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 March 31, 2004
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from _______________ to _______________
Commission File number 0-14183
ENERGY WEST, INCORPORATED
(Exact name of registrant as specified in its charter)
Montana 81-0141785
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
1 First Avenue South, Great Falls, 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 March 31, 2004
(Common stock, $.15 par value) 2,597,681 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
March 31, 2004, March 31, 2003 and June 30, 2003 1
Condensed Consolidated Statements of Operations -
three months and nine months ended March 31, 2004 and 2003 2
Condensed Consolidated Statements of Cash Flows -
nine months ended March 31, 2004 and 2003 3
Notes to Condensed Consolidated Financial Statements 4-11
Item 2 - Management's discussion and analysis of
financial condition and results of operations 11-27
Item 3 - Quantitative and Qualitative Disclosures about Market Risk 27-28
Item 4 - Controls and Procedures 28
Part II - Other Information
Item 1 - Legal Proceedings 29
Item 2 - Changes in Securities 29
Item 3 - Defaults upon Senior Securities 29
Item 4 - Submission of Matters to a Vote of Security Holders 29
Item 5 - Other Information 29
Item 6 - Exhibits and Reports on Form 8-K 30
Signatures 31
Item 1. Financial Statements
FORM 10-Q
ENERGY WEST, INCORPORATED
CONDENSED CONSOLIDATED BALANCE SHEETS
March 31 March 31 June 30
2004 2003 2003
(Unaudited) (Unaudited) (Unaudited)
----------- ----------- -----------
Current assets:
Cash and cash equivalents $ 4,399,596 $ 1,532,886 $ 1,938,768
Accounts receivable (net) 9,424,679 13,282,926 7,971,632
Derivative assets 2,367,718 2,770,684 2,719,640
Natural gas and propane inventories 2,599,787 465,051 1,038,690
Materials and supplies 360,390 472,960 371,490
Prepayments and other 400,650 287,443 352,982
Deferred tax assets 453,181 53,370 828,698
Deferred purchase gas costs 669,807 769,266 1,067,109
Prepaid income tax payments 1,325,060 847,362 1,882,889
----------- ----------- -----------
Total current assets 22,000,868 20,481,948 18,171,898
Long term notes receivable 409,638
Property, plant and equipment, net 38,398,206 39,211,269 39,576,596
Deferred charges 5,624,694 1,831,692 4,388,372
Other assets 227,313 313,998 271,429
----------- ----------- -----------
Total assets $66,660,719 $61,838,907 $62,408,295
=========== =========== ===========
Capitalization and liabilities:
Current liabilities:
Lines of credit $ 9,229,304 $ 5,694,152 $ 6,104,588
Current portion of long-term debt 8,537,618 507,219 532,371
Accounts payable 3,520,212 10,853,949 8,841,779
Derivative liabilities 1,167,652 404,117 780,703
Accrued and other current liabilities 3,771,781 5,524,123 5,309,254
----------- ----------- -----------
Total current liabilities 26,226,567 22,983,560 21,568,695
----------- ----------- -----------
Long-term liabilities:
Deferred tax liabilities 5,154,352 4,618,134 5,460,083
Deferred investment tax credits 339,610 360,672 355,406
Other long-term liabilities 4,593,039 2,329,733 4,891,200
----------- ----------- -----------
Total 10,087,001 7,308,539 10,706,689
Long-term debt 14,687,996 15,280,075 14,834,452
Stockholders' equity:
Preferred stock - $.15 par value
Authorized - 1,500,000 shares; Issued - none
Common stock - $.15 par value 389,659 389,024 $ 389,295
Authorized - 3,500,000 shares
Outstanding - 2,597,681 shares at March 31, 2004;
2,594,258 shares at March 31, 2003;
and 2,595,250 shares at June 30, 2003
Capital in excess of par value 5,072,316 5,044,507 5,056,425
Retained earnings 10,197,180 10,833,202 9,852,739
----------- ----------- -----------
Total stockholders' equity 15,659,155 16,266,733 15,298,459
----------- ----------- -----------
Total capitalization 30,347,151 31,546,808 30,132,911
----------- ----------- -----------
Total capitalization and liabilities $66,660,719 $61,838,907 $62,408,295
=========== =========== ===========
The accompanying notes are an integral part of these condensed
financial statements.
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FORM 10-Q
ENERGY WEST, INCORPORATED
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
Three Months Ended Nine Months Ended
March 31 March 31
2004 2003 2004 2003
(Unaudited) (Unaudited) (Unaudited) (Unaudited)
----------- ----------- ----------- -----------
Revenues:
Natural gas operations $14,922,716 $13,348,431 $31,862,710 $25,107,458
Propane operations 3,293,484 5,527,217 6,616,562 10,858,859
Gas and electric-wholesale 6,272,088 10,639,380 20,894,635 26,244,115
Pipeline 93,197 101,481 298,963 254,759
----------- ----------- ----------- -----------
Total revenues 24,581,485 29,616,509 59,672,870 62,465,191
----------- ----------- ----------- -----------
Expenses:
Gas and propane purchased 12,662,446 13,761,454 26,367,866 24,641,892
Gas and electric-wholesale 6,995,703 9,090,259 20,631,243 23,677,017
Distribution, general and administrative 2,143,361 2,527,860 7,645,328 8,918,162
Maintenance 126,518 118,586 350,938 411,194
Depreciation and amortization 500,281 564,482 1,732,755 1,665,022
Taxes other than income 457,695 209,222 886,175 647,800
----------- ----------- ----------- -----------
Total operating expenses 22,886,004 26,271,863 57,614,305 59,961,087
----------- ----------- ----------- -----------
Operating income 1,695,481 3,344,646 2,058,565 2,504,104
Non-operating income 50,587 55,243 308,994 217,263
Interest expense:
Long-term debt 283,058 291,452 850,433 875,517
Lines of credit 435,334 143,553 961,069 352,012
----------- ----------- ----------- -----------
Total interest expense 718,392 435,005 1,811,502 1,227,529
----------- ----------- ----------- -----------
Income before income tax expense 1,027,676 2,964,884 556,057 1,493,838
Income tax expense 358,597 1,185,726 195,360 614,444
----------- ----------- ----------- -----------
Net income $ 669,079 $ 1,779,158 $ 360,697 $ 879,394
=========== =========== =========== ===========
Earnings per common share:
Basic and diluted income per common share $ 0.26 $ 0.69 $ 0.14 $ 0.34
Weighted average common shares outstanding:
Basic 2,596,048 2,582,551 2,596,048 2,582,551
Diluted 2,596,048 2,582,551 2,596,048 2,582,551
The accompanying notes are an integral part of these condensed
financial statements.
