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 December 31, 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 December 31, 2003
(Common stock, $.15 par value) 2,595,641 shares
ENERGY WEST, INCORPORATED
INDEX TO FORM 10-Q
PAGE NO.
--------
Part I - Financial Information
Item 1 - Financial Statements
Condensed Consolidated Balance Sheets as of
December 31, 2003, December 31, 2002 and June 30, 2003 1
Condensed Consolidated Statements of Operations -
three months and six months ended December 31, 2003 and 2002 2
Condensed Consolidated Statements of Cash Flows -
six months ended December 31, 2003 and 2002 3
Notes to Condensed Consolidated Financial Statements 4-10
Item 2 - Management's discussion and analysis of
financial condition and results of operations 11-25
Item 3 - Quantitative and Qualitative Disclosures about Market Risk 25-26
Item 4 - Controls and Procedures 26
Part II - Other Information
Item 1 - Legal Proceedings 26-27
Item 2 - Changes in Securities 27
Item 3 - Defaults upon Senior Securities 27
Item 4 - Submission of Matters to a Vote of Security Holders 27
Item 5 - Other Information 27
Item 6 - Exhibits and Reports on Form 8-K 28-29
Signatures 30-34
Item 1. Financial Statements
FORM 10Q
ENERGY WEST, INCORPORATED
CONDENSED CONSOLIDATED BALANCE SHEETS
December 31 December 31 June 30
2003 2002 2003
(Unaudited) (Unaudited) (Audited)
----------- ----------- -----------
Current assets:
Cash and cash equivalents $ 1,598,221 $ 1,369,661 $ 1,938,768
Accounts receivable (net) 11,828,792 12,512,040 7,971,632
Derivative assets 2,218,412 2,277,891 2,719,640
Natural gas and propane inventories 4,456,921 2,281,048 1,038,690
Materials and supplies 379,353 514,478 371,490
Prepayments and other 496,535 518,461 352,982
Deferred tax assets 309,679 395,811 828,698
Deferred purchase gas costs 1,099,197 1,067,109
Prepaid income tax payments 1,883,702 1,676,502 1,882,889
----------- ----------- -----------
Total current assets 24,270,812 21,545,892 18,171,898
Long term notes receivable 461,060
Property, plant and equipment, net 38,473,678 37,822,628 39,576,596
Deferred charges 5,661,271 1,907,770 4,388,372
Other assets 247,958 292,380 271,429
----------- ----------- -----------
Total assets $69,114,779 $61,568,670 $62,408,295
=========== =========== ===========
Capitalization and liabilities:
Current liabilities:
Lines of credit $20,629,304 $10,642,078 $ 6,104,588
Current portion of long term-debt 537,533 507,147 532,371
Accounts payable 4,104,644 7,933,012 8,841,779
Derivative liabilities 884,628 780,703
Refundable cost of gas purchases 115,158
Accrued and other current liabilities 3,200,036 5,117,111 5,309,254
----------- ----------- -----------
Total current liabilities 29,356,145 24,314,506 21,568,695
----------- ----------- -----------
Long-term liabilities:
Deferred tax liabilities 5,146,631 4,430,306 5,460,083
Deferred investment tax credits 344,875 365,937 355,406
Other long-term liabilities 4,588,367 2,354,254 4,891,200
----------- ----------- -----------
Total 10,079,873 7,150,497 10,706,689
Long-Term Debt 14,688,684 15,280,750 14,834,452
Stockholders' equity:
Preferred stock - $.15 par value
Authorized - 1,500,000 shares; Issued - none
Common stock - $.15 par value 389,295 388,608 $ 389,295
Authorized - 3,500,000 shares
Outstanding - 2,595,641 shares outstanding
at December 31, 2003; 2,579,948 at December
31, 2002; and 2,595,250 at June 30, 2003
Capital in excess of par value 5,056,425 5,022,397 5,056,425
Retained earnings 9,544,357 9,411,912 9,852,739
----------- ----------- -----------
Total stockholders' equity 14,990,077 14,822,917 15,298,459
----------- ----------- -----------
Total capitalization 29,678,761 30,103,667 30,132,911
----------- ----------- -----------
Total capitalization and liabilities $69,114,779 $61,568,670 $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 Six Months Ended
December 31 December 31
2003 2002 2003 2002
(Unaudited) (Unaudited) (Unaudited) (Unaudited)
----------- ----------- ------------ ------------
Revenues:
Natural gas operations $12,276,986 $ 8,778,652 $ 16,939,994 $ 11,759,027
Propane operations 2,141,177 4,268,933 3,323,078 5,331,642
Gas and electric-wholesale 8,297,247 9,368,696 14,622,547 15,604,735
Pipeline 96,416 69,534 205,766 153,278
----------- ----------- ------------ ------------
Total revenues 22,811,826 22,485,815 35,091,385 32,848,682
----------- ----------- ------------ ------------
Expenses:
Gas & propane purchased 9,961,438 8,711,769 13,705,420 10,880,438
Gas and electric-wholesale 7,948,509 8,755,823 13,635,540 14,586,758
Distribution, general and administrative 2,928,240 3,660,708 5,501,965 6,390,302
Maintenance 115,086 128,057 224,420 292,608
Depreciation and amortization 614,842 542,239 1,232,474 1,100,540
Taxes other than income 164,618 216,026 428,480 438,578
----------- ----------- ------------ ------------
Total operating expenses 21,732,733 22,014,622 34,728,299 33,689,224
----------- ----------- ------------ ------------
Operating income (loss) 1,079,093 471,193 363,086 (840,542)
Non-operating income 65,790 84,050 258,407 162,020
Interest expense:
Long-term debt 283,059 291,452 567,375 584,064
Lines of credit 363,954 113,972 525,735 208,460
----------- ----------- ------------ ------------
Total interest expense 647,013 405,424 1,093,110 792,524
----------- ----------- ------------ ------------
Income (loss) before income tax expense (benefit) 497,870 149,819 (471,617) (1,471,046)
Income tax expense (benefit) 184,696 29,008 (163,235) (571,282)
----------- ----------- ------------ ------------
Net income (loss) $ 313,174 $ 120,811 $ (308,382) $ (899,764)
=========== =========== ============ ============
Earnings (loss) per common share:
Basic and diluted loss per common share $ 0.12 $ 0.05 $( 0.12) $( 0.35)
Weighted average common shares outstanding:
Basic 2,595,641 2,579,948 2,595,641 2,579,948
Diluted 2,595,641 2,579,948 2,595,641 2,579,948
The accompanying notes are an integral part of these condensed
financial statements.
