------ ----- -----
Total................. $7,034 $5,940 $5,610
------ ------ ------
------ ------ ------
6
The following table shows the volumes of natural gas, expressed in millions
of cubic feet ("MMcf") at 13.28 P.S.I.A., sold by the Cody division for the year
ended June 30, 1997 and the past two fiscal years:
Gas Volumes
(Mmcf)
Years Ended June 30,
--------------------
1997 1996 1995
---- ---- ----
Residential.................. 541 536 486
Commercial................... 573 565 539
Industrial................... 636 552 517
--- --- ---
Total Gas Sales....... 1,750 1,653 1,542
----- ----- -----
----- ----- -----
Transportation 295 642 1,484
--- --- -----
--- --- -----
The industrial sale in the Cody division is to Celotex, a manufacturer of
gypsum wallboard, under a long-term contract expiring in 2000. Sales to the
customer are made pursuant to a special industrial customer tariff which
fluctuates with the cost of gas. In fiscal 1997 this customer accounted for
approximately 26% of the revenues of the division and approximately 5% of the
consolidated revenues of the Company. The division's sales to Celotex, whose
business is cyclical and dependent on the level of national housing starts,
increased by 15% over previous year's volumes. Celotex and its parent company
Jim Walters Corporation, have been operating under Chapter 11 bankruptcy since
October, 1990. The bankruptcy stems from potential asbestos claims.
Approximately $132,000 was due the Cody division prior to the bankruptcy filing.
During 1995 the division increased its allowance for uncollectible accounts to
$52,000. On July 12, 1996, a joint Plan of Reorganization was filed by Celotex.
The Bankruptcy Court held a confirmation hearing on the Plans beginning on
October 7, 1996. A settlement was reached and on June 20, 1997, the Cody
division received 90% of the amount due or approximately $118,000. The effect
of the settlement was to decrease bad debt expense by approximately $39,000,
which increased the Cody division and consolidated earnings by approximately
$26,000 for fiscal 1997. No assurance can be given that Celotex will continue to
be a significant customer of the Cody division.
The Cody division's primary transportation customer is Interenergy
Corporation, a regional aggregator, producer and marketer of gas and the
division's primary supplier of natural gas. The parameters of the
transportation tariff (currently between $.08 and $.30 per Mcf) are established
by the WPSC. Agreements between the Company and the customer are negotiated
periodically within the parameters.
7
The division's revenues are generated under regulated tariffs that are
designed to recover a base cost of gas, administrative and operating expenses
and provide sufficient return to cover interest and profit. The division also
services customers under separate contract rates that were individually approved
by the WPSC. The division's tariffs include a purchased gas adjustment clause
which allows an adjustment of rates charged to customers in order to recover
changes in gas costs from base gas costs. A Wyoming statute permitted the WPSC
to allow gas utilities to retain 10% of its cost of gas savings over a base
period level through fiscal 1996. In fiscal 1996 this gas cost incentive
improved gross margin for the division by approximately $139,000. The amount of
gas cost incentive if any, fluctuates with the market price of natural gas. In
fiscal 1997, the WPSC lowered the target amount in the gas cost incentive and
the Cody division currently does not earn an incentive on its gas costs.
The Cody division's last general rate order was effective in 1989. The
Company does not contemplate filing an application for a general rate increase
for the division in the foreseeable future. The division's allowed return on
common equity on normalized earnings, calculated in accordance with the WPSC
order, has been 13.01% since the last general rate order.
In January, 1997 the Cody division received a 19% increase in rates as a
rate adjustment filed with the WPSC, to recover increased gas supply costs.
This rate increase does not increase the Cody division's margins.
The Cody division has a five-year agreement, expiring in 1999, with
Interenergy Corporation, a regional aggregator, producer and marketer of gas, to
supply natural gas to the division. The contract has been renewed and
renegotiated annually since 1989. The contract requires Interenergy to deliver
gas to various points on the division's transmission system. Most of the gas
purchased by the division is transported on the division's own transportation
system and the balance is transported on Interenergy's transportation system.
The division also has several small supply contracts with small producers in the
Cody transportation network. (The division's service area is located in a gas
producing region.) In addition, the division has a backup contract to purchase
natural gas from Coastal Gas Marketing, but has never purchased gas under this
contract.
BROKEN BOW DIVISION
The Broken Bow division is involved in the regulated distribution of
propane in the Payson, Arizona area. The division was formed following the
Company's acquisition of Broken Bow Gas's underground propane vapor distribution
system in January 1993. The acquisition was effective as of November 1, 1992.
The service area of the Broken Bow division includes approximately 575 square
miles and has a population base of approximately 30,000. As of June 30, 1997,
the Broken Bow division provided service to approximately 4,400 customers,
including approximately 3,800 residential customers and approximately 600
commercial customers.
8
The Broken Bow division's operations are subject to regulation by the
Arizona Corporation Commission, which regulates rates, adequacy of service,
issuance of securities and other matters. The Broken Bow division's properties
include approximately 100 miles of underground distribution pipeline and an
office building leased from a third party. The division purchases its propane
supplies from Petrogas under terms reviewed periodically by the Arizona
Corporation Commission.
In September, 1996, the Broken Bow division filed a general rate increase
with the Arizona Corporation Commission, which reflects increased operating,
maintenance and depreciation costs as well as a change in the cost of capital.
On August 29, 1997, the Arizona Corporation Commission approved a rate increase
of $390,000 effective October 1, 1997.
NON-UTILITY OPERATIONS
The Company conducts its non-utility operations through its three
wholly-owned subsidiaries: RMF, EWR and Montana Sun. RMF is engaged in the
bulk sale of propane through its three divisions: Wyo L-P, which serves
Northwestern Wyoming and Cooke City, Montana, Petrogas, which serves the
Payson, Arizona area and Missouri River Propane, which sells bulk propane in the
Cascade area, immediately southwest of Great Falls, Montana. RMF acquired
assets and operations comprising its Wyo L-P divisions through acquisitions of
existing propane distribution businesses in August 1991 and May 1992. RMF
acquired the assets and operations of its Petrogas division through an
acquisition of an existing propane distribution business in January 1993. The
aggregate purchase price for RMF's acquisitions were approximately $2.79
million. RMF had approximately 3,900 customers as of June 30, 1997, of which
the Wyo L-P division had approximately 2,500 customers and the Petrogas division
and Missouri River Propane had approximately 1,400 customers. RMF purchases
propane from various suppliers under short-term contracts and on the spot
market, and sells propane to residential and commercial customers, primarily for
use in space heating and cooking. Petrogas also supplies propane to the Broken
Bow division, while Missouri River Propane supplies propane to Cascade Gas, an
underground propane-vapor system serving the city of Cascade, Montana and the
Hardy Creek area located southwest of Cascade through a satellite tank system.
For the twelve months ended June 30, 1997, RMF's revenues (excluding
approximately $1,874,000 sales by Wyo L-P Gas Wholesale to Petrogas and Missouri
River Propane, $1,677,000 sales by Petrogas to the Broken Bow division and
approximately $141,000 sales by Missouri River Propane to Cascade Gas Company,
an operating district of the Great Falls division) were approximately
$5,313,000, of which approximately $4,268,000 was attributable to the Wyo L-P
division, $937,000 was attributable to the Petrogas division and the balance
attributable to the Missouri River Propane division.
9
On June 28, 1996, Petrogas sold real property, consisting of land and
office and warehouse building, for $525,000 in cash resulting in a gain of
$236,000. The gain will be amortized ratably into income over the initial
ten-year lease term. Concurrent with the sale, the Company leased the property
back for a period of ten years at an annual rental of $51,975. Petrogas
sub-leases the property to the Broken Bow division.
On August 1, 1997, the Company entered into a take or pay propane contract
which expires July 31, 1998. The contract generally required the Company to
purchase all propane quantities produced by a propane producer in Wyoming
(approximately 200,000 gallons per month) tied to the Worland, Wyoming spot
price.
RMF faces competition from other propane distributors and suppliers of the
same fuels that compete with natural gas. Competition is based primarily on
price and there is a high degree of competition with other propane distributors
in the service areas.
EWR was involved in a small amount of oil and gas development and the
marketing of gas in Montana and Wyoming. EWR had varying working interests in
four oil and nine gas producing properties. Those properties were sold in
fiscal 1997, with no appreciable or significant gain. Volumes of oil and gas
produced were not significant and did not result in significant net income in
fiscal 1997. The Company believes that the ordering of MPC to provide open
access on its gas transportation system in Montana presents an opportunity for
EWR to do business as a broker of natural gas using the MPC and other systems.
EWR presently has ten customers for those services, plus several units of the
State of Montana. EWR has an underground storage facility near Havre, Montana,
which allows more flexibility in the timing of its gas purchases.
For the fiscal year ended June 30, 1997, the Company is a party to three
gas hedge agreements for nonregulated operations. These agreements represent
approximately 95% of the supply required for those operations. The hedges were
made to minimize the Company's exposure to price fluctuations and to secure a
known margin for the purchase and resale of gas.
Montana Sun owns a commercial real estate property and a parcel of
undeveloped land in Great Falls, Montana. Montana Sun leases the commercial
property to a federal governmental agency. The Company is presently seeking to
sell the commercial property, but is otherwise inactive at this time.
Additional information with respect to the nonutility operation of the
Company is set forth in Notes 1, 6, 9 and 10 to the Company's consolidated
financial statements.
10
CAPITAL EXPENDITURES
The Company generally conducts a continuing construction program and is
continuing expansion of its gas pipeline in areas around metropolitan Great
Falls as well as an underground propane-vapor system in the town of Cascade,
Montana, southwest of Great Falls. In the Cody division, expansion of the gas
system in that area was completed and in the Broken Bow division, construction
is still being completed, as a result of growth. The Company has completed
construction of a natural gas system in West Yellowstone, Montana started in May
of 1994. West Yellowstone Gas Company transports liquefied natural gas from
southwestern Wyoming for revaporization into the system; operations started in
May of 1995. The Great Falls division has also added an underground propane
vapor system to service customers in the Hardy area, 30 miles southwest of Great
Falls, Montana. In fiscal years 1997, 1996 and 1995, total capital expenditures
were $3,207,200, $4,590,608 and $4,705,868 respectively.
OTHER BUSINESS INFORMATION
The principal competition faced by the Company in its distribution of
natural gas is from other suppliers of competitive fuels, including electricity,
oil, propane and coal. The principal competition faced by the Company in its
distribution and sales of propane is from other propane distributors and
suppliers of the same energy sources that compete with natural gas and
electricity. Competition is based primarily on price and there is a high degree
of competition with other propane distributors in the service areas. The
principal considerations affecting a customer's selection of utility gas service
over competing energy sources include service, price, equipment costs,
reliability and ease of delivery. In addition, the type of equipment already
installed in businesses and residences significantly affects the customer's
choice of energy. However, where previously installed equipment is not an
issue, households in recent years have consistently preferred the installation
of gas heat. The Great Falls division's statistics indicate that approximately
95% of the houses and businesses in the service area use natural gas for space
heating fuel, approximately 91% use gas for water heating and approximately 99%
of the new homes built on or near the Great Falls division's service mains in
recent years have selected natural gas as their energy source. The Cody
division believes that approximately 95% of the houses and businesses in the
service area use natural gas for space heating fuel, approximately 90% use gas
for water heating, and approximately 99% of the new homes built on or near the
division's service mains in recent years have selected gas as their energy
source. The Broken Bow division believes that approximately 59% of the houses
and businesses adjacent to the division's distribution pipeline use the
division's propane for space heating or water heating.
11
The Company had approximately 143 employees as of June 30, 1997, of which
131 were full-time. Twenty-four of the employees were with the Cody division,
23 employees were with RMF and 17 were with the Broken Bow division. The other
79 employees were with the Great Falls division, including Cascade Gas and West
Yellowstone Gas and at corporate headquarters. Approximately 13 full-time and 3
seasonal hourly employees in the Great Falls division are represented by two
collective bargaining units, the United Association of Journeymen and
Apprentices of the Plumbing and Pipefitting Industry of the USA and the
Construction and General Laborer's Union. The Company's two labor contracts
were renegotiated through April 30, 2000. The Company considers its
relationship with its employees to be satisfactory.
The Company has instituted an extensive customer-related energy
conservation program which encourages the efficient use of energy through proper
conservation measures. The Company provides inspection services to homeowners
and businesses and recommends appropriate conservation projects. The Company
also is concentrating on increasing load in existing residential structures by
the addition of gas appliances and conversion of homes with all electric
appliances. The Company has started a natural gas and propane appliance
showroom to market gas appliances in the Great Falls and Cody divisions with
future plans to market appliances in the propane offices of the Company.
In addition, the Company encourages converting commercial food service
equipment to natural gas through a developed commercial equipment efficiency
program, both in Great Falls and Cody. The Company's field marketing personnel
are paid through an incentive plan geared to how much load they add to the
system.
12
The Company has management and employee incentive programs tied to
bottom-line performance of the corporation. Officers and management, down to
first-line supervisors, participate in a pay-for-performance program. If the
Company meets a minimum earnings per share for the consolidated corporation for
25% and a minimum rank on the comparison of utilities published by Edward D.
Jones & Co. for an additional 25% funding and individual divisions meet their
allocated consolidated earnings per share for the other 50%, or in the case of
senior officers and corporate staff the corporation meets a minimum rank on the
comparison of utilities published by Edward D. Jones & Co. for the other 50%;
then the incentive pool is triggered; then whether the incentive is actually
earned depends on whether the individuals in the program achieve individual
specific performance objectives set at the beginning of the year. Incentives
vary from .8% on up of base wages. The Company is in the process of changing the
incentive program effective for fiscal 1998, which will be based on new
performance criteria. All officers and eligible employees participate in the
Company's Employee Stock Ownership Plan, in which payout is based on pre-tax
earnings of the Company and approved by the Board each year.
The Company has implemented a deferred compensation plan for directors,
which allows a director to defer directors' fees and incentive awards until such
time as the director ceases to be a director of the Company by retirement or
otherwise. The plan provides an incentive compensation based on the total fees
earned by each Director for that year multiplied by the highest percentage
incentive award for that year to any employee under the Company's management
incentive compensation plan, which in fiscal 1997 was 48.33%. Fees (either cash
or stock) and incentive compensation (stock only) can be received either
currently, as they are earned, or on a deferred basis. Elections to defer
receipts are subject to timing requirements. The deferred compensation plan for
directors was approved by the shareholders at the Annual Shareholders Meeting of
Energy West, Incorporated November 21, 1996.
13
PART I
Item 2. - PROPERTIES
The Company owns all of its properties in Great Falls, including an office
building, a service and operating center, regulating stations and its
distribution system. In Wyoming, the Company owns its distribution system,
including 167 miles of transmission pipeline. Office and service buildings for
the Cody division are leased under long-term leases. RMF owns buildings,
propane tanks and related metering and regulating equipment for the Wyoming and
Arizona propane distribution operations. The Company owns mains and service
lines for the Broken Bow division's propane vapor distribution operation in
Payson, Arizona. In June, 1996, Petrogas a division of RMF sold its land and
office and warehouse buildings in Payson, Arizona to an outside party and signed
a lease agreement with the same party for a period of ten (10) years, with a
provision of extension of the lease for two successive five (5) year periods.
RMF does not have an option to repurchase the real property. However, should
the lessor have a bona fide third-party offer, the Company has the right of
first refusal to buy the land and buildings under the same terms and conditions
offerred.
