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FORM 10-Q
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D. C. 20549
X QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2003
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM TO
------------ ------------
COMMISSION FILE NUMBER 0-14183
------------------------------
ENERGY WEST, INCORPORATED
-----------------------------------------------------
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)
MONTANA 81-0141785
- ------------------------------- -------------------
(STATE OR OTHER JURISDICTION OF (I.R.S. EMPLOYER
INCORPORATION OR ORGANIZATION IDENTIFICATION NO.)
1 FIRST AVENUE SOUTH, GREAT FALLS, MT. 59401
--------------------------------------------------
(ADDRESS OF PRINCIPAL EXECUTIVE OFFICES) (ZIP CODE)
Registrant's telephone number, including area code (406)-791-7500
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days.
Yes X No
Indicate by checkmark whether the registrant is an accelerated filer (as defined
in Rule 12b-2 of the Exchange Act).
Yes No X
Indicate the number of shares outstanding of each of the issuer's classes of
common stock, as of the latest practicable date.
Class Outstanding at September 30, 2003
(Common stock, $.15 par value) 2,595,250 shares
ENERGY WEST, INCORPORATED
INDEX TO FORM 10-Q
PAGE NO.
PART I - FINANCIAL INFORMATION
Item 1 - Financial Statements (UNAUDITED)
Condensed Consolidated Balance Sheets as of
September 30, 2003, September 30, 2002 and June 30, 2003 1
Condensed Consolidated Statements of Operations -
three months ended September 30, 2003 and 2002 2
Condensed Consolidated Statements of Cash Flows -
three months ended September 30, 2003 and 2002 3
Notes to Condensed Consolidated Financial Statements 4-9
Item 2 - Management's discussion and analysis of
financial condition and results of operations 9-20
Item 3 -- Quantitative and Qualitative Disclosures about
Market Risk 20-21
Item 4 -- Controls and Procedures 21
Part II Other Information
Item 1 - Legal Proceedings 22
Item 2 - Changes in Securities 22
Item 3 - Defaults upon Senior Securities 22
Item 4 - Submission of Matters to a Vote of Security Holders 22
Item 5 - Other Information 22
Item 6 -- Exhibits and Reports on Form 8-K 22-23
Signatures 24-28
Item 1. Financial Statements
FORM 10Q
ENERGY WEST, INCORPORATED
CONDENSED CONSOLIDATED BALANCE SHEETS
SEP 30 SEP 30 June 30
2003 2002 2003
(Unaudited) (Unaudited) (Unaudited)
---------------------------------------------------
Current assets
Cash and cash equivalents $ 1,791,264 $ 94,289 $ 1,938,768
Restricted cash 2,600,000
Accounts and note receivable (net) 5,886,687 5,710,019 7,971,632
Derivative assets 2,135,647 2,438,562 2,719,640
Natural gas and propane inventories 6,240,812 5,777,455 1,038,690
Materials and supplies 376,083 627,488 352,982
Prepayments and other 747,762 715,992 371,490
Deferred tax assets 317,957 1,328,184 828,698
Deferred purchase gas costs 1,205,071 1,067,109
Prepaid income tax receivable 2,240,768 1,137,530 1,882,889
---------------------------------------------------
Total current assets 23,542,051 17,829,519 18,171,898
Note receivable 461,060
Property, plant and equipment, net 38,557,024 37,151,932 39,576,596
Deferred charges 4,828,244 1,905,341 4,388,372
Other assets 263,266 300,869 271,429
---------------------------------------------------
Total assets $67,651,645 $57,187,661 $62,408,295
===================================================
Capitalization and liabilities
Current liabilities:
Lines of credit $ 16,601,548 $ 9,019,881 $ 6,104,588
Current portion of long term-debt 537,451 507,147 532,371
Accounts payable 6,756,191 4,930,926 8,841,779
Derivative liabilities 636,628 780,703
Refundable cost of gas purchases 227,514
Accrued and other current liabilities 3,495,400 5,215,369 5,309,254
---------------------------------------------------
Total current liabilities 28,027,218 19,900,837 21,568,695
---------------------------------------------------
Long-term liabilities:
Deferred tax liabilities 4,949,615 4,745,249 5,460,083
Deferred investment tax credits 350,141 371,203 355,406
Other long-term liabilities 4,953,419 1,970,129 4,891,200
---------------------------------------------------
Total $10,253,175 $7,086,581 10,706,689
---------------------------------------------------
Long-Term Debt $14,694,349 $15,281,260 14,834,452
Stockholders' equity
Preferred stock - $.15 par value
Authorized - 1,500,000
Issued -- none
Common stock -- $.15 par value 389,295 386,341 $389,295
Authorized - 3,500,000
Outstanding -- 2,595,250 shares outstanding
at September 30, 2003; 2,575,565 at September 30, 2002;
and 2,595,250 at June 30, 2003.
Capital in excess of par value 5,056,425 4,884,927 5,056,425
Retained earnings 9,231,183 9,647,715 9,852,739
---------------------------------------------------
Total stockholders' equity 14,676,903 14,918,983 15,298,459
---------------------------------------------------
Total capitalization $29,371,252 $30,200,243 $30,132,911
---------------------------------------------------
Total capitalization and liabilities $67,651,645 $57,187,661 $62,408,295
===================================================
The accompanying notes are an integral part of these condensed
financial statements.
1
FORM 10Q
ENERGY WEST, INCORPORATED
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
Three Months Ended
Sep 30
2003 2002
(Unaudited) (Unaudited)
-----------------------------
Revenues:
Natural gas operations $ 4,663,008 $ 2,980,375
Propane operations 1,181,901 1,062,709
Gas and electric-wholesale 6,325,300 6,236,039
Pipeline 109,350 83,744
-----------------------------
Total revenues 12,279,559 10,362,867
-----------------------------
Expenses:
Gas & propane purchased 3,743,982 2,168,669
Gas and electric-wholesale 5,687,031 5,830,935
Distribution, general and administrative 2,573,725 2,729,594
Maintenance 109,334 164,551
Depreciation and amortization 617,632 558,301
Taxes other than income 263,862 222,552
-----------------------------
Total operating expenses 12,995,566 11,674,602
-----------------------------
Operating loss (716,007) (1,311,735)
Non-operating income 192,617 77,970
Interest expense:
Long-term debt 284,316 292,612
Lines of credit 161,781 94,488
-----------------------------
Total interest expense 446,097 387,100
-----------------------------
Loss before income tax benefit (969,487) (1,620,865)
Income tax benefit (347,931) (600,290)
-----------------------------
Net Loss ($621,556) ($1,020,575)
=============================
Earnings per common share:
Basic and diluted loss per common share ($0.24) ($0.40)
Weighted average common shares outstanding:
Basic 2,595,250 2,573,128
Diluted 2,595,250 2,573,128
The accompanying notes are an integral part of these condensed
financial statements.
2
FORM 10Q
ENERGY WEST, INCORPORATED
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
Three Months Ended
Sep 30
2003 2002
(Unaudited) (Unaudited)
-----------------------------
Cash flow from operating activities:
Net loss ($621,556) ($1,020,575)
Adjustment to reconcile net loss to net cash flows
provided by operating activities
Depreciation and amortization, including deferred charges and
financing costs 668,660 605,065
Gain on sale of property, plant & equipment (338,204)
Deferred gain on sale of assets (5,907) (5,907)
Investment tax credit - net (5,265) (5,265)
Deferred income taxes - net 267 305,174
Change in operating assets and liabilities
Accounts receivable - net 1,984,946 2,534,220
Derivative assets 583,993 429,155
Natural gas and propane inventory (5,202,122) (136,795)
Prepayments and other (2,994,780) (270,340)
Recoverable/refundable cost of gas purchases (137,962) (1,796,645)
Accounts payable (2,085,591) (4,482,767)
Derivative liabilities (144,075)
Other assets and liabilities (2,590,753) (373,713)
------------------------------
Net cash used in operating activities (10,888,349) (4,218,393)
Cash flow from investing activities:
Construction expenditures (466,239) (1,187,045)
Proceeds from sale of property, plant & equipment 828,940
Collection of long-term notes receivable 3,300
Customer advances for construction 13,600 21,660
Proceeds from contributions in aid of constructions (400) 1,104
------------------------------
Net cash provided by (used) in investing activities 375,901 (1,160,981)
Cash flow from financing activities:
Repayment of Long-term debt (132,016) (81,089)
Proceeds from lines of credit 21,197,090 11,801,987
Repayment of lines of credit (10,700,130) (6,282,106)
Dividends on common stock (332,786)
------------------------------
Net cash provided by financing activities 10,364,944 5,106,006
------------------------------
Net increase (decrease) in cash and cash equivalents (147,504) (273,368)
Cash and cash equivalents at beginning of year 1,938,768 367,657
------------------------------
Cash and cash equivalents at end of period $ 1,791,264 $94,289
==============================
The accompanying notes are an integral part of these condensed
financial statements.