-2-
FORM 10Q
ENERGY WEST, INCORPORATED
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
Six Months Ended
December 31
2003 2002
(Unaudited) (Unaudited)
------------ ------------
Cash flow from operating activities:
Net Loss $ (308,382) $ (899,764)
Adjustment to reconcile net loss to net cash flows
used in by operating activities
Depreciation and amortization, including deferred charges and
financing costs 1,442,785 1,159,980
Gain on sale of property, plant & equipment (333,988)
Deferred gain on sale of assets (11,814) (11,814)
Investment tax credit - net (10,531) (10,531)
Deferred income taxes - net 205,561 922,604
Change in operating assets and liabilities
Accounts receivable - net (3,957,159) (4,267,801)
Derivative assets 501,228 589,826
Natural gas and propane inventory (3,418,231) 3,359,612
Prepayments and other (143,553) (72,809)
Recoverable/refundable cost of gas purchases (32,088) (1,909,001)
Accounts payable (4,737,139) (1,480,681)
Derivative liabilities 103,925
Other assets and liabilities (2,645,286) (374,587)
------------ ------------
Net cash used In operating activities (13,344,672) (2,994,966)
Cash flow from investing activities:
Construction expenditures (1,055,820) (2,442,498)
Proceeds from sale of property, plant & equipment 840,216
Collection of long-term notes receivable 3,300
Customer advances for construction 13,600 22,460
Proceeds from contributions in aid of constructions 2,133 20,948
------------ ------------
Net cash used in investing activities (199,871) (2,395,790)
Cash flow from financing activities:
Repayment of long-term debt (140,606) (81,599)
Debt issuance costs (1,180,114)
Proceeds from lines of credit 27,832,346 22,154,697
Repayment of lines of credit (13,307,630) (15,012,619)
Dividends on common stock (667,719)
------------ ------------
Net cash provided by financing activities 13,203,996 6,392,760
------------ ------------
Net increase (decrease) in cash and cash equivalents (340,547) 1,002,004
Cash and cash equivalents at beginning of year 1,938,768 367,657
------------ ------------
Cash and cash equivalents at end of period $ 1,598,221 $ 1,369,661
============ ============
The accompanying notes are an integral part of these condensed
financial statements.
-3-
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
December 31, 2003
Note 1
Basis of Presentation---The accompanying unaudited condensed
consolidated financial statements of Energy West, Incorporated and its
subsidiaries (collectively, 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 six month period ended December 31,
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 and 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 that runs between Montana and
Wyoming.
The Company's reporting segments are: Natural Gas Operations, Propane
Operations, EWR Operations and Pipeline Operations. An application was 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.
Stock Options---Pursuant to Statement of Financial Accounting Standards
("SFAS") No. 123, Accounting for Stock-Based Compensation, the Company has
elected to account for its employee stock option plan under Accounting
Principals Board Opinion ("APB") Opinion No. 25, Accounting for Stock Issued to
Employees, which recognizes expense based on the intrinsic value at date of
grant. As stock options have been issued with exercise prices equal to the
market value of the underlying shares on the grant date, no compensation cost
has resulted. Had compensation cost for all options granted been determined
based on the fair value at grant date consistent with SFAS No. 123, the effect
on the Company's net earnings and earnings per share would not be significant
for the six months ended December 31, 2003.
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 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
4
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 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. 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 December 31, 2003, 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 in one year or less: $ 822,999 $ 267,970
Contracts maturing in two to three years: 1,038,129 420,082
Contracts maturing in four to five years: 357,284 196,576
----------- -----------
Total $ 2,218,412 $ 884,628
=========== ===========
During the first six months 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 derivative contracts are
subject to deferral under regulatory procedures of 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.
5
NOTE 3 - INCOME TAXES
Income tax expense (benefit) differs from the amount computed by
applying the federal statutory rate to pre-tax income or loss as demonstrated in
the following table:
Three Months Ended Six Months Ended
December 31 December 31
2003 2002 2003 2002
Tax expense (benefit) at statutory rates - 34% $ 171,070 $ 51,899 ($156,769) ($497,734)
State tax expense (benefit) net of federal tax benefit 24,138 33 (28,481) (37,382)
Amortization of deferred investment tax credits (5,265) (5,265) (10,531) (10,531)
Other expense (benefit) (5,247) (17,659) 32,546 (25,635)
--------- --------- --------- ---------
Total income tax expense (benefit) $ 184,696 $ 29,008 ($163,235) ($571,282)
========= ========= ========= =========
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 (collectively, the "Lender"). 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. In addition, the LaSalle Facility requires that the Company provide a
first priority security interest in certain assets to the Lender no later than
March 31, 2004, which would require either restructuring or refinancing of the
Company's outstanding long-term notes and bonds (the "Long Term Debt"). The
Company is presently working on refinancing in order to satisfy the Lender's
requirements. The Company believes that it will be able to implement such
refinancing by March 31, 2004. Failure to complete such refinancing would result
in a default under the terms of the LaSalle Facility.
The terms of the LaSalle Facility also provide that the Company cannot
pay dividends to its shareholders during the period prior to such refinancing of
the LaSalle Facility. In June 2003, the Company suspended its dividend to allow
for strengthening of the Company's balance sheet.
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 - 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 secured promissory note for $620,000 to be
repaid over a four year period. The pre-tax gain resulting from the sale of
these assets was approximately $236,000. The balance due on the promissory note
as of December 31, 2003 is $600,000 of which $461,000 is included in Long Term
Notes Receivable and the balance in included in Current Assets.
6
NOTE 6 - DEFERRED CHARGES
Deferred Charges consists of the following:
December 31 December 31 June 30
2003 2002 2003
----------- ----------- -----------
Unamortized debt issue costs $ 1,744,214 $ 818,982 $ 778,557
Deferred environmental remediation (see note 7) 496,253 524,918 541,196
Regulatory asset for property tax increases (see note 7) 2,897,000 2,430,000
Regulatory asset for income taxes 523,804 563,870 638,619
----------- ----------- -----------
Total $ 5,661,271 $ 1,907,770 $ 4,388,372
=========== =========== ===========
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 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.
