Gas Natural 10Q 2006 Q1 Quarterly report

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-Q


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

For the quarterly period ended March 31, 2006


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 (State or other jurisdiction of incorporation or organization)		81-0141785 (I.R.S. Employer Identification No.)

1 First Avenue South, Great Falls, Montana 59401
(Address of principal executive offices) (Zip Code)

Registrant’s telephone number, including area code (406)-791-7500

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 check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filero Accelerated filerþ Non-accelerated filero

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 May 8, 2006 was 2,931,677 shares.

ENERGY WEST, INCORPORATED
INDEX TO FORM 10-Q


	Page No.
PART I — FINANCIAL INFORMATION

Item 1 - Financial Statements

Condensed Consolidated Balance Sheets (unaudited) as of March 31, 2006, March 31, 2005 and June 30, 2005		2

Condensed Consolidated Statements of Operations (unaudited)- three months ended March 31, 2006 and 2005 and nine months ended March 31, 2006 and 2005		3

Condensed Consolidated Statements of Cash Flows (unaudited)- nine months ended March 31, 2006 and 2005		4

Notes to Condensed Consolidated Financial Statements		5

Item 2 - Management’s Discussion and Analysis of Financial Condition and Results of Operations		13

Item 3 - Quantitative and Qualitative Disclosures About Market Risk		32

Item 4 - Controls and Procedures		33

PART II — OTHER INFORMATION

Item 6 - Exhibits		33

SIGNATURES
EX-10
EX-31
EX-32

PART I — FINANCIAL INFORMATION

Item 1 — Financial Statements

ENERGY WEST, INCORPORATED AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)


	March 31,				June 30,
	2006		2005		2005
ASSETS
Current assets:
Cash and cash equivalents	$	485,030	$	982,069	$	93,606
Accounts and notes receivable, less $437,159 $326,649, and $294,646, respectively, allowance for bad debt		9,358,547		7,628,410		5,791,888
Unbilled gas		3,413,147		3,902,838		1,092,320
Derivative assets		130,949		150,745		119,069
Natural gas and propane inventories		3,032,665		1,009,784		3,711,033
Materials and supplies		518,958		482,249		440,959
Prepayments and other		378,175		713,178		386,306
Deferred income taxes		171,257		280,687		—
Income tax receivable		—		—		1,924,648
Recoverable cost of gas purchases		1,321,026		1,521,321		1,863,475


Total current assets		18,809,754		16,671,281		15,423,304

Property, plant and equipment, net		39,017,104		38,883,579		38,942,123
Note receivable		—		253,944		174,561
Deferred charges		4,253,148		4,896,419		4,725,924
Other assets		173,865		142,068		167,481

*TOTAL ASSETS*	$	62,253,871	$	60,847,291	$	59,433,393


LIABILITIES AND CAPITALIZATION

Current Liabilities:
Current portion of long-term debt	$	1,023,336	$	2,977,988	$	1,013,089
Line of credit		1,490,000		3,500,000		3,900,000
Accounts payable		5,769,263		4,185,150		2,651,047
Derivative liabilities		49,002		111,492		114,237
Deferred income tax		—		—		96,214
Accrued and other current liabilities		4,551,898		4,934,165		3,750,177


Total current liabilities		12,883,499		15,708,795		11,524,764


Other obligations:
Deferred income taxes		6,429,791		4,970,601		6,267,858
Deferred investment tax credits		297,486		318,548		313,282
Other long-term liabilities		5,168,632		5,282,787		5,463,667

Total other obligations		11,895,909		10,571,936		12,044,807


Long-term debt		18,270,198		19,333,341		18,677,197


Commitments and contingencies

Stockholders’ equity:
Common stock; $.15 par value, 5,000,000 shares authorized, 2,931,158; 2,625,064 and 2,912,564 shares outstanding at March 31, 2006 and 2005, and June 30, 2005 respectively		439,674		393,767		436,892
Preferred stock; $.15 par value, 1,500,000 shares authorized, no shares outstanding		—		—		—
Capital in excess of par value		7,608,528		5,295,663		7,435,309
Retained earnings		11,156,063		9,543,789		9,314,424