3
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
SEPTEMBER 30, 2003
NOTE 1 - BASIS OF PRESENTATION
The accompanying unaudited condensed consolidated financial statements
of Energy West, Incorporated and its subsidiaries (the Company) have been
prepared in accordance with accounting principles generally accepted in the
United States of America for interim financial information and with the
instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do
not include all of the information and footnotes required by generally accepted
accounting principles for complete financial statements. In the opinion of
management, all adjustments (consisting of normal recurring accruals) considered
necessary for a fair presentation have been included. Operating results for the
three month period ended September 30, 2003 are not necessarily indicative of
the results that may be expected for the fiscal year ending June 30, 2004. The
financial statements should be read in conjunction with the audited consolidated
financial statements and footnotes thereto included in the Company's annual
report on Form 10-K for the fiscal year ended June 30, 2003.
Certain non-regulated, non-utility operations are conducted by three
wholly-owned subsidiaries of the Company: Energy West Propane, Inc. ("EWP");
Energy West Resources, Inc. ("EWR"); and Energy West Development, Inc. ("EWD").
EWP is engaged in wholesale distribution of bulk propane in Arizona, and is
engaged in retail distribution of bulk propane in Arizona. EWR markets gas and,
on a limited basis, electricity in Montana and Wyoming, and owns certain natural
gas production properties in Montana. EWD owns a natural gas gathering system
that is located in both Montana and Wyoming and an interstate natural gas
transportation pipeline also that runs between Montana and Wyoming.
The Company's reporting segments are: Natural Gas Operations, Propane
Operations, EWR and Pipeline Operations. An application has been granted by the
Federal Energy Regulatory Commission ("FERC") and EWD began operations of the
interstate natural gas pipeline as a transmission pipeline on July 1, 2003. The
revenue and expenses associated with this transmission pipeline are included
in the Pipeline Operations segment.
NOTE 2 -- DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITY
Management of Risks Related to Derivatives--The Company and its
subsidiaries are subject to certain risks related to changes in certain
commodity prices and risks of counter-party performance. The Company has
established certain policies and procedures to manage such risks. The Company
has a Risk Management Committee ("RMC"), comprised of Company officers 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,
counter-party credit risks, and other risks related to the energy commodity
business.
General---From time to time the Company or its subsidiaries may use
derivative financial contracts to mitigate the risk of commodity price
volatility related to firm commitments to purchase and sell natural gas or
electricity. The Company may use such arrangements to protect its profit margin
on future obligations to deliver quantities of a commodity at a fixed price.
Conversely, such arrangements may be used to hedge against future market price
declines where the Company or a subsidiary enters into an obligation to purchase
a commodity at a fixed price in the future. The Company accounts for such
financial instruments in accordance with Statement of Financial Accounting
Standard ("SFAS") No. 133, Accounting for Derivative Instruments and Hedging
Activities, as amended by SFAS No. 138, Accounting for Certain Derivative
Instruments and Certain Hedging Activities.
In accordance with SFAS No. 133, contracts that do not qualify as
normal purchase and sale contracts must be reflected in the Company's financial
statements at fair value, determined as of the date of the balance sheet. This
accounting treatment is also referred to as "mark-to-market" accounting.
Mark-to-market accounting treatment can result in a disparity between reported
earnings and realized cash flow, because
4
changes in the value of the financial instrument are reported as income or loss
even though no cash payment may have been made between the parties to the
contract. If such contracts are held to maturity, the cash flow from the
contracts, and their hedges, are realized over the life of the contract.
Quoted market prices for natural gas derivative contracts of the
Company or its subsidiaries generally are not available. Therefore, to determine
the fair value of natural gas derivative contracts, the Company uses internally
developed valuation models that incorporate independently available current and
historical pricing information.
The Company's wholly owned subsidiary, EWR, was party to a number of
contracts that were valued on a mark-to-market basis under SFAS No. 133.
Although certain firm commitments for the purchase and sale of natural gas could
have been classified as normal purchases and sales and excluded from the
requirements of SFAS No. 133, as described above, EWR elected to treat these
contracts as derivative instruments under SFAS No. 133 in order to match
contracts for the purchase and sale of natural gas for financial reporting
purposes. Such contracts were recorded in the Company's consolidated balance
sheet at fair value. Periodic mark-to-market adjustments to the fair values of
these contracts are recorded as adjustments to gas costs.
As of September 30, 2003, these agreements were reflected on the Company's
consolidated balance sheet as derivative assets and liabilities at an
approximate aggregate fair value as follows:
ASSETS LIABILITIES
Contracts maturing in one year or less: $ 600,539 $162,323
Contracts maturing in two to three years: 1,180,503 324,673
Contracts maturing in four to five years: 305,992 129,119
Contracts maturing in five years or more: 48,613 20,513
---------- --------
Total $2,135,647 $636,628
========== ========
During the first quarter of fiscal 2004, the Company has not entered into
any new contracts that have required mark-to-market accounting under SFAS No.
133.
Natural Gas and Propane Operations--In the case of the Company's regulated
divisions, gains or losses resulting from the derivative contracts are subject
to deferral under regulatory procedures approved by the public service
regulatory commissions of Montana, Wyoming and Arizona. Therefore, related
derivative assets and liabilities are offset with corresponding regulatory
liability and asset amounts included in "Recoverable Cost of Gas Purchases",
pursuant to SFAS No. 71, Accounting for the Effects of Certain Types of
Regulation.
NOTE 3 -- INCOME TAXES
Income tax benefit differs from the amount computed by applying the
federal statutory rate to pre-tax loss as demonstrated in the following table:
THREE MONTHS ENDED
SEPTEMBER 30
2003 2002
Tax benefit at statutory rates - 34%.......................... ($327,839) ($551,094)
State tax benefit, net of federal tax benefit................. (52,619) (37,349)
Amortization of deferred investment tax credits............... (5,266) (5,266)
Other......................................................... 37,793 (6,581)
--------- -------
Total income tax benefit...................................... ($347,931) ($600,290)
========= =========
5
NOTE 4 -- LINES OF CREDIT
On September 30, 2003, the Company established a $23,000,000 revolving
line of credit (the "LaSalle Facility") with LaSalle Bank National Association,
as Agent for certain banks. The LaSalle Facility replaced the Company's existing
credit facility with Wells Fargo Bank Montana National Association (the "Wells
Fargo Facility") and the amount due under the Wells Fargo Facility was paid in
full out of the proceeds of the LaSalle Facility. Borrowings under the LaSalle
Facility are secured by liens on substantially all of the assets of the Company
and its subsidiaries.
The LaSalle Facility provides that the maximum availability under the
facility will be reduced from $23,000,000 to $15,000,000 no later than March 31,
2004. As a result of the provisions providing for the reduction in the maximum
availability under the LaSalle Facility, the Company will be required to
refinance or restructure its long term debt by March 31, 2004.
The terms of the LaSalle Facility also provide that the Company cannot
pay dividends to its shareholders during the period prior to the refinancing or
restructuring of the Company's Long Term Debt. In June 2003, the Company
suspended its dividend to allow for strengthening of the Company's balance
sheet. The Company expects that it will be able to accomplish the long-term debt
restructuring by March 31, 2004.