As of December 31, 2003, the Company had incurred cumulative net costs
of approximately $1,984,000 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 Montana
Public Service Commission ("MPSC") allowing for recovery of the costs associated
with the evaluation and remediation of the site through a surcharge on customer
bills. As of December 31, 2003, the Company had recovered approximately
$1,488,000 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
7
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 $496,000 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 $496,000, the Company could be required to
refund to customers a portion of the $1,488,000 previously collected through
surcharges.
MONTANA PROPERTY TAX CONTINGENCY
By letter dated August 30, 2002, the Montana Department of Revenue
(DOR) notified the Company that the DOR had completed a property tax audit of
the Company for the period January 1, 1997 through and including December 31,
2001, and had determined that the Company had under-reported its personal
property and that additional property taxes and penalties should be assessed.
On August 8, 2003, the Company reached agreement with the DOR to pay to
the DOR $2,430,000 in back taxes (without interest or penalty) for tax years
1992 through and including 2002. The settlement amount will be paid in ten equal
annual installments of $243,000 on or before November 30 of each year and the
first payment under this obligation was made on November 21, 2003.
In October 2003, the Company received Montana property tax billings for
year 2003 and the property taxes on all Montana properties increased by
approximately $467,000 over the amount of property taxes approved for recovery
in current approved tariff rates.
The Company believes that Montana law permits it to recover through
future rate adjustments all amounts paid in connection with the DOR settlement,
and the increase in property taxes for calendar year 2003. Accordingly, in
November 2003, the Company filed amended rate schedules with the MPSC requesting
rate adjustments of approximately $768,000 to recover the additional taxes paid
for year 2003 and the DOR settlement. On December 31, 2003, the MPSC granted
interim relief to the Company, but reduced the amount of the Company's recovery
to $455,000. In its order granting the interim rate relief, the MPSC took the
position that the original rate increase request had not been reduced for income
tax benefits resulting from the property tax increases, and that Montana law
requires such reduction. The Company has filed comments with the MPSC taking the
position that no income tax benefit will result from the property tax. The
MPSC's final order has not been issued, and there is no assurance that the MPSC
will accept the Company's comments. If the final MPSC order retains the same tax
treatment as the interim order, then the Company intends through a general rate
filing to request an order from the MPSC allowing recovery of such costs.
The Company has established a regulatory asset and a liability for the
$2,430,000 payment obligation under the DOR settlement and the $467,000 increase
in property taxes for year 2003. Although the Company believes that full
recovery of such costs is permitted by Montana law, if the Company does not
recover all of such costs through rates, the Company would incur an additional
expense which could be materially adverse to the Company's financial statements.
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 (the "Fund") 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 and seeking other relief. On November 20, 2003,
the Company reached an agreement with J. Michael Gorman, Lawrence P. Haren,
Richard M. Osborne, and
8
Thomas J. Smith (collectively, the "Committee") and the Fund to resolve the
proxy contest initiated by the Committee to Re-Energize Energy West and settle
all pending litigation outstanding between the Fund and the Company. Pursuant to
the settlement agreement, immediately following the conclusion of the 2003
annual meeting, the Company expanded the size of its board of directors to nine
members and appointed Richard M. Osborne and Thomas J. Smith, two of the
Committee's proposed nominees for the board, and David A. Cerotzke, a mutually
agreed upon candidate, to the board of directors. Under the settlement agreement
the Committee and the Fund also agreed not to nominate any person for director
and generally not to solicit proxies from shareholders, including for the
election of directors, until the conclusion of the 2004 annual meeting of
shareholders, provided that the Company renominates Mr. Smith and Mr. Osborne
(or other designees of the Committee and the Fund) for election at the 2004
annual meeting.
EWR was involved in a lawsuit with PPLM Montana, LLC ("PPLM") which was
filed in U.S. Dirstrict Court for the District of Montana on July 2, 2001,
involving a wholesale electricity supply contract between EWR and PPLM. 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 of the settlement
amount was charged to operating expenses in fiscal year 2003.
NOTE 8 - OPERATIONS BY LINE OF BUSINESS
Three Months Ended Six Months Ended
December 31 December 31
-------------------------- --------------------------
2003 2002 2003 2002
----------- ----------- ----------- ------------
Gross Margin (Operating
Revenue Less Gas and
Power Purchased):
Natural Gas Operations $ 3,343,439 $ 3,014,315 $5,008,476 $ 4,453,792
Propane Operations 1,113,286 1,321,501 1,549,176 1,756,439
EWR 348,738 612,873 987,007 1,017,977
Pipeline Operations 96,416 69,534 205,766 153,278
----------- ----------- ----------- ------------
$ 4,901,879 $ 5,018,223 $7,750,425 $ 7,381,486
=========== =========== =========== ============
Operating Income (Loss):
Natural Gas Operations $ 777,953 $ 830,831 ($ 122,489) $ 126,860
Propane Operations 248,199 419,291 75,817 (8,229)
EWR 11,733 (791,794) 310,587 (1,022,789)
Pipeline Operations 41,208 12,865 99,171 63,616
----------- ----------- ----------- ------------
$ 1,079,093 $ 471,193 $ 363,086 ($ 840,542)
=========== =========== =========== ============
Net Income (Loss):
Natural Gas Operations $ 238,485 $ 386,735 ($ 469,527) ($ 231,195)
Propane Operations 84,107 230,314 (59,739) (43,711)
EWR (40,066) (504,170) 95,419 (663,465)
Pipeline Operations 30,648 7,932 125,465 38,607
----------- ----------- ----------- ------------
$ 313,174 $ 120,811 ($ 308,382) ($ 899,764)
=========== =========== =========== ============
(Segment information for prior periods has been restated to reflect the
realignment of the Company's reporting segments)
9
NOTE 9 - ACCRUED AND OTHER CURRENT LIABILITIES
Accrued and Other Current Liabilities consists of the following:
December 31 December 31 June 30
2003 2002 2003
----------- ----------- -----------
Litigation reserve for PPLM settlement $ 2,000,000 $ 2,200,000
Property tax settlement - current portion $ 243,000 243,000
Payable to employee benefit plans 309,482 506,820 568,133
Accrued vacation 438,008 445,288 429,333
Customer deposits 420,273 381,298 576,917
Accrued compensation 785,760 1,608,443 464,394
Accrued interest 172,573 124,177 106,860
Accrued taxes other than income 594,206 (3,368) 219,853
Other 236,734 54,453 500,764
----------- ----------- -----------
Total $ 3,200,036 $ 5,117,111 $ 5,309,254
=========== =========== ===========
NOTE 10 - OTHER LONG TERM LIABILITIES
Other Long Term Liabilities consists of the following:
December 31 December 31 June 30
2003 2002 2003
----------- ----------- -----------
Contribution in aid of construction $ 1,068,937 $ 1,034,732 $ 1,066,804
Property tax settlement 1,989,456 2,187,000
Asset retirement obligation 570,947 363,750 555,665
Customer advances for construction 551,610 584,261 538,010
Accumulated post retirement obligation 235,068 177,382 209,800
Deferred gain on sale leaseback of assets 59,081 82,709 70,895
Regulatory liabilities 83,161 83,161 263,026
Other 30,107 28,259
----------- ----------- -----------
Total $ 4,588,367 $ 2,354,254 $ 4,891,200
=========== =========== ===========
NOTE 11 - NEW ACCOUNTING PRONOUNCEMENTS
In April 2003, the 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 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.
