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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, 2003
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
(Exact name of registrant as specified in its charter)
Montana 81-0141785
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
1 First Avenue South, Great Falls, Montana 59401
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code (406)-791-7500
Securities to be registered pursuant to Section 12(b) of the Act:
None
Securities registered pursuant to Section 12(g) of the Act:
Title of each class
Common Stock - Par Value $.15
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 [X].
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 [ ].
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Act). Yes [ ] No [X].
The aggregate market value of the voting stock held by non-affiliates of the
registrant as of December 31, 2002: Common Stock, $.15 Par Value - $19,044,030.
The number of shares outstanding of the registrant's classes of common stock as
of September 30, 2003: Common Stock, $.15 Par Value - 2,595,250 shares.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the proxy statement for the 2003 Annual Meeting of Shareholders are
incorporated by reference into Part III.
PART I
Item 1. - Business
General
Energy West, Incorporated (the "Company") is a regulated public
utility, with certain non-utility operations conducted through its subsidiaries.
The Company was originally incorporated in Montana in 1909. The Company's
regulated utility operations involve the distribution and sale of natural gas to
the public in and around Great Falls and West Yellowstone, Montana and Cody,
Wyoming, and the distribution and sale of propane to the public through
underground propane vapor systems in and around Payson, Arizona and Cascade,
Montana. The Company's West Yellowstone, Montana operation is supplied by
liquefied natural gas (LNG).
Certain non-regulated, non-utility operations are conducted by three
wholly-owned subsidiaries of the Company: Energy West Propane, Inc. (EWP);
Energy West Resources, Inc. (EWR); and Energy West Development, Inc. (EWD). EWP
is engaged in wholesale distribution of bulk propane in Wyoming, Arizona and
Montana, and is engaged in retail distribution of bulk propane in Arizona. EWR
markets gas and electricity in Montana and Wyoming, and owns certain natural gas
production properties in Montana. EWD owns two pipeline systems in Montana and
Wyoming, natural gas production properties in north central Montana and certain
other real property in Montana.
The Company's reporting segments are: Natural Gas Operations, Propane
Operations, EWR and Pipeline Operations. To reflect management and business
changes, the Company realigned its reporting segments effective July 1, 2002.
The Company's wholly owned subsidiary, Energy West Development, Inc. (EWD), owns
a renovated pipeline located in Wyoming and Montana. An application has been
granted by the Federal Energy Regulatory Commission (FERC) and EWD began
operations of this pipeline as a transmission pipeline on July 3, 2003. The
revenue and expenses associated with this transmission pipeline are included in
the "Pipeline Operations" segment. EWD also owns a gathering system pipeline in
Wyoming and recently purchased natural gas production reserves in north central
Montana. The revenue and expenses associated with EWD's gathering system
pipeline were reported as part of the "EWR" segment for periods prior to fiscal
year 2003. Beginning with fiscal year 2003, such revenue and expenses are
reported as part of the "Pipeline Operations" segment as are the revenues and
expenses associated with the recently purchased production properties. Also
beginning with fiscal year 2003, the operations of a regulated propane
distribution system located in Cascade, Montana are reported as part of the
"Natural Gas Operations" segment. The Cascade, Montana system was reported as
part of the Company's "Propane Operations" segment prior to fiscal year 2003.
Segment information for prior periods has been restated to reflect the
realignment of the Company's reporting segments.
Natural Gas Operations
The Company's primary business is the distribution and sale of natural
gas to residential, commercial and industrial customers. The Company's natural
gas operations consist of two divisions. The Energy West - Montana Division
serves customers with operations in Great
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Falls, West Yellowstone and Cascade, Montana. The Energy West - Wyoming Division
serves customers in and around Cody, Meeteetse and Ralston, Wyoming. Generally,
residential customers use natural gas for space heating and water heating,
commercial customers use natural gas 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 natural gas operations are generated
under tariffs regulated by the state utility commissions of Montana and Wyoming,
respectively. During fiscal year 2003 the Company filed applications for rate
increases for its Great Falls, Montana and Cody, Wyoming operations with the
Montana Public Service Commission (MPSC) and Wyoming Public Service Commission
(WPSC), respectively. Effective on December 15, 2002, the Company received
approval from the MPSC for an interim rate increase for the Great Falls, Montana
operation of approximately $600,000 which became final on June 15, 2003, with a
final rate increase approved for $687,000. Effective on June 1, 2003, the
Company received approval from the WPSC for a rate increase for the Cody,
Wyoming operation of approximately $721,000.
Energy West - Montana (EWM) Division
The EWM division provides natural gas service to customers in and
around Great Falls and West Yellowstone, Montana and provides propane through an
underground vapor system in Cascade, Montana. The division's service area has a
population of approximately 79,000 in the Great Falls area, 1,200 in the West
Yellowstone area and approximately 900 in the Cascade area.
The division has a franchise to distribute natural gas within the city
of Great Falls that expires in 2021. The division also provides natural gas
transportation service to certain customers who purchase natural gas from other
suppliers.
The following table shows the EWM division's revenues by customer class
for the fiscal year ended June 30, 2003 and the two preceding fiscal years:
Gas Revenues
(in thousands)
Years Ended June 30,
--------------------
2003 2002 2001
---- ---- ----
Residential $13,643 $17,563 $17,180
Commercial 8,383 10,443 9,935
Transportation 1,789 1,958 2,045
------- ------- -------
Total $23,815 $29,964 $29,160
------- ------- -------
Note: Revenues reduced in fiscal year 2003 compared to fiscal year
2002 due to the discontinuance of the surcharge to collect
unrecovered gas costs and lower volume sales due to warmer
than normal temperatures.
The following table shows the volumes of natural gas, expressed in
millions of cubic feet (MMcf) (measured at standard operating pressure) sold or
transported by the division for the fiscal year ended June 30, 2003 and the two
preceding fiscal years:
3
Gas Volumes
(MMcf)
Years Ended June 30,
--------------------
2003 2002 2001
---- ---- ----
Residential 2,267 2,417 2,513
Commercial 1,359 1,442 1,430
----- ----- -----
Total Gas Sales 3,626 3,859 3,943
===== ===== =====
Transportation 1,462 1,522 1,615
----- ----- -----
Note: The reduction in sales volumes in fiscal year 2003 compared to
fiscal year 2002 was due to warmer than normal temperatures experienced
in the Great Falls area.
The EWM division has approximately 173 transportation customers. No
customer of the EWM division accounted for more than 2% of the consolidated
revenues of the Company in fiscal 2003.
The operations of the EWM division are subject to regulation by the
MPSC. The MPSC regulates rates, adequacy of service, issuance of securities,
compliance with U.S. Department of Transportation Safety Regulations and other
matters.
In December 1998, the MPSC approved a proposed plan filed by the
Company (the "Plan") to allow customers to choose a natural gas supplier other
than the EWM division. The Plan allows customers to purchase natural gas from
other suppliers. Under the Plan, the EWM division continues to provide delivery
service to customers who purchase from other suppliers. Customers who do not
wish to choose another supplier may continue purchasing natural gas from the EWM
division.
The EWM division uses the NorthWestern Energy (NWE) pipeline
transmission system to transport supplies of natural gas for its core load. The
division also uses this pipeline capacity to provide transportation,
distribution and balancing services to customers who have chosen to obtain
natural gas from other suppliers. In 2000, the Company entered into a 10-year
transportation agreement with NWE that fixes the cost of pipeline and storage
capacity for the EWM division.
In October 2000, the Company filed its annual gas cost recovery
application for the EWM division with the MPSC. The MPSC granted interim rate
relief in December 2000. During late 2000, however, the EWM division's costs of
gas rose due to an increase in index prices, and as a result the Company amended
its application in February 2001. In response, the MPSC issued a second interim
order in March 2001 (which the MPSC made final in August 2001). This order
established a monthly cost tracking process under which the Company was required
to file for an increase or decrease in rates if natural gas costs change more
than $.10 per thousand cubic feet (Mcf) in any month, subject to an annual audit
of the unrecovered balance by the MPSC and Montana Consumer Counsel.
4
In May 2002, after fully recovering the previous increase in gas costs
experienced by the EWM division, the Company filed for a reduction in the rates
as required by the MPSC's order. In June 2002, the Company received approval
from the MPSC to reduce the rates charged by the EWM division effective July 1,
2002.
In September 2002, the Company filed an application with the MPSC
seeking an increase in annual utility rates for the Great Falls, Montana
operation. On December 15, 2002, the Company received from the MPSC an interim
increase in annual revenues in the amount of $600,000. The Company subsequently
entered into a stipulation with the Montana Consumer Counsel, the only other
party to the rate application investigation, for a permanent increase in the
amount of approximately $687,000. The permanent increase was approved by the
MPSC in the amount of $687,000 on June 15, 2003.
Energy West - Wyoming (EWW) Division
The EWW division provides natural gas service to customers in and
around Cody, Meeteetse and Ralston, Wyoming. This service area has a population
of approximately 12,000. The EWW division has a certificate of public
convenience and necessity granted by the WPSC for 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, 2003, the EWW division provided service to approximately 5,750
customers, including one industrial customer. The division also offers
transportation service for natural gas producers and other parties.
The following table shows the EWW division's revenues by customer class
for the fiscal year ended June 30, 2003 and the two preceding fiscal years:
Gas Revenues
(in thousands)
Years Ended June 30,
--------------------
2003 2002 2001
---- ---- ----
Residential $3,119 $3,434 $ 4,409
Commercial 2,591 3,035 3,512
Industrial 2,101 3,044 3,481
Transportation 301 346 447
------ ------ -------
Total $8,112 $9,859 $11,849
====== ====== =======
Note: Lower revenues were experienced in fiscal year 2003 compared to
fiscal year 2002 due to warmer than normal temperatures and reduced
sales to a large industrial customer, Celotex. The lower revenues in
fiscal year 2002 compared to fiscal year 2001 were the result of the
discontinuance of a surcharge to collect unrecovered gas costs.