Under the LaSalle Facility, the Company has the option to pay interest
at either the London Interbank Offered Rate (LIBOR) plus 250 basis points (bps)
or the higher of (a) the rate publicly announced from time to time by LaSalle as
its "prime rate" or (b) the Federal Funds Rate plus 0.5% per annum. The LaSalle
Facility also has a commitment fee of 35 bps due on the daily unutilized portion
of the facility.
NOTE 5 -- RESTRICTED CASH
The Company was required to establish a cash reserve of $2,600,000 for
letters of credit that remained outstanding with Wells Fargo at the time of
completing the new short term line of credit facility with LaSalle Bank. The
cash reserve will be returned to the Company by Wells Fargo within ten days of
the expiration date of the individual letters of credit.
NOTE 6 -- NOTE RECEIVABLE
On August 21, 2003, EWP sold the majority of its wholesale propane
assets in Montana and Wyoming consisting of $782,000 in storage and other
related assets and $352,000 in inventory and accounts receivable. The Company
received cash of $750,000 and a promissory note for $620,000 to be repaid over a
four year period. The pretax gain resulting from the sale of these assets was
approximately $236,000.
NOTE 7 -- CONTINGENCIES
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.
Several years ago, the Company initiated an assessment of the site to
determine if remediation of the site was required. That assessment resulted in a
submission of a proposed remediation plan to the Montana Department of
Environmental Quality ("MDEQ") in 1994. The Company has worked with the MDEQ
since that time to obtain the data that would lead to a remediation action
acceptable to the MDEQ. In the summer of 1999, the Company received final
approval from the MDEQ for its plan for remediation of soil contaminants. The
Company has completed its remediation of soil contaminants and in April 2002
received a closure letter from the MDEQ approving the completion of such
remediation program.
The Company and its consultants continue their work with the MDEQ
relating to the remediation plan for water contaminants. The MDEQ has
established regulations that allow water contaminants at a site to exceed
standards if it is technically impracticable to achieve them. Although the MDEQ
has not established
6
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 September 30, 2003, the Company had incurred cumulative costs of
approximately $2,036,000 in connection with its evaluation and remediation of
the site. The Company also estimates that it will incur at least $60,000 in
additional expenses in connection with its investigation and remediation for
this site. On May 30, 1995, the Company received an order from the MPSC allowing
for recovery of the costs associated with the evaluation and remediation of the
site through a surcharge on customer bills. As of September 30, 2003, the
Company had recovered approximately $1,450,000 through such surcharges.
On April 15, 2003, the MPSC issued an Order to Show Cause Regarding the
Environmental Surcharge. The MPSC required the Company to show cause why it was
not in violation of the 1995 order by failing to seek renewal of the surcharge
at the conclusion of the initial two year recovery period. The Company responded
to the MPSC and an interim order has been issued by the MPSC suspending the
collection by the Company of the surcharge until further investigation can be
conducted and requiring a new application from the Company respecting this
surcharge. The Company has submitted its revised application and is awaiting
further MPSC action. Company management believes the Company's application will
be granted. The Company currently has an unrecovered balance of $586,000
awaiting recovery through this mechanism. In the event that the MPSC does not
approve the Company's revised application, in addition to potentially being
unable to recover the unrecovered balance of $586,000, the Company could be
required to refund to customers a portion of the $1,450,000 previously collected
through surcharges.
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.
On November 12, 2003, Turkey Vulture Fund XIII, Ltd., an Ohio limited
liability company ("Turkey Vulture") filed a complaint in Montana Eighth
Judicial District Court against the Company seeking a temporary restraining
order and a preliminary and permanent injunction to prevent the Company from
postponing its annual meeting of shareholders from its previously scheduled date
of November 12, 2003 until December 3, 2003, soliciting additional proxies from
Energy West shareholders and counting the shares of Ian Davidson, the Company's
largest shareholder, in the annual election of directors which is to occur at
the annual meeting of shareholders. On November 12, 2003, the Court issued a
temporary restraining order requiring the Company to hold its annual
shareholders' meeting and election of directors on or before November 24, 2003,
and ordering that the only shareholders and proxies eligible to vote are those
that were eligible, under the Energy West bylaws and applicable law, on November
12, 2003 and restraining all parties from engaging in any additional proxy
solicitation efforts regarding the election of directors. The Court has set a
formal hearing on the motion for preliminary injunction on November 21, 2003.
The Company believes that it has valid defenses to the claims of Turkey Vulture
and intends to vigorously oppose the temporary restraining order and the
preliminary and permanent injunction sought by Turkey Vulture.
In addition to other litigation referenced above, the Company or its
subsidiaries are involved in the following described litigation:
EWR has been involved in a lawsuit with PPL Montana, LLC ("PPLM") which
was filed on July 2, 2001, and involves a wholesale electricity supply contract
between EWR and PPLM dated March 17, 2000 and a confirmation letter thereunder
dated June 13, 2000. On June 17, 2003, EWR and PPLM reached agreement on a
settlement of the lawsuit. Under the terms of the settlement, EWR paid PPLM a
total of $3,200,000, consisting of an initial payment of $1,000,000 on June 17,
2003, and a second payment of $2,200,000 on September 30, 2003, terminating all
proceedings in the case. EWR had established reserves in fiscal year 2002 of
approximately $3,032,000 to pay a potential settlement with PPLM and the
remaining $168,000 was charged to operating expenses in fiscal year 2003.
By letter dated August 30, 2002, the Montana Department of Revenue
("DOR") notified the Company that the DOR had completed a property tax audit of
the Company for the period January 1, 1997 through and including December 31,
2001, and had determined that the Company had under-reported its personal
property and that additional property taxes and penalties should be assessed.
On August 8, 2003, the Company reached agreement with the DOR to pay
$2,430,000 in back taxes (without interest or penalty) for tax years 1992
through and including 2002. The settlement amount will be paid in ten equal
annual installments of $243,000 on or before November 30 of each year beginning
November 30, 2003.
Under Montana law, the Company believes it is entitled to recover the
amounts paid in connection with the DOR settlement through future rate
adjustments without seeking approval from the MPSC. The amended rates will go
into effect on January 1 following the date of each tax payment. The amended
rate schedules must be filed with the MPSC on or before the effective date of
the changes in taxes paid and the
7
commission has 45 days to act on the adjusted rates submitted. If the commission
determines that the rates were adjusted in error, then refunds must be paid to
the customers. The company has established a regulatory asset and a liability in
the amount of $2,430,000. The Company expects to begin collection of the
additional amounts paid in November of 2003 on or about January 1, 2004.
NOTE 8 -- OPERATIONS BY LINE OF BUSINESS
THREE MONTHS ENDED
SEPTEMBER 30
2003 2002
Gross Margin (Operating
Revenue Less Gas and
Power Purchased):
Natural Gas Operations $1,665,037 $1,439,477
Propane Operations 435,890 434,938
EWR 638,269 405,104
Pipeline Operations 109,350 83,744
---------- ----------
$2,848,546 $2,363,263
========== ==========
Operating Income (Loss):
Natural Gas Operations ($900,442) ($703,971)
Propane Operations (172,382) (427,520)
EWR 298,854 (230,995)
Pipeline Operations 57,963 50,751
---------- -----------
($716,007) ($1,311,735)
========== ===========
Net Income (Loss):
Natural Gas Operations ($708,012) ($617,930)
Propane Operations (143,846) (274,025)
EWR 135,485 (159,295)
Pipeline Operations 94,817 30,675
---------- -----------
($621,556) ($1,020,575)
========== ===========
NOTE 9 -- 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 has 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
8
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.
NOTE 10 -- STOCK OPTIONS
The Company has elected to follow Accounting Principals Board Opinion
("APB") No. 25, Accounting for Stock Issued to Employees, in accounting for its
stock options. Pro forma information regarding net income and earnings per share
is required by SFAS No. 123, Accounting for Stock-Based Compensation, as amended
by SFAS No. 148, Accounting for Stock-Based Compensation-Transition and
Disclosure. The stock-based employee compensation cost that would have been
included in net loss if the fair value method had been applied to all awards is
not significant for the quarter ended September 30, 2003.