10
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 Section 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 our
operating capital requirements, negotiations with our lender, recovery of
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 risk 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
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 Company utilizes short-term credit facilities in order to finance
its operations. The Company is subject to the risks associated with the need to
renegotiate and renew such credit facilities on at least an annual basis. The
Company presently is in the process of refinancing the LaSalle Credit Facility,
and is subject to risks of default under its credit facilities in the event that
such refinancing cannot be completed.
The Company is subject to regulation at both the state and federal
level. These regulatory structures have undergone major, significant changes.
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 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 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
11
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 that would cause it to discontinue the application of
SFAS No. 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.
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 involve the distribution of
regulated natural gas to the public in the Great Falls and West Yellowstone,
Montana and the Cody, Wyoming areas. Also included
12
in the Natural Gas Operations is the Company's Cascade Gas operation, a small
regulated propane operation located in Cascade, Montana.
The Company's Propane Operations include 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 EWP. Until August 21, 2003, EWP marketed its
product throughout the Rocky Mountain states including 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 pre-tax 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.
EWR 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 and the revenues and expenses associated with these gathering systems
were previously reported by the Pipeline Operations for fiscal year 2003. EWR
also owns natural gas production reserves in north central Montana which
generate approximately 1,000 Mmbtus per day, or approximately five percent of
EWR's annual sales volume.
The Company's pipeline operations consist 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 for reporting purposes
beginning on July 1, 2003.
ENERGY WEST, INCORPORATED AND SUBSIDIARIES
DECEMBER 31, 2003
QUARTERLY RESULTS OF CONSOLIDATED OPERATIONS
Gross Margin
Gross margin, which is defined as operating revenue less gas purchased,
decreased $116,000, from $5,018,000 in the second quarter of fiscal year 2003 to
$4,902,000 in the second quarter of fiscal year 2004. The Natural Gas Operations
margins increased $329,000 due to approved rate increase in both the Wyoming and
Montana operations. The Propane Operations margins decreased $209,000 due to the
exiting of the wholesale propane market. The Company's EWR Operations margin
decreased approximately $264,000, attributable to the exiting of the electricity
market and lower gas margins partially offset by additional margins from
production properties. Pipeline Operations margins increased $26,000 due to the
Shoshone interstate pipeline being placed in service effective as of July 1,
2003.
Operating Expense
Operating expenses decreased by $724,000 in the second quarter of
fiscal year 2004 as compared to the second quarter of fiscal year 2003. The
Company's distribution, general and administration expenses decreased by
$733,000 primarily due to the reduced legal expenses related the PPLM
litigation, maintenance expense decreased by $13,000, depreciation expense
increased by
13
approximately $73,000 due to the depletion of the natural gas reserves and the
depreciation of the Shoshone pipeline, and all other expenses decreased by
approximately $51,000 due to various cost reduction measures.
Interest Expense
Interest expense increased by approximately $242,000 during the second
quarter of fiscal year 2004 from the second quarter of fiscal year 2003 due to
higher short term corporate borrowings and the amortization of debt issuance
costs related to the recently negotiated short term credit facility.
Income Taxes
Income taxes increased from $29,000 for the second quarter of fiscal
year 2003 to $185,000 for the second quarter of fiscal year 2004, an increase of
$156,000, due to higher pre-tax income.
SIX MONTHS RESULTS FOR CONSOLIDATED OPERATIONS
Gross Margin
Gross margins increased from approximately $7,381,000 for the first six
months of fiscal year 2003 to $7,750,000 for the first six months of fiscal year
2004 or $369,000. The increase in margins was due to a combination of higher
Natural Gas margins of $554,000 due to approved rate increases in the Great
Falls and Cody locations, lower propane margins of $207,000 due to exiting of
the wholesale propane market, lower EWR margins of approximately $31,000, and
higher Pipeline margins of approximately $53,000, attributable to the Shoshone
pipeline.
Operating Expenses
Total operating expenses for the first six months of fiscal year 2003
were $8,222,000 compared to $7,387,000 for the first six months of fiscal year
2004 a decrease of $835,000. Distribution, general and administrative expenses
decreased by approximately $888,000 due to reduced legal and other professional
fees, maintenance expenses decreased by $68,000, depreciation expense increased
by approximately $131,000 due to the depletion of the natural gas reserves and
the depreciation of the Shoshone pipeline, and all other expenses decreased by
$10,000.
Interest Expense
Interest expense increased by approximately $301,000 during the first
six months of fiscal year 2004 due to higher short term corporate borrowing and
the amortization of debt issuance costs related to the recently negotiated short
term credit facility.
Income Taxes
Income tax benefits decreased from $571,000 for the first six months of
fiscal year 2003 to $163,000 for the first six months of fiscal year 2004, a
decrease of $408,000, due to lower pre-tax losses.
