Gas Natural 10-Q/A 2005 Q3 Quarterly report (amended)

FORM 10-Q/A

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

þ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2005

OR

o 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. Yesþ Noo

Indicate by checkmark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Yeso Noþ

Indicate by checkmark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yeso Noþ

The number of shares outstanding of the issuer’s common stock, $.15 par value per share, as of November 9, 2005 was 2,913,781 shares

EXPLANATORY NOTE

This Amendment on Form 10-Q/A (this “Amendment”) amends the Quarterly Report on Form 10-Q for the period ended September 30, 2005, as originally filed by Energy West, Incorporated on November 14, 2005 (the “Original Filing”), solely for the purpose of correcting a typographical error in Part I, Item 2, explanation of changes in revenues on page 17 and page 21. In addition, in connection with the filing of this Amendment and pursuant to the rules of the Securities and Exchange Commission, we are including with this Amendment certain currently dated certifications.

Except as described above, no other changes have been made to the Original Filing. This Amendment continues to speak as of the date of the Original Filing, and we have not updated the disclosures contained in this Amendment to reflect any events that occurred at a date subsequent to the filing of the Original Filing. The filing of this Form 10-Q/A is not a representation that any statements contained in items of the Original Filing other than that information being amended are true or complete as of any date subsequent to the date of the Original Filing. The filing of this Form 10-Q/A shall not be deemed an admission that the Original Filing or the amendments made thereto, when made, included any untrue statement of a material fact or omitted to state a material fact necessary to make a statement not misleading.

ENERGY WEST, INCORPORATED

INDEX TO FORM 10-Q

	Page No.
Part I — Financial Information
Item 1 - Financial Statements
Condensed Consolidated Balance Sheets as of September 30, 2005, September 30, 2004 and June 30, 2005		3
Condensed Consolidated Statements of Operations - three months ended September 30, 2005 and 2004		4
Condensed Consolidated Statements of Cash Flows - three months ended September 30, 2005 and 2004		5
Notes to Condensed Consolidated Financial Statements		6
Item 2 - Management’s Discussion and Analysis of Financial Condition and Results of Operations		15
Item 3 – Quantitative and Qualitative Disclosures about Market Risk		29
Item 4 – Controls and Procedures		30
Part II – Other Information
Item 6 – Exhibits		31
Signatures		32
EX-31
EX-32

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PART I – FINANCIAL INFORMATION

ITEM 1 – FINANCIAL STATEMENTS.

2

ENERGY WEST INCORPORATED AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS, SEPTEMBER 30, 2005 AND 2004

	September 30,				June 30,
	2005		2004		2005
ASSETS
Current Assets:
Cash	$	250,303	$	1,731,446	$	93,606
Accounts and notes receivable less $308,182, $312,911 and $294,646, respectively, allowance for bad debt		4,072,636		3,335,132		5,791,888
Unbilled gas		1,406,705		1,845,125		1,092,320
Derivative assets		300,799		66,799		119,069
Natural gas and propane inventories		9,205,044		9,910,169		3,711,033
Materials and supplies		455,350		404,736		440,959
Prepayments and other		358,527		1,219,797		386,306
Deferred income taxes		152,334		658,225
Income tax receivable		1,025,397		1,957,211		1,924,648
Recoverable cost of gas purchases		1,275,210		1,117,334		1,863,475
Total current assets		18,502,305		22,245,974		15,423,304
Property, Plant and Equipment, Net		38,903,460		38,569,083		38,942,123
Note Receivable				332,301		174,561
Deferred Charges		4,576,340		5,209,144		4,725,924
Other Assets		172,521		184,561		167,481
TOTAL ASSETS	$	62,154,626	$	66,541,063	$	59,433,393
LIABILITIES AND CAPITALIZATION
Current Liabilities:
Current portion of long-term debt	$	1,013,089	$	872,706	$	1,013,089
Line of credit		5,200,000		13,129,304		3,900,000
Accounts payable		3,969,447		2,856,198		2,651,047
Derivative liabilities		255,165		2,067,018		114,237
Deferred income taxes						96,214
Accrued and other current liabilities		4,498,324		3,842,974		3,750,177
Total current liabilities		14,936,025		22,768,200		11,524,764
Other Obligations:
Deferred income taxes		6,307,574		4,664,269		6,267,858
Deferred investment tax credits		308,017		329,079		313,282
Other long-term liabilities		5,460,761		4,803,498		5,463,667
Total		12,076,352		9,796,846		12,044,807
Long-Term Debt		18,577,197		21,697,286		18,677,197
Commitments and Contingencies (Note 6)
Stockholders’ Equity:
Preferred stock; $.15 par value, 1,500,000 shares authorized, no shares outstanding
Common stock; $.15 par value, 5,000,000 shares authorized, 2,912,564, 2,598,506 and 2,912,564 shares outstanding at September 30, 2005 and 2004, and June 30, 2005 respectively		436,892		389,783		436,892
Capital in excess of par value		7,435,309		5,077,687		7,435,309
Retained earnings		8,692,851		6,811,261		9,314,424
Total stockholders’ equity		16,565,052		12,278,731		17,186,625
TOTAL CAPITALIZATION		35,142,249		33,976,017		35,863,822
TOTAL LIABILITIES AND CAPITALIZATION	$	62,154,626	$	66,541,063	$	59,433,393

The accompanying notes are an integral part of these condensed financial statements.

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ENERGY WEST, INCORPORATED AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS
FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2005 AND 2004

	Three Months Ended
	September 30,
	2005			2004
REVENUES:
Natural gas operations	$	6,315,367		$	5,207,676
Propane operations		997,982			852,611
Gas and electric—wholesale		2,869,832			5,722,507
Pipeline operations		108,208			84,355
Total revenues		10,291,389			11,867,149
EXPENSES:
Gas purchased		4,887,849			3,859,356
Gas and electric—wholesale		2,741,469			5,783,668
Distribution, general, and administrative		2,218,787			2,295,684
Maintenance		147,892			132,794
Depreciation and amortization		574,377			594,316
Taxes other than income		362,636			383,809
Total expenses		10,933,010			13,049,627
OPERATING (LOSS)		(641,621	)		(1,182,478	)
OTHER INCOME		111,022			66,175
INTEREST EXPENSE		493,414			752,244
(LOSS) BEFORE INCOME TAXES		(1,024,013	)		(1,868,547	)
INCOME TAX BENEFIT		402,440			746,853
NET (LOSS)	$	(621,573	)	$	(1,121,694	)
(LOSS) PER COMMON SHARE:
Basic	$	(0.21	)	$	(0.43	)
Diluted	$	(0.21	)	$	(0.43	)
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:
Basic		2,912,564			2,598,506
Diluted		2,912,564			2,598,506

The accompanying notes are an integral part of these condensed financial statements.