ITEM 2 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF INTERIM FINANCIAL STATEMENTS
CAUTIONARY STATEMENT FOR PURPOSES OF THE "SAFE HARBOR" PROVISIONS OF THE PRIVATE
SECURITIES LITIGATION REFORM ACT OF 1995
The following Management's Discussion and Analysis and other portions
of this quarterly report on Form 10-Q 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 such as "anticipates," "believes," "expects,"
"planned," "scheduled" or similar expressions and statements regarding the
required restructuring of our long-term debt, our operating capital
requirements, the DOR property tax payments, the Company's environmental
remediation plans, and similar statements that are not historical are forward
looking statements that involve risks and uncertainties. Although the Company
believes these forward-looking statements are based on reasonable assumptions,
statements made regarding future results are subject to a number of assumptions,
uncertainties and risks that could cause future results to be materially
different from the results stated or implied in this document.
Such forward-looking statements, as well as other oral and written
forward-looking statements made by or on behalf of the Company from time to
time, including statements contained in the Company's filings with the
Securities and Exchange Commission and its reports to shareholders, involve
known and unknown risks and other factors which may cause the Company's actual
results in future periods to differ materially from those expressed in any
forward-looking statements. See "Risk Factors" below. 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 statements that may be made from time to time by
or on behalf of the Company except as required by law.
RISK FACTORS
The major factors which affect the Company's future results include the
ability to restructure our long-term debt as required by our current credit
facility and potential costs associated with such restructuring, the potential
nonallowance by the MPSC of the recovery of the environmental surcharge, the
potential impacts of our proxy contest with the Committee to Re-Energize Energy
West, changes in the utility regulatory environment, general and regional
economic conditions, weather, customer retention and growth, the ability to meet
competitive pressures, the ability 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 EWR segment, could have a significant
impact on the performance of the Company.
The regulatory structure is in transition. Legislative and regulatory
initiatives, at both the federal and state levels, are designed to promote
competition. Changes in regulation of the gas industry have allowed certain
customers to negotiate their own gas purchases directly with producers or
brokers. To date, the
9
regulatory changes affecting the gas industry have not had a negative impact on
earnings or cash flow of the Company's natural gas operations.
The Company's regulated natural gas and propane vapor operations follow
SFAS 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 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 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 that would cause it to
discontinue the application of SFAS 71 in the foreseeable future.
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
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
natural gas and power markets;
- Changes in general economic conditions in the United States and
changes in the industries in which the Company conducts business;
- Changes in federal or state laws and regulations to which the
Company is subject, including tax, environmental and employment
laws and regulations;
- The impact of FERC and state public service commission statutes
and regulation, including allowed rates of return, the pace of
deregulation in retail natural gas and electricity markets, and
the resolution of other regulatory matters;
- The ability of the Company and its subsidiaries to obtain
governmental and regulatory approval of various expansion or other
projects;
- The costs and effects (including the possibility of adverse
outcomes) of legal and administrative claims and proceedings
against the Company or its subsidiaries;
- Conditions of the capital markets the Company utilizes to access
capital to finance operations;
- The ability to raise capital in a cost-effective way;
- The effect of changes in accounting policies, if any;
- The ability to manage growth of the Company;
- The ability to control costs;
- The ability of each business unit to successfully implement key
systems, such as service delivery systems;
- The ability of the Company and its subsidiaries to develop
expanded markets and product offerings as well as their ability to
maintain existing markets;
- The ability of customers of the energy marketing and trading
business to obtain financing for various projects;
- The ability of customers of the energy marketing and trading
business to obtain governmental and regulatory approval of various
projects;
- Future utilization of pipeline capacity, which can depend on
energy prices, competition from alternative fuels, the general
level of natural gas and propane demand, decisions by customers
not to renew expiring natural gas or propane contracts, and
weather conditions; and
- Global and domestic economic repercussions from terrorist
activities and the government's response thereto.
10
GENERAL BUSINESS DESCRIPTION
The following discussion reflects results of operations of the Company
and its consolidated subsidiaries for the periods indicated.
The Company's Natural Gas Operations segment involves the distribution
of regulated natural gas to the public in the Great Falls and West Yellowstone,
Montana and the Cody, Wyoming areas. Also included in the Natural Gas Operations
segment is a small regulated propane operation located in Cascade, Montana.
The Company's Propane Operations segment includes the distribution of
regulated propane to the public through underground propane vapor systems in the
Payson, Arizona and Cascade, Montana areas as well as non-utility retail and
wholesale propane operations, operated by its wholly owned subsidiary, Energy
West Propane, Inc. (EWP). Until August 21, 2003, EWP marketed its product in
Wyoming, Montana, Arizona, Colorado, South Dakota, North Dakota, Washington,
Idaho and Nebraska. On August 21, 2003, EWP sold the majority of its wholesale
propane assets in Montana and Wyoming consisting of $782,000 in storage and
other related assets and $352,000 in inventory and accounts receivable. These
assets served wholesale customers in Montana, Idaho, Washington and Wyoming. The
pretax gain resulting from the sale of these assets was approximately $236,000.
The sale represents less than 8% of the assets of EWP, and less than 2% of the
Company's consolidated assets. EWP wholesale and non-utility retail propane
operations continues to serve customers in Arizona. The Company believes that
the retail propane assets in Arizona remain a strategic fit for the Company, and
EWP has no plans to dispose of these assets at the present time.
The EWR segment conducts marketing and distribution activities
involving the sale of natural gas, and to a very limited extent electricity,
mainly in Montana and Wyoming. EWR owns various natural gas gathering systems
located in north central Montana. The revenues and expenses associated with
these gathering systems were reported as part of the Pipeline Operations segment
for fiscal year 2003. EWR also owns natural gas production reserves in north
central Montana which generate approximately 1,000 Mmbtu's per day, or
approximately 5 percent of EWR's annual sales volume.
The Company's Pipeline Operations segment consists of a natural gas
gathering system located in Montana and Wyoming and an interstate natural gas
transportation pipeline between Wyoming and Montana. For fiscal year 2003, the
Pipeline Operations segment also reported revenues and expenses associated with
production properties located in Montana. These natural gas production
properties have been transferred to the EWR segment as of July 1, 2003.
ENERGY WEST, INCORPORATED AND SUBSIDIARIES
SEPTEMBER 30, 2003
QUARTERLY RESULTS OF CONSOLIDATED OPERATIONS
The Company's net loss for the first quarter of fiscal year 2004 was
$622,000 compared to a net loss of $1,021,000 for the first quarter of fiscal
year 2003. The decrease in loss of $399,000 was due primarily to gains on sale
of assets, a reduction in general and administrative expenses due to reductions
in litigation costs and various other cost savings measures, and increases in
margins realized on wholesale gas and electricity sales. These increases were
partially offset by increases in corporate overhead costs, financing costs,
interest and income taxes.
Gross margin, which is defined as operating revenue less gas purchased,
increased $486,000, from $2,363,000 in the first quarter of fiscal year 2003 to
$2,849,000 in the first quarter of fiscal year 2004. The Natural Gas Operations
segment's margins increased $226,000, or 16%, due to approved rate increases in
both the Wyoming and Montana operations. The Company's EWR segment's margin
increased approximately $233,000, or 58% attributed to an increase in natural
gas sales volumes and exiting the electricity market. The
11
Pipeline Operations segment's margins increased 31%, or $26,000 due to the
Shoshone interstate pipeline being placed in service effective as of July 1,
2003.
Distribution, general and administrative expenses decreased by $156,000
in the first quarter of fiscal year 2004 primarily due to decreased legal
expenses related to the PPLM litigation, a reduction in expenses resulting from
the sale of the wholesale propane assets and reductions in expenses resulting
from various cost savings programs. Offsetting these reductions in expenses was
additional property tax expense in the Montana operations, an increase in
corporate overhead expenses resulting from additional professional fees, and
additional general and liability insurance costs in all of the Company's
operating locations.
