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, 2002
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, Mt. 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
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K (229.45 of this chapter) is not contained herein, and will not
be contained, to the best of registrant's knowledge, in definitive proxy or
information statements incorporated by reference in Part III of this Form 10-K
or any amendment to this Form 10-K [X].
The aggregate market value of the voting stock held by non-affiliates of the
registrant as of September 25, 2002: Common Stock, $.15 Par Value -
$20,222,060
The number of shares outstanding of the issuer's classes of common stock as of
September 25, 2002: Common Stock, $.15 Par Value - 2,573,734 shares.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the proxy statement for the annual shareholders meeting to be held
November 21, 2002 are incorporated by reference into Part III.
2
TABLE OF CONTENTS
Page
Part I
Item 1 Business 4
Item 2 Properties 14
Item 3 Legal Proceedings 15
Item 4 Submission of Matters to a Vote of Security Holders 16
Part II
Item 5 Market for Registrant's Common Stock and Related Stockholder Matters 16
Item 6 Selected Financial Data 19
Item 7 Management's Discussion and Analysis of Financial Condition and
Results of Operation 20
Item 7A Quantitative and Qualitative Disclosures about Market Risk 38
Item 8 Financial Statements 40
Item 9 Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure 69
Part III
Item 10 Directors and Executive Officers of the Registrant 70
Item 11 Executive Compensation 70
Item 12 Security Ownership of Certain Beneficial Owners and Management 70
Item 13 Certain Relationships and Related Transactions 70
Item 14 Controls and Procedures 71
Part IV
Item 15 Exhibits, Financial Statement Schedules and Reports on form 8-K 72
3
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 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. EWD owns one parcel of real
estate property and conducts a gas appliance retail business in Great Falls,
Montana.
The Company reports financial results for three business segments:
Natural Gas Operations, Propane Operations, and Marketing and Wholesale
Operations. The results of all three of these segments are seasonal in nature.
Summarized financial information for these three segments is set forth in Note
11 to the Company's Consolidated Financial Statements included in this Report.
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 in and around Great Falls and West Yellowstone, Montana. The
Energy West - Wyoming Division serves customers in and around Cody, Meeteetsee
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.
EWD's operations are reported as part of the Company's natural gas
operations.
Energy West - Montana ("EWM") Division
4
The EWM division provides natural gas service to customers in and
around Great Falls and West Yellowstone, Montana. The division's service area
has a population of approximately 79,000 in the Great Falls area and 1,200 in
the West Yellowstone 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, 2002 and the two preceding fiscal years:
Gas Revenues
(in thousands)
Years Ended June 30,
--------------------
2002 2001 2000
------- ------- -------
Residential $17,328 $16,974 $ 9,921
Commercial 10,326 9,878 5,495
Transportation 1,958 2,045 2,090
------- ------- -------
Total $29,612 $28,897 $17,506
======= ======= =======
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, 2002 and the
two preceding fiscal years:
Gas Volumes
(MMcf)
Years Ended June 30,
--------------------
2002 2001 2000
------- ------- -------
Residential 2,350 2,442 2,062
Commercial 1,406 1,409 1,106
------- ------- -------
Total Gas Sales 3,756 3,851 3,168
======= ======= =======
Transportation 1,522 1,615 1,632
======= ======= =======
5
The EWM division has 855 transportation customers. No customer of the
EWM division accounted for more than 1% of the consolidated revenues of the
Company in fiscal 2002.
The operations of the EWM division are subject to regulation by the
Montana Public Service Commission ("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 ("Plan") to allow customers to choose a natural gas supplier other than
the EWM division. 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 are free to 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 system to provide transportation, distribution
and balancing services to customers who have chosen to obtain natural gas from
other suppliers. The Company has a 10-year transportation agreement with NWE
that fixes the cost of pipeline and storage capacity for the EWM division at
rates which are currently lower than the rates applicable to most other pipeline
customers of NWE.
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 very high 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 changed more
than $.10 per thousand cubic feet (Mcf) in any month, subject to an audit of the
unrecovered balance by the MPSC and Montana Consumer Counsel once a year.
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 for the EWM
division with the MPSC seeking a general increase in rates, related primarily to
increases in costs of operations. The application is presently pending.
Energy West - Wyoming ("EWW") Division
The EWW division provides natural gas service to customers in and
around Cody, Meeteetsee 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 Wyoming Public Service Commission (the
"WPSC") for transportation and distribution covering
6
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, 2002, the
EWW division provided service to approximately 5,700 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, 2002 and the two preceding fiscal years:
Gas Revenues
(in thousands)
Years Ended June 30,
2002 2001 2000
------ ------- ------
Residential $3,434 $ 4,409 $2,334
Commercial 3,035 3,512 1,927
Industrial 3,044 3,481 1,852
Transportation 346 447 304
------ ------- ------
Total $9,859 $11,849 $6,417
====== ======= ======
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, 2002 and the two
preceding fiscal years:
Gas Volumes
(MMcf)
Years Ended June 30,
2002 2001 2000
----- ----- -----
Residential 564 529 461
Commercial 539 488 482
Industrial 610 571 625
----- ----- -----
Total Gas Sales 1,713 1,588 1,568
===== ===== =====
Transportation 235 380 261
===== ===== =====
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 cost of gas. In fiscal 2002 Celotex accounted
for approximately 31% 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 FY 2002 were approximately 7% greater than in FY 2001. No assurance
can be given that Celotex will continue to be a significant customer of the EWW
division.
7
EWR is the EWW division's primary supplier of natural gas, pursuant to
a three-year agreement entered into in May of 2000. In addition, the division
has a backup contract to purchase natural gas from Coastal Gas Marketing, but
has purchased only immaterial amounts of gas under this backup agreement.
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 $.30 per Mcf) are established by the WPSC.
During fiscal 2002, the Company was a party to financial swap
agreements for natural gas for its regulated operations in the EWW division.
These agreements expired on March 31, 2002. The net cash payments and receipts
under these agreements did not have a material effect on the Company's income or
financial condition.
The EWW division's revenues are generated under regulated tariffs that
are designed to recover a base cost of gas, administrative and operating
expenses and provide sufficient return to cover interest and profit. The
division also serves some customers under separate contract rates that were
individually approved by the WPSC. The division's tariffs include a purchased
gas adjustment clause which allows the division to adjust its rates to recover
changes in gas costs from base gas costs.
The EWW division's last general rate order was effective in 1989. The
Company anticipates filing an application for a general rate increase for the
division during fiscal year 2003.
Propane Operations
For financial reporting purposes, the Company reports as a separate
business segment the distribution of propane by the Company and the Company's
wholly-owned subsidiary, Energy West Propane, Inc. ("EWP"). The Company is
engaged in the regulated distribution of propane through two divisions, Energy
West Arizona ("EWA") and Energy West Montana - Cascade ("EWM - Cascade"). EWP is
engaged in the unregulated distribution of propane in Montana, Wyoming and
Arizona.
Regulated Propane Operations
The EWA division distributes propane in the Payson, Arizona area. The
service area of the EWA division has a population of approximately 30,000. The
operations of the EWA division are subject to regulation by the Arizona
Corporation Commission (the "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 7,100 customers. The
division's principal
8
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, 2002 and the two
preceding fiscal years:
Propane Revenue
(in thousands)
Years Ended June 30,
--------------------
2002 2001 2000
------ ------ ------
Residential $3,384 $3,530 $2,334
Commercial 1,520 1,459 1,098
------ ------ ------
Total $4,904 $4,989 $3,432
====== ====== ======
Propane Volumes
(in gallons)
Years Ended June 30,
--------------------
2002 2001 2000
--------- --------- ---------
Residential 2,678,000 2,835,000 2,296,000
Commercial 1,012,000 1,063,000 875,000
--------- --------- ---------
Total 3,690,000 3,898,000 3,171,000
========= ========= =========
The EWM - Cascade division distributes propane in the Cascade, Montana
area. The service area of the EWM - Cascade division has a population of
approximately 1,000. The operations of the EWM - Cascade division are subject to
regulation by the Montana Public Service Commission, which regulates rates,
adequacy of service, issuance of securities and other matters. The EWM Cascade
division's properties include approximately 10 miles of underground distribution
pipeline. The division purchases its propane supplies from EWP under terms
reviewed periodically by the MPSC.
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
9
wholesale operations primarily in Montana, Wyoming and Arizona. EWP had 4,530
customers as of June 30, 2002.
Energy West Propane - Arizona sells propane to residential and
commercial customers in the Payson, Arizona area.
EWP's wholesale division, Rocky Mountain Fuels Wholesale, supplies
propane for the Company's underground propane-vapor systems serving the cities
of Payson, Arizona and Cascade, Montana and surrounding areas.
In March and June of 2002, as a result of a decision to shift its
strategic emphasis to wholesale propane operations, EWP sold its retail
operations in Montana and Wyoming. The before tax gain on the sale of these two
operations was approximately $338,000. EWP has entered into long-term agreements
to supply wholesale propane, through Rocky Mountain Fuels Wholesale, to the
purchaser of these assets.
EWP faces competition from other propane distributors and suppliers of
alternative fuels that compete with natural gas. Competition is based primarily
on price and there is a high degree of competition with other propane
distributors in each of EWP's service areas.
Energy Marketing and Wholesale Operations
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 Montana Power Company gas transportation and
electricity transmission system and other systems in Montana have presented
opportunities for EWR to do business as a broker of natural gas and electricity,
using these systems. 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 2000. EWR has from time to time
entered into certain financial agreements to 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," in this Report.
In order to provide a stable source of natural gas to provide 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 5% 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 is serving as
the operator of the wells. As part of the transaction, EWR received a $300,000
discount on the purchase price as a settlement
10
of certain claims. The $300,000 was recorded in "nonoperating income" during the
fourth quarter of fiscal year 2002.
In order to take advantage of certain natural synergies resulting from
the location of the Company's operations in Cody, Wyoming, and to expand its
options in procuring natural gas supplies, in August 2000, EWR purchased two
pipelines in northern Wyoming. One of the pipelines is classified as a gathering
system, and has been placed into service. The other pipeline is presently being
renovated. This other pipeline is expected to become operational during fiscal
2003. This pipeline will serve as a transmission pipeline. An application is
being filed with the Federal Energy Regulatory Commission (FERC) to obtain FERC
approval for the pipeline to be operated as a transmission pipeline. Both of the
pipelines will be sold to, and operated by, the Company's wholly-owned
subsidiary, EWD.
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 unregulated retail and wholesale propane operations,
requiring additional capital expenditures. In fiscal years 2002, 2001 and 2000,
total capital expenditures for the Company were approximately $6,442,000,
$3,276,000 and $4,757,000 respectively. The increase in capital expenditures by
approximately $3,166,000 from fiscal year 2001 to fiscal year 2002 was the
result of the purchase of production properties (described in "Energy Marketing
and Wholesale Operations", above) and renovations of the pipelines in Wyoming
(described in "Energy Marketing and Wholesale Operations", above) and
construction of a gas transmission pipeline around the City of Cody, Wyoming.
Competition
The principal competition faced by the Company in its distribution and
sale 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's statistics indicate that
approximately 95% of the houses and businesses in the Great Falls service area
use natural gas for space heating fuel, approximately 91% use gas for water
heating and approximately 99% of the new homes built on or near the Company's
Great Falls service mains in recent years have selected natural gas as their
energy source.
The EWW division believes that approximately 95% of the houses and
businesses in the division's 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 believes that approximately 59% of the houses and
businesses adjacent to the division's distribution pipeline use the division's
propane for space heating or water heating.
11
The principal competition faced by the Company and its subsidiaries in
the distribution and sales of propane is from other propane distributors and
suppliers of the alternate fuels and sources that compete with natural gas and
electricity. Competition is based primarily on price and there is a high degree
of competition with other propane distributors in the service areas.
EWR's principal competition is from other gas and electricity marketing
firms doing business in the State of Montana. As of June 30, 2002, EWR had 163
customers for natural gas services and 709 for electricity services. EWR
believes that the recent changes in applicable law, which allow its customers to
choose a natural gas supplier other than their local utility company, will
continue to provide future opportunities for gas marketing operations.
Employees
The Company and its subsidiaries had an aggregate total of 131
employees as of June 30, 2002. Six of these were employed by EWR, 27 by the
propane operations, 85 were employed by the Company's natural gas operations and
the remaining 13 individuals are employed at the corporate office. The Company's
natural gas operations include 19 employees represented by two labor unions.
Contracts with each of these unions are in place until June 30, 2003. The
Company believes that its relationship with its employees is good.
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
Edward J. Bernica 53 President and Chief
Executive Officer
Sheila M. Rice 55 Vice President and
Corporate Administrator
John C. Allen 51 General Counsel, Vice-
President and Secretary
Tim A. Good 57 Vice-President and Manager
of Natural Gas Operations
Douglas R. Mann 55 Vice-President and Manager
of Energy West Propane Operations
JoAnn S. Hogan 36 Assistant Vice-President and
Treasurer
12
Robert B. Mease 55 Assistant Vice-President and
Controller
Edward J. Bernica was appointed President and Chief Executive Officer on
September 17, 2001. From March 1999 until September 17, 2001, he was Executive
Vice-President, Chief Operating Officer and Chief Financial Officer of the
Company. He joined the Company in November 1994, as Vice-President and Chief
Financial Officer.
Sheila M. Rice has been Vice-President of Energy West Incorporated and Corporate
Administrator since October of 2001. She was Vice President of Marketing from
1998 to 2001 and was Vice President and Division Manager of Energy West Montana
from 1993 until 1998.
John C. Allen has been General Counsel, Vice-President and Secretary of the
Company since 1992.
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, Inc.
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 has been Assistant Vice-President and Treasurer of the Company
since January 2002. 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 has been Assistant Vice-President and Controller of the Company
since joining the Company in February 2002. 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.
13
PART I
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. 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.
EWP owns several large bulk propane tanks to serve the areas in and around the
towns of Cascade and Superior, Montana.
During fiscal year 2002, EWR purchased a 56% ownership interest in natural gas
production properties that provide approximately 600 Mcf of natural gas daily
for resale.
During fiscal 2002, as part of its strategic emphasis on wholesale propane
operations, EWP sold its retail propane operations located in Wyoming and
Montana. The assets sold represented approximately 7% of EWP's total assets and
less than 2% of the Company's consolidated assets.
WYOMING: In Cody, Wyoming, the Company leases office and service buildings for
the EWW division under long-term lease agreements. The Company owns
approximately 300 miles of mains, and related metering and regulating equipment,
all of which are located in or around Cody.
EWP owns two large bulk propane tanks, located in Cody, to serve its customers
in northern Wyoming.
EWR owns two pipelines in Wyoming. One pipeline is currently being operated as a
gathering system, and the other will upon receipt of the necessary FERC
approvals operate as an interstate pipeline transmission system. 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 (5) year periods.
EWP owns several large bulk propane tanks located in Pine, Strawberry, Payson
and Starr Valley, Arizona which are utilized to serve customers in these and
other surrounding areas.
14
Item 3. - Legal Proceedings
From time to time the Company is involved in litigation relating to
claims arising from its operations in the normal course of business. 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.
In addition to other litigation referred to above, the Company or its
subsidiaries are currently involved in the following described litigation.
EWR is currently involved in a lawsuit with PPL Montana, LLC (PPLM)
which is pending in the United States District Court for the District of
Montana. The lawsuit was filed on July 2, 2001, and involves a wholesale
electricity supply contract between EWR and PPL dated March 17, 2000 and a
confirmation letter thereunder dated June 13, 2000 (together, the "Contract").
EWR has received substantial imbalance payments as a result of the amount of
power that it has scheduled and purchased from PPLM under the Contract. PPLM
claims that, as a result of EWR's scheduling under the Contract, PPLM was
deprived of the fair market value of energy which PPLM contends it could have
subsequently sold. PPLM estimates the fair market value of the excess energy
scheduled by EWR to be approximately $18.0 million. Any recovery of damages by
PPLM could have a material adverse effect on the Company and its financial
condition. EWR denies liability to PPLM. EWR believes that its scheduling
practices were reasonable under the circumstances, and that in any event PPLM
did not sustain any damages. The Company believes that it has established
adequate reserves with respect to the litigation with PPLM; however, there can
be no assurance that any liability will not exceed such reserves. A liability in
excess of the recorded reserves could a have material adverse effect on the
Company and its financial condition.