14
RESULTS OF THE COMPANY'S NATURAL GAS OPERATIONS
Three Months Six Months
Ended December 31 Ended December 31
2003 2002 2003 2002
Natural Gas Revenues $ 12,276,986 $ 8,778,652 $16,939,994 $11,759,027
Natural Gas Purchased 8,933,547 5,764,337 11,931,518 7,305,235
------------ ------------ ------------ ------------
Gross Margin 3,343,439 3,014,315 5,008,476 4,453,792
Operating Expenses 2,565,486 2,183,484 5,130,965 4,326,932
------------ ------------ ------------ ------------
Operating Income (Loss) 777,953 830,831 (122,489) 126,860
Other (Income) (27,459) (18,404) (60,934) (47,065)
Interest Expense 423,200 250,695 700,528 513,169
Income Taxes (Benefit) 143,727 211,805 (292,556) (108,049)
------------ ------------ ------------ ------------
Net Natural Gas Income (Loss) $ 238,485 $ 386,735 ($ 469,527) ($ 231,195)
------------ ------------ ------------ ------------
QUARTERLY RESULTS FOR NATURAL GAS OPERATIONS
Revenues and Gross Margin
Natural gas operating revenues for the second quarter of fiscal year
2004 were approximately $12,277,000 compared to approximately $8,779,000 for the
second quarter of fiscal year 2003, an increase of approximately $3,498,000 or
40%. While the sales volumes remained consistent between periods the increase in
revenues is due to the higher price paid for natural gas that is passed through
to customers and increased customer rates that are in effect in both the Great
Falls and Cody locations.
Gas costs increased from $5,764,000 in the second quarter of fiscal
year 2003 to $8,934,000 in the second quarter of fiscal year 2004 an increase of
approximately $3,170,000. Volume sales remained constant but the price paid for
natural gas purchased increased approximately 46%, from an average of $2.78 per
Mcf for the three months ended December 31, 2002, compared to $4.05 per Mcf for
the period ended December 31, 2003.
Gross margin, which is defined as operating revenues less gas
purchased, was approximately $3,343,000 for the second quarter of fiscal year
2004, compared to a gross margin of approximately $3,014,000 for the second
quarter of fiscal year 2003. The increase of $329,000 is primarily due to higher
rates charged to customers in both the Great Falls and Cody locations.
Operating Expenses
Operating expenses from Natural Gas Operations increased approximately
$382,000, from $2,183,000 in the second quarter of fiscal year 2003 to
$2,565,000 in the second quarter of fiscal year 2004. The increase in operating
expenses is related primarily to increases in corporate overhead costs of
approximately $319,000 due to higher legal and professional fees paid and an
increase in general liability insurance expense of approximately $70,000. The
increase in expenses was partially offset by reductions in all other expenses
of approximately $7,000.
Interest Expense
Interest charges allocable to the Company's Natural Gas Operations
increased from approximately $251,000 for the second quarter of fiscal year 2003
to approximately $423,000 for the
15
second quarter of fiscal year 2004. The increase was due to higher short term
corporate borrowings and increased amortization of issuance costs related to the
recently negotiated short term credit facility.
Income Taxes
Income taxes related to the Company's Natural Gas Operations decreased
approximately $68,000 for the second quarter of fiscal year 2004 as compared to
the second quarter of fiscal year 2003 as a result of lower pre-tax earnings.
SIX MONTHS RESULTS FOR THE NATURAL GAS OPERATIONS
Revenues and Gross Margin
Natural gas operating revenues in the first six months of fiscal year
2004 were approximately $16,940,000 compared to approximately $11,759,000 for
the first six months of fiscal year 2003, an increase of approximately 44%. The
increase is due to the higher price of natural gas that is passed through to
customers and increased rates charged to customers in the Company's Great Falls
and Cody locations.
Gas costs increased from $7,305,000 in the first six months of fiscal
year 2003 to $11,932,000 in the first six months of fiscal year 2004 due to
increased gas prices of approximately 67%. Natural gas prices averaged
approximately $2.53 for the first six months of fiscal year 2003 compared to
$4.23 for the six months of fiscal year 2004.
Gross margin, which is defined as operating revenues less gas
purchased, was approximately $5,008,000 for the first six months of fiscal year
2004, compared to a gross margin of approximately $4,454,000 for the first six
months of fiscal year 2003. The increase in margin is related to increased rates
charged to customers in the Great Falls and Cody natural gas locations.
Operating Expenses
Operating expenses from Natural Gas Operations increased approximately
$804,000, from $4,327,000 for the first six months of fiscal year 2003 to
$5,131,000 for the first six months of fiscal year 2004. The increase in
operating expenses is related primarily to increases in corporate overhead costs
of $647,000 due to higher legal and professional fees, an increase in general
liability insurance expense of approximately $141,000 and an increase in
depreciation expense of approximately $29,000. These increased expenses were
partially offset by reductions in all other expenses of approximately $13,000.
Interest Expense
Interest charges allocable to the Company's Natural Gas Operations were
approximately $513,000 for the six months of fiscal year 2003, as compared to
$701,000 in the comparable period in fiscal year 2004, an increase of $188,000.
This increase was due to higher short term corporate borrowings and increased
amortization of issuance costs related to the recently negotiated short term
credit facility.
Income Taxes
The income tax benefit related to the Company's Natural Gas Operations
increased approximately $185,000 for the first six months of fiscal year 2004 as
compared to the first six months of fiscal year 2003 due to higher pre-tax
losses.
16
RESULTS OF THE COMPANY'S PROPANE OPERATIONS
Three Months Six Months
Ended December 31 Ended December 31
2003 2002 2003 2002
Operating Revenues $ 2,141,177 $ 4,268,933 $ 3,323,078 $ 5,331,642
Propane Purchased 1,027,891 2,947,432 1,773,902 3,575,203
----------- ----------- ----------- -----------
Gross Margin 1,113,286 1,321,501 1,549,176 1,756,439
Operating Expenses 865,087 902,210 1,473,359 1,764,668
----------- ----------- ----------- -----------
Operating Income (Loss) 248,199 419,291 75,817 (8,229)
Other (Income) (42,340) (60,647) (77,935) (108,436)
Interest Expense 148,826 96,220 264,135 193,177
Income Taxes (Benefit) 57,606 153,404 (50,644) (49,259)
----------- ----------- ----------- -----------
Net Propane Income (Loss) $ 84,107 $ 230,314 ($ 59,739) ($ 43,711)
----------- ----------- ----------- -----------
QUARTERLY RESULTS FOR PROPANE OPERATIONS
Gross Margin
Gross margin from the Propane Operations decreased approximately
$209,000, from $1,322,000 in second quarter of fiscal year 2003 to $1,113,000 in
second quarter of fiscal year 2004. This decrease is due primarily to the sale
of the wholesale propane business resulting in the elimination of approximately
four million gallons of volume during the second quarter of fiscal year 2004.