The following table shows the volumes of natural gas, expressed in
millions of cubic feet (MMcf) (measured at standard operating pressure), sold by
the EWW division for the fiscal year ended June 30, 2003 and the two preceding
fiscal years:
5
Gas Volumes
(MMcf)
Years Ended June 30,
--------------------
2003 2002 2001
---- ---- ----
Residential 541 564 563
Commercial 531 550 521
Industrial 525 610 608
----- ----- -----
Total Gas Sales 1,597 1,724 1,692
===== ===== =====
Transportation 1,383 1,588 1,413
----- ----- -----
The EWW division's industrial customer, BPB America (dba Celotex), a
manufacturer of gypsum wallboard, purchases gas pursuant to a special industrial
tariff, which fluctuates with the volumes of gas sold and the cost of gas. In
fiscal year 2003 Celotex accounted for approximately 27% of the revenues of the
EWW division and approximately 3% of the consolidated revenues of the Company.
Celotex's business is cyclical and dependent on the level of national housing
starts. The division's sales to Celotex in fiscal year 2003 were approximately
14% less than fiscal year 2002.
EWR is the EWW division's primary supplier of natural gas, pursuant to
an 18 month agreement entered into in May of 2003.
The EWW division transports gas for third parties pursuant to a tariff
filed with and approved by the WPSC. The terms of the transportation tariff
(currently between $.08 and $.31) per Mcf are established by the WPSC.
The EWW division's revenues are generated under regulated tariffs
designed to recover a base cost of gas, administrative and operating expenses
and provide sufficient return to cover interest and profit. The division's
tariffs include a purchased gas adjustment clause which allows the division to
adjust its rates periodically to recover changes in gas costs from base gas
costs.
On December 24, 2002, the Company's Wyoming division filed an
application with the WPSC seeking an increase in annual utility rates. The WPSC
granted an annual rate increase of approximately $721,000 with an effective date
of June 1, 2003.
Propane Operations
The Company reports as a separate business segment the regulated
distribution of propane by the Company, and the unregulated distribution of
propane by the Company's wholly-owned subsidiary, Energy West Propane, Inc.
(EWP). The Company is engaged in the regulated distribution of propane through
its Energy West Arizona (EWA) division and unregulated distribution of propane
in Montana, Wyoming and Arizona through its Energy West Propane, Arizona, and
Rocky Mountain Fuels divisions.
6
Regulated Propane Operations
The EWA division distributes propane in the Payson, Arizona area. The
service area of the EWA division includes approximately 575 square miles and has
a population of approximately 31,000. The operations of the EWA division are
subject to regulation by the Arizona Corporation Commission (ACC), which
regulates rates, adequacy of service, and other matters. The EWA division's
properties include approximately 190 miles of underground distribution pipeline
and an office building leased from a third party. The division purchases its
propane supplies from EWP under terms reviewed periodically by the ACC. The EWA
division has approximately 7,400 customers. The division's principal competition
comes from bulk propane retailers who sell to customers who draw propane for use
from storage tanks located at their homes or businesses, rather than using
propane from the division's underground distribution system.
The following tables show the EWA division's revenues and propane
volumes by customer class for the fiscal year ended June 30, 2003 and the two
preceding fiscal years:
Regulated Propane Revenues
(in thousands)
Years Ended June 30,
--------------------
2003 2002 2001
---- ---- ----
Residential $3,729 $3,384 $3,530
Commercial 1,639 1,520 1,459
------ ------ ------
Total $5,368 $4,904 $4,989
====== ====== ======
Regulated Propane Volumes
(in thousands of gallons)
Years Ended June 30,
--------------------
2003 2002 2001
---- ---- ----
Residential 2,874 2,678 2,835
Commercial 1,070 1,012 1,063
----- ----- -----
Total Gas Sales 3,944 3,690 3,898
----- ----- -----
Unregulated Propane Operations
The Company's subsidiary Energy West Propane, Inc. (EWP) is engaged in
the bulk sale of propane through its three divisions: Energy West
Propane-Arizona, which serves the Payson, Arizona area; Energy West
Propane-Montana, which sells bulk propane in the Cascade County area,
surrounding Great Falls, Montana; and Rocky Mountain Fuels Wholesale which has
wholesale operations primarily in Montana and Arizona. EWP had 9,430 customers
as of June 30, 2003.
7
Energy West Propane - Arizona sells propane to residential and
commercial customers in the Payson, Arizona area.
EWP's wholesale division, Rocky Mountain Fuels Wholesale (RMF),
supplies propane for the Company's underground propane-vapor systems serving the
cities of Payson, Arizona and Cascade, Montana and surrounding areas. The
majority of RMF's Wyoming and Montana assets, including the Superior, Montana
terminal were sold on August 21, 2003 to Jack's Wholesale Propane, Inc. (an
affiliate of Northern Petro NGL Marketing Inc.) for approximately $1,370,000.
EWP faces competition from other propane distributors and suppliers of
alternative fuels that compete with propane. Competition is based primarily on
price and there is a high degree of competition with other propane distributors
in each of the Company's service areas.
The following tables show the revenues and volumes for unregulated
propane operations by customer class for the fiscal year ended June 30, 2003 and
the two preceding fiscal years:
Unregulated Propane Revenues
(in thousands)
Years Ended June 30,
--------------------
2003 2002 2001
---- ---- ----
Residential $1,348 $1,275 $1,421
Commercial 5,985 3,365 5,734
------ ------ ------
Total $7,333 $4,640 $7,155
====== ====== ======
Unregulated Propane Volumes
(in thousands of gallons)
Years Ended June 30,
--------------------
2003 2002 2001
---- ---- ----
Residential 912 901 921
Commercial 10,870 6,934 7,821
------ ----- -----
Total Gas Sales 11,782 7,835 8,742
------ ----- -----
EWR
The Company's wholly owned subsidiary, EWR, conducts certain marketing
and trading activities and wholesale distribution activities involving the sale
of natural gas and electricity in Montana and Wyoming.
Montana legislation enacted in 1997, and subsequent MPSC orders,
permitting open access on the NorthWestern Energy gas transportation and
electricity transmission system, and
8
other systems in Montana have presented opportunities for EWR to do business as
a broker of natural gas and electricity. Although EWR has concentrated its
efforts on industrial and large commercial customers, EWR began to market gas
and electricity to small commercial and residential customers in fiscal year
2000. EWR has from time to time entered into certain financial agreements that
hedge against the risks of fluctuation in prices of natural gas and electricity.
If the price obtained through such instruments is favorable or unfavorable
compared to subsequent market conditions, net earnings or losses can result from
such arrangements. See Item 7, "MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF CONSOLIDATED OPERATIONS--Derivatives and Risk
Management." During fiscal year 2003, EWR effectively exited the electricity
marketing business, with services currently provided only to one customer,
delivering approximately one MW pursuant to a contract that continues through
fiscal year 2005.
In order to provide a stable source of natural gas for a portion of its
requirements, in May 2002, EWR purchased a 56% interest in a group of producing
natural gas reserves located in northern Montana. EWR's portion of the estimated
daily gas production from the reserves is approximately 600,000 cubic feet (600
Mcf), or approximately 3% of EWR's present volume requirements. This production
gives EWR a natural hedge, due to fixed production expenses when market prices
of natural gas are above the costs of production. One of the other owners of a
partial interest in these reserves serves as the operator of the wells. As part
of the transaction, EWR received a $300,000 settlement in connection with
certain claims. The $300,000 was recorded as nonoperating income during the
fourth quarter of fiscal year 2002.
Pipeline Operations
Pipeline Operations was added as a new segment as of July 1, 2002. The
results of this segment reflect operation of natural gas gathering systems
placed into service in fiscal year 2001, and transferred from EWR to EWD. The
revenues and expenses associated with the pipeline gathering systems had
previously been reported as part of the EWR segment.
The Company's wholly owned subsidiary, Energy West Development, Inc.
(EWD), owns a renovated pipeline located in Wyoming and Montana. EWD began
operations of this pipeline as a transmission pipeline on July 3, 2003. The
revenue and expenses associated with this transmission pipeline will be included
in the "Pipeline Operations" segment.
In March 2003, EWD acquired a 75% ownership interest in natural gas
production properties located in northcentral Montana, which will provide a
portion of the gas requirements of EWR. EWD's portion of the estimated daily gas
production from these properties is approximately 350,000 cubic feet (350 Mcf),
or approximately 2% of EWR's current volume requirements.
Capital Expenditures
The Company conducts ongoing construction activities, in all of its
utility service areas, in order to support expansion, maintenance and
enhancement of its gas and propane pipeline systems. The Company also continues
to experience growth in its Pipeline Operations segment and purchased additional
natural gas production properties during fiscal year 2003. In fiscal years 2003,
2002 and 2001, total capital expenditures for the Company were approximately
9
$4,970,000, $6,442,000 and $3,276,000, respectively, including purchases of
natural gas production properties. Expenditures for fiscal year 2002 were higher
than usual due to the renovation of the transmission pipeline between Wyoming
and Montana and a by-pass loop around Cody, Wyoming.
Available Information
The internet address for the Company is: http://www.ewst.com. The
Company makes available, free of charge, on its internet website annual reports
on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and
additional filings of the Company filed or furnished pursuant to Section 13(a)
or 15(d) of the Exchange Act as soon as reasonably practicable after these
filings have been made with the SEC.
Competition
The principal competition faced by the Company in its distribution and
sales of natural gas is from suppliers of alternative fuels, including
electricity, oil, propane and coal. 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 generally
preferred the installation of gas heat. The Company estimates that approximately
97% of the homes and businesses in the Great Falls service area use natural gas
as their primary source for space heating fuel, approximately 93% use gas for
water heating and approximately 99% of the new homes built on, or near, the
Company's Great Falls service mains in recent years have selected natural gas as
their energy source.
The EWW division estimates that approximately 95% of the homes and
businesses in its 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 EWA division estimates that approximately 67% of the homes and
businesses adjacent to the division's distribution pipeline use the division's
propane for space heating or water heating. Studies show that approximately 90%
of new subdivisions within the division's distribution system are using propane
as their primary fuel source.
The principal competition faced by the Company and its subsidiaries in
the distribution and sale of propane is from electricity suppliers and other
propane distributors. Competition is based primarily on price and customer
service and there is a high degree of competition from other propane
distributors in all of the service areas.
