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, 2004
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from _______________ to _______________
Commission File number 0-14183
ENERGY WEST, INCORPORATED
(Exact name of registrant as specified in its charter)
Montana 81-0141785
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
1 First Avenue South, Great Falls, Montana 59401
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code (406) 791-7500
Securities to be registered pursuant to Section 12(b) of the Act:
None
Securities registered pursuant to Section 12(g) of the Act:
Title of each class
Common Stock - Par Value $.15
Preferred Stock Purchase Rights
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 [ ] No [X]
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K [ ].
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Act). Yes [ ] No [X].
The aggregate market value of the voting stock held by non-affiliates of the
registrant as of December 31, 2003: Common Stock, $.15 Par Value - $15,448,829.
The number of shares outstanding of the registrant's classes of common stock as
of December 15, 2004: Common Stock, $.15 Par Value - 2,596,422 shares.
1
PART I
ITEM 1. - BUSINESS
GENERAL
Energy West, Incorporated (the "Company") is a regulated public utility,
with certain non-utility operations conducted through its subsidiaries. The
Company was originally incorporated in Montana in 1909. The Company has four
business segments:
Natural Gas Operations Distribute natural gas to approximately 33,000
customers through regulated utilities operating in and
around Great Falls and West Yellowstone, Montana, and
Cody, Wyoming. The approximate population of the
service territories is 100,000.
Propane Operations Distribute propane to approximately 7,600 customers
through regulated utilities operating underground vapor
systems in and around Payson, Pine and Strawberry,
Arizona. Non-regulated operations include retail
distribution of bulk propane to approximately 2,200
customers in the same Arizona communities. The
approximate population of the service territories is
40,000.
Energy West Resources, Inc. Market approximately 3 billion cubic feet ("BCF") of
(EWR) natural gas to commercial and industrial customers in
Montana and Wyoming and manage midstream supply
and production assets for transportation customers and
utilities. EWR also has an ownership interest in
production and gathering assets.
Pipeline Operations (Energy Owns the Shoshone interstate and the Glacier gathering
West Development, Inc. pipeline assets located in Montana and Wyoming.
(EWD)) Certain natural gas producing wells owned by EWD are
being operated, managed, and reported in EWR.
See Note 10 to the Consolidated Financial Statements for summary results of
operations for each of the Company's segments and total assets.
2
RECENT DEVELOPMENTS
RESTATEMENT OF FINANCIAL RESULTS
On September 29, 2004, the Company announced that it was delaying the
filing of its Annual Report on Form 10-K in order to complete a review of the
accounting for certain contracts. Based on the results of its review, the
Company has corrected its accounting and previous valuation of certain of EWR's
contracts for fiscal years 2002 and 2003, and the first three quarters of fiscal
year 2004, and has restated its earnings for those periods.
The Company's review of EWR's contracts included an evaluation of a gas
purchase agreement and a gas sales agreement entered into during fiscal year
2002 involving counterparties who are affiliated with each other. The gas
purchase agreement has previously been reflected in the Company's financial
statements as a derivative asset. The gas sales agreement was previously
classified by the Company as a normal sales contract, and therefore was not
reflected on the Company's financial statements as a derivative liability. The
Company determined that a shorter period similar to that of the gas sales
agreement should have been used in the determination of the fair value of the
gas purchase agreement and that the gas sales agreement does not qualify for the
"normal purchase and sale" exception. As a result the consolidated financial
statements have been restated to reflect a significant reduced fair value for
the gas purchase agreement and the gas sales agreement as a derivative liability
at its estimated fair value.
3
In the course of its review, the Company also determined that the fair
value of a small gas purchase contract and a small gas sales contract entered
into by EWR during the fiscal quarter ended December 31, 2003, had not been
properly reflected in the Company's unaudited quarterly financial statements.
The Company has reflected the fair value of these contracts in its restated
quarterly financial information.
None of the adjustments affects the Company's cash flows or cash
balances. The Company's cumulative gain (loss) in the portfolio of contracts
valued on a mark-to-market basis will be realized in later periods as contracts
settle or are performed and/or as natural gas prices change. See Note 15 of the
Consolidated Financial Statements included in Item 8 of this Annual Report on
Form 10-K.
4
AMENDMENTS TO LOAN AGREEMENT
As of August 30, 2004, the Company and its lender under its credit
facility (the "LaSalle Facility") amended certain covenants as follows: (1)
increased the total debt to capital ratio from .65 to .70, (2) allowed the
inclusion of certain expenses incurred by the Company for legal fees and costs
of the PPLM litigation, expenses and costs associated with the credit
facilities, proxy contest costs, and the costs of adoption of the shareholder
rights plan, in determining the interest coverage ratio, and (3) waived
compliance with the ratios referred to in (1) and (2) above as of June 30, 2004
in addition to a shareholder's acquisition of more than 15% of the outstanding
common stock of the Company.
As of September 10, 2004, the LaSalle Facility was amended to extend from
September 30, 2004 until October 31, 2004, the deadline for the Company to repay
the $2,000,000 term loan under the LaSalle Facility, with an infusion of new
equity.
On October 20, 2004, but effective as of September 28, 2004, the LaSalle
Facility was amended to extend until October 29, 2004, the deadline for the
Company to deliver its audited financial statements for the fiscal year ended
June 30, 2004.
On November 2, 2004, the Company executed a letter agreement effective as
of September 28, 2004 amending the LaSalle Facility. The letter agreement
provides for the extension of the deadline to deliver audited financial
statements for fiscal year 2004 from October 29, 2004 to November 12, 2004.
As of November 2, 2004, the Company executed an amendment to the LaSalle
Facility, which provides for an extension from October 31, 2004 to November 30,
2004 of the deadlines under the LaSalle Facility in connection with: (i) the
termination date of the revolving facility and
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(ii) the date to consummate infusions of new equity of at least $2.0 million to
repay the $2.0 million term loan under the LaSalle Facility.
As of November 30, 2004, the Company executed an agreement with its
lender providing for (i) an extension of the revolving facility until
November 28, 2005; (ii) an extension of the date to consummate infusions of new
equity of at least $2.0 million and to repay the $2.0 million term loan to
October 1, 2005; (iii) a conditional waiver of the deadline to deliver audited
financial statements for fiscal year 2004 and the deadline to deliver financial
statements for the fiscal quarter ended September 30, 2004; (iv) a waiver of
the technical default that otherwise would have been caused by the restatement
of financial results of prior periods; (v) modification of interest rates
applicable to the $2.0 million term loan; (vi) a limitation of $1.0 million on
total loans and additional capital investment from the Company to EWR; and
(vii) waivers of certain financial covenant defaults as of September 30, 2004.
The following tables representing revenues for all operating segments are
after all intercompany eliminations, by customer class for the fiscal year
ended June 30, 2004 and the two preceding fiscal years.
NATURAL GAS OPERATIONS
The Company's natural gas operations consist of two divisions. The Montana
Division serves customers with operations in Great Falls, West Yellowstone, and
Cascade, Montana. It also manages certain storage and vaporization facilities in
Cascade, Montana for Energy West Propane. The Wyoming Division serves customers
in and around Cody, Meeteetse and Ralston, Wyoming. Generally, residential
customers use natural gas for space heating and water heating; commercial
customers use natural gas for space heating and cooking; and industrial
customers use natural gas as a fuel in industrial processing and space heating.
The Company's revenues from natural gas operations are generated under tariffs
regulated by the state utility commissions of Montana and Wyoming. The Montana
division received an interim order from the Montana Public Service Commission
("MPSC") effective January 1, 2004 for a rate increase for the Great Falls
operations due to increased property taxes. The MPSC approval of this increase
did not cover the entire tax increase experienced by the Company due to an
interpretation by the MPSC of a statute that permits such increases on an
after-tax basis. The Company has filed for a general rate increase which
includes the net of tax effect mentioned above. The Company has entered into a
stipulation agreement with the Montana Consumer Council ("MCC") and has received
an interim order from MPSC adopting the stipulation. The interim rate increase
was effective November 1, 2004 and is estimated to provide additional gross
margin of approximately $800,000 annually. In addition, an interim order for the
West Yellowstone general rate filing was approved for approximately $200,000
annually and became effective on November 1, 2004.
NATURAL GAS - MONTANA DIVISION
The Natural Gas - Montana division provides natural gas service to
customers in and around Great Falls and West Yellowstone, Montana and manages an
underground vapor system in Cascade, Montana. The division's service area has a
population of approximately 79,000 in the Great Falls area, 1,200 in the West
Yellowstone area and approximately 900 in the Cascade area.
The division has a franchise to distribute natural gas within the city of
Great Falls that expires in 2021. The division also provides natural gas
transportation service to certain customers who purchase natural gas from other
suppliers.
6
The following table shows the Natural Gas - Montana division's revenues by
customer class for the fiscal year ended June 30, 2004 and the two preceding
fiscal years:
GAS REVENUE
(in thousands)
Year Ended June 30,
-------------------
2004 2003 2002
---- ---- ----
Residential $16,427 $13,643 $17,563
Commercial 9,918 8,383 10,443
Transportation 1,856 1,789 1,958
------- ------- -------
Total $28,201 $23,815 $29,964
======= ======= =======
Note: Revenue increased in fiscal year 2004 compared to fiscal year 2003 due to
increases in gas pricing and rate relief from approved rate cases in
Montana. Revenues were lower in fiscal year 2003 compared to fiscal year
2002 due to termination of a surcharge for collection of previously
unrecovered gas costs and a lower volume of sales due to warmer than
normal temperatures.
The following table shows the volumes of natural gas, expressed in
millions of cubic feet (MMCF) sold or transported by the division for the fiscal
year ended June 30, 2004 and the two preceding fiscal years:
GAS VOLUMES
(MMcf)
Year Ended June 30,
-------------------
2004 2003 2002
---- ---- ----
Residential 2,206 2,267 2,417
Commercial 1,317 1,359 1,442
Transportation 1,443 1,462 1,522
----- ----- -----
Total Gas Sales 4,966 5,088 5,381
===== ===== =====
The Natural Gas - Montana division has 173 transportation customers. No
customer of the Natural Gas - Montana division accounted for more than 2% of the
consolidated revenues of the Company in fiscal 2004.
The operations of the Natural Gas - Montana division are subject to
regulation by the MPSC. The MPSC regulates rates, adequacy of service, issuance
of securities, compliance with U.S. Department of Transportation safety
regulations and other matters.
7
The MPSC allows customers to choose a natural gas supplier other than the
Energy West Natural Gas - Montana division, but the division provides gas
transportation to customers who purchase from other suppliers.
The Natural Gas - Montana division uses the NorthWestern Energy ("NWE")
pipeline transmission system to transport supplies of natural gas for its core
load and to provide transportation, distribution and balancing services to
customers who have chosen to obtain natural gas from other suppliers. In 2000,
the Company entered into a ten-year transportation agreement with NWE that fixes
the cost of pipeline and storage capacity for the Natural Gas - Montana
division.
The Natural Gas - Montana division files monthly gas trackers that adjust
the gas cost recovery component of its rates to current market pricing. This
process is designed to keep deferred gas cost balances at minimum expected
levels.
NATURAL GAS - WYOMING DIVISION
The Natural Gas - Wyoming division provides natural gas service to
customers in and around Cody, Meeteetse and Ralston, Wyoming. This service area
has a population of approximately 12,000. The Natural Gas - Wyoming division has
a certificate of public convenience and necessity granted by the Wyoming Public
Service Commission ("WPSC") for transportation and distribution covering the
west side of the Big Horn Basin, which extends approximately 70 miles north and
south and 40 miles east and west from Cody. As of June 30, 2004, the Natural Gas
- - Wyoming division provided service to 5,860 customers, including one industrial
customer. The division also offers transportation through its system. This
service is designed to permit producers and other purchasers of gas to transport
their gas to markets outside of the division's distribution and transmission
system.
8
The following table shows the Natural Gas - Wyoming division's revenues by
customer class for the fiscal year ended June 30, 2004 and the two preceding
fiscal years:
GAS REVENUE
(in thousands)
Year Ended June 30,
-------------------
2004 2003 2002
---- ---- ----
Residential $ 4,149 $3,119 $3,434
Commercial 3,606 2,591 3,035
Industrial 3,107 2,102 3,044
Transportation - - 38
------- ------ ------
Total $10,862 $7,812 $9,551
======= ====== ======
Note: Higher revenues were realized in fiscal year 2004 compared to fiscal
year 2003 due to a general rate increase approved by Wyoming Public
Service Commission at the end of fiscal year 2003 as well as higher
commodity pricing in fiscal year 2004. Lower revenues were realized
in fiscal year 2003 compared to fiscal year 2002 due to warmer than
normal temperatures and reduced sales to a large industrial
customer.
The following table shows volumes of natural gas, expressed in MMCF, sold
by the Natural Gas - Wyoming division for the fiscal year ended June 30, 2004
and the two preceding fiscal years:
GAS VOLUMES
(MMcf)
Year Ended June 30,
-------------------
2004 2003 2002
---- ---- ----
Residential 515 541 564
Commercial 540 531 550
Industrial 568 525 610
Transportation 1,280 1,383 1,588
----- ----- -----
Total Gas Sales 2,903 2,980 3,312
===== ===== =====
The Natural Gas - Wyoming division has an industrial customer whose gas
sales rates are subject to an industrial tariff, which provides for lower
incremental prices as higher volumes are used. In fiscal year 2004 this customer
accounted for approximately 28% of the revenues of the Natural Gas - Wyoming
division and approximately 8% of the consolidated revenues of the Natural Gas
segment. This customer's business is cyclical and dependent on the level of
national housing
9
starts. Gross revenues from this customer in fiscal year 2004 increased
approximately 48% over revenues in fiscal year 2003.
EWR is the Natural Gas - Wyoming division's supplier of natural gas,
pursuant to a three year agreement entered into in May of 2003.
The Natural Gas - Wyoming division transports gas for third parties
pursuant to a tariff filed with and approved by the WPSC. The terms of the
transportation tariff (currently between $.08 and $.31 per MCF) are approved by
the WPSC.
The Natural Gas - Wyoming division's revenues are generated under
regulated tariffs designed to recover a base cost of gas and administrative and
operating expenses and provide a sufficient rate of return to cover interest and
profit. The division's tariffs include a purchased gas adjustment clause which
allows the division to adjust rates periodically to recover changes in gas costs
from base gas costs. The Wyoming division received an approval from the WPSC for
a general rate increase effective June 1, 2003, which the Company estimates will
provide increased revenues of $722,000 annually.
PROPANE OPERATIONS
The Company reports as a separate business segment the regulated and
unregulated distribution of propane.
REGULATED PROPANE OPERATIONS
The Company is engaged in the regulated sale of propane under the business
name Energy West Arizona ("EWA"). EWA distributes propane in the Payson, Pine,
and Strawberry, Arizona area located about 75 miles northeast of Phoenix in the
Arizona Rim Country. The service area of EWA includes approximately 575 square
miles and has a population of approximately 31,000. The operations of EWA are
subject to regulation by the Arizona Corporation Commission ("ACC"), which
regulates rates, adequacy of service, and other matters. EWA's properties
include approximately 170 miles of underground distribution pipeline and an
office building leased from a third party. EWA purchases propane from the
Company's unregulated subsidiary, Energy West Propane, Inc. ("EWP"), under terms
reviewed periodically by the ACC. EWA has approximately 7,600 regulated
customers. Annual customer growth has averaged roughly 8% for the last five
years. The principal competition comes from bulk propane retailers who sell to
customers who use propane from storage tanks located at their homes or
businesses rather than using propane from EWA's underground distribution system.
10
The following tables show EWA revenues and propane volumes by customer
class for the fiscal year ended June 30, 2004 and the two preceding fiscal
years:
REGULATED PROPANE REVENUE
(in thousands)
Year Ended June 30,
-------------------
2004 2003 2002
---- ---- ----
Residential $3,844 $3,729 $3,384
Commercial 1,785 1,629 1,520
------ ------ ------
Total $5,629 $5,358 $4,904
====== ====== ======
REGULATED PROPANE VOLUME
(in thousands of gallons)
Year Ended June 30,
-------------------
2004 2003 2002
---- ---- ----
Residential 2,818 2,874 2,678
Commercial 1,309 1,070 1,012
----- ----- -----
Total 4,127 3,944 3,690
===== ===== =====
UNREGULATED PROPANE OPERATIONS
EWP is engaged in the bulk sale of propane through its two divisions:
Energy West Propane-Arizona, which serves the Payson, Pine, and Strawberry,
Arizona area, and Rocky Mountain Fuels Wholesale ("RMF") which has wholesale
operations primarily in Montana and Arizona. EWP had 2,163 unregulated customers
as of June 30, 2004. Decreases in revenues, volumes, and customers are a result
of the sale of certain assets of RMF in August 2003.
EWP's wholesale division, RMF, supplies propane for the Company's
underground propane-vapor systems serving the cities of Cascade, Montana and
Payson, Arizona and surrounding areas. The majority of RMF's Wyoming and Montana
assets, including the Superior, Montana terminal were sold on August 21, 2003
for approximately $1,370,000. The Company realized a $252,000 before-tax gain on
the sale of these assets.
EWP faces competition from other propane distributors and suppliers of
alternative fuels that compete with propane. Competition is based primarily on
price and there is a high degree of competition with other propane distributors
in each of the Company's service areas.
11
The following tables show the revenues and volumes for unregulated propane
operations by customer class for the fiscal year ended June 30, 2004 and the two
preceding fiscal years:
UNREGULATED PROPANE REVENUE
(in thousands)
Year Ended June 30,
-------------------
2004 2003 2002
---- ---- ----
Residential $1,612 $1,426 $1,354
Commercial 495 6,002 4,398
------ ------ ------
Total $2,107 $7,428 $5,752
====== ====== ======
Note: Revenues decreased in fiscal year 2004 compared to fiscal year
2003 due to lost sales volumes from the sale of RMF's Superior
operation. The increase in revenue from fiscal year 2002 to
fiscal year 2003 was due to increased sales activity from
RMF's wholesale operations.
UNREGULATED PROPANE VOLUME
(in thousands of gallons)
Year Ended June 30,
-------------------
2004 2003 2002
---- ---- ----
Residential 917 912 901
Commercial 786 10,870 6,934
----- ------ -----
Total 1,703 11,782 7,835
----- ------ -----
EWR
The Company's wholly-owned subsidiary, EWR, conducts certain marketing
activities involving the sale of natural gas in Montana and Wyoming and
electricity in Montana.
Montana legislation and subsequent MPSC orders permit open access on the
NWE transportation systems, and other systems in Montana have presented
opportunities for EWR to conduct business as a broker of natural gas and
electricity. EWR has from time to time entered into certain financial agreements
that hedge against the risks of fluctuation in prices of natural gas and
electricity. If the price obtained through such instruments is favorable or
unfavorable compared to subsequent market conditions, net earnings or losses can
result from such arrangements. See Item 7, "Management's Discussion and Analysis
of Financial Condition and Results of Consolidated Operations -- Derivatives and
Risk Management." During fiscal year 2003, EWR exited the
12
electricity marketing business, with the exception of maintaining one customer,
delivering less than one MW per hour pursuant to a contract in effect through
fiscal year 2005.
In order to provide a stable source of natural gas for a portion of its
requirements, EWR and EWD purchased two groups of producing natural gas
properties consisting of 163 wells and three gathering systems located in north
central Montana. The purchases were made in May 2002 and March 2003. The wells
are depleting based upon current levels of production at approximately 10% per
year.
This production gives EWR a natural hedge due to fixed production expenses
when market prices of natural gas are above the cost of production. EWR's and
EWD's portion of estimated daily gas production from the properties is
approximately 920 MCF's per day, or 4.5% of EWR's present volume requirements.
PIPELINE OPERATIONS
Pipeline Operations was added as a new segment as of July 1, 2002. The
results of this segment reflect operation of the "Glacier" natural gas gathering
system placed in service in fiscal year 2001 and the "Shoshone" transmission
pipeline placed in service on July 3, 2003. Both pipelines have sections located
in Wyoming and Montana. The revenues and expenses associated with the pipelines
are included in the "Pipeline Operations" segment.
AVAILABLE INFORMATION
The internet address for the Company is: http://www.ewst.com. The Company
makes available, free of charge, on its internet website annual reports on Form
10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and additional
filings of the Company filed or furnished pursuant to Section 13(a) or 15(d) of
the Exchange Act as soon as reasonably practicable after these filings have been
made with the SEC.
13
COMPETITION
The traditional competition faced by the Company in its distribution and
sales of natural gas is from suppliers of alternative fuels, including
electricity, oil, propane and coal. Traditionally, 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, with
respect to the majority of the Company's service territory, previously installed
equipment is not an issue. Households in recent years have generally preferred
the installation of gas heat. For example, the Company estimates that
approximately 97% of the homes and businesses in the Great Falls, Montana
service area use natural gas as their primary source for space heating fuel;
approximately 93% use gas for water heating, and approximately 99% of the new
homes built on or near the Company's Great Falls, Montana service mains in
recent years have selected natural gas as their energy source. The Company's
operations in West Yellowstone and Cascade, Montana and the Payson / Strawberry
area of Arizona face more intense competition due to the cost of competing fuels
than the Company faces in the Great Falls area of Montana and the Company's
service territory in Wyoming.
The Natural Gas - Wyoming division estimates that approximately 95% of the
homes and businesses in its service area use natural gas for space heating fuel;
approximately 90% use gas for water heating, and approximately 99% of the new
homes built on or near the division's service mains in recent years have
selected gas as their energy source.
The Propane - Arizona division estimates that approximately 67% of the
homes and businesses adjacent to the division's distribution pipeline use the
division's propane for space heating or water heating. Studies show that
approximately 90% of new subdivisions within the division's distribution system
are using propane as their primary fuel source.
The principal competition faced by the Company and its subsidiaries in the
distribution and sale of propane is from electricity suppliers and other propane
distributors. Competition is based primarily on price and customer service and
there is a high degree of competition from other propane distributors in all of
the service areas.
EWR's principal competition is from other gas marketing firms doing
business in the State of Montana.
14
GOVERNMENTAL REGULATION
The Company's utility operations are subject to regulation by the MPSC,
the WPSC, FERC and the ACC. Such regulation plays a significant role in
determining the Company's return on equity. The commissions approve rates
intended to permit a reasonable rate of return on investment. The Company's
tariffs allow gas cost to be recovered in full (barring a finding of imprudence)
in regular (as often as monthly) rate adjustments. This mechanism may result in
some delay between the incurrence and recovery of increased gas costs. However,
recent adjustments in the mechanism in Montana have substantially reduced that
delay. In addition, an interim order for West Yellowstone's and Energy West
Montana's general rate filings was approved for approximately $200,000 and
approximately $800,000, respectively, on an annual basis, for services rendered
on and after November 1, 2004.
SEASONALITY
The business of the Company and its subsidiaries in all segments is
temperature-sensitive. In any given period, sales volumes reflect the impact of
weather, in addition to other factors, with colder temperatures generally
resulting in increased sales by the Company. The Company anticipates that this
sensitivity to seasonal and other weather conditions will continue to be
reflected in the Company's sales volumes in future periods.
ENVIRONMENTAL MATTERS
The Company owns property on which it operated a manufactured gas plant
from 1909 to 1928. The site is currently used as an office facility for Company
field personnel and storage location for certain equipment and materials. The
coal gasification process utilized in the plant resulted in the production of
certain by-products which have been classified by the federal government and the
State of Montana as hazardous to the environment.
The Company has completed its remediation of soil contaminants at the
plant site and in April of 2002 received a closure letter from Montana
Department of Environmental Quality ("MDEQ") approving the completion of such
remediation program.
The Company and its consultants continue to work with the MDEQ relating to
the remediation plan for water contaminants. The MDEQ has established
regulations that allow water contaminants at a site to exceed standards if it is
technically impracticable to achieve those standards. Although the MDEQ has not
established guidance respecting the attainment of a technical waiver, the U.S.