Maintenance expenses decreased by $55,000 during the first quarter of
fiscal year 2004 compared to the first quarter of fiscal year 2003 primarily
related to decreased expenses associated with maintaining our natural gas
facilities in Montana and Wyoming.
Depreciation and amortization expense increased by $60,000 during the
first quarter of fiscal year 2004 compared to the first quarter of fiscal year
2003 due to the addition of various pipeline facilities and depletion of the
recently purchased production properties.
Other income increased by approximately $115,000 during the first
quarter of fiscal year 2004 primarily due to the sale of real estate property
owned by the Company's pipeline operation.
Interest expense increased by approximately $59,000 during the first
quarter of fiscal year 2004 due to higher interest rates experienced by the
company for the first quarter fiscal 2004.
RESULTS OF THE COMPANY'S NATURAL GAS OPERATIONS
First Quarter
Ended September 30
2003 2002
Natural Gas Revenue $4,663,008 $2,980,375
Natural Gas Purchased 2,997,971 1,540,898
--------------------------
Gross Margin 1,665,037 1,439,477
Operating Expenses 2,565,479 2,143,448
--------------------------
Operating Loss (900,442) (703,971)
Other Income (33,475) (28,661)
Interest Expense 277,328 262,474
Income Tax Benefits (436,283) (319,854)
--------------------------
Net Natural Gas Loss ($708,012) ($617,930)
--------------------------
QUARTERLY RESULTS FOR NATURAL GAS OPERATIONS
The Natural Gas Operations segment incurred a loss from operations of
approximately $708,000 for the quarter ending September 30, 2003 compared to a
loss of $618,000 for the quarter ending September 30, 2002. This increase in
loss of approximately $90,000 was due to increased operating expenses of
approximately $422,000 and an increase in interest expense of approximately
$15,000. These additional expenses were offset by additional gross margin of
$226,000 resulting from approved rate increases, an increase in other income of
$5,000 and an increase in income tax benefits of approximately $116,000.
12
GROSS MARGIN
The Natural Gas Operations segment's revenues increased due to the
approved rate increases in effect at the beginning of fiscal year 2004 and an
increase in natural gas prices. Gross margin, defined as operating revenues less
purchased gas costs, increased by approximately $226,000 from the first quarter
of fiscal year 2003 to the first quarter of fiscal year 2004 due primarily to
approved rate increases.
OPERATING EXPENSES
The Natural Gas Operations segment's operating expenses were $2,565,000
for the first quarter of fiscal year 2004 compared to $2,143,000 for the
corresponding period in fiscal year 2003. The increase in operating expenses of
$422,000 is due primarily to an increase in corporate allocated overheads of
approximately $328,000, increases in general liability insurance expense of
approximately $60,000, and increased property taxes of approximately $89,000.
Offsetting these additional expenses was a reduction in maintenance expenses of
approximately $55,000 due to the implementation of various cost savings
measures.
INTEREST EXPENSE
Interest charges allocable to the Company's Natural Gas Operations
segment's increased by $15,000 from the first quarter of fiscal year 2003 to the
first quarter of fiscal year 2004 due to increases in interest rates charged to
the company for first quarter of fiscal year 2004.
INCOME TAXES
Income tax benefits increased from $320,000 for the first quarter of
fiscal year 2003 to $436,000 for the first quarter of fiscal year 2004. The
increase in tax benefits is the result of an increase in pre tax losses related
to natural gas operations.
RESULTS OF THE COMPANY'S PROPANE OPERATIONS
FIRST QUARTER
ENDED SEPTEMBER 30
2003 2002
Propane Revenue $1,181,901 $1,062,709
Propane Purchased 746,011 627,771
--------------------------
Gross Margin 435,890 434,938
Operating Expenses 608,272 862,458
--------------------------
Operating Loss (172,382) (427,520)
Other Income (35,595) (47,789)
Interest Expense 115,309 96,957
Income Tax Benefit (108,250) (202,663)
--------------------------
Net Propane Loss ($143,846) ($274,025)
--------------------------
QUARTERLY RESULTS FOR PROPANE OPERATIONS
Operating Revenues and Gross Margin
The Propane Operations segment's revenues for the first quarter of
fiscal year 2004 were $1,182,000 compared to $1,063,000 for the first quarter of
fiscal year 2003, an increase of $119,000 primarily due to higher retail prices
in the Arizona operations. Cost of sales for the first quarter of fiscal year
2004 were $746,000 compared to $628,000 for the first quarter fiscal year 2003,
a decrease of $118,000, which resulted in a gross margin increase of
approximately $1,000.
13
OPERATING EXPENSES
The Propane Operations segment's operating expenses were $608,000 for
the first quarter of fiscal 2004 as compared to $862,000 during the same period
in fiscal year 2003. The $254,000 decrease in operating expenses is primarily
due to the gain on the sale of the Rocky Mountain Fuel assets of $236,000 and a
decrease of $18,000 in operating expenses related to the discontinuance of the
wholesale propane operations.
INTEREST EXPENSE AND OTHER INCOME
Interest charges allocable to the Company's Propane Operations segment
were $115,000 for the first quarter of fiscal year 2004, compared to $97,000 in
the comparable period in fiscal year 2003. This increase of $18,000 is due
mainly to higher interest rates experienced by the Company during fiscal year
2004.
Other income decreased from $48,000 for the first quarter of fiscal
year 2003 to $36,000 for the same period in fiscal year 2004. This decrease of
$12,000 is due to the reduction in billing for external services provided to
third parties.
INCOME TAXES
Income tax benefits decreased from $203,000 in the first quarter fiscal
year 2003 to $108,000 for the first quarter of fiscal year 2004. The decrease in
tax benefits of $95,000 is due to the decrease in pre-tax losses related to
propane operations, and the gain on sale of assets by Rocky Mountain Fuels
wholesale on August 21, 2003.
RESULTS OF EWR
FIRST QUARTER
ENDED SEPTEMBER 30
2003 2002
Marketing Revenue $6,325,300 $6,236,039
Purchases 5,687,031 5,830,935
--------------------------
Gross Margin 638,269 405,104
Operating Expenses 339,415 636,099
---------------------------
Operating Income (Loss) 298,854 (230,995)
Other Income (2,625) (1,520)
Interest Expense 46,406 26,895
Income Tax Expense (Benefit) 119,588 (97,075)
---------------------------
Net Marketing Income (Loss) $135,485 ($159,295)
---------------------------
QUARTERLY RESULTS FOR EWR
GROSS MARGIN
EWR's energy marketing and wholesale operations experienced an increase
in gross margin of $233,000 during the first quarter of fiscal year 2004
compared to the same period in fiscal year 2003. This increase was due primarily
to increased sales volumes resulting from the addition of production properties
and exiting the electricity market.
14
OPERATING EXPENSES
Operating expenses for EWR's energy marketing and wholesale operations
were $339,000 for the first quarter of fiscal year 2004 compared to $636,000 for
the same period in fiscal year 2003. The decrease in operating expenses of
$297,000 was due primarily to decreased legal costs related to the PPLM
litigation of approximately $220,000 and a reduction in work force and other
cost saving measures of approximately $77,000.
INTEREST EXPENSE
Interest charges increased by $19,000 from $27,000 in the first quarter
of fiscal year 2003 to $46,000 in the first quarter of fiscal year 2004. This
increase is due mainly to higher interest rates experienced by the Company
during fiscal year 2004.
INCOME TAXES
State and federal income tax expense of EWR's energy marketing and
wholesale operations increased from a $97,000 income tax benefit for the first
quarter of fiscal year 2003 to an income tax expense of $120,000 in the first
quarter of fiscal year 2004, due to an increase in pre-tax income from EWR.