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FORM 10-Q
ENERGY WEST, INCORPORATED
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
Nine Months Ended
March 31
2004 2003
(Unaudited) (Unaudited)
------------ ------------
Cash flow from operating activities:
Net income $ 360,697 $ 879,394
Adjustment to reconcile net income to net cash flows
provided by (used in) operating activities
Depreciation and amortization, including deferred charges and
financing costs 2,177,519 1,788,367
Gain on sale of property, plant & equipment (333,988) (13,436)
Deferred gain on sale of assets (17,721) (17,721)
Investment tax credit - net (15,796) (15,796)
Deferred income taxes - net 69,780 1,452,873
Change in operating assets and liabilities
Accounts receivable - net (1,553,046) (5,038,687)
Derivative assets 351,922 97,033
Natural gas and propane inventory (1,561,097) 5,175,609
Prepayments and other (47,668) 158,209
Recoverable/refundable cost of gas purchases 397,302 (2,793,425)
Accounts payable (5,321,572) 1,440,256
Derivative liabilities 386,949 0
Other assets and liabilities (1,533,383) 1,326,440
============ ============
Net cash provided by (used in) operating activities (6,640,102) 4,439,116
Cash flow from investing activities:
Construction expenditures (1,405,016) (4,419,691)
Proceeds from sale of property, plant & equipment 840,216 14,458
Collection of long-term notes receivable 51,422 3,300
Customer advances for construction 21,600 (2,131)
Proceeds from contributions in aid of construction 5,381 21,288
============ ============
Net cash used in investing activities (486,397) (4,382,776)
Cash flow from financing activities:
Repayment of long-term debt (82,202)
Proceeds from long-term debt 8,000,000
Debt issuance costs (1,396,180)
Proceeds from lines of credit 28,432,346 37,267,406
Repayment of lines of credit (25,448,839) (35,073,254)
Dividends on common stock (1,003,061)
============ ============
Net cash provided by financing activities 9,587,327 1,108,889
------------ ------------
Net increase in cash and cash equivalents 2,460,828 1,165,229
Cash and cash equivalents at beginning of year 1,938,768 367,657
------------ ------------
Cash and cash equivalents at end of period $ 4,399,596 $ 1,532,886
============ ============
The accompanying notes are an integral part of these condensed
financial statements.
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
March 31, 2004
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 three and nine month periods ended
March 31, 2004 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 Marketing 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") 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 three and nine months ended March 31, 2003 and March 31, 2004.
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, 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
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future obligations to deliver quantities of a commodity at a fixed price.
Conversely, such arrangements may be used to hedge against future market price
declines where the Company or a subsidiary enters into an obligation to purchase
a commodity at a fixed price in the future. The Company accounts for such
financial instruments in accordance with SFAS No. 133, Accounting for Derivative
Instruments and Hedging Activities, as amended by SFAS No. 138, Accounting for
Certain Derivative Instruments and Certain Hedging Activities.
In accordance with SFAS No. 133, contracts that do not qualify as
normal purchase and sale contracts must be reflected in the Company's financial
statements at fair value, determined as of the date of the balance sheet. This
accounting treatment is also referred to as "mark-to-market" accounting.
Mark-to-market accounting treatment can result in a disparity between reported
earnings and realized cash flow, because changes in the value of the financial
instrument are reported as income or loss even though no cash payment may have
been made between the parties to the contract. If such contracts are held to
maturity, the cash flow from the contracts, and their hedges, 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 accounts for 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 March 31, 2004, these agreements were reflected on the Company's
consolidated balance sheet as derivative assets and liabilities at an
approximate fair value as follows:
Assets Liabilities
------ -----------
Contracts maturing in one year or less: $ 1,009,963 $ 471,084
Contracts maturing in two to three years: 925,127 403,898
Contracts maturing in four to five years: 432,628 292,670
----------- -----------
Total $ 2,367,718 $ 1,167,652
=========== ===========
During the first nine 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. As of March
31, 2004, the Company's regulated operations have no contracts meeting the
mark-to-market accounting requirements.
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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 Nine Months Ended
March 31 March 31
2004 2003 2004 2003
Federal tax expense at statutory rates - 34% $ 351,200 $ 1,008,973 $ 194,431 $ 511,239
State tax expense net of federal tax benefit 54,508 116,925 26,027 79,543
Amortization of deferred investment tax credits (5,266) (5,266) (15,797) (15,797)
Other expense (benefit) (41,845) 65,094 (9,301) 39,459
----------- ----------- ----------- -----------
Total income tax expense $ 358,597 $ 1,185,726 $ 195,360 $ 614,444
=========== =========== =========== ===========
NOTE 4 -- LINES OF CREDIT
On March 31, 2004, the Company entered into a modification of its
existing credit facility (as amended, the "LaSalle Facility") with LaSalle Bank
National Association ("LaSalle"). The LaSalle Facility converts $8,000,000 of
existing revolving loans into a $6,000,000, five-year term loan and a $2,000,000
term loan due on September 30, 2004, and reduces the maximum amount of the line
of credit, which expires on October 31, 2004, from $23,000,000 to $15,000,000.
The $2,000,000 term loan must be repaid with the proceeds of a placement of
equity securities by the Company. The credit facilities with LaSalle are
secured, on an equal and ratable basis with the Company's other long-term debt,
by substantially all of the Company's assets. On April 16, 2004, a stockholder
acquired certain shares of common stock which together with other shares owned
by the stockholder total approximately 20.8% of all outstanding shares.
Ownership by any individual or group of 15% or more of the Company's outstanding
common stock constitutes an event of default under the LaSalle Credit Facility.
LaSalle has agreed to forbear from exercising its rights with respect to the
default until June 4, 2004, subject to prior revocation by LaSalle. The Company
is engaged in discussions with LaSalle and the stockholder concerning a
resolution of the situation. Without the forbearance agreement, La Salle has
the right to accelerate the due date of the obligations under the La Salle
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. The Company's dividends are also restricted to an
amount not to exceed 60% of the Company's earnings during the previous four
fiscal quarters. In addition, the Company must restrict its open positions and
Value at Risk (VaR) in its marketing operations to an amount not to exceed
$1,000,000 in the aggregate. 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 March 31, 2004, the ratio was .67 to 1.00. As
of May 17, 2004, La Salle had not agreed to waive the covenant violation for a
period of more than one year. As a result of this covenant violation and the
temporary forbearance described above, the noncurrent portion of the $6,000,000,
five-year term loan has been classified as current as of March 31, 2004.
In the event that LaSalle were to declare the Company's obligations
under the LaSalle Facility immediately due and payable as a result of an event
of default under the LaSalle Facility, such acceleration also could result in
events of default under the Company's Series 1993 Notes and Series 1997 Notes.
In such circumstances, an event of default under either series of notes would
occur if (a) the Company were given notice to that effect either by the trustee
under the indenture governing such series of notes, or the holders of at least
25% in principal amount of the notes of such series then outstanding, and (b)
within 10 days after such notice from the trustee or the note holders to the
Company, the acceleration of the Company's obligations under the LaSalle
Facility has not been rescinded or annulled and the obligations under the
LaSalle Facility have not been discharged. There is no similar cross-default
provision with respect to the Cascade County, Montana Series 1992B Industrial
Development Revenue Bonds and the related Loan Agreement between the Company and
Cascade County, Montana. If the Company's obligations were accelerated under the
terms of any of the LaSalle Facility, the Series 1993 Notes or the Series 1997
Notes, such acceleration (unless rescinded or cured) could result in a loss of
liquidity and cause a material adverse effect on the Company and its financial
condition.