Environmental Protection Agency ("EPA") has developed such guidance. The EPA
guidance lists factors which render mediations technically impracticable. The
Company has filed a request for a waiver from complying with certain standards
with the MDEQ.
At June 30, 2004, the Company had incurred cumulative costs of
approximately $1,925,000 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, 2004, the Company had
recovered approximately $1,440,000 through such surcharges. As of June 30, 2004,
the cost remaining to be recovered is $485,000.
15
On April 15, 2003, the MPSC issued an Order to Show Cause Regarding the
Environmental Surcharge. The MPSC determined that the initial order allowing the
collection of the surcharge was intended by the MPSC to cover only a two year
collection period, after which it would contemplate additional filings by the
Company, if necessary. The Company responded to the Show Cause Order and the
MPSC subsequently ordered the termination of the Environmental Surcharge on
August 20, 2003. The Company filed a request with the commission to continue the
collection of the surcharge until all expenses have been recovered. This request
was approved by the MPSC and the surcharge was reinstated in September 2004. The
Company is required, under the Commission's most recent order, to file with the
MPSC every two years for approval to continue the recovery of the surcharge.
EMPLOYEES
The Company and its subsidiaries had a total of 115 employees as of June
30, 2004. Three of these employees were employed by EWR, 24 by the Company's
Propane Operations, 76 by the Company's Natural Gas Operations and 12 at the
corporate office. The Company's Natural Gas Operations include 17 employees
represented by two labor unions. Contracts with each of these unions expire on
June 30, 2006. However, both unions have requested to reopen wage negotiations
in the current agreement pursuant to wage opener provisions. The Company is
involved in negotiations with the two labor unions on this issue.
EXECUTIVE OFFICERS
The following table sets forth the names, ages, and the positions and
offices presently held by the executive officers of the Company:
NAME AGE POSITION
David A. Cerotzke 54 President, Chief
Executive Officer and
Director
John C. Allen 53 Senior Vice-President,
General Counsel and
Secretary
Tim A. Good 59 Vice-President and Manager
of Natural Gas Operations
Douglas R. Mann 57 Vice-President and Manager
of Propane Operations
16
James E. Morin 50 President of Energy West
Resources, Inc.
M. Shawn Shaw 43 Principal Financial Officer
DAVID A. CEROTZKE was appointed President and Chief Executive Officer on July 1,
2004. He has been a member of the Board of Directors of the Company since
December 2003. Prior to joining the Company he was a consultant in the energy
industry from January 2003 to December 2003. From 1990 to 2003, he served in
various executive capacities, including Vice-President of Engineering,
Vice-President of Operations, Vice-President of Marketing and Treasurer of Nicor
Inc., a diversified energy holding company.
JOHN C. ALLEN was appointed Senior Vice-President, General Counsel and Secretary
on July 1, 2004. He served as Interim President and Chief Executive Officer from
September 22, 2003 to June 30, 2004. He joined the Company in 1986 as Corporate
Counsel and Secretary and was appointed General Counsel, Vice-President and
Secretary of the Company in 1992. Prior to joining Energy West he was a Staff
Attorney for the Montana Consumer Counsel from 1979 to 1986.
TIM A. GOOD has been the 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 Natural Gas - Wyoming Division from 1988 to July 1,
2000.
DOUGLAS R. MANN has been the Vice-President and Manager of the Company's Propane
Operations since July 1, 2000. From February 1999 until July 1, 2000, he served
as Vice-President and Manager of the EWA Division. From 1995 until July 1, 1999,
he served as Assistant Vice-President and Manager of the Arizona Division. He
joined Energy West in 1983, after a 14 year career in computer engineering and
technical sales.
JAMES E. MORIN has been President of EWR since February 2003. From July 2001 to
February 2003 he served as Vice-President of Electricity Marketing and from
August 1997 to July 2001 he served as Manager of Industrial and Commercial
Marketing for EWR.
M. SHAWN SHAW was appointed Principal Financial Officer effective September 10,
2004. He has served the Company as a Senior Accountant in various financial and
regulatory capacities since 1991.
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,
17
Montana, the Company owns an office building and a liquefied natural gas plant
that provides natural gas through approximately 13 miles of underground mains
owned by the Company. The Company owns approximately 10 miles of underground
mains in the town of Cascade, as well as two large propane storage tanks.
EWR and EWD combined own 163 natural gas production wells and three
gathering systems in north central Montana.
At June 30, 2003, EWD owned approximately 30 acres of real property in
Great Falls, Montana. The property was sold on September 8, 2003, and EWD
realized a pre-tax gain of approximately $121,000. During fiscal year 2003, EWD
purchased a 40% ownership interest in natural gas production properties in north
central Montana that provide approximately 350 MCF of natural gas daily for
resale.
WYOMING: In Cody, Wyoming, the Company leases office and service buildings for
the Natural Gas - Wyoming division under long-term lease agreements. The Company
owns approximately 500 miles of transmission and distribution mains and related
metering and regulating equipment, all of which are located in or around Cody,
Meeteetse and Ralston.
EWD owns two pipelines in Wyoming and Montana. One is currently being
operated as a gathering system. The other pipeline began operating as a natural
gas interstate transmission pipeline on July 3, 2003. The pipelines extend from
north of Cody, Wyoming to Warren, Montana.
ARIZONA: The Company owns approximately 170 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. The Company leases an office building in Payson under an
agreement that expires in 2006. The Company has the right to extend the lease
for two successive five year periods. EWP owns several large bulk propane tanks
and numerous customer tanks located in Pine, Strawberry, Payson and Star Valley,
which are used to serve customers in those communities and surrounding areas.
ITEM 3. - LEGAL PROCEEDINGS
From time to time the Company is involved in litigation relating to claims
arising from its operations in the normal course of business. The Company
utilizes various risk management strategies, including maintaining liability
insurance against certain risks, employee education and safety programs and
other processes intended to reduce liability risk.
In addition to other litigation referred to above, the Company or its
subsidiaries are involved in the following described litigation.
On June 17, 2003, EWR and PPL Montana, LLC ("PPLM") reached agreement on a
settlement of a lawsuit involving a wholesale electricity supply contract. Under
the terms of the settlement, EWR paid PPLM a total of $3,200,000, consisting of
an initial payment of $1,000,000 on June 17, 2003, and a second payment of
$2,200,000 on September 30, 2003, terminating all proceedings in the case. EWR
had established reserves and accruals in fiscal year 2001 of
18
approximately $3,032,000 to pay a potential settlement with PPLM and the
remaining $168,000 was charged to operating expenses in fiscal year 2003.
On August 8, 2003, the Company reached agreement with the Montana
Department of Revenue ("DOR") to settle a claim that the Company had
under-reported its personal property for the years 1997 - 2002 and that
additional property taxes and penalties should be assessed. The settlement
amount is being paid in ten annual installments of $243,000 each, beginning
November 30, 2003.
The Company initially determined that it was entitled to recover the
amounts paid in connection with the DOR settlement through future rate
adjustments as a result of legislation permitting "automatic adjustments" to
rates to recover such property tax increases. The MPSC, however, interpreted the
new legislation as allowing recovery of only a portion of the higher property
taxes. Rates recovering the portion of the higher taxes permitted under the
MPSC's interpretation of the legislation went into effect on January 1, 2004.
The Company has since obtained interim rate relief which includes full recovery
of the property tax associated with the DOR settlement.
ITEM 4. - SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
19
PART II
ITEM 5. - MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS,
AND ISSUER PURCHASES OF EQUITY SECURITIES
Common Stock Prices and Dividend Comparison - Fiscal Years 2004 and 2003
Prior to October 19, 2004, shares of the Company's Common Stock were
traded on the Nasdaq National Market under the symbol "EWST." Effective as of
the opening of business on October 19, 2004, shares of the Company's Common
Stock are being traded on the Nasdaq National Market under the symbol "EWSTE."
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,
mark-down or commission, and may not necessarily represent the actual
transactions.
PRICE RANGE -- FISCAL YEAR 2004 HIGH LOW
- ------------------------------- ---- ---
First Quarter $ 7.89 $ 6.00
Second Quarter $ 7.79 $ 5.95
Third Quarter $ 7.60 $ 6.01
Fourth Quarter $ 8.50 $ 6.42
Year $ 8.50 $ 5.95
PRICE RANGE -- FISCAL YEAR 2003 HIGH LOW
- ------------------------------- ---- ---
First Quarter $ 9.79 $ 8.40
Second Quarter $ 8.89 $ 7.25
Third Quarter $ 9.00 $ 7.31
Fourth Quarter $ 8.74 $ 4.74
Year $ 9.79 $ 4.74
As of June 30, 2004, there were approximately 1,700 holders of record of
the Company's common stock.
DIVIDEND POLICY
The Board of Directors historically considered approving common stock
dividends for payments in March, June, September and January. On June 17, 2003,
the Company's Board of Directors suspended the payment of quarterly cash
dividends. The LaSalle Facility contains restrictions respecting the payment of
dividends. (See Item 7 "Management's Discussion and Analysis of Financial
Condition and Results of Operations - Liquidity and Capital Resources").
Quarterly dividend payments per common share for fiscal years 2004 and 2003
were:
2004 2003
---- ----
First Quarter - $ 0.1350
Second Quarter - $ 0.1350
Third Quarter - $ 0.1350
Fourth Quarter - -
20
ITEM 6.- SELECTED FINANCIAL DATA
The following table contains certain selected historical consolidated
financial information and is qualified by the more detailed Consolidated
Financial Statements and Notes thereto included elsewhere in this Annual Report
on Form 10-K. The information below should be read in conjunction with the
Consolidated Financial Statements and Notes thereto and "Management's Discussion
and Analysis of Financial Conditions and Results of Operations" included
elsewhere in this Annual Report on Form 10-K. (Dollar amounts are in thousands,
except per share and number of shares.)
2004 (1) 2003 (2) 2002 (2) 2001 2000
-------- -------- -------- ---- ----
(Restated) (Restated)
(See Note 15 (See Note 15
to Consolidated to Consolidated
Financial Financial
Statements) Statements)
Operating results
Operating revenue $ 73,291 $ 77,898 $ 89,240 $ 111,612 $ 64,398
Operating expenses
Gas and electric purchases 57,911 62,520 74,590 90,173 50,800
General and administrative 10,170 11,669 8,790 12,095 7,649
Maintenance 480 497 466 428 400
Depreciation and amortization 2,332 2,393 2,059 1,970 1,856
Taxes other than income (3) 1,210 888 946 723 639
----------- ------------ -------------- ----------- -----------
Total operating expenses 72,103 77,967 86,851 105,389 61,344
----------- ------------ -------------- ----------- -----------
Operating income 1,188 (69) 2,389 6,223 3,054
Other income-net 385 302 658 282 449
Total interest charges (4) 2,498 1,633 1,704 2,097 1,674
----------- ------------ -------------- ----------- -----------
Income (loss) before taxes (925) (1,400) 1,343 4,408 1,829
Income tax expense (benefit) (369) (543) 516 1,643 708
----------- ------------ -------------- ----------- -----------
Net Income (Loss) ($ 556) ($ 857) $ 827 $ 2,765 $ 1,121
----------- ------------ -------------- ----------- -----------
Basic earnings (loss) per common share ($ 0.21) ($ 0.33) ($ 0.32) $ 1.11 $ 0.46
Diluted earnings (loss) per common share ($ 0.21) ($ 0.33) ($ 0.32) $ 1.10 $ 0.46
Dividends per common share (5) $ 0.00 $ 0.41 $ 0.52 $ 0.51 $ 0.49
Weighted average common shares
Outstanding - diluted 2,596,454 2,586,487 2,558,782 2,509,738 2,456,555
At year end:
Current assets $ 16,739 $ 15,790 $ 18,517 $ 26,621 $ 16,387
Total assets $ 61,445 $ 60,027 $ 57,295 $ 62,278 $ 51,194
Current liabilities $ 16,725 $ 21,833 $ 19,899 $ 24,416 $ 14,831
Total long-term obligations $ 21,697 $ 14,834 $ 15,367 $ 15,881 $ 16,395
Total stockholders' equity $ 13,401 $ 13,957 $ 15,699 $ 15,613 $ 13,786
----------- ------------ -------------- ----------- -----------
Total capitalization $ 35,098 $ 28,791 $ 31,066 $ 31,494 $ 30,181
=========== ============ ============== =========== ===========
21
(1) First three quarters as restated, See "Item 7. Management's Discussion and
Analysis of Financial Condition and Results of Operations - Restatement of
Financial Results" and Note 16 to the consolidated financial statements
for a comparison of previously reported and restated condensed quarterly
financial data.
(2) As restated. See "Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations - Restatement of Financial
Results" and Note 15 to the consolidated financial statements for a
summary of the significant effects of the restatement.
(3) Taxes other than income includes approximately $290,000 in the fiscal year
2004 for additional personal property taxes assessed by the Montana
Department of Revenue.
(4) Total interest charges reflect the costs associated with the addition of
$8,000,000 long-term debt incurred by the Company in March 2004.
(5) There have been no cash dividends paid subsequent to March 2003.
22
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF CONSOLIDATED OPERATIONS
RECENT DEVELOPMENTS
RESTATEMENT OF FINANCIAL RESULTS
On September 29, 2004, the Company announced that it was delaying the
filing of its Annual Report on Form 10-K in order to complete a review of the
accounting for certain contracts. Based on the results of its review, the
Company has corrected its accounting and previous valuation of certain of EWR's
contracts for fiscal years 2002 and 2003, and the first three quarters of fiscal
year 2004, and has restated its earnings for those periods.
The Company's review of EWR's contracts included an evaluation of a gas
purchase agreement and a gas sales agreement entered into during fiscal year
2002 involving counterparties who are affiliated with each other. The gas
purchase agreement has previously been reflected in the Company's financial
statements as a derivative asset. The gas sales agreement was previously
classified by the Company as a normal sales contract, and therefore was not
reflected on the Company's financial statements as a derivative liability. The
Company determined that a shorter period similar to that of the gas sales
agreement should have been used in the determination of the fair value of the
gas purchase agreement and that the gas sales agreement does not qualify for the
"normal purchase and sale" exception. As a result the consolidated financial
statements have been restated to reflect a significant reduced fair value for
the gas purchase agreement and the gas sales agreement as a derivative liability
at its estimated fair value.
23
In the course of its review, the Company also determined that the fair
value of a small gas purchase contract and a small gas sales contract entered
into by EWR during the fiscal quarter ended December 31, 2003, had not been
properly reflected in the Company's unaudited quarterly financial statements.
The Company has reflected the fair value of these contracts in its restated
quarterly financial information.
None of the adjustments affects the Company's cash flows or cash
balances. The Company's cumulative gain (loss) in the portfolio of contracts
valued on a mark-to-market basis will be realized in later periods as contracts
settle or are performed and/or as natural gas prices change. See Note 15 of the
Consolidated Financial Statements included in Item 8 of this Annual Report on
Form 10-K.
24
AMENDMENTS TO LOAN AGREEMENT
The Company has recently entered into a number of amendments and waivers
with respect to its credit facility. See Liquidity and Capital Resources.
CRITICAL ACCOUNTING POLICIES
Critical accounting policies are those that are most significant to the
portrayal of the Company's condition and results of operations and require
difficult, subjective and complex judgments by management in order to make
estimates about the effect of matters that are inherently uncertain. In applying
such policies management must record income and expense amounts that are based
upon informed judgments and best estimates. Because of the uncertainty inherent
in these estimates, actual results could differ from estimates used in applying
critical accounting policies. Changes in estimates, based on more accurate
future information, may affect amounts reported in future periods. Management is
not aware of any reasonably likely events or circumstances which would result in
different amounts being reported that would materially affect the Company's
financial condition or results of operation
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 rate-making 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 utility for amounts previously collected from customers and for
amounts that are expected to be refunded to customers (regulatory liabilities).
Costs recovered through rates include income taxes, property taxes,
environmental remediation and costs of gas.
RECOVERABLE/ REFUNDABLE COSTS OF GAS AND PROPANE PURCHASES -- The Company
accounts for purchased gas costs in accordance with procedures authorized by the
MPSC, the WPSC and the ACC under which purchased gas and propane costs that are
different from those provided for in present rates are accumulated and recovered
or credited through future rate changes.
25
DERIVATIVES -- The Company accounts for certain derivative contracts that
are used to manage risk in accordance with SFAS No. 133.
Contracts that are required to be valued as derivatives under SFAS No. 133
are reflected at "fair value" under the mark-to-market method of accounting. The
market prices or fair values used in determining the value of the Company's
portfolio are management's best estimates utilizing information such as closing
exchange rates, over-the-counter quotes, historical volatility and the potential
impact on market prices of liquidating positions in an orderly manner over a
reasonable amount of time under current market conditions. As additional
information becomes available, or actual amounts are determinable, the recorded
estimates may be revised. As a result, operating results can be affected by
revisions to prior accounting estimates. Operating results can also be affected
by changes in underlying factors used in the determination of fair value of
portfolio such as the following:
- There is variability in mark-to-market earnings due to changes
in the market price for gas. The Company's portfolio is valued
based on current and expected future gas prices. Changes in
these prices can cause fluctuations in earnings.
- The Company discounts derivative assets and liabilities using
risk-free interest rates adjusted for credit standing in
accordance with SFAS No. 133, which is more fully described in
Statement of Financial Accounting Concepts No. 7, "Using Cash
Flow Information and Present Value in Accounting Measurement"
(SFAS Concept 7).
Other activities consist of the purchasing of gas for utility operations,
which fall under the normal purchases and sales exception, and entering into
transactions to hedge risk associated with these purchases. These activities
require that management make certain judgments regarding election of the normal
purchases and sales exceptions and qualification of hedge accounting by
identifying hedge relationships and assessing hedge effectiveness.
RESULTS OF CONSOLIDATED OPERATIONS
The following discussion of the Company's financial condition and results of
operations should be read in conjunction with the Consolidated Financial
Statements and Notes thereto and other financial information included elsewhere
in this Report. The following gives effect to the restatement of the Company's
consolidated financial statements as discussed in Note 15 to the consolidated
financial statements.
FISCAL YEAR ENDED JUNE 30, 2004 COMPARED TO FISCAL YEAR ENDED JUNE 30, 2003
NET LOSS
The Company's net loss for fiscal year 2004 was $556,000 compared to a net
loss of $857,000 for fiscal year 2003, an improvement of $301,000. The
improvement in the Company's net loss from fiscal year 2003 to fiscal year 2004
was primarily the result of a reduction in distribution, general and
administrative expenses, costs of gas and electricity-wholesale and cost of
goods sold, and an increase in other income from fiscal year 2003 to fiscal year
2004, which were partially offset by an increase in interest expense, taxes and
gas purchased and a decrease in income tax benefits from fiscal year 2003 to
fiscal year 2004. The
26
principal changes that contributed to the improvement of $301,000 in net loss
from fiscal year 2003 to fiscal year 2004 are explained below.
REVENUES
The Company's revenues for fiscal year 2004 were $73,291,000 compared to
$77,898,000 in fiscal year 2003, a decrease of $4,607,000. The decrease was
primarily attributable to: (1) a $6,944,000 decrease in EWR marketing revenue
primarily due to the loss of revenues of $11,682,000 and $238,000 after the exit
from its electricity and appliance businesses, respectively, partially offset by
a $4,049,000 increase in volumes and prices of gas sales and the $932,000
increase in revenues as a result of mark-to-market accounting, and (2) a
reduction of $5,050,000 in revenue from Propane Operations primarily as a result
of the sale of wholesale propane assets in Superior, Montana. Revenues were
relatively flat in Pipeline Operations. The lower consolidated revenues were
partially offset by a $7,436,000 increase in revenue from Natural Gas Operations
resulting primarily from $6,136,000 of surcharges on higher gas costs and
$1,100,000 of increased revenue from higher rates approved by the respective
commissions in Montana and Wyoming as well as the approval of $200,000 for
property tax recovery in Montana.
GROSS MARGIN
Gross margins (revenues less cost of gas and electricity and costs of
goods sold) were nearly the same in fiscal years 2004 and 2003. Significant
changes in gross margins for the Company's segments from fiscal year 2003 to
fiscal year 2004 were: (1) decreased gross margins in EWR of $1,255,000,
primarily due to decreases in marketing activities, increases in prices related
to gas purchases necessary to satisfy fixed price contract agreements, and the
$932,000 adjustment under mark-to-market accounting, (2) decreased gross margins
in the Propane Operations of $288,000, due to the sale of the wholesale propane
assets in Superior, Montana, offset by gross margin increases in (1) Natural Gas
Operations of $1,307,000 due to the rate increases in Montana and Wyoming, and
(2) Pipeline Operations of $239,000 due to the placement in service of the
Shoshone interstate pipeline.
27
EXPENSES OTHER THAN COSTS OF GAS AND ELECTRICITY AND COSTS OF GOODS SOLD
Expenses other than costs of gas and electricity and costs of goods sold
decreased by $1,255,000 from fiscal year 2003 to fiscal year 2004 due to a
decrease in distribution, general and administrative expenses, and maintenance
and depreciation expenses, partially offset by an increase in taxes other than
taxes on income.
Distribution, general and administrative expenses decreased by $1,499,000.
This reduction resulted from the settlement of the PPLM litigation in fiscal
year 2003, and the resulting elimination for fiscal year 2004 of any costs and
expenses relating to the PPLM litigation, in fiscal year 2004. Such costs were
$1,552,000 in fiscal year 2003. Debt issuance expenses of $100,000 were included
in distribution, general and administrative expenses in fiscal year 2004
compared with $420,000 included in fiscal year 2003, a reduction of $561,000 in
operating expenses due to the sale of wholesale propane assets in fiscal year
2004, and cost savings of $376,000 related to a reduction in payroll and other
associated costs in fiscal year 2004. The reductions were partially offset by
proxy contest expenses of $570,000 incurred in fiscal year 2004, shareholder
rights plan expenses of $227,000 incurred in fiscal year 2004, an increase of
$337,000 in general liability insurance premiums in fiscal year 2004, and a
$175,000 increase in director expenses. (Additional debt issuance costs incurred
in fiscal year 2004 were amortized as interest expense. See table below.)
Maintenance and depreciation expenses decreased $77,000 for fiscal year
2004 as compared to fiscal year 2003.
Taxes other than taxes on income increased by $322,000 due to a Montana
DOR audit of assessed personal property values. The Company recovered
approximately $200,000 of this expense through higher rates in fiscal year 2004.
CERTAIN EXPENSES INCURRED DURING FISCAL YEARS 2002, 2003, AND 2004
The Company's consolidated results of operations were negatively affected
by certain costs and expenses that occurred during fiscal years 2002, 2003, and
2004. These expenses, summarized in the table below, include litigation expenses
in connection with the PPLM lawsuit during fiscal years 2002 and 2003, expenses
associated with the proxy contest during fiscal year 2004, and expenses
associated with the shareholder rights plan during fiscal year 2004.
In addition, the Company incurred significant expenses associated with
restructuring the Company's credit facilities during fiscal years 2003 and 2004.
These expenses are also summarized in the table. Although future expenses
associated with credit facilities and other capital-related expenses can be
expected in the normal course, the credit facility restructuring expenses
incurred during fiscal years 2003 and 2004 were substantially higher than
similar expenses incurred in previous periods. No assurance can be given with
respect to future levels of expenses related to capital needs.
28
2004 2003 2002 TOTAL
---- ---- ---- -----
Cost of PPLM litigation $1,552,000 $565,000 $2,117,000
Proxy Contest Expenses $ 570,000 570,000
Debt Issuance Expenses 663,000 420,000 * 1,083,000
Shareholder Rights Plan 227,000 227,000
---------- ---------- -------- ----------
Total $1,460,000 $1,972,000 $565,000 $3,997,000
========== ========== ======== ==========
*In fiscal year 2004, $696,000 of short-term debt issuance costs were
capitalized. Beginning October 31, 2003 these costs started amortizing at
$58,000 per month. At June 30, 2004, $522,000 of amortization had been included
as interest expense. In addition, $41,000 was included as interest expense at
June 30, 2004 for amortization of costs totaling $830,000 associated with
obtaining long-term debt. In fiscal year 2004, $100,000 related to obtaining
short-term financing was recorded in general and administrative expenses
compared to $420,000 in fiscal year 2003.