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ENERGY WEST, INCORPORATED AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2005 AND 2004

	Three Months Ended
	September
	2005			2004
CASH FLOWS FROM OPERATING ACTIVITIES:
Net (loss)	$	(621,573	)	$	(1,121,694	)
Adjustments to reconcile net (loss) to net cash (used in) operating activities:
Depreciation and amortization, including deferred charges and financing costs		749,404			881,518
Derivative assets		(181,730	)		132,449
Derivative liabilities		140,928			382,342
Deferred gain		(139,501	)
Investment tax credit		(5,265	)		(5,265	)
Deferred gain on sale of assets		(5,907	)		(5,907	)
Deferred income taxes		380,225			3,562
Changes in assets and liabilities:
Accounts and notes receivable		2,165,516			1,892,958
Natural gas and propane inventories		(5,494,011	)		(4,727,123	)
Accounts payable		858,586			(754,881	)
Recoverable/refundable cost of gas purchases		588,265			(328,927	)
Prepayments and other		27,778			(849,418	)
Other assets & liabilities		862,161			(906,597	)
Net cash (used in) operating activities		(675,124	)		(5,406,983	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Construction expenditures		(581,854	)		(585,925	)
Collections on notes receivable		174,561			75,237
Customer advances received (refunded) for construction		20,000			29,173
Increase (decrease) from contributions in aid of construction		19,114			(2,000	)
Net cash provided by (used in) investing activities		(368,179	)		(483,515	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Repayments of long-term debt		(100,000	)		(100,000	)
Proceeds from lines of credit		2,200,000			7,400,000
Repayments of lines of credit		(900,000	)		(1,000,758	)
Net cash provided by financing activities		1,200,000			6,299,242
NET INCREASE IN CASH AND CASH EQUIVALENTS		156,697			408,744
CASH AND CASH EQUIVALENTS:
Beginning of period		93,606			1,322,702
End of period	$	250,303		$	1,731,446

The accompanying notes are an integral part of these condensed financial statements.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

September 30, 2005

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 considered necessary for a fair presentation have been included. Operating results for the three month period ended September 30, 2005 are not necessarily indicative of the results that may be expected for the fiscal year ending June 30, 2006. 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, 2005.

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. EWD also owns natural gas production properties in Montana. The Company’s reporting segments are: Natural Gas Operations, Propane Operations, EWR and Pipeline Operations. An application was granted by the Federal Energy Regulatory Commission (“FERC”) and EWD began operations of an interstate natural gas pipeline as a transmission pipeline on July 1, 2003. The revenue and expenses associated with this transmission pipeline are included in the Pipeline Operations segment.

Note 1 — 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 counterparty performance. The Company has established policies and procedures to manage such risks. The Company has a Risk Management Committee, comprised of Company officers and management to oversee the Company’s risk management program as defined in its risk management policy. The purpose of the risk management program is to minimize adverse impacts on earnings resulting from volatility of energy prices, counterparty credit risks, and other risks related to the energy commodity business.

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In order to mitigate the risk of natural gas market price volatility related to firm commitments to purchase or sell natural gas or electricity, from time to time the Company and its subsidiaries have entered into hedging arrangements. Such arrangements may be used to protect profit margins on future obligations to deliver gas at a fixed price, or to protect against adverse effects of potential market price declines on future obligations to purchase gas at fixed prices.

Quoted market prices for natural gas derivative contracts of the Company and its subsidiaries are generally not available. Therefore, to determine the net present value of natural gas derivative contracts, the Company uses internally developed valuation models that incorporate independently available current and forecasted pricing information.

During the first three months of fiscal 2006, the Company has not entered into any new contracts that have required mark-to-market accounting under Statement of Financial Accounting Standards (“SFAS”) No. 133. However existing derivatives as of September 30, 2005 were reflected on the Company’s consolidated balance sheet as derivative assets and liabilities at an approximate fair value as follows:

	Assets		Liabilities
Contracts maturing during fiscal year 2006	$	254,810	$	255,165
Contracts maturing during fiscal years 2007 and 2008		—		—
Contracts maturing during fiscal years 2009 and beyond		45,989		—
Total	$	300,799	$	255,165

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 September 30, 2005, the Company’s regulated operations have no contracts meeting the mark-to-market accounting requirements.

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NOTE 2 – INCOME TAX BENEFITS

Income tax benefit differs from the amount computed by applying the federal statutory rate to pre-tax loss as demonstrated in the following table:

	Three Months Ended
	September 30
	2005			2004
Tax benefit at statutory rate of 34%	$	358,404		$	652,151
State income tax benefit, net of federal tax benefit		39,153			90,000
Amortization of deferred investment tax credits		5,265			5,266
Other		(382	)		(564	)
Total income tax benefit	$	402,440		$	746,853

NOTE 3 — LINES OF CREDIT AND LONG-TERM DEBT

The Company’s operating capital needs, as well as dividend payments and capital expenditures, are generally funded through cash flow from operating activities and short-term borrowing. Historically, to the extent cash flow has not been sufficient to fund capital expenditures, the Company has borrowed short-term funds. When the short-term debt balance significantly exceeds working capital requirements, the Company has issued long-term debt or equity securities to pay down short-term debt. The Company has greater need for short-term borrowing during periods when internally generated funds are not sufficient to cover all capital and operating requirements, including costs of gas purchased and capital expenditures. In general, the Company’s short-term borrowing needs for purchases of gas inventory and capital expenditures are greatest during the summer and fall months and the Company’s short-term borrowing needs for financing customer accounts receivable are greatest during the winter months.

The Company substantially restructured its credit facilities during fiscal year 2004 by establishing a $23.0 million revolving credit facility with LaSalle Bank National Association, as Agent for certain banks (collectively, the “Lender”), replacing a previous short-term line of credit. The Montana Public Service Commission (“MPSC”) order granting approval of the $23.0 million credit facility imposes restrictions on the use of the proceeds to utility purposes, and requires the Company to provide monthly reports to the MPSC with respect to the financial condition of the Company. The Company continues to be subject to these MPSC requirements.

On March 31, 2004, the Company entered into a restated credit agreement with the Lender. Pursuant to the restated credit agreement, the previous $23.0 million revolving credit facility was replaced with a $15.0 million revolving credit facility, a $6.0 million term loan maturing on March 31, 2009, and a $2.0 million term loan maturing on November 30, 2005 (collectively referred to as the “LaSalle Facility”). The $2,000,000 term loan was repaid May 26, 2005 with the proceeds of a sale of equity securities by the Company.

Borrowings under the LaSalle Facility are secured by liens on substantially all of the assets of the Company and its subsidiaries. The Company’s obligations under certain other notes and industrial development revenue obligations are collateralized on an equal and ratable basis with

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the Lender in the collateral granted to secure the borrowings under the LaSalle Facility with the with the exception of the first $1.0 million which is secured to LaSalle.

Under the LaSalle Facility the Company may elect to pay interest on portions of the amounts outstanding under the $15.0 million revolving line of credit at the London interbank offered rate (LIBOR), plus 250 basis points, for interest periods selected by the Company. For all other balances outstanding under the $15.0 million revolving line of credit, the Company pays interest at the rate publicly announced from time to time by LaSalle Bank as its “prime rate” (the
“Prime Rate”). For the $6.0 million term loan under the LaSalle Facility, the Company may elect to pay interest at either the applicable LIBOR rate plus 350 basis points or at the Prime Rate plus 200 basis points. For the $2.0 million term loan under the LaSalle Facility, the Company paid interest at the Prime Rate plus 200 basis points through March 31, 2005; the Prime Rate plus 300 bps from April 1, 2005 through May 26, 2005. The Company also pays a commitment fee of 35 basis points for the daily unutilized portion of the $15.0 million revolving credit facility.

The LaSalle Facility requires the Company to maintain compliance with a number of financial covenants, including meeting limitations on annual capital expenditures, maintaining a total debt to total capital ratio of not more than .70 to 1.00 and an interest coverage ratio of no less than 2.00 to 1.00. During the three months ended September 30, 2005, the Company was in compliance with the financial covenants under the LaSalle Facility. The LaSalle Facility also restricts the Company’s ability to pay dividends during any period to a certain percentage of cumulative earnings of the Company over that period, and restricts open positions and Value at Risk (VaR) in the Company’s wholesale operations.