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 promissory note for $620,000 to be repaid over a
four year period, which is secured by the wholesale propane assets sold. The
pre-tax gain resulting from the sale of these assets was approximately $236,000.
The balance due on the
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promissory note as of March 31, 2004 is $554,000 of which $410,000 is included
in Long Term Notes Receivable and the balance is included in Current Assets.
NOTE 6 -- DEFERRED CHARGES
Deferred Charges consist of the following:
March 31 March 31 June 30
2004 2003 2003
---------- ---------- ----------
Unamortized debt issue costs $1,766,050 $ 798,787 $ 778,558
Unamortized rate case costs 71,905 90,934 101,000
Deferred environmental remediation (see note 7) 478,523 483,218 440,196
Regulatory asset for property tax increases (see note 7) 2,849,463 2,430,000
Regulatory asset for income taxes 458,753 458,753 638,618
---------- ---------- ----------
Total $5,624,694 $1,831,692 $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 March 31, 2004, the Company had incurred cumulative net costs of
approximately $1,953,000 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 March 31, 2004, the Company had recovered approximately $1,474,000
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
-7-
period. The Company responded to the MPSC and an interim order has been issued
by the MPSC suspending the collection by the Company of the surcharge until
further investigation can be conducted and requiring a new application from the
Company respecting this surcharge. The Company has submitted its revised
application and has submitted supporting documentation requested by the MPSC and
is awaiting further MPSC action. Company management believes the Company's
application will be granted. The Company currently has an unrecovered balance of
$479,000 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 $479,000, the Company could
be required to refund to customers a portion of the $1,474,000 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 recovery 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 filed comments with the MPSC taking the
position that no income tax benefit will result from the property tax.
On April 16, 2004, the MPSC issued a proposed order and reduced the
amount of the recovery from the original amount requested of $768,000 to
$425,000. The MPSC proposed order also requires that the Company rebate to
customers the difference between the amount approved as interim recovery and the
reduced amount of $425,000. The proposed order provides that the Company may use
a general rate filing to identify property taxes that it would propose be
recovered through the rate making process and the MPSC would allow full
consideration of such costs with all other costs relevant to rates. The Company
has submitted a general rate filing with the MPSC and has requested full
recovery through the rate filing of all property taxes paid including the amount
disallowed in the April 16, 2004 proposed order.
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. The Company is reducing the amount of the
regulatory asset as recoveries are made through the interim rates in effect. The
Company believes that full recovery of property taxes paid will be allowed by
the MPSC through the general rate filing. 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 condition.
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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 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.
-9-
NOTE 8 -- OPERATIONS BY LINE OF BUSINESS
Three Months Ended Nine Months Ended
March 31 March 31
--------- --------
2004 2003 2004 2003
---- ---- ---- ----
Gross Margin (Operating Revenue
Less Gas and
Power Purchased):
Natural Gas Operations $3,911,042 $3,495,043 $ 8,919,518 $ 7,948,835
Propane Operations 1,642,712 1,619,151 3,191,888 3,375,590
EWR Marketing Operations (723,615) 1,549,121 263,392 2,567,098
Pipeline Operations 93,197 101,481 298,963 254,759
---------- ---------- ----------- -----------
$4,923,336 $6,764,796 $12,673,761 $14,146,282
========== ========== =========== ===========
Operating Income (Loss):
Natural Gas Operations $1,631,055 $1,587,353 $ 1,508,566 $ 1,714,213
Propane Operations 882,107 748,071 957,924 739,842
EWR Marketing Operations (853,673) 954,591 (543,086) (68,198)
Pipeline Operations 35,992 54,631 135,163 118,247
---------- ---------- ----------- -----------
$1,695,481 $3,344,646 $ 2,058,567 $ 2,504,104
========== ========== =========== ===========
Net Income (Loss):
Natural Gas Operations $760,243 $831,998 $ 290,716 $ 600,803
Propane Operations 446,826 375,603 387,087 331,892
EWR Marketing Operations (542,601) 539,543 (447,182) (123,922)
Pipeline Operations 4,611 32,014 130,076 70,621
---------- ---------- ----------- -----------
$ 669,079 $1,779,158 $ 360,697 $ 879,394
========== ========== =========== ===========
(Segment information for prior periods has been restated to reflect the
realignment of the Company's reporting segments)
NOTE 9 -- ACCRUED AND OTHER CURRENT LIABILITIES
Accrued and Other Current Liabilities consists of the following:
March 31 March 31 June 30
2004 2003 2003
--------- ----------- ----------
Litigation reserve for PPLM settlement $2,000,000 $2,200,000
Property tax settlement -- current portion $ 195,793 243,000
Payable to employee benefit plans 469,263 598,019 568,133
Accrued vacation 434,605 451,508 429,333
Customer deposits 413,782 365,934 576,917
Accrued compensation 807,696 1,640,647 464,394
Accrued interest 359,399 397,563 106,860
Accrued taxes other than income 814,887 (5,386) 219,853
Other 276,356 75,838 500,764
---------- ----------- ----------
Total $3,771,781 $5,524,123 $5,309,254
========== ========== ==========
-10-
NOTE 10 -- OTHER LONG TERM LIABILITIES
Other Long Term Liabilities consists of the following:
March 31 March 31 June 30
2004 2003 2003
---------- ---------- ----------
Contribution in aid of construction $1,072,185 $1,035,072 $1,066,804
Property tax settlement 1,989,456 2,187,000
Asset retirement obligation 578,588 363,750 555,665
Customer advances for construction 559,610 559,670 538,010
Accumulated post retirement obligation 250,615 187,421 209,800
Deferred gain on sale leaseback of assets 53,174 76,802 70,895
Regulatory liabilities 83,161 83,161 263,026
Other 6,250 23,857
---------- ---------- ----------
Total $4,593,039 $2,329,733 $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.
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,
-11-
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 credit facilities on at least an annual basis. The Company
is negotiating a permanent forbearance as a result of a stockholder's stock
ownership exceeding 15%, and the Company is subject to the risk of default under
its credit facilities and other long term debt in the event that such a
forbearance cannot be arranged. (see Liquidity and Capital Resources)
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 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 operations 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 gross margins due to uncertainty in the natural gas
markets;
- Changes in general economic conditions in the United States and changes
in the industries in which the Company conducts business;
-12-
- 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
regulations, including allowed rates of return, recovery of regulatory
assets, the pace of deregulation in retail natural gas 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, accounting systems or
internal controls;
- 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 governmental responses 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 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's EWR Marketing Operations 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
-13-
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 Marketing Operations segment for
reporting purposes beginning on July 1, 2003.
ENERGY WEST, INCORPORATED AND SUBSIDIARIES
MARCH 31, 2004
QUARTERLY RESULTS OF CONSOLIDATED OPERATIONS
The Company's EWR Marketing Operations experienced significant
reductions in gross margins primarily due to increases in the cost of natural
gas and exiting the electricity market. Non-reoccurring adjustments identified
in the discussion below as pipeline imbalances and reclassifications of
inventories, also contributed to the EWR Marketing Operations reductions in
gross margins.