Operating Expenses
Operating expenses from the Propane Operations decreased approximately
$37,000, from $902,000 in the second quarter of fiscal year 2003 to $865,000 in
the second quarter of fiscal year 2004. This decrease is due to a reduction in
operating expenses resulting from the sale of the wholesale propane business of
approximately $136,000 partially offset by an increase in corporate overhead
costs of approximately $99,000.
Interest Expense
Interest expense increased from approximately $96,000 for the second
quarter of fiscal year 2003 to approximately $149,000 for the second quarter of
fiscal year 2004, an increase of approximately $53,000. This increase was due to
higher short term corporate borrowings and the amortization of issuance costs of
the recently negotiated short term credit facility.
Income Taxes
Income taxes related to the Company's Propane Operations decreased
approximately $96,000 for the second quarter of fiscal year 2004 as compared to
the second quarter of fiscal year 2003 as a result of lower pre-tax earnings.
17
SIX MONTHS RESULTS FOR PROPANE OPERATIONS
Gross Margin
Gross margin from Propane Operations decreased approximately $207,000,
from $1,756,000 for the first six months of fiscal year 2003 to $1,549,000 for
the first six months of fiscal year 2004. This decrease was due primarily to the
sale of the wholesale propane operations which resulted in lost volumes of
approximately five million gallons and related gross margin of approximately
$287,000. The lost margin from the sale of the wholesale propane operations was
offset by additional gross margins from the retail operations in the Company's
Payson Arizona location.
Operating Expenses
Operating expenses from the Propane Operations segment decreased
approximately $292,000, from $1,765,000 for the first six months of fiscal year
2003 to $1,473,000 for the first six months of fiscal year 2004. This decrease
in operating expenses is related to the gain on the sale of the wholesale
propane operations of $236,000, a reduction of operating expenses related to the
wholesale propane operations of approximately $172,000 and additional expense
reduction of $86,000. Offsetting these expense reductions was an increase in
corporate overhead costs of approximately $202,000.
Interest Expense
Interest expense increased from approximately $193,000 for the first
six months of fiscal year 2003 to approximately $264,000 for the first six
months of fiscal year 2004. This increase of approximately $71,000 was due to
higher short term corporate borrowings and increased amortization of issuance
costs of the recently negotiated short term credit facility.
Income Taxes
The income tax benefit related to the Company's Propane Operations
increased approximately $1,000 for the first six months of fiscal year 2004 as
compared to the first six months of fiscal year 2003 resulting from lower
pre-tax earnings.
RESULTS OF THE COMPANY'S EWR OPERATIONS
Three Months Six Months
Ended December 31 Ended December 31
2003 2002 2003 2002
Marketing Revenue $ 8,297,247 $ 9,368,696 $ 14,622,547 $ 15,604,735
Purchases 7,948,509 8,755,823 13,635,540 14,586,758
------------ ------------ ------------ ------------
Gross Margin 348,738 612,873 987,007 1,017,977
Operating Expenses 337,005 1,404,667 676,420 2,040,766
------------ ------------ ------------ ------------
Operating Income (Loss) 11,733 (791,794) 310,587 (1,022,789)
Other (Income) Expense 4,009 (4,050) 1,384 (5,570)
Interest Expense 62,758 57,614 109,164 84,509
Income taxes (14,968) (341,188) 104,620 (438,263)
------------ ------------ ------------ ------------
Net Marketing Income (Loss) ($ 40,066) ($ 504,170) $ 95,419 ($ 663,465)
------------ ------------ ------------ ------------
18
QUARTERLY RESULTS OF EWR OPERATIONS
Gross Margin
Gross margin from EWR Operations decreased approximately $264,000, from
$613,000 in the second quarter of fiscal year 2003 to $349,000 in the second
quarter of fiscal year 2004. This decrease was due primarily to exiting the
electricity market reducing margins by approximately $231,000 and lower gas
trading margins of $154,000. These margin decreases were offset by an increase
in production margins of approximately $121,000.
Operating Expenses
Operating expenses from the EWR Operations decreased approximately
$1,068,000, from $1,405,000 in the second quarter of fiscal year 2003 to
$337,000 in the second quarter of fiscal year 2004. This decrease in operating
expenses is related to the decreased legal costs related to the PPLM litigation
of approximately $855,000 and other cost savings measures of $213,000.
Interest Expense
Interest expense increased from approximately $58,000 for the second
quarter fiscal year 2003 to approximately $63,000 for the second quarter of
fiscal year 2004, an increase of approximately $5,000. This increase was due to
higher short term corporate borrowings and the amortization of issuance costs
related to the recently negotiated short term credit facility.
Income Taxes
Income tax benefits related to the Company's EWR Operations decreased
approximately $326,000 for the second quarter of fiscal 2004 as compared to the
second quarter of fiscal 2003 due to the lower pre-tax losses.
SIX MONTHS RESULTS OF EWR OPERATIONS
Gross Margin
Gross margin from EWR for the first six months of fiscal year 2004 was
approximately $987,000 compared to $1,018,000 for the first six months of fiscal
year 2003, a decrease of approximately $31,000. This decrease was due primarily
to reduced gas margins of approximately $178,000 offset by an increase in
electricity margins of $60,000 and production margins of approximately $87,000.
Operating Expenses
Operating expenses from EWR Operations decreased approximately
$1,364,000, from $2,040,000 for the first six months of fiscal year 2003 to
$676,000 for the first six months of fiscal year 2004. This decrease in
operating expenses is due to decreased legal costs related to the PPLM
litigation of approximately $1,075,000, a reduction in other professional fees
of $59,000, a reduction in salaries and related expenses of approximately
$78,000, a reduction in travel and related expenses of $25,000 and other cost
saving measures of $127,000.