OTHER INCOME
Other income increased by $83,000 from $302,000 in fiscal year 2003 to
$385,000 in fiscal year 2004 primarily due to sale of non-operating real estate
assets located in Montana.
INTEREST EXPENSE
Interest expense increased by $866,000 or 53% from $1,633,000 in fiscal
year 2003 to $2,499,000 in fiscal year 2004 due to higher overall corporate
borrowings and amortization of $563,000 in costs associated with debt refinanced
in fiscal year 2004.
INCOME TAX BENEFITS
Income tax benefits decreased by $174,000 from a tax benefit of $543,000
in fiscal year 2003 to a tax benefit of $369,000 in fiscal year 2004 due to
decreased net loss.
FISCAL YEAR ENDED JUNE 30, 2003 (AS RESTATED) COMPARED TO FISCAL YEAR ENDED JUNE
30, 2002 (AS RESTATED).
NET INCOME (LOSS)
The Company's net loss for fiscal year 2003 was $857,000 compared to net
income of $827,000 in fiscal year 2002, a decrease of $1,684,000. The reduction
in net income is primarily a result of the following: Natural Gas Operations
reduction of $755,000 in net income due to reduced volumes and additional
operating expenses related to overhead and interest costs, and Propane
Operations had reduced net income of approximately $465,000 due to lower margins
resulting from higher costs of propane and additional overhead expense. The
Company's EWR segment experienced an increase in net loss of $324,000 due
primarily to additional legal fees of $987,000 related to the PPLM litigation,
and Pipeline Operations had reduced net income of $140,000 primarily due to
expenses incurred to obtain Federal Energy Regulatory Commission ("FERC")
regulatory approval of the Shoshone pipeline.
REVENUES
Operating revenues of the Company decreased $11,342,000 from $89,240,000
in fiscal year 2002 to $77,898,000 in fiscal year 2003. The Natural Gas
Operations' revenues decreased
29
$7,888,000 due to elimination of the surcharge approved by the MPSC in March
2001 for the recovery of increased gas costs that had been incurred prior to
March 2001. The increased gas costs were fully recovered by June 2002, and the
surcharge was eliminated. Also, warmer than normal weather experienced during
fiscal year 2003 resulted in lower volumes. EWR experienced lower revenues of
$5,880,000 due to decreased marketing activity and a $3,892,000 decrease in
revenue under mark-to-market accounting. Propane Operations experienced
$2,130,000 higher revenues due to both higher prices and sales volumes and the
Pipeline Operations experienced an increase in revenues of approximately
$295,000.
GROSS MARGIN
Gross margins (operating revenues less cost of gas and electricity and
cost of goods sold) increased $727,000 in fiscal year 2003. This increase was
attributable mainly to increased gross margins in the Company's EWR segment of
$1,120,000 offset by the $3,892,000 adjustment under mark-to-market accounting
and gross margin decreases in both the Propane Operations and Natural Gas
Operations resulting from higher than normal propane and gas costs.
EXPENSES OTHER THAN COSTS OF GAS AND ELECTRICITY AND COSTS OF GOODS SOLD
Expenses other than costs of gas and electricity and costs of goods sold
increased by $3,185,000 from fiscal year 2002 to fiscal year 2003.
Distribution, general and administrative expenses increased from
$8,790,000 in fiscal year 2002 to $11,669,000 in fiscal year 2003. This increase
of $2,879,000 was due in part to costs and expenses of the PPLM litigation of
$1,552,000 in fiscal year 2003 compared with $565,000 in fiscal year 2002.
Additional increases in these expenses included: $700,000 related to payroll and
employee benefit costs, $140,000 in general liability insurance expenses,
$462,000 in outside professional services, $80,000 in bad debt expense, $90,000
in director and shareholder expenses, and $420,000 related to restructuring the
Company's credit facilities.
Maintenance and depreciation increased $31,000 and $333,000,
respectively, with a decrease of $58,000 in taxes other than income.
OTHER INCOME
Other income decreased by $356,000 from $658,000 in fiscal year 2002 to
$302,000 in fiscal year 2003 primarily due to a $300,000 settlement received by
EWR in fiscal year 2002 as part of a transaction to purchase a group of
producing natural gas reserves.
INTEREST EXPENSE
Interest expense decreased by $71,000 from $1,704,000 in fiscal year 2002
to $1,633,000 in fiscal year 2003 due to lower overall corporate borrowings in
fiscal year 2003.
INCOME TAX BENEFIT (EXPENSE)
Income taxes benefits increased by $1,058,000 from a $515,000 tax expense
in fiscal year 2002 to a $543,000 tax benefit in fiscal year 2003 due to a loss
in fiscal 2003.
30
OPERATING RESULTS OF THE COMPANY'S NATURAL GAS OPERATIONS
Year Ended June 30
------------------
2004 2003 2002
---- ---- ----
(in thousands)
NATURAL GAS OPERATIONS
Operating revenues $ 39,063 $ 31,627 $ 39,515
Gas purchased 27,883 21,754 29,465
--------- -------- --------
Gross margin 11,180 9,873 10,050
Operating expenses 9,843 8,542 7,497
--------- -------- --------
Operating income 1,337 1,331 2,553
Other (income) (97) (94) (153)
--------- -------- --------
Income before interest and taxes $ 1,434 $ 1,425 $ 2,706
========= ======== ========
FISCAL YEAR ENDED JUNE 30, 2004 COMPARED TO FISCAL YEAR ENDED JUNE 30, 2003
NATURAL GAS REVENUES AND GROSS MARGINS
The Natural Gas Operations' operating revenues in fiscal year 2004
increased to $39,063,000 from $31,627,000 in fiscal year 2003. This was
primarily due to surcharges related to higher gas costs and increased rates
related to property tax recovery in Montana and higher rates from approved rate
cases in Montana and Wyoming.
Gross margin, which is defined as operating revenues less gas purchased,
was approximately $11,180,000 for fiscal year 2004 compared to approximately
$9,873,000 in fiscal year 2003. The increase of $1,307,000 is primarily due to
general rate increases placed in effect on December 15, 2002 of $600,000 and
June 1, 2003 for an additional $80,000 in Montana and $722,000 on June 1, 2003
in Wyoming. On January 1, 2004 an additional rate increase of approximately
$500,000 per year went into effect to recover property taxes in Montana.
Gas purchases in Natural Gas Operations increased by $6,129,000 from
$21,754,000 in fiscal year 2003 to $27,883,000 in fiscal year 2004. The increase
in gas costs reflect higher gas prices during the fiscal year.
NATURAL GAS OPERATING EXPENSES
Natural Gas Operations' operating expenses were approximately $9,843,000
for fiscal year 2004, as compared to $8,542,000 for fiscal year 2003. The
increase of $1,301,000 is due mainly to $672,000 increase in overhead costs,
$274,000 in personal property tax, $100,000 in bad debt expense, and $184,000 in
insurance expenses and $52,000 in depreciation expense.
31
NATURAL GAS OTHER INCOME
Other income increased by $3,000 from $94,000 in fiscal year 2003 to
$97,000 in fiscal year 2004. The increase was due primarily to miscellaneous
fixed assets sales during fiscal year 2004.
FISCAL YEAR ENDED JUNE 30, 2003 COMPARED TO FISCAL YEAR ENDED JUNE 30, 2002
NATURAL GAS REVENUES AND GROSS MARGINS
Natural Gas Operations' operating revenues decreased from approximately
$39,515,000 in fiscal year 2002 to approximately $31,627,000 in fiscal year
2003. This decrease of $7,888,000 was due primarily to the elimination of the
surcharge approved by the MPSC in March 2001 for the recovery of increased gas
costs that had been incurred prior to March 2001. The increased gas costs were
fully recovered by June 2002, and the surcharge was eliminated. Also, warmer
than normal weather experienced during fiscal year 2003 and reduced volumes sold
to a large industrial customer by Natural Gas - Wyoming resulted in lower total
volumes of natural gas sold of approximately 369,000 MCF, a 6% reduction from
fiscal year 2002.
Gross margin, defined as operating revenues less cost of natural gas,
declined from approximately $10,050,000 in fiscal year 2002 to approximately
$9,873,000 in fiscal year 2003, primarily due to the reduction in sales volumes
experienced during fiscal year 2003.
Natural gas purchases decreased from $29,465,000 in fiscal year 2002 to
$21,754,000 in fiscal year 2003. The decrease in gas costs of $7,711,000 is due
to lower volumes being sold and the lower cost of natural gas during fiscal year
2003.
NATURAL GAS OPERATING EXPENSES
Natural Gas Operations' operating expenses were $8,542,000 for fiscal year
2003 compared to $7,497,000 for fiscal year 2002. The increase in operating
expenses of $1,045,000 was due primarily to an increase in property taxes, an
increase in general liability insurance premiums, increases in employee benefit
costs and increases in overhead costs.
NATURAL GAS OTHER INCOME
Other income decreased by $59,000 from $153,000 in fiscal year 2002 to
$94,000 in fiscal year 2003. The decrease was primarily due to a reduction in
service sales related to home and industrial installations.
32
OPERATING RESULTS OF THE COMPANY'S PROPANE OPERATIONS
Year Ended June 30
------------------
2004 2003 2002
---- ---- ----
(in thousands)
PROPANE OPERATIONS
Operating revenues $ 7,736 $ 12,786 $ 10,656
Gas purchased 4,000 8,762 6,407
-------- --------- ---------
Gross margin 3,736 4,024 4,249
Operating expenses 3,039 3,600 3,065
-------- --------- ---------
Operating income 697 424 1,184
Other (income) (181) (187) (199)
-------- --------- ---------
Income before interest and taxes $ 878 $ 611 $ 1,383
======== ========= =========
FISCAL YEAR ENDED JUNE 30, 2004 COMPARED TO FISCAL YEAR ENDED JUNE 30, 2003
PROPANE REVENUE AND GROSS MARGINS
Propane Operations' revenues decreased $5,050,000 from $12,786,000 in
fiscal year 2003 to $7,736,000 in fiscal year 2004 as a result of the sale of
the wholesale propane assets located at Superior, Montana. Cost of propane sold
decreased from $8,762,000 to $4,000,000 for the same period due to the decrease
in volumes sold by the Company's wholesale operations, partially offset by
increases in the cost of propane for both the regulated utility and the
wholesale propane operations. These decreases in revenues and corresponding
decrease in cost of propane resulted in a $288,000 decrease in gross margin,
from $4,024,000 in fiscal year 2003 to $3,736,000 in fiscal year 2004.
Crude oil prices play a significant role in wholesale pricing for propane.
Wholesale propane prices move up as the cost of crude oil increases and play a
significant role in the Company's ability to stay competitive. While propane
normally enjoys a significant cost performance advantage over electricity, crude
oil price increases over the past year have eroded that advantage. Designers and
home builders are beginning to view propane and electricity as equal in cost
performance. Because electric generation uses crude oil as well as natural gas,
in time the Company expects electric rates to increase due to fuel price
increases. However, currently in the Company's markets, electric rates have not
been significantly impacted by the crude oil price increases.
PROPANE OPERATING EXPENSES
Operating expenses were $3,039,000 for fiscal year 2004 compared to
$3,600,000 for fiscal year 2003. This decrease of $561,000 is related to the
gain on the sale of wholesale propane assets of $252,000, decreases in operating
costs of $474,000, which includes savings from exiting the wholesale propane
market in Superior, Montana, and a decrease in depreciation and maintenance
expense of $76,000. Offsetting these expense reductions was an increase in
overhead costs (much of which the Company believes are nonrecurring) of
approximately $198,000 and an increase in taxes other than income of $43,000,
primarily related to increased property tax expense.
PROPANE OTHER INCOME
Other income decreased by $6,000 from $187,000 in fiscal year 2003 to
$181,000 in fiscal year 2004. Increases in interest income from the note
receivable from the buyer of the RMF
33
wholesale propane assets, and an increase in the revenue from contracted
services related to the sale, were offset by a decrease in other miscellaneous
income.
FISCAL YEAR ENDED JUNE 30, 2003 COMPARED TO FISCAL YEAR ENDED JUNE 30, 2002
PROPANE REVENUES AND GROSS MARGINS
The Propane Operations segment's revenues rose from $10,656,000 in fiscal
year 2002 to $12,786,000 in fiscal year 2003, an increase of $2,130,000 or 20%.
This increase in revenues was due to increased sales prices in the second half
of fiscal year 2003 in the Company's wholesale propane operations, coupled with
an overall increase in volume in the Propane Operations segment. Total volume
for the Propane Operations segment increased from 12,816,000 gallons in fiscal
year 2002 to 16,033,000 gallons in fiscal year 2003, an increase of 25%. Cost of
propane increased from $6,407,000 to $8,762,000 for the same period, a 37%
increase, due to the increase in volumes sold and increases in the cost of
propane for both the regulated utility and the wholesale propane operations. The
increase in revenues and the increase in cost of propane resulted in a decrease
of $225,000 in gross margin, or 5%, from $4,249,000 in fiscal year 2002 to
$4,024,000 in fiscal year 2003.
PROPANE OPERATING EXPENSES
Operating expenses were $3,600,000 for fiscal year 2003 compared to
$3,065,000 for fiscal year 2002. The increase of $535,000 was primarily related
to increases in depreciation, overhead costs, and increased sales expenses in
the wholesale propane operation.
PROPANE OTHER INCOME
Other income decreased by $12,000 from $199,000 in fiscal year 2002 to
$187,000 in fiscal year 2003. This decrease was due primarily to the collection
of a previously written off account in fiscal year 2002.
34
OPERATING RESULTS OF THE COMPANY'S EWR OPERATIONS
Years Ended June 30
2004 2003 2002
---- ---- ----
(in thousands)
ENERGY WEST RESOURCES ("EWR")
Operating revenues $ 26,091 $ 33,035 $ 38,914
Gas purchased 26,028 31,717 38,717
---------- ----------- ----------
Gross margin 63 1,318 197
Operating expenses 1,096 3,040 1,628
---------- ----------- ----------
Operating loss (1,033) (1,722) (1,431)
Other (income) expense 13 (19) (304)
---------- ----------- ----------
(Loss) before interest and taxes ($ 1,046) ($ 1,703) ($ 1,127)
========== =========== ==========
Note: Revenues are declining over the last three years due to decreased
sales market and impact of net derivative values.
FISCAL YEAR ENDED JUNE 30, 2004 COMPARED TO FISCAL YEAR ENDED JUNE 30, 2003 (AS
RESTATED)
EWR REVENUES AND GROSS MARGINS
Revenues were negatively impacted by declines in derivative values of
$1,244,000 at the end of fiscal year 2004 from the end of fiscal year 2003,
under mark-to-market accounting. Fiscal year 2003 included revenues of $245,000
from electricity marketing and $27,000, from appliance sales which decreased in
fiscal year 2004 as the Company elected to not sell any new electricity
contracts or gas appliances. EWR's fiscal year 2004 gross margin of $63,000
represents a decrease of $1,255,000 from gross margins earned in fiscal 2003.
This decrease was due primarily to $2,091,000 more in fiscal year 2004 to
purchase natural gas to satisfy fixed price contract agreements. The decrease in
natural gas margins was partially offset by an increase in production margins of
$175,000.
EWR OPERATING EXPENSES
Operating expenses of EWR decreased approximately $1,944,000, from
$3,040,000 for fiscal year 2003 to $1,096,000 for fiscal year 2004. This
decrease is due primarily to the decreased legal expenses related to the
settlement of the PPLM litigation in fiscal 2003. Legal expenses related to the
PPLM litigation in 2003 were approximately $1,552,000. The remainder of the
decrease is due to a reduction in general and administrative expenses related to
payroll and associated costs, travel and training and other cost savings
measures.
EWR OTHER INCOME (EXPENSE)
Other expense was approximately $13,000 in fiscal year 2004 compared to
other income of approximately $19,000 for fiscal year 2003. The reduction is
primarily due to EWR devaluing an investment in a distributorship for $17,000.
The decrease was partially offset by the gain on the sale of two vehicles and a
gathering system compressor.
35
FISCAL YEAR ENDED JUNE 30, 2003 (AS RESTATED) COMPARED TO FISCAL YEAR ENDED JUNE
30, 2002 (AS RESTATED)
EWR REVENUES AND GROSS MARGINS
Revenues were negatively impacted by declines in derivative values of
$2,177,000 at the end of fiscal year 2003 from the end of fiscal year 2002,
under mark-to-market accounting. EWR's gross margin was approximately $1,318,000
for fiscal year 2003 compared to $197,000 for fiscal year 2002, an increase of
$1,121,000. This increase was primarily due to a $1,509,000 increase in natural
gas margins (primarily from the sale of storage inventories during the third
quarter) and an increase in margins of $338,000 from production properties
purchased in fiscal year 2002, offset by a decline of approximately $411,000 in
gross margins from the sale of electricity.
EWR OPERATING EXPENSES
Operating expenses for EWR were approximately $3,040,000 for fiscal year
2003 compared to $1,628,000 for the previous fiscal year. The most significant
factor causing the increase of $1,412,000 was legal expenses related to the PPLM
litigation. The costs of the PPLM litigation were approximately $1,552,000 for
fiscal year 2003 compared to approximately $535,000 for fiscal year 2002. The
remainder of the increase in operating expenses of $395,000 was due primarily to
increases in liability insurance, employee benefits, increased uncollectible
expenses and an increase in the amount of allocated corporate overhead.
EWR OTHER INCOME
Other income was approximately $19,000 in fiscal year 2003 compared to
approximately $304,000 for fiscal year 2002. The reduction is primarily due to a
$300,000 settlement on the purchase of production properties during fiscal year
2002 that was not repeated during fiscal year 2003.
OPERATING RESULTS OF THE COMPANY'S PIPELINE OPERATIONS
Years Ended June 30
2004 2003 2002
---- ---- ----
(in thousands)
PIPELINE OPERATIONS
Operating revenues $ 401 $ 449 $ 154
Gas purchased 0 287 0
------- -------- ------
Gross margin 401 162 154
Operating expenses 214 265 71
------- -------- ------
Operating income (loss) 187 (103) 83
Other (income) expense (121) (1) 0
------- -------- ------
Income (loss) before interest and taxes $ 308 ($ 102) $ 83
======= ======== ======
36
FISCAL YEAR ENDED JUNE 30, 2004 COMPARED TO FISCAL YEAR ENDED JUNE 30, 2003
PIPELINE REVENUES AND GROSS MARGINS
Pipeline Operations added the Shoshone pipelines as of July 2003, which
produced revenue of $337,000 in fiscal year 2004. For fiscal year 2004
reporting, Pipeline Operations revenue consists only of gathering revenues
related to the pipelines located in Wyoming and Montana. Revenues and expenses
associated with the interests in natural gas production acquired in fiscal years
2002 and 2003 have been transferred to EWR.
Pipeline Operations' margin increased from $162,000 in fiscal year 2003
to $401,000 in fiscal year 2004. The increase of $239,000 was due primarily to
the addition of $337,000 in revenues from the addition of the Shoshone pipeline
in July 2003. This increase was partially offset by a reduction in margins of
$98,000 due to the transfer of operation of natural gas production interests to
EWR effective as of fiscal year 2004.
PIPELINE OPERATING EXPENSES
Operating expenses decreased from $265,000 in fiscal year 2003 to $214,000
in fiscal year 2004. The decrease of $51,000 was due to a reduction in payroll
and related expenses.
PIPELINE OTHER INCOME
Other income for fiscal year 2004 included the sale of certain
non-operating real estate assets located in Montana, which resulted in a gain of
$121,000.
FISCAL YEAR ENDED JUNE 30, 2003 COMPARED TO FISCAL YEAR ENDED JUNE 30, 2002
PIPELINE REVENUES AND GROSS MARGINS
Pipeline Operations' revenues increased from $154,000 in fiscal year 2002
to approximately $449,000 in fiscal year 2003. The increase of $295,000 was due
primarily to revenues generated from natural gas production properties purchased
in fiscal year 2003. The cost of gas purchased increased $287,000 from fiscal
year 2003 compared to fiscal year 2002 due to the increased cost of production.
PIPELINE OPERATING EXPENSES
Operating expenses increased from $71,000 in fiscal year 2002 to $265,000
in fiscal year 2003. The increase of $194,000 was due to additional expenses
associated with production properties and additional expenses incurred in
obtaining FERC regulatory approval to operate the Shoshone pipeline.
CONSOLIDATED CASH FLOW ANALYSIS
CASH FLOWS USED IN OPERATING ACTIVITIES
Cash flows used in operations in fiscal 2004 were unfavorable as a result
of the net loss incurred in fiscal 2004. The Company's fiscal 2004 operating
cash flows were driven by the following events and factors:
37
- Higher prices of natural gas and propane inventories.
- A significant pay down of trade accounts payable and other
liabilities.
The amount of debt has substantially increased resulting in higher
interest costs, which will continue to negatively impact operating cash flows.
The Company is currently required to retire debt through the use of proceeds
generated from the sale of equity securities under the terms of the LaSalle
Facility.
The Company is attempting to improve operating cash flows by improving the
efficiency of the core businesses, increasing revenues through utility rates,
retiring debt and restructuring existing debt obligations.
CASH FLOWS USED IN INVESTING ACTIVITIES
Cash flows used in investing activities decreased in fiscal 2004 compared
to fiscal 2003. This decrease mainly stemmed from reduced capital expenditures
in 2004, a result of a management decision to limit fiscal 2004 expenditures. In
addition, RMF propane assets were sold in August 2003.
Cash used in investing activities in fiscal 2003 decreased from fiscal
2002. This decrease primarily stemmed from a $1,445,000 reduction in capital
expenditures for system extensions as well as the replacement and improvement of
existing transmission, distribution, gathering and general facilities. In
addition, $957,000 was expended for the acquisition of producing natural gas
properties in May 2002.
CASH FLOWS FROM FINANCING ACTIVITIES
Cash flows from financing activities increased in fiscal 2004 compared to
fiscal 2003. Fiscal 2004 net cash provided from financing activities stems from
the $8,000,000 proceeds from additional long-term debt, net of $1,526,000 in
debt issuance costs.
Cash flows from financing activities increased in fiscal 2003 compared to
fiscal 2002. Net cash provided from financing activities in fiscal 2003 is the
net effect of lower repayments on lines of credit.
GOVERNMENTAL REGULATION
The Company's utility operations are subject to regulation by the MPSC,
the WPSC, and the ACC. Such regulation plays a significant role in determining
the Company's return on equity. The commissions approve rates that are intended
to permit a reasonable rate of return on investment. The Company's tariffs allow
the cost of gas to pass through to the customers. There is some delay, however,
between the time that the gas costs are incurred by the Company and the time
that the Company recovers such costs from customers as part of its gas cost
recovery mechanism. The interim rate increase became effective November 1, 2004
and is estimated to provide additional gross margin of approximately $800,000
annually. In addition, an interim order for the West
38
Yellowstone general rate filing was approved for approximately $200,000 annually
and became effective on November 1, 2004.
SEASONALITY
The business of the Company and its subsidiaries in all segments is
temperature-sensitive. In any given period, sales volumes reflect the impact of
weather, in addition to other factors, with colder temperatures generally
resulting in increased sales by the Company. The Company anticipates that this
sensitivity to seasonal and other weather conditions will continue to be
reflected in the Company's sales volumes in future periods.