Gross Margin
Gross margin, which is defined as operating revenue less gas purchased,
decreased $1,841,000, from $6,764,000 in the third quarter of fiscal year 2003
to $4,923,000 in the third quarter of fiscal year 2004. The Natural Gas
Operations margins increased $416,000 due to approved rate increases in both the
Wyoming and Montana operations. The Propane Operations margins increased $24,000
due primarily to the increase in margins in the propane segment's non-regulated
Arizona retail operation, offset by reductions in margin due to the exiting of
the wholesale propane market in August 2003. The Pipeline Operations margins
decreased $8,000 due to transfer of production properties from the Pipeline
Operations to the EWR Marketing Operations offset by margins from the Shoshone
interstate pipeline being placed in service effective as of July 1, 2003. Also,
the EWR Marketing Operations margins decreased $2,273,000 due to the following:
-- Reduced margins from marketing activities. EWR sold excess storage
inventories during the third quarter of fiscal year 2003 and there were
no sale of excess inventories during the third quarter of fiscal year
2004. $ 845,000
-- Increases in prices related to gas purchases necessary to satisfy fixed
price contract agreements. 687,000
-- Increase in gas index prices affecting contracts identified and accounted
for under SFAS No. 133. (see note 2) 222,000
-- Increase in gas costs due to adjustments related to pipeline imbalances 181,000
-- Reduction in gross margins resulting from exiting the electricity market 177,000
-- Reclassification of EWR inventories to inventories owned by customers 122,000
-- Reduced margins due to lower production and increased storage costs 39,000
----------
Total Decrease in EWR Gross Margin $2,273,000
----------
Operating Expense
Operating expenses decreased by $192,000 in the third quarter of fiscal
year 2004 as compared to the third quarter of fiscal year 2003. The Company's
total distribution, general and administration expenses decreased by $384,000
due primarily to the reduced legal expenses related to the PPLM litigation and
reduced expenses in the Propane Operations segment due to the sale of the
wholesale propane assets. Maintenance expenses increased by $8,000, depreciation
expense decreased by approximately $64,000 and all other expenses increased by
approximately $248,000 due primarily to an increase in property tax and
liability insurance expense.
-14-
Interest expense increased by approximately $283,000 during the third
quarter of fiscal year 2004 from the third quarter of fiscal year 2003 due to
higher short term corporate borrowings and the amortization of debt issuance
costs related to the LaSalle short term credit facility.
Income Taxes
Income taxes decreased from $1,186,000 for the third quarter of fiscal
year 2003 to $359,000 for the third quarter of fiscal year 2004, a decrease of
$827,000, due to lower pretax income.
NINE MONTHS RESULTS OF CONSOLIDATED OPERATIONS
The Company's EWR Marketing Operations experienced significant
reductions in gross margins primarily due to increases in the cost of natural
gas and exiting the electricity market. Non-reoccurring adjustments identified
in the discussion below as pipeline imbalances and reclassifications of
inventories, also contributed to the EWR Marketing Operations reductions in
gross margins.
Gross Margin
Gross margins decreased from approximately $14,146,000 for the first
nine months of fiscal year 2003 to $12,674,000 for the first nine months of
fiscal year 2004 or $1,472,000. The decrease in margins was due to a combination
of higher Natural Gas Operations margins of $971,000 resulting from approved
rate increases in the Great Falls and Cody locations, lower propane margins of
$184,000 due to exiting of the wholesale propane business and the Pipeline
Operations margins increased by $44,000 primarily due to the Shoshone pipeline
being placed in service as of July 1, 2003. In addition, the EWR Marketing
Operations experienced a reduction in gross margins of $2,304,000 of due to the
following:
-- Reduced margins from marketing activities. EWR sold excess
storage inventories during the third quarter of fiscal year 2003
and there were no sale of excess inventories during the third
quarter of fiscal year 2004. $ 845,000
-- Increases in prices related to gas purchases necessary to satisfy fixed
price contract agreements. 815,000
-- Increase in gas index prices affecting contracts identified and accounted
for under SFAS No. 133. (See note 2) 238,000
-- Increase in gas costs due to adjustments related to pipeline imbalances 181,000
-- Reduction in gross margins resulting from exiting the electricity market 120,000
-- Reclassification of EWR inventories to inventories owned by customers 122,000
-- Increased margins due to higher production volumes (17,000)
-------------
Total Decrease in EWR Gross Margin $ 2,304,000
-------------
Operating Expenses
Total operating expenses for the first nine months of fiscal year 2003
were $11,642,000 compared to $10,615,000 for the first nine months of fiscal
year 2004, a decrease of $1,027,000. Distribution, general and administrative
expenses decreased by approximately $1,273,000 due to reduced legal and other
professional fees, maintenance expenses decreased by $60,000, depreciation
expense increased by approximately $68,000 due to the depletion of the natural
gas reserves and the depreciation of the Shoshone pipeline, and all other
expenses increased by $238,000, due primarily to an increase in property tax and
liability insurance expenses.
Interest Expense
Interest expense increased by approximately $584,000 during the first
nine months of fiscal year 2004 due to higher short term corporate borrowing and
the amortization of debt issuance costs related to the short term LaSalle credit
facility.
Income Taxes
Income tax expense decreased from $614,000 for the first nine months of
fiscal year 2003 to $195,000 for the first nine months of fiscal year 2004, a
decrease of $419,000, due to lower pretax income.
-15-
RESULTS OF THE COMPANY'S NATURAL GAS OPERATIONS
Three Months Nine Months
Ended March 31 Ended March 31
2004 2003 2004 2003
Natural Gas Revenues $14,162,533 $12,720,815 $31,102,527 $24,479,842
Natural Gas Purchased 10,251,491 9,225,772 22,183,009 16,531,007
----------- ----------- ----------- -----------
Gross Margin 3,911,042 3,495,043 8,919,518 7,948,835
Operating Expenses 2,279,987 1,907,690 7,410,952 6,234,622
----------- ----------- ----------- -----------
Operating Income 1,631,055 1,587,353 1,508,566 1,714,213
Other (Income) (4,515) (5,104) (65,449) (52,169)
Interest Expense 473,466 244,698 1,173,994 757,867
Income Taxes 401,861 515,761 109,305 407,712
----------- ----------- ----------- -----------
Net Natural Gas Income $760,243 $831,998 $290,716 $600,803
----------- ----------- ----------- -----------
STATISTICAL DATA
Sales Volumes (Mcf's) 2,463,081 2,574,954 5,395,298 5,503,378
----------- ----------- ----------- -----------
Degree Days 13,243 13,437 26,444 27,289
----------- ----------- ----------- -----------
(A degree day is defined as a measure of the coldness of weather experienced,
based on the extent to which the daily average temperature falls below 65
degrees Fahrenheit)
QUARTERLY RESULTS OF NATURAL GAS OPERATIONS
Revenues and Gross Margin
Natural gas operating revenues for the third quarter of fiscal year
2004 were approximately $14,163,000 compared to approximately $12,721,000 for
the third quarter of fiscal year 2003, an increase of approximately $1,442,000
or 11%. While the sales volumes decreased approximately 4% between periods due
to warmer than normal weather, 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 $9,226,000 in the third quarter of fiscal
year 2003 to $10,251,000 in the third quarter of fiscal year 2004 an increase of
approximately $1,025,000. Sales volume decreased by 4%, but the price paid for
natural gas purchased increased approximately 37%, from an average of $3.47 per
Mcf for the three months ended March 31, 2003, compared to $4.75 per Mcf for the
period ended March 31, 2004.