At September 30, 2005, the Company had approximately $250,000 of cash on hand. In addition, at September 30, 2005, the Company had borrowed approximately $5.2 million under the LaSalle Facility revolving line of credit. The Company’s short-term borrowings under its lines of credit during the three months ended September 30, 2005 had a daily weighted average interest rate of 7.38% per annum. The Company’s net availability at September 30, 2005, was approximately $9.8 million under the LaSalle Facility revolving line of credit.

In addition to the LaSalle Facility, the Company has outstanding certain notes and industrial development revenue obligations (collectively “Long Term Notes and Bonds”). The Company’s Long Term Notes and Bonds are made up of three separate debt issues: $8.0 million of Series 1997 notes bearing interest at an annual rate of 7.5%; $7.8 million of Series 1993 notes bearing interest at annual rates ranging from 6.20% to 7.60%; and Cascade County, Montana Series 1992B Industrial Development Revenue Obligations in the amount of $1.8 million bearing interest at annual rates ranging from 6.0% to 6.5%. The Company’s obligations under the Long Term Notes and Bonds are secured on an equal and ratable basis with the Lender in the collateral granted to secure the LaSalle Facility with the exception of the first $1.0 million which is secured to LaSalle.

Under the terms of the Long Term Notes and Bonds, the Company is subject to certain restrictions, including restrictions on total dividends and distributions during and period to the cumulated net income for the prior sixty months, liens and secured indebtedness, and asset sales,

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and is restricted from incurring additional long-term indebtedness if it does not meet certain debt to interest and debt to capital ratios.

The total amount outstanding under all of the Company’s long-term debt obligations was approximately $19.6 million and $22.6 million, at September 30, 2005 and September 30, 2004, respectively. The portion of such obligations due within one year was approximately $1,010,000 and $870,000 at September 30, 2005, and September 30, 2004, respectively.

NOTE 4 — NOTE RECEIVABLE

On August 21, 2003, EWP sold the majority of its wholesale propane assets in Montana and Wyoming consisting of approximately $782,000 in storage and other related assets and approximately $352,000 in inventory and accounts receivable. The Company received cash of $750,000 and a promissory note for approximately $620,000 to be repaid over a four year period, which is secured by the wholesale propane assets sold. This note was paid in full on July 19, 2005. The gain was recognized when the promissory note was issued.

NOTE 5 — DEFERRED CHARGES

Deferred Charges consist of the following:

	Three Months Ended
	September 30,				June 30,
	2005		2004		2005
Regulatory asset for property taxes	$	2,477,247	$	2,748,583	$	2,561,265
Regulatory asset for income taxes		458,753		458,753		458,753
Regulatory asset for deferred environmental remediation costs		408,824		489,693		413,218
Other regulatory assets		53,361		84,850		52,198
Unamortized debt issue costs		1,178,155		1,427,265		1,240,490
Total	$	4,576,340	$	5,209,144	$	4,725,924

Regulatory assets will be recovered over a period of approximately seven to twenty years.

The property tax asset does not earn a return in the rate base; however the property tax is recovered in rates over a ten-year period starting January 1, 2004. The income taxes and environmental remediation costs earn a return equal to that of the Company’s rate base. No other assets earn a return or are recovered in the rate structure. Other regulatory assets are amortized over fiscal year 2006.

NOTE 6 — 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

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gasification process utilized in the plant resulted in the production of certain by-products, which have been classified by the federal government and the State of Montana as hazardous to the environment.

In the summer of 1999, the Company received approval from the Montana Department of Environmental Quality (“MDEQ”) for its plan for remediation of soil contaminants. The Company has completed its remediation of soil contaminants and in April of 2002 received a closure letter from MDEQ approving the completion of such remediation program.

The Company and its consultants continue to work with the MDEQ relating to the remediation plan for water contaminants. The MDEQ has established regulations that allow water contaminants at a site to exceed standards if it is technically impracticable to achieve them. Although the MDEQ has not established guidance to attain a technical waiver, the U.S. Environmental Protection Agency (“EPA”) has developed such guidance. The EPA guidance lists factors which render mediations technically impracticable. The Company has filed a request for a waiver respecting compliance with certain standards with the MDEQ.

At September 30, 2005, the Company had incurred cumulative costs of approximately $1,925,000 in connection with its evaluation and remediation of the site. On May 30, 1995, the Company received an order from the MPSC allowing for recovery of the costs associated with the evaluation and remediation of the site through a surcharge on customer bills. As of September 30, 2005, the Company had recovered approximately $1,526,000 through such surcharges. As of September 30, 2005, the cost remaining to be recovered is $409,000.

On April 15, 2003, the MPSC issued an Order to Show Cause Regarding the Environmental Surcharge. The MPSC determined that the initial order allowing the collection of the surcharge was intended by the MPSC to cover only a two year collection period, after which it would contemplate additional filings by the Company, if necessary. The Company responded to the Show Cause Order and the MPSC subsequently ordered the termination of the Environmental Surcharge on August 20, 2003. The Company filed a request with the commission to continue the collection of the surcharge until all expenses have been recovered. This request was approved by the MPSC and the surcharge was reinstated in September 2004. The Company is required, under the Commission’s most recent order, to file with the MPSC every two years for approval to continue the recovery of the surcharge.

Derivative Contingencies— Among the risks involved in natural gas marketing is the risk of nonperformance by counterparties to contracts for purchase and sale of natural gas. EWR is party to certain contracts for purchase or sale of natural gas at fixed prices for fixed time periods. Some of these contracts are recorded as derivatives, valued on a mark-to-market basis.

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.

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In addition to other litigation referred to above, the Company or its subsidiaries have been involved in the following described litigation.

On August 8, 2003, the Company reached agreement with the Montana Department of Revenue (“DOR”) to settle a claim that the Company had under-reported its personal property for the years 1997-2002 and that additional property taxes and penalties should be assessed. The settlement amount is being paid in ten annual installments of $243,000 each, beginning November 30, 2003.

The Company initially determined that it was entitled to recover the amounts paid in connection with the DOR settlement through future rate adjustments as a result of legislation permitting “automatic adjustments” to rates to recover such property tax increases. The MPSC, however, interpreted the new legislation as allowing recovery of only a portion of the higher property taxes. Rates recovering the portion of the higher taxes permitted under the MPSC’s interpretation of the legislation went into effect on January 1, 2004. The Company has since obtained rate relief which includes full recovery of the property tax associated with the DOR settlement.