The Montana Department of Revenue ("DOR"), by letter dated August 30,
2002, has advised the Company that based on property tax audit of the Company
for the period January 1, 1997 through December 31, 2001, DOR is assessing the
Company for willfully under-reporting its personal property and that a two and
one-half times penalty should be assessed. The Company estimates that if the
proposed assessment stands, it would owe approximately $3.9 million in property
taxes and penalties. The Company believes it has valid defenses to the
assessment of tax and penalties and intends to vigorously oppose the DOR's
position. The Company also believes that any tax deficiency that may be imposed
on the Company would (to the extent the deficiency relates to regulated
property, which is substantially all of the deficiency) be properly classified
as a regulatory asset (i.e., an amount that can be recovered through increased
rates to utility customers). Assuming authorization for such treatment is
received from regulatory authorities the assessment of taxes would not have a
material affect on the Company. However, if the DOR prevails in its imposition
of penalties, the Company anticipates that such penalties would not be
recoverable through rates. The Company believes that any interest associated
with the property tax assessment also should be classified as a regulatory
asset. An adverse outcome in this matter (including imposition of penalties on
the Company, or failure of the Company to obtain classification of any tax
liability or interest as a regulatory asset) could have a material adverse
effect on the Company and its financial condition.
15
Item 4. - Submission of Matters to a Vote of Security Holders
None
PART II
Item 5. - Market for registrant's common equity and related stockholder matters
Common Stock Prices and Dividend Comparison - Fiscal 2002 and 2001
Shares of the Company's Class "A" 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 2002 High Low
- ------------------------- ---- ---
First Quarter 14.100 9.050
Second Quarter 12.520 10.400
Third Quarter 11.500 9.510
Fourth Quarter 10.510 9.000
Year 14.100 9.000
Price Range - Fiscal 2001 High Low
- ------------------------- ---- ---
First Quarter 9.125 7.563
Second Quarter 9.750 8.500
Third Quarter 10.563 9.313
Fourth Quarter 16.500 9.500
Year 16.500 7.563
At September 25, 2002, there were 493 holders of record of the Company's common
stock. The Board of Directors normally considers approving common stock
dividends for payments in March, June, September and January. Quarterly dividend
payments per common share for Fiscal Years 2002 and 2001 were:
Fiscal 2002 Fiscal 2001
----------- -----------
September $ .1300 $ .1250
January $ .1300 $ .1250
March $ .1300 $ .1250
June $ .1350 $ .1300
The following chart sets forth information concerning the number of shares of
common stock to be issued upon exercise of outstanding options, warrants and
rights, the weighted average exercise price, and the number of shares remaining
available for issuance under such plans.
16
EQUITY COMPENSATION PLAN INFORMATION
Number of securities
Weighted-average remaining available for
Number of securities to be exercise future issuance under
issued upon exercise of price of outstanding equity compensation plans
outstanding options, options, warrants (excluding securities
Plan Category warrants and rights. and rights. reflected in column (a))
- ------------- -------------------- ----------- ------------------------
(a) (b) (c)
Equity compensation plans 62,276 shares $9.25 per share 82,564 shares
approved by security holders
------------- --------------- -------------
Equity compensation plan not None Not Applicable Not Applicable
approved by security holders
------------- --------------- -------------
TOTAL 62,276 shares $9.25 per share 82,564 shares
17
Unregistered Issuances of Securities
During the last 3 years, the Company has issued certain securities that
have not been covered by a registration statement filed with the Securities and
Exchange Commission. These issuances are as follows:
On October 12, 2001, the Company issued a total of 4,332.751 shares of
common stock of the Company to four members of the board of directors of the
Company. The shares were issued at the request of the directors in lieu of cash
payments due under the Company's long term incentive plan. The shares were
issued at a price of $11.45 per share, or an aggregate of $49,610. With respect
to this issuance of shares, the Company claims an exemption from registration
under Section 4(2) of the Securities Act of 1933 ("Section 4(2)") because of the
limited number of individuals to whom shares were issued, and the fact that the
individuals who received the shares were well informed about the Company and its
affairs and in general are sophisticated investors.
The Company has issued shares of its common stock to certain Company
executives upon the exercise by such executives of options previously granted
pursuant to the Company's 1992 Incentive Stock Option Plan. With respect to
these issuances of shares, the Company claims an exemption from registration
under Section 4(2) because of the limited number of individuals to whom shares
were issued, the fact that each of the individuals who received the shares was
either a current senior Company executive, or had recently retired from a
position as a senior executive of the Company, and that each of such individuals
was well informed about the Company and its affairs. The issuances upon stock
option exercise were as follows:
Executive's
Name and Title Number of Total
at Date of Date of Option Shares Exercise Price Consideration
Option Exercise Exercise Purchased Per Share Paid
- -------------- -------------- --------- -------------- -------------
Larry Geske, December 27, 10,000 $8.375 $83,750
Retired 2001
President and
CEO (retired in
September 2001)
John Allen, Vice December 19, 5,000 $8.375 $41,875
President and 2001
General Counsel
Edward Bernica, November 21, 5,000 $8.50 $42,500
President and 2001
CEO
William Quast, December 19, 2,300 $9.00 $20,700
Treasurer 2000
</Table>
18
Item 6. - Selected Financial Data
Selected Financial Data on a Consolidated Basis (2002-1998)
(dollar amounts in thousands, except per share data)
2002 2001 2000 1999 1998
---------- ---------- ---------- ---------- ----------
Operating results
Operating revenue 99,635 $ 120,161 $ 72,386 $ 53,815 $ 43,064
Operating expenses
Gas and electric purchases 84,052 98,722 58,788 39,687 28,757
General and administrative 8,790 12,095 7,649 8,018 7,697
Maintenance 466 428 400 469 497
Depreciation and amortization 2,059 1,970 1,856 1,695 1,732
Taxes other than income 946 723 639 708 628
---------- ---------- ---------- ---------- ----------
Total operating expenses 96,313 113,938 69,332 50,577 39,311
---------- ---------- ---------- ---------- ----------
Operating income 3,322 6,223 3,054 3,238 3,753
Other income - net 658 282 450 909 209
Total interest charges (1,705) (2,097) (1,674) (1,493) (1,583)
---------- ---------- ---------- ---------- ----------
Income before taxes 2,275 4,408 1,830 2,654 2,379
Income taxes (874) (1,643) (709) (1,067) (859)
---------- ---------- ---------- ---------- ----------
Net Income $ 1,401 $ 2,765 $ 1,121 $ 1,587 $ 1,520
---------- ---------- ---------- ---------- ----------
Basic earnings per common share .55 1.11 .46 .66 .64
Diluted earnings per common share .55 1.10 .46 .66 .64
Dividends per common share .53 .51 .49 .47 .45
Weighted average common shares
Outstanding - diluted 2,558,782 2,509,738 2,456,555 2,418,910 2,390,814
At year end:
Current assets $ 19,090 $ 26,621 $ 16,387 $ 11,429 $ 12,326
Total assets 57,869 62,278 51,194 43,710 42,808
Current liabilities 19,899 24,416 14,831 7,230 7,272
Total long-term obligations 15,367 15,881 16,395 16,840 17,278
Total stockholders' equity 16,272 15,613 13,786 13,532 12,811
---------- ---------- ---------- ---------- ----------
Total capitalization $ 31,639 $ 31,494 $ 30,181 $ 30,372 $ 30,089
========== ========== ========== ========== ==========
19
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 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).
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 Statement of Financial
Accounting Standard (SFAS) 133, Accounting for Derivative Instruments and
Hedging Activities, as amended by SFAS 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, 2002 COMPARED TO FISCAL YEAR ENDED JUNE 30, 2001
NET INCOME
The Company's net income for fiscal 2002 was $1,401,000 compared to $2,765,000
in fiscal 2001, a decrease of $1,364,000. The Company's subsidiary, Energy West
Resources, Inc. ("EWR"), had an earnings decrease of $1,946,000 primarily due to
reductions in revenues from the remarketing of power. EWR's unusually high
margins in fiscal year 2001 resulted from a combination of unusual factors,
including historically high market prices and remarketing of uncommitted power.
The reduction in EWR's net income from fiscal 2001 to fiscal 2002 was partially
offset by an increase in net income in the natural gas operations of $300,000
and the propane operations of $282,000. The increase in natural gas net income
was due primarily to record cold temperatures experienced during the months of
April, May and June, 2002. In addition, the natural gas operations implemented
reductions in discretionary expenses due to warmer-than-normal weather
conditions experienced during the first nine months of the year. The increase in
net income from propane operations is due to the sale of EWP's retail propane
business in Montana and Wyoming.
20
REVENUE
Operating revenues of the Company decreased by 17% from approximately
$120,161,000 in fiscal 2001 to $99,635,000 in fiscal 2002. This decrease was due
primarily to a reduction in EWR's power remarketing revenues of $16,122,000, a
reduction of revenues from the propane operations of $3,123,000, and a reduction
in revenues from the natural gas operations of $1,281,000 due to lower prices of
natural gas.
GROSS MARGIN
Gross margins (operating revenues less cost of goods sold) decreased
approximately $5,856,000 from fiscal 2001 to fiscal 2002. EWR's gross margins
decreased by $5,990,000 due mainly to a decline in revenue from remarketing of
power. The unusually high margins from EWR's operations in fiscal 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 gross margins
in fiscal 2001 to be repeated in future years. The gross margins from the
natural gas operations increased by $170,000 due to an increase in volumes of
gas sold while the gross margin in the propane operations decreased by $36,000
due to higher propane costs.
OPERATING INCOME
The Company's operating income decreased by approximately $2,902,000
from fiscal 2001 to fiscal 2002. Operating income from EWR's operations
decreased by $3,589,000 due to lower gross margins from the remarketing of
power. This lower margin was partially offset by a reduction in EWR's other
operating expenses of $2,401,000.
Operating income from the regulated natural gas operations increased by
approximately $411,000 due to increased gross margins of $170,000 and reductions
in other operating expenses of $241,000.
Propane operations experienced an increase of $275,000 in operating
income primarily due to the gain from the sale of the retail propane assets
reducing general and administrative expenses by $338,000 offset by an increase
in other expenses of $27,000 and gross margin reductions of $36,000.
The Company's total operating expenses decreased by approximately
$2,955,000 from fiscal 2001 to fiscal 2002. This reduction was due primarily to
reduced incentive payments made during fiscal year 2002 compared to fiscal year
2001, and a reduction in corporate overhead 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 2002. The cutbacks
were implemented primarily in reaction to the expectation that warmer than
normal temperatures in Montana, Wyoming and Arizona during the first nine months
of fiscal year 2002 would cause reduced earnings.
INTEREST EXPENSE
Interest expense decreased by $392,000 from fiscal 2001 to fiscal 2002
due to a reduction in short term borrowings and a decrease in short term average
interest rates from 8.4% during fiscal 2001 to approximately 4.6% during fiscal
2002.
21
NONOPERATING INCOME
Nonoperating income increased by $376,000 from fiscal 2001 to fiscal
2002 due in part to a $300,000 settlement received by EWR in connection with its
purchase a group of certain producing natural gas reserves. EWR received the
$300,000 discount on the portion of its purchase price from the seller as a
settlement on certain claims.
FISCAL YEAR ENDED JUNE 30, 2001 COMPARED TO FISCAL YEAR ENDED JUNE 30, 2000
NET INCOME
The Company's net income for fiscal 2001 was $2,765,000 compared to
$1,121,000 in fiscal 2000, an increase of $1,644,000. Net income from natural
gas operations decreased by $198,000, primarily due to increases in
distribution, general and administrative costs over the prior year. In fiscal
year 2000, the Company implemented a planned reduction in certain discretionary
expenses due to the warmer-than-normal weather conditions the Company was
experiencing. In addition, increased corporate overheads from non-recurring
costs increased distribution, general and administrative costs. In fiscal 2001,
the propane operations experienced a decrease in net income of $118,000 also due
to the spending restrictions imposed in the year 2000 that were not repeated in
2001. EWR had an earnings increase of $1,960,000 due to remarketing of
electricity at unusually high market prices. The Company believes that such
remarketing margins are unlikely to continue into the future at the higher
levels experienced during fiscal 2001. The margins 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 for energy marketing and
wholesale operations to be repeated in the future.
REVENUE
Operating revenues increased by $47,775,000, or 66% from fiscal 2000 to
fiscal 2001. This was due to colder temperatures in all the Company's
operations, higher costs of natural gas which are passed directly to the
customers, and remarketing of electricity at unusually high market prices. The
Company does not expect the combination of unusual factors that resulted in the
unusually high income for energy marketing and wholesale operations to be
repeated in the future.
GROSS MARGIN
Gross margins (operating revenues less cost of gas and electric
trading) increased approximately $7,841,000, or 58% from fiscal 2000 to fiscal
2001. The Company's natural gas operations contributed $709,000 of this increase
due to colder temperatures in both the Montana and Wyoming markets served by
this operation. The propane operations contributed $568,000 due to significantly
colder temperatures in all three markets served - Arizona, Wyoming and Montana.
EWR's operations contributed $6,564,000 in increased margins due to remarketing
of electricity at unusually high market prices. The Company does not expect the
combination of unusual factors that resulted in the unusually high income for
energy marketing and wholesale operations to be repeated in the future.
22
OPERATING INCOME
Operating income increased by approximately $3,169,000 from fiscal 2000
to fiscal 2001. EWR's operating income increased by $3,349,000, due mainly to
the remarketing of power at unusually high market prices. Operating income for
the natural gas and propane operations decreased by $175,000 and $4,000
respectively. Gross margin for natural gas operations increased by $709,000;
however, increased operating expenses of nearly $884,000 caused a net reduction
in operating income. The Company had implemented cutbacks in non-essential
operating and maintenance expenses in fiscal 2000, but had not done so during
fiscal 2001. In addition, the Company incurred approximately $473,000 in
corporate overhead costs related to non-recurring strategic expenses, of which
$179,000 was allocated to the natural gas operation.
The breakout of the decrease in operating income from the propane
operations was as follows: gross margins increased by $568,000, but were offset
by an increase in operating expenses of $572,000. The increase in operating
expenses was due to a reduction in non-essential expenses during year 2000,
which were not in place during 2001.
EWR's operating income increased by $3,349,000 due almost entirely to
the remarketing of electricity at unusually high market prices. Gross margin
increased by $6,564,000, which was offset by increased incentives and
commissions of $2,293,000, equating to approximately 3% of the operation's
revenue, an allocation of $224,000 related non-recurring fiscal 2001 strategic
expenses allocated to EWR, and other cost increases resulting from EWR's
expanded operations.
INTEREST EXPENSE
Interest expense increased by $423,000 or 25% from $1,674,000 in fiscal
2000 to $2,097,000 in fiscal 2001, due to higher short-term borrowing, as a
result of higher gas and propane inventories and a higher level of gas costs in
Montana (which were recoverable eventually through the regulatory cost tracking
system.).
NONOPERATING INCOME
Nonoperating income decreased approximately $168,000 or 37% from
$450,000 in fiscal 2000 to $282,000 in fiscal 2001. The primary reason for this
decrease was due to a one-time gain in fiscal 2000 on the sale of various assets
of EWD, which is included with the results of the natural gas operations.
23
OPERATING RESULTS OF THE COMPANY'S NATURAL GAS OPERATIONS
Years Ended June 30
2002 2001 2000
(In thousands)
Operating revenues $39,709 $40,991 $24,301
Gas purchased 29,751 31,203 15,222
------- ------- -------
Gross Margin 9,958 9,788 9,079
Operating expenses 7,540 7,781 6,897
------- ------- -------
Operating Income 2,418 2,007 2,182
Other utility (income) - net (169) (110) (252)
Interest charges 1,161 1,239 1,186
Income taxes 565 317 489
------- ------- -------
Net natural gas income $ 861 $ 561 $ 759
======= ======= =======
FISCAL YEAR ENDED JUNE 30, 2002 COMPARED TO FISCAL YEAR ENDED JUNE 30, 2001
REVENUES AND GROSS MARGINS
Natural gas operating revenues in fiscal 2002 decreased to $39,709,000
from $40,991,000 in fiscal 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
increased 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 natural gas prices
increase or decrease by $.10 per Mcf.
Gross margin, which is defined as operating revenues less gas
purchased, was approximately $9,958,000 for fiscal 2002 compared to
approximately $9,788,000 in fiscal 2001 primarily due to lower cost of gas.