Total stockholders’ equity		19,204,265		15,233,219		17,186,625


TOTAL CAPITALIZATION		37,474,463		34,566,560		35,863,822

*TOTAL LIABILITIES AND CAPITALIZATION*	$	62,253,871	$	60,847,291	$	59,433,393

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

ENERGY WEST, INCORPORATED AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)


	Three Months Ended				Nine Months Ended
	March 31,				March 31,
	2006		2005		2006		2005
REVENUES:
Natural gas operations	$	21,357,055	$	17,328,722	$	47,859,970	$	36,764,948
Propane operations		4,605,009		3,491,498		8,133,939		7,366,600
Gas and electric—wholesale		6,093,338		6,501,734		15,071,222		18,159,632
Pipeline operations		100,340		116,095		311,087		302,381


Total revenues		32,155,742		27,438,049		71,376,218		62,593,561


EXPENSES:
Gas purchased		20,407,387		14,990,440		43,193,794		31,168,104
Gas and electric—wholesale		5,432,770		4,894,793		13,896,435		16,423,272
Distribution, general, and administrative		2,059,937		2,317,759		6,342,717		7,170,592
Maintenance		143,442		126,810		417,012		420,441
Depreciation and amortization		529,901		581,576		1,632,976		1,763,846
Taxes other than income		456,139		444,219		1,231,164		1,211,662


Total expenses		29,029,576		23,355,597		66,714,098		58,157,917


OPERATING INCOME		3,126,166		4,082,452		4,662,120		4,435,644

OTHER INCOME		105,268		76,725		424,423		284,195

INTEREST EXPENSE		582,279		640,998		1,671,734		2,115,187


INCOME BEFORE INCOME TAXES		2,649,155		3,518,179		3,414,809		2,604,652

INCOME TAX EXPENSE		1,003,373		1,331,864		1,273,496		973,634


NET INCOME	$	1,645,782	$	2,186,315	$	2,141,313	$	1,631,018


INCOME PER COMMON SHARE:
Basic	$	0.56	$	0.84	$	0.73	$	0.63
Diluted	$	0.55	$	0.84	$	0.73	$	0.63

WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:
Basic		2,931,013		2,601,996		2,921,839		2,596,048
Diluted		3,008,880		2,601,996		2,946,899		2,596,048

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

ENERGY WEST, INCORPORATED AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)


	Nine Months Ended
	March 31,
	2006			2005
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	2,141,313		$	1,631,018
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization, including deferred charges and financing costs		2,140,930			2,303,377
Derivative assets		(11,880	)		48,503
Derivative liabilities		(65,235	)		(1,573,184	)
Deferred gain		(582,567	)		1,081,372
Gain on sale of assets		—			(3,005	)
Investment tax credit		(15,796	)		(15,796	)
Deferred gain on sale of assets		(17,721	)		(17,721	)
Deferred income taxes		483,519			687,432
Changes in assets and liabilities:
Accounts and notes receivable		(5,482,115	)		(4,648,634	)
Natural gas and propane inventories		678,368			4,173,262
Accounts payable		2,658,410			574,071
Recoverable/refundable cost of gas purchases		542,449			(732,914	)
Prepayments and other		8,130			(342,799	)
Other assets & liabilities		2,531,214			(1,580,290	)

Net cash provided by operating activities		5,009,019			1,584,692


CASH FLOWS FROM INVESTING ACTIVITIES:
Construction expenditures		(1,799,506	)		(2,126,166	)
Proceeds from sale of assets		—			3,005
Collection of long-term notes receivable		174,561			—
Customer advances received for construction		57,455			23,616
Increase from contributions in aid of construction		15,571			61,167

Net cash used in investing activities		(1,551,919	)		(2,038,378	)