Gross margin, which is defined as operating revenues less gas
purchased, was approximately $3,495,000 for the third quarter of fiscal year
2003, compared to a gross margin of approximately $3,911,000 for the third
quarter of fiscal year 2004. The increase of $416,000 in gross margin 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
$372,000, from $1,908,000 in the third quarter of fiscal year 2003 to $2,280,000
in the third quarter of fiscal year 2004.
-16-
The increase in operating expenses is related primarily to increases in
corporate overhead costs of approximately $80,000 due to higher legal and
professional fees paid, an increase in general and administrative expenses of
$94,000 primarily related to increased liability insurance expense, increases in
maintenance and depreciation of $17,000, and increases in property tax expense
of $181,000.
Interest Expense
Interest expenses allocable to the Company's Natural Gas Operations
increased from approximately $245,000 for the third quarter of fiscal year 2003
to approximately $473,000 for the third quarter of fiscal year 2004. The
increase was due to higher short term corporate borrowings and increased
amortization of issuance costs related to the LaSalle short term credit
facility.
Income Taxes
Income taxes related to the Company's Natural Gas Operations decreased
approximately $114,000 for the third quarter of fiscal year 2004 as compared to
the third quarter of fiscal year 2003 as a result of lower pretax earnings.
NINE MONTHS RESULTS OF THE NATURAL GAS OPERATIONS
Revenues and Gross Margin
Natural gas operating revenues in the first nine months of fiscal year
2004 were approximately $31,102,000 compared to approximately $24,480,000 for
the first nine months of fiscal year 2003, an increase of approximately 27%. 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 $16,531,000 in the first nine months of fiscal
year 2003 to $22,183,000 in the first nine months of fiscal year 2004 due to
increased gas prices of approximately 55%. Natural gas prices averaged
approximately $2.84 for the first nine months of fiscal year 2003 compared to
$4.40 for the nine months of fiscal year 2004.
Gross margin was approximately $7,949,000 for the first nine months of
fiscal year 2003, compared to a gross margin of approximately $8,920,000 for the
first nine months of fiscal year 2004. 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
$1,176,000, from $6,235,000 for the first nine months of fiscal year 2003 to
$7,411,000 for the first nine months of fiscal year 2004. The increase in
operating expenses is related primarily to increases in corporate overhead costs
of $727,000 due to higher legal and professional fees, an increase in general
and administrative expenses of $275,000 primarily related to an increase in
liability insurance expense, an increase in property tax expense of
approximately $187,000, and an increase in depreciation expense of approximately
$34,000, offset by a decrease in maintenance expense of $47,000, attributable to
the Great Falls and Cody locations.
Interest Expense
Interest expense allocable to the Company's Natural Gas Operations was
approximately $758,000 for the first nine months of fiscal year 2003, as
compared to $1,174,000 in the comparable
-17-
period in fiscal year 2004, an increase of $416,000. This increase was due to
higher short term corporate borrowings and increased amortization of issuance
costs related to the LaSalle short term credit facility.
Income Taxes
Income tax expense related to the Company's Natural Gas Operations
decreased approximately $298,000 for the first nine months of fiscal year 2004
as compared to the first nine months of fiscal year 2003 due to lower pretax
income.
RESULTS OF THE COMPANY'S PROPANE OPERATIONS
Three Months Nine Months
Ended March 31 Ended March 31
2004 2003 2004 2003
Operating Revenues $ 3,293,484 $ 5,527,217 $ 6,616,562 $ 10,858,859
Propane Purchased 1,650,772 3,908,066 3,424,674 7,483,269
------------ ------------ ------------ ------------
Gross Margin 1,642,712 1,619,151 3,191,888 3,375,590
Operating Expenses 760,605 871,080 2,233,964 2,635,748
------------ ------------ ------------ ------------
Operating Income 882,107 748,071 957,924 739,842
Other (Income) (46,072) (39,825) (124,007) (148,261)
Interest Expense 160,732 106,576 424,867 299,753
Income Taxes 320,621 305,717 269,977 256,458
------------ ------------ ------------ ------------
Net Propane Income $ 446,826 $ 375,603 $ 387,087 $ 331,892
------------ ------------ ------------ ------------
STATISTICAL DATA
Sales volumes (in Gallons) 2,349,103 5,790,837 5,355,447 13,894,353
------------ ------------ ------------ ------------
Degree Days 2,086 2,030 3,265 3,392
------------ ------------ ------------ ------------
QUARTERLY RESULTS OF THE PROPANE OPERATIONS
Gross Margin
Gross margin from Propane Operations increased approximately $24,000,
from $1,619,000 in third quarter of fiscal year 2003 to $1,643,000 in third
quarter of fiscal year 2004. This increase is due primarily to increased margins
of $156,000 in the Payson Arizona retail operations due to increased volumes and
higher retail propane prices charged to customers. In addition, increased
margins were also generated in the regulated operations of approximately
$111,000 due primarily to increased volumes of approximately 7%. This increase
was offset by the sale of the wholesale propane business in August of 2003
resulting in the elimination of approximately 3.4 million gallons of volume and
$243,000 margin for the third quarter of fiscal year 2004.
Operating Expenses
Operating expenses from Propane Operations decreased approximately
$110,000, from $871,000 in the third quarter of fiscal year 2003 to $761,000 in
the third quarter of fiscal year 2004. This decrease is due to a reduction in
general and administrative expenses of $121,000 resulting from the
-18-
sale of the wholesale propane business, other cost savings measures of
approximately $47,000, and a reduction in maintenance and depreciation of
$23,000 due primarily to the sale of the propane assets. These savings were
partially offset by increases in corporate overhead costs of approximately
$20,000, and taxes other than income taxes of $61,000.
Interest Expense
Interest expense allocable to Propane Operations increased from
approximately $107,000 for the third quarter of fiscal year 2003 to
approximately $161,000 for the third quarter of fiscal year 2004, an increase of
approximately $54,000. This increase was due to higher short term corporate
borrowings and the amortization of issuance costs related to the LaSalle short
term credit facility.
Income Taxes
Income taxes related to the Company's Propane Operations increased
approximately $15,000 for the third quarter of fiscal year 2004 as compared to
the third quarter of fiscal year 2003 as a result of higher pretax earnings.
NINE MONTHS RESULTS OF THE PROPANE OPERATIONS
Gross Margin
Gross margin from Propane Operations decreased approximately $184,000,
from $3,376,000 for the first nine months of fiscal year 2003 to $3,192,000 for
the first nine months of fiscal year 2004. This decrease was due primarily to
the sale of the wholesale propane operations resulting in lost volumes of
approximately 8.5 million gallons and related gross margin of approximately
$530,000. The lost margin from the sale of the wholesale propane operations was
offset by additional gross margins of $346,000 from the operations in the
Company's Payson Arizona location. The Payson margin increases were the result
of a 7% increase in volumes, coupled with higher retail propane prices charged
to the non-regulated customers.