Gas purchases in the natural gas operations decreased by $1,452,000
from $31,203,000 in fiscal 2001 to $29,751,000 in fiscal 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
Natural gas operating expenses, exclusive of the cost of gas purchased
and federal and state income taxes were approximately $7,540,000 for fiscal
2002, as compared to $7,781,000 for fiscal 2001. The reduction of $241,000 is
due to the reduction in non-essential operating expenses and reductions in the
amount of overhead allocated to the natural gas operations.
24
NONOPERATING INCOME
Nonoperating income increased by $59,000 from $110,000 in fiscal 2001
to $169,000 in fiscal 2002. The increase was due primarily to miscellaneous
fixed asset sales during the current fiscal year.
INTEREST CHARGES
Interest charges allocable to the Company's natural gas divisions
reduced by $78,000 from $1,239,000 in fiscal 2001 compared to $1,161,000 during
fiscal 2002. The reduction is the result of lower annual interest rates
experienced in fiscal 2002 and lower short term borrowings by the Company.
INCOME TAXES
State and federal income taxes allocated to the Company's natural gas
divisions increased by $248,000 from $317,000 in fiscal 2001 to $565,000 during
fiscal 2002. The increase was the result of an increase in taxable income of the
natural gas operations.
FISCAL YEAR ENDED JUNE 30, 2001 COMPARED TO FISCAL YEAR ENDED JUNE 30, 2000
REVENUES AND GROSS MARGINS
Natural gas operating revenues in fiscal 2001 increased to $40,991,000
from approximately $24,301,000 in fiscal 2000, or 69%. This was primarily due to
colder temperatures in the two states served by these operations, and higher
rates recovered from customers for the additional costs of gas. The majority of
this increase was in the EWM division. In March 2001, the Montana Public Service
Commission (MPSC) approved recovery of approximately $6,500,000 over one year
for gas costs the Company had incurred prior to that period. Going forward from
that date, the MPSC requires a monthly filing to adjust customer rates if
commodity prices increase or decrease by $.10 per Mcf.
Gross margin, which is defined as operating revenues less gas
purchased, was approximately $9,788,000 for fiscal 2001 compared to
approximately $9,079,000 in fiscal 2000. This increase resulted from colder
temperatures in fiscal 2001. Weather in the Company's Montana operations was 16%
colder than fiscal 2000, and 5% colder than normal. In the Company's Wyoming
operations, weather was 25% colder in fiscal 2001 than fiscal 2000, and 2%
warmer than normal.
Gas purchases in the natural gas operations increased by $15,981,000
from $15,222,000 in fiscal 2000 to $31,203,000 in fiscal 2001, an increase of
nearly 105%. These increased costs are reflective of the additional volumes sold
due to the colder temperatures, 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. The market price of natural gas hit historic
highs during the winter months of fiscal 2001.
25
OPERATING EXPENSES
Natural gas operating expenses, exclusive of the cost of gas purchased
and federal and state income taxes were approximately $7,781,000 for fiscal
2001, as compared to approximately $6,897,000 for fiscal 2000. In fiscal 2000,
the Company reduced non-essential discretionary expenses in response to the
warmer temperatures. The 13% increase in fiscal 2001 is representative of a
return to budgeted expenditures.
OTHER INCOME
Other income declined from $252,000 in fiscal year 2000 to $110,000 in
fiscal year 2001. In fiscal 2000, EWD realized a one-time capital gain of
approximately $95,000 from the sale of property.
INTEREST CHARGES
Interest charges allocable to the Company's natural gas divisions were
approximately $1,239,000 in fiscal 2001, as compared to approximately $1,186,000
in fiscal 2000, primarily due to higher short-term borrowing, as a result of
higher costs of gas, and increased gas costs in Montana that were not recovered
until following the MPSC's ruling in March 2001.
INCOME TAXES
State and federal income taxes allocated to the Company's natural gas
divisions were approximately $317,000 in fiscal 2001, as compared to
approximately $489,000 in fiscal 2000 primarily due to the decrease in pre-tax
earnings.
OPERATING RESULTS OF THE COMPANY'S PROPANE OPERATIONS
Years Ended June 30
(In thousands)
2002 2001 2000
PROPANE OPERATIONS
Operating revenues $11,007 $14,130 $8,481
Cost of propane 6,624 9,711 4,630
------- ------- ------
Gross Margin 4,383 4,419 3,851
Operating expenses 3,129 3,440 2,868
------- ------- ------
Operating income 1,254 979 983
Other (income) expense - net (196) (128) (145)
Interest expense 450 518 366
Income taxes 362 231 287
------- ------- ------
Net propane income $ 639 $ 358 $ 475
======= ======= ======
26
FISCAL YEAR ENDED JUNE 30, 2002 COMPARED TO FISCAL YEAR ENDED JUNE 30, 2001
REVENUES AND GROSS MARGINS
Propane revenues decreased from $14,130,000 in fiscal 2001 to
$11,007,000 in fiscal 2002, a reduction of $3,123,000 or 22%. This decrease in
revenues was due mainly to lower spot market prices for propane sold during
fiscal year 2002 as well as a 10% reduction in volumes sold from fiscal 2001
compared to fiscal 2002. In addition, the sale of EWP's retail propane
operations in Montana and Wyoming caused a reduction in total revenues of
approximately $383,000. The propane operations were able to utilize the lower
market prices advantageously to purchase lower priced propane. The cost of
propane sold decreased from $9,711,000 during fiscal 2001 to $6,624,000 in
fiscal 2000, a reduction of approximately 32%. Gross margins decreased by
$36,000, or less than 1%.
OPERATING EXPENSES
Operating expenses were $3,129,000 for fiscal 2002 compared to
$3,440,000 for fiscal 2001, a decrease of $311,000. The operating expenses
decreased due to a reduction in general and administrative expenses of $338,000
resulting from the sale of EWP's retail propane assets in Montana and Wyoming.
This was offset by costs incurred for propane pipeline safety maintenance in the
EWA division.
NONOPERATING INCOME
Other income increased by $68,000 from $128,000 in fiscal 2001 to
$196,000 in fiscal year 2002.
INTEREST EXPENSE AND INCOME TAXES
Interest expense was reduced from $518,000 in fiscal 2001 to $450,000
in fiscal 2002. The reduction of $68,000 is due to lower interest costs
allocated to the propane operations resulting from lower overall borrowings by
the Company and the lower average interest rates on short term borrowings.
Income taxes increased from $231,000 in fiscal 2002 to $362,000 in fiscal 2002
due to higher taxable income for the year.
FISCAL YEAR ENDED JUNE 30, 2001 COMPARED TO FISCAL YEAR ENDED JUNE 30, 2000
REVENUES AND GROSS MARGINS
Propane revenues increased approximately $5,649,000 or 67% from
$8,481,000 in fiscal 2000 to $14,130,000 in fiscal 2001. These increases
occurred primarily because of significantly colder temperatures in EWP's market
areas in Arizona, Wyoming and Montana, and higher propane prices during the
winter months of fiscal 2001. Gross margin increased by approximately $568,000,
again due to the weather related increases. Weather in 2001 was closer to normal
versus much warmer than normal temperatures in fiscal year 2000.
EXPENSES FOR OPERATIONS, INTEREST AND INCOME TAXES
Operating expenses for propane operations increased from approximately
$2,868,000 in fiscal 2000 to approximately $3,440,000 in fiscal 2001, an
increase of $572,000. The increase in operating expenses was primarily due to
the fact that the Company had imposed certain spending reductions during fiscal
2000 in response to the unusually warm temperatures. In fiscal year 2001, the
Company returned to more normal spending patterns. Interest charges allocable to
the Company's propane divisions were approximately $518,000 in fiscal 2001
compared to approximately $366,000 in fiscal 2000. The increased interest costs
were primarily due to increased average capital employed in fiscal year 2001.
State and federal income taxes decreased to approximately $231,000 for fiscal
2001 from $287,000 for fiscal 2000 due to lower pre-tax income in the propane
operations in fiscal 2001.
27
OPERATING RESULTS OF ENERGY WEST RESOURCES, INC.
Years Ended June 30
2002 2001 2000
(In thousands)
ENERGY WEST RESOURCES, INC (EWR)
Gas & electric trading revenue $48,917 $65,039 $39,604
Cost of gas & electric trading 47,676 57,808 38,937
------- ------- -------
Gross margin 1,241 7,231 667
Operating expenses 1,593 3,994 779
------- ------- -------
Operating income (loss) (352) 3,237 (112)
Other (income) (293) (43) (54)
Interest expense 94 338 122
Income tax expense (benefit) (54) 1,095 (67)
------- ------- -------
Net marketing income (loss) $ (99) $ 1,847 $ (113)
======= ======= =======
FISCAL YEAR ENDED JUNE 30, 2002 COMPARED TO FISCAL YEAR ENDED JUNE 30, 2001
REVENUES
EWR's revenues decreased $16,122,000 from fiscal 2001 to fiscal 2002.
The 25% decrease was attributable to the reduction in revenues associated with
the remarketing of power. Additionally, lower commodity prices in fiscal 2002
were reflected in revenue.
GROSS MARGINS
EWR experienced a reduction in gross margin from fiscal 2001 to fiscal
2002 of $5,990,000. The majority of this 83% decrease in gross margin was
attributable to the reduction in margins associated with the remarketing of
electricity. EWR benefited from unusually high market prices during fiscal year
2001. The same market conditions were not present during fiscal year 2002.
OPERATING EXPENSES
Operating expenses for EWR were $1,593,000 during fiscal 2002 compared
to $3,994,000 during fiscal 2001. The $2,401,000 decrease was due mainly to a
reduction in incentives and commissions related to the decrease in gross
margins. These reductions were offset in part by approximately $535,000 in legal
expenses incurred by EWR in fiscal 2002 related to its ongoing litigation with
PPL, Montana (described in Part II, Item 1, Legal Proceedings).
28
NONOPERATING INCOME
EWR's nonoperating income was $250,000 higher in fiscal year 2002
compared to fiscal year 2001. The majority of this increase was due to a
$300,000 settlement received by EWR as in connection with its purchase of a
group of producing natural gas reserves located in northern Montana. EWR
received the $300,000 discount on its purchase price from the seller as a
settlement on certain claims against the seller. This transaction took place
during the fourth quarter of fiscal 2002.
INTEREST EXPENSE
Interest expense decreased during fiscal year 2002 by $244,000 due
mainly to a decrease in short-term borrowing rates, as well as an overall
reduction in borrowing.
INCOME TAXES
The EWR operations realized an income tax benefit of $54,000 during
fiscal 2002 compared to an expense of $1,095,000 in fiscal year 2001 due to the
reduction in taxable income from its operations.
FISCAL YEAR ENDED JUNE 30, 2001 COMPARED TO FISCAL YEAR ENDED JUNE 30, 2000
REVENUE
EWR's revenue increased by $25,435,000 from fiscal 2000 to fiscal 2001.
The 69% increase was a result of the remarketing of power at unusually high
market prices. Additionally, the commodity price of gas in fiscal 2001 was
higher than in fiscal 2000 which is also reflected in increased revenue.
GROSS MARGINS
EWR's gross margins increased by $6,564,000 from fiscal 2000 to fiscal
2001 mainly as result of a combination of unusual factors, including
historically high market prices and remarketing of uncommitted power. The
Company does not expect these unusual conditions to continue in future periods.
EXPENSES FOR OPERATIONS, INTEREST AND INCOME TAXES
EWR's operating expenses related to energy marketing and wholesale
activities increased from approximately $779,000 in fiscal 2000 to approximately
$3,994,000 in fiscal 2001. The increase of $3,215,000 (or 5% of EWR's revenue)
was mainly due to higher incentive and commissions related to higher margins in
fiscal 2001, and costs related to non-recurring strategic expenses. Interest
charges increased approximately $216,000 from fiscal 2000 to fiscal 2001 due to
increased working capital requirements in fiscal 2001. State and federal income
taxes increased in fiscal 2001 to approximately $1,095,000 from a benefit of
$67,000 in fiscal 2000, due to the increase in pre-tax earnings.
CASH FLOW ANALYSIS
The primary cash flows during the last three years are summarized below:
2002 2001 2000
--------------- ---------------- ----------------
Provided by Operating activities $7,114,030 $6,008,065 $ 616,282
Used in investing activities (5,149,890) (3,287,843) (4,133,615)
Provided by (used in) financing
activities (1,817,150) (2,611,729) 3,403,537
----------- ----------- ------------
Net increase (decrease) in cash
and cash equivalents $ 146,990 $ 108,493 $ (113,796)
=========== =========== ============
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,
normal capital expenditure and dividend requirements.
29
LIQUIDITY AND CAPITAL RESOURCES
The Company's utility operations are subject to regulation by the MPC,
the WYPSC, and the ACC. This factor plays a significant role in determining the
Company's return on equity. The various commissions approve rates that are
intended to permit a specified rate of return on
30
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 cost are incurred by the Company and the time that the Company recovers
such costs from customers.
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.
Because of the seasonal nature of the Company's sales, cash generated
from operations during the warmer months (when sales volumes decrease
considerably) is significantly lower than during colder months. Additionally,
most of the Company's construction activity takes place during the non-heating
season because of more favorable weather conditions. During these warmer,
non-heating months, cash needs for operations and construction are primarily met
through short-term borrowings.
Capital expenditures for the Company and its subsidiaries for fiscal
2003 are expected to be $3.3 million. The capital expenditures will be made for
system extensions as well as the replacement and improvement of existing
transmission, distribution, gathering and general facilities.
At June 30, 2002, the Company had $26,000,000 in bank lines of credit,
of which $3,500,000 had been borrowed the application at June 30, 2002. The
Company's short-term borrowings under these lines of credit during fiscal 2001
had a daily weighted average interest rate of 4.60% per annum. At the June 30,
2002, the Company had outstanding letters of credit totaling $4,150,000 related
to electricity and gas purchase contracts. These letters of credit are netted
against the Company's bank lines of credit, resulting in net availability of
$18,350,000 under the lines of credit at June 30, 2002.
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
obligations: $8.0 million of Series 1997 unsecured notes bearing interest at the
rate of 7.5%; $7.8 million of Series 1993 unsecured notes bearing interest at
rates ranging from 6.20% to 7.60%; and Cascade County, Montana Series 1992B
Industrial Development Revenue Obligations in the amount of $1.8 million.
The total amount of such obligations was $15,856,000 and $16,346,000,
at June 30, 2002 and June 30, 2001, respectively. The portion of such
obligations due within one year was $500,000 and $465,000, at June 30, 2001, and
June 30, 2002, respectively. Under the terms of such Long-Term Debt obligations,
additional principal payments of $530,000 will be due during fiscal 2004,
$570,000 during fiscal 2005, $610,000 during fiscal 2006, $655,000 during fiscal
2007, and $12,991,000 during periods after fiscal 2007.
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 "Less than 1 year" amount listed below for "Unconditional Purchase
Obligations" represents purchase obligations of natural gas under take or pay
agreements and obligations due within one year related to operating lease
commitments.
31
Payments Due by Period
Less
Contractual than 1 - 3 4 - 5 After 5
Obligations Total 1 year years years years
- ----------- ----- ------ ----- ----- -----
Long-Term Debt 15,856,000 500,000 1,100,000 1,265,000 12,991,000
---------- --------- --------- --------- -------
Capital Lease
Obligations 13,496 2,072 5,093 6,331 --
---------- --------- --------- --------- -------
Unconditional
Purchase Obligations 10,077,613 3,281,802 4,215,871 1,647,789 932,151
---------- --------- --------- --------- -------
Under the terms of the Long Term Debt obligations, the Company is
subject to certain restrictions, including restrictions on total dividends and
distributions, senior indebtedness, and asset sales, and the Company is required
to maintain certain financial debt and interest ratios.
An adverse outcome in the litigation with PPLM or the tax dispute with
the DOR could have a material adverse effect on the Company's liquidity and
capital resources. See "Item 3-Legal Proceedings."
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 is in transition. Legislative and regulatory
initiatives, at both the federal and state levels, have been 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 No. 71 "Accounting for the Effects of Certain
Types of Regulation," ("SFAS 71"), 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
32
propane vapor operations were to discontinue the application of SFAS 71, the
accounting impact would be an extraordinary, non-cash charge to operations that
could be material to the financial position and results of operation of the
Company. However, the Company is unaware of any circumstances or events in the
foreseeable future that would cause it to discontinue the application of SFAS
71.