ENVIRONMENTAL MATTERS
The Company owns property on which it operated a manufactured gas plant from
1909 to 1928. The site is currently used as a service center for the Company
where certain equipment and materials owned by the Company are stored. The coal
gasification process utilized in the plant resulted in the production of certain
by-products which have been classified by the federal government and the State
of Montana as hazardous to the environment. Several years ago the Company
initiated an assessment of the site to determine if remediation of the site was
required. That assessment resulted in a submission of a report to the Montana
Department of Environmental Quality (MDEQ), formerly known as the Montana
Department of Health and Environmental Sciences (MDHES), in 1994. The Company
has worked with the MDEQ since that time to obtain the data that would lead to a
remediation action acceptable to MDEQ. The Company's environmental consultant
filed the report with the MDEQ on June 11, 1997. The MDEQ is evaluating the
report and after completion of its review will provide for public comment
related to the remediation plan. Once the comment period has lapsed and due
consideration of any comments occurs, the plan can be finalized. Assuming
acceptance of the plan, remediation can begin by the fall of 1998.
At June 30, 1997 the costs incurred in evaluating this site have totalled
approximately $430,000. On May 30, 1995 the Company received an order from the
Montana Public Service Commission allowing for recovery of the costs associated
with evaluation and remediation of the site through a surcharge on customer
bills. As of June 30, 1997, that recovery mechanism had generated approximately
$410,000, or about what had been expended. The Commission's decision calls for
ongoing review by the Commission of the costs incurred for this matter. The
Company will submit an application for review by the Commission when the
remediation plan is approved by the MDEQ.
14
Item 3. - LEGAL PROCEEDINGS
From time to time the Company is involved in litigation relating to claims
arising from its operations in the normal course of business. Neither the
Company nor any of its subsidiaries is a party to any legal proceedings, other
than as described below, the adverse outcome of which individually or in the
aggregate, in the Company's view, would have a material adverse effect on the
Company's results of operations, financial position or liquidity.
On December 20, 1996, an action was filed against the Company by Randy Hynes and
Melissa Hynes in Federal District Court in Wyoming. The action arises from a
natural gas explosion involving a four-plex apartment building which was damaged
after natural gas from a gas line leaked into the building on February 3, 1996
(which was not served by natural gas). The plaintiffs, who were tenants in the
building, sustained burns and other injuries as well as property damage. The
plaintiffs allege that the Company was negligent in that it failed to maintain
the natural gas line consistent with its duty to do so and failed to properly
odorize the gas which caused the explosion. The action also asserts claims of
product liability, willful and wanton conduct and breach of warranty. The
plaintiffs are seeking damages for personal injury, pain and suffering,
emotional distress, loss of earnings, medical expenses, physical disability and
property damage as well as punitive damages. A dollar amount has not been set
forth in the pleadings. The Company denies responsibility for the damages and
is vigorously contesting the matter. The Company believes the gas leak resulted
from damage caused to the pipeline by an unknown third party. Discovery is
proceeding at this time. A trial has been scheduled for October 27, 1997.
A similar lawsuit involving the same explosion was filed by five other
plaintiffs in Wyoming District court, Park County, Wyoming on April 3, 1997.
The allegations are substantially the same as the allegations in the Federal
District Court case. The Company has filed an answer denying liability and is
contesting the matter vigorously. Only limited discovery has occurred to date.
The plaintiffs, Heidl Woodward, et al., were also tenants in the apartment
building.
On October 24, 1996, an action was filed against the Company by Colten and Julie
White and their three children in Superior Court in Gila County, Arizona. The
action arises from an explosion that occurred on May 3, 1995 in the plaintiffs'
new home which was serviced by the Company's propane business. The explosion
occurred in the course of the plaintiffs' attempt to light their appliances for
the first time. The plaintiffs sustained injuries and property damage in the
explosion and the fire that occurred after the explosion. The claims are for
personal injury, mental suffering and anguish, medical expenses, lost income,
property damages and punitive damages. Plaintiffs' claims are based on a strict
liability claim that the propane was defective, breach of warranty in that the
propane was not fit for the purpose for which it was intended and negligence for
failure to assure that the propane was properly odorized. The dollar value of
the claims has not been set forth in the pleadings of the plaintiffs.
The Company carries commercial general liability insurance for bodily injury and
property damages of $1,000,000 per occurrence and $5,000,000 in the aggregate,
and has an additional $30,000,000 umbrella policy for excess claims. The
Company's general liability carrier has assumed the defense of both Wyoming
actions and the Arizona action. The Company believes it has insurance coverage
for these matters. However, no assurance can be given that insurance will cover
these matters in the event that the company is held liable. In the event of an
adverse result for the Company, and if the Company's insurance does not cover
the matters or is not sufficient to cover the matters, such result could have a
material adverse effect on the Company's results of operations, financial
position and liquidity (depending on the amount of the judgment or judgments).
Item 4. - SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None
15
EXECUTIVE OFFICERS AND DIRECTORS OF THE COMPANY
The following table sets forth the names and ages of, and the positions and
offices within the Company presently held by, all directors and executive
officers of the Company:
NAME AGE POSITION
---- --- --------
Larry D. Geske 58 President and Director since
1978; appointed Chief
Executive Officer in 1979
Edward J. Bernica 47 Vice-President and Chief
Financial Officer since
October, 1994
William J. Quast 58 Vice-President, Treasurer,
Controller and Assistant
Secretary since 1988, has been
Vice-President, Secretary and
Treasurer since 1987,
Assistant Vice-President,
Secretary Controller and
Assistant Treasurer since
1983, Secretary since 1982 and
an Assistant Treasurer of the
Company since 1979
Tim A. Good 52 Vice-President and Manager of
the CGD since 1988; General
Manager of Cody Gas Company, a
Division of the Coastal
Corporation, for five years
prior to the acquisition of
CGD by the Company
Sheila M. Rice 50 Vice-President and Division
Manager of the Great Falls
division since April, 1993;
Vice-President Marketing and
Consumer Services since 1988
and has been Vice-President,
Marketing and Consumer
Relations since 1987; was
Assistant Vice-President for
Marketing and Customer
Relations 1983-1987
16
NAME AGE POSITION
---- --- --------
John C. Allen 46 Vice-President of Human
Resources and Corporate
Counsel and Secretary since
1992; Corporate Counsel and
Secretary since 1988; Counsel
and Assistant Secretary from
November 1986 to 1988 and
Corporate Attorney to the
Company from March 1986 to
November 1986
Lynn F. Hardin 49 Assistant Vice-President of
Gas Supply for the Great Falls
division since June 1, 1993;
Assistant Vice-President of
Division Administration since
1989; was manager of
Accounting and Administration
for Cody Gas Company, a
Division of The Coastal
Corporation, for five years
prior to acquisition of CGD by
the Company
Earl L. Terwilliger, Jr. 49 Assistant Vice-President for
Market Development for the
Great Falls division since
1990; has been Assistant Vice-
President of Customer
Accounting and Credit since
1988
Ian B. Davidson 65 Director since 1969
George D. Ruff 59 Director since 1996
Thomas N. McGowen, Jr. 71 Director since 1978
G. Montgomery Mitchell 69 Director since 1984
Dean South 54 Director since 1996
David A. Flitner 64 Director since 1988
17
Larry D. Geske has been employed by the Company since 1975 and became President
and Director of the Company in 1978. In 1979, Mr. Geske was appointed to the
position of Chief Executive Officer. In addition, Mr. Geske is a past Director
of First Interstate Bank of Great Falls (parent Company is First Interstate Bank
Corporation) and is a Director of the Great Falls Capital Corporation and the
Great Falls Dodgers Baseball Club. He is also a Director of the American Gas
Association's Board. Mr. Geske, prior to service with the Company, was a Field
Engineer "A" with NIGAS in Aurora, Illinois and a Senior Consultant with Stone
and Webster Management Consultants, Inc. in New York.
Mr. Edward J. Bernica has been employed by the Company since October 1994 and
became Vice-President and Chief Financial Officer in November, 1994. Mr.
Bernica, prior to service with the Company, was Director of Finance at U. S.
West in Englewood, Colorado and prior to that, was employed by ENRON Corporation
in Omaha, Nebraska as Director-Financial Analysis and Planning
William J. Quast has been Vice-President, Treasurer, Controller and Assistant
Secretary since 1988. He has served as Vice-President, Secretary and Treasurer
since 1987 and as Assistant Vice-President, Secretary, Controller and Assistant
Treasurer since 1983. He has served as Secretary of the Company since 1982 and
as Assistant Treasurer of the Company since 1979. Mr. Quast, prior to service
with the Company, was an accounting manager for Wyton Oil and Gas Company, a
multi-state propane distributor headquartered in Denver, Colorado, and was
Treasurer for D. A. Davidson & Co. in Great Falls, Montana.
Tim A. Good has been Vice-President and Division Manager of the CGD since 1988.
He served as General Manager of Cody Gas Company, a Division of The Coastal
Corporation for five years prior to the acquisition of the Cody Gas Company by
EWST in 1988.
Sheila M. Rice has been Vice-President and Division Manager of the Great Falls
division since April, 1993. Prior to that, she was Vice-President of Marketing
and Consumer Services since 1988. She served as Vice-President, Marketing and
Consumer Relations from 1987 to 1988, Assistant Vice-President for
Marketing/Customer Relations from 1983 to 1987 and as Consumer Service
Representative/Conservation Specialist for the Company from 1979 to 1983.
John C. Allen has been Vice-President of Human Resources and Corporate Counsel
since 1992 and previously served as Corporate Counsel and Secretary of the
Company since 1988. He served as Corporate Counsel and Assistant Secretary from
November 1986 until 1988 and as Corporate Attorney of the Company (March,
1986-November 1986). From 1979 to 1986, Mr. Allen was employed as a staff
attorney with the Montana Consumer Counsel.
18
Lynn F. Hardin has been Assistant Vice-President of Gas Supply since June 1,
1993. Prior to that, he was Assistant Vice-President of Division Administration
since 1989. He was Manager of Accounting and Administration of Cody Gas
Company, a Division of The Coastal Corporation for five years prior to the
acquisition of the Cody Gas Company by the Company in 1988.
Earl L. Terwilliger, Jr. has been Assistant Vice-President for Market
Development since 1990. He served as Assistant Vice-President of Customer
Accounting and Credit from 1988 to 1990 and Manager of Customer Accounting and
Credit for the previous four years. Prior to that time, Mr. Terwilliger was
office manager.
Ian B. Davidson has been a Director of the Company since 1969. Mr. Davidson has
been Chairman and Chief Executive Officer of D. A. Davidson & Co. since October,
1970. Mr. Davidson also is a Director of Plum Creek Management Company, a
member of the 1996 Nominating Committee for District 3 of the National
Association of Securities Dealers and a member of the C. M. Russell Museum
Advisory Board.
George D. Ruff has been a Director of the Company since 1996. Mr. Ruff is
currently Vice President of Montana Operations for U. S. West, Incorporated. He
has held that position since June of 1983. He has been employed in the
telecommunications industry for over thirty years. He is also a director of
Norwest Bank, the Political Education Council of Montana, the Montana Taxpayers
Association and the Montana Tech Foundation.
Thomas N. McGowen, Jr. has been a Director of the Company since 1978. Mr.
McGowen is past President and Chairman of the Board of Pabst Brewing Company.
Mr. McGowen is a Director of Federal Signal Corporation and Ribi Immunochem
Corporation.
G. Montgomery Mitchell has been a Director of the Company since 1984. Mr.
Mitchell was a Senior Vice-President and Director of Stone and Webster
Management Consultants, Inc. until his retirement in 1993. Mr. Mitchell was
responsible for Stone and Webster's services provided to natural gas utility and
pipeline companies and managed their Houston, Texas office. He is presently
retained by Stone and Webster for advisory and senior consulting services. Mr.
Mitchell also is a Director of Mobile Gas Service Corporation (Alabama).
Dean South has been a Director of the Company since 1996. Mr. South currently
ranches north of Helena, Montana. In 1991, Mr. South retired from the propane
distribution industry having served as Vice President of Western Operations for
Heritage Propane Corporation from October 1989 through 1991. From 1986 until
1989 he served as President and Chief Operating Officer of Louis Dreyfus Propane
Corporation. From 1981 until 1986 he served as President of Northern Energy
Company which subsequently merged with Louis Dreyfus Propane.
David A. Flitner has been a Director of the Company since 1988. Mr. Flitner is
owner of the Flitner Ranch and Dave Flitner Packing and Outfitting (Wyoming
Companies) and Hideout Adventures, Inc., a recreational enterprise.
19
PART II
Item 5. - MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
Common Stock Prices and Dividend Comparison - Fiscal 1997 and Shares of the
Company's Class A Common Stock are traded in the over-the-counter market on the
NASDAQ (National Association of Securities Dealers Automated Quotation)
system-symbol: EWST. The over-the-counter market quotations reflect
inter-dealer prices, without retail mark-up, mark-down or commission, and may
not necessarily represent the actual transactions. Prices are shown as a result
of a 2-for-1 stock split, effective June 24, 1994.
PRICE RANGE - FISCAL 1997 HIGH LOW
- ------------------------- ---- ---
First Quarter 8 3/4 7 7/8
Second Quarter 8 3/4 8 1/8
Third Quarter 8 5/8 8 1/8
Fourth Quarter 8 5/8 8 1/8
Year 8 5/8 7 7/8
PRICE RANGE - FISCAL 1996 HIGH LOW
- ------------------------- ---- ---
First Quarter 8 1/4 7 3/4
Second Quarter 9 1/2 7 3/4
Third Quarter 9 3/4 8 3/4
Fourth Quarter 9 3/8 8
Year 9 3/8 7 3/4
Dividends: The Board of Directors normally consider approving common stock
dividends for payments in March, June, September and January. Quarterly
dividend payments per common share for Fiscal Years 1997 and 1996 were:
FISCAL 1997 FISCAL 1996
----------- -----------
September $.1050 $.1000
January $.1050 $.1000
March $.1050 $.1000
June $.1100 $.1050
20
Item 6. - SELECTED FINANCIAL DATA
SELECTED FINANCIAL DATA (1997-1993)
--------------------------------------------------------------------------------------------------------------------------
(dollar amounts in thousands, except per share data)
1997 1996 1995 1994 1993
Operating results:
Operating revenue $ 38,215 $ 31,318 $30,548 $ 29,347 $27,629
Operating expenses
Gas purchased 24,675 18,724 18,616 18,410 17,232
General administrative 7,498 6,924 6,380 5,979 5,454
Maintenance 497 409 306 331 376
Depreciation and amortization 1,689 1,667 1,559 1,464 1,286
T axes other than income 660 629 595 527 540
--------------------------------------------------------------------------------------------------------------------------
Total operating expenses 35,019 28,353 27,456 26,711 24,888
Operating income 3,196 2,965 3,092 2,636 2,741
--------------------------------------------------------------------------------------------------------------------------
Other income - net 325 215 175 199 139
--------------------------------------------------------------------------------------------------------------------------
Income before interest charges 3,521 3,180 3,267 2,835 2,880
Total interest charges 1,525 1,243 938 962 959
--------------------------------------------------------------------------------------------------------------------------
Income before taxes 1, 996 1,937 2,329 1,873 1,921
Income taxes 703 670 816 614 637
Income before a cumulative effect of
a change in accounting principal 1,293 1,267 1,513 1,259 1,284
Cumulative effect of change as of
July 1, 1993 from adoption of
FASB 109 0 0 0 92 0
- - - -- -
Net income $1,293 $ 1,267 $ 1,513 $ 1,351 $ 1,284
------ ------- ------- ------- -------
------ ------- ------- ------- -------
Eps before cumulative effect of FASB 109 0.55 0.55 0.68 0.57 0.59
Earnings per common share 0.55 0.55 0.68 0.61 0.59
Dividends per common share 0. 43 0.41 0.39 0.36 0.32
Weighted average common shares Outstanding 2,356,624 2,298,734 2,235,413 2,205,050 2,171,448
At year end:
Current assets 12,398 9,092 6,263 5,270 6,761
Total assets 42,885 37,495 32,375 28,786 28,036
Current liabilities 15,317 11,088 6,786 4,193 4,881
Total long-term obligations 9,684 10,046 10,435 10,718 11,050
Total stockholders' equity 11, 997 11,400 10,533 9,393 8,733
- ----------------------------------------------------------------------------------------------------------------------------------
Total capitalization $ 21,681 $ 21,446 $ 20,968 $ 20,111 $ 19,783
- ----------------------------------------------------------------------------------------------------------------------------------
21
Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF CONSOLIDATED OPERATIONS
RESULTS OF CONSOLIDATED OPERATIONS
Fiscal 1997 Compared to Fiscal 1996
Net Income
The Company's net income for fiscal 1997 was $1,293,000 compared to
$1,267,000 in fiscal 1996, an increase of $26,000 or 2%. The following summary
describes the components of the change between years.