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NOTE 7 — SEGMENTS OF OPERATIONS

	Three Months Ended
	September 30
	2005			2004
Gross margin (operating revenue less cost of gas purchased):
Natural gas operations	$	1,978,281		$	1,753,616
Propane operations		447,219			447,315
EWR		128,363			(61,161	)
Pipeline operations		108,208			84,355
	$	2,662,071		$	2,224,125
Operating income (loss):
Natural gas operations	$	(305,453	)	$	(555,035	)
Propane operations		(251,717	)		(274,395	)
EWR		(146,146	)		(390,581	)
Pipeline operations		61,695			37,533
	$	(641,621	)	$	(1,182,478	)
Net income (loss):
Natural gas operations	$	(348,037	)	$	(638,253	)
Propane operations		(195,413	)		(200,736	)
EWR		(109,519	)		(292,965	)
Pipeline operations		31,396			10,260
	$	(621,573	)	$	(1,121,694	)

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NOTE 8 — ACCRUED AND OTHER CURRENT LIABILITIES

     Accrued and other current liabilities consists of the following:

	September 30,				June 30,
	2005		2004		2005
Property tax settlement—current portion	$	243,000	$	243,000	$	243,000
Payable to employee benefit plans		148,783		170,862		481,514
Accrued vacation		262,669		398,472		267,859
Customer deposits		443,840		410,406		418,148
Accrued incentives		11,585		532,189		12,246
Accrued interest		382,369		386,102		97,987
Accrued taxes other than income		680,396		710,666		507,288
Deferred short-term gain		321,639				399,760
Customer prepayments from levelized billing (a)		1,142,433		344,195		459,814
Other		861,610		647,082		862,561
Total	$	4,498,324	$	3,842,974	$	3,750,177

(a) In order to conform to the current year presentation, certain reclassifications have been made for prior reporting periods. The reclassifications had no effect on net income or cash flow.

NOTE 9 — OTHER LONG TERM LIABILITIES

     Other long-term liabilities consist of the following

	September 30,				June 30,
	2005		2004		2005
Asset retirement obligation	$	626,534	$	594,290	$	618,473
Contribution in aid of construction		1,466,562		1,223,539		1,447,448
Customer advances for construction		697,937		632,762		677,936
Accumulated postretirement obligation		360,105		284,378		342,900
Deferred gain — long-term (b)		507,722				569,102
Deferred gain on sale leaseback of assets		17,732		41,360		23,639
Regulatory liability for income taxes		83,161		83,161		83,161
Property tax settlement		1,701,008		1,944,008		1,701,008
Total	$	5,460,761	$	4,803,498	$	5,463,667

(b) In January 2005, two long-term contracts were designated as “normal purchases and sales”. The derivative liability as of January 2005 will now be amortized over the remaining monthly volumes of the contract at a rate of $1.21 per MMBtu.

NOTE 10 – STOCK OPTIONS

As of July 1, 2005, SFAS No. 123(R) became effective for the Company. The Company had previously followed Accounting Principles Board Opinion (“APB”) No. 25 and related Interpretations in accounting for its employee stock options. Under APB No. 25, no compensation expense was recognized, as the exercise price of the Company’s employee stock

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options equals the market price of the underlying stock on the date of grant. Under SFAS No. 123(R), compensation expense is now recognized. Stock-based compensation cost is measured at the grant date, based on the fair value of the award and is recognized over the employee’s requisite service period. Compensation expense is calculated using the Black-Scholes option pricing model. The Black-Scholes calculations performed for the first quarter fiscal 2006 stock-based compensation expense utilized the methodology and assumptions consistent with those used in prior periods under APB No. 25, which were disclosed in the Company’s previously filed Annual Report on Form 10-K for the year ended June 30, 2005. The general and administrative expense for the stock-based compensation in the first quarter of fiscal 2006 was approximately $25,000 which is less than $0.01 per share.

The Company uses the Black Scholes methodology, with a volatility assumption of 53%, an expected life of 7 years, 2% expected dividend rate, and a risk free interest rate of 3.9%. If the Company had recorded stock option expense in the quarter ended September 30, 2004, its pro forma net loss would have been increased by approximately $32,000 or approximately $.01 per share.

ITEM 2 — MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

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 the required restructuring of
our debt, our operating capital requirements, negotiations with our lender, recovery of property tax payments, the Company’s environmental remediation plans, and similar statements that are not historical are forward-looking statements that involve risks and uncertainties. Although the Company believes these forward-looking statements are based on reasonable assumptions, statements made regarding future results are subject to a number of assumptions, uncertainties and risks that could cause future results to be materially different from the results stated or implied in this document.

Such forward-looking statements, as well as other oral and written forward-looking statements made by or on behalf of the Company from time to time, including statements contained in the Company’s filings with the Securities and Exchange Commission and its reports to shareholders, involve known and unknown risks and other factors which may cause the Company’s actual
results in future periods to differ materially from those expressed in any forward-looking statements See “Risk Factors” in the Company’s Annual Report on Form 10-K for the fiscal year ended June 30, 2005 filed with the Securities and Exchange Commission. 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.

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EXECUTIVE OVERVIEW

We believe that we have made significant progress since the first quarter of last year. We have seen significant benefits from controlling costs and the renewed focus on our core business. This has lead to a $5 million decrease in the amount we have had to borrow under our credit facility as compared to last year. In turn, this has resulted in an opportunity to restore dividends for the first time in several quarters and significantly improved payment terms with key suppliers. However, we continue to address certain challenges.

We must remain vigilant about our increasing demand for cash due to high commodity prices and our heavy reliance on a few gas suppliers. This often leads to a demand for credit assurance to third parties. Additionally, we operate in a lean fashion. Accordingly, the loss of key personnel in such areas as accounting, engineering and pipeline operations can have a dramatic impact on the efficient operation of the Company. Our small size makes the Company vulnerable to large earnings variations if litigation or other one-time expenses occur.

     The foregoing concerns are counterbalanced by what we believe are our strengths:

• Geographic proximity of our regulated natural gas business to production and our pipelines to active drilling.

• High growth in and around our Arizona propane business.

• Our positive reputation with regulators and customers.

• Our corporate infrastructure, which provides a platform for additional projects with lower incremental expenses.

QUARTERLY RESULTS OF CONSOLIDATED OPERATIONS.

Fiscal Quarter Ended September 30, 2005 Compared to Fiscal Quarter Ended September 30, 2004

The following discussion of the Company’s financial condition and results of operations should be read in conjunction with the Condensed Consolidated Financial Statements and Notes thereto and other financial information included elsewhere in this report and the Company’s Annual Report on Form 10-K for the fiscal year ended June 30, 2005. The following gives effect to the unaudited Condensed Consolidated Financial Statements as of September 30, 2005 and for the three month period ended September 30, 2005. Results of operations for interim periods are not necessarily indicative of results to be attained for any future period.

Net Income (Loss)— The Company’s net loss for the first quarter of fiscal year 2005 was $622,000 compared to a net loss of $1,122,000 in the first quarter of fiscal year 2004, a decrease of $500,000. The decrease in the Company’s net loss from the first quarter of fiscal year 2005 to the first quarter of fiscal year 2004 was primarily due to higher gross margins in Natural Gas and EWR, lower operating expenses in all segments, higher other income and a decrease in interest

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expense. The increases in gross margin and the reductions in expenses were partially offset by a decrease in income tax benefit due to lower pretax losses.

Revenues— The Company’s revenues for the first quarter of fiscal year 2006 were $10,291,000 compared to $11,867,000 in the first quarter of fiscal year 2005, a decrease of $1,576,000. The decrease was primarily attributable to: (1) decreases in EWR trading revenue of $1,807,000 and decreases in retail gas revenues of $1,688,000 due to a 65% decrease in volumes sold; and a $12,000 decrease in production and electric revenue. When analyzing the change in revenues it should be noted that revenue in the first quarter of fiscal year 2005 was reduced by $515,000 to record mark to market unrealized losses on derivative contacts. There was no material mark to market adjustments in the first quarter of fiscal year 2006. However the first quarter of fiscal year 2006 revenue was favorably impacted by $139,000 of amortization of a deferred gain. The deferred gain was recorded in January 2005 when certain derivative contracts were re–classified as “normal purchase or normal sales.” The deferred gain is being amortized ratably over the life of the contracts (For further discussion regarding this reclassification see the Company June 30, 2005 10–K.) (2) propane and natural gas revenue increases of $145,000 and $1,108,000 respectively due to higher prices for propane and natural gas passed through to customers, and (3) increased revenues in Pipeline operations of $24,000 due to an increase in gathering volumes on the Glacier line.