CASH FLOWS FROM FINANCING ACTIVITIES:
Repayments of long-term debt		(396,752	)		(358,663	)
Proceeds from lines of credit		14,850,000			8,900,000
Repayments of lines of credit		(17,260,000	)		(12,130,062	)
Proceeds from other short-term borrowings		—			3,500,000
Deferred director compensation — stock		—			201,778
Dividends paid		(258,924	)		—

Net cash (used in) provided by financing activities		(3,065,676	)		113,053


NET INCREASE IN CASH AND CASH EQUIVALENTS		391,424			(340,633	)

CASH AND CASH EQUIVALENTS:
Beginning of period		93,606			1,322,702

End of period	$	485,030		$	982,069

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

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

March 31, 2006

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 and nine month periods ended March 31, 2006 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 in Montana and Wyoming and, on a limited basis, electricity in Montana, and owns natural gas producing wells 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 producing wells in Montana. The Company’s reporting segments are: Natural Gas Operations, Propane Operations, EWR and Pipeline Operations.

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 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.

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 nine months ended March 31, 2006, the Company has not entered into any new contracts that have required fair value accounting under Statement of Financial Accounting Standards (“SFAS”) No. 133. (Fair value accounting is also referred to as mark-to-market accounting.) However, existing derivatives as of March 31, 2006 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	$	48,837	$	49,002
Contracts maturing during fiscal years 2007 and 2008		—		—
Contracts maturing during fiscal years 2009 and beyond		82,112		—

Total	$	130,949	$	49,002

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, 2006, the Company’s regulated operations have no contracts meeting the mark-to-market accounting requirements.

NOTE 2 — INCOME TAX EXPENSES

Income tax expense differs from the amount computed by applying the federal statutory rate to pretax income (loss) as demonstrated in the following table:


	Three Months Ended						Nine Months Ended
	March 31,						March 31,
	2006			2005			2006			2005
Tax expense at statutory rate of 35%	$	927,204		$	1,233,205		$	1,195,183		$	917,157
State income tax expense, net of federal tax benefit		126,286			167,089			138,901			116,163
Amortization of deferred investment tax credits		(5,265	)		(5,266	)		(15,796	)		(15,797	)
Other		(44,852	)		(63,164	)		(44,792	)		(43,889	)


Total income tax expense	$	1,003,373		$	1,331,864		$	1,273,496		$	973,634

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.

On November 28, 2005, the Company entered into a restated credit agreement with LaSalle Bank National Association, as agent for certain banks (collectively, the “Lender”). Pursuant to the restated credit agreement, the previous $15.0 million revolving credit facility was replaced with a $15.0 to $20.0 million revolving credit facility. The revolving line of credit is $20.0 million during the three month period November 28, 2005 through February 28, 2006 and continues at $15.0 million during the nine month period March 1, 2006 to November 26, 2006.

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 the Lender in the collateral granted to secure the borrowings under the LaSalle Facility 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 revolving line of credit at the London interbank offered rate (LIBOR), plus

200 basis points or at the Prime Rate, for interest periods selected by the Company. 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 300 basis points or at the Prime Rate. The Company also pays a commitment fee of 25 basis points for the daily unutilized portion of the revolving credit facility.

During the quarter ended September 30, 2004, the Company entered into an interest rate swap agreement related to the LaSalle Facility. The interest rate swap agreement converts a declining notional amount of variable rate debt to a fixed rate of 7.40%. The amortizing notional principal amount begins at $2,933,333 on August 9, 2004 and amortizes to $2,016,666 as of March 31, 2009. The effect of the interest rate swap, therefore, is to fix the rate of interest at 7.40% for that portion on the $6.0 million term loan under the LaSalle 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. 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 March 31, 2006, the Company had approximately $500,000 of cash on hand. In addition, at March 31, 2006, the Company had borrowed $1.5 million under the revolving line of credit. The Company’s short-term borrowings under its lines of credit during the nine months ended March 31, 2006 had a daily weighted average interest rate of 7.46% per annum. The Company’s net availability at March 31, 2006 was $13.5 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, liens and secured indebtedness, asset sales, and from incurring additional long-term indebtedness if it does not meet certain debt to interest and debt to capital ratios. Dividends and distributions during the period are limited to the cumulated net income for the prior sixty months. During the three months and nine months ended March 31, 2006, the Company was in compliance with all financial covenants.