Revenue
Operating revenues increased approximately 22%. Regulated revenues
increased approximately 14% compared to the prior year due to a rate and gas
tracker increase in the Great Falls division, effective November 4, 1996, and a
gas tracker increase in the Cody division effective January 1997, in addition to
colder weather this year than one year ago in the Great Falls, Cody, West
Yellowstone and Broken Bow utility divisions. Nonregulated revenues increased
approximately 48%, from increased bulk propane sales in the areas served by Wyo
L-P gas in Wyoming, Missouri River Propane in Montana and Petrogas in Arizona,
as well as increased wholesale propane sales in Wyo L-P in Wyoming. Both
Missouri River Propane and Petrogas sell propane to related regulated utilities
Cascade Gas Company and Broken Bow Gas Company, respectively. Operating
revenues in Energy West Resources decreased by 31%; however, gas trading
revenues increased by 38% due to customer growth and an increase in volumes.
Gross Margin
Gross margins (operating revenues less cost of gas purchased and cost of
gas trading) increased approximately $944,000 in 1997. Regulatory gross margins
increased approximately $663,000 because of higher margins from natural gas
sales in the Great Falls and Cody divisions and in the West Yellowstone area and
higher margins from propane vapor sales in the Broken Bow division, due to
colder weather than one year ago and customer growth in all utility operations,
as well as a 1.86% interim rate increase in the Great Falls division, effective
November 4, 1996, which contributed to increased margins by approximately
$112,000. Nonregulated gross margins increased approximately $283,000,
primarily due to larger margins in the Wyo L-P division for wholesale propane
sales partially offset by lower gas trading margins in Energy West Resources.
Regulated Revenues
Regulated revenues increased from $23,672,000 in fiscal 1996 to $26,882,000
in fiscal 1997 or 14%, primarily due to increases in the revenues of the Great
Falls division of approximately $1,397,000, the Cody division of approximately
$1,094,000 and the Broken Bow division of approximately $720,000 because of
increased natural gas and propane vapor sales, due to colder weather than one
year ago and customer growth in all utility operations, as well as a 1.86%
interim rate increase in the Great Falls division, effective November 4, 1996
and a 19% increase in the Cody division effective January, 1997 and increased
sales in Cody to an industrial customer who increased production, requiring more
natural gas. Gas purchased increased from approximately $13,646,000 in fiscal
1996 to $16,193,000 in fiscal 1997 or 19%, primarily due to a 35% increase in
natural gas costs from one year ago and increased volumes of natural gas
purchased, due to colder weather than one year ago as well as increases in
customers.
22
Regulated Operating Income
Regulated operating income increased approximately $317,000 in fiscal 1997
or 14%, primarily due to increased gross margins of approximately $663,000, due
to customer growth, colder weather than one year ago, as well as a 1.86% rate
increase in the Great Falls division, effective November, 1996, partially offset
by higher utility operating expenses and taxes other than income of
approximately $345,000, due to normal inflationary trends and less payroll,
payroll taxes and other expenses capitalized to projects as well as higher
property taxes in all three states served by Energy West.
Nonregulated Operating Income
Nonregulated operating income decreased approximately $87,000 in fiscal
1997 or 11%, due to higher operating and maintenance expenses of approximately
$328,000 due to inflation and growth of nonregulated operations, higher
depreciation and amortization costs of approximately $32,000, higher property
taxes of approximately $9,000, offset partially by higher margins on gas and
propane sales of approximately $283,000.
Other Expenses
Operating expenses (excluding cost of gas sales) increased approximately
$714,000 or 7% in 1997. The primary reason for this increase was due to normal
inflationary trends and less payroll and other expenses capitalized to
projects.
As a result of the above changes, operating income increased 8% from
$2,965,000 in 1996 to $3,195,000 in 1997. Total interest expense for the
Company was $1,525,000 for fiscal 1997, up from $1,243,000 in fiscal 1996,
primarily due to facility expansion and increases in gas storage, which has been
temporarily financed with short term debt. Other additions to or deductions
from operating income in determining net income remained comparable between the
two years.
Fiscal 1996 Compared to Fiscal 1995
Net Income
The Company's net income for fiscal 1996 was $1,267,000 compared to
$1,513,000 in fiscal 1995, a decrease of $246,000 or 16%. The following summary
describes the components of the change between years.
Revenue
Operating revenues increased approximately 3%. Regulated revenues
decreased 3% compared to the prior year due to a rate decrease in the Great
Falls division, effective July 1, 1995. This decrease in rates was partially
offset by colder weather this year than one year ago in the Great Falls and Cody
utility divisions, increased transport revenues in the Cody division and the
recognition of West Yellowstone revenues in this start-up operation. Both
Missouri River Propane and Petrogas sell propane to related regulated utilities
Cascade Gas Company and Broken Bow Gas Company, respectively. Operating
revenues in Energy West Resources decreased by 31%; however, gas trading
revenues increased by 38% due to customer growth and an increase in volumes.
23
Gross Margin
Gross margins (operating revenues less cost of gas purchased and cost of gas
trading) increased approximately $664,000 in 1996. Regulatory gross margins
increased approximately $740,000 because of higher margins from natural gas
sales in the Great Falls and Cody divisions. Margins were tempered by the
effects of a rate reduction in the Great Falls division of approximately
$260,000 annually, ordered by the Montana Public Service Commission, which went
into effect on July 1, 1995. In addition, margins of West Yellowstone, a new
operation in Montana, are reflected in this fiscal year. Nonregulated gross
margins decreased approximately $84,000, primarily due to smaller margins in
Energy West Resources' gas marketing operations.
Regulated Revenues
Regulated revenues decreased from $24,363,000 in fiscal 1995 to $23,672,000
in fiscal 1996 or 3%, primarily due to a decrease in the revenues of the Great
Falls division of approximately $1,550,000, due to a $260,000 rate decrease
ordered by the Montana Public Service Commission, a reduction in gas costs
reducing rates by approximately $290,000 and the shift of Malmstrom Air Force
Base revenues to a transportation customer, which further reduced revenues by
approximately $1,000,000. This was offset by the inclusion of West Yellowstone
revenues of approximately $300,000 and increased Cody division revenues of
approximately $330,000, due to increased volumes sold due to customer growth,
colder weather, higher transportation revenues and increases in Propane sales in
the Broken Bow and Cascade divisions, due to customer growth. Gas purchased
decreased from $15,077,500 in fiscal 1995 to $13,646,200 in fiscal 1996 or 10%,
primarily due to a reduction in natural gas costs.
Regulated Operating Income
Regulated operating income increased approximately $65,000 in fiscal 1996
or 3%, primarily due to increased gross margins of approximately $740,000, due
to customer growth, colder weather, higher transportation sales and the
inclusion of West Yellowstone margins. This was offset by increases in
distribution, general, administrative and general expenses of approximately
$490,000, due to operations growth and inflation, increases in depreciation and
amortization expenses of approximately $153,000, due to additional utility plant
and increases in taxes other than income of approximately $29,000, due to higher
property taxes in all three states served by Energy West.
Nonregulated Operating Income
Nonregulated operating income decreased approximately $190,000 in fiscal
1996 or 20%, due to smaller margins in Energy West Resources' gas marketing
operations of approximately $151,000 and higher operating and maintenance
expenses of approximately $156,000 due to inflation and growth of nonregulated
operations, offset partially by lower depreciation and amortization costs.
Other Expenses
Operating expenses (excluding cost of gas sales) increased approximately
$790,000 or 9% in 1996. The primary reason for this increase was due to normal
inflationary trends and lower capitalized payroll since the completion of the
West Yellowstone system, as well as the addition of West Yellowstone's utility
operating expenses this fiscal year.
As a result of the above changes, operating income decreased 4% from
$3,092,000 in 1995 to $2,965,000 in 1996. Total interest expense for the
Company was $1,243,000 for fiscal 1996, up from $939,000 in fiscal 1995, due to
higher short-term borrowing used in expansion of the Company's utility systems.
Other additions to or deductions from operating income in determining net income
remained comparable between the two years.
24
OPERATING RESULTS OF THE COMPANY'S UTILITY OPERATIONS
Years Ended June 30
-------------------
1997 1996 1995
---- ---- ----
(in thousands)
Operating revenues:
Great Falls division $17,133 $15,737 $16,812
Cody division 7,034 5,940 5,609
Broken Bow division 2,715 1,995 1,942
Total operating revenues 26,882 23,672 24,363
Gas purchased 16,193 13,646 15,077
------- ------ ------
Gross Margin 10,689 10,026 9,286
Operating expenses 8,155 7,810 7,136
Interest charges [SEE NOTE BELOW] 1,477 1,145 908
Other utility (income) expense-net (125) (118) (126)
Federal and state income taxes 377 385 454
---- --- ---
Net utility income $805 $804 $ 914
----- ---- -----
----- ---- -----
[INTEREST CHARGES FOR UTILITY AND NON-UTILITY OPERATIONS DO NOT EQUAL TOTAL
INTEREST CHARGES FOR THE COMPANY, DUE TO ELIMINATING ENTRIES BETWEEN ENTITIES.]
25
Fiscal 1997 Compared to Fiscal 1996
Revenues and Gross Margins
Utility operating revenues in fiscal 1997 were approximately $26,882,000
compared to $23,672,000 in fiscal 1996. Regulated gross margin, which is
defined as operating revenues less gas purchased, was approximately $10,689,000
for fiscal 1997 compared to approximately $10,026,000 in fiscal 1996.
Overall revenues increased approximately $3,210,000 from fiscal 1996 due
primarily to a rate and gas tracker increase in the Great Falls division and a
tracker increase in the Cody division, in addition to colder weather this year
than one year ago in all utility divisions. Utility margins increased
approximately $662,000 or 7% because of higher margins from natural gas sales in
the Great Falls and Cody divisions and in the West Yellowstone area and higher
margins from propane vapor sales in the Broken Bow division, due to colder
weather than one year ago and customer growth in all utility operations, as well
as a 1.86% rate increase in the Great Falls division, effective November, 1996.
The winter heating season was 3% colder than one year ago in the Great Falls
division and 13% colder than the same period one year ago in the Broken Bow
division and about equivalent to one year ago in the Cody division.
Operating Expenses
Utility operating expenses, exclusive of the cost of gas purchased and
federal and state income taxes, were approximately $8,155,000 for fiscal 1997,
as compared to approximately $7,810,000 for fiscal 1996. The 4% increase in
the period is due to normal inflationary trends, less payroll and other
expenses capitalized to projects.
Interest Charges
Interest charges allocable to the Company's utility divisions were
approximately $1,477,000 in fiscal 1997, as compared to approximately
$1,145,000 in fiscal 1996. Long term debt interest decreased; however,
short-term interest increased primarily due to facility expansion, which has
been temporarily financed with short-term debt.
Income Taxes
State and federal income taxes of the Company's utility divisions was
approximately $426,000 in fiscal 1997, as compared to approximately $427,000 in
fiscal 1996.
26
Fiscal 1996 Compared to Fiscal 1995
Revenues and Gross Margins
Utility operating revenues in fiscal 1996 were approximately $23,672,000
compared to $24,363,000 in fiscal 1995. Gross margin, which is defined as
operating revenues less gas purchased, was approximately $10,026,000 for fiscal
1996 compared to approximately $9,286,000 in fiscal 1995.
Overall revenues decreased from fiscal 1995 due primarily to a $250,000
rate decrease in the Great Falls division in Montana, effective July 1, 1995.
In addition, Malmstrom AFB became a transport customer of the Great Falls
division in fiscal 1996, further reducing operating revenues. Energy West
Resources sold natural gas to Malmstrom AFB in fiscal 1996. This decrease in
rates and the Malmstrom change to transport was tempered by colder weather this
year than one year ago in all utility divisions and recognition of West
Yellowstone revenues this year in this start-up operation. While utility
revenues decreased from fiscal 1995, margins increased approximately 8% for
fiscal 1996, primarily due to higher margins from natural gas sales in the Great
Falls and Cody divisions and propane sales in the Broken Bow division because of
customer growth and colder weather than one year ago in the Great Falls and Cody
divisions and the addition of West Yellowstone's margins in fiscal 1996, in this
new start-up operation. The winter heating season in the Great Falls division in
fiscal 1996 was approximately 10% colder than fiscal 1995 and 8% colder than
"normal" (i.e., the average temperature during the preceding 30 years). The
winter heating season in the Cody division was approximately 5% colder than
fiscal 1995, and very close to normal in fiscal 1996. The Broken Bow division
experienced an 18% warmer period than 1995 and 15% warmer period than normal.
Operating Expenses
Utility operating expenses, exclusive of the cost of gas purchased and
federal and state income taxes, were approximately $7,810,000 for fiscal 1996,
as compared to approximately $7,136,000 for fiscal 1995. The 9% increase in the
period is due to normal inflationary trends, less payroll capitalized since the
completion of the West Yellowstone system as well as the addition of West
Yellowstone's utility operating expenses of approximately $257,000 this fiscal
year from this start-up operation.
Interest Charges
Interest charges allocable to the Company's utility divisions were
approximately $1,145,000 in fiscal 1996, as compared to approximately $908,000
in fiscal 1995. Long term debt interest decreased; however, short-term interest
increased primarily due to facility expansion, which has been temporarily
financed with short-term debt.
Income Taxes
State and federal income taxes of the Company's utility divisions was
approximately $385,000 in fiscal 1996, as compared to approximately $454,000 in
fiscal 1995. The 15% decrease was primarily attributable to a $184,000
decrease in pre-tax income of the utility divisions.