RESULTS OF THE COMPANY'S PIPELINE OPERATIONS
First Quarter
Ended September 30
2003 2002
Pipeline Revenue $109,350 $83,744
--------------------------
Gross Margin 109,350 83,744
Operating Expenses 51,387 32,993
--------------------------
Operating Income 57,963 50,751
Other Income (120,922)
Interest Expense 7,054 774
Income Taxes 77,014 19,302
--------------------------
Net Pipeline Income $94,817 $30,675
--------------------------
QUARTERLY RESULTS FOR PIPELINE OPERATIONS
GROSS MARGIN
The Company's Pipeline Operations segment experienced an increase in
gross margin of $25,000 during the first quarter of fiscal year 2004 compared to
the same period in fiscal year 2003. This increase was due primarily to the
Shoshone interstate pipeline beginning operations effective on July 1, 2003.
OPERATING EXPENSES
Operating expenses for the Pipeline Operations segment were $51,000 for
the first quarter of fiscal year 2004 as compared to $33,000 for the same period
in fiscal year 2003. The increase in operating expenses of $18,000 was due
primarily to expenses related to the operation of the Shoshone Pipeline.
15
OTHER INCOME
Other income for the quarter ended September 30, 2003, of $121,000
resulted from a gain on the sale of certain real estate assets located in
Montana.
INTEREST EXPENSE
Interest charges for the first quarter of fiscal year 2004 increased by
$6,000 from $1,000 in the first quarter of fiscal year 2003 to $7,000 in the
first quarter of fiscal year 2004. This increase is due mainly to higher
interest rates experienced by the Company during fiscal year 2004.
INCOME TAXES
State and federal income tax expense for Pipeline Operations increased
from a $19,000 income tax expense for the first quarter of fiscal year 2003 to
$77,000 in the first quarter of fiscal year 2004. The increase in income tax
expense resulted from the increase in earnings attributed to the operations of
the interstate pipeline effective on July 1, 2003 and the gain resulting from
the sale of the real estate assets during the first quarter of fiscal year 2003.
CASH FLOW ANALYSIS
For the three months ended September 30, 2003, the Company, and its
subsidiaries, used $10,888,000 of cash in its operating activities compared to
$4,218,000 for the three months ended September 30, 2002. This increase in cash
used of $6,670,000 was primarily due to an increase in restricted cash of
$2,600,000, an increase in recoverable cost of gas of $1,205,000, an increase in
natural gas inventories of $464,000, an increase in accounts receivable of
$176,000, a decrease in accrued current liabilities of $1,720,000, an increase
in deferred charges of approximately $2,922,000, and an increase in income tax
receivable of $1,103,000
Offsetting these amounts was a decrease in net loss of $399,000, an
increase in accounts payable of $1,826,000, a reduction in deferred tax assets
of $1,010,000, and a decrease in other working capital items of approximately
$285,000.
Cash provided by investing activities was $376,000 for the three months
ended September 30, 2003, compared to cash used of $1,161,000 for the three
months ended September 30, 2002. This increase in cash of $1,537,000 was
primarily due to a reduction in construction expenditures of $721,000, and an
increase in cash from the sale of the wholesale propane and real estate assets
of $829,000. Offsetting these reductions was an increase in cash used in
investing activities of $13,000 related to the Company's regulatory operations.
Cash provided by financing activities was $10,365,000 for the three
months ended September 30, 2003, as compared to $5,106,000 for the three months
ended September 30, 2002. This increase of $5,259,000 was due primarily to an
increase in net proceeds from the Company's short term lines of credit of
$4,978,000, and a reduction in shareholder dividend payments of $333,000, offset
by an increase in the Company's payments on long term debt of approximately
$52,000.
Capital expenditures of the Company are primarily for expansion and
improvement of its gas utility properties. To a lesser extent, funds are also
expended to meet the equipment needs of the Company and its operating
subsidiaries and to meet the Company's administrative needs. During fiscal year
2004 the Company's capital expenditures are expected to be approximately
$2,028,000. These capital expenditures are expected to be generally for routine
system expansion and operating needs. The Company continues to evaluate
opportunities to expand its existing business and continues to evaluate new
business opportunities, which could result in additional capital expenditures.
16
LIQUIDITY AND CAPITAL RESOURCES
The Company's operating capital needs 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.
Following an adverse ruling in the Company's lawsuit with PPLM on March
7, 2003, the Company's bank lender, Wells Fargo Bank Montana, National
Association ("Wells Fargo") and the Company began negotiations with respect to
the Company's credit facility which was set to expire in May 2003. Wells Fargo
granted a series of extensions of the credit facility through September 5, 2003.
On September 5, 2003, the Company reached an agreement with Wells Fargo
for a new credit facility through October 15, 2003 (the "Wells Fargo Facility").
The terms of the new Wells Fargo Facility established a term loan of
approximately $10,400,000, the proceeds of which were used to repay the prior
Wells Fargo credit facility and to establish a reserve of approximately
$2,600,000 for letters of credit that remained outstanding from the prior
facility. In addition, the Wells Fargo Facility established a revolving line of
credit under which the Company could borrow up to $3,000,000 for working capital
and certain other expenses. Borrowings under the new Wells Fargo Facility were
secured by liens on substantially all of the assets of the Company used in its
regulated operations in Arizona, and by substantially all of the assets of the
Company's subsidiaries. As required under the terms of the Company's outstanding
long-term notes and bonds (the "Long Term Debt"), the Company's obligations
under the Long Term Debt were secured on an equal and ratable basis with Wells
Fargo in the collateral granted to secure the Wells Fargo Facility with the
exception of the first $1,000,000 of debt under the Wells Fargo Facility.
On September 30, 2003, the Company established a $23,000,000 revolving
credit facility (the "LaSalle Facility") with LaSalle Bank National Association,
as Agent for certain banks (collectively, the "Lender"). The LaSalle Facility
replaced the Wells Fargo Facility and the amount due under the Wells Fargo
Facility was paid in full out of the proceeds of the LaSalle Facility.
Borrowings under the LaSalle Facility are secured by liens on substantially all
of the assets of the Company and its subsidiaries. As required under the terms
of the Long Term Debt, the Company's obligations under the Long Term Debt are
secured on an equal and ratable basis with the Lender in the collateral granted
to secure the LaSalle Facility with the exception of the first $1,000,000 of
debt under the LaSalle Facility.
The Company obtained required approvals from the Montana Public Service
Commission ("MPSC") and the Wyoming Public Service Commission ("WPSC") to enter
into the LaSalle Facility. The MPSC order granting approval imposed several
requirements on the Company including restrictions on the use of the proceeds of
the LaSalle Facility for anything other than utility purposes, and requirements
that the Company provide ongoing reports to the MPSC with respect to the
financial condition of the Company and its non-regulated subsidiaries, and
certain other matters. The MPSC order provided that the Company could fund the
remaining $2,200,000 settlement payment owed by EWR to PPLM. The settlement
payment was made on September 30, 2003, ending the litigation between the two
parties.
The LaSalle Facility provides that the maximum availability under the
facility will be reduced from $23,000,000 to $15,000,000 no later than March 31,
2004. From and after the date on which the amount of availability under the
LaSalle Facility is reduced, the LaSalle Facility is to be secured by a senior
priority lien in the accounts receivable and inventory of the Company and its
subsidiaries. As a result of the provisions providing for the reduction in the
maximum availability under the LaSalle Facility, the Company will be
17
required to refinance or restructure the Long Term Debt by March 31, 2004. The
Company anticipates that such refinancing or restructuring will involve
providing a senior priority lien in the fixed assets of the Company and its
subsidiaries to secure the Long Term Debt or any long-term debt that the Company
issues to replace the current Long Term Debt. The Company also anticipates that
it will increase the total amount of long-term debt outstanding in connection
with such refinancing or restructuring. The Company presently anticipates that
the amount of such increase in long-term debt will be approximately $8,000,000.
The Company believes that it will be able to accomplish the Long Term Debt
restructuring or refinancing by March 31, 2004. Failure to complete the
restructuring or refinancing of the Long Term Debt, as discussed above, would be
a default under the terms of the LaSalle Facility.
The terms of the LaSalle Facility provide that the Company cannot pay
dividends to its shareholders during the period prior to the refinancing or
restructuring of the Company's Long Term Debt. In June 2003, the Company
suspended its dividend to allow for strengthening of the Company's balance
sheet. The Company expects that it will be able to accomplish the long-term debt
restructuring by March 31, 2004.