LIQUIDITY AND CAPITAL RESOURCES
The Company's operating capital needs, as well as dividend payments and
capital expenditures, are generally funded through cash flow from operating
activities and short-term borrowing. Historically, to the extent cash flow has
not been sufficient to fund capital expenditures, the Company has borrowed
short-term funds. When the short-term debt balance significantly exceeds working
capital requirements, the Company has issued long-term debt or equity securities
to pay down short-term debt. The Company has greater need for short-term
borrowing during periods when internally generated funds are not sufficient to
cover all capital and operating requirements, including costs of gas purchased
and capital expenditures. In general, the Company's short-term borrowing needs
for purchases of gas inventory and capital expenditures are greatest during the
summer and fall months and the Company's short-term borrowing needs for
financing customer accounts receivable are greatest during the winter months.
The Company substantially restructured its credit facilities during fiscal
year 2004. On September 30, 2003, the Company established a $23.0 million
short-term revolving credit facility with LaSalle Bank National Association, as
Agent for certain banks (collectively, the "Lender"), replacing a previous
short-term line of credit. The MPSC order granting approval of the $23.0 million
credit facility imposes restrictions on the use of the proceeds to utility
purposes, and requires the Company to provide monthly reports to the MPSC with
respect to the financial condition of the Company. The Company continues to be
subject to these MPSC requirements.
On March 31, 2004, the Company entered into a restated credit agreement
with the Lender. Pursuant to the restated credit agreement, the previous $23.0
million revolving credit facility was replaced with a $15.0 million short-term
revolving credit facility, a $6.0 million term loan maturing on March 31, 2009,
and a $2.0 million term loan maturing on September 30, 2004 (collectively
referred to as the "LaSalle Facility").
As of August 30, 2004, the Company and its lender under its credit
facility (the "LaSalle Facility") amended certain covenants as follows: (1)
increased the total debt to capital ratio from .65 to .70, (2) allowed the
inclusion of extraordinary expenses incurred by the Company for legal fees and
costs of the PPLM litigation, expenses and costs associated with the credit
facilities, proxy contest costs, and the costs of adoption of the shareholder
rights plan, in determining the interest coverage ratio, and (3) waived
compliance with the ratios referred to in (1) and (2) above as of June
39
30, 2004 in addition to a shareholder's acquisition of more than 15% of the
outstanding common stock of the Company.
As of September 10, 2004, the LaSalle Facility was amended to extend from
September 30, 2004 until October 31, 2004, the deadline for the Company to repay
the $2,000,000 term loan under the LaSalle Facility, with an infusion of new
equity.
On October 20, 2004, but effective as of September 28, 2004, the LaSalle
Facility was amended to extend until October 29, 2004, the deadline for the
Company to deliver its audited financial statements for the fiscal year ended
June 30, 2004.
On November 2, 2004, the Company executed a letter agreement effective as
of September 28, 2004 amending the LaSalle Facility. The letter agreement
provides for the extension of the deadline to deliver audited financial
statements for fiscal year 2004 from October 29, 2004 to November 12, 2004.
As of November 2, 2004, the Company executed an amendment to the LaSalle
Facility, which provides for an extension from October 31, 2004 to November 30,
2004 of the deadlines under the LaSalle Facility in connection with: (i) the
termination date of the revolving facility and (ii) the date to consummate
infusions of new equity of at least $2.0 million to repay the $2.0 million term
loan under the LaSalle Facility.
As of November 30, 2004, the Company executed an agreement with its
lender providing for (i) an extension of the revolving facility until
November 28, 2005; (ii) an extension of the date to consummate infusions of new
equity of at least $2.0 million and to repay the $2.0 million term loan to
October 1, 2005; (iii) a conditional waiver of the deadline to deliver audited
financial statements for fiscal year 2004 and the deadline to deliver financial
statements for the fiscal quarter ended September 30, 2004; (iv) a waiver of
the technical default that otherwise would have been caused by the restatement
of financial results of prior periods; (v) modification of interest rates
applicable to the $2.0 million term loan; (vi) a limitation of $1.0 million on
total loans and additional capital investment from the Company to EWR; and
(vii) waivers of certain financial covenant default as of September 30, 2004.
Borrowings under the LaSalle Facility are secured by liens on
substantially all of the assets of the Company and its subsidiaries. The
Company's obligations under certain other notes and industrial development
revenue obligations are secured on an equal and ratable basis with the Lender in
the collateral granted to secure the borrowings under the LaSalle Facility with
the exception of the first $1.0 million of debt under the LaSalle Facility.
Under the LaSalle Facility the Company may elect to pay interest on
portions of the amounts outstanding under the $15.0 million revolving line of
credit at the London interbank offered rate (LIBOR), plus 250 basis points, for
interest periods selected by the Company. For all other balances outstanding
under the $15.0 million revolving line of credit, the Company pays interest at
the rate publicly announced from time to time by LaSalle Bank as its "prime
rate" (the "Prime Rate"). For the $6.0 million term loan under the LaSalle
Facility, the Company may elect to pay interest at either the applicable LIBOR
rate plus 350 basis points or at the Prime Rate plus 200 basis points. Pursuant
to the November 30, 2004 amendment to the LaSalle Facility, the interest rate on
the $2.0 million term loan will be: the Prime Rate plus 200 basis points through
March 31, 2005; the Prime Rate plus 300 basis points from April 1, 2005 through
June 30, 2005; and the Prime Rate plus 400 basis points from and after July 1,
2005. The Company also pays a commitment fee of 35 basis points for the daily
unutilized portion of the $15.0 million revolving credit facility.
The LaSalle Facility requires the Company to maintain compliance with a
number of financial covenants, including meeting limitations on annual capital
expenditures, maintaining a total debt to total capital ratio of not more than
..70 to 1.00 and an interest coverage ratio of no less than
40
2.00 to 1.00. At June 30, 2004, the Company would not have been in compliance
with the financial covenants under the LaSalle Facility had the Lender not
waived or modified certain financial covenants. The LaSalle Facility also
restricts the Company's ability to pay dividends during any period to a certain
percentage of cumulative earnings of the Company over that period, and restricts
open positions and Value at Risk (VaR) in the Company's wholesale operations.
In June 2003, the Company's Board of Directors suspended the Company's
fourth quarter dividend to allow for strengthening of the Company's balance
sheet. No determination has been made with respect to resumption of cash
dividend payments.
At June 30, 2004, the Company had approximately $1.3 million of cash on
hand. In addition, at June 30, 2004, the Company had borrowed approximately $6.7
million under the LaSalle Facility revolving line of credit. The Company's
short-term borrowings under its lines of credit during fiscal year 2004 had a
daily weighted average interest rate of 4.48% per annum. At June 30, 2004, the
Company had outstanding letters of credit totaling $1,700,000 related to
electricity and gas purchase contracts. These letters of credit are netted
against the Company's bank line of credit, which resulted in net availability at
June 30, 2004, of approximately $6.6 million under the LaSalle Facility
revolving line of credit. At December 1, 2004, the Company had borrowed
approximately $14.6 million under the LaSalle Facility revolving line of credit.
Accordingly, the Company had net availability at December 1, 2004, of
approximately $371,000 under the LaSalle Facility revolving line of credit. As
discussed above, the Company's short-term borrowing needs for purchases of gas
inventory and capital expenditures are greatest during the summer and fall
months. The Company's availability normally increases in January as monthly
heating bills are paid and gas purchases are no longer necessary.
In addition to the LaSalle Facility, the Company has outstanding certain
notes and industrial development revenue obligations (collectively "Long Term
Notes and Bonds"). The Company's Long Term Notes and Bonds are made up of three
separate debt issues: $8.0 million of Series 1997 notes bearing interest at an
annual rate of 7.5%; $7.8 million of Series 1993 notes bearing interest at
annual 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
bearing interest at annual rates ranging from 6.0% to 6.5%. The Company's
obligations under the Long Term Notes and Bonds are secured on an equal and
ratable basis with the Lender in the collateral granted to secure the LaSalle
Facility with the exception of the first $1.0 million of debt under the LaSalle
Facility.
Under the terms of the Long Term Notes and Bonds, the Company is subject
to certain restrictions, including restrictions on total dividends and
distributions, liens and secured indebtedness, and asset sales, and is
restricted from incurring additional long-term indebtedness if it does not meet
certain debt to interest and debt to capital ratios.
In the event that the Company's obligations under the LaSalle Facility
were declared immediately due and payable as a result of an event of default,
such acceleration also could result in events of default under the Company's
Series 1993 Notes and Series 1997 Notes. In such circumstances, an event of
default under either series of notes would occur if (a) the Company were given
notice to that effect either by the trustee under the indenture governing such
series of notes, or the holders of at least 25% in principal amount of the notes
of such series then outstanding, and (b) within 10 days after such notice from
the trustee or the note holders to the Company, the acceleration of the
Company's obligations under the LaSalle Facility has not been rescinded or
annulled and the obligations under the LaSalle Facility have not been
discharged. There is no similar cross-default provision with respect to the
Cascade County, Montana Series 1992B Industrial Development Revenue Bonds and
the related Loan Agreement between the Company and Cascade County, Montana. If
the Company's obligations were accelerated under the terms of any of the LaSalle
Facility, the Series 1993 Notes or the Series 1997 Notes, such acceleration
(unless rescinded or cured)
41
could result in a loss of liquidity and cause a material adverse effect on the
Company and its financial condition.
The total amount outstanding under all of the Company's long term debt
obligations was approximately $21.7 million and $15.4 million, at June 30, 2004
and June 30, 2003, respectively. The portion of such obligations due within one
year was approximately $973,000 and $530,000 at June 30, 2004, and June 30,
2003, respectively.
The Company would not have been in compliance with certain covenants under the
LaSalle Facility had the lender not waived or modified the covenants. The
Company is currently evaluating its options with respect to raising equity
capital to fund the repayment of the $2.0 million term loan, which matures on
October 1, 2005.
CONTRACTUAL OBLIGATIONS
A table of the Company's long-term debt obligations, as well as other
long-term commitments and contingencies, and the corresponding maturity dates
are listed below.
PAYMENTS DUE BY PERIOD
Less
Contractual than 2 - 3 4 - 5 After 5
Obligations Total 1 year Years Years Years
- ----------- ----------- ---------- ---------- ---------- -----------
Long-Term Debt $22,669,992 $ 972,706 $ 4,071,302 $ 1,615,000 $16,010,984
Operating Lease Obligations 473,046 142,599 233,223 97,224 --
Transportation and Storage Obligation 24,378,587 4,367,715 8,653,816 8,517,792 2,839,264
----------- ---------- ----------- ----------- -----------
Total Obligations $47,521,625 $5,483,020 $12,958,341 $10,230,016 $18,850,248
----------- ---------- ----------- ----------- -----------
42
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. In fiscal years 2004, 2003 and 2002, total
capital expenditures for the Company were approximately $2,317,000, $4,130,000
and $6,442,000, respectively, including purchases of natural gas production
properties. Expenditures for fiscal year 2002 were higher than usual due to the
renovation of a transmission pipeline between Wyoming and Montana and a by-pass
pipeline loop around Cody, Wyoming. Expenditures for fiscal year 2004 were
limited to essential needs only. Expenditures in fiscal year 2005 are expected
to be limited to essential needs only.
The Company estimates future cash requirements for capital expenditures
will be as follows:
ESTIMATED
FUTURE CASH
ACTUAL REQUIREMENTS
------ ------------
(in thousands) 2004 2005
Natural Gas Operations $1,632 $1,041
Propane Operations 515 836
Energy West Resources 75 200
Pipeline Operations 95 0
------ ------
Total capital expenditures $2,317 $2,077
====== ======
NEW ACCOUNTING PRONOUNCEMENTS
In April 2003, the Financial Accounting Standards Board ("FASB") issued
SFAS No. 149, Amendments of Statement 133 on Derivative Instruments and Hedging
Activities. SFAS No. 149 amends and clarifies accounting for derivative
instruments, including certain derivative instruments embedded in other
contracts, and hedging activities. The Statement is effective for contracts
entered into or modified after June 30, 2003 and for hedging relationships
designated after June 30, 2003. Management adopted this standard on July 1, 2003
and determined that there is no current impact from SFAS No. 149 on the
consolidated financial statements.
In May 2003, the FASB issued SFAS No. 150, Accounting for Certain
Financial Instruments with Characteristics of both Liabilities and Equity, which
provides standards for how an issuer classifies and measures certain financial
instruments with characteristics of both liabilities and equity. The Statement
is effective for financial instruments entered into or modified after May 31,
2003 and for pre-existing instruments as of the beginning of the first interim
period beginning after June 15, 2003. Management has determined that there is no
current impact from SFAS No. 150 on the consolidated financial statements.
RISK FACTORS
The major factors which will affect the Company's future results include
general and regional economic conditions, weather, customer retention and
growth, the ability to meet competitive pressures and to contain costs, the
adequacy and timeliness of rate relief, cost recovery and necessary regulatory
approvals, and continued access to capital markets. In addition, changes in the
competitive environment particularly related to the Company's propane and energy
marketing segments could have a significant impact on the performance of the
Company.
The regulatory structure in which the Company operates is in transition.
Legislative and regulatory initiatives, at both the federal and state levels,
are designed to promote competition. The changes in the gas industry have
allowed certain customers to negotiate gas purchases directly with producers or
brokers. To date, open access in the gas industry has not had a negative impact
on earnings or cash flow of the Company's regulated segment. The Company's
regulated natural gas and propane vapor operations follow Statement of
Accounting Standards (SFAS) No. 71 "Accounting for the Effects of Certain Types
of Regulation," and 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
43
period in which the costs would be charged to expense by an unregulated
enterprise. When this occurs, costs are deferred as assets in the balance sheet
(regulatory assets) and recorded as expenses in the periods when those same
amounts are reflected in rates. Additionally, regulators can impose liabilities
upon a regulated company for amounts previously collected from customers and for
amounts that are expected to be refunded to customers (regulatory liabilities).
If the Company's natural gas and propane vapor operations were to discontinue
the application of SFAS No. 71, the accounting impact would be an extraordinary,
non-cash charge to operations that could be material to the financial position
and results of operation of the Company. However, the Company is unaware of any
circumstances or events in the foreseeable future that would cause it to
discontinue the application of SFAS No. 71.
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 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
such default has occurred.
Among the risks involved in natural gas marketing is the risk of
nonperformance by counterparties to contracts for purchase and sale of natural
gas. EWR is party to certain contracts for purchase or sale of natural gas at
fixed prices for fixed time periods. Some of these contracts are recorded as
derivatives, valued on a mark-to-market basis. At June 30, 2004, the net fair
value of the contracts was a derivative liability of approximately $1,485,000.
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, and the resolution of other
regulatory matters;
- - The ability of the Company and its subsidiaries to obtain governmental and
regulatory approval of various expansion or other projects;
- - The costs and effects of legal and administrative claims and proceedings
against the Company or its subsidiaries;
- - Conditions of the capital markets the Company utilizes to access capital to
finance operations;
- - The ability to raise capital in a cost-effective way;
- - The ability to meet the financial covenants imposed by lenders to be able to
draw down on revolving lines of credit;
44
- - The effect of changes in accounting policies, if any;
- - The ability to manage growth of the Company;
- - The ability to control costs;
- - The ability of each business unit to successfully implement key systems, such
as service delivery systems;
- - The ability of the Company and its subsidiaries to develop expanded markets
and product offerings as well as their ability to maintain existing markets;
- - The ability of customers of the energy marketing and trading business to
obtain financing for various projects;
- - The ability of customers of the energy marketing and trading business to
obtain governmental and regulatory approval of various projects;
- - Future utilization of pipeline capacity, which can depend on energy prices,
competition from alternative fuels, the general level of natural gas and propane
demand, decisions by customers not to renew expiring natural gas or propane
contracts, and weather conditions; and
- - Global and domestic economic repercussions from terrorist activities and the
government's response thereto.
INFLATION
Capital-intensive businesses, such as the Company's natural gas and
propane vapor operations, are significantly affected by long-term inflation.
Neither depreciation charges against earnings nor the ratemaking process reflect
the replacement cost of utility plant. However, based on past practices of
regulators, these businesses will be allowed to recover and earn on the actual
cost of their investment in the replacement or upgrade of plant. Although prices
for natural gas and propane vapor may fluctuate, earnings are not impacted
because gas and propane vapor cost tracking procedures annually, and more often
with approval of the various Public Service Commissions, balance gas and propane
vapor costs collected from customers with the costs of supplying natural gas and
propane vapor. The Company believes that the effects of inflation, at currently
anticipated levels, will not materially affect results of operations.
ENVIRONMENTAL MATTERS
The Company owns property on which it operated a manufactured gas plant
from 1909 to 1928. The site is currently used as an office facility for Company
field personnel and storage location for certain equipment and materials. The
coal gasification process utilized in the plant resulted in the production of
certain by-products, which have been classified by the federal government and
the State of Montana as hazardous to the environment.
The Company has completed its remediation of soil contaminants at the
plant site and in April of 2002 received a closure letter from Montana
Department of Environmental Quality ("MDEQ") approving the completion of such
remediation program.
The Company and its consultants continue to work with the MDEQ relating to
the remediation plan for water contaminants. The MDEQ has established
regulations that allow water contaminants at a site to exceed standards if it is
technically impracticable to achieve those standards. Although the MDEQ has not
established guidance respecting the attainment of a technical waiver, the U.S.
Environmental Protection Agency ("EPA") has developed such guidance.
45
The EPA guidance lists factors which render mediations technically
impracticable. The Company has filed a request for a waiver respecting
compliance with certain standards with the MDEQ.
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. At June 30, 2004, the Company had
incurred cumulative costs of approximately $1,925,000 in connection with its
evaluation and remediation of the site. As of June 30, 2004, the Company had
recovered approximately $1,440,000 through such surcharges.
On April 15, 2003, the MPSC issued an Order to Show Cause Regarding the
Environmental Surcharge. The MPSC determined that the initial order allowing the
collection of the surcharge was intended by the MPSC to cover only a two year
collection period, after which it contemplated additional filings by the
Company, if necessary. The Company responded to the Show Cause Order and the
MPSC subsequently ordered the termination of the Environmental Surcharge on
August 20, 2003. The Company filed a request with the commission to continue the
collection of the surcharge until all expenses have been recovered. This request
was approved by the MPSC and the surcharge was reinstated in September 2004. The
Company is required to file with the MPSC every two years for approval to
continue the recovery of the surcharge.
DERIVATIVES AND RISK MANAGEMENT
Management of Risks Related to Derivatives -- The Company and its
subsidiaries are subject to certain risks related to changes in certain
commodity prices and risks of counterparty performance. The Company has
established policies and procedures to manage such risks. The Company has a Risk
Management Committee (RMC), comprised of Company officers and management to
oversee the Company's risk management program as defined in its risk management
policy. The purpose of the risk management program is to minimize adverse
impacts on earnings resulting from volatility of energy prices, counterparty
credit risks, and other risks related to the energy commodity business.
In order to mitigate the risk of natural gas market price volatility
related to firm commitments to purchase or sell natural gas or electricity, from
time to time the Company and its subsidiaries have entered into hedging
arrangements. Such arrangements may be used to protect profit margins on future
obligations to deliver gas at a fixed price, or to protect against adverse
effects of potential market price declines on future obligations to purchase gas
at fixed prices.
The Company accounts for certain of such purchases or sale agreements in
accordance with SFAS No. 133. Under SFAS 133, such contracts are reflected in
the Company's financial statements as derivative assets or derivative
liabilities and valued at "fair value," determined as of the date of the balance
sheet. Fair value accounting treatment is also referred to as "mark-to-market"
accounting. Mark-to-market accounting results in disparities between reported
earnings and realized cash flow, because changes in the derivative values are
reported in the Company's Consolidated Statement of Operations as an increase or
(decrease) in "Revenues - Gas and Electric - Wholesale" without regard to
whether any cash payments 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. SFAS No. 133 requires that
contracts for purchase or sale at fixed
46
prices and volumes must be valued at fair value (under mark-to-market
accounting) unless the contracts qualify for treatment as a "normal purchase or
sale."
Quoted market prices for natural gas derivative contracts of the Company
and its subsidiaries are generally not available. Therefore, to determine the
fair value of natural gas derivative contracts, the Company uses internally
developed valuation models that incorporate independently available current and
forecasted pricing information.
As of June 30, 2004, these agreements were reflected on the Company's
consolidated balance sheet as derivative assets and liabilities at an
approximate fair value as follows:
ASSETS LIABILITIES
Contracts maturing during fiscal year 2005 $ 199,248 $ 733,822
Contracts maturing during fiscal years 2006 and 2007 - 606,862
Contracts maturing during fiscal years 2008 and 2009 - 343,992
------------- -------------
Total $ 199,248 $ 1,684,676
============= =============
Regulated Operations -- In the case of the Company's regulated divisions,
gains or losses resulting from derivative contracts are subject to deferral
under regulatory procedures approved by the public service regulatory
commissions of the States of Montana and Wyoming. 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, Accounting for the Effects of Certain Types of Regulation.
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 include, but are not limited to risks associated with contracts
accounted for as derivatives, statements regarding competition, weather
conditions, changes in the utility regulatory environment, the effects of the
PPLM settlement and the DOR settlement, the outcome of regulatory proceedings,
capital expenditure needs, the Company's liquidity position, the effects of
inflation, the ability of the Company to meet the financial covenants under the
LaSalle Facility, and the availability of financing on acceptable terms.
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.
47
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 include, but are not limited to the risk factors set forth under the
heading "Risk Factors."
Any such forward-looking statement is qualified by reference to these risk
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 is subject to certain market risks, including commodity price
risk (i.e., natural gas 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 seeks to protect itself against natural gas price
fluctuations by limiting the aggregate level of net open positions that are
exposed to market price changes. Open positions are to be managed with policies
designed to limit the exposure to market risk, with regular reporting to
management of potential financial exposure. The Company's risk management
committee has limited the types of contracts the Company will consider to those
related to physical natural gas deliveries. Therefore, management believes that
the Company's results of operations are not significantly exposed to changes in
natural gas prices.
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, however, are subject to variable interest rates. A
hypothetical 100 basis point change in market rates applied to the balance of
the notes payable would change interest expense by $150,000 annually.
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
48
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 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 such default has occurred.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The Consolidated Financial Statements of the Company are filed under this
Item, beginning on page F-1 of this Annual Report on Form 10-K.
Selected quarterly financial data required under this Item is included in
Note 16 to the Company's Consolidated Financial Statements.
ITEM 9. - CHANGES AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL
DISCLOSURE
None.
ITEM 9 (A) - CONTROLS AND PROCEDURES
Company's management has evaluated, with the participation of the Chief
Executive Officer and the Principal Financial Officer, the effectiveness of the
disclosure controls and procedures as of the end of the period covered by this
Annual Report on Form 10-K. Based on this evaluation, although the Company had a
deficiency that gave rise to a restatement of the consolidated financial
statements (see Note 15 of the Consolidated financial statements); the Chief
Executive Officer and the Principal Financial Officer have concluded that the
disclosure controls and procedures that are now in place at the Company are
effective to ensure that information we are required to disclose in reports that
we file or submit under the Securities Exchange Act of 1934 is recorded,
processed, summarized and reported within the time periods specified in
Securities and Exchange Commission rules and forms.
The Company corrected its accounting with regard to certain natural gas
agreements following a review which identified accounting treatment issues with
the agreements. The Company's independent auditors have advised the Company that
they have identified a material weakness in the Company's internal control over
financial reporting in connection with energy contracts. During fiscal year 2004
and the first part of fiscal year 2005, the Company has implemented changes in
the internal control over financial reporting to address the material weakness.
Those changes involved implementation of procedures respecting the contracting
for gas under natural gas purchase and sale agreements, including establishing a
separation between the deal-making function and the accounting and contract
administration functions, establishment of record systems and procedures that
require reconciliation of actual performance by the contracting parties against
the prices, quantities and other material terms specified in the agreements, and
redundant documentation for every agreement regarding its classification
pursuant to SFAS 133. The procedures are designed to make sure that all material
obligations entered into on behalf of the Company or its subsidiaries receive
proper review and that those agreements are enforced and performed according to
their terms and conditions. The procedures are also designed to make sure that
the Company complies with applicable accounting requirements.