Operating Expenses
Operating expenses from Propane Operations decreased approximately
$402,000, from $2,636,000 for the first nine months of fiscal year 2003 to
$2,234,000 for the first nine months of fiscal year 2004. This decrease in
operating expenses is related to the gain on the sale of the wholesale propane
assets of $236,000, a reduction of operating expenses related to the wholesale
propane operations of approximately $298,000, a reduction of $82,000 in other
general and administrative expenses, and a decrease in maintenance and
depreciation of approximately $59,000. Offsetting these expense reductions was
an increase in corporate overhead costs of approximately $223,000, and an
increase in taxes other than income taxes of $50,000 primarily related to
increased property tax expense.
Interest Expense
Interest expense allocable to Propane Operations increased from
approximately $300,000 for the first nine months of fiscal year 2003 to
approximately $425,000 for the first nine months of fiscal year 2004. This
increase of approximately $125,000 was due to higher short term corporate
borrowings and increased amortization of issuance costs related to the LaSalle
short term credit facility.
-19-
Income Taxes
Income tax expense related to the Company's Propane Operations
increased approximately $14,000 for the first nine months of fiscal year 2004 as
compared to the first nine months of fiscal year 2003 resulting from higher
pretax income.
RESULTS OF THE COMPANY'S EWR MARKETING OPERATIONS
Three Months Nine Months
Ended March 31 Ended March 31
2004 2003 2004 2003
Marketing Revenue $ 7,032,271 $ 10,639,380 $ 21,654,818 $ 26,244,115
Purchases 7,755,886 9,090,259 21,391,426 23,677,017
------------ ------------ ------------ ------------
Gross Margin (Loss) (723,615) 1,549,121 263,392 2,567,098
Operating Expenses 130,058 594,530 806,478 2,635,296
------------ ------------ ------------ ------------
Operating Income (Loss) (853,673) 954,591 (543,086) (68,198)
Other (Income) Expense (10,245) 1,384 (15,815)
Interest Expense 68,634 81,190 177,798 165,699
Income Taxes (Benefits) (379,706) 344,103 (275,086) (94,160)
------------ ------------ ------------ ------------
Net Marketing Income (Loss) ($ 542,601) $ 539,543 ($ 447,182) ($ 123,922)
------------ ------------ ------------ ------------
QUARTERLY RESULTS OF EWR MARKETING OPERATIONS
The Company's EWR Marketing Operations experienced significant
reductions in gross margins primarily due to increases in the cost of natural
gas and exiting the electricity market. Non-reoccurring adjustments identified
in the discussion below as pipeline imbalances and reclassifications of
inventories, also contributed to the EWR Marketing Operations reductions in
gross margins.
Gross Margin
Gross margin from EWR Marketing Operations decreased approximately
$2,273,000, from $1,549,000 in the third quarter of fiscal year 2003 to
($724,000) in the third quarter of fiscal year 2004. The decrease in gross
margins is attributable to the following:
-- Reduced margins from marketing activities. EWR sold excess
storage inventories during the third quarter of fiscal year 2003
and there were no sale of excess inventories during the third
quarter of fiscal year 2004. $ 845,000
-- Increases in prices related to gas purchases necessary to satisfy fixed
price contract agreements. 687,000
-- Increase in gas index prices affecting contracts identified and accounted
for under SFAS No. 133. (See note 2) 222,000
-- Increase in gas costs due to adjustments related to pipeline imbalances 181,000
-- Reduction in gross margins resulting from exiting the electricity market 177,000
-- Reclassification of EWR inventories to inventories owned by customers 122,000
-- Reduced margins due to lower production and increased storage costs 39,000
-------------
Total Decreases in EWR Gross Margins $ 2,273,000
-------------
Operating Expenses
Operating expenses from EWR Marketing Operations decreased
approximately $465,000, from $595,000 in the third quarter of fiscal year 2003
to $130,000 in the third quarter of fiscal year 2004. This decrease in operating
expenses is related to the decreased legal expenses related to the PPLM
litigation of approximately $158,000, a reduction in pipeline expenses of
$117,000 now being reported by EWD, and a reduction in general and
administrative expenses of $190,000 primarily related to reductions in payroll
and related costs, travel and training and other cost savings measures.
-20-
Interest Expense
Interest expense allocable to EWR Marketing Operations decreased from
approximately $81,000 for the third quarter fiscal year 2003 to approximately
$69,000 for the third quarter of fiscal year 2004, a decrease of approximately
$12,000. This decrease in interest expense is related to a reduction in capital
employed by the EWR Marketing Operations, which is the methodology applied by
the Company in allocating interest to the reporting locations.
Income Taxes
Income tax benefits related to the Company's EWR Marketing Operations
increased approximately $724,000 for the third quarter of fiscal 2004 as
compared to the third quarter of fiscal 2003 due to the lower pretax income.
NINE MONTHS RESULTS OF EWR MARKETING OPERATIONS
The Company's EWR Marketing Operations experienced significant
reductions in gross margins primarily due to increases in the cost of natural
gas and exiting the electricity market. Non-reoccurring adjustments identified
in the discussion below as pipeline imbalances and reclassifications of
inventories, also contributed to the EWR Marketing Operations reductions in
gross margins.
Gross Margin
Gross margin from the EWR Marketing Operations for the first nine
months of fiscal year 2004 was approximately $263,000 compared to $2,567,000 for
the first nine months of fiscal year 2003, a decrease of approximately
$2,304,000.
-- Reduced margins from marketing activities. EWR sold excess
storage inventories during the third quarter of fiscal year 2003
and there were no sale of excess inventories during the third
quarter of fiscal year 2004. $ 845,000
-- Increases in prices related to gas purchases necessary to satisfy fixed
price contract agreements. 815,000
-- Increase in gas index prices affecting contracts identified and accounted
for under sfas no. 133. (see note 2) 238,000
-- Increase in gas costs due to adjustments related to pipeline imbalances 181,000
-- Reduction in gross margins resulting from exiting the electricity market 120,000
-- Reclassification of EWR inventories to inventories owned by customers 122,000
-- Increased margins due to higher production volumes (17,000)
-------------
Total Decreases in EWR Gross Margins $ 2,304,000
-------------
Operating Expenses
Operating expenses from EWR Marketing Operations decreased
approximately $1,829,000, from $2,635,000 for the first nine months of fiscal
year 2003 to $806,000 for the first nine months of fiscal year 2004. This
decrease in operating expenses is due to decreased legal expenses related to the
PPLM litigation of approximately $1,278,000, a reduction in salaries and related
expenses of approximately $147,000, a reduction in travel and related expenses
of $41,000, a reduction in expenses relating to the pipeline operations of
$289,000 and other cost saving measures of $74,000.
Interest Expense
Interest expense allocable to EWR Marketing Operations increased from
approximately $166,000 for the first nine months of fiscal year 2003 to
approximately $178,000 for the first nine months of fiscal year 2004. This
increase of approximately $12,000 was due to higher short term corporate
borrowings and the increased amortization of issuance costs related to the short
term LaSalle Facility.