EWR's principal competition is from other gas marketing firms doing
business in the State of Montana. As of July 1, 2003, EWR has successfully
exited the electricity marketing business with the exception of maintaining one
customer existing under a contract through fiscal year 2005.
10
Governmental Regulation
The Company's utility operations are subject to regulation by the MPC,
the WPSC, and the ACC. Such regulation plays a significant role in determining
the Company's return on equity. The commissions approve rates that are intended
to permit a specified rate of return on investment. The Company's tariffs allow
the cost of gas to be passed through to customers. The pass-through causes some
delay, however, between the time that gas costs are incurred by the Company and
the time that the Company recovers such costs from customers.
Seasonality
The business of the Company and its subsidiaries in all segments is
temperature-sensitive. In any given period, sales volumes reflect the impact of
weather, in addition to other factors, with colder temperatures generally
resulting in increased sales by the Company. The Company anticipates that this
sensitivity to seasonal and other weather conditions will continue to be
reflected in the Company's sales volumes in future periods.
Environmental Matters
The Company owns property on which it operated a manufactured gas plant
from 1909 to 1928. The site is currently used as an office facility for Company
field personnel and storage location for certain equipment and materials. 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 proposed remediation plan to the Montana Department of
Environmental Quality (MDEQ) 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. In the summer of 1999 the Company received final approval from the
MDEQ for its plan for remediation of soil contaminants. The Company has
completed its remediation of soil contaminants and in April of 2002 received a
closure letter from MDEQ approving the completion of such remediation program.
The Company and its consultants continue their work with the MDEQ
relating to the remediation plan for water contaminants. The MDEQ has
established regulations that allow water contaminants at a site to exceed
standards if it is technically impracticable to achieve them. Although the MDEQ
has not established guidance to attain a technical waiver, the U.S.
Environmental Protection Agency (EPA) has developed such guidance. The EPA
guidance lists factors which render mediations technically impracticable. The
Company has filed a request for a waiver respecting compliance with certain
standards with the MDEQ.
At June 30, 2003, the Company had incurred cumulative costs of
approximately $2,034,000 in connection with its evaluation and remediation of
the site. The Company also estimates that it will incur at least $60,000 in
additional expenses in connection with its investigation and remediation for
this site. On May 30, 1995, the Company received an order from the MPSC allowing
for recovery of the costs associated with the evaluation and
11
remediation of the site through a surcharge on customer bills. As of June 30,
2003, the Company had recovered approximately $1,443,000 through such
surcharges.
On April 15, 2003, the MPSC issued an Order to Show Cause Regarding the
Environmental Surcharge. The MPSC required the Company to show cause why it was
not in violation of the 1995 order by failing to seek renewal of the surcharge
at the conclusion of the initial two year recovery period. The Company responded
to the MPSC and an interim order has been issued by the MPSC suspending the
collection by the Company of the surcharge until further investigation can be
conducted and requiring a new application from the Company respecting this
surcharge. The Company has submitted its revised application and is awaiting
further MPSC action. The Company currently has an unrecovered balance of
$590,000 awaiting recovery through this mechanism. In the event that the MPSC
does not approve the Company's revised application, in addition to potentially
being unable to recover the unrecovered balance of $590,000, the Company could
be required to refund to customers a portion of the $1,443,000 previously
collected through surcharges.
Employees
The Company and its subsidiaries had an aggregate total of 131
employees as of June 30, 2003. Five of these employees were employed by EWR, 28
by the Company's Propane Operations, 85 were employed by the Company's Natural
Gas Operations and 13 individuals were employed at the corporate office. The
Company's Natural Gas Operations include 16 employees represented by two labor
unions. Contracts with each of these unions expired on June 30, 2003, and the
Company continues negotiations with the two labor unions. In July 2003, the
Company initiated a cost reduction program and reduced the total number of
Company employees to 125.
Executive Officers
The following table sets forth the names and ages of, and the positions
and offices within the Company presently held by, the executive officers of the
Company:
Name Age Position
John C. Allen 52 Interim President and Chief
Executive Officer
Tim A. Good 58 Vice-President and Manager
of Natural Gas Operations
Douglas R. Mann 56 Vice-President and Manager
of Energy West Propane Operations
JoAnn S. Hogan 37 Vice-President, Treasurer and
Secretary
12
Robert B. Mease 56 Vice-President and
Controller
James E. Morin 49 President of Energy West
Resources, Inc.
John C. Allen was appointed Interim President and Chief Executive Officer on
September 22, 2003. He joined the Company in 1986 as Corporate Counsel and
Secretary and was appointed General Counsel, Vice-President and Secretary of the
Company in 1992. Prior to joining Energy West he was Staff Attorney for the
Montana Consumer Counsel from 1979 to 1986.
Tim A. Good has been Vice-President of the Company and Manager of the Company's
Natural Gas Operations since July 1, 2000. He served as Vice President and
Division Manager of the EWW Division from 1988 to July 1, 2000.
Douglas R. Mann has been Vice-President and Manager of Energy West Propane
Operations since July 1, 2000. From February, 1999 until July 1, 2000, he served
as Vice-President and Manager of the EWA Division. From 1995 until July 1, 1999,
he served as Assistant Vice-President and Manager of the Arizona Division.
JoAnn S. Hogan was appointed Vice-President, Treasurer and Secretary on
September 25, 2003. From January 2002 until her most recent appointment she was
Assistant Vice-President and Treasurer of the Company. She served as Controller
from 2000 to 2002. From 1995 to 2000, she served in various financial capacities
for the Company including Assistant Controller and Tax Manager.
Robert B. Mease was appointed Vice-President and Controller on September 25,
2003. From February 2002, when joining the Company, until September 25, 2003, he
was Assistant Vice-President and Controller. From October 2000 to February 2002,
he served as a business consultant with Junkermier, Clark, Campanella & Stevens,
a public accounting firm. From 1998 to 2000 he was Vice-President and CFO of TMC
Sales, a steel manufacturer and wholesale distributor located in Seattle,
Washington. From 1994 to 1998, he was Vice-President of Finance for American
Agri-Technology, located in Great Falls, Montana.
James E. Morin was appointed President of Energy West Resources, Inc., a wholly
owned subsidiary of the Company in February of 2003. From July 2001 to February
2003, he served as Vice President of Electricity Marketing and from August 1997
to July 2001, he served as Manager of Industrial and Commercial Marketing for
Energy West Resources, Inc.
Item 2. - Properties
The Company owns and leases properties located in the following states:
Montana: In Great Falls, Montana, the Company owns a 9,000 square foot office
building, which serves as the Company's headquarters, and a 3,000 square foot
service and operating center (with various outbuildings) which supports
day-to-day maintenance and construction operations. The Company owns
approximately 400 miles of underground distribution lines ("mains"), and related
metering and regulating equipment in and around Great Falls, Montana.
13
In West Yellowstone, Montana, the Company owns an office building, and a
liquefied natural gas plant that provides natural gas through approximately 13
miles of underground mains owned by the Company. The Company owns approximately
10 miles of underground mains in the town of Cascade.
As of June 30, 2003, EWP owned several large bulk propane tanks to
serve the areas in and around the towns of Cascade and Superior, Montana. The
wholesale propane assets located in Superior, Montana, including the bulk
propane tanks, were sold on August 21, 2003.
During fiscal year 2002, EWR purchased a 56% ownership interest in
natural gas production properties in north central, Montana, that provide
approximately 600 Mcf of natural gas daily for resale.
At June 30, 2003, EWD owned approximately 30 acres of real property in
Great Falls, Montana. The property was sold on September 8, 2003, and EWD
realized a pre-tax gain of approximately $118,000. During fiscal year 2003, EWD
purchased a 75% ownership interest in natural gas production properties in north
central, Montana, that provide approximately 350 Mcf of natural gas daily for
resale.
Wyoming: In Cody, Wyoming, the Company leases office and service buildings for
the EWW division under long-term lease agreements. The Company owns
approximately 483 miles of transportation and distribution mains, and related
metering and regulating equipment, all of which are located in or around Cody,
Meeteetse and Ralston.
EWP owns two large bulk propane tanks, located in Cody, to serve its
customers in northern Wyoming. The wholesale propane assets located in Cody,
Wyoming were sold on August 21, 2003.
EWD owns two pipelines in Wyoming. One is currently being operated as a
gathering system. The other pipeline began operating as a natural gas interstate
transmission pipeline on July 3, 2003. The pipelines are located north of Cody,
Wyoming.
Arizona: The Company owns approximately 190 miles of distribution mains located
in and around the community of Payson. The Company owns five acres of land in
Payson, on which the Company maintains and operates a propane vapor system for
its operations in Payson. The Company leases an office building in Payson under
an agreement that expires in 2006. The Company has the right to extend the lease
for two successive five year periods. EWP owns several large bulk propane tanks
located in Pine, Strawberry, Payson and Starr Valley, which are used to serve
customers in those communities and surrounding areas.
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. The Company
utilizes various risk management strategies, including maintaining liability
insurance against certain risks, employee education and safety programs and
other processes intended to reduce liability risk.
14
In addition to other litigation referred to above, the Company or its
subsidiaries are involved in the following described litigation.
EWR has been involved in a lawsuit with PPL Montana, LLC (PPLM) which
was filed on July 2, 2001, and involved a wholesale electricity supply contract
between EWR and PPLM dated March 17, 2000 and a confirmation letter thereunder
dated June 13, 2000. On June 17, 2003, EWR and PPLM reached agreement on a
settlement of the lawsuit. Under the terms of the settlement, EWR paid PPLM a
total of $3,200,000, consisting of an initial payment of $1,000,000 on June 17,
2003, and a second payment of $2,200,000 on September 30, 2003, terminating all
proceedings in the case. EWR had established reserves in fiscal year 2001 of
approximately $3,032,000 to pay a potential settlement with PPLM and the
remaining $168,000 was charged to operating expenses in fiscal year 2003.
By letter dated August 30, 2002, the Montana Department of Revenue
(DOR) notified the Company that the DOR had completed a property tax audit of
the Company for the period January 1, 1997 through and including December 31,
2001, and had determined that the Company had under-reported its personal
property and that additional property taxes and penalties should be assessed.