The total amount outstanding under all of the Company’s long-term debt obligations was approximately $18.3 million and $22.3 million at March 31, 2006 and March 31, 2005,

respectively. The portion of such obligations due within one year was approximately $1,000,000 and $3,000,000 at March 31, 2006, and March 31, 2005, 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 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, collateralized by the wholesale propane assets sold. This note was paid in full on July 19, 2005.

NOTE 5 — DEFERRED CHARGES

Deferred Charges consist of the following:


	March 31,				June 30,
	2006		2005		2005
Regulatory asset for property taxes	$	2,361,092	$	2,632,429	$	2,561,265
Regulatory asset for income taxes		458,753		458,753		458,753
Regulatory asset for deferred environmental remediation costs		350,519		429,296		413,218
Other regulatory assets		29,298		72,334		52,198
Unamortized debt issue costs		1,053,486		1,303,607		1,240,490


Total	$	4,253,148	$	4,896,419	$	4,725,924

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

The property tax asset is recovered in rates over a ten-year period starting January 1, 2004. The regulatory 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 consist of rate case costs. The majority of these costs 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 gasification process utilized in the plant resulted in the production of certain by-products that 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 March 31, 2006, the Company had incurred cumulative costs of approximately $1,963,000 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 March 31, 2006, the Company had recovered approximately $1,612,000 through such surcharges. As of March 31, 2006, the cost remaining to be recovered is $351,000.

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. The Company is required 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.

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 should be assessed. The settlement amount is being paid in ten annual installments of $243,000 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 that includes full recovery of the property tax associated with the DOR settlement.

NOTE 7 — SEGMENTS OF OPERATIONS


	Three Months Ended				Nine Months Ended
	March 31,				March 31,
	2006		2005		2006		2005
Gross margin (operating revenue less cost of gas purchased):
Natural gas operations	$	3,993,427	$	4,260,992	$	9,712,055	$	9,589,780
Propane operations		1,561,250		1,568,788		3,088,060		3,373,664
EWR		660,568		1,606,941		1,174,787		1,736,360
Pipeline operations		100,340		116,095		311,087		302,381

		6,315,585		7,552,816		14,285,989		15,002,185


Operating income:
Natural gas operations		1,638,634		1,774,248		2,775,780		2,356,285
Propane operations		907,013		811,083		1,068,995		1,132,356
EWR		520,200		1,427,488		635,893		775,972
Pipeline operations		60,319		69,633		181,452		171,031

		3,126,166		4,082,452		4,662,120		4,435,644


Net income:
Natural gas operations		824,132		876,586		1,241,415		663,267
Propane operations		496,006		404,412		490,555		511,031
EWR		295,291		873,878		318,527		381,941
Pipeline operations		30,353		31,439		90,816		74,779

	$	1,645,782	$	2,186,315	$	2,141,313	$	1,631,018

NOTE 8 — ACCRUED AND OTHER CURRENT LIABILITIES

Accrued and other current liabilities consist of the following:


	March 31,				June 30,
	2006		2005		2005
Property tax settlement—current portion	$	243,000	$	243,000	$	243,000
Accrued income taxes		615,184		390,766		—
Payable to employee benefit plans		174,530		508,152		481,514
Accrued vacation		268,357		402,146		267,859
Customer deposits		483,412		414,957		418,148
Accrued incentives		32,609		—		12,246
Accrued interest		408,219		308,572		97,987
Accrued taxes other than income		871,079		836,865		507,288
Customer prepayments from levelized billing		405,371		456,756		459,814
Deferred gas revenues		—		206,731		—
Deferred gain		243,519		451,557		399,760
Other		806,618		714,663		862,561

Total	$	4,551,898	$	4,934,165	$	3,750,177

NOTE 9 — OTHER LONG TERM LIABILITIES

Other long-term liabilities consist of the following:


	March 31,				June 30,
	2006		2005		2005
Asset retirement obligation	$	642,656	$	610,412	$	618,473
Contribution in aid of construction		1,969,517		1,286,706		1,447,448
Customer advances for construction		228,894		627,205		677,936
Accumulated postretirement obligation		394,183		314,934		342,900
Deferred gain — long-term *		386,295		629,815		569,102
Deferred gain on sale leaseback of assets		5,918		29,546		23,639
Regulatory liability for income taxes		83,161		83,161		83,161
Property tax settlement		1,458,008		1,701,008		1,701,008

Total	$	5,168,632	$	5,282,787	$	5,463,667


*		In January 2005, two long-term contracts were designated as “normal purchases and sales”. The derivative liability as of January 2005 is being 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, since the exercise price of the Company’s employee

stock options equals the market price of the underlying stock on the date of grant. The Company has adopted SFAS No. 123(R), and 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 third quarter ended March 31, 2006 stock-based compensation expense utilized the methodology and assumptions consistent with those previously used by the Company to report pro-forma net income or loss under SFAS No. 123(R). The general and administrative expense for the stock-based compensation in the third quarter of fiscal 2006 was approximately $30,000, approximately $0.01 per share.

The Company uses the Black Scholes methodology, with a price volatility assumption of 53% based upon historical stock prices for the last twelve months, an expected life of 7 years, 3% expected dividend rate, and a risk free interest rate of 3.9%. If the Company had recorded stock option expense in the quarter ended March 31, 2005, its pro forma net income would have been decreased by approximately $20,000, 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 our 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, our environmental remediation plans, and similar statements that are not historical are forward-looking statements that involve risks and uncertainties. Although we believe 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 our company from time to time, including statements contained in our filings with the Securities and Exchange Commission and our reports to shareholders, involve known and unknown risks and other factors which may cause our actual results in future periods to differ materially from those expressed in any forward-looking statements. (See “Risk Factors” in our 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. We caution that these risk factors are not exclusive. We do not undertake to update any forward-looking statements that may be made from time to time by or on behalf of our company except as required by law.

Executive Overview

Our primary source of revenue and operating margin is derived from the distribution of natural gas and propane to end-use residential, commercial, and industrial customers. We also derive revenues providing gas supply and load management services to certain industrial and commercial customers through our gas marketing subsidiary on an “unregulated” basis.

We have seen measurable benefits from a renewed focus on our core business — utility service, pipelines and natural gas production. Significant cost reductions have helped us strengthen our balance sheet, build momentum in earnings growth, and restore dividends to our shareholders. We believe that our ongoing financial results will be less impacted by non-recurring events such as the derivative transactions that occurred in 2004 and 2005. Earnings for the nine months ending March 31, 2006 increased 31% over the same period in 2005 and represent an all time high for the core business of Energy West. We were able to achieve these positive results despite the occurrence of one of our warmest winters (leading to reduced sales), during a period of historically high natural gas commodity prices, and in a period of increasing interest rates.

We have been paying higher prices to obtain natural gas and propane during the past three fiscal quarters. To mitigate the effect on our customers of higher commodity prices, we are concentrating on improving the productivity of our employees, and reducing our general, administrative and overhead expenses as well as our interest expense. Our improved profitability has afforded us the opportunity to increase the dividend payment which is being announced contemporaneously with the filing of this Quarterly Report on Form 10-Q to $.08 per share which represents a 60% increase from the prior dividend payment.

Despite recent positive trends in our business, we continue to address certain challenges. We remained concerned about our increasing demand for cash due to high commodity prices and our heavy reliance on a few suppliers. In addition, a loss of key personnel in such areas as accounting, engineering, propane, and pipeline operations could have an impact on the efficient operation of our company due to the expense of hiring and training qualified personnel. Furthermore, our small size makes us vulnerable to large earnings variations if litigation or other one-time expenses occur.