Under the LaSalle Facility, the Company has the option to pay interest
at either the London Interbank Offered Rate (LIBOR) plus 250 basis points (bps)
or the higher of (a) the rate publicly announced from time to time by LaSalle as
its "prime rate" or (b) the Federal Funds Rate plus 0.5% per annum. The LaSalle
Facility also has a commitment fee of 35 bps due on the daily unutilized portion
of the facility.
The LaSalle Facility requires that the Company maintain compliance with
a number of financial covenants including limitations on annual capital
expenditures to an amount equal to or less than $5,000,000. The Company must
also maintain a total debt to total capital ratio of less than .65 to 1.00 and
an interest coverage ratio (earnings before interest, taxes, depreciation and
amortization (EBITDA), plus agreed upon add backs, divided by interest expense)
of no less than 2.00 to 1.00. Finally, the Company must restrict its open
positions and Value at Risk (VaR) in its wholesale operations to an amount not
to exceed $1,000,000. The Company met all of the financial covenants at the time
it entered into the LaSalle Facility except the total debt to capital ratio
which was .68 to 1.00. LaSalle Bank has waived this covenant for the quarter
ending September 30, 2003.
At September 30, 2003, the Company had borrowed $16,601,548 under the
LaSalle Facility and had $6,398,452 of borrowing capacity under the LaSalle
Facility.
In addition to its bank lines of credit, the Company has outstanding
certain notes and industrial development revenue obligations (collectively "Long
Term Debt"). The Company's Long Term Debt is made up of three separate debt
issues: $8,000,000 of Series 1997 unsecured notes bearing interest at the rate
of 7.5%; $7,800,000 of Series 1993 unsecured notes bearing interest at rates
ranging from 6.20% to 7.60%; and Cascade County, Montana Series 1992B Industrial
Development Revenue Obligations in the amount of $1,800,000. As required by the
terms of the Long Term Debt, the Company's obligations under the Long Term Debt
are secured on an equal and ratable basis with the Lender in the collateral
granted to secure the LaSalle Facility with the exception of the first
$1,000,000 of debt under the LaSalle Facility.
The total amount of the Company's obligations under the Long Term Debt
was $15,216,000 and $15,770,000, at September 30, 2003 and September 30, 2002,
respectively. The portion of such obligations due within one year was $530,000
and $500,000 at September 30, 2003, and September 30, 2002, respectively. Under
the terms of the Long Term Debt obligations, the Company is subject to certain
restrictions, including restrictions on total dividends and distributions, liens
and secured indebtedness, and asset sales, and the Company is restricted from
incurring additional long-term indebtedness if it does not meet certain
financial debt and interest ratios.
CONTRACTS ACCOUNTED FOR AT FAIR VALUE
Management of Risks Related to Derivatives--The Company and its
subsidiaries are subject to certain risks related to changes in certain
commodity prices and risks of counter-party performance. The Company has
established certain policies and procedures to manage such risks. The Company
has a Risk Management
18
Committee ("RMC"), comprised of Company officers to oversee the Company's risk
management program as defined in its risk management policy. The purpose of the
risk management program is to minimize adverse impacts on earnings resulting
from volatility of energy prices, counter-party credit risks, and other risks
related to the energy commodity business.
General - From time to time the Company or its subsidiaries may use
derivative financial contracts to mitigate the risk of commodity price
volatility related to firm commitments to purchase and sell natural gas or
electricity. The Company may use such arrangements to protect its profit margin
on future obligations to deliver quantities of a commodity at a fixed price.
Conversely, such arrangements may be used to hedge against future market price
declines where the Company or a subsidiary enters into an obligation to purchase
a commodity at a fixed price in the future. The Company accounts for such
financial instruments in accordance with Statement of Financial Accounting
Standard ("SFAS") No. 133, Accounting for Derivative Instruments and Hedging
Activities, as amended by SFAS No. 138, Accounting for Certain Derivative
Instruments and Certain Hedging Activities.
In accordance with SFAS No. 133, contracts that do not qualify as
normal purchase and sale contracts must be reflected in the Company's financial
statements at fair value, determined as of the date of the balance sheet. This
accounting treatment is also referred to as "mark-to-market" accounting.
Mark-to-market accounting treatment can result in a disparity between reported
earnings and realized cash flow, because changes in the value of the financial
instrument are reported as income or loss even though no cash payment may have
been made between the parties to the contract. If such contracts are held to
maturity, the cash flow from the contracts, and their hedges, are realized over
the life of the contract.
Quoted market prices for natural gas derivative contracts of the
Company or its subsidiaries generally are not available. Therefore, to determine
the fair value of natural gas derivative contracts, the Company uses internally
developed valuation models that incorporate independently available current and
historical pricing information.
EWR was a party to a number of contracts that were valued on a
mark-to-market basis under SFAS No. 133. Although certain firm commitments for
the purchase and sale of natural gas could have been classified as normal
purchases and sales and excluded from the requirements of SFAS No. 133, as
described above, EWR elected to treat these contracts as derivative instruments
under SFAS No. 133 in order to match contracts for the purchase and sale of
natural gas for financial reporting purposes. Such contracts were recorded in
the Company's consolidated balance sheet at fair value. Periodic mark-to-market
adjustments to the fair values of these contracts are recorded as adjustments to
gas costs.
As of September 30, 2003, these agreements were reflected on the Company's
consolidated balance sheet as derivative assets and liabilities at an
approximate aggregate fair value as follows:
ASSETS LIABILITIES
Contracts maturing in one year or less: $ 600,539 $162,323
Contracts maturing in two to three years: 1,180,503 324,673
Contracts maturing in four to five years: 305,992 129,119
Contracts maturing in five years or more: 48,613 20,513
---------- --------
Total $2,135,647 $636,628
========== ========
During the first quarter of fiscal 2004, the Company has not entered into
any new contracts that have required mark-to-market accounting under SFAS No.
133.
Natural Gas and Propane Operations--In the case of the Company's regulated
divisions, gains or losses resulting from the derivative contracts are subject
to deferral under regulatory procedures approved by the public service
regulatory commissions of Montana, Wyoming and Arizona. Therefore, related
derivative assets and liabilities are offset with corresponding regulatory
liability and asset amounts included in "Recoverable Cost of Gas Purchases",
pursuant to SFAS No. 71, Accounting for the Effects of Certain Types of
Regulation.
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CRITICAL ACCOUNTING POLICIES
The Company believes its critical accounting policies are as follows:
Effects of Regulation--The Company follows SFAS 71, Accounting for the
Effects of Certain Types of Regulation, and its financial statements reflect the
effects of the different rate making principles followed by the various
jurisdictions regulating the Company. The economic effects of regulation can
result in regulated companies recording costs that have been or are expected to
be allowed in the ratemaking process in a period different from the period in
which the costs would be charged to expense by an unregulated enterprise. When
this occurs, costs are deferred as assets in the balance sheet (regulatory
assets) and recorded as expenses in the periods when those same amounts are
reflected in rates. Additionally, regulators can impose liabilities upon a
regulated company for amounts previously collected from customers and for
amounts that are expected to be refunded to customers (regulatory liabilities).
Recoverable/ Refundable Costs of Gas and Propane Purchases--The Company
accounts for purchased-gas costs in accordance with procedures authorized by the
MPSC, the WPSC and the Arizona Corporation Commission (ACC) under which
purchased-gas and propane costs that are different from those provided for in
present rates are accumulated and recovered or credited through future rate
changes.
Derivatives--The Company accounts for certain derivative contracts that
are used to manage risk in accordance with SFAS No. 133, Accounting for
Derivative Instruments and Hedging Activities, as amended by SFAS No. 138,
Accounting for Certain Derivative Instruments and Certain Hedging Activities,
which the Company adopted July 1, 2000.