Gross Margin— Gross margin, which is defined as revenue less gas purchased and costs of gas and electricity (wholesale), increased $438,000, from $2,224,000 in the first quarter of fiscal year 2005 to $2,662,000 in the first quarter of fiscal year 2006. EWR margins increased $190,000 due to a $654,000 increase in derivative gains under mark-to-market accounting and an $11,000 increase in electricity margin, offset by a decrease in gas margin of $459,000 due to lower sales volumes and $17,000 decrease in production margin.

The Pipeline Operations’ margins increased $24,000 due to the Glacier line being temporarily down from early June 2004 until the first week of November 2004. The Natural Gas Operations’ margins increased $225,000 primarily due to approved rate increases put into effect in November 2004. The Propane Operations’ margins remained constant.

Expenses Other Than Costs of Gas and Electricity and Costs of Goods Sold— Expenses other than gas purchased decreased by $103,000 in the first quarter of fiscal year 2006 as compared to the first quarter of fiscal year 2005. The primary reasons for this decrease were (1) decreases in the Company’s general and administrative costs of $117,000, (2) decreases in depreciation and amortization of $20,000, and (3) decreases in taxes other than income taxes of $21,000, offset by (4) increases of $41,000 and $15,000 in overhead and maintenance expenses respectively.

Other Income— Other income increased by $45,000 from $66,000 in the first quarter of fiscal year 2005 to $111,000 in the first quarter of fiscal year 2006. Natural Gas other income increased $52,000 primarily due to income generated in fiscal year 2006 for services to customers over what had been provided in prior years. Propane other income decreased $21,000 due to the payoff on July 9^th, 2005 of the note receivable in RMF resulting in less interest and consulting fee income than in the first quarter fiscal year 2005. EWR other income increased $14,000 due to income from the settlement of a contract dispute.

Interest Expense— Interest expense decreased by approximately $258,000 during the first quarter of fiscal year 2006 from the first quarter of fiscal year 2005 due to lower short-term borrowings and the amortization in fiscal year 2005 of $171,000 in debt issuance costs related to securing the LaSalle short-term credit facility.

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Income Tax Benefits (Expense)— Income tax benefits decreased $344,000 in the first quarter of fiscal year 2006 as compared to the first quarter of fiscal year 2005 due to the decreased net loss in the first quarter of fiscal year 2006.

Operating Results of our Natural Gas Operations

	Three Months Ended
	September 30,
	2005			2004
Natural Gas Operations
Operating revenues	$	6,315,367		$	5,207,676
Gas Purchased		4,337,086			3,454,060
Gross Margin		1,978,281			1,753,616
Operating expenses		2,283,734			2,308,651
Operating income		(305,453	)		(555,035	)
Other (loss)		(65,779	)		(14,146	)
Loss before interest and taxes		(239,674	)		(540,889	)
Interest expense		329,161			493,158
(Loss) before income taxes		(568,835	)		(1,034,047	)
Income tax benefit		220,798			395,794
Net (loss)		($348,037	)		($638,253	)

Fiscal Quarter Ended September 30, 2005 Compared to Fiscal Quarter Ended September 30, 2004

Natural Gas Revenues and Gross Margins— The Natural Gas Operations’ operating revenues in fiscal year 2006 increased to $6,315,000 from $5,207,000 in fiscal year 2005. This $1,108,000 increase was primarily due to higher gas costs and an approved rate increase put into effect in November 2004.

Gas purchases in Natural Gas Operations increased by $883,000 from $3,454,000 in fiscal year 2005 to $4,337,000 in fiscal year 2006. The increase in gas cost reflects higher commodity prices during the current fiscal year.

Gross margin, which is defined as operating revenues less gas purchased, was approximately $1,978,000 for fiscal year 2006 compared to approximately $1,754,000 in fiscal year 2005. The increase of $224,000 is primarily due to approved rate increases put into effect in November 2004.

Natural Gas Operating Expenses— Natural Gas Segment’s operating expenses were approximately $2,284,000 for the first quarter fiscal year 2006 as compared to $2,309,000 for first quarter fiscal year 2005. The $25,000 reduction is due to $23,000 decrease in payroll and

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other general and administrative expenses resulting from the implementation of cost-saving measures, $23,000 in lower depreciation charges, $14,000 in lower taxes other than income taxes, partially offset by $25,000 in higher overhead charges and $10,000 in increased maintenance charges.

Natural Gas Other Income— Other income increased by $52,000 from $14,000 in fiscal year 2005 to $66,000 in fiscal year 2006. This was due primarily to service sales in Great Falls.

Natural Gas Interest Expense— Interest expense is $164,000 lower in the first quarter of fiscal year 2006 primarily due to lower short-term borrowings and the amortization in the first quarter of fiscal year 2005 of debt issue costs.

Natural Gas Income Tax Benefit (Expense)— Tax benefits are $175,000 lower in the first quarter of fiscal year 2006 due to lower pretax loss.

Operating Results of our Propane Operations

	Three Months Ended
	September 30,
	2005			2004
Propane Operations
Operating revenues	$	997,982		$	852,611
Gas Purchased		550,763			405,296
Gross Margin		447,219			447,315
Operating expenses		698,936			721,710
Operating income		(251,717	)		(274,395	)
Other (loss)		(31,094	)		(52,029	)
Loss before interest and taxes		(220,623	)		(222,366	)
Interest expense		106,606			158,459
(Loss) before income taxes		(327,229	)		(380,825	)
Income tax benefit		131,816			180,089
Net (loss)		($195,413	)		($200,736	)

Fiscal Quarter Ended September 30, 2005 Compared to Fiscal Quarter Ended September 30, 2004

Propane Revenue and Gross Margins— Propane Operations’ revenues increased $146,000 from $852,000 for the first quarter of fiscal year 2005 to $998,000 for the first quarter of fiscal year 2006 as a result of higher propane prices in fiscal year 2006. Gas purchased increased from $405,000 to $551,000 for the same period due also to increases in the cost of propane for both the regulated utility and the wholesale propane operations. Gross margin remained constant at $447,000. Although costs increased, revenues in all propane operations increased at the same rate, resulting in no change to gross margin.

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Propane Operating Expenses— Operating expenses were $722,000 in the first quarter of fiscal year 2005 compared to $699,000 in the first quarter of fiscal year 2006. This decrease of $23,000 is due to decreases in general and administrative costs of $40,000, and taxes other than income of $4,000. These savings were offset by increases in maintenance and depreciation of $9,000 and overhead costs of $12,000.

Propane Other Income— Other income decreased by $21,000 from $52,000 for the first quarter of fiscal year 2005 to $31,000 for the first quarter of fiscal year 2006. In the first quarter of fiscal year 2005, RMF had both interest income from a note receivable generated with the sale of assets in August 2003. Included with this sale was a contract for consulting fees. This note was paid in full on July 9^th, 2005, resulting in lower interest income. The payoff also included the elimination of consulting fee income for RMF.