49
PART III
ITEM 10. - DIRECTORS AND EXECUTIVE OFFICER OF THE REGISTRANT
The information set forth in response to Item 401 of Regulation S-K under
the heading "Executive Officers" located in Item 1, Part I of this Form 10-K is
incorporated herein by reference in partial response to this Item 10.
DIRECTORS OF THE COMPANY
W. E. `GENE' ARGO, (62), has been a Director of the Company since 2002. He
recently retired as the President and General Manager of Midwest Energy, Inc., a
gas and electric cooperative in Hays, Kansas, in which capacity he had served
since 1992. Mr. Argo serves as the Chairman of the Company's Compensation
Committee.
DAVID A. CEROTZKE, (54), has been a Director of the Company since December 2003.
He was appointed President and Chief Executive Officer of the Company on July 1,
2004. Prior to joining the Company he was a consultant in the energy industry
from January 2003 to December 2003. From 1990 to 2003, he served in various
executive capacities, including Vice-President of Engineering, Vice-President of
Operations, Vice-President of Marketing and Treasurer of Nicor Inc., a
diversified energy holding company.
ANDREW I. DAVIDSON, (36), has been a Director of the Company since 1999. He has
been Senior Vice President and Director of Client Service and Marketing for
Davidson Investment Advisors and a Financial Consultant for D.A. Davidson &
Company since 1993.
DAVID A. FLITNER, (71), has been a Director of the Company since 1988. He has
been the owner of the Flitner Ranch and Hideout Adventures, Inc., a recreational
enterprise, since 1994. Mr. Flitner serves as the Chairman of the Company's
Management and Business Development Committee.
G. MONTGOMERY MITCHELL, (76), has been a Director of the Company since 1984 and
has served as the Chairman of the Board since 2001. Mr. Mitchell was Senior Vice
President and Director of Stone and Webster Management Consultants, Inc. from
August 1980 until his retirement in 1993. Mr. Mitchell is also a director of
Energy South, Inc.
RICHARD M. OSBORNE, (59), has been a Director of the Company since December
2003. He is the President and Chief Executive Officer of OsAir, Inc., a company
he founded in 1963, which operates as a property developer and manufacturer of
industrial gases for pipeline delivery. Since September 1998, Mr. Osborne has
also been Chairman of the Board and Chief Executive Officer of Liberty
Self-Stor, Inc., a self-managed real estate investment trust that manages,
acquires, develops, expands, and operates self-storage facilities.
TERRY M. PALMER, (60), has been a Director of the Company since 2002. Mr. Palmer
was a partner in the accounting firm Ernst & Young LLP from 1979 until his
retirement in October 2002. Since January 2003, Mr. Palmer has been employed on
a part-time basis with the accounting firm of Marrs, Sevier & Company. Mr.
Palmer is also a director of Apex Silver Mines Limited.
50
RICHARD J. SCHULTE, (64), has been a Director of the Company since 1997.
Mr. Schulte is a principal in Schulte Associates LLC, a consulting firm
providing management, marketing, e-commerce and organizational services to
energy related businesses since 1998. He was formerly an officer of the American
Gas Association and Stone & Webster Management Consultants, Inc. He was 2002
Chairman of the Board of Directors for the American Society for Testing and
Materials (ASTM International). Mr. Schulte serves as Chairman of the Company's
Audit Committee.
THOMAS J. SMITH, (60), has been a Director of the Company since December 2003.
Since 1996 Mr. Smith has been the President of Liberty Self-Stor, Inc., a
self-managed real estate investment trust that manages, acquires, develops,
expands, and operates self-storage facilities. Mr. Smith is also a director of
Liberty Self-Stor, Inc.
The Board of Directors has determined that all the directors other than Mr.
Cerotzke are independent, as defined in Rule 4200(a)(15) of the National
Association of Securities Dealers' listing standards.
AUDIT COMMITTEE
The Company's Board of Directors has an Audit Committee consisting of
Messrs. Palmer, Schulte and Smith. The Committee met eight times during the
fiscal year and has responsibility for retaining the independent auditors,
reviewing the annual audit and making recommendations to the full Board
regarding accounting matters that come to its attention. Each member of the
Audit Committee is independent, both as defined in Rule 4200(a)(15) of the
National Association of Securities Dealers' listing standards, and as defined in
Rule 10A-3(b)(1)(ii) under the Securities Exchange Act of 1934, as amended. The
Board of Directors has determined that Mr. Palmer and Mr. Smith are "audit
committee financial experts" as defined in Item 401(h) of Regulation S-K.
SECTION 16(a) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE
Section 16(a) of the Securities Exchange Act of 1934 requires the
Company's directors, executive officers and persons who own more than ten
percent of the Company's common stock to file reports of ownership and changes
in ownership with the Securities and Exchange Commission and the National
Association of Securities Dealers (NASD). Such persons are also required to
furnish the Company with copies of all such reports. Based solely on its review
of the copies of such reports received by the Company, the Company believes that
its directors and executive officers filed all required reports during or with
respect to the fiscal year ending June 30, 2004 on a timely basis except for the
following: Mr. Morin filed a late Form 3 on August 11, 2003, reporting his
initial statement of beneficial ownership of securities of the Company as of
January 23, 2003;
51
Mr. Argo filed a late Form 4 on October 17, 2003, reporting the acquisition of
600 shares of Company common stock at a purchase price of $6.75 per share on
October 7, 2003, and 250 shares at $6.75 per share on October 8, 2003; Mr.
Osborne filed a late amended Form 4 on February 17, 2004, amending a Form 4
filed on December 29, 2003, restating the amount of securities beneficially
owned following the reported transaction to account for the 166,358 shares owned
by Turkey Vulture Fund XIII, Ltd., an Ohio limited liability company of which
Mr. Osborne is sole manager; Mr. Osborne filed a late Form 4 on March 15, 2004
reporting the acquisition of 1,000 shares of Company common stock at a purchase
price of $6.25 per share on March 8, 2004, in addition to other acquisitions
that were reported timely; Mr. Davidson filed a late Form 4 on April 1, 2004
reporting the acquisition of 237 deferred stock equivalents on February 19,
2004; and Mr. Davidson filed a late Form 4 on May 17, 2004 reporting the
acquisition of 98 deferred stock equivalents on April 28, 2004.
CODE OF ETHICS
Our Board of Directors has adopted a written Code of Business Conduct for
all directors, officers, and employees. A copy of this document is available on
our website at www.ewst.com, free of charge under the Our Company section. We
will satisfy any disclosure requirements under Item 5.05 of Form 8-K regarding
an amendment to, or waiver from, any provision of the Code of Business Conduct
with respect to our principal executive officer, principal financial officer,
principal accounting officer and persons performing similar functions by
disclosing the nature of such amendment or waiver on our website or in a report
on Form 8-K.
NOMINATION OF DIRECTORS
On February 20, 2004, the Board of Directors of the Company adopted an
amendment to the Company's By-Laws to amend the procedures to be followed for
stockholder nominations of directors. In order for a stockholder to propose
director nominations at the Company's annual meeting of stockholders, the
By-Laws, as amended, require a stockholder to provide the Company with a written
notice, which must be received by the Company at its principal executive
offices, not less than sixty (60) days prior to the date of the annual meeting.
The notice must set forth (a) as to each person whom the stockholder proposes to
nominate for election as a director (i) the name, age, business address and
residence address of the person, (ii) the principal occupation or employment of
the person, (iii) the class or series and number of shares of capital stock of
the Company which are owned beneficially or of record by the person and (iv) any
other information relating to the person that would be required to be disclosed
in a proxy statement or other filings required to be made in connection with
solicitations of proxies for election of directors pursuant to Section 14 of the
Securities Exchange Act of 1934, as amended, and the rules and regulations
promulgated thereunder (the "Exchange Act"); and (b) as to the stockholder
giving the notice (i) the name and record address of such stockholder, (ii) the
class or series and number of shares of capital stock of the Company which are
owned beneficially or of record by such stockholder, (iii) a description of all
arrangements or understandings between such stockholder and each proposed
nominee and any other person or persons (including their names) pursuant to
which the nomination(s) are to be made by such stockholder, (iv) a
representation that such stockholder intends to appear in person or by proxy at
the annual meeting to nominate the persons named in its notice and (v) any other
information relating to such stockholder that would be required to be disclosed
in a proxy statement or other filings required
52
to be made in connection with solicitations of proxies for election of directors
pursuant to Section 14 of the Exchange Act. Such notice must be accompanied by a
written consent of each proposed nominee to be named as a nominee and to serve
as a director if elected.
ITEM 11. - EXECUTIVE COMPENSATION
EXECUTIVE COMPENSATION
The following table sets forth the annual and long-term compensation of
the Chief Executive Officer and other named executive officers of the Company
earning compensation in excess of $100,000 in the fiscal year.
SUMMARY COMPENSATION TABLE
LONG TERM
COMPENSATION
------------
NUMBER OF
ANNUAL COMPENSATION SHARES
NAME AND PRINCIPAL FISCAL ------------------- UNDERLYING ALL OTHER
POSITION YEAR SALARY BONUS OPTIONS COMPENSATION
- ------------------ ---- ------ ----- ------- ------------
Edward J. Bernica, Former President & CEO(d) 2004 $ 36,810 -0- -0- $ 105,188(a)(e)
2003 131,212 13,500 20,000 24,027
2002 111,099 5,847 -0- 24,722
John C. Allen, Interim President and Chief Executive 2004 $ 126,464 $13,500 -0- $ 13,647(b)
Officer (d) 2003 100,970 10,010 $12,500 19,739
2002 99,419 4,542 -0- 14,334
Tim Good, VP Natural Gas Operations 2004 $ 111,667 $11,500 -0- $ 12,165(c)
2003 105,569 9,984 $12,500 20,222
2002 100,604 5,030 -0- 21,302
(a) Represents $4,665 of Company contributions to the Company's defined
contribution retirement pension plan.
(b) Represents $13,647 of Company contributions to the Company's defined
contribution retirement pension plan.
(c) Represents $12,165 of Company contributions to the Company's defined
contribution retirement pension plan.
(d) Mr. Bernica resigned as President and Chief Executive Officer of the Company
on September 22, 2003. Mr. Allen served as Interim President and Chief Executive
Officer from September 22, 2003 until June 30, 2004.
(e) On October 24, 2003 the Company entered into a separation agreement with Mr.
Bernica, providing for 30 semi-monthly payments of $6,187.50. On an annualized
basis, this rate is equal to the rate of Mr. Bernica's cash compensation for
fiscal year 2003. The agreement also provides that Mr. Bernica at his own cost
may continue health coverage under the Company's health plan as required under
Federal law.
53
AGGREGATED OPTION EXERCISES IN LAST FISCAL YEAR AND FY-END OPTION VALUES
SHARES NUMBER OF SECURITIES UNDERLYING
ACQUIRED ON VALUE UNEXERCISED OPTIONS AT FISCAL VALUE OF UNEXERCISED IN-THE-MONEY
EXERCISE REALIZED YEAR END (#) OPTIONS AT YEAR END ($)
-------- -------- ---------------------------------- ---------------------------------
Name (#) ($) Exercisable Unexercisable Exercisable Unexercisable
- ---- --- --- ----------- ------------- ----------- -------------
Edward J. Bernica -0- $0 -0- -0- $0 $0
John C. Allen -0- $0 6,250 6,250 $0 $0
Tim Good -0- $0 6,250 6,250 $0 $0
DIRECTOR COMPENSATION
The Company paid its outside directors an annual retainer of $6,000 per
year, $1,500 per Board meeting and $750 per Committee meeting. For Board or
Committee meetings held by telephone conference, the rate is one half the
regular rate indicated.
In addition, the Chairman of the Compensation Committee and the Chairman
of the Management and Business Development Committee each receives an additional
$3,000 annual retainer. The Chairman of the Audit Committee receives an
additional $5,000 annual retainer. The Chairman of the Board receives an
additional $8,000 annual retainer.
The directors have the option under the Deferred Compensation Plan for
Directors to receive their compensation in the form of stock, cash, or in the
form of deferred stock equivalents or deferred rights to receive cash. A
deferred stock equivalent is a hypothetical share of common stock valued at the
fair market value of a share of the common stock on the date of receipt. A
director will be paid any deferred stock equivalents in stock at the time of his
or her retirement from the Board of Directors.
EMPLOYMENT CONTRACTS
After Mr. Bernica's resignation, Mr. Allen served as Interim President and
Chief Executive Officer during fiscal 2004 until Mr. Cerotzke was appointed
President and Chief Executive Officer on July 1, 2004.
On June 23, 2004, the Company entered into written employment agreements
with Mr. Cerotzke and Mr. Allen. Mr. Cerotzke's employment agreement provides
for an initial base salary of $160,000, and Mr. Allen's employment agreement
provides for an initial base salary of $135,000. Each of the employment
agreements provides for periodic salary adjustments as determined by the Board.
Mr. Cerotzke's employment agreement provides for annual incentive compensation
under a program to be developed by the Board and under the Company's existing
annual incentive program and for a grant of 10,000 options, with additional
grants of 10,000 options on each of the first and second anniversaries of the
effective date of the employment agreement. Mr. Allen's employment agreement
provides for an initial grant of 20,000 options, with an additional grant of
10,000 options on the first anniversary of the effective date of the employment
agreement. Twenty-five percent of each option grant vests immediately and the
remainder of each option grant vests ratably over three years.
Mr. Cerotzke's agreement was effective July 1, 2004, and continues until
terminated as provided in the agreement. The agreement provides a continuation
of salary and medical benefits for 12 months, outplacement assistance, full
vesting of stock options and payment of a pro-rated annual bonus following
termination by the Company without cause or termination by Mr. Cerotzke if the
54
Company changes his title, materially reduces his duties or authority, requires
him to report internally other than to the Board, or requires a relocation from
the Great Falls area, or if his Board membership terminates other than by his
voluntary resignation. In the event that Mr. Cerotzke's employment is terminated
by the Company without cause or by Mr. Cerotzke for any of the reasons listed
above following a change in control of the Company, Mr. Cerotzke is entitled to
continuation of base salary and medical benefits for up to two years, payment of
a prorated annual bonus, and up to two times' his target annual bonus, together
with full vesting of his stock options. Under the employment agreement, Mr.
Cerotzke is subject to confidentiality, conflict of interest and nonsolicitation
provisions.
Mr. Allen's agreement was effective July 1, 2004, and continues for one
year. The agreement provides for a continuation of salary and medical benefits
for 12 months, outplacement assistance, full vesting of stock options and
payment of a pro-rated annual bonus following termination by the Company without
cause or termination by Mr. Allen if the Company materially reduces his duties
or authority, changes his title or requires him to relocate. In the event that
Mr. Allen's employment is terminated under circumstances entitling him to
benefits under the Company's existing change in control severance plan, any
benefits that Mr. Allen would receive under his employment agreement will be
offset by any benefits he receives under the plan. Under the employment
agreement, Mr. Allen is subject to confidentiality, conflict of interest and
nonsolicitation provisions.
On October 24, 2003, the Company entered into a Separation Agreement,
Release and Waiver of Claims with Edward J. Bernica, the Company's former
President and Chief Executive Officer. Pursuant to the agreement, Mr. Bernica
and the Company agreed to terminate Mr. Bernica's employment as President and
Chief Executive Officer and Mr. Bernica also resigned as a Director of Energy
West. As consideration for the agreement, the Company agreed to pay Mr. Bernica
30 semi-monthly payments of $6,187.50. On an annualized basis, this rate is
equal to the rate of Mr. Bernica's cash compensation for fiscal year 2003. The
agreement also provides that Mr. Bernica at his own cost may continue health
coverage under the Company's health plan as required under Federal law. The
agreement included a general release of all potential claims and contains
standard confidentiality and non-solicitation language for the benefit of the
Company.
55
ITEM 12. - SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
CERTAIN BENEFICIAL OWNERSHIP OF THE COMPANY'S COMMON STOCK
The following table sets forth certain information regarding the
beneficial ownership of the Common Stock of the Company on or about September
30, 2004 (i) by each shareholder who is known by the Company to own beneficially
more than 5% of the outstanding Common Stock, (ii) by each director, and nominee
for director, (iii) by each executive officer named in the Summary Compensation
Table above, and (iv) by all executive officers and directors as a group. Each
beneficial owner has sole voting and investment power unless otherwise
indicated.
NUMBER OF
SHARES
BENEFICIALLY PERCENT OF
NAME OF BENEFICIAL OWNER OWNED OWNERSHIP
- ------------------------ ----- ---------
Richard M. Osborne 540,347(a) 20.8
W.E. (Gene) Argo 850 *
Andrew I. Davidson 26,556(b) 1.0
David A. Flitner 5,984 *
G. Montgomery Mitchell 14,509(c) *
Terry M. Palmer 4,000 *
Thomas J. Smith 0 *
Richard J. Schulte 9,515(d) *
John C. Allen 28,950(e) 1.6
David A. Cerotzke 2,500(f) *
Tim Good 30,737(g) 1.2
All Directors and Executive Officers as a group 695,666(h) 26.9
(14 in number)
* Less than 1%
56
(a) Based solely on a Schedule 13D Amendment No. 11 filed with the Securities
and Exchange Commission on October 4, 2004.
(b) Includes 14,356 shares subject to deferred stock equivalents under the
Deferred Compensation Plan for Directors. Such deferred stock equivalents
are convertible to common stock upon the termination of a director's
service with the Company.
(c) Includes 7,185 shares subject to deferred stock equivalents under the
Deferred Compensation Plan for Directors.
(d) Includes 8,515 shares subject to deferred stock equivalents under the
Deferred Compensation Plan for Directors.
(e) Includes 11,250 shares subject to exercisable options, 862 shares pursuant
to the Company's 401(K) Plan and 8,174 shares pursuant to the company's
Employee Stock Ownership Plan.
(f) Includes 2,500 shares subject to exercisable options.
(g) Includes 6,250 shares subject to exercisable options, 485 shares pursuant
to the Company's 401(K) Plan and 7,436 shares pursuant to the Company's
Employee Stock Ownership Plan.
(h) Includes 30,056 shares subject to deferred stock equivalents, 26,400
shares subject to exercisable options, 1,347 shares pursuant to the
Company's 401(K) Plan and 15,610 shares pursuant to the Company's Employee
Stock Ownership Plan.
57
EQUITY COMPENSATION PLAN INFORMATION
Number of securities remaining
Number of securities to be available for future issuance
issued upon exercise of Weighted-average exercise under equity compensation
outstanding options, warrants price of outstanding options plans (excluding securities
Plan category and rights. warrants and rights. reflected in column (a) )
- ------------- ----------------------------- ---------------------------- ------------------------------
(a) (b) (c)
Equity compensation plans 128,384 $8.491 168,183 (1)
approved by security holders
Equity compensation plan not -0- $ 0 0
approved by security holders
TOTAL 128,384 $8.491 168,183
(1) Includes 100,000 shares available for future issuance under the
Company's Deferred Compensation Plan for Directors, 49,817 shares
of which have been issued or allocated for issuance under terms
of the plan.
ITEM 13. - CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
There are no transactions with management or business relationships with others
that require disclosure under Item 404 of Regulation S-K.
ITEM 14. - PRINCIPAL ACCOUNTANT FEES AND SERVICES
Aggregate fees billed to the Company during fiscal years 2004 and 2003 by the
Company's principal accounting firm, Deloitte & Touche LLP, and their
affiliates, were as follows:
2004 2003
Audit Fees $ 153,171 $ 177,083
Audit-Related Fees - -
------------- -------------
Total Audit and Audit-Related Fees 153,171 177,083
Tax Fees (a) 14,742 23,206
All Other Fees (b) 30,910 -
------------- -------------
Total Fees $ 198,823 $ 200,289
============= =============
(a) Advisory services related to preparation of income tax returns.
(b) Advisory services related to 404 Sarbanes - Oxley readiness.
The Audit Committee pre-approves all audit and non-audit services
performed by the independent auditors.
58
PART IV
ITEM 15. - EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
Page
(a) 1. Financial Statements included in Part II, Item 8:
Report of Independent Auditors F-2
Consolidated Balance Sheets F-3
Consolidated Statements of Operations F-4
Consolidated Statements of Stockholders' Equity F-5
Consolidated Statements of Cash Flows F-6
Notes to Consolidated Financial Statements F-8
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) EXHIBITS. The Exhibits required to be filed by Item 601 of Regulation S-K
are listed under the heading "Exhibit Index," below.
(c) SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS
ENERGY WEST, INCORPORATED
JUNE 30, 2004
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, 2002 $ 204,570 $ 59,506 $ (109,825) $ 154,251
Year Ended June 30, 2003 $ 154,251 $ 164,499 $ (105,737) $ 213,013
Year Ended June 30, 2004 $ 213,013 $ 163,041 $ (75,240) $ 300,814
59
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
Date: December 17, 2004 /s/ David A. Cerotzke
-----------------------------------------
By: David A. Cerotzke
President and Chief Executive Officer
(principal executive officer)
Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below by the following persons on behalf of the Registrant and
in the capacities and on the dates indicated.
/s/ David A. Cerotzke
- -----------------------
David A. Cerotzke President, Chief Executive Officer December 17, 2004
and Director
(principal executive officer)
/s/ M. Shawn Shaw
- -------------------
M. Shawn Shaw December 17, 2004
(principal financial officer
and principal accounting officer)
/s/ W.E. Argo
- -----------------
W.E. Argo Director December 17, 2004
/s/ Andrew I. Davidson
- ----------------------
Andrew I. Davidson Director December 17, 2004
/s/ David A. Flitner
- ---------------------
David A. Flitner Director December 17, 2004
/s/ G. Montgomery Mitchell
- ---------------------------
G. Montgomery Mitchell Director December 17, 2004
/s/ Richard M. Osborne
- ---------------------------
Richard M. Osborne Director December 17, 2004
/s/ Terry M. Palmer
- --------------------------
Terry M. Palmer Director December 17, 2004
/s/ Richard J. Schulte
- -----------------------
Richard J. Schulte Director December 17, 2004
/s/ Thomas J. Smith
- ---------------------
Thomas Smith Director December 17, 2004
60
EXHIBIT INDEX
3.1 Restated Articles of Incorporation of the Company, as amended to date
(incorporated by reference to Exhibit 3.1 on Form 10-K/A for the fiscal
year ended June 30, 1996, filed with the Commission on July 9, 1997).
3.2 Amended and Restated Bylaws of the Company, as amended to date
(incorporated by reference to Exhibit 3.2 on Form 8-K filed with the
Commission on March 5, 2004).
4.1 Form of Indenture (including form of Note) relating to the Company's
Series 1997 Notes (incorporated by reference to Exhibit 4.1 to the
Company's Registration Statement on Form S-2, File No. 333-31907).
4.2 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).
4.3 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).
4.4 Preferred Stock Rights Agreement, dated as of June 3, 2004, between
Energy West, Incorporated and Computershare Trust Company, Inc.,
including the Terms of Series A Participating Preferred Stock, the form
of Rights Certificate and the Summary of Rights attached thereto as
Exhibits A, B and C, respectively (incorporated by reference to Exhibit
4.1 to the Form 8-A filed with the Commission on June 3, 2004).
10.1(a) Amended and Restated Credit Agreement, dated March 31, 2004 ("Credit
Agreement"), by and among Energy West, Incorporated, its subsidiaries
and LaSalle Bank National Association ("LaSalle") (incorporated by
reference to Exhibit 10.1 to the Company's Current Report on Form 8-K
filed with the Commission on April 1, 2004).
10.1(b) Waiver and First Amendment to Credit Agreement dated as of August 30,
2004 by and among the Company, its subsidiaries and LaSalle
(incorporated by reference to Exhibit 10.1 to the Current Report on Form
8-K filed with the Commission on September 3, 2004).
10.1(c) Second Amendment to Credit Agreement dated as of September 10, 2004 by
and among the Company, its subsidiaries and LaSalle (incorporated by
reference to Exhibit 10.1 to the Current Report on Form 8-K filed with
the Commission on September 16, 2004).