ITEM 3 -- THE 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 protects itself against price fluctuations on natural gas
and electricity by limiting the aggregate level of net open positions, which are
exposed to market price changes and through the use of natural gas derivative
instruments. The net open position is actively managed with strict policies
designed to limit the exposure to market risk, and which require at least weekly
reporting to management of potential financial exposure. The risk management
committee has limited the types of financial instruments the company may trade
to those related to natural gas commodities. The Company's results of operations
are significantly impacted by changes in the price of natural gas. During 2003
and 2002, natural gas accounted for 55% and 62% respectively, of the Company's
operating expenses. In order to provide short-term protection against a sharp
increase in natural gas prices, the Company from time to time enters into
natural gas call and put options, swap contracts and purchase commitments. The
Company's gas hedging strategy could result in the Company not fully benefiting
from certain gas price declines.
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 long term notes payable, however, are subject to variable interest
rates. A
20
hypothetical 10 percent change in market rates applied to the balance of the
long term notes payable would not have a material effect on the Company's
earnings.
Credit Risk
Credit risk relates to the risk of loss that the Company would incur as
a result of non-performance by counterparties of their contractual obligations
under the various instruments with the Company. Credit risk may be concentrated
to the extent that one or more groups of counterparties have similar economic,
industry or other characteristics that would cause their ability to meet
contractual obligations to be similarly affected by changes in market or other
conditions. In addition, credit risk includes not only the risk that a
counterparty may default due to circumstances relating directly to it, but also
the risk that a counterparty may default due to circumstances which relate to
other market participants which have a direct or indirect 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 4. CONTROLS AND PROCEDURES
The Company's Interim President and Chief Executive Officer (principal
executive officer), John C. Allen and the Company's Vice President and
Controller (principal financial officer) Robert B. Mease have evaluated the
Company's internal controls and disclosure controls systems as of the end of the
period covered by this report. They have concluded that the Company's disclosure
controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) are
effective as of the date of this Quarterly Report on Form 10-Q to provide
reasonable assurance that the Company can meet its disclosure obligations. As of
the date of this Quarterly Report on Form 10-Q there have not been any
significant changes in internal controls or in other factors that could
significantly affect these controls subsequent to the date of their evaluation,
including any corrective actions with regard to significant deficiencies and
material weaknesses.
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Form 10-Q
Part II - Other Information
Item 1. 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.
On November 12, 2003, Turkey Vulture Fund XIII, Ltd., an Ohio limited
liability company ("Turkey Vulture") filed a complaint in Montana Eighth
Judicial District Court against the Company seeking a temporary restraining
order and a preliminary and permanent injunction to prevent the Company from
postponing its annual meeting of shareholders from its previously scheduled date
of November 12, 2003 until December 3, 2003, soliciting additional proxies from
Energy West shareholders and counting the shares of Ian Davidson, the Company's
largest shareholder, in the annual election of directors which is to occur at
the annual meeting of shareholders. On November 12, 2003, the Court issued a
temporary restraining order requiring the Company to hold its annual
shareholders' meeting and election of directors on or before November 24, 2003,
and ordering that the only shareholders and proxies eligible to vote are those
that were eligible, under the Energy West bylaws and applicable law, on November
12, 2003 and restraining all parties from engaging in any additional proxy
solicitation efforts regarding the election of directors. The Court has set a
formal hearing on the motion for preliminary injunction on November 21, 2003.
The Company believes that it has valid defenses to the claims of Turkey Vulture
and intends to vigorously oppose the temporary restraining order and the
preliminary and permanent injunction sought by Turkey Vulture.
EWR has been involved in a lawsuit with PPLM which was filed on July 2,
2001, and involves a wholesale electricity supply contract between EWR and PPLM
dated March 17, 2000 and a confirmation letter thereunder dated June 13, 2000.
On June 17, 2003, EWR and PPLM reached agreement on a settlement of the lawsuit.
Under the terms of the settlement, EWR paid PPLM a total of $3,200,000,
consisting of an initial payment of $1,000,000 on June 17, 2003, and a second
payment of $2,200,000 on September 30, 2003, terminating all proceedings in the
case. EWR had established reserves in fiscal year 2002 of approximately
$3,032,000 to pay a potential settlement with PPLM and the remaining $168,000
was charged to operating expenses in fiscal year 2003.
By letter dated August 30, 2002, the DOR notified the Company that the
DOR had completed a property tax audit of the Company for the period January 1,
1997 through and including December 31, 2001, and had determined that the
Company had under-reported its personal property and that additional property
taxes and penalties should be assessed.
On August 8, 2003, the Company reached agreement with the DOR to pay
$2,430,000 in back taxes (without interest or penalty) for tax years 1992
through and including 2002. The settlement amount will be paid in ten equal
annual installments of $243,000 on or before November 30 of each year beginning
November 30, 2003.
Under Montana law, the Company believes it is entitled to recover the
amounts paid in connection with the DOR settlement through future rate
adjustments without seeking approval from the MPSC. The amended rates will go
into effect on January 1 following the date of each tax payment. The amended
rate schedules must be filed with the MPSC on or before the effective date of
the changes in taxes paid and the commission had 45 days to act on the adjusted
rates submitted. If the commission determines that the rates were adjusted in
error, then refunds must be paid to the customers. The company has established a
regulatory asset and a liability in the amount of $2,430,000.
Item 2. Changes in Securities - Not Applicable
Item 3. Defaults upon Senior Securities - Not Applicable
Item 4. Submission of Matters to a Vote of Security Holders - Not Applicable
Item 5. Other Information - Not Applicable
Item 6. Exhibits and Reports on Form 8-K
A. Exhibits for the first quarter ended September 30, 2003.
10.1 Credit Agreement dated as of September 30, 2003 by
and among Energy West, Incorporated, Various
Financial Institutions and LaSalle Bank National
Association, as Agent (incorporated herein by
reference to the Company's Amended Current Report on
Form 8-K/A dated October 9, 2003)
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10.2 Credit Agreement dated as of September 2, 2003
between Energy West, Incorporated, Energy West
Development, Inc., Energy West Propane, Inc. and
Energy West Resources, Inc. and Wells Fargo Bank
Montana, National Association (incorporated by
reference to the Company's Current Report on Form 8-K
filed with the Commission on September 8, 2003)
31.1 Certification of the Principal Executive Officer
pursuant to Section 302 of the Sarbanes-Oxley Act of
2002 (filed herewith).
31.2 Certification of the Principal Financial Officer
pursuant to Section 302 of the Sarbanes-Oxley Act of
2002 (filed herewith)
32.1 Certification of the Principal Executive Officer
pursuant to Section 906 of the Sarbanes-Oxley Act of
2002 (filed herewith).
32.2 Certification of the Principal Financial Officer
pursuant to Section 906 of the Sarbanes-Oxley Act of
2002 (filed herewith).
B. The Company filed a Current Report on Form 8-K during the first
quarter ended September 30, 2003 as follows.
Date Filed Item No.
July 31, 2003 Item 5 -- Announcement of extension
of Wells Fargo credit facility.
Item 7 -- Press Release dated
July 30, 2003
August 12, 2003 Item 5 -- Announcement of settlement
with the Montana Department of
Revenue
Item 7 -- Press Release dated
August 11, 2003
August 25, 2003 Item 5 -- Announcement of sale of
Wholesale Propane assets in Montana
and Wyoming
Item 7 -- Press Release dated
August 22, 2003
September 2, 2003 Item 5 -- Announcement of
extension of Wells Fargo credit
facility.
Item 7 -- Press Release
dated August 29, 2003
September 8, 2003 Item 5 -- Announcement of
new credit facility with Wells Fargo
Bank Montana, National Association.
Item 7 -- Press Release dated
September 5, 2003
September 22, 2003 Item 5 -- Announcement of
resignation of President and CEO and
appointment of Interim President and
CEO.
Item 7 -- Press Release dated
September 22, 2003
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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934,
the registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
ENERGY WEST, INCORPORATED
/s/John C. Allen
- -------------------------------
John C. Allen, Interim President and
Chief Executive Officer
(principal executive officer)
/s/Robert B. Mease
- -------------------------------
Robert B. Mease, Vice-President
and Controller
(principal financial officer)
Dated November 14, 2003
24