19
Interest Expense
Interest expense increased from approximately $85,000 for the first six
months of fiscal year 2003 to approximately $109,000 for the first six months of
fiscal year 2004. This increase of approximately $24,000 was due to higher short
term corporate borrowings and the increased amortization of issuance costs
related to the recently negotiated short term credit facility.
Income Taxes
The income tax expense related to the Company's EWR Operations
increased approximately $543,000 for the first six months of fiscal 2004 as
compared to the first six months of fiscal year 2003 resulting from higher
pre-tax earnings.
RESULTS OF THE COMPANY'S PIPELINE OPERATIONS
Three Months Six Months
Ended December 31 Ended December 31
2003 2002 2003 2002
Pipeline Revenue $ 96,416 $ 69,534 $ 205,766 $ 153,278
--------- --------- --------- ---------
Gross Margin 96,416 69,534 205,766 153,278
Operating Expenses 55,208 56,669 106,595 89,662
--------- --------- --------- ---------
Operating Income 41,208 12,865 99,171 63,616
Other Income (949) (120,922) (949)
Interest Expense 12,229 895 19,283 1,669
Income Taxes (Benefit) (1,669) 4,987 75,345 24,289
--------- --------- --------- ---------
Net Pipeline Income (Loss) $ 30,648 $ 7,932 $ 125,465 $ 38,607
--------- --------- --------- ---------
QUARTERLY RESULTS FOR PIPELINE OPERATIONS
Gross Margin
Gross margin from the Pipeline Operations increased approximately
$26,000, from $70,000 in second quarter of fiscal year 2003 to $96,000 in second
quarter of fiscal year 2004. This increase was due primarily to the Shoshone
interstate pipeline beginning operations on July 1, 2003.
Operating Expenses
Operating expenses from the Pipeline Operations decreased approximately
$2,000, from $57,000 in the second quarter of fiscal year 2003 to $55,000 in the
second quarter of fiscal year 2004. This decrease was due to a decrease in
general expenses related to pipeline operations.
Interest Expense
Interest expense increased from approximately $1,000 for the second
quarter of fiscal year 2003 to approximately $12,000 for the second quarter of
fiscal year 2004. The increase was due to higher corporate short term borrowings
and the amortization of the issuance costs of the LaSalle Facility.
20
Income Taxes
Income taxes related to the Company's Pipeline Operations decreased
approximately $7,000 for the second quarter of fiscal year 2004 as compared to
the second quarter of fiscal year 2003.
SIX MONTHS RESULTS FOR PIPELINE OPERATIONS
Gross Margin
Gross margin from Pipeline Operations increased approximately $53,000,
from $153,000 in second quarter fiscal year 2003 to $206,000 in second quarter
fiscal year 2004. This increase was due primarily to the Shoshone interstate
pipeline beginning operations on July 1, 2003.
Operating Expenses
Operating expenses from the Pipeline Operations increased approximately
$17,000, from $90,000 for the first six months of fiscal year 2003 to $107,000
for the first six months of fiscal year 2004. The increase was due primarily to
an increase in corporate overhead expenses allocated to Pipeline Operations.
Other Income
Other income for the first six months of fiscal year 2004 included the
sale of certain non-operating real estate assets located in Montana, which
resulted in a gain of $121,000.
Interest Expense
Interest expense increased from approximately $2,000 for the first six
months of fiscal year 2003 to approximately $19,000 for the first six months of
fiscal year 2004. This increase was due to higher corporate borrowings and the
amortization of issuance costs related to the LaSalle Facility.
Income Taxes
Income taxes that relate to the Company's Pipeline Operations were
approximately $75,000 for the first six months of fiscal year 2004, as compared
to $24,000 for the first six months of fiscal year 2003, an increase of
approximately $51,000 due to higher pre-tax income.
CASH FLOW ANALYSIS
The primary cash flows during the six month periods ending December 31,
2003 and December 31, 2002 are summarized as follows:"
December 31 December 31
2003 2002
------------ ------------
Used in operating activities ($13,344,672) ($2,994,966)
Used in investing activities (199,871) (2,395,790)
Provided by financing activities 13,203,996 6,392,760
----------- -----------
Net increase (decrease) in cash and cash equivalents ($ 340,547) $ 1,002,004
=========== ===========
21
For the six months ended December 31, 2003, the Company and its
subsidiaries used $13,345,000 of cash in its operating activities compared to
$2,995,000 for the six months ended December 31, 2002. This increase in cash
used of $10,350,000 was primarily due to increases in natural gas and propane
inventory expenditures of $6,778,000, a decrease in deferred tax liability of
$288,000, an increase in the amount paid on accounts payable of $3,256,000 and
an increase in the amounts paid for other assets and liabilities of $2,807,000.
Offsetting these amounts was a decrease in net loss of $591,000, an increase in
the collection of accounts receivable of $311,000 and a decrease in the amount
of recoverable gas purchases of $1,877,000.
Cash used by investing activities was $200,000 for the six months ended
December 31, 2003, compared to cash used of $2,396,000 for the six months ended
December 31, 2002. This decrease in cash used of $2,196,000 was primarily due to
a reduction in construction expenditures of $1,386,000, and an increase in cash
from the sale of the wholesale propane and real estate assets of $840,000.
Offsetting these reductions was an increase in cash used in investing activities
of $30,000 related to the Company's regulatory operations.
Cash provided by financing activities was $13,204,000 for the six
months ended December 31, 2003, as compared to $6,393,000 for the six months
ended December 31, 2002. The increase of $6,811,000 was due primarily from an
increase in proceeds from the Company's short-term lines of credit of $7,382,000
and a reduction in shareholders dividend payments of $668,000. Offsetting these
increases in proceeds was an increase in debt issuance costs of $1,180,000 and
an increase in the payment related to the Company's long-term debt of $59,000.
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.
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.
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 Company's previous 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. 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 are
secured on an equal and ratable basis with the Lender in the collateral granted
to secure the LaSalle Facility with the exception of the first $1,000,000 of
debt under the LaSalle Facility.