-21-
Income Taxes
Income tax benefit related to the Company's EWR Marketing Operations
increased approximately $181,000 for the first nine months of fiscal 2004 as
compared to the first nine months of fiscal year 2003 resulting from lower
pre-tax earnings.
RESULTS OF THE COMPANY'S PIPELINE OPERATIONS
Three Months Nine Months
Ended March 31 Ended March 31
2004 2003 2004 2003
Pipeline Revenue $ 93,197 $ 101,481 $ 298,963 $ 254,759
--------- --------- --------- ---------
Gross Margin 93,197 101,481 298,963 254,759
Operating Expenses 57,205 46,850 163,800 136,512
--------- --------- --------- ---------
Operating Income 35,992 54,631 135,163 118,247
Other Income (69) (120,922) (1,018)
Interest Expense 15,560 2,541 34,843 4,210
Income Taxes 15,821 20,145 91,166 44,434
--------- --------- --------- ---------
Net Pipeline Income $ 4,611 $ 32,014 $ 130,076 $ 70,621
--------- --------- --------- ---------
QUARTERLY RESULTS OF PIPELINE OPERATIONS
Gross Margin
Gross margin from Pipeline Operations decreased approximately $8,000,
from $101,000 in the third quarter of fiscal year 2003 to $93,000 in the third
quarter of fiscal year 2004. This decrease was due primarily to the transfer of
production properties from Pipeline Operations to EWR Marketing Operations.
Operating Expenses
Operating expenses from Pipeline Operations increased approximately
$10,000, from $47,000 in the third quarter of fiscal year 2003 to $57,000 in the
third quarter of fiscal year 2004. This increase was due primarily to an
increase in depreciation and property taxes related to the Shoeshone interstate
pipeline that began operations in July of 2003.
Interest Expense
Interest expense allocable to Pipeline Operations increased from
approximately $3,000 for the third quarter of fiscal year 2003 to approximately
$16,000 for the third quarter of fiscal year 2004. The increase of $13,000 was
due to higher corporate short term borrowings and the amortization of the
issuance costs of the LaSalle Facility.
Income Taxes
Income taxes related to the Company's Pipeline Operations decreased
approximately $4,000 for the third quarter of fiscal year 2004 as compared to
the third quarter of fiscal year 2003 due to lower taxable income.
-22-
NINE MONTHS RESULTS OF PIPELINE OPERATIONS
Gross Margin
Gross margin from Pipeline Operations increased approximately $44,000,
from $255,000 in the third quarter of fiscal year 2003 to $299,000 in the third
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 Pipeline Operations increased approximately
$27,000, from $137,000 for the first nine months of fiscal year 2003 to $164,000
for the first nine months of fiscal year 2004. The increase was due primarily to
an increase in depreciation expense of approximately $20,000 related to the
Shoshone interstate pipeline, an increase in property tax expense of
approximately $14,000, offset by a reduction in general and administrative
expenses of approximately $7,000.
Other Income
Other income for the first nine 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 allocable to Pipeline Operations increased from
approximately $4,000 for the first nine months of fiscal year 2003 to
approximately $35,000 for the first nine 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 $91,000 for the first nine months of fiscal year 2004, as compared
to $44,000 for the first nine months of fiscal year 2003, an increase of
approximately $47,000 due to higher pre-tax income.
CASH FLOW ANALYSIS
The primary cash flows during the nine month periods ending March 31,
2004 and March 31, 2003 are summarized as follows:
March 31 March 31
2004 2003
---- ----
Provided by (used in) operating activities $(6,640,102) $ 4,439,116
Used in investing activities (486,397) (4,382,776)
Provided by financing activities 9,587,327 1,108,889
----------- -----------
Net increase in cash and cash equivalents $ 2,460,828 $ 1,165,229
=========== ===========
For the nine months ended March 31, 2004, the Company and its
subsidiaries used $6,640,000 of cash in its operating activities compared to
$4,439,000 of cash provided by operating activities for the nine months ended
March 31, 2003. This increase in cash used of $11,079,000 was primarily due to
increases in natural gas and propane inventory expenditures of $6,737,000, a
decrease in deferred tax liability of $1,383,000, an increase in the amount paid
on accounts payable of $6,762,000, an increase in the amounts paid for other
assets and liabilities of $2,355,000, and a decrease in net income of $519,000.
Offsetting these changes were an increase in the collection of accounts
receivable of $3,486,000 and a decrease in the amount of recoverable gas
purchases of $3,191,000.
-23-
Cash used in investing activities was $486,000 for the nine months
ended March 31, 2004, compared to cash used of $4,383,000 for the nine months
ended March 31, 2003. This decrease in cash used of $3,897,000 was primarily due
to a reduction in construction expenditures of $3,015,000, and an increase in
cash from the sale of property plant and equipment of $826,000, an increase in
collection of notes receivable of $48,000 and an increase in cash used in
investing activities of $8,000 related to the Company's regulatory operations.
Cash provided by financing activities was $9,587,000 for the nine
months ended March 31, 2004, as compared to $1,109,000 for the nine months ended
March 31, 2003. The increase of $8,478,000 was due primarily from an increase in
proceeds from long term debt restructuring of $8,000,000. There were also
decreases in the proceeds in the Company's short term lines of credit of
$8,835,000, offset by an increase in payment of short term lines of credit of
$9,624,000. Additionally, there was a reduction in shareholders dividend
payments of $1,003,000, and a reduction in repayment of long term debt of
$82,000. Offsetting these increases in proceeds was an increase in debt issuance
costs of $1,396,000.
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 "Initial Facility") with LaSalle Bank National Association,
as Agent for certain banks (collectively, the "Lender"). The Initial 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 Initial
Facility. Borrowings under the Initial 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 Initial Facility with the exception of the first $1,000,000 of
debt under the Initial 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 granting approval imposed several requirements
on the Company including restrictions on the use of the proceeds of the Initial
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.
-24-
On March 31, 2004, the Company entered into a modification of the
Initial Facility (as amended, the "LaSalle Facility"). The LaSalle Facility
converts $8,000,000 of existing revolving loans into a $6,000,000, five-year
term loan and a $2,000,000 term loan due on September 30, 2004, and reduces the
line of credit, which expires on October 31, 2004, from $23,000,000 to
$15,000,000. The $2,000,000 term loan must be repaid with the proceeds of a
placement of equity securities by the Company. The LaSalle Facility is secured,
on an equal and ratable basis with the Company's other Long-Term Debt, by
substantially all of the Company's assets. On April 16, 2004, Richard Osborne
acquired certain shares of common stock which together with other shares owned
by Mr. Osborne total approximately 20.8% of all outstanding shares. Ownership by
any individual or group of 15% or more of the Company's outstanding common stock
constitutes an event of default under the LaSalle Facility. The Lender has
agreed to forbear from exercising its rights with respect to the default until
June 4, 2004, subject to prior revocation by the Lender. The Company is engaged
in discussions with the Lender and Mr. Osborne concerning a resolution on the
situation. Without the forbearance agreement, the Lender has the right to
accelerate the due date of the obligations under the LaSalle 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. The Company's dividends are also restricted to an
amount not to exceed 60% of the Company's earnings during the previous four
fiscal quarters. In addition, the Company must restrict its open positions and
Value at Risk (VaR) in its marketing operations to an amount not to exceed
$1,000,000 in the aggregate. 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 March 31, 2004, the ratio was .67 to 1.00. As
of May 17, 2004, La Salle had not agreed to waive the covenant violation for a
period of more than one year. As a result of this covenant violation and the
temporary forbearance described above, the noncurrent portion of the
$6,000,000, five-year term loan has been classified as current as of March 31,
2004.