10.1(d) Letter Agreement to Credit Agreement entered into on October 20, 2004,
by and among the Company, its subsidiaries and LaSalle (incorporated by
reference to Exhibit 10.1 to the Current Report on Form 8-K filed
with the Commission on October 21, 2004).
10.1(e) Letter Agreement to Credit Agreement entered into on November 2, 2004,
by and among the Company, its subsidiaries and LaSalle (incorporated by
reference to Exhibit 10.1 to the Current Report on Form 8-K filed
with the Commission on November 5, 2004).
10.1(f) Third Amendment to Credit Agreement dated as of November 2, 2004, by
and among the Company, its subsidiaries and LaSalle (incorporated by
reference to Exhibit 10.2 to the Current Report on Form 8-K filed with
the Commission on November 5, 2004).
10.1(g) Fourth Amendment to Credit Agreement dated as of November 30, 2004, by
and among the Company, its subsidiaries and LaSalle (incorporated by
reference to Exhibit 10.1 to the Current Report on Form 8-K filed with
the Commission on December 6, 2004).
10.2 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
61
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 (incorporated by reference to Exhibit 10.6 on
Form 10-K/A for the fiscal year ended June 30, 1996, filed with the
Commission on July 9, 1997).
10.3 Delivered Gas Purchase Contract dated December 1, 1985, as amended by that
Letter Agreement dated July 1, 1986; that Letter Agreement dated November
19, 1987; that Letter Agreement dated December 1, 1988; that Letter
Agreement dated July 30, 1992; that Assignment Conveyance and Bill of Sale
effective as of January 1, 1993; that Letter Agreement dated March 8,
1993; that Letter Agreement dated October 21, 1993; that Letter Agreement
dated October 18, 1994; that Letter Agreement dated January 30, 1995; that
Letter Agreement dated August 30, 1995; that Letter Agreement dated
October 3, 1995; that Letter Agreement dated October 31, 1995; that Letter
Agreement dated December 21, 1995; that Letter Agreement dated April 25,
1996; that Letter Agreement dated January 29, 1997; and that Letter dated
April 11, 1997 (incorporated by reference to Exhibit 10.7 on Form 10-K/A
for the fiscal year ended June 30, 1996, filed with the Commission on July
9, 1997).
10.4 Natural Gas Sale and Purchase Agreement dated July 20, 1992 between Shell
Canada Limited and the Company, as amended by that Letter Agreement dated
August 23, 1993; that Amending Agreement effective as of November 1, 1994;
and that Schedule A Incorporated Into and Forming a part of That Natural
Gas Sale and Purchase Agreement, effective as of November 1, 1996
(incorporated by reference to Exhibit 10.8 on Form 10-K/A for the fiscal
year ended June 30, 1996, filed with the Commission on July 9, 1997).
10.5 Employee Stock Ownership Plan Trust Agreement (incorporated by reference
to Exhibit 10.2 to Registration Statement on Form S-1, File No. 33-1672).*
10.6 1992 Stock Option Plan (incorporated by reference to Exhibit 10.10 on Form
10-K/A for the fiscal year ended June 30, 1996, filed with the Commission
on July 9, 1997).*
10.7 Form of Incentive Stock Option under the 1992 Stock Option Plan
(incorporated by reference to Exhibit 10.11 on Form 10-K/A for the fiscal
year ended June 30, 1996, filed with the Commission on July 9, 1997).*
10.8 Management Incentive Plan (incorporated by reference to Exhibit 10.12 on
Form 10-K/A for the fiscal year ended June 30, 1996, filed with the
Commission on July 9, 1997).*
10.9 Energy West Senior Management Incentive Plan (incorporated by reference to
Exhibit 10.19 to the Company's Annual Report on Form 10-K for the fiscal
year ended June 30, 2002, filed with the Commission on September 30,
2002).*
10.10 Energy West Incorporated Deferred Compensation Plan for Directors
(incorporated by reference to Exhibit 10.20 to the Company's Annual Report
on Form 10-K for the fiscal year ended June 30, 2002, filed with the
Commission on September 30, 2002).*
62
10.11 Amended and Restated Advisory Agreement, dated October 3, 2003, by and
among Energy West, Incorporated, D.A. Davidson & Co. and DAMG Capital LLC
(incorporated by reference to Exhibit 10.11 to the Company's Annual Report
on Form 10-K for the fiscal year ended June 30, ,2003, filed with the
Commission on October 9, 2003).
10.12 Letter Agreement dated June 5, 2003 between DAMG Capital LLC and the
Company (incorporated by reference to Exhibit 10.12 to the Company's
Annual Report on Form 10-K for the fiscal year ended June 30, 2003, filed
with the Commission on October 9, 2003).
10.13 Letter Agreement dated June 5, 2003 between D.A. Davidson & Co. and the
Company (incorporated by reference to Exhibit 10.13 to the Company's
Annual Report on Form 10-K for the fiscal year ended June 30, 2003, filed
with the Commission on October 9, 2003).
10.14 Agreement dated November 20, 2003 between and among J. Michael Gorman,
Lawrence P. Haren, Richard M. Osborne, Thomas J. Smith, Turkey Vulture
Fund XIII, Ltd., an Ohio limited liability company and, Energy West,
Incorporated (incorporated by reference to Exhibit 10.1 to the Company's
Current Report on Form 8-K filed with the Commission on November 21,
2003).
10.15 Separation Agreement, Release and Waiver of Claims between Energy West,
Incorporated and Edward J. Bernica dated October 24, 2003 (incorporated by
reference to Exhibit 10.1 to the Company's Current Report on Form 8-K
filed with the Commission on October 27, 2003).
10.16 Employment Agreement entered into as of June 23, 2004, between the Company
and David Cerotzke (filed herewith).*
10.17 Employment Agreement entered into as of June 23, 2004, between the Company
and John Allen (filed herewith). *
10.18 Option Agreement dated July 1, 2004, between the Company and David
Cerotzke (filed herewith).*
10.19 Option Agreement dated July 1, 2004, between the Company and John Allen
(filed herewith).*
10.20 Energy West, Incorporated 2002 Stock Option Plan (incorporated by
reference to Appendix A to the Company's Proxy Statement filed with the
Commission on October 30, 2002).
21.1 Subsidiaries of the Company (incorporated by reference to Exhibit 21.1 to
the Company's Annual Report on Form 10-K for the fiscal year ended June
30, 2000, filed with the Commission on September 28, 2000).
23.1 Consent of Independent Registered Public Accounting Firm - DELOITTE &
TOUCHE LLP (filed herewith).
31.1 Certification of Principal Executive Officer pursuant to Section 302 of
the Sarbanes-Oxley Act of 2002 (filed herewith).
63
31.2 Certification of Principal Financial Officer pursuant to Section 302 of
the Sarbanes-Oxley Act of 2002 (filed herewith).
32.1 Certification of Principal Executive Officer pursuant to Section 906 of
the Sarbanes-Oxley Act of 2002 (filed herewith).
32.2 Certification of Principal Financial Officer pursuant to Section 906 of
the Sarbanes-Oxley Act of 2002 (filed herewith).
* Represents a management contract or a compensatory plan or arrangement
64
ENERGY WEST, INCORPORATED AND SUBSIDIARIES
TABLE OF CONTENTS
PAGE
Report of Independent Registered Public Accounting Firm F-2
Consolidated Balance Sheets as of June 30, 2004 and 2003 (As Restated) F-3
Consolidated Statements of Operations for the Years Ended June 30, 2004, 2003 (As Restated),
and 2002 (As Restated) F-4
Consolidated Statements of Stockholders' Equity for the Years Ended June 30, 2004, 2003 (As Restated),
and 2002 (As Restated) F-5
Consolidated Statements of Cash Flows for the Years Ended June 30, 2004, 2003 (As Restated),
and 2002 (As Restated) F-6
Notes to Consolidated Financial Statements F-8
F-1
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of
Energy West, Incorporated
Great Falls, Montana
We have audited the accompanying consolidated balance sheets of Energy West,
Incorporated and subsidiaries as of June 30, 2004 and 2003, and the related
consolidated statements of operations, stockholders' equity, and cash flows for
each of the three years in the period ended June 30, 2004. Our audits also
included the financial statement schedule listed in the Index at Item 15. 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 audits.
We conducted our audits in accordance with the standards of the Public Company
Accounting Oversight Board (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, such consolidated financial statements present fairly, in all
material respects, the financial position of Energy West, Incorporated and
subsidiaries at June 30, 2004 and 2003, and the results of their operations and
their cash flows for each of the three years in the period ended June 30, 2004,
in conformity with accounting principles generally accepted in the United States
of America. Also, in our opinion, such 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.
As discussed in Note 15 to the consolidated financial statements, the
accompanying consolidated financial statements for fiscal years 2003 and 2002
have been restated.
DELOITTE AND TOUCHE LLP
Salt Lake City, Utah
December 16, 2004
F-2
ENERGY WEST, INCORPORATED AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS, JUNE 30, 2004 AND 2003
2004 2003
(AS RESTATED)
(SEE NOTE 15)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents $ 1,322,702 $ 1,938,768
Accounts and notes receivable, less $300,814 and $213,013, respectively, allowance
for bad debt 6,729,020 7,971,632
Derivative assets 199,248 623,635
Natural gas and propane inventories 5,183,046 1,038,690
Materials and supplies 350,764 371,490
Prepayments and other 370,379 352,982
Deferred income taxes 526,899 543,028
Income tax receivable 1,268,243 1,882,889
Recoverable cost of gas purchases 788,407 1,067,109
------------ ------------
Total current assets 16,738,708 15,790,223
PROPERTY, PLANT AND EQUIPMENT, NET 38,605,644 39,576,596
NOTE RECEIVABLE 407,538
DEFERRED CHARGES 5,488,415 4,388,372
OTHER ASSETS 204,772 271,429
------------ ------------
TOTAL ASSETS $ 61,445,077 $ 60,026,620
============ ============
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Current portion of long-term debt $ 972,706 $ 532,371
Line of credit 6,729,304 6,104,588
Accounts payable 3,611,080 8,841,779
Derivative liabilities 1,684,676 864,929
Accrued and other current liabilities 3,726,982 5,489,119
------------ ------------
Total current liabilities 16,724,748 21,832,786
------------ ------------
OTHER OBLIGATIONS:
Deferred income taxes 4,529,381 4,335,896
Deferred investment tax credits 334,344 355,406
Other long-term liabilities 4,758,893 4,711,335
------------ ------------
Total 9,622,618 9,402,637
------------ ------------
LONG-TERM DEBT 21,697,286 14,834,452
COMMITMENTS AND CONTINGENCIES (NOTE 7, 12, 13 AND 14)
STOCKHOLDERS' EQUITY:
Common stock; $.15 par value, 3,500,000 shares authorized,
2,598,506 and 2,595,250 shares outstanding at June 30, 2004 and 2003, respectively 389,783 389,295
Preferred stock; $.15 par value, 1,500,000 shares authorized, no shares
outstanding -- --
Capital in excess of par value 5,077,687 5,056,425
Retained earnings 7,932,955 8,511,025
------------ ------------
Total stockholders' equity 13,400,425 13,956,745
------------ ------------
TOTAL CAPITALIZATION 35,097,711 28,791,197
------------ ------------
TOTAL LIABILITIES AND CAPITALIZATION $ 61,445,077 $ 60,026,620
============ ============
See notes to consolidated financial statements
F-3
ENERGY WEST, INCORPORATED AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
FOR THE YEARS ENDED JUNE 30, 2004, 2003, AND 2002
2004 2003 2002
(AS RESTATED) (AS RESTATED)
(SEE NOTE 15) (SEE NOTE 15)
REVENUES:
Natural gas operations $ 39,062,689 $ 31,627,242 $ 39,515,060
Propane operations 7,736,379 12,786,918 10,656,152
Gas and electric -- wholesale 26,090,845 33,035,024 38,914,674
Pipeline operations 401,269 448,681 154,494
-------------- -------------- --------------
Total revenues 73,291,182 77,897,865 89,240,380
-------------- -------------- --------------
EXPENSES:
Gas purchased 31,883,566 30,803,655 35,872,169
Gas and electric -- wholesale 26,027,876 31,506,102 38,522,409
Cost of goods sold 210,661 195,254
Distribution, general, and administrative 10,169,560 11,669,029 8,790,183
Maintenance 480,086 496,717 465,771
Depreciation and amortization 2,332,073 2,392,368 2,059,169
Taxes other than income 1,209,916 888,281 946,214
-------------- -------------- --------------
Total expenses 72,103,077 77,966,813 86,851,169
-------------- -------------- --------------
OPERATING INCOME (LOSS) 1,188,105 (68,948) 2,389,211
OTHER INCOME 385,277 302,110 657,887
INTEREST EXPENSE (2,498,623) (1,633,042) (1,704,492)
-------------- -------------- --------------
INCOME (LOSS) BEFORE INCOME TAXES (925,241) (1,399,880) 1,342,606
INCOME TAX BENEFIT (EXPENSE) 368,921 542,880 (515,409)
-------------- -------------- --------------
NET INCOME (LOSS) $ (556,320) $ (857,000) $ 827,197
============== ============== ==============
EARNINGS (LOSS) PER COMMON SHARE:
Basic $ (0.21) $ (0.33) $ 0.32
Diluted $ (0.21) $ (0.33) $ 0.32
WEIGHTED AVERAGE COMMON SHARES
OUTSTANDING:
Basic 2,596,454 2,586,487 2,549,245
Diluted 2,596,454 2,586,487 2,558,782
See notes to consolidated financial statements.
F-4
ENERGY WEST, INCORPORATED AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
FOR THE YEARS ENDED JUNE 30, 2004, 2003, AND 2002
CAPITAL IN
COMMON EXCESS OF RETAINED
SHARES STOCK PAR VALUE EARNINGS TOTAL
BALANCE AT JULY 1, 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 (As Restated see Note 15) 827,197 827,197
Dividends (1,365,473) (1,365,473)
--------- ---------- ------------ ------------- -------------
BALANCE AT JUNE 30, 2002 (As Restated see Note 15) 2,573,046 385,964 4,863,113 10,449,673 15,698,750
Sales of common stock at $6.010 to $9.720
per share under the Company's dividend
reinvestment plan 9,820 1,473 77,114 78,587
Issuance of common stock to ESOP at
estimated fair value of $9.533 per share 12,384 1,858 116,198 118,056
Net loss (As Restated see Note 15) (857,000) (857,000)
Dividends (1,081,648) (1,081,648)
--------- ---------- ------------ ------------- -------------
BALANCE AT JUNE 30, 2003 (As Restated see Note 15) 2,595,250 389,295 5,056,425 8,511,025 13,956,745
Shares Issued at $5.950 to $7.250
per share under the Company's dividend
reinvestment plan 3,256 488 21,262 21,750
Net loss (556,320) (556,320)
Dividends (21,750) (21,750)
--------- ---------- ------------ ------------- -------------
BALANCE AT JUNE 30, 2004 2,598,506 $ 389,783 $ 5,077,687 $ 7,932,955 $ 13,400,425
========= ========== ============ ============= =============
F-5
ENERGY WEST, INCORPORATED AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED JUNE 30, 2004, 2003, AND 2002
2004 2003 2002
(AS RESTATED) (AS RESTATED)
(SEE NOTE 15) (SEE NOTE 15)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss) $ (556,320) $ (857,000) $ 827,197
Adjustments to reconcile net income (loss) to
net cash provided by (used in) operating activities:
Depreciation and amortization, including deferred
charges and financing costs 3,467,774 2,594,141 2,326,909
Gain on sale of assets (333,987) (23,657) (393,584)
Investment tax credit (21,062) (21,062) (21,062)
Deferred gain on sale of assets (23,628) (23,628) (23,628)
Deferred income taxes 209,612 1,039,449 (1,716,632)
Changes in assets and liabilities:
Accounts and notes receivable 1,090,118 275,907 2,221,791
Derivative assets 424,387 1,312,016 1,509,209
Natural gas and propane inventories (4,144,356) 4,601,970 (873,114)
Accounts payable (5,230,702) (711,004) 108,573
Derivative liabilities 819,747 864,930 (3,921,354)
Recoverable/refundable cost of gas purchases 278,702 (3,091,268) 8,848,379
Prepayments and other (17,397) 92,670 (44,510)
Other assets 539,349 (4,751,472) 114,868
Other liabilities (2,374,106) 3,247,477 (1,714,385)
-------------- -------------- --------------
Net cash provided by (used in) operating activities (5,871,869) 4,549,469 7,248,657
-------------- -------------- --------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Construction expenditures (2,316,695) (4,040,286) (5,485,108)
Acquisition of producing natural gas reserves (90,113) (956,888)
Proceeds from sale of assets 946,233 23,958 1,188,458
Customer advances received (refunded) for construction 65,579 (2,131) (28,078)
Increase (decrease) from contributions in aid of construction 158,735 31,360 (2,901)
-------------- -------------- --------------
Net cash used in investing activities (1,146,148) (4,077,212) (5,284,517)
-------------- -------------- --------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Repayments of long-term debt (696,831) (502,673) (490,000)
Proceeds from lines of credit 32,932,346 40,032,623 44,084,650
Repayments of lines of credit (32,307,630) (37,428,035) (44,370,639)
Proceeds from long-term debt 8,000,000 -- --
Debt issuance costs (1,525,934) -- --
Sale of common stock -- 78,587 298,873
Dividends paid -- (1,081,648) (1,340,034)
-------------- -------------- --------------
Net cash provided by (used in) financing activities 6,401,951 1,098,854 (1,817,150)
-------------- -------------- --------------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS (616,066) 1,571,111 146,990
CASH AND CASH EQUIVALENTS:
Beginning of year 1,938,768 367,657 220,667
-------------- -------------- --------------
End of year $ 1,322,702 $ 1,938,768 $ 367,657
============== ============== ==============
See notes to consolidated financial statements (Continued)
F-6
ENERGY WEST, INCORPORATED AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED JUNE 30, 2004, 2003, AND 2002
2004 2003 2002
SUPPLEMENTAL DISCLOSURES OF
CASH FLOW INFORMATION:
Cash paid during the period for interest $ 1,858,023 $ 1,490,265 $ 2,025,468
Cash paid during the period for income taxes - - 2,937,000
SUPPLEMENTAL SCHEDULE OF NONCASH
INVESTING AND FINANCING ACTIVITIES:
Shares issued to satisfy liability to the ESOP - 118,056 249,838
Capital lease - - 13,496
Assets acquired for debt issued and liabilities assumed - 834,667 -
Assets sold in exchange for note receivable 620,333 - -
Shares issued under the Company's 401k dividend
reinvestment plan 21,750 31,417 25,439
Capitalized interest 24,602 25,947 43,680
See notes to consolidated financial statements (concluded)
F-7
ENERGY WEST, INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED JUNE 30, 2004, 2003, AND 2002
1. SUMMARY OF BUSINESS AND SIGNIFICANT ACCOUNTING POLICIES
NATURE OF BUSINESS -- Energy West, Incorporated (the "Company") is a
regulated public entity with certain non-regulated 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.
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").
BASIS OF PRESENTATION -- The accompanying consolidated financial
statements have been prepared on a going concern basis, which contemplates
the realization of assets and the satisfaction of liabilities in the
normal course of business.
As of June 30, 2004, the Company would not have been in compliance with
certain covenants under the LaSalle Facility had the lender not waived or
modified the covenants. See note 14.
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 fiscal year 2003 and
2002. All intercompany transactions and accounts have been eliminated.
SEGMENTS -- The Company reports financial results for four business
segments: Natural Gas Operations, Propane Operations, EWR, and Pipeline
Operations. Summarized financial information for these four segments is
set forth in Note 10.
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
F-8
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, asset retirement obligations, 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 ("WPSC"),
and the Arizona Corporation Commission. Purchased gas and propane costs
that are different from those provided for in present rates, and approved
by the applicable commissions, are accumulated and recovered or credited
through future rate changes. As of June 30, 2004 and June 30, 2003, the
Company has unrecovered purchase gas costs of $788,407 and $1,067,109
respectively.
PROPERTY, PLANT, AND EQUIPMENT -- 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%,
3.69% and 3.40% during the years ended June 30, 2004, 2003 and 2002,
respectively.
CONSTRUCTION IN AID AND ADVANCES RECEIVED FOR CONSTRUCTION --
Contributions in aid of construction are contributions received from
customers for construction which are not refundable. Customer advances for
construction includes advances received from customers for construction
which are to be refunded wholly or in part.
NATURAL GAS RESERVES -- EWR owns an undivided interest in certain
producing natural gas reserves on properties located in northern Montana.
EWD also owns an undivided interest in certain natural gas producing
properties located in northern Montana. The Company is depleting these
reserves using the units-of-production method. The gas reserves are
included in the Property, Plant and Equipment, net in the accompanying
consolidated financial statements. The production of the gas reserves is
not considered to be significant to the operations of the Company as
defined by Statement of Financial Accounting Standard ("SFAS") No. 69,
Disclosures About Oil and Gas Producing Properties.
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. As of June 30, 2004 and 2003, management does not
consider the value of any of its long-lived assets to be impaired.
STOCK-BASED COMPENSATION -- The Company has elected to use the intrinsic
value method of accounting under 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 SFAS No. 123, Accounting
for Stock-Based Compensation.
F-9
The following table illustrates the effect on net loss and loss per share
for the years ended June 30, 2004 and 2003 if the fair value based method
had been applied to all outstanding and unvested awards in the period:
2004 2003
Net loss, as reported $ (556,320) $ (857,000)
Deduct: Total stock-based employee compensation expense
determined under fair value based method for all awards,
net of related tax effects (19,160) (22,793)
------------ ------------
Pro forma net loss $ (575,480) $ (879,793)
============ ============
Loss per share:
Basic -- as reported $ (0.21) $ (0.33)
Basic -- pro forma $ (0.22) $ (0.34)
Diluted -- as reported $ (0.21) $ (0.33)
Diluted -- pro forma $ (0.22) $ (0.34)
In the fiscal years ended June 30, 2004 and 2002, no options were granted.
In the fiscal year ended June 30, 2003, 114,500 options were granted.
Additionally, the carryover effect of options granted prior to fiscal year
2002 was not significant.
The fair value of the options issued in fiscal year ended June 30, 2003
was estimated at the date of grant using the Black-Scholes option pricing
model with the following assumptions:
1) risk-free interest rate of 3.2 percent;
2) dividend yield of 6.6 percent prior to third quarter of fiscal
year 2003;
3) no discount for lack of marketability;
4) expected life of 5 years; and
5) a volatility factor of the expected market price of the
Company's common stock of 37 percent.
COMPREHENSIVE INCOME -- During the years ended June 30, 2004, 2003, and
2002, the Company had no components of comprehensive income (loss) other
than net income (loss).
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 accounting for derivative financial instruments that
are used to manage risk is 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 and SFAS No. 149,
Amendment of Statement 133 on Derivatives and Hedging Activities, which
the Company adopted July 1, 2003. Derivatives are recorded at estimated
fair value and gains and losses from derivative instruments are included
as a component of gas and electric -- wholesale revenues in the
accompanying
F-10
consolidated statements of operations. For the years ended June 30, 2004,
2003, and 2002, the Company recognized a reduction in revenues "gas and
electric - wholesale" from derivative instruments of approximately
$1,244,000, $2,177,000, and $4,240,000 respectively. Pursuant to SFAS No.
133, as amended, contracts for the purchase or sale of natural gas at
fixed prices and notional volumes must be valued at fair value unless the
contracts qualify for treatment as a "normal" purchase or sale and the
appropriate election has been made. As of June 30, 2004 and 2003, the
Company had elected the normal treatment for the majority of its
contracts.
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 maturities
of three months or less at the date of acquisition are considered to be
cash equivalents.