The above concerns are counterbalanced by what we believe to be our strengths:

	•		Geographic proximity of our regulated natural gas business to gas 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 limited incremental expenses.

Strategy

Based on the foregoing, the key elements of our current strategy include the following:

	•		Focus on the natural gas distribution and related businesses.

	•		Pursue appropriate regulatory treatment of higher commodity prices, including changing customer consumption patterns and removing other regulatory impediments to effective management of the business.

	•		Economic expansion of our customer base by prudently managing capital expenditures and ensuring new customers provide sufficient margins for an appropriate return on the new investment required to acquire the customers.

	•		Continue to focus on operational efficiencies.

	•		Manage cash flow to avoid the requirement of additional debt financing.

	•		Plan for and execute upon the continued high growth in and around our Arizona propane business.

	•		Maintain and improve our positive reputation with regulators and customers.

	•		Refine our corporate infrastructure to be able to provide a platform for additional projects with limited incremental expenses.

Opportunities and Challenges

Overall revenues and margins are negatively affected by higher efficiency in new homes and commercial buildings, higher efficiency in gas-burning equipment, and customer measures to reduce energy usage. The increasing cost of energy in recent years, including the wholesale cost of natural gas and propane, continues to encourage such measures.

We earn approximately 20% of our operating margin from providing gas marketing services to “unregulated” commercial and industrial gas customers. The loss of a major customer, or unfavorable conditions affecting an industry segment, could have a detrimental impact on our earnings. Many external factors over which we have no control can significantly impact the amount of gas consumed by industrial and commercial customers and, consequently, affect the margins we earn. We endeavor to enter into sales agreements through which we can match estimated demand with a supply that provides an acceptable margin.

Revenues and margins from our residential and small commercial customers are highly weather-sensitive. In a cold year, our earnings are boosted by the effects of the weather. Conversely, in a warm year, our earnings suffer. Peak requirements also drive the need to reinforce our systems to increase capacity, which in turn, increases costs.

Prospects for continuing our strong residential and commercial customer growth are excellent. The pace of new home and commercial construction remains steady particularly in the Arizona communities we serve. Growth of customer count in these Arizona communities has been about double the average of U.S. utilities.

We carefully analyze the economics of our spending to support growth. When justified under our tariffs, we work with developers, business owners, and residences to share certain construction costs to assure a fair return to our company. Non-revenue-generating spending is also managed to assure that we use the most economically attractive solutions, while providing for a safe and reliable system.

We are analyzing drilling opportunities within our gas production property located in north central Montana and drilling activities by others near our pipeline properties located in southeast Montana and northwest Wyoming to increase revenues and margins.

In summary, we intend to maintain in future periods the momentum we have built this year and to continue to sharpen our focus on opportunities and strategies that improve shareholder value.

Operating Results of Our Company

Three Months Ended March 31, 2006 Compared to Three Months Ended March 31, 2005

The following discussion of our 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 our 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 March 31, 2006 and for the three month period ended March 31, 2006. Results of operations for interim periods are not necessarily indicative of results to be attained for any future period.

Net Income.Our net income for the third quarter ended March 31, 2006 was $1,646,000 compared to a net income of $2,186,000 in the third quarter ended March 31, 2005, a decrease of $540,000. The decrease in our net income was primarily due to lower gross margins offset by lower operating expenses in all segments, higher other income, and decreases in interest and income tax expense. EWR margin decreased $946,000 for the third quarter resulting primarily from a timing difference relating to a November 2004 transaction in which we sold storage gas during the second quarter and agreed to purchase gas in the third quarter. This transaction had the effect of enhancing reported third quarter fiscal year 2005 revenues by $743,500. We have made substantial progress in the elimination of such one-time events. Our results for the future should be more reflective of ongoing business without these abnormal fluctuations. Natural Gas experienced decreased margins due to warm weather, with Montana and Wyoming experiencing some of the warmest weather on record.

Revenues.Our revenues for the third quarter ended March 31, 2006 were $32,156,000 compared to $27,438,000 in the third quarter ended March 31, 2005, an increase of $4,718,000. The increase was primarily attributable to natural gas and propane revenue increases of $4,028,000 and $1,114,000 respectively due to higher prices for natural gas and propane passed through to customers.