27
OPERATING RESULTS OF EACH OF THE COMPANY'S NON-UTILITY SUBSIDIARIES
Years Ended June 30
-------------------
1997 1996 1995
---- ---- ----
(in thousands)
ROCKY MOUNTAIN FUELS (RMF)
Operating revenues $9,004 $4,352 $3,902
Cost of propane 6,747 2,540 2,171
Operating expenses 1,875 1,548 1,484
Other (income) expense-net (92) (64) (33)
Interest expense [see note below] 171 112 87
Federal and state income taxes 106 85 71
---- ------ -----
Net income $ 197 $ 131 $ 122
------ ------ ------
------ ------ ------
ENERGY WEST RESOURCES
Operating revenues $ 42 $ 61 $ 76
Gas trading revenue 5,993 4,348 3,239
Operating expenses 251 201 172
Cost of gas trading 5,560 3,773 2,500
Other (income) expense-net (120) (20) (43)
Federal and state income taxes 154 169 259
--- --- ------
Net income $ 190 $286 $ 427
------ ----- ------
------ ----- ------
MONTANA SUN
Operating revenues $ 97 $ 97 $ 99
Operating expenses 43 48 47
Other (income) expense-net (113) (24) (16)
Interest expense [see note below] 0 0 (14)
Federal and state income taxes 67 27 31
-- -- ---
Net income $ 100 $ 46 $ 51
------ ------ ------
------ ------ ------
Total Non-Utility Net Income $ 487 $ 463 $ 600
------ ------ ------
------ ------ ------
[INTEREST CHARGES FOR UTILITY AND NON-UTILITY OPERATIONS DO NOT EQUAL
TOTAL INTEREST CHARGES FOR THE COMPANY, DUE TO ELIMINATING ENTRIES BETWEEN
ENTITIES.]
28
Non-Utility Operations
Rocky Mountain Fuels
For the fiscal year ended June 30, 1997, Rocky Mountain Fuels (RMF)
generated net income of approximately $197,000 compared to $131,000 for fiscal
1996. Approximately $127,000 of RMF's net income for fiscal 1997 was
attributable to the Wyo L-P Gas division in Wyoming, $111,000 to the Petrogas
division in Arizona, with the balance of ($40,000) net loss attributable to
Missouri River Propane in Montana. RMF's gross margins increased approximately
24% or $443,000 in fiscal 1997 compared to the same period last year, primarily
due to increased wholesale propane sales in the Wyo L-P Gas division in Wyoming.
Margins this fiscal 1997 increased approximately $257,000 for wholesale propane
sales, due to customer growth and colder weather and decreased approximately
$44,000, or 4%, for retail propane sales due to higher propane prices and
competitive market conditions, while margins in the Petrogas division in Arizona
increased from a year ago by approximately $118,000, or 25%, due to customer
growth and weather, while Missouri River Propane in Montana margins increased
from a year ago by approximately $13,000, or 20%, due to weather and customer
growth. RMF experienced higher operating expenses, due to normal inflationary
trends experienced and increased use of staff, due to customer growth, as well
as higher short-term interest costs due to expansion of plant in Montana and
Wyoming, which was financed by short-term debt. State and federal income taxes
increased to approximately $106,000 for fiscal 1997 from $85,000 due to higher
pre-tax income in RMF this year of approximately $89,000.
For the fiscal year ended June 30, 1996, Rocky Mountain Fuels (RMF)
generated net income of approximately $131,000 compared to $122,000 for fiscal
1995. Earnings improved by approximately $76,000, due to decreasing depreciation
expense in all of RMF's operating divisions as a result of changing the
estimated useful lives for certain propane properties from twelve and fifteen
years to twenty years, to better reflect its useful lives. Missouri River
Propane and Big Horn Answering Service had a loss for the fiscal year.
Energy West Resources
For fiscal 1997, Energy West Resources' (EWR) net income was approximately
$190,000 compared to $286,000 for fiscal 1996, primarily due to lower gas
trading margins. Gas trading margins decreased approximately $142,000, or 24%.
Although gas trading revenues are up approximately $1,646,000 in fiscal 1997
from one year ago, cost of gas trading was up approximately $1,788,000, due to
increased natural gas prices in Canada and Montana and increased competition,
requiring lower margins in order to retain or secure new Energy West Resource
customers. EWR expenses were also higher than 1996 because of power marketing
investigations, salary and expenses for an EWR specific employee, increased
direct charges and overheads allocated to EWR from EWST management in connection
with efforts to enhance EWR operations. State and federal income taxes decreased
in fiscal 1997 to approximately $154,000 from $169,000 in fiscal 1996, due to
lower pre-tax income.
For fiscal 1996, Energy West Resources' (EWR) net income was approximately
$285,000 compared to $427,000 for fiscal 1995, primarily due to lower margins
experienced by its gas marketing operations. Although margins were lower than
1995, EWR's sales volumes have increased 34%. EWR expenses were also higher
than 1995 because of power marketing investigations, salary and expenses for an
EWR specific employee, increased direct charges and overheads allocated to EWR
from EWST management in connection with efforts to enhance EWR operations.
Montana Sun, Inc.
For fiscal 1997, Montana Sun's net income was approximately $100,000 as
compared to $46,000 for fiscal 1996, due primarily to the sale of mutual fund
investments at a capital gain.
For fiscal 1996, Montana Sun's net income was approximately $46,000 as
compared to $51,000 for fiscal 1995.
29
Liquidity and Capital Resources
The Company's operating capital needs, as well as dividend payments and
capital expenditures, are generally funded through cash flow from operating
activities, short-term borrowing and liquidation of temporary cash investments.
Historically, to the extent cash flow has not been sufficient to fund capital
expenditures, the Company has borrowed short-term or issued equity securities to
fund capital expansion projects or reduce short-term borrowing.
The Company's short-term borrowing requirements vary according to the
seasonal nature of its sales and expense activity. The Company has greater need
for short-term borrowing during periods when internally generated funds are not
sufficient to cover all capital and operating requirements, including costs of
gas purchases and capital expenditures. In general, the Company's short-term
borrowing needs for purchases of gas inventory and capital expenditures are
greatest during the summer months and the Company's short-term borrowing needs
for financing of customer accounts receivable are greatest during the winter
months. In addition during the past three years, the Company has used
short-term borrowing to finance the acquisition of propane operations and LNG
for West Yellowstone Gas. Short-term borrowing utilized for construction or
property acquisitions generally has been on an interim basis and converted to
long-term debt and equity when it becomes economical and feasible to do so.
At June 30, 1997, the Company had $19,000,000 in bank lines of credit, of
which $11,380,000 had been borrowed under the credit agreement. The short-term
borrowings bear a daily weighted average interest rate of 8% as of June 30,
1997.
The Company used net cash in operating activities for fiscal 1997 of
approximately $901,000 as compared to net cash provided by operating activities
of approximately $606,000 for fiscal 1996. This increase in cash used in
operating activities of approximately $1,507,000 was primarily due to higher
working capital requirements of approximately $1,686,000 due to the following:
1) increased purchases of natural gas inventory of approximately $3,078,000, 2)
lower accounts payable of approximately $100,000 primarily due to decreased gas
purchases, partially offset by a decrease in utility unrecovered gas costs of
approximately $100,000 due to gas tracker increases in fiscal 1997 in the Great
Falls and Cody divisions, lower accounts receivable of approximately $520,000
due to increased receivables in fiscal 1996 from 1995 due to increased gas
trading activity of approximately $142,000, Wyo L-P Gas wholesale increased
receivables of approximately $126,000, with the balance of receivables up
$126,000 due to colder weather in fiscal 1996 than 1995 in the Great Falls, Cody
and Broken Bow divisions, whereas the weather in fiscal 1997 was approximately
the same as fiscal 1996 and receivables were down approximately $84,000 from
fiscal 1996. Reduced prepaid items of approximately $607,000, primarily related
to a $500,000 prepaid gas contract commitment made in fiscal 1996 reduced
working capital requirements. In addition other assets and liabilities increased
working capital by approximately $262,000, due to the following: a change in
refundable income tax payments from fiscal 1997 to fiscal 1996 increasing cash
by $60,000, incentives paid in fiscal 1996 for fiscal 1995 were higher than
incentives paid in fiscal 1997 increasing cash by approximately $496,000, offset
partially by an increase in rate case costs in fiscal 1997 from fiscal 1996
resulting in a decrease in cash of approximately $221,000 and a $62,000 decrease
in cash related to a decrease in employee benefits from fiscal 1996 to fiscal
1997.
Higher net income of approximately $26,000, higher depreciation and amortization
costs of $59,000 and higher deferred income taxes of approximately $231,000,
reduced cash used in operating activities, offset partially by an increase in
the gain and deferred gain on the sale of assets of approximately $37,000 and
the gain on sale of marketable securities of approximately $ 100,000.
30
Cash used in investing activities was approximately $2,819,000 in fiscal
1997, as compared to approximately $3,989,000 in fiscal 1996, a decrease of
approximately $1,170,000 primarily due to lower construction expenditures for
capital projects of approximately $1,384,000 and the proceeds from the sale of
marketable equity securities of approximately $274,000, increased proceeds from
contributions in aid of construction of approximately $140,000, partially offset
by reduced proceeds from the sale of property, plant and equipment of
approximately $400,000, because of the sale-leaseback of the Payson, Arizona
properties in fiscal 1996 and an investment of $250,000 in a financing operation
of the American Gas Association. Cash provided by financing activities was
approximately $3,100,000 in fiscal 1997, as compared to approximately $3,740,000
in fiscal 1996, a decrease of approximately $640,000 primarily due to an
increase in dividends paid of approximately $228,000, increased principal
payments on notes payable of approximately $350,000, reduced sale of common
stock through the Company's Dividend Reinvestment Plan and the Company's
Incentive Stock Option Plan of approximately $68,000, partially offset by
reduced principal payments on long-term debt of approximately $45,000.
The Company generated net cash from operating activities for fiscal 1996 of
approximately $606,000 as compared to $3,605,000 for fiscal 1995. This change
from fiscal 1995 is attributed to a $246,000 decrease in net income, a reduction
in accounts payable of approximately $1,000,000, an increase in recoverable
costs of gas purchases and prepaid gas of approximately $1,627,000 and other
miscellaneous working capital changes of approximately $1,170,000 offset by
approximately $491,000 increase in deferred income taxes, an increase in gas
inventory of approximately $470,000 and an increase in accounts receivable of
approximately $80,000. Cash used in investing activities was approximately
$3,989,000 for fiscal 1996, as compared to $4,274,000 for fiscal 1995. Capital
expenditures for fiscal 1996 was approximately $4,591,000, primarily due to
system expansion in Payson, Arizona and all other areas and continued expansion
of the West Yellowstone system. Partially offsetting these capital expenditures
were proceeds received from a sale lease back in Payson, Arizona of
approximately $525,000, proceeds from the sale of property, plant and equipment
of $27,000 and proceeds from contributions in aid of construction of
approximately $63,000.
Capital expenditures of the Company are primarily for expansion and
improvement of its gas utility properties. To a lesser extent, funds are also
expended to meet the equipment needs of the Company's operating subsidiaries and
to meet the Company's administrative needs. The Company's capital expenditures
were approximately $3.2 million in fiscal 1997 and approximately $4.6 million
for fiscal 1996 and $4.7 million in fiscal 1995. During fiscal 1997,
approximately $1.7 million has been expended for the construction and
maintenance of the natural gas systems in Great Falls, Cascade and West
Yellowstone, Montana and Cody, Wyoming and approximately $1.2 million had been
expended for gas system expansion projects for new subdivisions in the Broken
Bow division's service area in Arizona and approximately $400,000 for additions
to the propane operations of the Company in Wyoming, Montana and Arizona.
Capital expenditures are expected to be approximately $2.8 million in fiscal
1998, including approximately $783,000 for continued expansion for the Broken
Bow division, with approximately $1.3 million for maintenance and other special
system expansion projects in the Great Falls, West Yellowstone and Cody
divisions and the balance of approximately $700,000 for the Company's propane
operations in the three states it serves. The Company continues to evaluate
opportunities to expand its existing businesses from time to time.
The major factors which will affect the Company's future results include
general and regional economic conditions, weather, customer retention and
growth, the ability to meet competitive pressures and to contain costs, changes
in the competitive environment in the Company's non-regulated segment, the
adequacy and timeliness of rate relief, cost recovery and necessary regulatory
approvals, and continued access to capital markets.
31
The regulatory structure which has historically embraced the gas industry
has been in the process of transition. Legislative and regulatory initiatives,
at both the federal and state levels, are designed to promote competition and
will continue to impose additional pressure on the Company's ability to retain
customers and to maintain current rate levels. The changes in the gas industry
have allowed commercial and industrial customers to negotiate their own gas
purchases directly with producers or brokers. To date, the changes in the gas
industry have not had a negative impact on earnings or cash flow of the
Company's regulated segment.
The accounts and rates of the Company's regulated segment are subject, in
certain respects, to the requirements of the Montana, Wyoming and Arizona public
utilities commissions. As a result, the Company's regulated segment maintains
its accounts in accordance with the requirements of those regulators. The
application of generally accepted accounting principles by the Company's
regulated segments differ in certain respects from application by the
non-regulated segment and other non-regulated businesses. The regulated segment
prepares its financial statements in accordance with Statement of Accounting
Standards No. 71 --"Accounting for the Effects of Certain Types of Regulation"
(SFAS 71). In general, SFAS 71 recognizes that accounting for rate-regulated
enterprises should reflect the relationship of costs and revenues. As a result,
a regulated utility may defer recognition of cost (a regulatory asset) or
recognize an obligation (a regulatory liability) if it is probable that, through
the rate-making process, there will be a corresponding increase or decrease in
revenues. Accordingly, the Company has deferred certain costs, which will be
amortized over various periods of time. The costs deferred are further
described in the Company's financial statements and the notes thereto. To the
extent that collection of such costs or payment of liabilities is no longer
probable as a result of changes in regulation and/or the Company's competitive
position, the associated regulatory asset or liability will be reversed with a
charge or credit to income. If the Company's regulated segment were to
discontinue the application of SFAS 71, the accounting impact would be an
extraordinary, non-cash charge to operations that could be material to the
financial position and results of operation of the Company. However, the
Company is unaware of any circumstances or events in the foreseeable future that
would cause it to discontinue the application of SFAS 71.
SEC Ratio of Earnings to Fixed Charges
For the twelve months ended June 30, 1997, 1996 and 1995, the Company's
ratio of earnings to fixed charges was 2.11, 2.28 and 3.01 times, respectively.
Fixed charges include interest related to long-term debt, short-term borrowing,
certain lease obligations and other current liabilities.
Inflation
Capital intensive businesses, such as the Company's natural gas operations,
are significantly affected by long-term inflation. Neither depreciation charges
against earnings nor the rate-making process reflect the replacement cost of
utility plant. However, based on past practices of regulators, these businesses
will be allowed to recover and earn on the actual cost of their investment in
the replacement or upgrade of plant. Although prices for natural gas may
fluctuate, earnings are not impacted because gas cost tracking procedures
semi-annually balance gas costs collected from customers with the costs of
supplying natural gas. The Company believes that the effects of inflation, at
currently anticipated levels, will not significantly affect results of
operations.
32
Accounting for Income Taxes
Effective July 1, 1993, the Company changed its method of accounting for
income taxes from the deferred method to the liability method required by SFAS
No. 109, ACCOUNTING FOR INCOME TAXES. The cumulative effect of adopting
Statement No. 109 created a regulatory asset and a regulatory liability for
regulated operations, representing the anticipated effects on regulated rates
charged to customers which will result from the adoption of Statement No. 109.
For the Year ended June 30, 1997, changes in certain assets and liabilities
resulted in an increase in regulatory assets of $43,109 and a decrease in
regulatory liabilities of $13,160 for regulated entities, resulting in ending
balances of $487,027 and $148,961, respectively.