Under applicable law, the Company obtained required approvals from the
MPSC and the Wyoming Public Service Commission ("WPSC") to enter into the
LaSalle Facility. The MPSC order
22
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. In addition, the LaSalle Facility requires that the Company provide a
first priority security interest in certain assets to the Lender no later than
March 31, 2004, which would require either restructuring or refinancing of the
Company's Long Term Debt. The Company is presently working on refinancing in
order to satisfy the Lender's requirements. The Company believes that it will be
able to implement such refinancing by March 31, 2004. Failure to complete such
refinancing would result in a default under the terms of the LaSalle Facility.
During the period prior to such refinancing of the LaSalle Facility,
the terms of the LaSalle Facility provide that the Company cannot pay dividends
to its shareholders. In June 2003, the Company's Board of Directors suspended
the Company's dividend to allow for strengthening of the Company's balance
sheet.
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. At December 31, 2003, the ratio was .70 to 1.00. The
Lender has waived this covenant for the quarters ended September 30, 2003 and
December 31, 2003.
At December 31, 2003, the Company had borrowed approximately
$20,629,000 under the LaSalle Facility and $2,300,000 was pledged as security
for outstanding letters of credit.
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 notes bearing interest at the rate of 7.5%;
$7,800,000 of Series 1993 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 $15,211,000 and $15,770,000, at December 31, 2003 and December 31, 2002,
respectively. The portion of such obligations due within one year was $530,000
and $500,000 at December 31, 2003, and December 31, 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.
23
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 Committee , 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 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 December 31, 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: $ 822,999 $ 267,970
Contracts maturing in two to three years: 1,038,129 420,082
Contracts maturing in four to five years: 357,284 196,576
----------- -----------
Total $ 2,218,412 $ 884,628
=========== ===========
24
During the first six months 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 derivative contracts are
subject to deferral under regulatory procedures of 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.
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 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. In
25
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 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, 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-15(e) and 15d-15(e)) 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.
Form 10-Q
Part II - Other Information
Item 1 LEGAL PROCEEDINGS
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.
26
On November 12, 2003, Turkey Vulture Fund XIII, Ltd., an Ohio limited
liability company (the "Fund") 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 and seeking other relief. On November 20, 2003,
the Company reached an agreement with J. Michael Gorman, Lawrence P. Haren,
Richard M. Osborne, and Thomas J. Smith (collectively, the "Committee") and the
Fund to resolve the proxy contest initiated by the Committee to Re-Energize
Energy West and settle all pending litigation outstanding between the Fund and
the Company. Pursuant to the settlement agreement, immediately following the
conclusion of the 2003 annual meeting, the Company expanded the size of its
board of directors to nine members and appointed Richard M. Osborne and Thomas
J. Smith, two of the Committee's proposed nominees for the board, and David A.
Cerotzke, a mutually agreed upon candidate, to the board of directors. Under the
settlement agreement the Committee and the Fund also agreed not to nominate any
person for director and generally not to solicit proxies from shareholders,
including for the election of directors, until the conclusion of the 2004 annual
meeting of shareholders, provided that the Company renominates Mr. Smith and Mr.
Osborne (or other designees of the Committee and the Fund) for election at the
2004 annual meeting.
EWR was involved in a lawsuit with PPLM Montana, LLC ("PPLM") which was
filed in U.S. District Court for the District of Montana on July 2, 2001,
involving a wholesale electricity supply contract between EWR and PPLM. 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 of the settlement
amount was charged to operating expenses in fiscal year 2003.
Item 2. Changes in Securities, Use of Proceeds and Issuer Purchases of Equity -
Not Applicable
Item 3. Defaults upon Senior Securities - Not Applicable
Item 4. Submission of Matters to a Vote of Security Holders
The Company held its annual shareholder meeting on December 3, 2003.
The item voted on by the shareholders consisted of the election of corporate
directors. Those individuals elected to the Company Board of Directors, for a
one-year term, and their respective number of votes cast for and withheld are as
follows:
Name Votes Cast For Votes Withheld
- ---------------------- -------------- --------------
W.E. (Gene) Argo 1,480,900 110,330
Andrew Davidson 1,992,753 149,581
David A. Flitner 1,034,568 107,766
G. Montgomery Mitchell 1,489,925 101,306
Terry M. Palmer 1,466,368 124,863
George D. Ruff 970,296 172,038
Richard J. Schulte 1,511,540 79,691
Item 5. Other Information - Not Applicable
27
Item 6. Exhibits and Reports on Form 8-K
A. Exhibits for the second quarter ended December 31, 2003.
10.1 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).
10.2 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).
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 second quarter
ended December 31, 2003 as follows.
Date Filed Item No.
October 2, 2003 Item 7 - Press Release dated September 30,
2003.
Item 12 - Earnings announcement on September
30, 2003 regarding the Company's preliminary
fiscal year 2003 earnings.
October 2, 2003 Item 5 - Announcement regarding the new
credit agreement with LaSalle Bank National
Association
Item 7 - Credit Agreement, dated as of
September 30, 2003, by and among Energy
West, Incorporated, Various Financial
Institutions and LaSalle Bank National
Association, as Agent; and Press Release
dated September 30, 2003.
October 9, 2003 Item 5 - Announcement regarding the new
credit agreement with LaSalle Bank National
Association
Item 7 - Credit Agreement, dated as of
September 30, 2003, by and among Energy
West, Incorporated, Various Financial
Institutions and LaSalle Bank National
Association, as Agent; and Press Release
dated September 30, 2003.
October 27, 2003 Item 5 - Announcement of Separation
Agreement with Edward J. Bernica.
28
Item 7 - Separation Agreement, Release and
Waiver of Claims between Energy West,
Incorporated and Edward J. Bernica dated
October 24, 2003.
October 30, 2003 Item 5 - Announcement regarding
reconstitution of the compensation
committee.
November 12, 2003 Item 5 - Announcement of postponement of the
Company's annual meeting.
Item 7 - Press Release dated November 11,
2003.
November 19, 2003 Item 5 - Announcement regarding answer and
counterclaim filed in connection with the
proxy contest.
Item 7 - Answer and Counterclaim for
Declaratory Relief filed in the Montana
Eighth Judicial District Court, Cascade
County, Cause No. DDV-03-1214.
November 21, 2003 Item 5 - Announcement regarding resolution
of the proxy contest.
Item 7 - Press Release dated November 21,
2003.
29
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)
February 17, 2004
30