EWR experienced a decrease in revenues of $409,000 from $6,502,000 for the third quarter ended March 31, 2005, to $6,093,000 for the third quarter ended March 31, 2006. Revenues changed primarily due to decreases in the valuation of derivative contracts of $961,000, (related to the November 2004 transaction mentioned above) a $97,000 decrease in the amortization of deferred gain and decreases of $15,000 from normal operations. These decreases were offset by increased gas revenues of $664,000 due to higher volumes and prices.

Pipeline operations also experienced a $16,000 decrease in revenues, from $116,000 in the third quarter ended March 31, 2005 to $100,000 in the third quarter ended March 31, 2006, due to a decrease in transportation flows.

Gross Margin.Gross margin, which is defined as revenue less gas purchased and costs of gas and electricity (wholesale), decreased $1,237,000, from $7,553,000 in the third quarter ended March 31, 2005 to $6,316,000 in the third quarter ended March 31, 2006.

EWR margin decreased $946,000 due to a $1,058,000 decrease in the valuation of derivative contracts offset by increases totaling $112,000 in production, gas and electric margin.

Natural Gas Operations’ margin decreased $268,000 primarily due to warmer weather and lower volumes sold, with Montana experiencing one of the warmest winters on record.

Expenses Other Than Costs of Gas and Electricity and Costs of Goods Sold. Expenses other than gas purchased decreased by $281,000 in the third quarter ended March 31, 2006 as compared to the third quarter ended March 31, 2005. The primary reasons for this decrease were decreases in our general and administrative costs of $57,000, decreases in depreciation and amortization of $52,000, and decreases in overhead costs of $201,000, offset by increases in maintenance and taxes other than income of $17,000 and $12,000 respectively.

Other Income.Other income increased by $28,000, from $77,000 in the third quarter ended March 31, 2005 to $105,000 in the third quarter ended March 31, 2006. Natural Gas other income increased $39,000 primarily due to income generated in fiscal year 2006 for services to customers over what had been provided in prior years, and other miscellaneous income. Propane other income decreased $11,000 due to the payoff on July 9, 2005 of the note receivable in RMF resulting in less interest income than in the third quarter ended March 31, 2005.

Interest Expense.Interest expense decreased by approximately $59,000 during the third quarter ended March 31, 2006 from the third quarter ended March 31, 2005 due to lower short-term borrowings partially offset by higher interest rates in fiscal year 2006.

Income Tax Expense.Income tax expense decreased $328,000 in the third quarter ended March 31, 2006 as compared to the third quarter ended March 31, 2005 due to decreased pretax income in the third quarter ended March 31, 2006.

Nine Months Ended March 31, 2006 Compared to Nine Months Ended March 31, 2005

The following discussion of our 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 our 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 March 31, 2006 and for the nine month period ended March 31, 2006. Results of operations for interim periods are not necessarily indicative of results to be attained for any future period.

Net Income.Our net income for the nine months ended March 31, 2006 was $2,141,000 compared to $1,631,000 in the nine months ended March 31, 2005, an increase of $510,000. The increase in our net income was primarily due to lower operating expenses in all segments, increased other income and decreased interest expense. These were partially offset by decreased margins and increased income tax expense.

Revenues. Our revenues for the nine months ended March 31, 2006 were $71,376,000 compared to $62,594,000 in the nine months ended March 31, 2005, an increase of $8,782,000. The increase was primarily attributable to natural gas revenue increases of $11,095,000 due to higher prices for natural gas passed through to customers, as well as a rate increase put into effect in November of 2004, partially offset by decreases in EWR totaling $3,088,000.

The decreased revenues in EWR were due to $2,277,000 lower revenue from the sale of storage gas, $733,000 reduced gas revenue from lower volumes to our regular customers, reductions of $8,000, and $5,000 in production and electric revenue respectively, and a $247,000 change in the value of derivative contracts. These reductions were offset by an increase of $182,000 in amortization of the deferred gain.