EARNINGS PER SHARE -- Net income (loss) 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 11. Options to purchase 77,000 and 130,420
shares of common stock were outstanding at June 30, 2004 and June 30,
2003, respectively, but were not included in the computation of diluted
earnings (loss) per share as the exercise price on the options is greater
than the market price of the stock. The dilutive effect of stock options
for the year ended June 30, 2002 was an increase to basic weighted average
common shares outstanding of 9,537.
CREDIT RISK -- The Company's primary market areas are 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.
ASSET RETIREMENT OBLIGATIONS ("ARO") -- The Company adopted SFAS No. 143,
Accounting for Asset Retirement Obligation effective July 1, 2002, and has
recorded an asset
F-11
and an asset retirement obligation in the accompanying consolidated
balance sheet in "Property, plant and equipment, net," and in "Other
long-term liabilities." The asset retirement obligation of $586,229 and
$555,665 represents the Company's estimated future liability as of June
30, 2004 and June 30, 2003 respectively, to plug and abandon existing oil
and gas wells owned by EWR and EWD. EWR and EWD will depreciate the asset
amount and increase the liability over the estimated useful life of these
assets. In the future, the Company may have other asset retirement
obligations arising from its business operations.
The Company has identified but not recognized ARO liabilities related to
gas transmission and distribution assets resulting from easements over
property not owned by the Company. These easements are generally perpetual
and only require retirement action upon abandonment or cessation of use of
the property for the specified purpose. The ARO liability is not estimable
for such easements as the Company intends to utilize these properties
indefinitely. In the event the Company decides to abandon or cease the use
of a particular easement, an ARO liability would be recorded at that time.
Changes in the asset retirement obligation can be reconciled as follows:
Balance--July 1, 2003 $ 555,665
Accretion 30,564
----------
Balance--June 30, 2004 $ 586,229
==========
NEW ACCOUNTING PRONOUNCEMENTS -- In April 2003, the Financial Accounting
Standards Board ("FASB") issued SFAS No. 149, Amendments of Statement 133
on Derivative Instruments and Hedging Activities. SFAS No. 149 amends and
clarifies accounting for derivative instruments, including certain
derivative instruments embedded in other contracts, and hedging
activities. The Statement is effective for contracts entered into or
modified after June 30, 2003 and for hedging relationships designated
after June 30, 2003. Management adopted this standard on July 1, 2003 and
determined that there is no current impact from SFAS No. 149 on the
consolidated financial statements.
In May 2003, the FASB issued SFAS No. 150, Accounting for Certain
Financial Instruments with Characteristics of both Liabilities and Equity,
which provides standards for how an issuer classifies and measures certain
financial instruments with characteristics of both liabilities and equity.
The Statement is effective for financial instruments entered into or
modified after May 31, 2003 and for pre-existing instruments as of the
beginning of the first interim period beginning after June 15, 2003.
Management has determined that there is no current impact from SFAS No.
150 on the consolidated financial statements.
RECLASSIFICATIONS - Certain prior year amounts have been reclassified to
conform to the current year presentation.
2. NATURAL GAS WELLS
In order to provide a stable source of natural gas for a portion of its
requirements, effective December 2001, EWR purchased a 70% working
interest (59% net revenue interest) in a group of producing natural gas
properties consisting of 116 wells and a 75% ownership interest in two
gathering systems located in northern Montana.
The wells are depleting based upon production at approximately 10% per
year as of June 30, 2004. For the period ended June 30, 2004, EWR's
portion of the daily gas production was approximately 640 MCF per day, or
approximately 3% of EWR's present volume requirements.
In March 2003, EWD acquired a 47% working interest (40% net revenue
interest) in a group of producing natural gas properties consisting of 47
wells and a 75% ownership interest in a gathering system located in
northern Montana.
F-12
For the period ended June 30, 2004, EWD's portion of the daily gas
production was approximately 280 MCF per day, or approximately 1.5% of
EWR's present volume requirements.
EWR and EWD's combined portion of the estimated daily gas production from
the reserves is approximately 920 MCF, or approximately 4.5% of the
Company's present volume requirements. This production gives the Company a
natural hedge, due to fixed production expenses when market prices of
natural gas are above the costs of production. The wells are operated by
an independent third party operator who also has an ownership interest in
the reserves. In 2002 and 2003 the Company entered into agreements with
the operator of the wells to purchase a portion of the operator's share of
production.
3. PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment consist of the following as of June 30,
2004 and 2003:
2004 2003
Gas transmission and distribution facilities $ 51,612,893 $ 49,617,786
Land 332,386 567,011
Buildings and leasehold improvements 3,242,240 3,317,535
Transportation equipment 2,238,774 2,541,367
Computer equipment 4,765,726 4,642,657
Other equipment 4,436,516 3,909,996
Construction work-in-progress 428,036 1,523,660
Producing natural gas reserves 1,969,567 1,858,601
------------ ------------
69,026,138 67,978,613
Accumulated depreciation, depletion,
and amortization (30,420,494) (28,402,017)
------------ ------------
Total $ 38,605,644 $ 39,576,596
============ ============
4. DEFERRED CHARGES
Deferred charges consist of the following as of June 30, 2004 and 2003:
2004 2003
Regulatory asset for property taxes $ 2,806,660 $ 2,609,866
Regulatory asset for income taxes 458,753 458,753
Regulatory asset for deferred environmental remediation costs 485,066 440,196
Other regulatory assets 77,858 101,000
Unamortized debt issue costs 1,660,078 778,557
------------ ------------
Total $ 5,488,415 $ 4,388,372
============ ============
Regulatory assets will be recovered over a period of approximately seven to
twenty years.
F-13
5. ACCRUED AND OTHER CURRENT LIABILITIES
Accrued and other current liabilities consist of the following as of June
30, 2004 and 2003:
2004 2003
Property tax settlement -- current portion (see Note 12) $ 243,000 $ 243,000
Litigation reserve for PPLM settlement (see Note 12) -- 2,200,000
Payable to employee benefit plans 545,375 568,133
Accrued vacation 394,219 429,333
Customer deposits 407,635 576,917
Accrued incentives 524,642 464,394
Accrued interest 103,047 106,860
Accrued taxes other than income 520,536 399,718
Deferred payments from levelized billing 496,897 205,389
Other 491,631 295,375
------------ ------------
Total $ 3,726,982 $ 5,489,119
============ ============
6. OTHER LONG-TERM LIABILITIES
Other long-term liabilities consist of the following as of June 30, 2004
and 2003:
2004 2003
Asset retirement obligation $ 586,229 $ 555,665
Contribution in aid of construction 1,225,539 1,066,804
Customer advances for construction 603,589 538,010
Accumulated postretirement obligation 269,100 209,800
Deferred gain on sale leaseback of assets 47,267 70,895
Regulatory liability for income taxes 83,161 83,161
Property tax settlement (see Note 12) 1,944,008 2,187,000
------------ ------------
Total $ 4,758,893 $ 4,711,335
============ ============
7. LINES OF CREDIT AND LONG-TERM DEBT
LINES OF CREDIT -- On March 31, 2004, the Company entered into a
modification of its existing credit facility (as amended, the "LaSalle
Facility") with LaSalle Bank National Association ("LaSalle"). The LaSalle
Facility converted $8,000,000 of existing revolving loans into a
$6,000,000, five-year term loan and a $2,000,000 term loan due on November
30, 2004, (collectively the "Term Loan") and reduces the maximum amount of
the line of credit, which expires on November 30, 2004 (recently extended
to November 28, 2005), from $23,000,000 to $15,000,000. The $2,000,000
term loan must be repaid with the proceeds of a placement of equity
securities by the Company by November 30, 2004 (recently extended to
October 1, 2005). See DEBT COVENANTS below. The credit facilities with
LaSalle are secured, on an equal and ratable basis with the Company's
other long-term debt, by substantially all of the Company's assets.
F-14
LONG-TERM DEBT -- Long-term debt at June 30, 2004 and 2003 consists of the
following:
2004 2003
Series 1997 notes payable $ 7,860,984 $ 7,925,444
Series 1993 notes payable 5,835,000 6,280,000
Series 1992B industrial development revenue obligations 1,065,000 1,150,000
Term loan 7,900,000
Capital lease 9,008 11,379
------------ ------------
Total long-term debt 22,669,992 15,366,823
Current portion of long-term debt (972,706) (532,371)
------------ ------------
Long-term debt $ 21,697,286 $ 14,834,452
============ ============
Borrowings under the LaSalle Facility are secured by liens on
substantially all of the assets of the Company and its subsidiaries. The
Company's obligations under the 1997 Notes, 1993 Notes and 1992B Notes,
described below, are secured on an equal and ratable basis with the Lender
in the collateral granted to secure the borrowings under the LaSalle
Facility with the exception of the first $1.0 million of debt under the
LaSalle Facility.
SERIES 1997 NOTES PAYABLE - On August 1, 1997, the Company issued
$8,000,000 of Series 1997 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, the notes may be
redeemed at any time prior to maturity, in whole or part, at 101% of face
value if redeemed before June 1, 2005, and at 100% of face value if
redeemed thereafter, plus accrued interest. As of June 30, 2004, the
Company had not redeemed any of the notes under this issue, except for
$139,016 in redemptions as a result of redemption rights exercisable upon
the deaths of holders of the notes.
SERIES 1993 NOTES PAYABLE - On June 24, 1993, the Company issued
$7,800,000 of Series 1993 notes bearing interest at rates ranging from
6.20% to 7.60%, payable semiannually on June 1 and December 1 of each
year. The 1993 notes mature serially in increasing amounts on June 1 of
each year beginning in 1999 and extending to June 1, 2013. At the
Company's option, the notes may be redeemed at any time prior to maturity,
in whole or part, at redemption prices declining from 103% to 100% of face
value, plus accrued interest. As of June 30, 2004, the Company had not
redeemed prior to their scheduled maturity any of the notes under this
issue.
SERIES 1992B INDUSTRIAL DEVELOPMENT REVENUE OBLIGATIONS - On September 15,
1992, Cascade County, Montana issued $1,800,000 of Series 1992B Industrial
Development Revenue Bonds (the "1992B Bonds") bearing interest at rates
ranging from 3.35% to 6.50%, and loaned the proceeds to the Company. The
Company is required to pay the loan, with interest, in amounts and on a
schedule to repay the 1992B Bonds. Interest is payable semiannually on
April 1 and October 1 of each year. The 1992B Bonds began maturing
serially in increasing amounts on October 1, 1993, and continuing on each
October 1 thereafter until October 1, 2012. At the Company's option, 1992B
Bonds may be redeemed in whole or in part on any interest payment date at
redemption prices declining from 101% to 100% of face value, plus accrued
interest. As of June 30, 2004, the Company had not redeemed prior to their
scheduled maturity any of the 1992B Bonds.
TERM LOAN -- On March 31, 2004, the Company entered into a modification of
its LaSalle Facility. The modification converted $8,000,000 of existing
revolving loans into a $6,000,000, five-year term loan with principal
payments of $33,333 each month and a $2,000,000 term loan due on November
30, 2004 (recently extended to October 1, 2005). Under the LaSalle
Facility, the Company pays interest (i) on its line of credit borrowings
at either (a) the London Interbank Offered Rate (LIBOR) plus 250 basis
points (bps) or, if the Company elects, (b) the rate publicly announced
from time to time by the Lender as its "prime rate" ("Prime"), (ii) on its
$6,000,000 term loan at either (a) LIBOR plus 350 bps or, if the Company
elects, (b) Prime plus 150 bps and (iii) on its $2,000,000 term loan at
Prime plus 200 bps through March 31, 2005; the Prime Rate plus 300 bps
from April 1, 2005 through June 30, 2005; and the Prime Rate plus 400 bps
from and after July 1, 2005. The LaSalle Facility also has a commitment
fee of 35 bps due on the daily unutilized portion of the facility.
F-15
AGGREGATE ANNUAL MATURITIES -- The scheduled maturities of long-term debt
at June 30, 2004 are as follows:
TOTAL
SERIES SERIES SERIES TERM CAPITAL LONG-TERM
1997 1993 1992B LOAN LEASE DEBT
Year ending June 30:
2005 $ 480,000 $ 90,000 $ 400,000 $ 2,706 $ 972,706
2006 515,000 95,000 2,400,000 3,088 3,013,088
2007 550,000 105,000 400,000 3,214 1,058,214
2008 590,000 110,000 400,000 1,100,000
2009 115,000 400,000 515,000
Thereafter $ 7,860,984 3,700,000 550,000 3,900,000 16,010,984
----------- ----------- ----------- ----------- -------- ------------
Total $ 7,860,984 $ 5,835,000 $ 1,065,000 $ 7,900,000 $ 9,008 $ 22,669,992
=========== =========== =========== =========== ======== ============
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
$24,796,889 and $16,580,495 as of June 30, 2004 and 2003, respectively.
DEBT COVENANTS -- 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, maintaining certain financial debt and
interest ratios and others.
On April 16, 2004, a stockholder acquired certain shares of common stock
which together with other shares owned by that stockholder total
approximately 20.8% of all outstanding shares, which violated a covenant
of the LaSalle Facility. Subsequently, the LaSalle Facility was amended to
approve this concentration of equity ownership (see Note 14).
As of August 30, 2004, the Company and its lender under its credit
facility (the "LaSalle Facility") amended certain covenants as follows:
(1) increased the total debt to capital ratio from .65 to .70, (2) allowed
the inclusion of certain expenses incurred by the Company for legal fees
and costs of the PPLM litigation, expenses and costs associated with the
credit facilities, proxy contest costs, and the costs of adoption of the
shareholder rights plan, in determining the interest coverage ratio, and
(3) waived compliance with the ratios referred to in (1) and (2) above as
of June 30, 2004. In addition, LaSalle waived compliance to a
shareholder's acquisition of more than 15% of the outstanding common stock
of the Company.
F-16
On November 2, 2004, the Company executed a letter agreement effective as
of September 28, 2004 amending the LaSalle Facility. The letter agreement
provides for the extension of the deadline to deliver audited financial
statements for fiscal year 2004 to November 12, 2004.
As of November 2, 2004, the Company executed an amendment to the LaSalle
Facility, which provides for an extension to November 30, 2004 of the
deadlines under the LaSalle Facility in connection with: (i) the
termination date of the revolving facility and (ii) the date to consummate
infusions of new equity of at least $2.0 million to repay the $2.0 million
term loan under the LaSalle Facility.
As of November 30, 2004, the Company executed an agreement with its lender
providing for (i) an extension of the revolving facility until November
28, 2005; (ii) an extension of the date to consummate infusions of new
equity of at least $2.0 million and to repay the $2.0 million term loan to
October 1, 2005; (iii) a conditional waiver of the deadline to deliver
audited financial statements for fiscal year 2004 and the deadline to
deliver financial statements for the fiscal quarter ended September 30,
2004; (iv) a waiver of the technical default that otherwise would have
been caused by the restatement of financial results of prior periods; (v)
modification of interest rates applicable to the $2.0 million term loan;
(vi) a limitation of $1.0 million on total loans and additional capital
investment from the Company to EWR; and (vii) waivers of certain financial
covenant defaults as of September 30, 2004.
8. EMPLOYEE BENEFIT PLANS
The Company has a defined contribution plan (the "401k Plan") which covers
substantially all of the Company's employees. Under the 401k Plan, the
Company contributes 10% of each participant's eligible compensation. Total
contributions to the 401k Plan for the years ended June 30, 2004, 2003,
and 2002 were $512,220, $568,133, and $617,275, respectively. The Company
also sponsors a defined postretirement health benefit plan (the "Retiree
Health 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 Retiree Health
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.
F-17
A portion of the Company's 401k Plan consists of 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 made no contributions for the fiscal years ended June 30, 2004
and 2003, and recognized as expense $129,802 for the year ended June 30,
2002, related to the common stock contributions. In addition, the Company
makes matching contributions in the form of Company stock equal to 10% of
each participant's elective deferrals. The Company contributed shares of
the Company's stock valued at $21,750, $24,686, and $26,142 in fiscal year
2004, 2003, and 2002, respectively.
F-18
The following table sets forth the funded status of the Retiree Health
Plan and amounts recognized in the consolidated financial statements as of
June 30, 2004 and 2003 and for the years ended June 30, 2004, 2003, and
2002:
2004 2003
Change in benefit obligation:
Projected benefit obligation
Benefit obligation at beginning of year $ 782,300 $ 602,800
Service costs 33,200 31,100
Interest costs 41,300 44,300
Actuarial (gains) losses (65,000) 123,400
Benefits paid (15,200) (19,300)
------------ ------------
Benefit obligation at end of year 776,600 782,300
------------ ------------
Change in plan assets:
Fair value of plan assets at beginning of year 456,800 470,800
Actual return on plan assets 2,900 5,300
Benefits paid (15,200) (19,300)
------------ ------------
Fair value of plan assets at end of year 444,500 456,800
------------ ------------
Benefit obligation in excess of plan assets 332,100 325,500
Unrecognized transition obligation (176,600) (196,200)
Unrecognized prior service cost (126,600) (144,500)
Unrecognized gains 240,200 225,000
------------ ------------
Net liability recognized $ 269,100 $ 209,800
============ ============
2004 2003 2002
Components of net periodic benefit cost:
Service costs $ 33,200 $ 31,100 $ 26,000
Interest costs 41,300 44,300 39,200
Expected return on plan assets (37,500) (39,000) (42,400)
Amortization of transition obligation 19,600 19,600 19,600
Amortization of unrecognized prior service costs 17,900 17,900 17,900
Actuarial gains (15,200) (21,400) (28,300)
-------------- -------------- --------------
Net periodic benefit cost $ 59,300 $ 52,500 $ 32,000
============== ============== ==============
F-19
2004 2003
Weighted-average assumptions as of June 30:
Discount rate 6.00 % 6.00 %
Expected return on plan assets 8.50 % 8.50 %
Health care inflation rate 10.00 % 8.50 %
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 $4,600 and the accumulated
postretirement benefit obligation by $33,200. A one-percentage-point
decrease in the assumed health care cost trend rate would decrease
interest and service cost by $3,900 and the accumulated postretirement
benefit obligation by $28,600.
Included in the postretirement benefit expense amounts were $55,100 in
2004, $40,260 in 2003 and $26,100 in 2002 related to regulated operations.
The MPSC allows for 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.
9. INCOME TAXES
Significant components of the Company's deferred tax assets and
liabilities as of June 30, 2004 and 2003 are as follows:
2004 2003
--------------------------- ---------------------------
CURRENT LONG-TERM CURRENT LONG-TERM
Deferred tax assets:
Allowances for doubtful accounts $ 114,983 $ - $ 62,824 $ -
Unamortized investment tax credit - 35,208 - 45,887
Contributions in aid of construction - 270,053 - 216,957
Other nondeductible accruals 159,515 - 168,033 173,769
Deferred gain on sale of assets - 18,179 - 28,890
Recoverable purchase gas costs 40,378 - - -
Derivatives 571,296 - 92,802 -
Deferred incentive and pension accrual - 3,461 - 60,983
NOL and charitable contribution carryover - 1,054,253 - 1,124,195
Other 9,526 548,954 219,369 396,360
------------ ------------ ------------ ------------
Total 895,698 1,930,108 543,028 2,047,041
------------ ------------ ------------ ------------
Deferred tax liabilities:
Recoverable purchase gas costs 368,799 - - 494,631
Property, plant, and equipment - 5,812,245 - 5,667,489
Debt issue costs - 97,255 - 121,944
Deferred rate case costs - 29,226 - 39,531
Covenant not to compete - 55,101 - 59,342
Other - 465,662 - -
------------ ------------ ------------ ------------
Total 368,799 6,459,489 - 6,382,937
------------ ------------ ------------ ------------
Net deferred tax asset (liabilities) $ 526,899 $ (4,529,381) $ 543,028 $ (4,335,896)
============ ============ ============ ============
As of June 30, 2004, the Company has a federal net operating loss of
approximately $930,000 which will be carried back to fiscal year ended
June 30, 2002.
F-20
Income tax expense (benefit) for the years ended June 30, 2004, 2003, and
2002 consists of the following:
2004 2003 2002
Current income taxes:
Federal $ (453,156) $ (1,474,595) $ 1,857,616
State (104,315) (86,672) 395,487
-------------- -------------- --------------
Total current income taxes (benefits) (557,471) (1,561,267) 2,253,103
-------------- -------------- --------------
Deferred income taxes:
Federal 138,344 1,124,103 (1,356,354)
State 71,268 (84,654) (360,278)
-------------- -------------- --------------
Total deferred income taxes (benefits) 209,612 1,039,449 (1,716,632)
-------------- -------------- --------------
Total income taxes (benefits) before credits (347,859) (521,818) 536,471
Investment tax credit, net (21,062) (21,062) (21,062)
-------------- -------------- --------------
Total income tax expense (benefit) $ (368,921) $ (542,880) $ 515,409
============== ============== ==============
Income tax expense (benefit) differs from the amount computed by applying
the federal statutory rate to pre-tax income (loss) for the following
reasons:
2004 2003 2002
Tax expense (benefit) at statutory rate of 35% $ (323,834) $ (489,958) $ 469,912
State income tax (benefit), net of federal tax benefit (41,266) (62,435) 59,880
Amortization of deferred investment tax credits (21,062) (21,062) (21,062)
Other 17,241 30,575 6,679
-------------- -------------- --------------
Total income tax expense (benefit) $ (368,921) $ (542,880) $ 515,409
============== ============== ==============
10. SEGMENTS OF OPERATIONS
Effective July 1, 2002, the Company changed the structure of its internal
organization such that the Pipeline Operations was established as a new
segment. The results of this segment reflect operations of oil and gas
gathering systems placed into service in fiscal 2002, and transferred from
EWR to EWD. For fiscal year 2002 and prior years, EWD consisted primarily
of real estate holdings and incurred minimal expenses. The financial
operations of EWD's pipeline assets and real estate holdings are now being
reported as Pipeline Operations.