On August 8, 2003, the Company reached agreement with the DOR to pay to
DOR $2,430,000 in back taxes (without interest or penalty) for tax years 1992
through and including 2002. The settlement amount will be paid in ten equal
annual installments of $243,000 on or before November 30 of each year beginning
November 30, 2003.
Under Montana law, the Company believes it is entitled to recover the
amounts paid in connection with the DOR settlement through future rate
adjustments without seeking approval from the MPSC. The amended rates will go
into effect on January 1 following the date of each tax payment. The amended
rate schedules must be filed with the MPSC on or before the effective date of
the changes in taxes paid and the commission has 45 days to act on the adjusted
rates submitted. If the commission determines that the rates were adjusted in
error, then refunds must be paid to the customers. The Company has established a
regulatory asset and a liability in the amount of $2,430,000.
Item 4. - Submission of Matters to a Vote of Security Holders
None
15
PART II
Item 5. - Market for Registrant's Common Equity and Related Stockholder Matters
Common Stock Prices and Dividend Comparison - Fiscal Years 2003 and 2002
Shares of the Company's Common Stock are traded on the Nasdaq National
Market under the symbol: "EWST." The following table sets forth the high and low
bid prices for the Company's common stock. These prices reflect inter-dealer
prices, without retail mark-up, markdown or commission, and may not necessarily
represent the actual transactions.
Price Range -- Fiscal Year 2003 High Low
- --------------------------------------- --------------- -----------------
First Quarter $ 9.79 $ 8.40
Second Quarter $ 8.89 $ 7.25
Third Quarter $ 9.00 $ 7.31
Fourth Quarter $ 8.74 $ 4.74
Year $ 9.79 $ 4.74
Price Range -- Fiscal Year 2002 High Low
- --------------------------------------- --------------- -----------------
First Quarter $ 14.10 $ 9.05
Second Quarter $ 12.52 $ 10.40
Third Quarter $ 11.50 $ 9.51
Fourth Quarter $ 10.51 $ 9.00
Year $ 14.10 $ 9.00
On September 30, 2003, there were approximately 450 holders of record
of the Company's common stock. The Board of Directors historically considered
approving common stock dividends for payments in March, June, September and
January. On June 17, 2003, the Company's Board of Directors suspended the
payment of quarterly dividends. The Company's current credit agreement with
LaSalle Bank prohibits the payment of dividends by the Company until such time
as the Company's long-term debt is restructured or refinanced as required by the
LaSalle credit agreement. (See Item 7 "MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS - Liquidity and Capital
Resources"). Quarterly dividend payments per common share for fiscal years 2003
and 2002 were:
Fiscal Year Fiscal Year
2003 2002
-------------- ---------------
September $ 0.1350 $ 0.1300
January $ 0.1350 $ 0.1300
March $ 0.1350 $ 0.1300
June -- $ 0.1350
16
Item 6. - Selected Financial Data
Selected Financial Data on a Consolidated Basis (2003-1999)
(dollar amounts in thousands, except per share data)
2003 2002 2001 2000 1999
---- ---- ---- ---- ----
Operating results
Operating revenue $ 79,146 $ 90,172 $ 111,612 $ 64,398 $ 48,864
Operating expenses
Gas and electric purchases 62,520 74,590 90,173 50,800 34,736
General and administrative 11,669 8,790 12,095 7,649 8,018
Maintenance 497 466 428 400 469
Depreciation and amortization 2,393 2,059 1,970 1,856 1,695
Taxes other than income 888 946 723 639 708
------------------------------------------------------------------------------
Total operating expenses 77,967 86,851 105,389 61,344 45,626
------------------------------------------------------------------------------
Operating income 1,179 3,321 6,223 3,054 3,238
Other income-net 302 658 282 449 909
Total interest charges 1,633 1,704 2,097 1,674 1,493
------------------------------------------------------------------------------
Income (loss) before taxes (152) 2,275 4,408 1,829 2,654
Income tax expense (benefit) (63) 874 1,643 708 1,067
------------------------------------------------------------------------------
Net Income (Loss) $ (89) $ 1,401 $ 2,765 $ 1,121 $ 1,587
------------------------------------------------------------------------------
Basic earnings (loss) per common share $ (0.03) $ 0.55 $ 1.11 $ 0.46 $ 0.66
Diluted earnings (loss) per common share $ (0.03) $ 0.55 $ 1.10 $ 0.46 $ 0.66
Dividends per common share $ 0.41 $ 0.52 $ 0.51 $ 0.49 $ 0.47
Weighed average common shares
Outstanding - diluted 2,586,487 2,558,782 2,509,738 2,456,555 2,418,910
At year end:
Current assets $ 18,172 $ 19,091 $ 26,621 $ 16,387 $ 11,429
Total assets $ 62,408 $ 57,869 $ 62,278 $ 51,194 $ 43,710
Current liabilities $ 21,569 $ 19,899 $ 24,416 $ 14,831 $ 7,230
Total long-term obligations $ 14,834 $ 15,367 $ 15,881 $ 16,395 $ 16,840
Total stockholders' equity $ 15,299 $ 16,272 $ 15,613 $ 13,786 $ 13,532
------------------------------------------------------------------------------
Total capitalization $ 30,133 $ 31,639 $ 31,494 $ 30,181 $ 30,372
==============================================================================
17
Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF CONSOLIDATED OPERATIONS
CRITICAL ACCOUNTING POLICIES
Note 1 to the Company's Consolidated Financial Statements contains a
summary of the Company's significant accounting policies. The Company believes
that its critical accounting policies are as follows:
Effects of Regulation--The Company follows Statement of Financial
Accounting Standards (SFAS) No. 71, Accounting for the Effects of Certain Types
of Regulation, and its financial statements reflect the effects of the different
rate making principles followed by the various jurisdictions regulating the
Company. The economic effects of regulation can result in regulated companies
recording costs that have been or are expected to be allowed in the ratemaking
process in a period different from the period in which the costs would be
charged to expense by an unregulated enterprise. When this occurs, costs are
deferred as assets in the balance sheet (regulatory assets) and recorded as
expenses in the periods when those same amounts are reflected in rates.
Additionally, regulators can impose liabilities upon a regulated company for
amounts previously collected from customers and for amounts that are expected to
be refunded to customers (regulatory liabilities). Costs recovered through rates
include income taxes, property taxes, environmental remediation and costs of
gas.
Recoverable/ Refundable Costs of Gas and Propane Purchases--The Company
accounts for purchased gas costs in accordance with procedures authorized by the
MPSC, the WPSC and the ACC under which purchased-gas and propane costs that are
different from those provided for in present rates are accumulated and recovered
or credited through future rate changes.
Derivatives--The Company accounts for certain derivative contracts that
are used to manage risk in accordance with SFAS No. 133, Accounting for
Derivative Instruments and Hedging Activities, as amended by SFAS No. 138,
Accounting for Certain Derivative Instruments and Certain Hedging Activities,
which the Company adopted July 1, 2000.
RESULTS OF CONSOLIDATED OPERATIONS
Fiscal Year Ended June 30, 2003 Compared to Fiscal Year Ended June 30, 2002
Net Income
The Company's net loss for fiscal year 2003 was $89,000 compared to a
net income of $1,401,000 in fiscal year 2002, a decrease of $1,490,000. The
reduction in net income is primarily due to the natural gas operations reduction
of $755,000 due to reduced volumes and additional operating expenses. The
Propane Operations segment had reduced net income of approximately $465,000 due
to lower margins resulting from higher costs of propane and additional operating
expense. The Company's EWR segment experienced a reduction in net income of
$130,000 due primarily to additional legal fees of $1,017,000 related to the
PPLM litigation which were partially offset by additional margins from natural
gas trading. The Pipeline Operations segment had reduced income of $140,000
primarily due to expenses incurred to obtain FERC regulatory approval.
18
Revenue
Operating revenues of the Company decreased by 12% from approximately
$90,172,000 in fiscal year 2002 to $79,146,000 in fiscal year 2003. The Natural
Gas Operations segment's revenues decreased $7,888,000 due to elimination of the
surcharge approved by the MPSC in March 2001 for the recovery of increased gas
costs that had been incurred prior to March 2001. The increased gas costs were
fully recovered by June 2002, and the surcharge was eliminated. Also, warmer
than normal weather experienced during fiscal year 2003 resulted in lower
volumes. The Company's EWR segment experienced a decrease in revenues of
$5,564,000 due to reduction in gas marketing revenues. The Propane Operations
segment experienced an increase in revenues of $2,130,000 due to both higher
prices and sales volumes and the Pipeline Operations segment experienced an
increase in revenues of approximately $295,000.
Gross Margin
Gross margins (operating revenues less cost of gas and electricity)
increased approximately $1,044,000, or 6.0% in fiscal year 2003. This increase
was attributable mainly to increased gross margins in the Company's EWR segment
of $1,436,000 offset by gross margin decreases in both the Propane Operations
and Natural Gas Operations segments resulting from higher than normal propane
and gas costs.
Operating Income
The Company's operating income decreased by approximately $2,142,000,
from $3,321,000 in fiscal year 2002 to $1,179,000 in fiscal year 2003 due
primarily to increased operating expenses. The Company's total operating
expenses for fiscal year 2003 increased by approximately $3,186,000. This was
primarily due to increases in general and administrative expenses of $2,879,000,
as well as maintenance and depreciation increases of $31,000 and $334,000
respectively, with a corresponding decrease of $58,000 in taxes other than
income.
General and administrative expenses increased from $8,790,000 in fiscal
year 2002 to $11,669,000 in fiscal year 2003. This increase of $2,879,000 was
due primarily to increased legal expenses related to the PPLM litigation and
additional expenses incurred to obtain short term financing. The costs of the
PPLM litigation were approximately $1,552,000 in fiscal year 2003 compared with
approximately $565,000 in fiscal year 2002. The Company also incurred additional
expenses of approximately $420,000 in fiscal year 2003 related to obtaining
short term financing.
Other Income
Other income decreased by $356,000 from $658,000 in fiscal year 2002 to
$302,000 in fiscal year 2003 primarily due to a non-recurring $300,000
settlement received by EWR in fiscal year 2002 as part of a transaction to
purchase a group of producing natural gas reserves.