Deferred income taxes reflect the net tax effects of temporary differences
between the carrying amounts of assets and liabilities for financial reporting
purposes and the amounts used for income tax purposes. See Note 5 to the
Consolidated Financial Statements for additional information.
Postretirement Benefits Other Than Pensions
The Company adopted, effective July 1, 1993, SFAS No. 106, "Employers'
Accounting for Postretirement Benefits Other Than Pensions." This standard
requires that the projected future cost of providing postretirement benefits be
recognized as an expense as employees render service rather than when paid.
Effective for fiscal year 1994, the Company modified its plan for these benefits
and has elected to pay eligible retirees (post 65 years of age) $125 per month
in lieu of contracting for health and life insurance benefits. The amount of
this payment is fixed and will not increase with medical trends or inflation.
The Company's transition obligation at June 30, 1997 and 1996 was $313,200 and
$332,800, respectively, of which $271,500 in 1997 and $288,600 in 1996 is
related to the regulated utility operations. The transition obligation was
accrued as a deferred charge and will be amortized over 20 years. Substantially
all of the transition obligation is for the future cost of benefits to active
employees.
The Company made a change to the plan, effective July 1, 1996 allowing
pre-65 retirees and their spouses to remain on the same medical plan as active
employees by contributing 125% of the current COBRA rate to retain this
coverage. The increased liability from this change is $269,200. The prior
service obligation associated with this plan change at June 30, 1997 and 1996
was $251,300 and $269,200, respectively, of which $210,600 in 1997 and $225,600
in 1996 is related to regulated utility operations. The prior service
obligation was accrued as a deferred charge and will be amortized over fifteen
years. The Company expects regulators in Montana and Wyoming to allow recovery
of the additional costs associated with this plan change. The adoption of SFAS
No. 106 did not have a significant effect upon results of operations. See Note
4 to the Consolidated Financial Statements for additional information.
33
Environmental Issues
The Company owns property on which it operated a manufactured gas plant
from 1909 to 1928. The site is currently used as a service center where certain
equipment and materials are stored. The coal gasification process utilized in
the plant resulted in the production of certain by-products which have been
classified by the federal government and the State of Montana as hazardous to
the environment. Several years ago the Company initiated an assessment of the
site to determine if remediation of the site was required. That assessment
resulted in a submission to the Montana Department of Environmental Quality
(MDEQ) formerly known as Montana Department of Health and Environmental Science
("MDHES") in 1994. The Company has worked with the MDEQ since that time to
obtain the data that would lead to a remediation action acceptable to MDEQ. The
Company's environmental consultant filed the report with the MDEQ on June 11,
1997. MDEQ is evaluating the report and after completion of its review will
provide for public comment related to the remediation plan. Once the comment
period has lapsed and due consideration of any comments occurs, the plan can be
finalized. Assuming acceptance of the plan, remediation could be in place by
the fall of 1998.
At June 30, 1997 the costs incurred in evaluating this site have totalled
approximately $430,000. On May 30, 1995 the Company received an order from the
Montana Public Service Commission allowing for recovery of the costs associated
with evaluation and remediation of the site through a surcharge on customer
bills. As of June 30, 1997 that recovery mechanism had generated approximately
$410,000 or what had been expended. The Commission's decision calls for ongoing
review by the Commission of the costs incurred for this matter. The Company
intends to submit an application for such review when the remediation plan is
approved by the MDEQ.
Subsequent Event
The Company closed an $8,000,000 debt issuance on August 15, 1997. The net
proceeds received, after payment of issuance costs, were approximately
$7,600,000 and were used to pay down short-term debt. The interest rate for
these bonds is 7.5% for a term of fifteen years to be paid off by June 1, 2012.
34
Item 8. Financial Statements and Supplementary Data
Report of Independent Auditors
The Board of Directors
Energy West Incorporated
We have audited the accompanying consolidated balance sheets of Energy West
Incorporated and subsidiaries as of June 30, 1997 and 1996, and the related
consolidated statements of income, stockholders' equity, and cash flows for
each of the three years in the period ended June 30, 1997. Our audits also
included the financial statement schedule listed in the Index at Item 14(a).
These financial statements and schedule are the responsibility of the Company's
management. Our responsibility is to express an opinion on these financial
statements 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 consolidated financial position of Energy West
Incorporated and subsidiaries at June 30, 1997 and 1996, and the consolidated
results of their operations and their cash flows for each of the three years in
the period ended June 30, 1997, in conformity with generally accepted
accounting principles. Also, in our opinion, the related financial statement
schedule, when considered in relation to the basic financial statements taken
as a whole, presents fairly in all material respects, the information set forth
therein.
/s/ Ernst & Young LLP
Denver, Colorado
August 21, 1997
35
Energy West Incorporated and Subsidiaries
Consolidated Balance Sheets
June 30
1997 1996
-----------------------------
Assets
Current assets:
Cash and cash equivalents $ 148,665 $ 721,093
Marketable equity securities - 172,208
Accounts receivable, less allowances for
uncollectible accounts of $167,824
at June 30, 1996) 3,40,528 3,486,328
Natural gas and propane inventory 5,792,517 2,200,778
Materials and supplies 561,112 543,316
Prepayments and other 518,504 602,427
Refundable income tax payments 301,711 412,662
Recoverable costs of gas purchases 1,673,285 953,392
-----------------------------
Total current assets 12,398,322 9,092,204
Investments 257,560 12,476
Notes receivable due after one year 2,537 9,190
Property, plant and equipment 46,481,447 43,919,358
Less accumulated depreciation and amortization 19,083,667 17,829,528
-----------------------------
Net property, plant and equipment 27,397,780 26,089,830
Deferred charges:
Net unamortized debt issue costs 888,188 974,876
Regulatory assets for income taxes 487,027 443,918
Unrecognized postretirement obligation 564,500 332,800
Other regulated assets 532,481 296,526
Other nonregulated assets 356,454 242,853
-----------------------------
Total deferred charges 2,828,650 2,290,973
-----------------------------
Total assets $ 42,884,849 $ 37,494,673
-----------------------------
-----------------------------
36
June 30
1997 1996
-----------------------------
Capitalization and liabilities
Current liabilities:
Long-term debt due within one year $ 361,959 $ 348,044
Notes payable 11,380,000 7,175,000
Accounts payable--gas purchases 1,158,700 1,226,508
Accounts payable--other 562,854 826,885
Payable to employee benefit plans 512,773 508,890
Accrued vacation 344,863 327,897
Other current liabilities 519,796 420,954
Deferred income taxes--current 475,940 253,385
-----------------------------
Total current liabilities 15,316,885 11,087,563
Other:
Deferred income taxes 3,107,272 2,700,184
Deferred investment tax credits 481,779 502,841
Contributions in aid of construction 1,039,431 834,917
Accumulated postretirement obligation 867,919 507,386
Regulatory liability for income taxes 148,961 162,121
Deferred gain on sale-leaseback of assets 212,663 236,291
-----------------------------
Total other 5,887,275 4,961,539
Long-term debt (less amounts due within
one year) 9,683,755 10,045,714
Commitments and contingencies
Stockholders' equity:
Preferred stock--$.15 par value:
Authorized--1,500,000 shares;
Outstanding--none - -
Common stock--$.15 par value:
Authorized--3,500,000 shares;
Outstanding--2,357,470 shares
at June 30, 1996) 353,623 348,198
Capital in excess of par value 2,932,962 2,635,540
Retained earnings 8,710,349 8,416,119
-----------------------------
Total stockholders' equity 11,996,934 11,399,857
-----------------------------
Total capitalization 21,680,689 21,445,571
-----------------------------
Total capitalization and liabilities $ 42,884,849 $ 37,494,673
-----------------------------
-----------------------------
SEE ACCOMPANYING NOTES.
37
Energy West Incorporated and Subsidiaries
Consolidated Statements of Income
Year ended June 30
1997 1996 1995
----------------------------------------
Operating revenue:
Regulated utilities $ 26,882,248 $ 23,672,186 $ 24,363,446
Nonregulated operations 5,339,553 3,297,583 2,946,114
Gas trading 5,993,668 4,348,239 3,238,839
---------------------------------------
Total operating revenue 38,215,469 31,318,008 30,548,399
Operating expenses:
Gas purchased 19,136,723 14,972,454 16,116,688
Cost of gas trading 5,538,847 3,751,053 2,500,363
Distribution, general and 7,498,467 6,924,391 6,379,651
Maintenance 496,721 408,590 306,077
Depreciation and amortization 1,689,082 1,667,256 1,558,755
Taxes other than income 660,133 629,428 594,569
---------------------------------------
Total operating expenses 35,019,973 28,353,172 27,456,103
---------------------------------------
Operating income 3,195,496 2,964,836 3,092,296
Other income, net 325,334 214,902 174,878
---------------------------------------
Income before interest charges and
income taxes 3,520,830 3,179,738 3,267,174
Interest charges:
Long-term debt 700,484 709,872 735,813
Short-term and other 824,100 532,866 202,770
---------------------------------------
Total interest charges 1,524,584 1,242,738 938,583
---------------------------------------
Income before income taxes 1,996,246 1,937,000 2,328,591
Provision for income taxes 703,472 670,025 815,688
---------------------------------------
Net income $ 1,292,774 $ 1,266,975 $ 1,512,903
---------------------------------------
---------------------------------------
Net income per common share $ .55 $ .55 $ .68
---------------------------------------
---------------------------------------
SEE ACCOMPANYING NOTES.
38
Energy West Incorporated and Subsidiaries
Consolidated Statements of Stockholders' Equity
Capital in
Common Excess of Retained
Stock Par Value Earnings Total
-------------------------------------------------------
Balance at June 30, 1994 $ 328,722 $ 1,643,793 $ 7,420,447 $ 9,392,962
Exercise of stock options into 14,410
shares of common stock at $4.94 to
$8.75 per share 2,161 78,318 - 80,479
Sale of 36,720 shares of common stock at
$7.50 to $ 9.00 per share under the
Company's dividend reinvestment plan 5,508 293,529 - 299,037
Issuance of 11,535 shares of common
stock to ESOP at estimated fair value of
$9.00 per share 1,730 102,090 - 103,820
Net income for the year ended June 30,
1995 - - 1,512,903 1,512,903
Dividends on common stock--$.385 per share - - (856,443) (856,443)
-------------------------------------------------------
Balance at June 30, 1995 338,121 2,117,730 8,076,907 10,532,758
Exercise of stock options into 13,680
shares of common stock at $4.875 to $7.125
per share 2,052 72,918 - 74,970
Sale of 37,611 shares of common stock
at $8.00 to $ 9.50 per share under the
Company's dividend reinvestment plan 5,642 320,158 - 325,800
Issuance of 15,889 shares of common
stock to ESOP at estimated fair value of
$8.00 per share 2,383 124,734 - 127,117
Net income for the year ended June
30, 1996 - - 1,266,975 1,266,975
Dividends on common stock--$.405 per
share - - (927,763) (927,763)
-------------------------------------------------------
Balance at June 30, 1996 348,198 2,635,540 8,416,119 11,399,857
Exercise of stock options into 980
shares of common stock at $6.50 to $7.13
per share 147 6,773 - 6,920
Sale of 20,692 shares of common
stock at $8.38 to $8.50 per share under the
Company's dividend reinvestment plan 3,104 171,466 _ 174,570
Issuance of 14,490 shares of common stock to 119,183
ESOP at an estimated value of $8.38 per share 2,174 - 121,357
Net income for the year ended June - - 1,292,774 1,292,774
30, 1997
Dividends on common stock--$.425 per share - - (998,544) (998,544)
-------------------------------------------------------
Balance at June 30, 1997 $ 353,623 $ 2,932,962 $ 8,710,349 $11,996,934
-------------------------------------------------------
-------------------------------------------------------
SEE ACCOMPANYING NOTES.
39
Energy West Incorporated and Subsidiaries
Consolidated Statements of Cash Flows
Year ended June 30
1997 1996 1995
------------------------------------------
Operating activities
Net income $ 1,292,774 $ 1,266,975 $ 1,512,903
Adjustments to reconcile net income
to net cash provided by (used in)
operating activities:
Depreciation and amortization 1,893,368 1,833,511 1,777,559
Gain on sale of assets (24,484) (11,406) (4,174)
Gain on sale of marketable equity
securities (100,526) - -
Investment tax credit (21,062) (21,062) (21,062)
Deferred gain on sale of assets (23,628) - -
Deferred income taxes 629,643 399,205 4,197
Changes in operating assets and
liabilities:
Accounts receivable 83,800 (443,725) (415,072)
Natural gas and propane
inventory (3,591,739) (514,074) (987,081)
Accounts payable (331,839) (218,153) 778,999
Recoverable costs of gas
purchases (719,893) (827,982) 275,556
Prepaid gas 83,923 (523,212) -
Other assets and liabilities (71,364) (333,878) 682,896
------------------------------------------
Net cash provided by (used in) operating
activities (901,027) 606,199 3,604,721
Investing activities
Construction expenditures (3,207,200) (4,590,609) (4,705,868)
Increase in investments (250,000) - -
Restricted deposit - - 204,550
Proceeds from sale of assets 153,716 552,160 79,749
Proceeds from sale of marketable equity
securities 273,572 - -
Increase in marketable equity securities - (20,958) (12,171)
Collection of long-term notes
receivable 6,653 6,794 78,737
Proceeds from contributions in aid
of construction 204,514 63,215 81,177
------------------------------------------
Net cash used in investing activities (2,818,745) (3,989,398) (4,273,826)
40
Energy West Incorporated and Subsidiaries
Consolidated Statements of Cash Flows (continued)
Year ended June 30
1997 1996 1995
------------------------------------------
Financing activities
Proceeds from long-term debt $ - $ - $ 117,808
Payment of long-term debt (361,959) (407,032) (335,000)
Proceeds from notes payable 32,512,000 20,965,000 19,926,854
Repayment of notes payable (28,307,000) (16,410,000) (18,625,000)
Sale of common stock 6,920 74,970 80,479
Dividends paid (702,617) (474,846) (453,586)
------------------------------------------
Net cash provided by financing
activities 3,147,344 3,748,092 711,555
------------------------------------------
Net increase (decrease) in cash
and cash equivalents (572,428) 364,893 42,450
Cash and cash equivalents at
beginning of year 721,093 356,200 313,750
------------------------------------------
Cash and cash equivalents at
end of year $ 148,665 $ 721,093 $ 356,200
------------------------------------------
------------------------------------------
Supplemental disclosures of cash
flow information:
Cash paid for:
Interest $ 1,528,441 $ 1,242,035 $ 942,221
Income taxes 169,546 498,461 870,327
Noncash financing activities:
Dividend reinvestment plan 174,570 325,800 299,037
ESOP shares issued 121,357 127,117 103,820
SEE ACCOMPANYING NOTES.
41
Energy West Incorporated and Subsidiaries
Notes to Consolidated Financial Statements
June 30, 1997
1. PRINCIPAL ACCOUNTING POLICIES
GENERAL
Energy West Incorporated (the "Company") operates principally in a single
business segment as a distributor of natural gas and propane to residential and
commercial customers. Natural gas and propane vapor distribution operations
(regulated utilities) are regulated by the Montana Public Service Commission
("MPSC"), the Wyoming Public Service Commission ("WPSC") and the Arizona
Corporation Commission ("ACC"). Accordingly, most of the Company's accounting
policies are subject to the requirements set forth in the Federal Energy
Regulatory Commission's Uniform System of Accounts. In some cases, because of
the rate- making process, these accounting policies differ from those used by
nonregulated operations. Bulk propane distribution is a nonregulated
operation.