In the event that LaSalle were to declare the Company's obligations
under the LaSalle Facility immediately due and payable as a result of the event
of default under the LaSalle Facility, such acceleration also could result in
events of default under the Company's Series 1993 Notes and Series 1997 Notes.
In such circumstances, an event of default under either series of notes would
occur if (a) the Company were given notice to that effect either by the trustee
under the indenture governing such series of notes, or the holders of at least
25% in principal amount of the notes of such series then outstanding, and (b)
within 10 days after such notice from the trustee or the note holders to the
Company, the acceleration of the Company's obligations under the LaSalle
Facility has not been rescinded or annulled and the obligations under the
LaSalle Facility have not been discharged. There is no similar cross-default
provision with respect to the Cascade County, Montana Series 1992B Industrial
Development Revenue Bonds and the related Loan Agreement between the Company and
Cascade County, Montana. If the Company's obligations were accelerated under the
terms of any of the LaSalle Facility, the Series 1993 Notes or the Series 1997
Notes, such acceleration (unless rescinded or cured) could result in a loss of
liquidity and cause a material adverse effect on the Company and its financial
condition.
Under the LaSalle Facility, the Company pays interest (i) on its line
of credit borrowings at either (a) the London Interbank Offered Rate (LIBOR)
plus 250 basis points (bps) or, if the Company elects, (b) the rate publicly
announced from time to time by the Lender as its "prime rate" ("Prime"), (ii) on
its $6,000,000 term loan at either (a) LIBOR plus 350 bps or, if the Company
elects, (b) Prime plus 150 bps and (iii) on its $2,000,000 term loan at Prime
plus 100 bps until June 30, 2004 and thereafter at Prime plus 200 bps. The
LaSalle Facility also has a commitment fee of 35 bps due on the daily unutilized
portion of the lines of credit.
At March 31, 2004, the Company had total short-term borrowings of
approximately $9,229,000 and letters of credit outstanding in the face amount of
$1,700,000 under the LaSalle Facility.
In addition to the LaSalle Facility, the Company has outstanding
certain other notes and industrial development revenue obligations. The
Company's Long-Term Debt consists of:
-25-
$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. 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 long-term debt was $14,688,000 and
$15,280,000, at March 31, 2004 and March 31, 2003, respectively. Under the terms
of the Long-Term Debt, the Company is subject to certain restrictions, including
restrictions on total dividends and distributions, liens and secured
indebtedness, and asset sales, and the Company is restricted from incurring
additional long-term indebtedness if it does not meet certain financial debt and
interest ratios.
CONTRACTS ACCOUNTED FOR AT FAIR VALUE
Management of Risks Related to Derivatives--The Company and its
subsidiaries are subject to certain risks related to changes in certain
commodity prices and risks of counter-party performance. The Company has
established 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 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
instruments 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 is 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 are 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.
-26-
As of March 31, 2004, 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: $1,009,963 $ 471,084
Contracts maturing in two to three years: 925,127 403,898
Contracts maturing in four to five years: 432,628 292,670
---------- ----------
Total $2,367,718 $1,167,652
========== ==========
During the first nine 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. As of March
31, 2004, the Company's regulated operations have no contracts meeting the
mark-to-market accounting requirements.
CRITICAL ACCOUNTING POLICIES
The Company believes its critical accounting policies are as follows:
Effects of Regulation--The Company follows SFAS No. 71, Accounting for
the Effects of Certain Types of Regulation, and its financial statements reflect
the effects of the different rate making principles followed by the various
jurisdictions regulating the Company. The economic effects of regulation can
result in regulated companies recording costs that have been or are expected to
be allowed in the ratemaking process in a period different from the period in
which the costs would be charged to expense by an unregulated enterprise. When
this occurs, costs are deferred as assets in the balance sheet (regulatory
assets) and recorded as expenses in the periods when those same amounts are
reflected in rates. Additionally, regulators can impose liabilities upon a
regulated company for amounts previously collected from customers and for
amounts that are expected to be refunded to customers (regulatory liabilities).
Recoverable/Refundable Costs of Gas and Propane Purchases--The Company
accounts for purchased-gas costs in accordance with procedures authorized by the
MPSC, the WPSC and the 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), interest rate risk and credit
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
-27-
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 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 disclosure controls and
procedures (as defined in Rules 13a-15(e) or 15d-15(e) of the Securities
Exchange Act of 1934, as amended (the "Exchange Act")) as of the end of the
period covered by this report. Based upon this evaluation, they have concluded
that the Company's disclosure controls and procedures are effective as of the
end of the period covered by this report to provide reasonable assurance that
the Company will meet its disclosure obligations.
There were not any changes in the Company's internal controls over
financial reporting that occurred during the quarter ended March 31, 2004 that
have materially affected, or that are reasonably likely to materially affect,
the Company's internal control over financial reporting. The design of any
system of controls and procedures is based in part upon certain assumptions
about the likelihood of future events.
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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.
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 -- See Liquidity and Capital Resources
above
Item 4. Submission of Matters to a Vote of Security Holders -- Not Applicable
Item 5. Other Information - Not Applicable
Item 6. Exhibits and Reports on Form 8-K
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A. Exhibits for the third quarter ended March 31, 2004.
3.1 Bylaws of the Company, as amended to date
(incorporated by reference to Exhibit 3.2 to the
Company's Current Report on Form 8-K filed with the
Commission on March 5, 2003)
10.1 Amended and Restated Credit Agreement, dated March
31, 2004, by and among Energy West, Incorporated,
Various Financial Institutions and LaSalle Bank
National Association (incorporated by reference to
Exhibit 10.1 to the Company's Current Report on Form
8-K filed with the Commission of April 1, 2004.
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 third
quarter ended March 31, 2004 as follows.
Date Filed Item No.
March 2, 2004 Item 5 -- Announcement that the Company
filed applications with the Montana Public
Service Commission and the Wyoming Public
Service Commission seeking approval to
modify its revolving credit facility with
LaSalle National Association.
Item 7 -- Press release dated March 1, 2004.
March 5, 2004 Item 5 -- Announcement regarding the
amendment of the Company's By-Laws.
Item 7 -- Amendment to By-Laws of the
Company; Amended and Restated By-Laws of the
Company.
March 29, 2004 Item 5 -- Announcement regarding Company
filing for general rate increase with the
Montana Public Service Commission.
Item 7 -- Press release dated March 26, 2004.
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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
ENERGY WEST, INCORPORATED
/s/John C. Allen
- ------------------------------------
John C. Allen, Interim President and
Chief Executive Officer
(principal executive officer)
/s/Robert B. Mease
- -------------------------------
Robert B. Mease, Vice-President
and Controller
(principal financial officer)
May 17, 2004
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