Interest Expense
Interest expense decreased by $71,000 from $1,704,000 in fiscal year
2002 to $1,633,000 in fiscal year 2003 due to lower overall corporate borrowings
in fiscal year 2003. Interest expense is allocated among the segments based on
capital employed.
19
Fiscal Year Ended June 30, 2002 Compared to Fiscal Year Ended June 30, 2001
Net Income
The Company's net income for fiscal year 2002 was $1,401,000 compared
to $2,765,000 in fiscal year 2001, a decrease of $1,364,000. The EWR segment had
an earnings decrease of $1,922,000 due to reductions in revenues primarily from
the remarketing of power and reductions in its wholesale gas revenues. The
unusually high margins in fiscal year 2001 resulted from a combination of
factors, including historically high market prices and remarketing of
uncommitted power. The reduction in net income from the EWR segment was
partially offset by an increase in net income in the Natural Gas Operations
segment of $324,000, an increase in income from the propane operations of
$264,000 and a reduction in income from the Pipeline Operations segment of
approximately $30,000. The increase in the Natural Gas Operations segment's net
income is due primarily to record cold temperatures experienced during the
months of April, May and June. In addition, the Natural Gas Operations segment
implemented reductions in discretionary expenses due to the warmer-than-normal
weather conditions experienced during the first nine months of fiscal year 2002.
The increase in net income from the Propane Operations segment is due to
divestiture of retail propane assets in Montana and Wyoming.
Revenue
Operating revenues of the Company decreased by 19% from approximately
$111,612,000 to $90,172,000. This is due primarily to the EWR segment's
reduction in revenues from remarketing power and natural gas of $17,125,000, a
reduction of revenues from the Propane Operations segment of $3,211,000, and a
reduction in revenue from the Natural Gas Operations segment of $1,090,000
related to lower prices of natural gas and a reduction from the Pipeline
Operations segment of $14,000. The unusually high margins from the EWR segment
in fiscal year 2001 resulted from a combination of unusual factors, including
historically high market prices and remarketing of uncommitted power. The
Company does not expect the combination of unusual factors that resulted in the
unusually high income from the previous year to be repeated in the current year
or in future years.
Gross Margin
Gross margins (operating revenues less cost of gas and electricity)
decreased approximately $5,857,000. The Company's EWR segment decreased gross
margins by $5,977,000 due mainly to reductions in remarketing of power. The
gross margins from the Natural Gas Operations segment increased by $180,000 due
to an increase in volumes of gas sold while the gross margin in the Propane
Operations segment decreased by $45,000 due to higher propane costs. Gross
margins decreased by $14,000 in the Pipeline Operations segment due to lower
gathering revenues.
Operating Income
The Company's operating income decreased by approximately $2,902,000.
Operating income from the EWR segment decreased by $3,550,000 due to lower gross
margins from the remarketing of power. This lower margin was partially offset by
a reduction in other operating expenses of $2,427,000.
Operating income from the Natural Gas Operations segment increased by
approximately $462,000 due to increased gross margins of $180,000 and reductions
in other operating expenses
20
of $282,000. The Propane Operations segment experienced an increase of $263,000
in operating income primarily due to the gain on the sale of the retail propane
assets, and a reduction in general and administrative expenses of $308,000
offset by an increase in other expenses of $45,000 and gross margin reductions
of $45,000.
The Company's total operating expenses for fiscal year 2002 decreased
by approximately $2,955,000. This reduction is due primarily to reduced
incentive payments made during fiscal year 2002 compared to fiscal year 2001,
reduced legal fees, a reduction in corporate overheads and the reduction
attributable to the sale of the propane assets. Also, the Company implemented
cutbacks in non-essential operating and maintenance expenses in fiscal year
2002. The cutback was due primarily to lower volumes being sold as a result of
higher than normal temperatures in Montana, Wyoming and Arizona during the first
nine months of fiscal year 2002.
Interest Expense
Interest expense decreased by $393,000 due to reduction in short term
borrowings and a decrease in short term average interest rates from 8.4% to
approximately 4.6%
Other Income
Other income increased by $376,000 due in part to a $300,000 settlement
received by EWR as part of a transaction to purchase a group of producing
natural gas reserves. EWR received the $300,000 discount on the portion of its
purchase price from the seller as a settlement on any claims.
OPERATING RESULTS OF THE COMPANY'S NATURAL GAS OPERATIONS
Years Ended June 30
2003 2002 2001
---- ---- ----
(in thousands)
Natural Gas Operations
Operating revenues $31,627 $39,515 $40,605
Gas purchased 21,754 29,465 30,735
---------------------------
Gross margin 9,873 10,050 9,870
Operating expenses 8,542 7,497 7,779
---------------------------
Operating income 1,331 2,553 2,091
Other (income) loss (94) (153) (131)
Interest expense 999 1,170 1,254
Income tax expense 245 600 356
---------------------------
Net income natural gas operations $ 181 $ 936 $ 612
---------------------------
Fiscal Year Ended June 30, 2003 Compared to Fiscal Year Ended June 30, 2002
Revenues and Gross Margins
The Natural Gas Operations segment's operating revenues decreased from
approximately $39,515,000 in fiscal year 2002 to approximately $31,627,000 in
fiscal year 2003. This decrease of $7,888,000 was due primarily to the
elimination of the surcharge approved by the MPSC in March 2001 for the recovery
of increased gas costs that had been incurred prior to March 2001.
21
The increased gas costs were fully recovered by June 2002, and the surcharge was
eliminated. Also, warmer than normal weather experienced during fiscal year 2003
and reduced volumes being sold to a large industrial customer by EWW, resulted
in lower total volumes of natural gas sold of approximately 369,000 Mcf, a 6%
reduction from fiscal year 2002.
Gross margin, defined as operating revenues less cost of natural gas,
declined from approximately $10,050,000 in fiscal year 2002 to approximately
$9,873,000 in fiscal year 2003, primarily due to the reduction in sales volumes
experienced during fiscal year 2003.
Natural gas purchases decreased from $29,465,000 in fiscal year 2002 to
$21,754,000 in fiscal year 2003. The decrease in gas costs of $7,711,000 is due
to lower volumes being sold and the lower cost of natural gas during fiscal year
2003.
Operating Expenses
The Natural Gas Operations segment's operating expenses were $8,542,000
for fiscal year 2003 compared to $7,497,000 for fiscal year 2002. The increase
in operating expenses of $1,045,000 was due primarily to an increase in property
taxes, an increase in general liability insurance premiums, increases in
employee benefit costs and increases in general corporate overhead items
allocated to the Natural Gas Operations segment.
Non Operating Income
Non operating income decreased by $59,000 from $153,000 in fiscal year
2002 to $94,000 in fiscal year 2003. The decrease was primarily due to a
reduction in service sales related to home and industrial installations.
Interest Expense
Interest expense decreased from $1,170,000 in fiscal year 2002 to
$999,000 in fiscal year 2003. The decrease of $171,000 was due primarily to
reduced overall corporate borrowings.
Income Tax Expense
Income tax expense was $600,000 for fiscal year 2002 compared to
$245,000 for fiscal year 2003. The reduction of $355,000 is the result of
reduced taxable income for the natural gas operations for fiscal year 2003.
Income tax expense for each segment is computed as if the segment filed its own
income tax returns.
Fiscal Year Ended June 30, 2002 Compared to Fiscal Year Ended June 30, 2001
Revenues and Gross Margins
The Natural Gas Operations segment's operating revenues in fiscal year
2002 decreased to $39,515,000 from $40,605,000 in fiscal year 2001. This was
primarily due to warmer temperatures in the two states served by these
operations, and lower cost of gas. In March 2001, the MPSC approved recovery of
approximately $6,500,000 over one year for gas costs the Company had incurred
prior to that period. As of June 2002, the EWM division had recovered all of the
increased costs, and therefore, the surcharge previously approved by the MPSC
was eliminated. Going forward, the MPSC requires a monthly filing to adjust
customer rates if commodity prices increase or decrease by $.10 per Mcf or more.
22
Gross margin, which is defined as operating revenues less gas
purchased, was approximately $10,050,000 for fiscal year 2002 compared to
approximately $9,873,000 in fiscal year 2001 primarily due to lower cost of gas.
Gas purchases in the Natural Gas Operations segment decreased by
$1,270,000 from $30,735,000 in fiscal year 2001 to $29,465,000 in fiscal year
2002. The decrease in gas costs are reflective of the lower volumes sold due to
the warmer temperatures, the lower cost of gas and the new gas cost recovery
mechanism in Montana, which allowed for a more responsive treatment of the
regulated gas costs to reflect market prices.
Operating Expenses
The Natural Gas Operations segment's operating expenses were
approximately $7,497,000 for fiscal year 2002, as compared to $7,779,000 for
fiscal year 2001. The reduction of $282,000 is due to the reduction in operating
expenses and reductions in the amount of overhead allocated to the Natural Gas
Operations segment.
Non Operating Income
Non operating income increased by $22,000 from $131,000 in fiscal year
2001 to $153,000 in fiscal year 2002. The increase was due primarily to
miscellaneous fixed assets sales during fiscal year 2002.
Interest Expense
Interest charges allocable to the Company's Natural Gas Operations
segment decreased by $84,000 from $1,254,000 in fiscal year 2001 to $1,170,000
during fiscal year 2002. The reduction is the result of lower annual interest
rates experienced in fiscal year 2002 and lower short term borrowings by the
Company.
Income Tax Expense
State and federal income taxes of the Company's Natural Gas Operations
segment increased by $244,000 from $356,000 in fiscal year 2001 to $600,000
during fiscal year 2002. The increase was the result of an increase in taxable
income of the Natural Gas Operations segment.