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;
- - The impact of FERC and state public service commission statutes and
regulation, including allowed rates of return, the pace of deregulation in
retail natural gas and electricity markets, 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 (including the possibility of adverse outcomes) of
legal and administrative claims and proceedings against the Company or its
subsidiaries, particularly the litigation with PPLM and the property tax
dispute with the DOR;
- - 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.
33
RATIO OF EARNINGS TO FIXED CHARGES
For the twelve months ended June 30, 2002, 2001 and 2000, the Company's
ratio of earnings to fixed charges was 2.20, 2.95 and 1.95 times, respectively.
Fixed charges include interest related to long-term debt, short-term borrowing,
certain lease obligations and other current liabilities.
INFLATION
Capital intensive businesses, such as the Company's natural gas 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, the Company anticipates that it will be permitted to recover and
earn a rate of return on the actual cost of its investment in the replacement or
upgrade of plant assets. Although prices for natural gas and propane vapor may
fluctuate, earnings are not impacted by such fluctuation because gas and propane
vapor cost tracking procedures approved by 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 a service center by the
Company. The coal gasification process utilized in the manufactured gas plant
resulted in the production of certain by-products that have been classified by
the federal government and the State of Montana as hazardous to the environment.
In 1999, the Company received approval from the Montana Department of
Environmental Quality ("MDEQ") for a plan proposed by the Company for
remediation of soil contaminants at the site. To date, all contaminated soil has
been removed, and an asphalt cap has been placed over the site. The Company and
its consultants continue their work with the MDEQ relating to a remediation plan
proposed by the Company for water contaminants.
At June 30, 2002, the Company had incurred cumulative costs of
approximately $1,950,000 in connection with its evaluation and remediation of
the 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, 2002, the Company had
recovered approximately $1,276,000 through such surcharges. The Company expects
to recover the full amount expended through the surcharge. The Commission's
decision calls for ongoing review by the Commission of any costs incurred. The
Company will submit an application for review by the Commission when the
remediation plan for water contaminants is approved by the MDEQ.
34
DERIVATIVES AND RISK MANAGEMENT
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 and its subsidiaries have established certain policies and
procedures to manage such risks. The Company has a Risk Management Committee
("RMC"), comprised of Company officers 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 impacts on earnings resulting from
volatility of energy prices, counter-party credit risks, and other risks related
to the energy commodity business. The RMC is overseen by the Audit Committee of
the Company's Board of Directors.
GENERAL - From time to time the Company or its subsidiaries may use
derivative financial contracts to mitigate the risk of commodity price
volatility related to firm commitments to purchase and sell natural gas or
electricity. The Company or a subsidiary 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 Statement of
Financial Accounting Standard (SFAS) 133, "Accounting for Derivative Instruments
and Hedging Activities" as amended by SFAS 138 "Accounting for Certain
Derivative Instruments and Certain Hedging Activities," which the Company
adopted July 1, 2000.
In accordance with SFAS 133, such financial instruments are 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, are realized over the life of the contracts.
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
developed valuation models that incorporate available current and historical
independent pricing information. The use of such models is inherently less
reliable than reference to an active market or exchange in determining fair
value.
The Company classifies contracts under which the Company or a
subsidiary agrees to future purchases or sales of physical volumes of natural
gas as normal purchase or sale arrangements, and therefore is not required to
use mark-to-market valuation for such contracts under SFAS 133.
WHOLESALE OPERATIONS - During fiscal year 2001 and part of fiscal year
2002, EWR was party to a number of contracts, which were valued on a
mark-to-market basis under SFAS 133. Although certain firm commitments to
purchase and sell could potentially have been classified as
35
normal purchases and sales, and excluded from the valuation requirements of SFAS
133, EWR elected to classify these commitments as derivatives subject to the
mark-to-market valuation under SFAS 133 in order to properly match commitments
to purchase and sell for financial reporting purposes. Therefore, such
commitments were recorded in the Company's consolidated balance sheet at fair
value. Quarterly mark-to-market adjustments to the fair values of these
commitments were recorded in gross margin.
In January 2002, EWR terminated its derivative contracts with Enron
Canada Corporation (ECC), a subsidiary of Enron, Inc. Most of these contracts
were commodity swaps that EWR had obtained to protect against fluctuations in
the market price of natural gas. The derivative contracts with ECC were entered
into at various times in order to lock in margins on certain agreements under
which EWR had agreed to sell natural gas to customers for future delivery at
fixed prices (the "Future Supply Agreements"). EWR made the decision to
terminate these ECC contracts because of concerns relating to the bankruptcy of
Enron, Inc. At the time of termination, the prevailing price of natural gas was
substantially lower than such price had been at the times when EWR entered into
the ECC contracts, resulting in a net amount due from EWR to ECC of
approximately $5,400,000. EWR paid this amount to ECC upon the termination of
the ECC contracts, and thereby discharged the liability related to the
contracts. The net effect of the termination on the Company's consolidated net
income was immaterial. The costs related to such termination are reflected in
the Company's Consolidated Income Statement as Gas Purchases.
At the time it terminated the ECC derivative contracts, EWR secured new
gas purchase contracts (the "Future Purchase Agreements") at prices much lower
than those provided for under the ECC contracts. The Future Supply Agreements
continue to be valued on a mark-to market basis. Therefore, the value of such
agreements has been reflected in the Company's consolidated net income.
As of June 30, 2002, the Future Supply Agreements were reflected on the
Company's Consolidated Balance Sheet at an approximate aggregate fair value as
follows:
Contracts maturing in one year or less: $1,252,000
Contracts maturing in two to three years: $1,027,000
Contracts maturing in four to five years: $ 489,000
Contracts maturing in five years or more: $ 100,000
The Company does not expect the values of such Future Supply Agreements
to fluctuate significantly because the values are a function of the fixed prices
under both the Future Supply Agreements and the Future Purchase Agreements.
Therefore, EWR expects that the present value of future cash collections (net of
the cost of the commodity supplied) under such agreements will be approximately
equal to the amounts set forth above. Factors that could negatively affect the
ability of EWR to realize on such net cash collections include credit risk
associated with individual customers, and possible volume demands in excess of
the amount for which EWR has contracted at a fixed price under the Future
Purchase Agreements. The Company does not expect such factors to have a material
effect, although no assurance can be given that such factors will not negatively
and materially affect such expected cash collections.
36
Failure to realize the full amount of expected net cash collections would
negatively affect the Company's future income.
Since January 2002, EWR has not entered into any new contracts that
have required mark-to-market valuation under SFAS 133.
NATURAL GAS OPERATIONS - In the case of the Company's regulated
divisions, gains or losses resulting from the eventual settlement of derivative
contracts are subject to deferral under regulatory procedures approved by the
public service regulatory commissions of Montana, Wyoming and Arizona.
Therefore, related derivative assets and liabilities are offset with
corresponding regulatory liability and asset amounts included in "Recoverable
Cost of Gas Purchases", pursuant to SFAS 71, "Accounting for Certain Types of
Regulation." Thus, SFAS 133 has no effect on earnings from the Company's
regulated operations.
SUPPLEMENTAL QUARTERLY FINANCIAL INFORMATION
Supplemental quarterly financial information is set forth in Note 15 to
the Company's Consolidated Financial Statements.
CAUTIONARY STATEMENT FOR PURPOSES OF THE "SAFE HARBOR" PROVISIONS OF THE PRIVATE
SECURITIES LITIGATION REFORM ACT OF 1995
The foregoing Management's Discussion and Analysis and other portions
of this annual report on Form 10-K contain various "forward looking statements"
within the meaning of Section 27A of the Securities Act of 1933, as amended, and
Sections 21E of the Securities Exchange Act of 1934, as amended, which represent
the Company's expectations or beliefs concerning future events. Forward-looking
statements can be identified by words such as "anticipates," "believes,"
"expects," "planned," "scheduled" or similar expressions. Although the Company
believes these forward-looking statements are based on reasonable assumptions,
statements made regarding future results are subject to a number of assumptions,
uncertainties and risks that could cause future results to be materially
different from the results stated or implied in this document.
Such forward-looking statements, as well as other oral and written
forward-looking statements made by or on behalf of the Company from time to
time, including statements contained in the Company's filings with the
Securities and Exchange Commission and its reports to shareholders, involve
known and unknown risks and other factors which may cause the Company's actual
results in future periods to differ materially from those expressed in any
forward-looking statements. Factors that could cause or contribute to such
differences included, but are not limited to: (i) fluctuations in energy
commodity prices, including prices for fuel and purchased power, (ii) the impact
of state and federal laws and regulations, (iii) the possibility that regulators
may not permit the Company to pass through all costs to customers, (iv)
fluctuations in wholesale margins due to uncertainty in the wholesale gas,
propane and power markets, (iv) costs and expenses of, and uncertainties
relating to, pending litigation and other disputes, particularly the litigation
with PPLM and the property tax dispute with the DOR, and (v) other factors
discussed above, including items under the heading "Risk Factors."
37
Any such forward-looking statement is qualified by reference to these
risks and factors. The Company cautions that these risks and factors are not
exclusive. The Company does not undertake to update any forward-looking
statement that may be made from time to time by or on behalf of the Company
except as required by law.
Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Company and its subsidiaries are subject to certain market risks,
including commodity price risk (i.e., natural gas, electric and propane prices)
and interest rate risk. The adverse effects of potential changes in these market
risks are discussed below. The sensitivity analyses presented do not consider
the effects that such adverse changes may have on overall economic activity nor
do they consider additional actions management may take to mitigate the
Company's exposure to such changes. Actual results may differ. See the notes to
the financial statements for a description of the Company's accounting policies
and other information related to these financial instruments.
COMMODITY PRICE RISK
The Company protects itself against price fluctuations on natural gas
and electricity by limiting the aggregate level of net open positions, which are
exposed to market price changes and through the use of natural gas derivative
instruments. The net open position is actively managed with strict policies
designed to limit the exposure to market risk, and which require at least weekly
reporting to management of potential financial exposure. The risk management
committee has limited the types of financial instruments the Company or its
subsidiaries may trade to those related to natural gas commodities. The
Company's results of operations are significantly impacted by changes in the
price of natural gas. During 2002 and 2001, natural gas accounted for 66% and
77% respectively, of the Company's operating expenses. The Company's regulated
operations are allowed recovery of costs associated with the purchase of natural
gas. In most cases, these costs are recovered within one year which mitigates
the risk associated with changes in the market price of the commodity.
INTEREST RATE RISK
The Company's results of operations are affected by fluctuations in
interest rates (e.g. interest expense on debt). The Company mitigates this risk
by entering into long-term debt agreements with fixed interest rates. The
Company's notes payable are subject to variable interest rates. Based on the
amount of the outstanding notes payable on June 30, 2002, a one percent increase
(decrease) in average interest rates would result in a decrease (increase) in
annual pre-tax net income of approximately $35,000. See Note 7 to the Company's
Consolidated Financial Statements.
CREDIT RISK
Credit risk relates to the risk of loss that the Company would incur as
a result of non-performance by counterparties of their contractual obligations
under the various instruments with the Company. Credit risk may be concentrated
to the extent that one or more groups of counterparties have similar economic,
industry or other characteristics that would cause their ability to meet
contractual obligations to be similarly affected by changes in market or other
conditions. In addition, credit risk includes not only the risk that a
counterparty may default due to circumstances relating directly to it, but also
the risk that a counterparty may default due to circumstances which relate to
other market participants which have a direct or indirect
38
relationship with such counterparty. The Company seeks to mitigate credit risk
by evaluating the financial strength of potential counterparties. However,
despite mitigation efforts, defaults by counterparties may occur from time to
time. To date, no material default has occurred.
39
Item 8. Financial Statements and Supplementary Data
Report of Independent Auditors
To the Board of Directors and Stockholders of
Energy West Incorporated
Great Falls, Montana
We have audited the accompanying consolidated balance sheet of Energy West
Incorporated and subsidiaries as of June 30, 2002, and the related consolidated
statements of income, stockholders' equity, and cash flows for the year then
ended. Our audit also included the information for the year ended June 30, 2002
in the financial statement schedule listed in the Index at Item 14. These
financial statements and financial statement schedule are the responsibility of
the Company's management. Our responsibility is to express an opinion on the
financial statements and financial statement schedule based on our audit.
We conducted our audit in accordance with auditing standards generally accepted
in the United States of America. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audit provides a
reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all
material respects, the financial position of Energy West Incorporated and
subsidiaries at June 30, 2002, and the results of their operations and their
cash flows for the year then ended, in conformity with accounting principles
generally accepted in the United States of America. Also, in our opinion, the
information for the year ended June 30, 2002, in the financial statement
schedule, when considered in relation to the basic consolidated financial
statements taken as a whole, presents fairly in all material respects the
information set forth therein.
DELOITTE & TOUCHE LLP
Salt Lake City, Utah
September 25, 2002
40
Report of Independent Auditors
The Board of Directors
Energy West Incorporated
We have audited the accompanying consolidated balance sheet of Energy West
Incorporated and subsidiaries as of June 30, 2001, and the related consolidated
statements of income, stockholders' equity, and cash flows for each of the two
years in the period ended June 30, 2001. Our audits also included the
information for each of the two years in the period ended June 30, 2001 in the
financial statement schedule listed in the index at item 14(a). These financial
statements and schedule are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements and
schedule based on our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States. Those standards require that we plan and perform the audit
to obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant estimates
made by management, as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for our
opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the consolidated financial position of Energy West
Incorporated and subsidiaries at June 30, 2001, and the consolidated results of
their operations and their cash flows for each of the two years in the period
ended June 30, 2001, in conformity with accounting principles generally accepted
in the United States. Also, in our opinion, the related financial statement
schedule for each of the two years in the period ended June 30, 2001, when
considered in relation to the basic financial statements taken as a whole,
presents fairly in all material respects, the information set forth therein.
ERNST & YOUNG LLP
Salt Lake City, Utah
August 31, 2001
41
ENERGY WEST INCORPORATED AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS, JUNE 30, 2002 AND 2001
- --------------------------------------------------------------------------------
ASSETS 2002 2001
CURRENT ASSETS:
Cash and cash equivalents $ 367,657 $ 220,667
Accounts receivable (net of allowance of $154,251
and $204,570 at June 30, 2002 and 2001, respectively) 8,244,239 10,331,403
Derivative assets 2,867,717 3,444,861
Natural gas and propane inventories 5,640,660 4,767,546
Materials and supplies 593,674 631,574
Prepayments and other 445,652 401,142
Deferred tax assets 931,147 --
Recoverable cost of gas purchases -- 6,824,220
----------- -----------
Total current assets 19,090,746 26,621,413
NOTES RECEIVABLE 3,300 137,927
PROPERTY, PLANT, AND EQUIPMENT, Net 36,518,908 32,999,158
DEFERRED CHARGES 1,935,263 2,314,671
OTHER ASSETS 320,830 204,466
----------- -----------
TOTAL ASSETS $57,869,047 $62,277,635
=========== ===========
See notes to consolidated financial statements. (Continued)
42
ENERGY WEST INCORPORATED AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS, JUNE 30, 2002 AND 2001
- --------------------------------------------------------------------------------
CAPITALIZATION AND LIABILITIES 2002 2001
CURRENT LIABILITIES:
Current portion of long-term debt $ 502,072 $ 465,000
Lines of credit 3,500,000 3,785,989
Accounts payable 7,413,693 7,305,120
Derivative liabilities -- 3,921,354
Income taxes payable 1,005,975 1,840,591
Deferred income taxes -- 631,305
Refundable cost of gas purchases 2,024,159 --
Accrued and other current liabilities 5,453,304 6,466,626
---------- ----------
Total current liabilities 19,899,203 24,415,985
---------- ----------
LONG-TERM LIABILITIES:
Deferred income taxes 4,043,038 3,835,513
Deferred investment tax credits 376,468 397,530
Other long-term liabilities 1,910,571 2,134,333
---------- ----------
Total 6,330,077 6,367,376
---------- ----------
LONG-TERM DEBT 15,367,424 15,881,000
---------- ----------
COMMITMENTS AND CONTINGENCIES (Notes 3, 7, 8, 13, and 14)
STOCKHOLDERS' EQUITY:
Preferred stock; $.15 par value, 1,500,000 shares authorized,
no shares outstanding
Common stock; $.15 par value, 3,500,000 shares authorized,
2,573,046 and 2,513,383 shares outstanding at June 30, 2002
and 2001, respectively 385,964 377,015
Capital in excess of par value 4,863,113 4,248,310
Retained earnings 11,023,266 10,987,949
---------- ----------
Total stockholders' equity 16,272,343 15,613,274
---------- ----------
TOTAL CAPITALIZATION 31,639,767 31,494,274
---------- ----------
TOTAL CAPITALIZATION AND LIABILITIES $57,869,047 $62,277,635
=========== ===========
See notes to consolidated financial statements. (Concluded)
43
ENERGY WEST INCORPORATED AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
FOR THE YEARS ENDED JUNE 30, 2002, 2001, AND 2000
- --------------------------------------------------------------------------------
2002 2001 2000
REVENUES:
Natural gas operations $ 39,709,775 $ 40,991,236 $ 24,301,491
Propane operations 11,007,389 14,130,518 8,480,531
Gas and electric -- wholesale 48,917,476 65,039,290 39,603,660
------------- ------------- -------------
Total revenues 99,634,640 120,161,044 72,385,682
------------- ------------- -------------
EXPENSES:
Gas purchased 36,180,500 40,711,934 19,608,511
Gas and electric -- wholesale 47,676,271 57,807,640 38,936,671
Cost of goods sold 195,254 202,775 243,128
Distribution, general, and administrative 8,790,183 12,094,815 7,648,834
Maintenance 465,772 427,767 399,579
Depreciation and amortization 2,059,170 1,970,081 1,856,453
Taxes other than income 946,214 722,776 638,788
------------- ------------- -------------
Total expenses 96,313,364 113,937,788 69,331,964
------------- ------------- -------------
OPERATING INCOME 3,321,276 6,223,256 3,053,718
NON-OPERATING INCOME 657,887 281,559 450,019
INTEREST EXPENSE:
Long-term debt (1,187,749) (1,225,840) (1,242,380)
Lines of credit (516,743) (870,727) (431,523)
------------- ------------- -------------
Total interest expense (1,704,492) (2,096,567) (1,673,903)
INCOME BEFORE INCOME TAXES 2,274,671 4,408,248 1,829,834
INCOME TAX EXPENSE (873,881) (1,643,111) (708,564)
------------- ------------- -------------
NET INCOME $ 1,400,790 $ 2,765,137 $ 1,121,270
============= ============= =============
EARNINGS PER COMMON SHARE:
Basic $ 0.55 $ 1.11 $ 0.46
============= ============= =============
Diluted $ 0.55 $ 1.10 $ 0.46
============= ============= =============
WEIGHTED AVERAGE COMMON SHARES
OUTSTANDING:
Basic 2,549,245 2,495,537 2,456,555
============= ============= =============
Diluted 2,558,782 2,509,738 2,456,555
============= ============= =============
See notes to consolidated financial statements.