Consolidated Subsidiaries
The Company's wholly-owned nonregulated subsidiaries, Energy West Resources,
Inc. ("EWR"), Montana Sun, Inc. ("Montana Sun") and Rocky Mountain Fuels, Inc.
("RMF"), are included in the consolidated financial statements. The results of
operations of these subsidiaries constitute all of the Company's nonregulated
operations. All significant intercompany accounts and transactions have been
eliminated in consolidation.
EWR is a gas marketing operation. Its principal assets are capitalized storage
field costs and inventory. EWR primarily markets gas to large industrial
customers (businesses using over 60,000 Mcf of natural gas annually). In
fiscal year 1998, EWR will be able to market to commercial customers with
annual consumptions of 5,000 Mcf.
Montana Sun's operating activities consist of commercial real estate
development. Its significant assets consist of real estate held for future
sale.
RMF is a bulk retail and wholesale liquid propane sales operation. Its
principal assets include bulk storage and customer tanks, delivery trucks and
related equipment.
Use of Estimates
The preparation of financial statements in conformity with generally accepted
accounting principles requires management to make estimates and assumptions
that affect the
42
Energy West Incorporated and Subsidiaries
Notes to Consolidated Financial Statements (continued)
1. Principal Accounting Policies (continued)
amounts reported in the financial statements and accompanying notes. Actual
results could differ from those estimates.
Natural Gas and Propane Inventory
Natural gas inventory and propane inventory are stated at the lower of weighted
average cost or net realizable value except for Great Falls Gas, which is
stated at the rate approved by the MPSC, which includes transportation costs.
Recoverable Costs of Gas Purchases
Differences between the costs of gas approved by regulators in the Company's
rate structure and actual gas costs are accounted for as a current asset or
liability, as applicable. These differences are recovered or refunded, as
applicable, in future periods by adjustment of the Company's rates.
Property, Plant and Equipment
Additions to property, plant and equipment are recorded at original cost when
placed in service. Depreciation and amortization are recorded on a straight-
line basis over estimated useful lives or the units-of-production method, as
applicable, at various rates averaging approximately 3.70%, 3.93% and 4.15%
during the years ended June 30, 1997, 1996 and 1995, respectively. During the
fourth quarter of 1997 the Company reduced accumulated depreciation, which
lowered depreciation expense by $109,000 due to a pending rate order by the
Arizona Corporation Commission related to regulated operations in Arizona. The
Commission requested that the Company change the estimated depreciation rates
on mains, meters, services and regulators from 3.75% to 3.25% to be in
accordance with the rate case filed in 1981. During the fourth quarter of
1996, the estimated useful lives for certain propane properties were increased
from twelve and fifteen years to twenty years to better reflect their estimated
useful lives. This change in estimate reduced depreciation expense by
approximately $83,000 in 1996.
Oil and Gas Activities
Oil and gas operations are accounted for under the successful efforts method.
Exploratory drilling costs are capitalized pending determination of proved
reserves; all other exploration costs are expensed. All development and lease
acquisition costs are
43
1. Principal Accounting Policies (continued)
capitalized. Provision for depreciation and amortization, including estimated
future dismantlement and restoration costs, is determined on a field-by-field
basis using the units-of-production method. All oil and gas properties were
sold on January 1, 1997 with no material gain or loss.
Marketable Equity Securities
Marketable equity securities are classified as available-for-sale securities.
Investments
The Company is entering into various joint venture agreements. When the Company
has the ability to exercise significant influence over the operations of these
joint ventures (generally when its investment exceeds 20%), they are recorded
as equity investments. Investments of less than 20% are recorded at cost.
Gas Trading
The Company's business activities include the buying and selling of natural gas.
The Company recognizes revenue and costs on gas trading transactions when gas
is delivered to the purchaser.
Debt Issuance and Reacquisition Costs
Debt premium, discount and issuance expenses are amortized over the life of each
issue. Debt reacquisition costs for refinanced debt are amortized over the
remaining life of the new debt.
Consolidated Statements of Cash Flows
For purposes of these statements, all highly liquid investments with original
maturities of three months or less are considered to be cash equivalents.
Financial Instruments
All of the Company's financial instruments requiring fair value disclosure were
recognized in the consolidated balance sheet as of June 30, 1997. Except for
long-term
44
Energy West Incorporated and Subsidiaries
Notes to Consolidated Financial Statements (continued)
1. Principal Accounting Policies (continued)
debt, their carrying values approximate the estimated fair values.
Descriptions of the methods and assumptions used to reach this conclusion are
as follows:
Cash and cash equivalents, temporary cash investments, accounts receivable,
accounts payable, and payable to employee benefit plans: These financial
instruments have short maturities, or are invested in financial instruments
with short maturities.
Notes receivable: These notes generally relate to energy conservation
incentive programs, some of which bear favorable interest rates compared to
market for similar risks. However, due to the relatively small balances of
these notes, any differences between carrying value and fair value are
immaterial.
Notes payable: Represent lines of credit, with maturities of a year or less,
bearing interest at current market rates.
The fair value of the Company's long-term debt, based on quoted market prices
for the same or similar issues, is approximately 101% of the carrying value.
Earnings Per Share
Earnings per common share were computed based on the weighted average number of
common shares outstanding and common stock equivalents, if dilutive.
The weighted average number of such shares at June 30 was 2,356,624 in 1997,
2,298,734 in 1996, and 2,235,413 in 1995.
In February 1997, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 128, EARNINGS PER SHARE. The overall
objective of Statement 128 is to simplify the calculation of earnings per share
("EPS") and achieve comparability with the recently issued International
Accounting Standard No. 33, EARNINGS PER SHARE. Statement 128 is effective for
both interim and annual financial statements for periods ending after December
15, 1997. Earlier application is not permitted. As a result, calendar year
end companies will first report on the new EPS basis in the fourth quarter
ending December 31, 1997. Subsequent to the effective date, all prior-period
EPS amounts (including EPS information in interim financial statements,
45
1. PRINCIPAL ACCOUNTING POLICIES (CONTINUED)
earnings summaries, and selected financial data) are required to be restated to
conform to the provisions of Statement 128. Under Statement 128, primary EPS
will be replaced with a new, simpler calculation called BASIC EPS. Basic EPS
will be calculated by dividing income available to common stockholders (i.e.,
net income less preferred stock dividends) by the weighted average common
shares outstanding. Thus, in the most significant change in current practice,
options, warrants, and convertible securities will be excluded from the
calculation. Further, contingently issuable shares will be included in basic
EPS only if all the necessary conditions have been satisfied by the end of the
period and it is only a matter of time before they are issued. Basic EPS under
Statement 128 will result in higher earnings per share because common stock
equivalents will not be included. Thus, the basic EPS calculation will be less
complex and easier to prepare. The Company has not calculated basic earnings
per share at June 30, 1997, but will adopt this standard in the second quarter
of fiscal 1998.
STOCK-BASED COMPENSATION
The Company has elected to follow Accounting Principles Board Opinion ("APB")
No. 25, ACCOUNTING FOR STOCK ISSUED TO EMPLOYEES (the intrinsic value method),
for its stock options rather than the alternative fair value method provided
for by SFAS No. 123, ACCOUNTING FOR STOCK-BASED COMPENSATION. Accounting for
stock options using APB No. 25 results in no compensation expense to the
Company because the exercise price for the stock options equals the market
price of the underlying stock on the date of the grant.
EFFECTS OF REGULATION
The regulatory structure which has historically embraced the gas industry has
been in the process of transition. Legislative and regulatory initiatives, at
both the federal and state levels, are designed to promote competition and will
continue to impose additional pressure on the Company's ability to retain
customers and to maintain current rate levels. The changes in the gas industry
have allowed commercial and industrial customers to negotiate their own gas
purchases directly with producers or brokers. To date, the changes in the gas
industry have not had a negative impact on earnings or cash flows of the
Company's regulated segment.
46
1. PRINCIPAL ACCOUNTING POLICIES (CONTINUED)
The accounts and rates of the Company's regulated segment are subject, in
certain respects, to the requirements of the Montana, Wyoming and Arizona
public utilities commissions. As a result, the Company's regulated segment
maintains its accounts in accordance with the requirements of those regulators.
The application of generally accepted accounting principles by the Company's
regulated segments differs in certain respects from application by the
nonregulated segment and other nonregulated businesses. The regulated segment
prepares its financial statements in accordance with Statement of Financial
Accounting Standards No. 71, ACCOUNTING FOR THE EFFECTS OF CERTAIN TYPES OF
REGULATION ("SFAS 71"). In general, SFAS 71 recognizes that accounting for
rate-regulated enterprises should reflect the relationship of costs and
revenues. As a result, a regulated utility may defer recognition of cost (a
regulatory asset) or recognize an obligation (a regulatory liability) if it is
probable that, through the rate-making process, there will be a corresponding
increase or decrease in revenues. Accordingly, the Company has deferred certain
costs, which will be amortized over various periods of time. The costs
deferred are further described in the Company's financial statements and the
notes thereto. To the extent that collection of such costs or payment of
liabilities is no longer probable as a result of changes in regulation and/or
the Company's competitive position, the associated regulatory asset or
liability will be reversed with a charge or credit to income. If the Company's
regulated segment were to discontinue the application of SFAS 71, the
accounting impact would be an extraordinary, noncash charge to operations that
could be material to the financial position and results of operations of the
Company.
However, the Company is unaware of any circumstances or events in the
foreseeable future that would cause it to discontinue the application of SFAS
71.
All regulatory assets have been formally approved by the applicable regulator,
although other than environmental cleanup costs, no return on assets is allowed
by the regulators.
The Company uses the lives for depreciation as defined by the regulators, which
approximate the economic lives for generally accepted accounting principles.
47
1. PRINCIPAL ACCOUNTING POLICIES (CONTINUED)
RECLASSIFICATIONS
Certain reclassifications have been made to the fiscal 1996 and 1995
consolidated financial statements to conform to the fiscal 1997 presentation.
2. NOTES PAYABLE
At June 30, 1997, the Company maintained two lines of credit totaling
$19,000,000. One line is for $11,000,000 with interest calculated at the
London Interbank Offering Rate ("LIBOR") plus 1/5 percent, expiring January 2,
1998. The other is for $8,000,000 with interest calculated at prime less 1/4
percent, expiring January 15, 1998. A total of $11,380,000, $7,175,000 and
$2,620,000 had been borrowed under the line of credit agreements at June 30,
1997, 1996 and 1995, respectively. Borrowings on lines of credit, based upon
daily loan balances, averaged $9,390,334, $6,166,380 and $2,397,175 during the
years ended June 30, 1997, 1996 and 1995, respectively. The maximum borrowings
outstanding on these lines at any month end were $11,380,000, $9,415,000 and
$4,983,000 during these same periods. The daily weighted average interest rate
was 8.0%, 8.5% and 8.2% for the years ended June 30, 1997, 1996 and 1995,
respectively. Management expects both lines of credit to be renewed for
another year.
3. LONG-TERM DEBT OBLIGATIONS
Long-term debt consists of the following:
JUNE 30
1997 1996
---------------------------
Series 1993 notes payable $ 7,800,000 $ 7,800,000
Industrial development revenue obligations:
Series 1992A 655,000 935,000
Series 1992B 1,575,000 1,635,000
Other 15,714 23,758
---------------------------
Total long-term obligations 10,045,714 10,393,758
Less portion due within one year 361,959 348,044
---------------------------
Long-term obligations due after one year $ 9,683,755 $10,045,714
---------------------------
---------------------------
3. LONG-TERM DEBT OBLIGATIONS (CONTINUED)
48
SERIES 1993 NOTES PAYABLE
On June 24, 1993, the Company issued $7,800,000 of Series 1993 unsecured notes
bearing interest at rates ranging from 6.20% to 7.60% (6.20% at June 30, 1997),
payable semiannually on June 1 and December 1 of each year, commencing on
December 1, 1993. Maturity dates begin in 1999 and extend to 2013. At the
Company's option, beginning June 1, 2003, notes maturing subsequent to 2003 may
be redeemed prior to maturity, in whole or part, at redemption prices declining
from 104% to 100% of face value, plus accrued interest.
INDUSTRIAL DEVELOPMENT REVENUE OBLIGATIONS
On September 15, 1992, Cascade County, Montana (the County) issued two
Industrial Development Revenue Obligations, the Series 1992A Bonds for
$1,700,000 and Series 1992B Bonds for $1,800,000. The Series 1992A and Series
1992B Bonds are unsecured; however, loan agreements are maintained with the
Company in the same amounts. Both the Series 1992A and Series 1992B Bonds
require annual principal payments on October 1 and semiannual interest payments
on April 1 and October 1 of each year beginning in 1993. The Series 1992A
Bonds have a final maturity in 1999 and bear interest at rates ranging from
3.25% to 5.30%. The Series 1992B bonds have a final maturity in 2012 and bear
interest at rates ranging from 3.35% to 6.50%.
AGGREGATE ANNUAL MATURITIES
IDR OBLIGATIONS
FISCAL SERIES -------------------- TOTAL
YEAR ENDING 1993 SERIES SERIES LONG-TERM
JUNE 30 NOTES 1992A 1992B OTHER OBLIGATIONS
- --------------------------------------------------------------------------------
1998 $ - $295,000 $ 60,000 $ 6,959 $ 361,959
1999 165,000 175,000 65,000 8,032 413,032
2000 175,000 185,000 70,000 723 430,723
2001 370,000 - 75,000 - 445,000
2002 390,000 - 75,000 - 465,000
Thereafter 6,700,000 - 1,230,000 - 7,930,000
--------------------------------------------------------------
7,800,000 655,000 1,575,000 15,714 10,045,714
Less current
portion - 295,000 60,000 6,959 361,959
--------------------------------------------------------------
$7,800,000 $360,000 $1,515,000 $ 8,755 $ 9,683,755
--------------------------------------------------------------
--------------------------------------------------------------
49
3. LONG-TERM DEBT OBLIGATIONS (CONTINUED)
The Company's long-term debt obligation agreements contain various covenants
including: limiting total dividends and distributions made in the immediately
preceding 60-month period to aggregate consolidated net income for such period,
restricting senior indebtedness, limiting asset sales, and maintaining certain
financial debt and interest ratios.
4. RETIREMENT PLANS
The Company has a defined contribution pension plan (the Plan) which
covers substantially all of the Company's employees. Under the Plan, the
Company contributes 10% of each participant's eligible compensation. Total
contributions to the Plan for the years ended June 30, 1997, 1996 and 1995 were
$392,868, $383,018 and $336,589, respectively.
The Company adopted, effective July 1, 1993, SFAS No. 106, EMPLOYERS' ACCOUNTING
FOR POSTRETIREMENT BENEFITS OTHER THAN PENSIONS. This standard requires that
the projected future cost of providing postretirement benefits be recognized as
an expense as employees render service rather than when paid. Effective for
fiscal year 1994, the Company modified its plan for these benefits and has
elected to pay eligible retirees (post-65 years of age) $125 per month in lieu
of contracting for health and life insurance benefits. The amount of this
payment is fixed and will not increase with medical trends or inflation. The
Company's transition obligation at June 30, 1997 and 1996 was $313,200 and
$332,800, respectively, of which $271,500 in 1997 and $288,600 in 1996 is
related to the regulated utility operations. The transition obligation was
accrued as a deferred charge and will be amortized over 20 years.