OPERATING RESULTS OF THE COMPANY'S PROPANE OPERATIONS
Years Ended June 30
2003 2002 2001
---- ---- ----
(in thousands)
Propane Operations
Operating revenues $12,786 $10,656 $13,867
Gas purchased 8,762 6,407 9,573
---------------------------
Gross margin 4,024 4,249 4,294
Operating expenses 3,600 3,065 3,373
---------------------------
Operating income 424 1,184 921
Other (income) loss (187) (199) (128)
Interest expense 403 427 487
Income tax expense 68 351 221
---------------------------
Net income propane operations $ 140 $ 605 $ 341
---------------------------
23
Fiscal Year Ended June 30, 2003 Compared to Fiscal Year Ended June 30, 2002
Revenues and Gross Margins
The Propane Operations segment's revenues rose from $10,656,000 in
fiscal year 2002 to $12,786,000 in fiscal year 2003, an increase of $2,130,000
or 20%. This increase in revenues is due to increased sales prices in the second
half of fiscal year 2003 in the Company's wholesale propane operations, coupled
with an overall increase in volume in the Propane Operations segment. Total
volume for the Propane Operations segment increased from 12,816,000 gallons in
fiscal year 2002 to 16,033,000 gallons in fiscal year 2003, an increase of 25%.
Cost of propane sold increased from $6,407,000 to $8,762,000 for the same
period, a 37% increase, due to the increase in volumes sold and increases in the
cost of propane for both the regulated utility and the wholesale propane
operations. These increases in revenues and corresponding increase in cost of
propane sold resulted in a decrease of $225,000 in gross margins, or 5.3%, from
$4,249,000 in fiscal year 2002 to $4,024,000 in fiscal year 2003.
Operating Expenses
Operating expenses were $3,600,000 for fiscal year 2003 compared to
$3,065,000 for fiscal year 2002. The increase of $535,000 was primarily related
to increases in depreciation, corporate overhead allocations, and increased
sales expenses in the wholesale propane operation.
Non Operating Income
Non operating income decreased by $12,000 from $199,000 in fiscal year
2002 to $187,000 in fiscal year 2003. This decrease is due primarily to the
collection of a previously written off bad debt account in fiscal year 2002.
Interest Expense
Interest expense decreased from $427,000 in fiscal year 2002 to
$403,000 in fiscal year 2003. The reduction of $24,000 is due to lower interest
costs being allocated to the propane operations resulting from lower overall
borrowings by the Company.
Income Tax Expense
Income taxes decreased from $351,000 in fiscal year 2002 to $68,000 in
fiscal year 2003 due to lower taxable income.
Fiscal Year Ended June 30, 2002 Compared to Fiscal Year Ended June 30, 2001
Revenues and Gross Margins
The Propane Operations segment's revenues decreased from $13,867,000 in
fiscal 2001 compared to $10,656,000 in fiscal year 2002, a reduction of
$3,211,000 or 23%. This decrease in revenues is due mainly to lower spot market
for propane sold during the year as well as a 10% reduction in volumes sold from
fiscal year 2001 compared to fiscal year 2002. Also contributing to the
reduction in revenues was the sale of the retail propane operations in Montana
and Wyoming. The reduction in total revenues attributable to the sale of these
two operations was approximately $260,000 related to the Wyoming operations and
approximately $123,000 related to the Montana retail operations. The Propane
Operations segment was able to take advantage of
24
the lower market prices for propane. The cost of propane sold decreased from
$9,573,000 during fiscal year 2001 to $6,407,000 for fiscal year 2002 or a
reduction of approximately 33%. Gross margins decreased by $45,000, less than
1%.
Operating Expenses
Operating expenses were $3,065,000 for fiscal year 2002 compared to
$3,373,000 for fiscal year 2001, a decrease of $308,000. Operating expenses
decreased due to reduction in general and administrative expenses of $338,000
resulting from the sale of the retail propane assets in Montana and Wyoming
offset by an increase to additional costs incurred for propane pipeline safety
maintenance in the Arizona locations.
Non Operating Income
Non operating income increased by $71,000 from $128,000 in fiscal year
2001 to $199,000 in fiscal year 2002. This increase in due primarily to the
collection of a previously written off bad debt account.
Interest Expense
Interest expense declined from $487,000 in fiscal year 2001 to $427,000
in fiscal year 2002. The reduction of $60,000 was due to lower interest costs
being allocated to the propane operations resulting from lower overall
borrowings by the Company and the lower average interest rate on short term
borrowings.
Income Tax Expense
Income taxes increased from $221,000 in fiscal year 2001 to $351,000 in
fiscal year 2002 due to higher taxable income for the year.
OPERATING RESULTS OF THE COMPANY'S EWR SEGMENT
Years Ended June 30
2003 2002 2001
---- ---- ----
(in thousands)
EWR
Operating revenues $34,283 $39,847 $56,972
Gas purchased 31,717 38,717 49,865
---------------------------
Gross margin 2,566 1,130 7,107
Operating expenses 3,040 1,628 4,055
---------------------------
Operating income (loss) (474) (498) 3,052
Other (income) loss (19) (304) (22)
Interest expense 223 104 338
Income tax expense (benefit) (360) (110) 1,002
---------------------------
Net income (loss) EWR operations $ (318) $ (188) $ 1,734
---------------------------
25
Fiscal Year Ended June 30, 2003 Compared to Fiscal Year Ended June 30, 2002
Revenues and Gross Margins
The EWR segment's gross margins were approximately $2,566,000 for
fiscal year 2003 compared to $1,130,000 for fiscal year 2002, an increase of
$1,436,000. This increase was primarily due to a $1,509,000 increase in natural
gas margins (primarily from the sale of storage inventories during the third
quarter) and an increase in margins of $338,000 from production properties
purchased in fiscal year 2002, offset by a decline of approximately $411,000 in
gross margins from the sale of electricity.
Operating Expenses
Operating expenses for the EWR segment were approximately $3,040,000
for fiscal year 2003 compared to $1,628,000 for the previous fiscal year. The
most significant factor causing the increase of $1,412,000 was increased legal
expenses related to the PPLM litigation. The costs of the PPLM litigation were
approximately $1,552,000 for fiscal year 2003 compared to approximately $535,000
for fiscal year 2002. The remainder of the increase in operating expenses of
$395,000 was due primarily to increases in liability insurance, employee
benefits, increased bad debt expenses and an increase in the amount of allocated
corporate overhead.
Non Operating Income
Non operating income was approximately $19,000 in fiscal year 2003
compared to approximately $304,000 for fiscal year 2002. The reduction is
primarily due to the EWR segment's receipt of a $300,000 discount on the
purchase of production properties during fiscal year 2002 that was not repeated
during the current fiscal year.
Interest Expense
Interest charges allocable to the EWR segment increased by $119,000
from $104,000 in fiscal year 2002 to $223,000 in fiscal year 2003. This increase
was primarily due to the allocation of interest expense based on an increase in
capital employed.
Income Tax Expense
The EWR segment experienced an income tax benefit of $360,000 during
fiscal year 2003 compared to an income tax benefit of $110,000 in fiscal year
2002 due to the reduction in taxable income from its operations.
Fiscal Year Ended June 30, 2002 Compared to Fiscal Year Ended June 30, 2001
Revenues and Gross Margins
The EWR segment experienced a reduction in gross margin of $5,977,000
for the fiscal year 2002 compared to fiscal year 2001. The majority of the 84%
decrease was due to the reduction in margins associated with the remarketing of
electricity at unusually high market prices experienced during fiscal year 2001.
The same market conditions were not present during fiscal year 2002.
Operating Expenses
Operating expenses for the EWR segment were $1,628,000 during fiscal
year 2002 compared to $4,055,000 during fiscal year 2001. The $2,427,000
decrease was due mainly to the reduction in incentives and commissions related
to the decrease in gross margins. Partially
26
offsetting those reductions were approximately $535,000 in legal expenses
related to the litigation with PPLM.
Non Operating Income
Non operating income was $282,000 higher in fiscal year 2002 compared
to fiscal year 2001. This increase was due to a $300,000 settlement received by
EWR as part of a transaction to purchase a group of producing natural gas
reserves located in northern Montana. EWR received the $300,000 discount on the
portion of its purchase price from the seller as a settlement on any claims
against it by EWR. This transaction took place during the fourth quarter of
fiscal year 2002.
Interest Expense
Interest expense decreased during fiscal year 2002 by $234,000 due
mainly to a decrease in short-term borrowing rates, as well as an overall
reduction in borrowing.
Income Tax Expense
The EWR segment experienced an income tax benefit of $110,000 during
fiscal year 2002 compared to an expense of $1,002,000 in fiscal year 2001 due to
the reduction in taxable income from its operations.
OPERATING RESULTS OF THE COMPANY PIPELINE OPERATIONS
Years Ended June 30
2003 2002 2001
---- ---- ----
(in thousands)
Pipeline Operations
Operating revenues $449 $154 $168
Gas purchased 287 -- --
---------------------------
Gross margin 162 154 168
Operating expenses 265 71 9
---------------------------
Operating income (loss) (103) 83 159
Other (income) loss (1) -- --
Interest expense 7 3 17
Income tax expense (benefit) (17) 32 64
---------------------------
Net income (loss) pipeline operations $(92) $48 $78
---------------------------
Pipeline Operations was added as a new segment as of July 1, 2002. The
results of this segment reflect operation of natural gas gathering systems
placed into service in fiscal year 2001, and transferred from EWR to EWD. For
fiscal year 2003 the revenues reported in the Pipeline Operations segment
consist of gathering revenues related to the pipeline operations in the Wyoming
and Montana areas. Also included in the Pipeline Operations segment are the
revenues and expenses associated with the recently purchased production
reserves.
27
Fiscal Year Ended June 30, 2003 Compared to Fiscal Year Ended June 30, 2002
Revenues and Gross Margins
The Pipeline Operations segment's revenues increased from $154,000 in
fiscal year 2002 to approximately $449,000 in fiscal year 2003. The increase of
$295,000 is due primarily to revenues generated from natural gas production
properties purchased in fiscal year 2003. The cost of gas purchased increased
$287,000 from fiscal year 2003 compared to fiscal year 2002 due to the increased
costs associated with the cost of the production.
Operating Expenses
Operating expenses increased from $71,000 in fiscal year 2002 to
$265,000 in fiscal year 2003. The increase of $194,000 is due to additional
expenses associated with production properties and additional expenses incurred
in obtaining FERC regulatory approval to operate the interstate natural gas
transportation pipeline placed in service on July 3, 2003.
Income Tax Expense
Income tax expense decreased $49,000 from an income tax expense in
fiscal year 2002 of $32,000 to an income tax benefit of $17,000 in fiscal year
2003. The decrease in income taxes is due to the reduction in taxable income
from pipeline operations.