Summarized financial information for the Company's Natural Gas Operations,
Propane Operations, EWR and Pipeline Operations (inter-company
eliminations between segments primarily consist of gas sales from EWR to
Natural Gas Operations, inter-company accounts receivable, accounts
payable, equity, and subsidiary investment) is as follows:
F-21
NATURAL GAS PROPANE PIPELINE
YEAR ENDED JUNE 30, 2004 OPERATIONS OPERATIONS EWR OPERATIONS ELIMINATIONS CONSOLIDATED
Operating revenue:
Natural gas operations $ 39,362,689 $ (300,000) $ 39,062,689
Propane operations $ 7,963,609 (227,230) 7,736,379
Gas and electric wholesale $ 51,097,486 (25,006,641) 26,090,845
Pipeline Operations $ 401,269 401,269
------------- ------------- ------------- ------------- ------------- -------------
Total operating revenue 39,362,689 7,963,609 51,097,486 401,269 (25,533,871) 73,291,182
------------- ------------- ------------- ------------- ------------- -------------
Gas purchased 28,183,288 4,227,508 (527,230) 31,883,566
Gas and electric - wholesale 51,034,517 (25,006,641) 26,027,876
Distribution, general, and
administrative 6,996,914 2,165,617 860,425 146,604 10,169,560
Maintenance 395,572 84,514 480,086
Depreciation and amortization 1,538,546 547,234 213,172 33,121 2,332,073
Taxes other than income 911,496 241,379 22,260 34,781 1,209,916
------------- ------------- ------------- ------------- ------------- -------------
Operating expenses 38,025,816 7,266,252 52,130,374 214,506 (25,533,871) 72,103,077
------------- ------------- ------------- ------------- ------------- -------------
Operating income (loss) 1,336,873 697,357 (1,032,888) 186,763 1,188,105
Other income (loss) 96,354 180,748 (12,678) 120,853 385,277
Interest expense (1,622,797) (572,522) (253,601) (49,703) (2,498,624)
------------- ------------- ------------- ------------- ------------- -------------
Income (loss) before income taxes (189,570) 305,583 (1,299,167) 257,913 (925,241)
Income taxes benefit (expense) 26,386 (2,475) 444,322 (99,312) 368,921
------------- ------------- ------------- ------------- ------------- -------------
Net income (loss) $ (163,184) $ 303,108 $ (854,845) $ 158,601 $ - $ (556,320)
============= ============= ============= ============= ============= =============
Capital expenditures and
natural gas reserves $ 1,631,549 $ 515,213 $ 74,634 $ 95,299 $ - $ 2,316,695
Total assets $ 47,260,442 $ 12,434,754 $ 8,880,950 $ 1,117,398 $ (8,248,467) $ 61,445,077
F-22
YEAR ENDED JUNE 30, 2003 NATURAL GAS PROPANE PIPELINE
OPERATIONS OPERATIONS EWR OPERATIONS ELIMINATIONS CONSOLIDATED
Operating revenue:
Natural gas operations $ 31,927,242 $ (300,000) $ 31,627,242
Propane operations $ 12,984,676 (197,758) 12,786,918
Gas and electric wholesale $ 49,123,253 (16,088,229) 33,035,024
Pipeline Operations $ 448,681 448,681
------------- ------------- ------------- ------------- ------------- -------------
Total operating revenue 31,927,242 12,984,676 49,123,253 448,681 (16,585,987) 77,897,865
------------- ------------- ------------- ------------- ------------- -------------
Gas purchased 22,054,365 8,959,974 287,074 (497,758) 30,803,655
Gas and electric - wholesale 47,594,331 (16,088,229) 31,506,102
Cost of goods sold 210,661 210,661
Distribution, general, and
administrative 6,006,710 2,693,842 2,827,550 140,927 11,669,029
Maintenance 410,829 85,888 496,717
Depreciation and amortization 1,486,754 622,156 168,537 114,921 2,392,368
Taxes other than income 637,635 198,369 43,977 8,300 888,281
------------- ------------- ------------- ------------- ------------- -------------
Operating expenses 30,596,293 12,560,229 50,845,056 551,222 (16,585,987) 77,966,813
------------- ------------- ------------- ------------- ------------- -------------
Operating income (loss) 1,330,949 424,447 (1,721,803) (102,541) (68,948)
Other income 93,850 187,329 19,632 1,299 302,110
Interest expense (998,650) (403,160) (224,052) (7,180) (1,633,042)
------------- ------------- ------------- ------------- ------------- -------------
Income (loss) before income taxes 426,149 208,616 (1,926,223) (108,422) (1,399,880)
Income taxes benefit (expense) (245,182) (68,833) 839,931 16,964 542,880
------------- ------------- ------------- ------------- ------------- -------------
Net income (loss) $ 180,967 $ 139,783 $ (1,086,292) $ (91,458) $ - $ (857,000)
============= ============= ============= ============= ============= =============
Capital expenditures and natural
gas reserves $ 2,660,788 $ 878,356 $ 80,776 $ 510,479 $ - $ 4,130,399
Total assets $ 47,031,703 $ 12,624,539 $ 10,067,276 $ 2,587,576 $ (12,284,474) $ 60,026,620
F-23
YEAR ENDED JUNE 30, 2002 NATURAL GAS PROPANE PIPELINE
OPERATIONS OPERATIONS EWR OPERATIONS ELIMINATIONS CONSOLIDATED
Operating revenue:
Natural gas operations $ 39,823,393 $ (308,333) $ 39,515,060
Propane operations $ 10,870,327 (214,175) 10,656,152
Gas and electric wholesale $ 55,887,485 (16,972,811) 38,914,674
Pipeline operations $ 154,494 154,494
------------- ------------- ------------- ------------- ------------- -------------
Total operating revenue 39,823,393 10,870,327 55,887,485 154,494 (17,495,319) 89,240,380
------------- ------------- ------------- ------------- ------------- -------------
Gas purchased 29,773,507 6,621,170 (522,508) 35,872,169
Gas and electric - wholesale 55,495,220 (16,972,811) 38,522,409
Cost of goods sold 195,254 195,254
Distribution, general, and
administrative 5,033,521 2,157,761 1,543,738 55,163 8,790,183
Maintenance 387,468 78,303 465,771
Depreciation and amortization 1,388,254 622,039 34,150 14,726 2,059,169
Taxes other than income 687,819 207,086 50,284 1,025 946,214
------------- ------------- ------------- ------------- ------------- -------------
Operating expenses 37,270,569 9,686,359 57,318,646 70,914 (17,495,319) 86,851,169
------------- ------------- ------------- ------------- ------------- -------------
Operating income (loss) 2,552,824 1,183,968 (1,431,161) 83,580 2,389,211
Other income (loss) 153,935 199,477 304,878 (403) 657,887
Interest expense (expense) (1,170,726) (426,968) (104,308) (2,490) (1,704,492)
------------- ------------- ------------- ------------- ------------- -------------
Income (loss) before income taxes 1,536,033 956,477 (1,230,591) 80,687 1,342,606
Income taxes benefit (600,339) (351,271) 468,584 (32,383) (515,409)
------------- ------------- ------------- ------------- ------------- -------------
Net income (loss) $ 935,694 $ 605,206 $ (762,007) $ 48,304 $ - $ 827,197
============= ============= ============= ============= ============= =============
Capital expenditures and natural
gas reserves $ 3,122,484 $ 1,221,971 $ 1,279,579 $ 817,962 $ - $ 6,441,996
Total assets $ 34,835,339 $ 12,761,255 $ 11,639,827 $ 69,238 $ (2,010,279) $ 57,295,380
11. STOCK OPTION AND SHAREHOLDER RIGHTS PLANS
STOCK OPTIONS -- The Energy West Incorporated 2002 Stock Option Plan is a
stock option plan (the "Option Plan") that provides for the issuance of up
to 200,000 shares of the Company's common stock to be issued to certain
key employees. As of June 30, 2004, 156,037 shares were available for
grant under the option plan. Additionally, the Company's 1992 Stock Option
Plan (the "1992 Option Plan"), which expired in September 2002, provided
for the issuance of up to 100,000 shares of the Company's common stock
pursuant to options issuable to certain key employees. Under the 2002
Option Plan and the 1992 Option Plan (collectively, "the Option Plans"),
the option price may not be less than 100% of the common stock fair market
value on the date of grant (in the event of incentive stock options, 110%
of the fair market value if the employee
F-24
owns more than 10% of the Company's outstanding common stock). Pursuant to
the Option Plans, the options vest over four years and are exercisable
over a five-year period from date of issuance. When the 1992 Option Plan
expired in September 2002, 12,600 shares remained unissued and were no
longer available for issuance.
A summary of activity under the Option Plan for the years ended June 30,
2004, 2003, and 2002 is as follows:
2004 2003 2002
-------------------------- -------------------------- --------------------------
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 130,420 $ 8.624 32,420 $ 9.089 56,420 $ 8.894
Granted - - 114,500 8.491 - -
Exercised - - - (24,000) 8.523
Forfeited (53,420) 8.816 (16,500) 8.614 -
------- ------- -------
Outstanding at end of year 77,000 8.491 130,420 8.624 32,420 9.089
======= ======= =======
Options exercisable at year end 30,800 8.491 48,820 8.846 19,452 9.089
======= ======= =======
Weighted Average Fair Value of
options granted during the year - 1.62 -
======= ======= =======
At June 30, 2004, the weighted average exercise price for the remaining
outstanding shares was $8.491 per share. The weighted-average remaining
contractual life of the remaining outstanding shares was three years. At
June 30, 2004, there were approximately 85,500 shares available for grant.
SHAREHOLDER RIGHTS -- On June 3, 2004, the Company's Board of Directors
declared a dividend of one Right to purchase one one-thousandth share of
the Company's Series A Participating Preferred Stock for each outstanding
share of Common Stock of the Company. Each Right entitles the registered
holder to purchase from the Company one one-thousandth of a share of
Series A Participating Preferred Stock at an exercise price of $24.00,
subject to adjustment (the "Purchase Price"). The Rights generally will be
exercisable only if a person or group acquires beneficial ownership of 15%
or more of the Company's common stock or commences a tender or exchange
offer upon consummation of which such person or group would beneficially
own 15% or more of the Company's common stock. Any person or group owning
15% or more of the Company's common stock on June 3, 2004 will not cause
the Rights to become exercisable unless such person or group acquires
additional common stock. Once exercisable, then each holder of a Right
that has not theretofore been exercised will thereafter have the right to
receive, upon exercise, Common Shares having a value equal to two times
the Purchase Price.
F-25
12. COMMITMENTS AND CONTINGENCIES
COMMITMENTS -- In 2000, the Company entered into a ten year transportation
agreement with Northwestern Energy that fixed the cost of pipeline and
storage capacity. Based on original contract prices, the minimum
obligation under this agreement at June 30, 2004 is as follows:
Year ending June 30:
2005 $ 4,367,715
2006 4,367,715
2007 4,286,101
2008 4,258,896
2009 4,258,896
2010 2,839,264
------------
Total $ 24,378,587
============
ENVIRONMENTAL CONTINGENCY -- The Company owns property on which it
operated a manufactured gas plant from 1909 to 1928. The site is currently
used as an office facility for Company field personnel and storage
location for certain equipment and materials. The coal gasification
process utilized in the plant resulted in the production of certain
by-products, which have been classified by the federal government and the
State of Montana as hazardous to the environment.
In the summer of 1999, the Company received approval from the Montana
Department of Environmental Quality ("MDEQ") for its plan for remediation
of soil contaminants. The Company has completed its remediation of soil
contaminants and in April of 2002 received a closure letter from MDEQ
approving the completion of such remediation program.
The Company and its consultants continue to work with the MDEQ relating to
the remediation plan for water contaminants. The MDEQ has established
regulations that allow water contaminants at a site to exceed standards if
it is technically impracticable to achieve them. Although the MDEQ has not
established guidance to attain a technical waiver, the U.S. Environmental
Protection Agency ("EPA") has developed such guidance. The EPA guidance
lists factors which render mediations technically impracticable. The
Company has filed a request for a waiver respecting compliance with
certain standards with the MDEQ.
At June 30, 2004, the Company had incurred cumulative costs of
approximately $1,925,000 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, 2004, the Company had recovered approximately $1,440,000 through such
surcharges. As of June 30, 2004, the cost remaining to be recovered is
$485,000.
On April 15, 2003, the MPSC issued an Order to Show Cause Regarding the
Environmental Surcharge. The MPSC determined that the initial order
allowing the collection of the surcharge was intended by the MPSC to cover
only a two year collection period, after which it would contemplate
additional filings by the Company, if necessary. The Company responded to
the Show Cause Order and the MPSC subsequently ordered the termination of
the Environmental Surcharge on August 20, 2003. The Company filed a
request with the commission to continue the collection of the surcharge
until all expenses have been recovered. This request was approved by the
MPSC and the surcharge was reinstated in September 2004. The Company is
required, under the Commission's most recent order, to file with the MPSC
every two years for approval to continue the recovery of the surcharge.
F-26
DERIVATIVE CONTINGENCIES -- Among the risks involved in natural gas
marketing is the risk of nonperformance by counterparties to contracts for
purchase and sale of natural gas. EWR is party to certain contracts for
purchase or sale of natural gas at fixed prices for fixed time periods.
Some of these contracts are recorded as derivatives, valued on a
mark-to-market basis.
LITIGATION -- 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 involved in the following described litigation.
On June 17, 2003, EWR and PPL Montana, LLC ("PPLM") reached agreement on a
settlement of a lawsuit involving a wholesale electricity supply contract.
Under the terms of the settlement, EWR paid PPLM a total of $3,200,000,
consisting of an initial payment of $1,000,000 on June 17, 2003, and a
second payment of $2,200,000 on September 30, 2003, terminating all
proceedings in the case. EWR had established reserves and accruals in
fiscal year 2001 of approximately $3,032,000 to pay a potential settlement
with PPLM and the remaining $168,000 was charged to operating expenses in
fiscal year 2003.
On August 8, 2003, the Company reached agreement with the Montana
Department of Revenue ("DOR") to settle a claim that the Company had
under-reported its personal property for the years 1997 - 2002 and that
additional property taxes and penalties should be assessed. The settlement
amount is being paid in ten annual installments of $243,000 each,
beginning November 30, 2003.
The Company initially determined that it was entitled to recover the
amounts paid in connection with the DOR settlement through future rate
adjustments as a result of legislation permitting "automatic adjustments"
to rates to recover such property tax increases. The MPSC, however,
interpreted the new legislation as allowing recovery of only a portion of
the higher property taxes. Rates recovering the portion of the higher
taxes permitted under the MPSC's interpretation of the legislation went
into effect on January 1, 2004. The Company has since obtained interim
rate relief which includes full recovery of the property tax associated
with the DOR settlement.
F-27
OPERATING LEASES -- The Company leases certain properties including land,
office buildings, and other equipment under non-cancelable operating
leases through fiscal year 2009. The future minimum lease payments on
these leases are as follows:
Year ended June 30:
2005 $ 142,599
2006 142,599
2007 90,624
2008 90,624
2009 6,600
----------
Total $ 473,046
==========
Lease expense resulting from operating leases for the years ended June 30,
2004, 2003, and 2002 totaled $171,765, $189,906, and $189,906,
respectively.
LETTERS OF CREDIT -- Outstanding letters of credit totaled $1,700,000 and
$4,400,000 at June 30, 2004 and 2003, respectively. The letters of credit
guarantee the Company's performance to third parties for gas and electric
purchases and gas transportation services.
13. FINANCIAL 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 counterparty performance. The Company has
established policies and procedures to manage such risks. The Company has
a Risk Management Committee (RMC), comprised of Company officers and
management to oversee the Company's risk management program as defined in
its risk management policy. The purpose of the risk management program is
to minimize adverse impacts on earnings resulting from volatility of
energy prices, counterparty credit risks, and other risks related to the
energy commodity business.
In order to mitigate the risk of natural gas market price volatility
related to firm commitments to purchase or sell natural gas or
electricity, from time to time the Company and its subsidiaries have
entered into hedging arrangements. Such arrangements may be used to
protect profit margins on future obligations to deliver gas at a fixed
price, or to protect against adverse effects of potential market price
declines on future obligations to purchase gas at fixed prices.
The Company accounts for certain of such purchases or sale agreements in
accordance with SFAS No. 133. Under SFAS 133, such contracts are reflected
in the Company's financial statements as derivative assets or derivative
liabilities and valued at "fair value," determined as of the date of the
balance sheet. Fair value accounting treatment is also referred to as
"mark-to-market" accounting. Mark-to-market accounting results in
disparities between reported earnings and realized cash flow, because
changes in the derivative values are reported in the Company's
Consolidated Statement of Operations as an increase or (decrease) in
"Revenues - Gas and Electric - Wholesale" without regard to whether any
cash payments 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. SFAS No. 133 requires
that contracts for purchase or sale at fixed prices and volumes must be
valued at fair value (under mark-to-market accounting) unless the
contracts qualify for treatment as a "normal purchase or sale."
F-28
Quoted market prices for natural gas derivative contracts of the Company
and its subsidiaries are generally not available. Therefore, to determine
the fair value of natural gas derivative contracts, the Company uses
internally developed valuation models that incorporate independently
available current and forecasted pricing information.
As of June 30, 2004, these agreements were reflected on the Company's
consolidated balance sheet as derivative assets and liabilities at an
approximate fair value as follows:
ASSETS LIABILITIES
Contracts maturing during fiscal year 2005 $ 199,248 $ 733,822
Contracts maturing during fiscal years 2006 and 2007 - 606,862
Contracts maturing during fiscal years 2008 and 2009 - 343,992
------------ ------------
Total $ 199,248 $ 1,684,676
============ ============
14. SUBSEQUENT EVENTS
As of August 30, 2004, the Company and its lender under its credit
facility (the "LaSalle Facility") amended certain covenants as follows:
(1) increased the total debt to capital ratio from .65 to .70, (2) allowed
the inclusion of extraordinary expenses incurred by the Company for legal
fees and costs of the PPLM litigation, expenses and costs associated with
the credit facilities, proxy contest costs, and the costs of adoption of
the shareholder rights plan, in determining the interest coverage ratio,
and (3) waived compliance with the ratios referred to in (1) and (2) above
as of June 30, 2004 in addition to a shareholder's acquisition of more
than 15% of the outstanding common stock of the Company.
As of September 10, 2004, the LaSalle Facility was amended to extend from
September 30, 2004 until October 31, 2004, the deadline for the Company to
repay the $2,000,000 term loan under the LaSalle Facility, with an
infusion of new equity.
On October 20, 2004, but effective as of September 28, 2004, the LaSalle
Facility was amended to extend until October 29, 2004, the deadline for
the Company to deliver its audited financial statements for the fiscal
year ended June 30, 2004.
On November 2, 2004, the Company executed a letter agreement effective as
of September 28, 2004 amending the LaSalle Facility. The letter agreement
provides for the extension of the deadline to deliver audited financial
statements for fiscal year 2004 from October 29, 2004 to November 12,
2004.
As of November 2, 2004, the Company executed an amendment to the LaSalle
Facility, which provides for an extension from October 31, 2004 to
November 30, 2004 of the deadlines under the LaSalle Facility in
connection with: (i) the termination date of the revolving facility and
(ii) the date to consummate infusions of new equity of at least $2.0
million to repay the $2.0 million term loan under the LaSalle Facility.
As of November 30, 2004, the Company executed an agreement with its lender
providing for (i) an extension of the revolving facility until
November 28, 2005; (ii) an extension of the date to consummate infusions
of new equity of at least $2.0 million and to repay the $2.0 million term
loan to October 1, 2005; (iii) a conditional waiver of the deadline to
deliver audited financial statements for fiscal year 2004 and the deadline
to deliver financial statements for the fiscal quarter ended September 30,
2004; (iv) a waiver of the technical default that otherwise would have
been caused by the restatement of financial results of prior periods; (v)
modification of interest rates applicable to the $2.0 million term loan;
(vi) a limitation of $1.0 million on total loans and additional capital
investment from the Company to EWR; and (vii) waivers of certain financial
covenant defaults as of September 30, 2004.
F-29
15. RESTATEMENT OF CONSOLIDATED FINANCIAL STATEMENTS
On September 29, 2004, the Company announced that it was delaying the
filing of its Annual Report on Form 10-K in order to complete a review of
the accounting for certain contracts. Based on the results of its review,
the Company has corrected its accounting and previous valuation of certain
of EWR's contracts for fiscal years 2002 and 2003, and the first three
quarters of fiscal year 2004, and has restated its earnings for those
periods.
The Company's review of EWR's contracts included an evaluation of a gas
purchase agreement and a gas sales agreement entered into during fiscal
year 2002 involving counterparties who are affiliated with each other. The
gas purchase agreement has previously been reflected in the Company's
financial statements as a derivative asset. The gas sales agreement was
previously classified by the Company as a normal sales contract, and
therefore was not reflected on the Company's financial statements as a
derivative liability. The Company determined that a shorter period similar
to that of the gas sales agreement should have been used in the
determination of the fair value of the gas purchase agreement and that the
gas sales agreement does not qualify for the "normal purchase and sale"
exception. As a result the consolidated financial statements have been
restated to reflect a significant reduced fair value for the gas purchase
agreement and the gas sales agreement as a derivative liability at its
estimated fair value.
F-30
In the course of its review, the Company also determined that the fair
value of a small gas purchase contract and a small gas sales contract
entered into by EWR during the fiscal quarter ended December 31, 2003, had
not been properly reflected in the Company's financial statements. The
Company has reflected the fair value of these contracts in its restated
financial statements.
As discussed in the table that follows, the accompanying consolidated
financial statements as of June 30, 2003 and for the fiscal years ended
June 30, 2002 and June 30, 2003 have been restated from amounts previously
reported to reflect the correction of the accounting and valuation of the
gas purchase and gas sale contracts discussed above.
None of the adjustments affects the Company's cash flows or cash balances.
The Company's cumulative gain (loss) in the portfolio of contracts valued
on a mark-to-market basis will be realized in later periods as contracts
settle or are performed and/or as natural gas prices change.
F-31
A summary of the significant effects of the restatement is as follows:
FOR THE YEAR ENDED FOR THE YEAR ENDED
JUNE 30, 2003 JUNE 30, 2002
--------------------------- ---------------------------
AS AS
PREVIOUSLY PREVIOUSLY
REPORTED AS RESTATED REPORTED AS RESTATED
CONSOLIDATED STATEMENTS OF OPERATIONS
REVENUES:
Gas and electric - wholesale $ 34,283,190 $ 33,035,024 $ 39,846,739 $ 38,914,674
Total Revenues 79,146,031 77,897,865 90,172,445 89,240,380
Operating Income (Loss) 1,179,218 (68,948) 3,321,276 2,389,211
Income (loss) before income taxes (151,714) (1,399,880) 2,274,671 1,342,606
Income tax benefit (expense) 62,835 542,880 (873,881) (515,409)
Net income (loss) (88,879) (857,000) 1,400,790 827,197
Earnings (loss) per common share:
Basic (0.03) (0.33) 0.55 0.32
Diluted (0.03) (0.33) 0.55 0.32
AS OF JUNE 30, 2003
----------------------------
AS
PREVIOUSLY
REPORTED AS RESTATED
CONSOLIDATED BALANCE SHEET
ASSETS
Derivative assets $ 2,719,640 $ 623,635
Total current assets 18,171,898 15,790,223
LIABILITIES AND CAPITALIZATION
Derivative liabilities 780,703 864,929
Total current liabilities 21,568,695 21,832,786
Deferred income taxes 5,460,083 4,335,896
Long Term Liabilities 10,706,689 9,402,637
Retained earnings 9,852,739 8,511,025
Total stockholder's equity 15,298,459 13,956,745
F-32
16. QUARTERLY INFORMATION (UNAUDITED)
As discussed in Note 15 above, the Company has determined to restate its
consolidated financial statements for fiscal years 2003 and 2002.
Quarterly results (unaudited) for the years ended June 30, 2004 and 2003
including the effect of the restatement are as follows (in thousands,
except per share data):
FIRST QUARTER SECOND QUARTER THIRD QUARTER
-------------------------- -------------------------- --------------------------
YEAR ENDED JUNE 30, 2004 AS PREVIOUSLY AS PREVIOUSLY AS PREVIOUSLY
REPORTED AS RESTATED REPORTED AS RESTATED REPORTED AS RESTATED FOURTH QUARTER
-------------------------- -------------------------- -------------------------- ---------------------
Revenues $ 12,280 $ 12,488 $ 22,812 $ 22,626 $ 24,581 $ 24,447 $ 13,730
Operating income (loss) (716) (508) 1,079 893 1,695 1,561 (758)
Net income (loss) (622) (494) 313 199 669 586 (847)
Basic earnings (loss) per
common share (0.24) (0.19) 0.12 0.08 0.26 0.23 (0.33)
Diluted earnings (loss)
per share (0.24) (0.19) 0.12 0.08 0.26 0.23 (0.33)
FIRST QUARTER SECOND QUARTER THIRD QUARTER FOURTH QUARTER
-------------------------- -------------------------- -------------------------- --------------------------
YEAR ENDED JUNE 30, AS PREVIOUSLY AS PREVIOUSLY AS PREVIOUSLY AS PREVIOUSLY
2003 REPORTED AS RESTATED REPORTED AS RESTATED REPORTED AS RESTATED REPORTED AS RESTATED
-------------------------- -------------------------- -------------------------- --------------------------
Revenues $ 10,363 $ 9,876 $ 22,485 $ 22,160 $ 29,617 $ 29,297 $ 16,681 $ 16,565
Operating income
(loss) (1,312) (1,798) 471 146 3,345 3,025 (1,325) (1,441)
Net income (loss) (1,021) (1,320) 121 (79) 1,779 1,582 (968) (1,040)
Basic earnings
(loss) per common
share (0.40) (0.51) 0.05 (0.03) 0.69 0.61 (0.37) (0.40)
Diluted earnings
(loss) per share (0.40) (0.51) 0.05 (0.03) 0.69 0.61 (0.37) (0.40)
F-33