Propane Interest Expense— Interest expense decreased by $52,000 from $158,000 in the first quarter of fiscal year 2005 to $106,000 for the first quarter of fiscal year 2006, primarily due to lower short-term borrowings and the amortization in the first quarter of fiscal year 2005 of debt issue costs.

Propane Income Tax Benefit (Expense)— Income tax benefit decreased by $48,000 from $180,000 in the first quarter of fiscal year 2005 to $132,000 in the first quarter of fiscal year 2006 due to lower pretax losses.

Operating Results of our EWR Operations

	Three Months Ended
	September 30,
	2005			2004
Energy West Resources (“EWR”)
Operating revenues	$	2,869,832		$	5,722,507
Gas Purchased		2,741,469			5,783,668
Gross Margin		128,363			(61,161	)
Operating expenses		274,509			329,420
Operating income		(146,146	)		(390,581	)
Other (loss)		(14,149	)		0
Loss before interest and taxes	($	131,997	)	($	390,581	)
Interest expense		47,276			84,784
(Loss) before income taxes		(179,273	)		(475,365	)
Income tax benefit		69,754			182,400
Net (loss)	($	109,519	)	($	292,965	)

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Fiscal Quarter Ended September 30, 2005 Compared to Fiscal Quarter Ended September 30, 2004

EWR Revenues and Gross Margins— Revenues in EWR decreased $2,853,000 from $5,723,000 in the first quarter of fiscal year 2005 to $2,870,000 in the first quarter of fiscal year 2006. Decreased fiscal revenues were due to $1,807,000 lower trading revenue, $1,688,000 lower retail gas revenues due to a 65% decrease in volumes sold and a $12,000 decrease in production and electric revenue. When analyzing the change in revenues it should be noted that revenue in the first quarter of fiscal year 2005 was reduced by $515,000 to record mark to market unrealized losses on derivative contracts. There was no material mark to market adjustments in the first quarter of fiscal year 2006. However the first quarter of fiscal year 2006 revenue was favorably impacted by $139,000 of amortization of a deferred gain. The deferred gain was recorded in January 2005 when certain derivative contracts were re-classified as “normal purchase or normal sales.” The deferred gain is being amortized ratably over the life of the contracts (For further discussion regarding this reclassification see the Company June 30, 2005 10-K.)

EWR’s first quarter fiscal year 2006 gross margin of $128,000 represents an increase of $189,000 from gross margin earned in the first quarter fiscal year 2005. This is primarily due to a $654,000 increase in the valuation of derivative contracts and $11,000 increase in electricity margin, offset by a decrease in gas margin of $459,000 due to lower sales volumes and $17,000 decrease in production margin.

EWR Operating Expenses— Operating expenses in EWR decreased approximately $54,000, from $329,000 for first quarter of fiscal year 2005 to $275,000 for the first quarter of fiscal year 2006. This decrease is due primarily to a reduction in outside services of $41,000 and various other general and administrative charges.

EWR Other Income (Expense)— Other income increased by $14,000 due to income from the settlement of a contract dispute.

EWR Interest Expense— Interest expense decreased by $38,000 due to a decrease in short-term borrowings and the amortization in the first quarter of fiscal year 2005 of debt issue costs.

EWR Income Tax Benefit (Expense)— Tax expense increased in the first quarter of fiscal year 2006 from a tax benefit of $182,000 in 2005 to a tax benefit of $70,000 due to lower pretax losses.

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Operating Results of our Pipeline Operations

	Three Months Ended
	September 30,
	2005			2004
Pipeline Operations
Operating revenues	$	108,208		$	84,355
Gas Purchased		—			—
Gross Margin		108,208			84,355
Operating expenses		46,513			46,822
Operating income		61,695			37,533
Other (income) loss		—			—
Income before interest and taxes		61,695			37,533
Interest expense		10,371			15,843
Income before income taxes		51,324			21,690
Income tax benefit (expense)		(19,928	)		(11,430	)
Net income	$	31,396		$	10,260

Fiscal Quarter Ended September 30, 2005 Compared to Fiscal Quarter Ended September 30, 2004

Pipeline Revenues and Gross Margins— Pipeline revenue consists of gathering revenue from the Glacier line and capacity charge revenue on the Shoshone line. Both pipelines are located in Montana and Wyoming.

Pipeline Operations’ margin increased from $84,000 in the first quarter of fiscal year 2005 to $108,000 in the first quarter of fiscal year 2006. The increase of $24,000 was due an increase in gathering volumes on the Glacier gathering line.

Pipeline Operating Expenses— Operating expenses remained constant at $47,000 in the first quarter of fiscal year 2005 and in the first quarter of fiscal year 2006.

Pipeline Interest Expense— Interest expense decreased from $19,000 in the first quarter of fiscal year 2005 to $10,000 in the first quarter of fiscal year 2006 due to a decrease in short-term borrowings and the amortization in fiscal year 2005 of debt issue costs.

Pipeline Income Tax Benefit (Expense)— Tax expense increased from $11,000 in the first quarter of fiscal year 2005 to $20,000 in the first quarter of fiscal year 2006. This increase is due to a higher pretax income in fiscal year 2006.

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Consolidated Cash Flow Analysis

Sources and Uses of Cash

Operating activities provide our primary source of cash. Cash provided by operating activities consists of net income (loss) adjusted for non-cash items, including depreciation, depletion, amortization, deferred income taxes and changes in working capital.

Our ability to maintain liquidity depends upon our $15,000,000 credit facility at LaSalle Bank, shown as line of credit on the accompanying balance sheet. Our use of the LaSalle credit facility decreased to $5,200,000 at September 30, 2005, compared with $13,129,304 at September 30, 2004. This $7,929,000 improvement reflects the fact that we generated less net loss — $622,000 net loss in the first quarter fiscal year 2006 as compared to a $1,122,000 net loss in the first quarter of fiscal year 2005, a $900,000 refund of income taxes collected from a carry back of net operating losses in prior years, a $1,482,000 decrease in accounts receivable and a $1,113,000 increase in accounts payable. We finance our capital expenditures on an interim basis through this LaSalle credit facility. We periodically repay our short-term borrowings under our LaSalle credit facility by using the net proceeds from the sale of long-term debt and equity securities.

Long-term debt decreased to $18,577,000 at September 30, 2005, compared with $21,697,000 at September 30, 2004. This $3,120,000 decrease resulted primarily from using $2,000,000 of the proceeds from the May 26, 2005, sale of common shares to pay off a portion of the LaSalle term note and the scheduled principal payments of $480,000 on the Series 1993 notes, $90,000 on the Series 1992B notes and $400,000 on the term loan as provided for in the debt agreements.

Cash increased to $250,000 at September 30, 2005, from June 30, 2005, compared with the $408,000 increase in cash for the first quarter ended September 30, 2004, as shown in the following table:

	September 30,
	2005			2004
Provided by (used in) operating activities	($	675,124	)	($	5,406,983	)
Used in investing activities		(368,179	)		(483,515	)
Provided by financing activities		1,200,000			6,299,242
Increase in cash	$	156,697		$	408,744

For the quarter ended September 30, 2005, cash used by operating activities decreased $4,732,000. This was due to a decrease in net loss of $500,000, increase in deferred income taxes of $377,000, increase in accounts receivable of $273,000, an increase in the value of derivative assets of $314,000, an increase in gas inventories of $767,000, a decrease in accounts payable of $1,613,000 a decrease in derivative liabilities of

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$241,000, an increase of deferred gain of $140,000, a decrease in recoverable gas costs of $917,000, a decrease in prepaid items of $877,000, and a decrease in cash used for other assets and liabilities of $1,769,000.