Fiscal Year Ended June 30, 2002 Compared to Fiscal Year Ended June 30, 2001
Revenues and Gross Margins
Revenues and gross margin decreased from $168,000 in fiscal year 2001
to $154,000 in fiscal year 2002. This decrease of $14,000 was due to reductions
in gathering system revenues resulting from lower volumes being transported.
Operating Expenses
Operating expenses increased by $62,000 from $9,000 in fiscal year 2001
compared to $71,000 in fiscal year 2002. The increase was due to additional
salaries and related benefits and depreciation of the natural gas gathering
systems.
Income Tax Expense
Income tax expense decreased from $64,000 in fiscal year 2001 to
$32,000 in fiscal year 2002. The decrease of $32,000 is due to lower taxable
income from the pipeline operations.
CASH FLOW ANALYSIS
Fiscal Year Ended June 30, 2003 Compared to Fiscal Year Ended June 30, 2002
Cash provided by operating activities consists of net income and
noncash items including depreciation, depletion, amortization and deferred
income taxes. Additionally, changes in working capital are also included in cash
provided by operating activities. The Company expects that internally generated
cash, coupled with short-term borrowings, will be sufficient to satisfy its
operating requirements and normal capital expenditures.
28
The primary cash flows during the last three years are summarized below:
Years Ended June 30
2003 2002 2001
---- ---- ----
(in thousands)
Provided by Operating activities $ 4,546,169 $ 7,114,030 $ 6,008,065
Used in investing activities (4,073,912) (5,149,890) (3,287,843)
Provided by (used in) financing activities 1,098,854 (1,817,150) (2,611,729)
--------------------------------------
Net increase in cash
and cash equivalents $ 1,571,111 $ 146,990 $ 108,493
--------------------------------------
Governmental Regulation
The Company's utility operations are subject to regulation by the MPC,
the WPSC, and the ACC. Such regulation plays a significant role in determining
the Company's return on equity. The commissions approve rates that are intended
to permit a specified rate of return on investment. The Company's tariffs allow
the cost of gas to be passed through to customers. The pass-through causes some
delay, however, between the time that the gas costs are incurred by the Company
and the time that the Company recovers such costs from customers.
Seasonality
The business of the Company and its subsidiaries in all segments is
temperature-sensitive. In any given period, sales volumes reflect the impact of
weather, in addition to other factors, with colder temperatures generally
resulting in increased sales by the Company. The Company anticipates that this
sensitivity to seasonal and other weather conditions will continue to be
reflected in the Company's sales volumes in future periods.
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 and short term borrowing. Historically, to the extent cash flow has
not been sufficient to fund capital expenditures, the Company has borrowed
short-term funds. When the short-term debt balance significantly exceeds working
capital requirements, the Company has issued long-term debt or equity securities
to pay down short-term debt. 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 purchased
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 and fall months and the Company's short-term borrowing needs for
financing customer accounts receivable are greatest during the winter months.
29
At June 30, 2003, the Company had approximately $1,939,000 of cash on
hand and a $10,595,000 unsecured bank credit facility, of which approximately
$6,105,000 had been borrowed under the credit agreement. The Company's
short-term borrowings under its lines of credit during fiscal 2003 had a daily
weighted average interest rate of 4.54% per annum. At June 30, 2003, the Company
had outstanding letters of credit totaling $4,400,000 related to electricity and
gas purchase contracts. These letters of credit are netted against the Company's
bank lines of credit, which resulted in net availability of approximately
$90,000 under the Company's line of credit at June 30, 2003.
Following an adverse ruling in the PPLM lawsuit on March 7, 2003, the
Company's bank lender, Wells Fargo Bank Montana, National Association ("Wells
Fargo") and the Company began negotiations with respect to the Company's credit
facility which was set to expire in May 2003. Wells Fargo granted a series of
extensions of the credit facility through September 5, 2003.
On September 5, 2003, the Company reached an agreement with Wells Fargo
for a new credit facility through October 15, 2003 (the "Wells Fargo Facility").
The terms of the new Wells Fargo Facility established a term loan of
approximately $10,400,000, the proceeds of which were used to repay the prior
Wells Fargo credit facility and to establish a reserve of approximately
$2,600,000 for letters of credit that remained outstanding from the prior
facility. In addition, the Wells Fargo Facility established a revolving line of
credit under which the Company could borrow up to $3,000,000 for working capital
and certain other expenses. Borrowings under the new Wells Fargo Facility were
secured by liens on substantially all of the assets of the Company used in its
regulated operations in Arizona, and by substantially all of the assets of the
Company's subsidiaries. As required under the terms of the Company's outstanding
long-term notes and bonds (the "Long Term Debt"), the Company's obligations
under the Long Term Debt were secured on an equal and ratable basis with Wells
Fargo in the collateral granted to secure the Wells Fargo Facility with the
exception of the first $1,000,000 of debt under the Wells Fargo Facility.
On September 30, 2003, the Company established a $23,000,000 revolving
credit facility (the "LaSalle Facility") with LaSalle Bank National Association,
as Agent for certain banks (collectively, the "Lender"). The LaSalle Facility
replaced the Wells Fargo Facility and the amount due under the Wells Fargo
Facility was paid in full out of the proceeds of the LaSalle Facility.
Borrowings under the LaSalle Facility are secured by liens on substantially all
of the assets of the Company and its subsidiaries. As required under the terms
of the Long Term Debt, the Company's obligations under the Long Term Debt are
secured on an equal and ratable basis with the Lender in the collateral granted
to secure the LaSalle Facility with the exception of the first $1,000,000 of
debt under the LaSalle Facility.
Under applicable law, the Company was required to obtain approval from
the MPSC and the WPSC to enter into the LaSalle Facility. Both commissions gave
the necessary approval. The MPSC order granting approval imposed several
requirements on the Company including restrictions on the use of the proceeds of
the LaSalle Facility for anything other than utility purposes, and requirements
that the Company provide ongoing reports to the MPSC with respect to the
financial condition of the Company and its non-regulated subsidiaries, and
certain other matters. The MPSC order provided that the Company could fund the
remaining $2.2 million
30
settlement payment owed by EWR to PPLM. The settlement payment was made on
September 30, 2003, ending the litigation between the two parties.
The LaSalle Facility provides that the maximum availability under the
facility will be reduced from $23,000,000 to $15,000,000 no later than March 31,
2004. From and after the date on which the amount of availability under the
LaSalle Facility is reduced, the LaSalle Facility is to be secured by a senior
priority lien in the accounts receivable and inventory of the Company and its
subsidiaries. As a result of the provisions providing for the reduction in the
maximum availability under the LaSalle Facility, the Company will be required to
refinance or restructure the Long Term Debt by March 31, 2004. The Company
anticipates that such refinancing or restructuring will involve providing a
senior priority lien in the fixed assets of the Company and its subsidiaries to
secure the Long Term Debt or any long-term debt that the Company issues to
replace the current Long Term Debt. The Company also anticipates that it will
increase the total amount of long-term debt outstanding in connection with such
refinancing or restructuring. The Company presently anticipates that the amount
of such increase in long-term debt will be approximately $8,000,000. The Company
believes that it will be able to accomplish the Long Term Debt restructuring or
refinancing by March 31, 2004. Failure to complete the restructuring or
refinancing of the Long Term Debt, as discussed above, would be a default under
the terms of the LaSalle Facility.
During the period prior to the refinancing or restructuring of the
Company's Long Term Debt, the terms of the LaSalle Facility provide that the
Company cannot pay dividends to its shareholders. In June 2003, the Company's
Board of Directors suspended the Company's fourth quarter dividend to allow for
strengthening of the Company's balance sheet. The Company expects that it will
be able to accomplish the long-term debt restructuring by March 31, 2004.
Under the LaSalle Facility, the Company has the option to pay interest
at either the London Interbank Offered Rate (LIBOR) plus 250 basis points (bps)
or the higher of (a) the rate publicly announced from time to time by LaSalle as
its "prime rate" or (b) the Federal Funds Rate plus 0.5% per annum. The LaSalle
Facility also has a commitment fee of 35 bps due on the daily unutilized portion
of the facility.
The LaSalle Facility requires that the Company maintain compliance
with a number of financial covenants including limitations on annual capital
expenditures to an amount equal to or less than $5,000,000. The Company must
also maintain a total debt to total capital ratio of less than .65 to 1.00 and
an interest coverage ratio (earnings before interest, taxes, depreciation and
amortization (EBITDA), plus agreed upon add backs, divided by interest expense)
of no less than 2.00 to 1.00. Finally, the Company must restrict its open
positions and Value at Risk (VaR) in its wholesale operations to an amount not
to exceed $1,000,000. The Company met all of these financial covenants at the
time it entered into the LaSalle Facility.
At September 30, 2003, the Company had borrowed $16,601,548 under the
LaSalle Facility and had $6,398,452 of borrowing capacity under the LaSalle
Facility.
In addition to its bank lines of credit, the Company has outstanding
certain notes and industrial development revenue obligations (collectively "Long
Term Debt"). The Company's Long Term Debt is made up of three separate debt
issues: $8,000,000 of Series 1997 unsecured notes bearing interest at the rate
of 7.5%; $7,800,000 of Series 1993 unsecured notes bearing
31
interest at rates ranging from 6.20% to 7.60%; and Cascade County, Montana
Series 1992B Industrial Development Revenue Obligations in the amount of
$1,800,000. As required by the terms of the Long Term Debt, the Company's
obligations under the Long Term Debt are secured on an equal and ratable basis
with the Lender in the collateral granted to secure the LaSalle Facility with
the exception of the first $1,000,000 of debt under the LaSalle Facility.
The total amount of the Company's obligations under the Long Term Debt
was $15,355,000 and $15,856,000, at June 30, 2003 and June 30, 2002,
respectively. The portion of such obligations due within one year was $530,000
and $500,000 at June 30, 2003, and June 30, 2002, respectively. Under the terms
of such Long Term Debt obligations, additional principal payments of $570,000
will be due during fiscal 2005, $610,000 during fiscal 2006, $655,000 during
fiscal 2007, $700,000 during fiscal 2008, and $12,290,444 during periods after
fiscal 2008.