44
ENERGY WEST INCORPORATED AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
FOR THE YEARS ENDED JUNE 30, 2002, 2001, AND 2000
- --------------------------------------------------------------------------------
CAPITAL IN
COMMON EXCESS OF RETAINED
SHARES STOCK PAR VALUE EARNINGS TOTAL
BALANCE AT JULY 1, 1999 2,433,740 $ 365,065 $ 3,560,541 $ 9,606,409 $ 13,532,015
Sales of common stock at $7.930 to $8.502
per share under the Company's dividend
reinvestment plan 24,499 3,677 194,779 -- 198,456
Issuance of common stock to ESOP at
estimated fair value of $8.922 per share 16,153 2,423 141,695 -- 144,118
Issuance of common stock at $9.149 per share
under the Company's deferred board stock
compensation plan 1,043 156 9,386 9,542
Net income 1,121,270 1,121,270
Dividends -- -- -- (1,219,196) (1,219,196)
------------ ------------ ------------ ------------ ------------
BALANCE AT JUNE 30, 2000 2,475,435 371,321 3,906,401 9,508,483 13,786,205
Exercise of stock options at $9.00 per share 2,300 345 20,355 -- 20,700
Sales of common stock at $7.990 to $11.800
per share under the Company's dividend
reinvestment plan 21,838 3,277 212,976 -- 216,253
Issuance of common stock to ESOP at
estimated fair value of $8.012 per share 13,810 2,072 108,578 -- 110,650
Net income 2,765,137 2,765,137
Dividends -- -- -- (1,285,671) (1,285,671)
------------ ------------ ------------ ------------ ------------
BALANCE AT JUNE 30, 2001 2,513,383 377,015 4,248,310 10,987,949 15,613,274
Exercise of stock options at $8.375 to $9.187
per share 24,002 3,600 200,974 -- 204,574
Sales of common stock at $8.012 to $11.958
per share under the Company's dividend
reinvestment plan 10,698 1,604 118,134 -- 119,738
Issuance of common stock to ESOP at
estimated fair value of $12.110 per share 20,631 3,095 246,743 -- 249,838
Issuance of common stock at $11.450 per
share under the Company's deferred board
stock compensation plan 4,332 650 48,952 -- 49,602
Net income 1,400,790 1,400,790
Dividends -- -- -- (1,365,473) (1,365,473)
------------ ------------ ------------ ------------ ------------
BALANCE AT JUNE 30, 2002 2,573,046 $ 385,964 $ 4,863,113 $ 11,023,266 $ 16,272,343
============ ============ ============ ============ ============
See notes to consolidated financial statements.
45
ENERGY WEST INCORPORATED AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED JUNE 30, 2002, 2001, AND 2000
- --------------------------------------------------------------------------------
2002 2001 2000
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 1,400,790 $ 2,765,137 $ 1,121,270
Adjustments to reconcile net income to
net cash provided by operating activities:
Depreciation and amortization, including deferred
charges and financing costs 2,326,909 2,378,894 2,132,118
Gain on sale of assets (393,584) -- (145,289)
Investment tax credit (21,062) (21,062) (21,062)
Deferred gain on sale of assets (23,628) (23,628) (23,628)
Deferred income taxes (1,354,927) (883,589) 834,876
Changes in assets and liabilities:
Accounts receivable 2,087,164 (2,640,452) (1,657,131)
Derivative assets 577,144 (3,405,971) (38,890)
Natural gas and propane inventories (873,114) (2,853,845) (489,791)
Accounts payable 108,573 945,828 2,157,349
Derivative liabilities (3,921,354) 3,921,354 --
Recoverable/refundable cost of gas purchases 8,848,379 (2,110,825) (1,872,420)
Prepayments and other (44,510) (40,314) (206,185)
Other assets and liabilities (1,602,750) 7,976,538 (1,174,935)
------------ ------------ ------------
Net cash provided by operating activities 7,114,030 6,008,065 616,282
------------ ------------ ------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Construction expenditures (5,485,108) (3,276,251) (4,756,883)
Acquisition of producing natural gas reserves,
net of settlement (see Note 2) (956,888) -- --
Proceeds from sale of assets 1,188,458 10,044 541,988
Proceeds from notes receivable 134,627 24,458 26,061
Customer advances refunded for construction (28,078) (68,869) (119)
Increase (decrease) from contributions in aid of
construction (2,901) 22,775 55,338
------------ ------------ ------------
Net cash used in investing activities (5,149,890) (3,287,843) (4,133,615)
------------ ------------ ------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Repayments of long-term debt (490,000) (494,000) (430,723)
Proceeds from lines of credit 44,084,650 83,035,477 44,325,000
Repayments of lines of credit (44,370,639) (84,104,488) (39,470,000)
Sales of common stock 324,312 236,953 198,456
Dividends paid (1,365,473) (1,285,671) (1,219,196)
------------ ------------ ------------
Net cash provided by (used in) financing activities (1,817,150) (2,611,729) 3,403,537
------------ ------------ ------------
NET INCREASE (DECREASE) IN CASH AND
CASH EQUIVALENTS 146,990 108,493 (113,796)
CASH AND CASH EQUIVALENTS AT BEGINNING
OF YEAR 220,667 112,174 225,970
------------ ------------ ------------
CASH AND CASH EQUIVALENTS AT END OF YEAR $ 367,657 $ 220,667 $ 112,174
============ ============ ============
(Continued)
46
ENERGY WEST INCORPORATED AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED JUNE 30, 2002, 2001, AND 2000
- --------------------------------------------------------------------------------
2002 2001 2000
SUPPLEMENTAL DISCLOSURES OF
CASH FLOW INFORMATION:
Cash paid during the period for interest $2,025,468 $2,047,819 $1,639,867
Cash paid during the period for income taxes 2,937,134 275,000 460,000
SUPPLEMENTAL SCHEDULE OF NONCASH
INVESTING AND FINANCING ACTIVITIES:
ESOP shares issued 249,838 110,650 144,118
Capital lease 13,496 -- --
See notes to consolidated financial statements. (Concluded)
47
ENERGY WEST INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
JUNE 30, 2002 AND 2001
- --------------------------------------------------------------------------------
1. SUMMARY OF BUSINESS AND SIGNIFICANT ACCOUNTING POLICIES
NATURE OF BUSINESS -- Energy West Incorporated (the "Company") is a
regulated public entity with certain non-utility operations conducted
through its subsidiaries. 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").
The Company's non-regulated operations include wholesale distribution of
bulk propane in Wyoming, Arizona, and Montana and the retail distribution
of bulk propane in Arizona. The Company also markets gas and electricity
in Montana and Wyoming through its non-regulated subsidiary, Energy West
Resources ("EWR").
PRINCIPLES OF CONSOLIDATION -- The consolidated financial statements
include the accounts of the Company and its wholly-owned subsidiaries,
Energy West Propane ("EWP"), EWR, and Energy West Development ("EWD"). The
consolidated financial statements also include the Company's proportionate
share of the assets, liabilities, revenues, and expenses of certain
producing natural gas reserves that were acquired in 2002 (see Note 2) of
which the Company owns a 56% undivided interest. All intercompany
transactions and accounts have been eliminated.
SEGMENTS -- The Company reports financial results for three business
segments: Natural Gas Operations, Propane Operations, and EWR.
Summarized financial information for these three segments is set
forth in Note 11.
USE OF ESTIMATES IN PREPARING FINANCIAL STATEMENTS -- The preparation of
financial statements in conformity with accounting principles generally
accepted in the United States of America requires management to make
estimates and assumptions that affect the reported amounts of assets and
liabilities, the disclosure of contingent assets and liabilities at the
date of the financial statements, and the reported amounts of revenues and
expenses during the reporting period. Actual results could differ from
these estimates. The Company has used estimates in measuring certain
deferred charges and deferred credits related to items subject to approval
of the various public service commissions with jurisdiction over the
Company. Estimates are also used in the development of discount rates and
trend rates related to the measurement of postretirement benefit
obligations and accrual amounts, allowances for doubtful accounts, valuing
derivative instruments, estimating litigation reserves, and in the
determination of depreciable lives of utility plant.
NATURAL GAS AND PROPANE INVENTORIES -- Natural gas inventory and propane
inventory are stated at the lower of weighted average cost or net
realizable value except for Energy West Montana - Great Falls, which is
stated at the rate approved by the Montana Public Service Commission
("MPSC"), which includes transportation and storage costs.
RECOVERABLE/REFUNDABLE COSTS OF GAS AND PROPANE PURCHASES -- The Company
accounts for purchased gas and propane costs in accordance with procedures
authorized by the MPSC, the Wyoming Public Service Commission, and the
Arizona Corporation Commission. Purchased gas and propane costs that
48
are different from those provided for in present rates are accumulated and
recovered or credited through future rate changes.
In March 2001, the Company was granted an interim order that allowed the
addition of $2.12 per Mcf surcharge to recover approximately $6,824,000 of
previously unrecovered gas costs. Such costs have been reflected as a
recoverable asset in the accompanying financial statements as of June 30,
2001. The Company recovered in excess of these costs during fiscal 2002
resulting in a refundable gas obligation totaling approximately $2,024,000
as of June 30, 2002. Such amount has been reflected as a liability in the
accompanying financial statements. Effective July 1, 2002, the MPSC
approved the Company's application to discontinue this surcharge. The
Company has in place an interim order that allows for the recovery of gas
costs when there is a gas cost change that exceeds $.10 per Mcf.
UTILITY PLANT -- Property, plant and equipment are recorded at original
cost when placed in service. Depreciation and amortization on assets are
generally recorded on a straight-line basis over the estimated useful
lives, as applicable, at various rates. The average rates of depreciation
and amortization were approximately 3.40%, 3.47% and 3.47% during the
years ended June 30, 2002, 2001 and 2000, respectively.
NATURAL GAS RESERVES -- During 2002, the Company acquired an undivided
interest in certain producing natural gas reserves on properties located
in northern Montana (see Note 2). The reserves are estimated to have
approximately 3.4 million Mmbtu in remaining natural gas reserves. The
Company is depleting these reserves using the units-of-production method.
The gas reserves are included in Utility Plant in the accompanying
financial statements.
IMPAIRMENT OF LONG-LIVED ASSETS -- The Company evaluates its long-lived
assets for impairment whenever events or changes in circumstances indicate
that the carrying amount of such assets or intangibles may not be
recoverable. Recoverability of assets to be held and used is measured by a
comparison of the carrying amount of an asset to future undiscounted net
cash flows expected to be generated by the asset. If such assets are
considered to be impaired, the impairment to be recognized is measured by
the amount by which the carrying amount of the assets exceeds the fair
value of the assets.
STOCK-BASED COMPENSATION -- The Company has elected to follow the
accounting provisions of Accounting Principles Board (APB) Opinion No. 25,
Accounting for Stock Issued to Employees for Stock-Based Compensation, for
stock options granted to employees and directors and to furnish the pro
forma disclosure required under Statement of Financial Accounting ("SFAS")
No. 123, Accounting for Stock-Based Compensation.
COMPREHENSIVE INCOME -- During the year ended June 30, 2002, 2001, and
2000, the Company had no components of comprehensive income other than net
income.
REVENUE RECOGNITION -- Revenues are recognized in the period that services
are provided or products are delivered. The Company records gas
distribution revenues for gas delivered to residential and commercial
customers but not billed at the end of the accounting period. The Company
periodically collects revenues subject to possible refunds pending final
orders from regulatory agencies. When this occurs, appropriate reserves
for such revenues collected subject to refund are established.
DERIVATIVES -- The Company uses exchange traded futures and options
contracts (derivative contracts) to manage the volatility related to firm
commitments to purchase and sell natural gas in order to lock in a margin
on a particular sales contract or group of contracts. The accounting for
derivative financial instruments that are used to manage risk is in
accordance with SFAS No. 133, Accounting for Derivative
49
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. Gains and losses from derivative
instruments are included as a component of gas and electric--wholesale
revenues in the accompanying consolidated statements of income. For the
years ended June 30, 2002 and 2001, the Company recognized net gains
totaling $2,647,000 and $221,000 respectively.
DEBT ISSUANCE AND REACQUISITION COSTS -- Debt premium, discount and issue
costs are amortized over the life of each debt issue. Debt reacquisition
costs for refinanced debt are amortized over the remaining life of the
debt.
CASH AND CASH EQUIVALENTS -- All highly liquid investments with original
maturities of three months or less at the date of acquisition are
considered to be cash equivalents.
EARNINGS PER SHARE -- Net income per common share is computed by both the
basic method, which uses the weighted average number of the Company's
common shares outstanding, and the diluted method, which includes the
dilutive common shares from stock options, as calculated using the
treasury stock method. The only dilutive securities are the stock options
described in Note 12. The dilutive effect of stock options for the years
ended June 30, 2002 and 2001 was an increase to basic weighted average
common shares outstanding of 9.837 and 14.201 respectively. The effect of
stock options for the years ended June 30, 2000 would have been
antidilutive.
CREDIT RISK -- The Company's primary market areas are primarily Montana,
Wyoming, and Arizona. Exposure to credit risk may be impacted by the
concentration of customers in these areas due to changes in economic or
other conditions. Customers include individuals and numerous industries
that may be affected differently by changing conditions. Management
believes that its credit review procedures, loss reserves, customer
deposits, and collection procedures have adequately provided for usual and
customary credit related losses.
EFFECTS OF REGULATION -- The Company follows SFAS No. 71, Accounting for
the Effects of Certain Types of Regulation, and its consolidated 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).
INCOME TAXES -- The Company files its income tax returns on a consolidated
basis. Rate-regulated operations record cumulative increases in deferred
taxes as income taxes recoverable from customers. The Company uses the
deferral method to account for investment tax credits as required by
regulatory commissions. Deferred income taxes are determined using the
asset and liability method, under which deferred tax assets and
liabilities are measured based upon the temporary differences between the
financial statement and income tax bases of assets and liabilities, using
current tax rates.