Substantially all of the transition obligation is for the future cost of
benefits to active employees.
The Company made a change to the plan, effective July 1, 1996, allowing pre-65
retirees and their spouses to remain on the same medical plan as active
employees by contributing 125% of the current COBRA rate to retain this
coverage. The increased liability from this change is $269,200. The prior
service obligation associated with this plan change at June 30, 1997 and 1996
was $251,300 and $269,200, respectively, of which $210,600 in 1997 and $225,600
in 1996 is related to regulated utility operations. The prior service
obligation was accrued as a deferred charge and will be amortized over fifteen
years. The Company expects regulators in Montana and Wyoming to allow
recovery of the additional costs associated with this plan change.
50
4. RETIREMENT PLANS (CONTINUED)
The incremental annual increases in consolidated expenses due to adoption of
SFAS No. 106 were $126,400, $70,900 and $71,200 in fiscal years 1997, 1996 and
1995, respectively. Included in these amounts were $101,900 in 1997, $58,100
in 1996 and $62,600 in 1995 relating to regulatory operations. The MPSC
allowed recovery of these costs beginning on November 4, 1997 for the utility
operations in Montana. Management believes it is probable that its regulators
in Wyoming will allow recovery of these costs based upon recent industry rate
decisions addressing this issue. The Company has established a VEBA trust fund
and is contributing to that trust the annual expense of the plan. The balance
in that trust after benefit payments in fiscal year 1997 is $141,900.
The following table presents the amounts recognized at June 30, 1997 and 1996 in
the consolidated financial statements.
1997 1996
---------------------------
Accumulated postretirement benefit:
Retirees $125,700 $128,500
Fully eligible active plan participants 86,500 80,500
Other active plan participants 604,200 522,900
---------------------------
816,400 731,900
Net unrecognized gains 51,519 44,686
---------------------------
$867,919 $776,586
---------------------------
---------------------------
Net periodic postretirement benefit cost:
Service cost $ 42,100 $ 19,300
Interest cost 52,000 32,000
Actual return on plan assets (3,200) (1,500)
Amortization of transition obligation 19,600 19,600
Net amortization and deferral 17,900 -
Deferred asset gain (loss) (2,000) -
---------------------------
Net periodic postretirement benefit cost $126,400 $ 69,400
---------------------------
---------------------------
51
4. RETIREMENT PLANS (CONTINUED)
The weighted-average discount rate used in determining the accumulated
postretirement benefit obligation at both June 30, 1997 and 1996 was 7.5
percent. The weighted-average annual assumed rate of increase in the per
capita cost of covered benefits (i.e., health care cost trend rate) is 10.0
percent for the 1997-98 fiscal year and is assumed to decrease gradually to 5.5
percent after 5 years and remain at that level thereafter. The weighted-
average health care cost trend rate was 11.0 percent for the 1996-97 fiscal
year and was assumed to decrease gradually to 5.5 percent after 6 years and
remain at that level thereafter.
The health care cost trend rate assumption has a significant effect on the
amounts reported. For example, increasing the assumed health care cost trend
rate by one percentage point in each year would increase the accumulated
postretirement benefit obligation as of June 30, 1997 by $51,000, and the
aggregate of interest and service cost for the year ended June 30, 1997 by
$7,900.
5. INCOME TAX EXPENSE
Effective July 1, 1993, the Company changed its method of accounting for income
taxes from the deferred method to the liability method required by FASB
Statement No. 109, ACCOUNTING FOR INCOME TAXES. The cumulative effect of
adopting Statement No. 109 created a regulatory asset and a regulatory
liability for regulated operations, representing the anticipated effects on
regulated rates charged to customers which will result from the adoption of
Statement No. 109. For the year ended June 30, 1997, changes in certain assets
and liabilities resulted in an increase in regulatory assets of $43,109 and a
decrease in regulatory liabilities of $13,160 for regulated entities, resulting
in ending balances of $487,027 and $148,961, respectively.
Deferred income taxes reflect the net tax effects of temporary differences
between the carrying amounts of assets and liabilities for financial reporting
purposes and the amounts used for income tax purposes.
52
5. INCOME TAX EXPENSE (CONTINUED)
Significant components of the Company's deferred tax assets and liabilities as
of June 30, 1997 and 1996 are as follows:
1997 1996
----------------------------
Deferred tax assets:
Allowance for doubtful accounts $ 36,187 $ 54,065
Unamortized investment tax credit 149,182 162,343
Contributions in aid of construction 204,222 115,876
Other nondeductible accruals 200,990 189,935
Deferred gain on sale of assets 84,853 95,900
Other 51,973 47,093
----------------------------
Total deferred tax assets 727,407 665,212
Deferred tax liabilities:
Customer refunds payable 657,459 399,255
Property, plant and equipment 3,268,078 2,908,836
Unamortized debt issue costs 187,443 201,635
Unamortized deferred rate case costs 109,540 -
Covenant not to compete 84,798 89,041
Other 3,301 20,014
----------------------------
Total deferred tax liabilities 4,310,619 3,618,781
----------------------------
Net deferred tax liabilities $3,583,212 $2,953,569
----------------------------
----------------------------
53
5. INCOME TAX EXPENSE (CONTINUED)
Income tax expense consists of the following:
YEAR ENDED JUNE 30
1997 1996 1995
--------------------------------------
Current income taxes:
Federal $202,356 $244,777 $705,420
State 31,477 21,819 120,074
--------------------------------------
Total current income taxes 233,833 266,596 825,494
Deferred income taxes (benefits):
Tax depreciation in excess of book 364,262 341,217 179,794
Book amortization in excess of tax (29,900) (35,958) (56,981)
Recoverable cost of gas purchases 255,130 322,479 (98,479)
Regulatory surcharges (70,955) (44,830) -
Deferred gain (loss) on
sale of assets 9,428 (95,900) -
Contributions in aid of
construction (88,347) - -
Deferred rate case costs 93,287 - -
Environmental study cleanup costs - - 20,539
Other 7,022 (25,362) 17,813
--------------------------------------
Total deferred income taxes 539,927 461,646 62,686
Investment tax credit, net (21,062) (21,062) (21,062)
--------------------------------------
Total income taxes $752,698 $707,180 $867,118
--------------------------------------
--------------------------------------
Income taxes--operations $703,472 $670,025 $815,688
Income taxes--other income 49,226 37,155 51,430
--------------------------------------
Total income taxes $752,698 $707,180 $867,118
--------------------------------------
--------------------------------------
54
5. INCOME TAX EXPENSE (CONTINUED)
Income tax expense from operations differs from the amount computed by applying
the federal statutory rate to pre-tax income for the following reasons:
1997 1996 1995
--------------------------------------
Tax expense at statutory rate - 34% $702,989 $666,930 $799,582
State income tax, net of federal tax 47,084 44,710 77,377
Amortization of deferred investment
tax credits (21,062) (21,062) (21,062)
Other 23,687 16,602 11,221
--------------------------------------
Total income taxes $752,698 $707,180 $867,118
--------------------------------------
--------------------------------------
6. REGULATED AND NONREGULATED OPERATIONS
Summarized financial information for the Company's regulated utility and
nonregulated nonutility operations (before intercompany eliminations between
regulated and nonregulated primarily consisting of gas sales from nonregulated
to regulated entities, intercompany accounts receivable, accounts payable,
equity, and subsidiary investment) is as follows:
55
6. Regulated and Nonregulated Operations (continued)
JUNE 30, 1997
ELIMINATIONS
REG. NONREG. CONSOL.
----------------------------------------------------------
CAPITAL EXPENDITURES $ 1,676,401 $1,530,799 $ 3,207,200
----------------------------------------------------------
----------------------------------------------------------
PROPERTY, PLANT AND EQUIPMENT, NET
REGULATED UTILITIES $23,739,918 $23,739,918
NONREGULATED PROPANE $3,069,236 3,069,236
OIL AND GAS OPERATIONS 120,762 120,762
REAL ESTATE HELD FOR INVESTMENT 467,864 467,864
----------------------------------------------------------
TOTAL PROPERTY PLANT AND EQUIPMENT 23,739,918 3,657,862 27,397,780
CURRENT ASSETS 9,820,008 2,790,148 $ (211,834) 12,398,322
OTHER ASSETS 3,823,659 337,086 (1,071,998) 3,088,747
----------------------------------------------------------
TOTAL ASSETS $37,383,585 $6,785,096 $(1,283,832) $42,884,849
----------------------------------------------------------
----------------------------------------------------------
EQUITY $ 9,411,406 $3,656,421 $(1,070,893) $11,996,934
LONG-TERM DEBT 7,952,072 1,731,683 9,683,755
CURRENT LIABILITIES 14,791,018 218,876 306,991 15,316,885
DEFERRED INCOME TAXES 2,746,547 360,725 3,107,272
OTHER LIABILITIES 2,482,542 817,391 (519,930) 2,780,003
----------------------------------------------------------
TOTAL CAPITALIZATION AND LIABILITIES $37,383,585 $6,785,096 $(1,283,832) $42,884,849
----------------------------------------------------------
----------------------------------------------------------
JUNE 30, 1996
ELIMINATIONS
REG. NONREG. CONSOL.
----------------------------------------------------------
CAPITAL EXPENDITURES $ 3,910,000 $ 680,609 $ 4,590,609
----------------------------------------------------------
----------------------------------------------------------
PROPERTY, PLANT AND EQUIPMENT, NET
REGULATED UTILITIES $22,362,130 $22,362,130
NONREGULATED PROPANE $2,971,174 2,971,174
OIL AND GAS OPERATIONS 274,352 274,352
REAL ESTATE HELD FOR INVESTMENT 482,173 $ 1 $ 482,174
----------------------------------------------------------
TOTAL PROPERTY PLANT AND EQUIPMENT 22,362,130 3,727,699 1 26,089,830
CURRENT ASSETS 7,663,566 2,385,186 (956,548) 9,092,204
OTHER ASSETS 3,669,404 590,542 (1,947,307) 2,312,639
----------------------------------------------------------
TOTAL ASSETS $33,695,100 $6,703,427 $(2,903,854) $37,494,673
----------------------------------------------------------
----------------------------------------------------------
EQUITY $ 9,303,596 $3,168,260 $(1,071,999) $11,399,857
LONG-TERM DEBT 8,257,090 1,788,624 10,045,714
CURRENT LIABILITIES 10,452,787 1,192,271 (557,495) 11,087,563
DEFERRED INCOME TAXES 3,207,968 270,816 (778,600) 2,700,184
OTHER LIABILITIES 2,473,659 283,456 (495,760) 2,261,355
----------------------------------------------------------
TOTAL CAPITALIZATION AND LIABILITIES $33,695,100 $6,703,427 $(2,903,854) $37,494,673
----------------------------------------------------------
----------------------------------------------------------
1997 1996
REG. NONREG. ELIMINATIONS CONSOL. REG. NONREG.
------------------------------------------------------------------------------------------
OPERATING REVENUE $26,882,248 $9,143,144 $(3,803,591) $32,221,801 $23,672,186 $ 4,510,942
GAS TRADING REVENUE 5,993,668 5,993,668 4,348,239
------------------------------------------------------------------------------------------
TOTAL OPERATING REVENUE 26,882,248 15,136,812 (3,803,591) 38,215,469 23,672,186 8,859,181
GAS PURCHASED 16,192,875 6,747,439 (3,803,591) 19,136,723 13,646,178 2,539,635
COST OF GAS TRADING 5,538,847 5,538,847 3,751,053
DISTRIBUTION, GENERAL & ADMINISTRATIVE 5,857,321 1,641,146 7,498,467 5,578,188 1,346,203
MAINTENANCE 403,723 92,998 496,721 348,123 60,467
DEPRECIATION AND AMORTIZATION 1,348,733 340,349 1,689,082 1,359,339 307,917
TAXES OTHER THAN INCOME 545,448 114,685 660,133 523,768 105,660
------------------------------------------------------------------------------------------
OPERATING INCOME $ 2,534,148 $ 661,348 $ - $ 3,195,496 $ 2,216,590 $ 748,246
------------------------------------------------------------------------------------------
------------------------------------------------------------------------------------------
1996 1995
ELIMINATIONS CONSOL. REG. NONREG. ELIMINATIONS CONSOL.
------------------------------------------------------------------------------------------
OPERATING REVENUE $(1,213,359) $26,969,769 $24,363,446 $4,077,768 $(1,131,655) $27,309,55
GAS TRADING REVENUE 4,348,239 3,238,839 3,238,839
------------------------------------------------------------------------------------------
TOTAL OPERATING REVENUE (1,213,359) 31,318,008 24,363,446 7,316,607 (1,131,655) 30,548,398
GAS PURCHASED (1,213,359) 14,972,454 15,077,466 2,170,877 (1,131,655) 16,116,688
COST OF GAS TRADING 3,751,053 2,500,363 2,500,363
DISTRIBUTION, GENERAL & ADMINISTRATIVE 6,924,391 5,130,220 1,249,431 6,379,651
MAINTENANCE 408,590 304,677 1,400 306,077
DEPRECIATION AND AMORTIZATION 1,667,256 1,205,758 352,997 1,558,755
TAXES OTHER THAN INCOME 629,428 494,338 100,230 594,568
------------------------------------------------------------------------------------------
OPERATING INCOME $ - $ 2,964,836 $ 2,150,987 $ 941,309 $ - $ 3,092,296
------------------------------------------------------------------------------------------
------------------------------------------------------------------------------------------
56
7. Stock Options and Ownership Plans
Stock Options
There are two Incentive Stock Option Plans which provide for grants of options
to purchase up to 200,000 shares of the Company's common stock to key
employees. The option price may not be less than 100% of the common stock fair
market value on the date of grant (110% of the fair market value if the
employee owns more than 10% of the Company's outstanding common stock). These
options may not have a term exceeding five years.
Since the Company has elected to use APB No. 25, pro forma information regarding
net income and earnings per share is required by SFAS No. 123 as if the Company
had accounted for its stock options under the fair value method of that
statement. For the fiscal year ended June 30, 1996, no options were granted
and for the fiscal year ended June 30, 1997 only a limited number of options
were granted, resulting in no material impact on pro forma net income or
earnings per share. The fair value for these options was estimated at the date
of grant using the Black-Scholes option pricing model with the following
weighted average assumptions:
1997
---------
Risk-free interest rate--length of exercise period 6.3%
Dividend yields 5.2%
Volatility factors of the expected market price of
the Company's common stock .187
Weighted-average expected life of the employee
stock options 5 years
The weighted-average fair value of options granted $1.20
The Black-Scholes option valuation model was developed for use in estimating the
fair value of traded options which have no vesting restrictions and are fully
transferable. In addition, option valuation models require the input of highly
subjective assumptions, including the expected stock price volatility. Because
the Company's stock options have characteristics significantly different from
those of traded options, and because changes
57
7. Stock Options and Ownership Plans (continued)
in the subjective input assumptions can materially affect the fair value
estimate, in management's opinion, the existing models do not necessarily
provide a reliable single measure of the fair value of the Company's stock
options.