A table of the Company's Long Term Debt, as well as other long-term
commitments and contingencies, and the corresponding maturity dates are listed
below. The table does not reflect commitments and liabilities incurred in the
ordinary course of business (such as gas purchase agreements), which are payable
within less than 12 months. The "Less than 1 year" amount listed below for
"Unconditional Purchase Obligations" represents commitments for long term gas
supply.
- ------------------------------------------------------------------------------------------------
Payments Due by Period
-----------------------------------------------------------------
Less 1 -3 4 - 5 After 5
Contractual Total than years years Years
Obligations 1 year
- ------------------------------------------------------------------------------------------------
Long-Term Debt $15,355,444 $530,000 $1,180,000 $1,355,000 $12,290,444
- ------------------------------------------------------------------------------------------------
Operating Lease
Obligations 746,011 183,765 295,198 181,248 85,800
- ------------------------------------------------------------------------------------------------
Capital Lease
Obligations 11,379 2,372 5,794 3,213 --
- ------------------------------------------------------------------------------------------------
Unconditional Gas
Purchase Obligations 7,984,082 3,426,573 3,078,905 1,478,604 --
- ------------------------------------------------------------------------------------------------
Transportation and Storage
Obligation 28,392,640 4,258,896 8,517,792 8,517,792 7,098,160
- ------------------------------------------------------------------------------------------------
Total Obligations 52,489,556 8,401,606 13,077,689 11,535,857 19,474,404
- ------------------------------------------------------------------------------------------------
Under the terms of the Long Term Debt obligations, the Company is
subject to certain restrictions, including restrictions on total dividends and
distributions, liens and secured indebtedness, and asset sales, and the Company
is restricted from incurring additional long-term indebtedness if it does not
meet certain financial debt and interest ratios. Management believes that the
Company is in compliance with all Long Term Debt covenants as of June 30, 2003.
For the fiscal year ended June 30, 2003, the Company's ratio of earnings to
fixed charges was less than 1.5. Under the terms of the Long-Term Debt, the
Company must achieve 1.5 ratio of earnings to fixed charges by the end of fiscal
year 2004, or the Company will be restricted from incurring additional debt with
a maturity of one year or longer. As required under the terms of
32
the Long Term Debt, the Company's obligations under the Long Term Debt are
secured on an equal and ratable basis with the Lender in the collateral granted
to secure the LaSalle Facility with the exception of the first $1,000,000 of
debt under the LaSalle Facility.
RISK FACTORS
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, the
adequacy and timeliness of rate relief, cost recovery and necessary regulatory
approvals, and continued access to capital markets. In addition, changes in the
competitive environment particularly related to the Company's propane and energy
marketing segments could have a significant impact on the performance of the
Company.
The regulatory structure in which the Company operates is in
transition. Legislative and regulatory initiatives, at both the federal and
state levels, are designed to promote competition. The changes in the gas
industry have allowed certain 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 Company's regulated natural gas and propane vapor
operations follow Statement of Accounting Standards (SFAS) No. 71 "Accounting
for the Effects of Certain Types of Regulation," and its financial statements
reflect the effects of the different rate making principles followed by the
various jurisdictions regulating the Company. The economic effects of regulation
can result in regulated companies recording costs that have been or are expected
to be allowed in the ratemaking process in a period different from the period in
which the costs would be charged to expense by an unregulated enterprise. When
this occurs, costs are deferred as assets in the balance sheet (regulatory
assets) and recorded as expenses in the periods when those same amounts are
reflected in rates. Additionally, regulators can impose liabilities upon a
regulated company for amounts previously collected from customers and for
amounts that are expected to be refunded to customers (regulatory liabilities).
If the Company's natural gas and propane vapor operations were to discontinue
the application of SFAS No. 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 No. 71.
In addition to the factors discussed above, the following are important
factors that could cause actual results to differ materially from any results
projected, forecasted, estimated or budgeted:
- - Fluctuating energy commodity prices, including prices for fuel and purchased
power;
- - The possibility that regulators may not permit the Company to pass through all
such increased costs to customers;
- - Fluctuations in wholesale margins due to uncertainty in the wholesale propane
and power markets;
- - Changes in general economic conditions in the United States and changes in the
industries in which the Company conducts business;
- - Changes in federal or state laws and regulations to which the Company is
subject, including tax, environmental and employment laws and regulations;
33
- - The impact of FERC and state public service commission statutes and
regulation, including allowed rates of return, and the resolution of other
regulatory matters;
- - The ability of the Company and its subsidiaries to obtain governmental and
regulatory approval of various expansion or other projects;
- - The costs and effects of legal and administrative claims and proceedings
against the Company or its subsidiaries;
- - Conditions of the capital markets the Company utilizes to access capital to
finance operations;
- - The ability to raise capital in a cost-effective way;
- - The effect of changes in accounting policies, if any;
- - The ability to manage growth of the Company;
- - The ability to control costs;
- - The ability of each business unit to successfully implement key systems, such
as service delivery systems;
- - The ability of the Company and its subsidiaries to develop expanded markets
and product offerings as well as their ability to maintain existing markets;
- - The ability of customers of the energy marketing and trading business to
obtain financing for various projects;
- - The ability of customers of the energy marketing and trading business to
obtain governmental and regulatory approval of various projects;
- - Future utilization of pipeline capacity, which can depend on energy prices,
competition from alternative fuels, the general level of natural gas and propane
demand, decisions by customers not to renew expiring natural gas or propane
contracts, and weather conditions; and
- - Global and domestic economic repercussions from terrorist activities and the
government's response thereto.
INFLATION
Capital intensive businesses, such as the Company's natural gas and
propane vapor operations, are significantly affected by long-term inflation.
Neither depreciation charges against earnings nor the ratemaking 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 and propane vapor may fluctuate, earnings are not impacted
because gas and propane vapor cost tracking procedures annually, and more often
with approval of the various Public Service Commissions, balance gas and propane
vapor costs collected from customers with the costs of supplying natural gas and
propane vapor. The Company believes that the effects of inflation, at currently
anticipated levels, will not materially affect results of operations.
ENVIRONMENTAL ISSUES
The Company owns property on which it operated a manufactured gas plant
from 1909 to 1928. The site is currently used as an office facility for Company
field personnel and storage location for certain equipment and materials. 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.
34
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 proposed remediation plan to the Montana Department of
Environmental Quality (MDEQ) 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. In the summer of 1999 the Company received final approval from the
MDEQ for its plan for remediation of soil contaminants. The Company has
completed its remediation of soil contaminants and in April of 2002 received a
closure letter from MDEQ approving the completion of such remediation program.
The Company and its consultants continue their work with the MDEQ
relating to the remediation plan for water contaminants. The MDEQ has
established regulations that allow water contaminants at a site to exceed
standards if it is technically impracticable to achieve them. Although the MDEQ
has not established guidance to attain a technical waiver, the U.S.
Environmental Protection Agency (EPA) has developed such guidance. The EPA
guidance lists factors which render mediations technically impracticable. The
Company has filed a request for a waiver respecting compliance with certain
standards with the MDEQ.
At June 30, 2003, the Company had incurred cumulative costs of
approximately $2,034,000 in connection with its evaluation and remediation of
the site. The Company also estimates that it will incur at least $60,000 in
additional expenses in connection with its investigation and remediation for
this site. On May 30, 1995, the Company received an order from the MPSC allowing
for recovery of the costs associated with the evaluation and remediation of the
site through a surcharge on customer bills. As of June 30, 2003, the Company had
recovered approximately $1,443,000 through such surcharges.
On April 15, 2003, the MPSC issued an Order to Show Cause Regarding the
Environmental Surcharge. The MPSC required the Company to show cause why it was
not in violation of the 1995 order by failing to seek renewal of the surcharge
at the conclusion of the initial two year recovery period. The Company responded
to the MPSC and an interim order has been issued by the MPSC suspending the
collection by the Company of the surcharge until further investigation can be
conducted and requiring a new application from the Company respecting this
surcharge. The Company has submitted its revised application and is awaiting
further MPSC action. Company management believes the Company's application will
be granted. The Company currently has an unrecovered balance of $590,000
awaiting recovery through this mechanism. In the event that the MPSC does not
approve the Company's revised application, in addition to potentially being
unable to recover the unrecovered balance of $590,000, the Company could be
required to refund to customers a portion of the $1,443,000 previously collected
through surcharges.
DERIVATIVES AND RISK MANAGEMENT
Management of Risks Related to Derivatives--The Company and its
subsidiaries are subject to certain risks related to changes in certain
commodity prices and risks of counter-party performance. The Company has
established policies and procedures to manage such risks. The Company has a Risk
Management Committee (RMC), comprised of Company officers and management to
oversee the Company's risk management program as defined in its risk management
policy. The purpose of the risk management program is to minimize adverse
35
impacts on earnings resulting from volatility of energy prices, counter-party
credit risks, and other risks related to the energy commodity business.
General--From time to time the Company or its subsidiaries may use
financial derivative contracts to mitigate the risk of commodity price
volatility related to firm commitments to purchase and sell natural gas or
electricity. The Company may use such arrangements to protect its profit margin
on future obligations to deliver quantities of a commodity at a fixed price.
Conversely, such arrangements may be used to hedge against future market price
declines where the Company or a subsidiary enters into an obligation to purchase
a commodity at a fixed price in the future. The Company accounts for such
financial instruments in accordance with SFAS No. 133, Accounting for Derivative
Instruments and Hedging Activities, as amended by SFAS No. 138, Accounting for
Certain Derivative Instruments and Certain Hedging Activities.
In accordance with SFAS No. 133, contracts that do not qualify as
normal purchase and sale contracts must be reflected in the Company's financial
statements at fair value, determined as of the date of the balance sheet. This
accounting treatment is also referred to as "mark-to-market" accounting.
Mark-to-market accounting treatment can result in a disparity between reported
earnings and realized cash flow, because changes in the value of the financial
instrument are reported as income or loss even though no cash payment may have
been made between the parties to the contract. If such contracts are held to
maturity, the cash flow from the contracts, and their hedges, is realized over
the life of the contract.
Quoted market prices for natural gas derivative contracts of the
Company or its subsidiaries generally are not available. Therefore, to determine
the fair value of natural gas derivative contracts, the Company uses internally
develope