FINANCIAL INSTRUMENTS -- The fair value of all financial instruments with
the exception of fixed rate long-term debt approximates carrying value
because they have short maturities or variable rates of interest that
approximate prevailing market interest rates.
NEW ACCOUNTING PRONOUNCEMENTS -- In July 2001, the FASB issued SFAS No.
142, Goodwill and Other Intangible Assets. SFAS 142 changes the accounting
for goodwill and indefinite lived intangible assets from an amortization
method to an impairment-only approach. Goodwill, including goodwill
recorded in past business combinations, is no longer amortized but is
tested for impairment at least annually at the reporting unit level. The
Company is required to adopt SFAS No. 142 for its fiscal year beginning
July 1, 2002. The Company has no recorded goodwill as of June 30, 2002.
Accordingly, management does not expect this statement to have a material
impact on the Company's financial position or results of operations.
In June 2001, the FASB issued SFAS No. 143, Accounting for Asset
Retirement Obligations. This statement addresses financial accounting and
reporting for obligations associated with the retirement of
50
tangible long-lived assets and the associated asset retirement costs. The
Company is required to implement SFAS No. 143 on July 1, 2002. Management
has not determined the impact, if any, that this statement will have upon
the Company.
In August 2001, the FASB issued SFAS No. 144, Accounting for the
Impairment or Disposal of Long-Lived Assets. This statement supersedes
SFAS No. 121, Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to Be Disposed Of. The statement retains the previously
existing accounting requirements related to the recognition and
measurement of the impairment of long-lived assets to be held and used but
expands the measurement requirements of long-lived assets to be disposed
of by sale to include discontinued operations. It also expands the
previously existing reporting requirements for discontinued operations to
include a component of an entity that either has been disposed of or is
classified as held for sale. The Company is required to implement SFAS No.
144 on July 1, 2002. Management does not expect this statement to have a
material impact on the Company's financial position or results of
operations.
In April 2002, the FASB issued SFAS No. 145, Rescission of FASB Statements
No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical
Corrections. This statement eliminates the required classification of gain
or loss on extinguishment of debt as an extraordinary item of income and
states that such gain or loss be evaluated for extraordinary
classification under the criteria of Accounting Principles Board No. 30
"Reporting Results of Operations." This statement also requires
sale-leaseback accounting for certain lease modifications that have
economic effects that are similar to sale-leaseback transactions, and
makes various other technical corrections to existing pronouncements. The
Company is required to implement SFAS No. 145 on July 1, 2002. Management
does not expect this statement to have a material impact on its financial
position or results of operations.
In June 2002, the FASB issued SFAS No. 146, Accounting for Costs
Associated with Exit or Disposal Activities. This statement nullifies
Emerging Issues Task Force (EITF) Issue No. 94-3, Liability Recognition
for Certain Employee Termination Benefits and Other Costs to Exit an
Activity (including Certain Costs Incurred in a Restructuring). This
statement requires that a liability for a cost associated with an exit or
disposal activity be recognized when the liability is incurred rather than
the date of an entity's commitment to an exit plan. The provisions of SFAS
No. 146 are effective for exit or disposal activities that are initiated
after December 31, 2002. Management has not determined the impact, if any,
that this statement will have on the Company.
RECLASSIFICATIONS -- Certain prior year amounts have been reclassified to
conform to the current year presentation.
2. PROVED NATURAL GAS RESERVES
In November 1999, EWR entered into a contract with a seller of natural gas
whereby the seller agreed to supply and EWR agreed to purchase a minimum
fixed quantity of natural gas at an agreed-upon price. During the term of
the contract, the seller was unable to supply EWR with the quantities
specified in the contract, and, accordingly, EWR was required to purchase
natural gas from other suppliers at prices that exceeded the contract
price. For remedies in the event of a breach on the part of the seller,
the contract required payment by the seller to EWR of an amount equal to
the difference between the contract quantity and the actual quantity
delivered multiplied by the difference between the contract price and the
spot price of natural gas during the term of the breach.
During 2001, EWR notified the seller of its intention to pursue collection
and demanded payment of damages for the breach by the seller. During
December 2001, EWR and the seller agreed to terms whereby the seller would
convey an interest in proved natural gas reserves to EWR for a price that
was
51
reduced by an amount agreed upon by the two parties to cure damages for
the seller's breach under the natural gas supply contract. In May 2002,
EWR paid the seller approximately $956,000, which consists of an agreed
upon price for the reserves and associated support equipment of $1,256,000
reduced by $300,000 to cure damages under the supply contract. The
agreed-upon price for the reserves is supported by an independent
third-party valuation and the contemporaneous purchase of interests in the
same reserves by two independent third parties.
EWR has recorded the acquisition of the natural gas reserves and the
settlement of the breach by the seller as two separate and distinct
transactions. Accordingly, EWR recorded the cost of the interest in the
proved natural gas reserves and associated support equipment at $1,257,000
and recorded a $300,000 settlement as non-operating income in the
accompanying consolidated statement of income for the year ended June 30,
2002.
3. PROPERTY PLANT & EQUIPMENT
Utility plant consists of the following as of June 30, 2002 and 2001:
2002 2001
Gas transmission and distribution facilities $ 47,204,701 $ 44,035,481
Non-depreciable property 395,996 415,829
Buildings and leasehold improvements 2,922,911 2,881,331
Transportation equipment 2,515,574 2,644,334
Computer equipment 4,008,767 3,848,065
Other equipment 3,788,845 3,731,387
Construction work-in-progress 1,001,449 365,048
Producing natural gas reserves 933,821 --
------------ ------------
62,772,064 57,921,475
Less accumulated depreciation, depletion,
and amortization (26,253,156) (24,922,317)
------------ ------------
Total $ 36,518,908 $ 32,999,158
============ ============
During fiscal year 2002, as part of its strategic emphasis on wholesale
propane operations, EWP disposed of its retail propane operations in
Wyoming and Montana. The Montana operations consisted of approximately
$371,000 in customer tanks and other fixed assets and approximately
$75,000 in inventory and accounts receivable. The Wyoming operations
consisted of approximately $549,000 in customer tanks and other fixed
assets and approximately $116,000 in inventory and accounts receivable. In
conjunction with the dispositions, EWP recorded gains totaling $338,000,
which are included in distribution, general, and administrative expenses
in the accompanying consolidated statement of income for the year ended
June 30, 2002. EWP has entered into long-term agreements to supply propane
to the purchaser of these assets in both Wyoming and Montana.
52
4. DEFERRED CHARGES
Deferred charges consist of the following as of June 30, 2002 and 2001:
2002 2001
Unamortized debt issue costs $ 859,440 $ 940,358
Regulatory asset for income taxes 458,754 471,913
Principally regulatory assets for deferred environmental
remediation costs 617,069 902,400
---------- ----------
Total $1,935,263 $2,314,671
========== ==========
5. ACCRUED AND OTHER CURRENT LIABILITIES
Accrued and other current liabilities consist of the following as of June
30, 2002 and 2001:
2002 2001
Reserves $2,000,000 $2,000,000
Payable to employee benefit plans 870,132 1,007,813
Accrued vacation 433,043 417,762
Customer deposits 341,276 274,327
Accrued incentives 1,615,524 2,481,295
Accrued interest 112,512 113,152
Other 80,817 172,277
---------- ----------
Total $5,453,304 $6,466,626
========== ==========
6. OTHER LONG-TERM LIABILITIES
Other long-term liabilities consist of the following as of June 30, 2002
and 2001:
2002 2001
Contribution in aid of construction $1,013,784 $1,016,685
Customer advances for construction 561,801 589,879
Accumulated postretirement obligation 157,305 125,304
Deferred gain on sale leaseback of assets 94,520 118,151
Regulatory liability for income taxes 83,161 96,321
Other -- 187,993
---------- ----------
Total $1,910,571 $2,134,333
========== ==========
7. NOTES PAYABLE
At June 30, 2002, the Company maintained two lines of credit totaling
$26,000,000. One line is for $11,000,000 with interest calculated (at the
discretion of the Company at the time of each draw) at either the London
Interbank Offering Rate ("LIBOR") plus 2% or prime less 0.6%, expiring
January 5, 2003. The other is for $15,000,000 with interest calculated (at
the discretion of the Company at the time of each draw) at either LIBOR
plus 2% or prime less 0.6%, expiring May 1, 2003. Borrowings on lines of
53
credit, based upon daily loan balances, averaged $9,312,531, $9,488,191
and $5,045,943 during the years ended June 30, 2002, 2001 and 2000,
respectively. The maximum borrowings outstanding on these lines at any
month end were $17,069,732, $17,140,000 and $10,855,000 during these same
periods. The daily weighted average interest rate was 4.60%, 8.43% and
8.01% for the years ended June 30, 2002, 2001 and 2000, respectively. At
June 30, 2002, the Company had $18,350,000 available under its lines of
credit.
The Company's lines of credit agreements contain various covenants that
require the maintenance of certain financial debt, interest, and cash flow
ratios. The Company was in compliance with the line of credit covenants as
of June 30, 2002.
8. LONG-TERM DEBT
Long-term debt at June 30, 2002 and 2001 consists of the following:
2002 2001
Series 1997 notes payable $ 7,926,000 $ 7,951,000
Series 1993 notes payable 6,700,000 7,090,000
Series 1992B industrial development
revenue obligations 1,230,000 1,305,000
Capital lease 13,496
------------ ------------
Total long-term debt 15,869,496 16,346,000
Less current portion of long-term debt (502,072) (465,000)
------------ ------------
Long-term debt $ 15,367,424 $ 15,881,000
============ ============
SERIES 1997 NOTES PAYABLE -- On August 1, 1997, the Company issued
$8,000,000 of Series 1997 unsecured notes bearing interest at the rate of
7.5%, payable semiannually on June 1 and December 1 of each year. All
principal amounts of the 1997 notes then outstanding, plus accrued
interest will be due and payable on June 1, 2012. At the Company's option,
beginning June 1, 2002, notes maturing subsequent to 2002 may be redeemed
prior to maturity, in whole or part, at 100% of face value, plus accrued
interest.
SERIES 1993 NOTES PAYABLE -- On June 24, 1993, the Company issued
$7,800,000 of Series 1993 unsecured notes bearing interest at rates
ranging from 6.20% to 7.60%, payable semiannually on June 1 and December 1
of each year. Maturity dates began in 1999 and extend to 2013. At the
Company's option, beginning June 1, 2003, notes maturing subsequent to
2003 may be redeemed prior to maturity, in whole or part, at redemption
prices declining from 104% to 100% of face value, plus accrued interest.
SERIES 1992B INDUSTRIAL DEVELOPMENT REVENUE OBLIGATIONS -- On September
15, 1992, Cascade County, Montana issued $1,800,000 of Series 1992B
Industrial Development Revenue Obligations bearing interest at rates
ranging from 3.35% to 6.50%. The Series 1992B Bonds are unsecured. The
Series 1992B Bonds require annual principal payments on October 1 and
semiannual interest payments on April 1 and October 1 of each year. The
Series 1992 Bonds have a final maturity in 2012.
54
AGGREGATE ANNUAL MATURITIES -- The scheduled maturities of long-term debt
at June 30, 2002 are as follows:
TOTAL
SERIES SERIES SERIES CAPITAL LONG-TERM
1997 1993 1992B LEASE DEBT
Year ending June 30:
2003 $ 420,000 $ 80,000 $ 2,072 $ 502,072
2004 445,000 85,000 2,380 532,380
2005 480,000 90,000 2,713 572,713
2006 515,000 95,000 3,094 613,094
2007 550,000 105,000 3,237 658,237
Thereafter $ 7,926,000 4,290,000 775,000 12,991,000
------------ ----------- ----------- ----------- -----------
Total $ 7,926,000 $ 6,700,000 $ 1,230,000 $ 13,496 $15,869,496
============ =========== =========== =========== ===========
The Company's long-term debt obligation agreements contain various
covenants including: limiting total dividends and distributions made in
the immediately preceding 60-month period to aggregate consolidated net
income for such period, restricting senior indebtedness, limiting asset
sales, and maintaining certain financial debt and interest ratios.
The Company is in compliance with all long-term debt covenants as of June
30, 2002.
The estimated fair value of the Company's fixed rate long-term debt, based
on quoted market prices for the same or similar issues, is approximately
$17,380,158 and $17,237,406 as of June 30, 2002 and 2001, respectively.
9. EMPLOYEE BENEFIT PLANS
The Company has a defined contribution plan (the "Plan") which covers
substantially all of the Company's employees. Under the Plan, the Company
contributes 10% of each participant's eligible compensation. Total
contributions to the plan for the years ended June 30, 2002, 2001, and
2000 were $617,275, $509,372 and $491,068, respectively.
The Company sponsors a defined postretirement health and life insurance
benefit pension plan (the "Pension Plan") providing health and life
insurance benefits to eligible retirees. The Company has elected to pay
eligible retirees (post-65 years of age) $125 per month in lieu of
contracting for health and life insurance benefits. The amount of this
payment is fixed and will not increase with medical trends or inflation.
The Company's Pension Plan allows retirees between the ages of 60 and 65
and their spouses to remain on the same medical plan as active employees
by contributing 125% of the current COBRA rate to retain this coverage.
Included in the postretirement benefit expense amounts were $26,100 in
2002, $29,400 in 2001 and $35,800 in 2000 related to regulated operations.
The MPSC allowed recovery of these costs over a 20-year period beginning
on November 4, 1997 for the utility operations in Montana. Management
believes it is probable that its regulators in Wyoming will allow recovery
of these costs based upon recent industry rate decisions addressing this
issue. The plan assets are held in a VEBA trust fund into which all the
Company's contributions are made.
55
The following table sets forth the funded status of the Pension Plan and
amounts recognized in the consolidated financial statements as of June 30,
2002 and 2001 and for the years ended June 30, 2002, 2001, and 2000:
2002 2001
Change in benefit obligation:
Projected benefit obligation
Benefit obligation at beginning of year $ 743,200 $ 686,900
Service costs 26,000 34,900
Interest costs 39,200 52,000
Actuarial gain (182,900) (22,400)
Benefits paid (22,700) (8,200)
--------- ---------
Benefit obligation at end of year 602,800 743,200
--------- ---------
Change in plan assets:
Fair value of plan assets at beginning of year 482,395 453,995
Actual return on plan assets 11,100 24,700
Contributions to the plan 11,900
Benefits paid (22,700) (8,200)
--------- ---------
Fair value of plan assets at end of year 470,795 482,395
--------- ---------
Benefit obligation in excess of plan assets 132,005 260,805
Unrecognized transition obligation (215,800) (235,400)
Unrecognized prior service cost (162,400) (180,300)
Unrecognized gain 403,500 280,199
--------- ---------
Net amount recognized $ 157,305 $ 125,304
========= =========
2002 2001 2000
Service costs $ 26,000 $ 34,900 $ 33,800
Interest costs 39,200 52,000 47,900
Expected return on plan assets (42,400) (39,500) (28,000)
Amortization of transition obligation 19,600 19,600 19,600
Amortization of unrecognized prior service costs 17,900 17,900 17,900
Actuarial gain (28,300) (13,500) (43,700)
-------- -------- --------
Postretirement benefit expense $ 32,000 $ 71,400 $ 47,500
======== ======== ========
56
2002 2001
Weighted-average assumptions as of June 30:
Discount rate 7.50 % 7.75 %
Expected return on plan assets 9.00 % 9.00 %
Health care inflation rate 9.50 % 6.00 %
Grading to 5.5% Grading to 5.5%
A one-percentage-point increase in the assumed health care cost trend rate
would increase interest and service cost by $2,900 and the accumulated
postretirement benefit obligation by $23,200. A one-percentage-point
decrease in the assumed health care cost trend rate would decrease
interest and service cost by $2,500 and the accumulated postretirement
benefit obligation by $20,100.