For the quarter ended September 30, 2005, cash used in investing activities decreased $115,000 as compared to the first quarter 2005 due primarily from the increase in cash received from long term notes receivable.

For the quarter ended September 30, 2005, cash provided by financing activities decreased by $5,100,000 as compared to the quarter ended September 30, 2004, due to lower advances against the line of credit.

LIQUIDITY AND CAPITAL RESOURCES

Our operating capital needs, as well as dividend payments and capital expenditures, are generally funded through cash flow from operating activities and short-term borrowing. Historically, to the extent cash flow has not been sufficient to fund capital expenditures, we have borrowed short-term funds. When the short-term debt balance significantly exceeds working capital requirements, we have issued long-term debt or equity securities to pay down short-term debt. We have 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, our short-term borrowing needs for purchases of gas inventory and capital expenditures are greatest during the summer and fall months and our short-term borrowing needs for financing customer accounts receivable are greatest during the winter months.

We maintain a $15 million revolving credit facility with LaSalle Bank National Association, as Agent for certain banks. The LaSalle credit facility is accompanied by a $6.0 million term loan maturing on March 31, 2009. The term loan at September 30, 2005 had an outstanding balance of $5.4 million. Borrowings under the LaSalle credit facility are secured by liens on substantially all of our assets. Our obligations under certain other notes and industrial development revenue obligations are secured on an equal and ratable basis with LaSalle in the collateral granted to secure the borrowings under the LaSalle credit facility with the exception of the first $1.0 million which is secured to LaSalle.

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The following table represents borrowings under the LaSalle credit facility for each of the periods presented.

	First		Second		Third		Fourth
	Quarter		Quarter		Quarter		Quarter
Year Ended June 30, 2006
Minimum borrowing	$	3,100,000
Maximum borrowing	$	5,200,000
Average borrowing	$	4,166,667
Year Ended June 30, 2005
Minimum borrowing	$	7,729,000	$	12,688,000	$	3,500,000	$	2,700,000
Maximum borrowing	$	13,129,000	$	14,629,000	$	13,929,000	$	3,900,000
Average borrowing	$	10,196,000	$	13,982,000	$	8,110,000	$	3,167,000
Year Ended June 30, 2004
Minimum borrowing	$	6,105,000	$	12,102,000	$	9,229,000	$	4,729,000
Maximum borrowing	$	8,602,000	$	12,629,000	$	13,229,000	$	6,729,000
Average borrowing	$	7,482,000	$	12,277,000	$	10,563,000	$	5,563,000

Under the LaSalle credit facility, we may elect to pay interest on portions of the amounts outstanding at the London Interbank Offered Rate (LIBOR), plus 250 basis points, for interest periods we select. For all other balances outstanding under the LaSalle credit facility, we pay interest at the rate publicly announced from time to time by LaSalle as its “Prime Rate.” For the term loan with LaSalle, we may elect to pay interest at either the applicable LIBOR rate, plus 350 basis points or at the Prime Rate, plus 200 basis points.

The LaSalle credit facility requires us to maintain compliance with a number of financial covenants, including meeting limitations on annual capital expenditures, maintaining a total debt to total capital ratio of not more than .70 to 1.00 and an interest coverage ratio of no less than 2.00 to 1.00. The LaSalle credit facility also restricts our ability to pay dividends during any period to a certain percentage of our cumulative earnings over that period, and restricts open positions and Value at Risk (VaR) in our wholesale operations. At June 30, 2005 and at September 30, 2005, we were in compliance with the financial covenants under the LaSalle credit facility.

At September 30, 2005, we had approximately $250,000 of cash on hand. In addition, at September 30, 2005, we had borrowed approximately $5.2 million under the LaSalle credit facility. Our short-term borrowings under our lines of credit during fiscal year 2005 had a daily weighted average interest rate of 7.38% per annum. At September 30, 2005, we had no outstanding letters of credit related to electricity and gas purchase contracts. We had net availability at September 30, 2005, of approximately $9,800,000 under the LaSalle credit facility revolving line of credit. As discussed above, our short-term borrowing needs for purchases of gas inventory and capital expenditures are greatest during the summer and fall months. Our

25

availability normally increases in January as monthly heating bills are paid and gas purchases are no longer necessary.

In addition to the LaSalle credit facility, we have outstanding certain notes and industrial development revenue obligations (collectively “Long Term Notes and Bonds”). Our Long Term Notes and Bonds are made up of three separate debt issues: $8.0 million of Series 1997 notes bearing interest at an annual rate of 7.5%; $7.8 million of Series 1993 notes bearing interest at annual rates ranging from 6.20% to 7.60%; and Cascade County, Montana Series 1992B Industrial Development Revenue Obligations in the amount of $1.8 million bearing interest at annual rates ranging from 6.0% to 6.5%. Our obligations under the Long Term Notes and Bonds are secured on an equal and ratable basis with the Lender in the collateral granted to secure the LaSalle credit facility with the exception of the first $1.0 million which is secured to LaSalle.

Under the terms of the Long Term Notes and Bonds, we are subject to certain restrictions, including restrictions on total dividends and distributions, liens and secured indebtedness, and asset sales, and are restricted from incurring additional long-term indebtedness if we do not meet certain debt to interest and debt to capital ratios.

In the event that our obligations under the LaSalle credit facility were declared immediately due and payable as a result of an event of default, such acceleration also could result in events of default under our Series 1993 Notes and Series 1997 Notes. In such circumstances, an event of default under either series of notes would occur if (a) we 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, the acceleration of our obligations under the LaSalle credit facility has not been rescinded or annulled and the obligations under the LaSalle credit 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 our obligations were accelerated under the terms of any of the LaSalle credit 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 our financial condition.

The total amount outstanding under all of our long term debt obligations was approximately $19.6 million and $22.6 million, at September 30, 2005 and September 30, 2004, respectively. The portion of such obligations due within one year was approximately $1,010,000 and $870,000 at September 30, 2005, and September 30, 2004, respectively. Our operating capital needs, as well as dividend payments and capital expenditures, are generally funded through cash flow from operating activities and short-term borrowing. Historically, to the extent cash flow has not been sufficient to fund capital expenditures, we have borrowed short-term funds. When the short-term debt balance significantly exceeds working capital requirements, we have issued long-term debt or equity securities to pay down short-term debt. We have 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, our short-term borrowing needs for purchases of gas inventory and capital expenditures are

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greatest during the summer and fall months and our short-term borrowing needs for financing customer accounts receivable are greatest during the winter months.

Contractual Obligations

Our major financial market risk exposure is to changing interest rates. Changing interest rates will affect interest paid on variable-rate debt. Our policy is to manage interest rates through the use of a combination of fixed-rate and floating-rate debt. On August 9, 2004, we entered into a fixed-for-floating interest rate swap transaction on our five-year floating interest rate term note. If we were to designate it as a hedge this transaction would qualify as a fair value hedge under SFAS No. 133; we have elected not to designate it as a hedge and have not recorded it as a fair value hedge.

The table below presents contractual balances of our consolidated long-term and short-term debt at the expected maturity dates as well as the fair value of those instruments on September 30, 2005. The interest rates presented below represent the weighted-average interest rates for the year ended September 30, 2005. The fair value of the interest rate swap was $45,989 and is recorded as a derivative asset on the accompanying financial statements.