A summary of the activity under the plans is as follows:
Weighted
Average
Number of Exercise
Shares Price
-----------------------------
Fiscal 1997
Outstanding at July 1, 1996 75,708 $7.244
Granted 20,000 $8.406
Exercised (980) $7.061
Expired (5,300) $6.783
-------------
89,428 $7.533
-------------
-------------
Outstanding at June 30, 1997
At June 30, 1997
Exercisable 89,428
Available for grant 8,400
Fiscal 1996
Outstanding at July 1, 1995 90,588 $6.976
Granted -
Exercised (13,680) $5.480
Expired (1,200) $6.500
-------------
75,708 $7.244
-------------
-------------
Outstanding at June 30, 1996
At June 30, 1996
Exercisable 75,708
Available for grant 6,052
Fiscal 1995
Outstanding at July 1, 1994 106,948 $6.625
Granted 5,000 $9.125
Exercised (14,410) $5.585
Expired (6,950) $6.008
-------------
Outstanding at June 30, 1995 90,588 $6.976
-------------
-------------
At June 30, 1995
Exercisable 90,588
Available for grant 29,652
58
7. Stock Options and Ownership Plans (continued)
Employee Stock Ownership Plan
In 1984, the Company established an Employee Stock Ownership Plan ("ESOP") which
covers most of the Company's employees. The unleveraged ESOP receives cash
contributions from the Company each year as determined by the Board of
Directors and will buy shares of the Company's common stock from either the
Company or the open market at the then current price per share. The ESOP has
no allocated shares, committed-to-be-released shares or suspense shares at the
balance sheet dates. In addition, there are no unearned shares and there is no
repurchase obligation. The Company has contributed and recognized as expense
$100,615, $121,400 and $129,367 for the years ended June 30, 1997, 1996 and
1995, respectively. During the years ended June 30, 1997, 1996 and 1995, the
ESOP acquired 14,490 shares at $8.38 per share, 15,889 shares at $8.00 per
share and 11,535 shares at $9.00 per share, respectively.
8. Operating Lease
The Company leases a building in Cody, Wyoming. The lease expires on June 30,
2005. Future minimum rental payments will be approximately $72,000 per year
from fiscal 1996 through fiscal 2005, for total future minimum lease payments
of $576,000. Rental expenses related to this lease were $73,599, $73,808 and
$70,133 in fiscal years 1997, 1996 and 1995, respectively.
9. Gain on Sale-Leaseback of Assets
On June 28, 1996, one of the Company's nonregulated subsidiaries sold real
property, consisting of land and office and warehouse buildings, for $525,000
in cash. Concurrent with the sale, the Company leased the property back for a
period of ten years at an annual rental of $51,975. The initial ten-year term
of the lease is extended for two successive five-year periods unless the
Company provides at least six months notice prior to the end of either the
initial term or the first successive five-year term.
59
9. Gain on Sale-Leaseback of Assets (continued)
The Company does not have an option to repurchase the real property. However,
should the lessor have a bona fide third-party offer, the Company has the right
of first refusal to buy the land and buildings under the same terms and
conditions. As a result, the transaction has been recorded as a sale,
resulting in a deferred gain of $236,000, which is amortized ratably into
income over the initial lease term. The balance of the deferred gain at June
30, 1997 is $213,000. The land, buildings and related accounts are no longer
recognized in the accompanying financial statements.
The future minimum lease payments under the terms of the related lease agreement
require the payment of $51,975 per year from fiscal 1997 through fiscal 2006,
for total future minimum lease payments of $467,775.
10. Commitments and Contingencies
Commitments
The Company has entered into long-term, take or pay natural gas supply contracts
which expire beginning in 1998 and ending in 2007. The contracts generally
require the Company to purchase specified minimum volumes of natural gas at a
fixed price which is subject to renegotiation every two years. Current prices
per Mcf for these contracts range from $1.60 to $1.65. Based on current
prices, the minimum take or pay obligation at June 30, 1997 for each of the
next five years and in total is as follows:
Fiscal Year
-----------
1998 $1,564,513
1999 1,260,913
2000 822,913
2001 555,713
2002 164,250
Thereafter 821,250
-----------
Total $5,189,552
-----------
-----------
Natural gas purchases under these contracts for the years ended June 30, 1997,
1996 and 1995 approximated $1,100,000, $3,530,000, and $4,000,000,
respectively.
60
10. Commitments and Contingencies (continued)
On August 1, 1997, the Company entered into a take or pay propane contract which
expires July 31, 1998. The contract generally requires the Company to purchase
all propane quantities produced by a propane producer in Wyoming (approximately
250,000 gallons per month) tied to the Worland, Wyoming spot price.
Environmental Contingency
The Company owns property on which it operated a manufactured gas plant from
1909 to 1928. The site is currently used as a service center where certain
equipment and materials are stored. The coal gasification process utilized in
the plant resulted in the production of certain by-products which have been
classified by the federal government and the State of Montana as hazardous to
the environment. Several years ago the Company initiated an assessment of the
site to determine if remediation of the site was required. That assessment
resulted in a submission to the Montana Department of Environmental Quality
("MDEQ"), formerly known as the Montana Department of Health and Environmental
Science ("MDHES"), in 1994. The Company has worked with the MDEQ since that
time to obtain the data that would lead to a remediation action acceptable to
the MDEQ. The Company's environmental consultant filed the report with the
MDEQ on June 11, 1997. The MDEQ is evaluating the report and after completion
of its review will provide for public comment related to the remediation plan.
Once the comment period has lapsed and due consideration of any comments
occurs, the plan can be finalized. Assuming acceptance of the plan,
remediation could be in place by the fall of 1998.
At June 30, 1997, the costs incurred in evaluating this site have totaled
approximately $430,000. On May 30, 1995, the Company received an order from
the Montana Public Service Commission allowing for recovery of the costs
associated with evaluation and remediation of the site through a surcharge on
customer bills. As of June 30, 1997, that recovery mechanism had generated
approximately $410,000, or about what had been expended. The Commission's
decision calls for ongoing review by the Commission of the costs incurred for
this matter. The Company will submit an application for review by the
Commission when the remediation plan is approved by the MDEQ.
61
11. Regulatory Matters
On July 8, 1996, the Company filed a general rate case with the MPSC requesting
a revenue increase for its Great Falls Gas operations. The MPSC approved an
interim general rate increase on November 4, 1996 of $275,000 with a final
order approved on April 7, 1997 for an additional $20,000. The Company
filed for a general rate increase for Broken Bow (a regulated utility
subsidiary in Payson, Arizona) on September 26, 1996 with the ACC. The ACC
will make its final ruling by August 27, 1997. It is expected the ACC will
approve a rate increase of approximately $390,000.
12. Financial Instruments and Risk Management
For the fiscal year ended June 30, 1996, the Company was a party to a gas
financial hedge agreement for its regulated operations. Under this agreement,
the Company is required to pay the counterparty (an entity making a market in
gas futures) a cash settlement equal to the excess of an agreed upon fixed
price over a stated index price for gas purchases. The Company receives cash
from the counterparty when the fixed price is below the stated index price.
This hedge agreement was made to minimize exposure to gas price fluctuations.
This price differential had no impact on earnings, because the effect of the
difference is included in gas costs and adjusted to recoverable cost of gas
purchases for any differences between the cost of gas allowed by the regulators
and the actual prices paid, including any financial hedge agreements.
62
12. Financial Instruments and Risk Management (continued)
For the fiscal year ended June 30, 1997, the Company is a party to three gas
hedge agreements for nonregulated operations. These agreements represent
approximately 95% of the supply required for those operations. The hedges
were made to minimize the Company's exposure to price fluctuations and to
secure a known margin for the purchase and resale of gas.
Fair
Index Price Value of
Volume Range for Contract Index Remaining
Fiscal Year (MMBTU Effective Termination Contract Fiscal Value at Price at Contract
Per Day) Date Date Price Year June 30 June 30 at June 30
------------------------------------------------------------------------------------------------------------
1996
---------
Hedge #1 5,000 11/1/95 10/31/96 $1.35 $.89 to $1.22 $830,250 $0.89 $547,350
1997
---------
Hedge #1 4,000 9/1/96 8/31/97 $1.03 $.88 to $2.11 $255,400 $1.19 $294,600
Hedge #2 400 9/1/96 8/31/97 $1.20 $.88 to $2.11 $ 29,800 $1.19 $ 29,500
Hedge #3 500 1/1/97 6/30/98 $2.08 $1.39 to $4.18 $379,600 $1.44 $262,800
In July 1997 the Company signed a gas hedge agreement beginning November 1, 1997
and ending March 31, 1998 for 5,000 MMBTU per day at $2.075 per MMBTU for one
of its regulated operations. This hedge was entered into to minimize the
Company's exposure to price fluctuations.
13. Subsequent Event
The Company closed an $8,000,000 debt issuance on August 15, 1997. The net
proceeds received, after payment of issuance costs, were approximately
$7,600,000, which were used to pay down short-term debt. The interest rate for
these bonds is 7.5%; principal repayment is due June 1, 2012.
63
Item 9. - CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
Not Applicable
64
PART III
Item 10. - DIRECTORS AND EXECUTIVE OFFICER OF THE REGISTRANT
Information concerning the directors and executive officers is included in Part
I, on pages 16 through 19. The information contained under the heading
"Election of Directors" in the Proxy Statement is incorporated herein by
reference in response to this item.
Item 11. - EXECUTIVE COMPENSATION
The information contained under heading "Executive Compensation" in the Proxy
Statement is incorporated herein by reference in response to this item.
Item 12. - SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information contained under the heading "Security Ownership of Certain
Beneficial Owners and Management" in the Proxy Statement is incorporated herein
by reference in response to this item.
Item 13. - CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information contained under the heading "Certain Transactions" in the Proxy
Statement is incorporated herein by reference in response to this item.
65
PART IV
Item 14. - EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8K
(a) 1. Financial Statements included in Part II, Item 8:
Report of Independent Auditors
Consolidated Balance Sheets
Consolidated Statements of Income
Consolidated Statements of Stockholders' Equity
Consolidated Statements of Cash Flows
Notes to Consolidated Financial Statements
2. Financial Statement Schedules included in Item 14 (d):
Schedule II - Valuation and Qualifying Accounts
All other schedules are omitted because they are not applicable or the required
information is shown in the financial statements or notes thereto.
3. Exhibits (See Exhibit Index on Page E-1)
(b) Reports on Form 8-K
none
(d) SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS
ENERGY WEST INC.
JUNE 30, 1997
Balance At Charged Write-Offs Balance
Beginning to Costs Net of at End of
Description of Period & Expenses Recoveries Period
- ---------- --------- ---------- ---------- ------
ALLOWANCE FOR
UNCOLLECTIBLE ACCOUNTS
Year Ended June 30, 1995 $189,291 $81,327 ($79,450) $191,168
Year Ended June 30, 1996 $191,168 $64,509 ($47,571) $208,106
Year Ended June 30, 1997 $208,106 $130,992 ($171,274) $167,824
66
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.
ENERGY WEST INCORPORATED
/S/ Larry D. Geske /s/ William J. Quast
- ------------------- ---------------------
Larry D. Geske, President and William J. Quast
Chief Executive Officer Vice-President, Treasurer,
and Chairman of the Board Controller and Assistant Secretary
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 and on the dates indicated.
/s/ Larry D. Geske 09/27/97
- ------------------- --------
Larry D. Geske
President and Chief Executive Date
Officer and Acting Chairman of the Board
/s/ Ian B. Davidson 09/27/97
- ------------------- --------
Ian B. Davidson Director Date
/s/ Thomas N. McGowen, Jr. 09/27/97
- -------------------------- --------
Thomas N. McGowen, Jr. Director Date
/s/ G. Montgomery Mitchell 09/27/97
- -------------------------- --------
G. Montgomery Mitchell Director Date
/s/ George D. Ruff 09/27/97
- ------------------ --------
George D. Ruff Director Date
/s/ David A. Flitner 09/27/97
- -------------------- --------
David A. Flitner Director Date
/s/ Dean South 09/27/97
- -------------- --------
Dean South Director Date
67
EXHIBIT INDEX
EXHIBITS
3.1 Restated Articles of Incorporation of the Company, as amended to date
(previously filed).
3.2 Bylaws of the Company, as amended to date (previously filed).
4.1 Form of Indenture (including form of Note) relating to the Company's Series
1993 Notes (incorporated by reference to Exhibit 4.1 to the Company's
Registration Statement on Form S-2, File No. 33-62680).
4.2 Loan Agreement, dated as of September 1, 1992, relating to the Company's
Series 1992A and Series 1992B Industrial Development Revenue Bonds
(incorporated by reference to Exhibit 4.2 to the Company's Registration
Statement on Form S-2, File No. 33-62680).
10.1 Credit Agreement dated as of January 18, 1995, by and between the
Company and Norwest Bank Great Falls, National Association (previously
filed).
10.2 Amendment dated April 17, 1996 to Credit Agreement dated as of January
18, 1995, by and between the Company and Norwest Bank Montana, National
Association (previously filed).
10.3 Amendment dated November 7, 1996 to Credit Agreement dated as of
January 18, 1995, the Company and Norwest Bank Montana, National Association
(previously filed).
10.4 Promissory Note dated November 7, 1996, issued to Norwest Bank Montana,
National Association (previously filed).
10.5 Credit Agreement dated as of February 12, 1997, by and between the Company
and First Bank Montana, National Association (previously filed).
10.6 Delivered Gas Purchase Contract dated February 23, 1997, as amended by
that Letter Amendment Amending Gas Purchase Contract dated March 9, 1982;
that Amendment to Delivered Gas Purchase Contract applicable as of March 20,
1986; that Letter Agreement dated December 18, 1986; that Letter Agreement
dated April 12, 1988; that Letter Agreement dated April 28, 1992; that
Letter Agreement dated March 14, 1996; that Letter Agreement dated April 15,
1996; a second Letter Agreement dated April 15, 1996; that Letter dated
February 18, 1997; and that Letter dated April 1, 1997, transmitting a
Notice of Assignment effective February 26, 1993 (previously filed).
10.7 Delivered Gas Purchase Contract dated December 1, 1985, as amended by
that Letter Agreement dated July 1, 1986; that Letter Agreement dated
November 19, 1987; that Letter Agreement dated December 1, 1988; that Letter
Agreement dated July 30, 1992; that Assignment Conveyance and Bill of Sale
effective as of January 1, 1993; that Letter Agreement dated March 8,,
1993; that Letter Agreement dated October 21, 1993; that Letter Agreement
dated October 18, 1994; that Letter Agreement dated January 30, 1995; that
Letter Agreement dated August 30, 1995; that Letter Agreement dated October 3,
1995; that Letter Agreement dated October 31, 1995; that Letter Agreement
dated December 21, 1995; that Letter Agreement dated April 25, 1996; that
Letter Agreement dated January 29, 1997; and that Letter dated April 11,
1997 (previously filed).
10.8 Natural Gas Sale and Purchase Agreement dated July 20, 1992 between
Shell Canada Limited and the Company, as amended by that Letter Agreement
dated August 23, 1993; that Amending Agreement effective as of November 1,
1994; and that Schedule A Incorporated Into and Forming a Part of That Natural
Gas Sale and Purchase Agreement, effective as of November 1, 1996 (previously
filed).
10.9 Employee Stock Ownership Plan Trust Agreement (incorporated by
reference to Exhibit 10.2 to Registrant's Registration Statement on Form S-1,
File No. 33-1672).
10.10 1992 Stock Option Plan (previously filed).
10.11 Form of Incentive Stock Option under the 1992 Stock Option Plan
(previously filed).
10.12 Management Incentive Plan (previously filed).
21.1 Subsidiaries of the Company (filed herewith).
23.1 Consent of Independent Auditors (filed herewith).
27.1 Financial Data Schedule (filed herewith).
E-1