10. INCOME TAXES
Significant components of the Company's deferred tax assets and
liabilities as of June 30, 2002 and 2001 are as follows:
2002 2001
-------------------------------- --------------------------------
CURRENT LONG-TERM CURRENT LONG-TERM
Deferred tax asset:
Allowances for doubtful accounts $ 30,917 $ -- $ 50,221 $ --
Unamortized investment tax credit -- 54,470 -- 96,560
Contributions in aid of construction -- 209,885 -- 192,040
Other accruals 991,465 703,339 1,998,301 169,884
Deferred gain on sale of assets -- 38,518 -- 47,190
Refundable purchase gas costs 783,554 -- -- --
Other 203,735 227,649 15,559 --
----------- ----------- ----------- -----------
Total 2,009,671 1,233,861 2,064,081 505,674
----------- ----------- ----------- -----------
Deferred tax liabilities:
Recoverable purchase gas costs -- -- (2,610,386) --
Utility plant -- (5,011,672) -- (4,068,781)
Debt issue costs -- (136,983) -- (130,674)
Deferred rate case costs -- (52,034) -- (73,903)
Derivative instruments (1,078,524) -- (85,000) --
Covenant not to compete -- (76,210) -- (67,829)
----------- ----------- ----------- -----------
Total (1,078,524) (5,276,899) (2,695,386) (4,341,187)
----------- ----------- ----------- -----------
Deferred income taxes, net $ 931,147 $(4,043,038) $ (631,305) $(3,835,513)
=========== =========== =========== ===========
57
Income tax expense (benefit) for the years ended June 30, 2002, 2001, and
2000 consists of the following:
2002 2001 2000
Current income taxes:
Federal $ 1,942,386 $ 2,249,626 $ (295,999)
State 395,487 428,125 (38,092)
----------- ----------- -----------
Total current income taxes 2,337,873 2,677,751 (334,091)
----------- ----------- -----------
Deferred income taxes
Federal (1,204,532) (811,901) 821,402
State (238,398) (201,677) 242,315
----------- ----------- -----------
Total deferred income taxes (1,442,930) (1,013,578) 1,063,717
----------- ----------- -----------
Total income taxes before credits 894,943 1,664,173 729,626
Investment tax credit, net (21,062) (21,062) (21,062)
----------- ----------- -----------
Total $ 873,881 $ 1,643,111 $ 708,564
=========== =========== ===========
Income tax expense differs from the amount computed by applying the
federal statutory rate to pre-tax income for the following reasons:
2002 2001 2000
Tax expense at statutory rate of 34% $ 773,388 $ 1,498,804 $ 622,143
State income tax, net of federal tax 102,741 182,930 52,422
benefit
Amortization of deferred investment (21,062) (21,062) (21,062)
tax credits
Other 18,814 (17,561) 55,061
----------- ----------- -----------
Total $ 873,881 $ 1,643,111 $ 708,564
=========== =========== ===========
11. SEGMENTS OF OPERATIONS
Effective July 1, 2001, the Company changed the structure of its internal
organization such that the composition of its reportable segments has
changed. Rocky Mountain Fuels, which was included in the marketing and
wholesale segment prior to 2002, is included in propane operations for
2002. Accordingly, segment information for 2001 and 2000 has been restated
to reflect the revised reportable segments. Summarized financial
information for the Company's natural gas operations, propane operations,
and marketing and wholesale operations (before inter-company eliminations
between segments primarily consisting of gas sales from marketing and
wholesale operations to natural gas operations, inter-company accounts
receivable, accounts payable, equity, and subsidiary investment) is as
follows:
58
NATURAL GAS PROPANE
YEAR ENDED JUNE 30, 2002 OPERATIONS OPERATIONS EWR ELIMINATIONS CONSOLIDATED
------------ ------------ ------------ ---------- ------------
Operating revenue:
Natural gas operations $ 39,709,775 $ -- $ -- $ -- $ 39,709,775
Propane operations 11,007,389 11,007,389
Marketing and wholesale 56,736,425 (7,818,949) 48,917,476
------------ ------------ ------------ ---------- ------------
Total operating revenue 39,709,775 11,007,389 56,736,425 (7,818,949) 99,634,640
------------ ------------ ------------ ---------- ------------
Gas purchased 29,556,078 6,624,422 36,180,500
Cost of goods sold 195,254 195,254
EWR cost of trading 55,495,220 (7,818,949) 47,676,271
Distribution, general, and
administrative 5,100,407 2,196,060 1,493,716 8,790,183
Maintenance 387,468 78,304 465,772
Depreciation 1,369,946 640,348 48,876 2,059,170
Taxes other than income 681,934 213,996 50,284 946,214
------------ ------------ ------------ ---------- ------------
Operating expenses 37,291,087 9,753,130 57,088,096 (7,818,949) 96,313,364
------------ ------------ ------------ ---------- ------------
Operating income (loss) 2,418,688 1,254,259 (351,671) 3,321,276
Non-operating income 168,472 196,444 292,971 657,887
Interest on long-term debt (793,268) (321,973) (72,508) (1,187,749)
Interest other (367,954) (127,741) (21,048) (516,743)
------------ ------------ ------------ ---------- ------------
Income (loss) before income
taxes 1,425,938 1,000,989 (152,256) 2,274,671
Income taxes (564,632) (361,769) 52,520 873,881
------------ ------------ ------------ ---------- ------------
Net income (loss) $ 861,306 $ 639,220 $ (99,736) $ -- $ 1,400,790
============ ============ ============ ========== ============
59
NATURAL GAS PROPANE
YEAR ENDED JUNE 30, 2001 OPERATIONS OPERATIONS EWR ELIMINATIONS CONSOLIDATED
(as restated) ------------ ------------ ------------ ------------- ------------
Operating revenue:
Natural gas operations $ 40,991,236 $ -- $ -- $ -- $ 40,991,236
Propane operations 14,130,518 14,130,518
Marketing and wholesale 77,590,996 (12,551,706) 65,039,290
------------ ------------ ------------ ------------- ------------
Total operating revenue 40,991,236 14,130,518 77,590,996 (12,551,706) 120,161,044
------------ ------------ ------------ ------------- ------------
Gas purchased 31,000,858 9,711,076 40,711,934
Cost of goods sold 202,775 202,775
EWR cost of trading 70,359,346 (12,551,706) 57,807,640
Distribution, general, and
administrative 5,621,787 2,562,381 3,910,647 12,094,815
Maintenance 339,527 88,240 427,767
Depreciation 1,320,489 622,632 26,960 1,970,081
Taxes other than income 499,374 167,039 56,363 722,776
------------ ------------ ------------ ------------- ------------
Operating expenses 38,984,810 13,151,368 74,353,316 (12,551,706) 113,937,788
------------ ------------ ------------ ------------- ------------
Operating income 2,006,426 979,150 3,237,680 6,223,256
Non-operating income 110,379 128,199 42,981 281,559
Interest on long-term debt (724,447) (304,991) (196,402) (1,225,840)
Interest other (515,036) (213,694) (141,997) (870,727)
------------ ------------ ------------ ------------- ------------
Income before income taxes 877,322 588,664 2,942,262 4,408,248
Income taxes (316,675) (231,114) (1,095,322) (1,643,111)
------------ ------------ ------------ ------------- ------------
Net income $ 560,647 $ 357,550 $ 1,846,940 $ -- $ 2,765,137
============ ============ ============ ============= ============
60
NATURAL GAS PROPANE
YEAR ENDED JUNE 30, 2000 OPERATIONS OPERATIONS EWR ELIMINATIONS CONSOLIDATED
(as restated)
Operating revenue:
Natural gas operations $ 24,301,491 $ -- $ -- $ -- $ 24,301,491
Propane operations 8,480,531 8,480,531
Marketing and wholesale 41,813,867 (2,210,207) 39,603,660
------------ ------------ ------------ ---------- ------------
Total operating revenue 24,301,491 8,480,531 41,813,867 (2,210,207) 72,385,682
------------ ------------ ------------ ---------- ------------
Gas purchased 14,978,526 4,629,985 19,608,511
Cost of goods sold 243,128 243,128
EWR cost of trading 41,146,878 (2,210,207) 38,936,671
Distribution, general, and
administrative 4,878,409 2,043,879 726,546 7,648,834
Maintenance 295,070 104,509 399,579
Depreciation 1,268,158 568,539 19,756 1,856,453
Taxes other than income 455,976 149,700 33,112 638,788
------------ ------------ ------------ ---------- ------------
Operating expenses 22,119,267 7,496,612 41,926,292 (2,210,207) 69,331,964
------------ ------------ ------------ ---------- ------------
Operating income (loss) 2,182,224 983,919 (112,425) 3,053,718
Non-operating income 251,631 144,625 53,763 450,019
Interest on long-term debt (851,606) (302,772) (88,002) (1,242,380)
Interest other (334,607) (62,539) (34,377) (431,523)
------------ ------------ ------------ ---------- ------------
Income (loss) before income
taxes 1,247,642 763,233 (181,041) 1,829,834
Income taxes (488,910) (287,498) 67,844 (708,564)
------------ ------------ ------------ ---------- ------------
Net income (loss) $ 758,732 $ 475,735 $ (113,197) $ -- $ 1,121,270
============ ============ ============ ========== ============
61
NATURAL GAS PROPANE
YEAR ENDED JUNE 30, 2002 OPERATIONS OPERATIONS EWR ELIMINATIONS CONSOLIDATED
Capital expenditures $ 3,114,919 $ 1,216,075 $ 2,111,002 $ -- $ 6,441,996
============ ============ ============ ============ ============
Total assets $ 34,783,707 $ 12,666,036 $ 11,242,687 $ (823,383) $ 57,869,047
============ ============ ============ ============ ============
NATURAL GAS PROPANE
YEAR ENDED JUNE 30, 2001 OPERATIONS OPERATIONS EWR ELIMINATIONS CONSOLIDATED
Capital expenditures $ 1,762,894 $ 1,203,118 $ 310,239 $ -- $ 3,276,251
============ ============ ============ ============ ============
Total assets $ 39,554,745 $ 13,388,877 $ 12,115,876 $ (2,781,863) $ 62,277,635
============ ============ ============ ============ ============
12. STOCK OPTIONS AND OWNERSHIP PLANS
STOCK OPTIONS -- The Company has an Incentive Stock Option Plan (the
"Option Plan") which provides for options to purchase up to 100,000 shares
of the Company's common stock to be issued to certain key employees. The
option price may not be less than 100% of the common stock fair market
value on the date of grant (110% of the fair market value if the employee
owns more than 10% of the Company's outstanding common stock). The options
vest over three years and are exercisable over a five-year period from
date of issuance.
62
The Company has elected to follow APB No. 25 in accounting for its stock
options. Pro forma information regarding net income and earnings per share
is required by SFAS No. 123 and has been determined as if the Company had
accounted for its stock options under the fair value method of SFAS No.
123. In the fiscal year ended June 30, 2002, 2001, and 2000, no options
were granted and accordingly, there was no pro forma effect on the
accompanying consolidated financial statements from the issuance of
options. Additionally, the carryover effect of options granted prior to
2000 was not significant.
A summary of activity under the plan for the years ended June 30, 2002,
2001, and 2000 is as follows:
2002 2001 2000
---------------------- --------------------- ----------------------
WEIGHTED WEIGHTED WEIGHTED
AVERAGE AVERAGE AVERAGE
NUMBER EXERCISE NUMBER EXERCISE NUMBER EXERCISE
OF SHARES PRICE OF SHARES PRICE OF SHARES PRICE
Outstanding at beginning of year 56,420 $ 8.894 62,720 $ 8.894 67,720 $ 8.894
Granted -- -- --
Exercised (24,000) 8.523 (2,300) 9.000 --
Expired -- (4,000) 9.187 (5,000) 9.135
------- ------ ------
Outstanding at end of year 32,420 9.089 56,420 8.849 62,720 8.972
======= ======= =======
Options exercisable at year end 19,452 9.089 30,568 8.733 20,544 8.692
======= ======= =======
At June 30, 2002, exercise prices range from $9.00 to $9.19 per share. The
weighted-average remaining contractual life of stock options is two years.
At June 30, 2002, there were approximately 12,600 shares available for
grant.
EMPLOYEE STOCK OWNERSHIP PLAN -- The Company has an Employee Stock
Ownership Plan ("ESOP") that covers most of the Company's employees. The
ESOP receives contributions of the Company's common stock from the Company
each year as determined by the Board of Directors. The contribution is
recorded based on the current market price of the Company's common stock.
The Company has contributed common stock and recognized as expense
totaling $129,802, $240,812 and $103,886 for the years ended June 30,
2002, 2001 and 2000, respectively.
13. COMMITMENTS AND CONTINGENCIES
COMMITMENTS -- The Company has entered into long-term, take or pay natural
gas supply contracts which expire at varying times through 2008. The
contracts generally require the Company to purchase specified minimum
volumes of natural gas at a fixed price over periods ranging from one to
six years. Current prices per MMBtu for these average approximately $2.80.
Based on current prices, the minimum take or pay obligation at June 30,
2002 is as follows:
63
Year ending June 30:
2003 $3,114,963
2004 2,785,053
2005 1,141,720
2006 861,261
2007 576,153
2008 767,151
-------
Total $9,246,301
==========
Natural gas purchases under these contracts for the years ended June 30,
2002, 2001 and 2000 approximated $920,475, $1,141,000 and $1,182,000,
respectively.
ENVIRONMENTAL CONTINGENCY -- The Company owns property on which it
operated a manufactured gas plant from 1909 to 1928. The site is currently
used as a service center where certain equipment and materials are stored.
The coal gasification process utilized in the plant resulted in the
production of certain by-products that have been classified by the federal
government and the State of Montana as hazardous to the environment.
Several years ago the Company initiated an assessment of the site to
determine if remediation of the site was required. That assessment
resulted in a submission to the Montana Department of Environmental
Quality ("MDEQ") 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. To date,
all contaminated soil has been removed, and an asphalt cap has been placed
over the site. The Company and its consultants continue their work with
the MDEQ relating to the remediation plan for water contaminants.
At June 30, 2002, the costs incurred in evaluating and beginning
remediation have totaled approximately $1,950,000. 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, 2002, that recovery mechanism
had generated approximately $1,276,000. The Company expects to recover the
full amount expended through the surcharge. The Commission's decision
calls for ongoing review by the Commission of any costs incurred. The
Company will submit an application for review by the Commission when the
water contaminants remediation plan is approved by the MDEQ. Future costs
are not estimable at this time.
LITIGATION -- From time to time the Company is involved in litigation
relating to claims arising from its obligations 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.
On July 2, 2001, EWR filed a complaint against PPL Montana, LLC (PPLM) in
the United States District Court for the District of Montana. In its
complaint, EWR sought injunctive and declaratory relief relating to a
wholesale electricity supply contract between EWR and PPL dated March 17,
2000 and a confirmation letter thereunder dated June 13, 2000 (together,
referred to as the "Contract"). The Contract calls for PPL to sell
wholesale electric energy to EWR for a two-year period commencing July 1,
2000. EWR filed its July 2, 2001 lawsuit because PPLM had threatened to
terminate sales and deliveries of electric energy to EWR under the
Contract, and also demanded that EWR make substantial payments to PPLM
relating to past power sales under the Contract. On July 13, 2001, PPLM
filed suit against EWR in Montana state court seeking unspecified damages
and other relief.
EWR has received substantial imbalance payments as a result of the amount
of power that it has scheduled and purchased from PPLM. The imbalance
payments were made to EWR by its transmission provider, The Montana Power
Company (MPC), pursuant to the imbalance provisions in MPC's transmission
tariff on file with the Federal Energy Regulatory Commission (FERC). PPLM
claims that,
64
as a result of EWR's scheduling under the Contract, PPLM was deprived of
the fair market value of that energy which it contends it could have
subsequently sold. PPLM estimates the fair market value of the excess
energy scheduled by EWR to be approximately $18,000,000. Any recovery of
damages by PPLM could be material to the Company and its financial
condition.
EWR denies liability to PPLM. EWR believes that its scheduling practices
were reasonable under the circumstances, and that in any event PPLM was
not deprived of the fair market value of the energy scheduled by EWR due
to the offsetting scheduling procedures utilized by the scheduler for the
transmission grid.
The litigation is pending in U.S. District Court in Montana. PPLM's
separate state court action has been removed to the U.S. District Court
for the District of Montana and consolidated with EWR's lawsuit in that
court. The parties currently are engaged in the process of discovery in
the judicial proceeding. A trial has been scheduled for the week of
December 9, 2002. EWR intends to vigorously advocate and defend its
position in the ongoing litigation with PPLM. The Company believes that it
has established adequate reserves with respect to the litigation with
PPLM; however, there can be no assurance that any liability will not
exceed the amounts provided. A future liability in excess of the recorded
reserves could have a material adverse effect on the Company and its
financial condition.