Payments Due by Period

			1 year						After
Contractual Obligations	Total		or less		2-3 years		4-5 years		5 years
Interest payments (a)	$	6,972,591	$	1,062,722	$	1,990,724	$	1,833,166	$	2,085,979
Long Term Debt (b)		19,590,286		1,013,089		2,158,213		4,540,000		11,878,984
Operating Lease Obligations		330,447		142,599		181,248		6,600		—
Funding of retiree health plan (c)		116,000		21,000		42,000		42,000		11,000
Transportation and Storage Obligation (d)		18,946,148		3,302,991		8,544,997		7,098,160		—
Total Obligations	$	45,955,472	$	5,542,401	$	12,917,182	$	13,519,926	$	13,975,963

(a)	Our long-term debt, notes payable and customers’ deposits all require interest payments. Interest payments are projected based on actual interest payments incurred in fiscal 2005 until the underlying debts mature.
(b)	See Note 3 of the Notes to Consolidated Financial Statements for a description of this debt. The cash obligations represent the maximum annual amount of redemptions to be made to certain holders or their beneficiaries through the debt maturity date.
(c)	For the purpose of this calculation, we have assumed that our obligation is limited to a maximum of $125 per month for each of our 14 retired persons for the remainder of their expected life.
(d)	Transportation and Storage Obligations represent annual commitments with suppliers for periods extending up to four years. These costs are recoverable in customer rates.

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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 counterparty performance. The Company has established policies and procedures to manage such risks. The Company has a Risk Management Committee (RMC), comprised of Company officers and management to oversee the Company’s risk management program as defined in its risk management policy. The purpose of the risk management program is to minimize adverse impacts on earnings resulting from volatility of energy prices, counterparty credit risks, and other risks related to the energy commodity business.

In order to mitigate the risk of natural gas market price volatility related to firm commitments to purchase or sell natural gas or electricity, from time to time the Company and its subsidiaries have entered into hedging arrangements. Such arrangements may be used to protect profit margins on future obligations to deliver gas at a fixed price, or to protect against adverse effects of potential market price declines on future obligations to purchase gas at fixed prices.

The Company accounts for certain of such purchases or sale agreements in accordance with SFAS No. 133. Under SFAS 133, such contracts are reflected in the Company’s financial statements as derivative assets or derivative liabilities and valued at “fair value,” determined as of the date of the balance sheet. Fair value accounting treatment is also referred to as “mark-to-market” accounting. Mark-to-market accounting results in disparities between reported earnings and realized cash flow, because changes in the derivative values are reported in the Company’s Consolidated Statement of Operations as an increase or (decrease) in “Revenues — Gas and Electric — Wholesale” without regard to whether any cash payments have been made between the parties to the contract. If such contracts are held to maturity, the cash flow from the contracts and their hedges are realized over the life of the contracts. SFAS No. 133 requires that contracts for purchase or sale at fixed prices and volumes must be valued at fair value (under mark-to-market accounting) unless the contracts qualify for treatment as a “normal purchase or sale.”

Quoted market prices for natural gas derivative contracts of the Company and its subsidiaries are generally not available. Therefore, to determine the net present value of natural gas derivative contracts, the Company uses internally developed valuation models that incorporate independently available current and forecasted pricing information.

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As of September 30, 2005, these agreements were reflected on the Company’s consolidated balance sheet as derivative assets and liabilities at an approximate fair value as follows:

	Assets		Liabilities
Contracts maturing during fiscal year 2006	$	254,810	$	255,165
Contracts maturing during fiscal years 2007 and 2008		—		—
Contracts maturing during fiscal years 2009 and beyond		45,989		—
Total	$	300,799	$	255,165

Regulated Operations — In the case of the Company’s regulated divisions, gains or losses resulting from derivative contracts are subject to deferral under regulatory procedures approved by the public service regulatory commissions of the States of Montana and Wyoming. Therefore, related derivative assets and liabilities are offset with corresponding regulatory liability and asset amounts included in “Recoverable Cost of Gas Purchases”, pursuant to SFAS No. 71, Accounting for the Effects of Certain Types of Regulation.

ITEM 3 — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

The Company is subject to certain market risks, including commodity price risk (i.e., natural gas and propane prices) and interest rate risk. The adverse effects of potential changes in these market risks are discussed below. The sensitivity analyses presented do not consider the effects that such adverse changes may have on overall economic activity nor do they consider additional actions management may take to mitigate our exposure to such changes. Actual results may differ. See the notes to the financial statements for a description of our accounting policies and other information related to these financial instruments.

Commodity Price Risk

The Company seeks to protect itself against natural gas price fluctuations by limiting the aggregate level of net open positions that are exposed to market price changes. Open positions are to be managed with policies designed to limit the exposure to market risk, with regular reporting to management of potential financial exposure. Our Risk Management Committee has limited the types of contracts the Company will consider to those related to physical natural gas deliveries. Therefore, management believes that our results of operations are not significantly exposed to changes in natural gas prices.

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Interest Rate Risk

Our 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. Some of our notes payable, however, are subject to variable interest rates which we may mitigate by entering into interest rate swaps. A hypothetical 100 basis point change in market rates applied to the balance of the notes payable would change interest expense by approximately $130,000 annually.

Credit Risk

Credit risk relates to the risk of loss that the Company would incur as a result of non-performance by counterparties of their contractual obligations under the various instruments with the Company. Credit risk may be concentrated to the extent that one or more groups of counterparties have similar economic, industry or other characteristics that would cause their ability to meet contractual obligations to be similarly affected by changes in market or other conditions. In addition, credit risk includes not only the risk that a counterparty may default due to circumstances 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

Disclosure controls and procedures are designed with an objective of ensuring that information required to be disclosed in our periodic reports filed with the Securities and Exchange Commission, such as this Quarterly Report on Form 10-Q, is recorded, processed, summarized and reported within the time periods specified by the Securities and Exchange Commission. Disclosure controls are also designed with an objective of ensuring that such information is accumulated and communicated to our management, including our chief executive officer and chief financial officer, in order to allow timely consideration regarding required disclosures.

The evaluation of our disclosure controls by our principal executive officer and principal financial officer included a review of the controls’ objectives and design, the operation of the controls, and the effect of the controls on the information presented in this Quarterly Report. Our management, including our chief executive officer and chief financial officer, does not expect that disclosure controls can or will prevent or detect all errors and all fraud, if any. A control system, no matter how well designed and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Also, projections of any evaluation of the disclosure controls and procedures to future periods are subject to the risk that the disclosure controls and procedures may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Based on their review and evaluation, as of the end of the period covered by this Quarterly Report on Form 10-Q, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under

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the Securities Exchange Act of 1934) were effective at the reasonable assurance level. They are not aware of any significant changes in our disclosure controls or in other factors that could significantly affect these controls subsequent to the date of their evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. During the most recent fiscal period, there have not been any changes in our internal control over financial reporting that have materially affected, or that are reasonably likely to materially affect, our internal control over financial reporting.

PART II — OTHER INFORMATION

ITEM 6.Exhibits

Exhibit
Number	Description
31	Certifications pursuant to SEC Release No. 33-8238, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32	Certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

SIGNATURES

Pursuant to the requirements of Section 13 or 15 (d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

ENERGY WEST, INCORPORATED
/s/ Wade F. Brooksby
Wade F. Brooksby	November 14, 2005
Chief Financial Officer
(principal financial officer
and principal accounting officer)

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