PROPERTY TAX CONTINGENCY -- By letter dated August 30, 2002, the Montana
Department of Revenue (the "DOR") notified the Company that the DOR's
property tax audit of the Company for the period January 1, 1997 through
December 31, 2001 had concluded. The notification stated that the DOR had
determined that the Company had willfully under-reported its personal
property and that a penalty should be assessed. Depending on the Company's
ability to successfully contest the proposed assessment, the Company
estimates the maximum exposure to approximate $3.9 million in property
taxes and penalties.
The Company has been in contact with the DOR and has arranged for an
informal review of the proposed assessment. The Company believes it has
valid defenses to the assessment of tax and penalties, and plans to
vigorously contest the proposed assessment and believes that the proposed
penalty is unsupportable.
The DOR review has not yet commenced. In the event the proposed assessment
cannot be resolved favorably, there are other avenues of appeal and review
that can be followed. The Company also believes that if any tax deficiency
is ultimately imposed on the Company, such deficiency that relates to
regulated property may be included in allowable costs for rate-making
purposes. However, if the DOR prevails on its imposition of penalties, the
Company anticipates that such penalties would not be recoverable through
rates. The Company believes that any interest associated with the property
tax assessment also would be included in allowable costs for rate-making
purposes. Because of the uncertainties related to the DOR notification,
the Company has not been able to determine a range of any potential losses
for reserve purposes; accordingly, no reserve amounts have been recorded.
65
OPERATING LEASES -- The Company leases certain properties including land,
office buildings, and other equipment under non-cancelable capital and
operating leases through fiscal year 2008. The future minimum lease
payments are as follows:
Year ending June 30:
2003 $166,839
2004 157,923
2005 131,175
2006 131,175
2007 79,200
Thereafter 165,000
-------
Total $831,312
========
LETTERS OF CREDIT -- Outstanding letters of credit totaled $4,150,000 at
June 30, 2002 and $6,000,000 at June 30, 2001. The letters of credit
guarantee the Company's performance to third parties for gas and electric
purchases and gas transportation services.
14. DERIVATIVE INSTRUMENTS 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 certain policies and procedures to manage such risks. The
Company has a Risk Management Committee ("RMC"), comprised of Company
officers 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 impacts on earnings resulting from volatility of
energy prices, counter-party credit risks, and other risks related to the
energy commodity business. The RMC is overseen by the Audit Committee of
the Company's Board of Directors.
GENERAL -- From time to time the Company or its subsidiaries may use
derivative financial 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, which the Company adopted July 1, 2000.
In accordance with SFAS No. 133, such financial instruments are 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, are 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 developed valuation models that incorporate available current
and historical independent pricing information.
66
The Company generally classifies contracts as normal purchases or sales
and, therefore, is not required to use mark-to-market accounting for such
contracts.
WHOLESALE OPERATIONS -- During 2002 and 2001, EWR was party to a number of
contracts that were valued on a mark-to-market basis under SFAS No. 133.
Although certain firm commitments to purchase and sell natural gas could
have been classified as normal purchases and sales and excluded from the
requirements of SFAS No. 133, EWR elected to treat these contracts as
derivative instruments under SFAS No. 133 in order to match contracts to
purchase and sell natural gas for financial reporting purposes. Such
contracts were recorded in the Company's consolidated balance sheet at
fair value. Periodic mark-to-market adjustments to the fair values of
these contracts are recorded as adjustments to gas costs.
In January 2002, EWR terminated its derivative contracts with Enron Canada
Corporation (ECC), a subsidiary of Enron, Inc. Most of these contracts
were commodity swaps that EWR had entered into to mitigate the effects of
fluctuations in the market price of natural gas. The derivative contracts
with ECC were entered into at various times in order to lock in margins on
certain contracts under which EWR had commitments to other parties to sell
natural gas at fixed prices (the "Future Supply Agreements"). EWR made the
decision to terminate these ECC contracts because of concerns relating to
the bankruptcy of Enron, Inc. At the date of termination, the market price
of natural gas was substantially lower than the price had been when the
Company entered into the contracts, resulting in a net amount due from EWR
to ECC of approximately $5,400,000. EWR paid this amount to ECC upon the
termination of the contracts, and thereby discharged the liability related
to the contracts. The costs related to such termination are reflected in
the Company's consolidated statement of income as adjustments to gas
purchased.
At the time EWR terminated the ECC derivative contracts, EWR entered into
new gas purchase contracts (the "Future Purchase Agreements") at prices
much lower than those provided for under the ECC contracts. The Future
Supply Agreements continue to be valued on a mark-to market basis.
Therefore, the value of such agreements has been reflected in the
Company's consolidated net income.
As of June 30, 2002, the Future Supply and Purchase Agreements were
reflected as derivative assets on the Company's consolidated balance sheet
at an approximate aggregate fair value as follows:
Contracts maturing in one year or less: $1,252,000
Contracts maturing in two to three years: 1,027,000
Contracts maturing in four to five years: 489,000
Contracts maturing in five years or more: 100,000
Since January 2002, neither the Company nor any of its subsidiaries has
entered into any new contracts that have required mark-to-market valuation
under SFAS No. 133.
NATURAL GAS OPERATIONS -- In the case of the Company's regulated
divisions, gains or losses resulting from the derivative contracts are
subject to deferral under regulatory procedures approved by the public
service regulatory commissions of Montana, Wyoming and Arizona. Therefore,
related derivative assets and liabilities are offset with corresponding
regulatory liability and asset amounts included in "Recoverable Cost of
Gas Purchases", pursuant to SFAS No. 71.
67
15. QUARTERLY INFORMATION (UNAUDITED)
Quarterly results (unaudited) for the years ended June 30, 2002 and 2001
are as follows (in thousands, except per share data):
FIRST SECOND THIRD FOURTH
FISCAL YEAR 2002 QUARTER QUARTER QUARTER QUARTER
Revenues $ 18,305 $ 24,962 $ 37,816 $ 18,552
Operating income (loss) 437 1,593 2,238 (947)
Net income (loss) (433) 623 1,174 37
Basic earnings (loss) per common share (0.17) 0.25 0.46 0.01
Diluted earnings (loss) per share (0.17) 0.25 0.46 0.01
FISCAL YEAR 2001
Revenues $ 16,247 $ 36,010 $ 39,988 $ 27,916
Operating income (loss) (528) 2,765 4,634 (558)
Net income (loss) (594) 1,309 2,605 (555)
Basic earnings (loss) per common share (0.24) 0.52 1.05 (0.22)
Diluted earnings (loss) per share (0.24) 0.52 1.04 (0.22)
Effective January 1, 2002, the Company changed its policy regarding the
classification of net gains from derivative instruments to include those
net gains in revenues rather than in non-operating income. Accordingly,
net gains from derivative instruments for quarters ended prior to January
1, 2002 have been restated to reflect the classification of net gains from
derivative instruments as a component of revenues. The reclassification
impacted amounts previously reported for revenues and operating income
(loss), but had no impact on net income.
* * * * * *
68
Item 9. - Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure
The Company's current report on Form 8-K dated October 25, 2001, describes the
dismissal of Ernst & Young as the Company's independent accountant and the
engagement of Deloitte & Touche as the Company's new independent accountant. At
the time of the dismissal of Ernst & Young, there were no reportable events with
respect to the Company's relationship with its independent accountants.
69
PART III
Item 10. - Directors and Executive Officer of the Registrant
Information concerning the executive officers is included in Part I, Item 1 of
this Form 10-K. The information contained under the heading "Election of
Directors" in the Proxy Statement is incorporated herein by reference in
response to this item.
Item 11. - Executive Compensation
The information contained under heading "Executive Compensation" in the Proxy
Statement is incorporated herein by reference in response to this item.
Item 12. - Security Ownership of Certain Beneficial Owners and Management
The information contained under the heading "Security Ownership of Certain
Beneficial Owners and Management" in the Proxy Statement is incorporated herein
by reference in response to this item.
Item 13. - Certain Relationships and Related Transactions
The information contained under the heading "Certain Transactions" in the Proxy
Statement is incorporated herein by reference in response to this item.
70
Item 14. - Controls and Procedures
The Company has made no significant changes in its internal controls or in other
factors that could significantly affect these controls.
PART IV
Item 15. - Exhibits, Financial Statement Schedules and Reports on Form 8K
(a) 1. Financial Statements included in Part II, Item 8:
Report of Independent Auditors
Consolidated Balance Sheets
Consolidated Statements of Income
Consolidated Statements of Stockholders' Equity
Consolidated Statements of Cash Flows
Notes to Consolidated Financial Statements
2. Financial Statement Schedules included in Item 15(d):
Schedule II - Valuation and Qualifying Accounts
All other schedules are omitted because they are not applicable or the required
information is shown in the financial statements or notes thereto.
3. The Exhibits required to be filed by Item 601 of Regulation S-K are
listed under the heading "Exhibit Index," below.
(b) None.
(c) EXHIBITS. The Exhibits required to be filed by Item 601 of Regulation S-K
are listed under the heading "Exhibit Index," below.
(d) SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS
ENERGY WEST INC.
JUNE 30, 2002, 2001, 2000
Balance At Charged Write-Offs Balance
Beginning to Costs Net of at End of
Description of Period & Expenses Recoveries Period .
- --------------------------------------------------------------------------------------------------------
ALLOWANCE FOR
UNCOLLECTIBLE ACCOUNTS
Year Ended June 30, 2000 $ 84,538 $ 104,132 $(100,671) $ 87,999
Year Ended June 30, 2001 $ 87,999 $ 169,785 $ (53,214) $ 204,570
Year Ended June 30, 2002 $ 204,570 $ 59,506 $(109,825) $ 154,251
71
SIGNATURES
Pursuant to the requirements of Section 13 or 15 (d) of the Securities Exchange
Act of 1934, the Registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized.
ENERGY WEST INCORPORATED
/s/ Edward J. Bernica
Edward J. Bernica, President and Chief
Executive Officer (Principal Executive Officer)
/s/ JoAnn S. Hogan
JoAnn S. Hogan, Assistant Vice President
And Treasurer (Principal Financial and
Accounting Officer)
Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below by the following persons on behalf of the Registrant and
in the capacities and on the dates indicated.
/s/ Edward J. Bernica September 30, 2002
Edward J. Bernica Director Date
/s/ Andrew Davidson September 30, 2002
Andrew Davidson Director Date
/s/ Thomas N. McGowen, Jr. September 30, 2002
Thomas N. McGowen, Jr. Director Date
/s/ G. Montgomery Mitchell September 30, 2002
G. Montgomery Mitchell Director Date
/s/ George D. Ruff September 30, 2002
George D. Ruff Director Date
/s/ David A. Flitner September 30, 2002
David A. Flitner Director Date
/s/ Dean A. South September 30, 2002
Dean A. South Director Date
/s/ Richard J. Schulte September 30, 2002
Richard J. Schulte Director Date
72
CERTIFICATIONS
I, Edward J. Bernica, certify that:
1. I have reviewed this annual report on Form 10-K of Energy West
Incorporated.
2. Based on my knowledge, this annual report does not contain any
untrue statement of a material fact or omit to state a material fact necessary
to make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by this
annual report; and
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this annual report.
Date: September 30, 2002
/s/ Edward J. Bernica
---------------------------------------
Edward J. Bernica
President and Chief Executive Officer
(principal executive officer)
I, JoAnn S. Hogan, certify that:
1. I have reviewed this annual report on Form 10-K of Energy West
Incorporated.
2. Based on my knowledge, this annual report does not contain any
untrue statement of a material fact or omit to state a material fact necessary
to make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by this
annual report; and
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this annual report.
Date: September 30, 2002
/s/ JoAnn S. Hogan
---------------------------------------
JoAnn S. Hogan
Assistant Vice-President & Treasurer
(principal financial officer)
73
EXHIBIT INDEX
EXHIBITS
3.1 Restated Articles of Incorporation of the Company, as amended to date
(previously filed).
3.2 Bylaws of the Company, as amended to date (previously filed).
4.1 Form of Indenture (including form of Note) relating to the Company's
Series 1993 Notes (incorporated by reference to Exhibit 4.1 to the
Company's Registration Statement on Form S-2, File No. 33-62680).
4.2 Loan Agreement, dated as of September 1, 1992, relating to the Company's
Series 1992A and Series 1992B Industrial Development Revenue Bonds
(incorporated by reference to Exhibit 4.2 to the Company's Registration
Statement on Form S-2, File No. 33-62680).
10.1 Credit Agreement dated as of January 18, 1995, by and between the Company
and Norwest Bank Great Falls, National Association (previously filed).
10.2 Amendment dated April 17, 1996 to Credit Agreement dated as of January 18,
1995, by and between the Company and Norwest Bank Montana, National
Association (previously filed).
10.3 Amendment dated November 7, 1996 to Credit Agreement dated as of January
18, 1995, the Company and Norwest Bank Montana, National Association
(previously filed).
10.4 Promissory Note dated November 7, 1996, issued to Norwest Bank Montana,
National Association (previously filed).
10.5 Credit Agreement dated as of February 12, 1997, by and between the Company
and First Bank Montana, National Association (previously filed).
10.6 Delivered Gas Purchase Contract dated February 23, 1997, as amended by
that Letter Amendment Amending Gas Purchase Contract dated March 9, 1982;
that Amendment to Delivered Gas Purchase Contract applicable as of March
20, 1986; that Letter Agreement dated December 18, 1986; that Letter
Agreement dated April 12, 1988; that Letter Agreement dated April 28,
1992; that Letter Agreement dated March 14, 1996; that Letter Agreement
dated April 15, 1996; a second Letter Agreement dated April 15, 1996; that
Letter dated February 18, 1997; and that Letter dated April 1, 1997,
transmitting a Notice of Assignment effective February 26, 1993
(previously filed).
10.7 Delivered Gas Purchase Contract dated December 1, 1985, as amended by that
Letter Agreement dated July 1, 1986; that Letter Agreement dated November
19, 1987; that Letter Agreement dated December 1, 1988; that Letter
Agreement dated July 30, 1992; that Assignment Conveyance and Bill of Sale
effective as of January 1, 1993; that Letter Agreement dated March 8,
1993; that Letter Agreement dated October 21, 1993; that
74
Letter Agreement dated October 18, 1994; that Letter Agreement dated
January 30, 1995; that Letter Agreement dated August 30, 1995; that Letter
Agreement dated October 3, 1995; that Letter Agreement dated October 31,
1995; that Letter Agreement dated December 21, 1995; that Letter Agreement
dated April 25, 1996; that Letter Agreement dated January 29, 1997; and
that Letter dated April 11, 1997 (previously filed).
10.8 Natural Gas Sale and Purchase Agreement dated July 20, 1992 between Shell
Canada Limited and the Company, as amended by that Letter Agreement dated
August 23, 1993; that Amending Agreement effective as of November 1, 1994;
and that Schedule A Incorporated Into and Forming a art of That Natural
Gas Sale and Purchase Agreement, effective as of November 1, 1996
(previously filed).
10.9 Employee Stock Ownership Plan Trust Agreement (incorporated by reference
to Exhibit 10.2 to Registration Statement on Form S-1, File No. 33-1672).
10.10 1992 Stock Option Plan (previously filed).
10.11 Form of Incentive Stock Option under the 1992 Stock Option Plan
(previously filed).
10.12 Management Incentive Plan (previously filed).
10.13 Energy West Incorporated Retention Bonus Plan dated September 14, 2000.
(previously filed)
10.14 Memorandum of Agreement dated as of September 14, 2000 between Energy West
Incorporated and Larry D. Geske. (previously filed)
10.15 Memorandum of Agreement dated as of September 14, 2000 between Energy West
Incorporated and Edward J. Bernica (previously filed)
10.16 Memorandum of Agreement dated as of September 14, 2000 between Energy West
Incorporated and Tim A. Good. (previously filed)
10.17 Separation Agreement, Release and Waiver of Claims dated October, 2001
between Energy West Incorporated and Larry D. Geske.
10.18 Energy West Long-Term Incentive Plan
10.19 Energy West Senior Management Incentive Plan
10.20 Energy West, Incorporated Deferred Compensation Plan for Directors
21.1 Subsidiaries of the Company (previously filed).
23.1 Consent of Independent Auditors -- Deloitte & Touche.
23.2 Consent of Independent Auditors -- Ernst & Young.
99.1 Certification of Principal Executive Officer.
99.2 Certification of Principal Financial Officer.
75