Revenues also reflect an increase of $767,000 in the Propane segment due to higher propane prices, partially offset by warmer weather and lower volumes sold, as well as reduced sales to external customers by Rocky Mountain Fuels. The increased revenues in Pipeline Operations of $9,000 are 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), decreased $716,000, from $15,002,000 in the nine months ended March 31, 2005 to $14,286,000 in the nine months ended March 31, 2006. EWR margins decreased $561,000. This is primarily due to a $595,000 decrease in gas margin due to lower sales volumes and higher gas prices and a $64,000 decrease in the valuation of derivative contracts and deferred gain. These decreases were offset by increases of $63,000 in production margin and $35,000 in electric margin.

Pipeline Operations’ margin increased $9,000 due to the Glacier line being temporarily down from early June 2004 until the first week of November 2004. Natural Gas Operations’ margin increased $122,000 primarily due to approved rate increases put into effect in November 2004. Propane Operations’ margin decreased $286,000 primarily due to warmer weather and lower volumes, as well as reduced sales to external customers through Rocky Mountain Fuels. Competitive pressures in the unregulated Arizona operation resulted in lower margins during times of high propane prices.

Expenses Other Than Costs of Gas and Electricity and Costs of Goods Sold. Expenses other than gas purchased decreased by $943,000 in the nine months ended March 31, 2006 as compared to the nine months ended March 31, 2005. The primary reasons for this decrease were reductions in our general and administrative costs of $606,000, decreases in depreciation and amortization of $131,000, and decreases in overhead and maintenance of $222,000 and $3,000 respectively, offset by an increase of $20,000 in taxes other than income.

Other Income.Other income increased by $140,000, from $284,000 in the nine months ended March 31, 2005 to $424,000 in the nine months ended March 31, 2006. Natural Gas other income increased $227,000 primarily due to income generated in fiscal year 2006 for services to customers over what had been provided in prior years, and other miscellaneous income. Propane other income decreased $53,000 due to the payoff on July 9, 2005 of the note receivable in RMF resulting in less interest and consulting fee income in fiscal year 2006. EWR other income was higher by $34,000 in the first nine moths ended March 31, 2005 due to income generated from settlement of a contract dispute during that time period.

Interest Expense.Interest expense decreased by approximately $443,000 during the nine months ended March 31, 2006 from the nine months ended March 31, 2005 due to lower short-term borrowings and the amortization of debt issuance costs related to securing the LaSalle short-term credit facility in fiscal year 2005. These reductions were partially offset by higher interest rates.

Income Tax Expense.Income tax expense increased $300,000 in the nine months ended March 31, 2006 as compared to the nine months ended March 31, 2005 due to increased pretax income in fiscal year 2006.

Operating Results of our Natural Gas Operations


	Three Months Ended						Nine Months Ended
	March 31,						March 31,
Natural Gas Operations	2006			2005			2006			2005
Operating revenues	$	21,357,055		$	17,328,722		$	47,859,970		$	36,764,948
Gas Purchased		17,363,628			13,067,730			38,147,915			27,175,168

Gross Margin		3,993,427			4,260,992			9,712,055			9,589,780
Operating expenses		2,354,793			2,486,744			6,936,275			7,233,495

Operating income		1,638,634			1,774,248			2,775,780			2,356,285
Other income		67,312			28,204			303,255			75,908

Income before interest and taxes		1,705,946			1,802,452			3,079,035			2,432,193
Interest expense		407,912			466,821			1,138,522			1,407,469

Income before income taxes		1,298,034			1,335,631			1,940,513			1,024,724
Income tax (expense)		(473,902	)		(459,045	)		(699,098	)		(361,457	)

Net income	$	824,132		$	876,586		$	1,241,415		$	663,267

Three Months Ended March 31, 2006 Compared to Three Months Ended March 31, 2005

Natural Gas Revenues and Gross Margins. The Natural Gas Operations’ operating revenues in the third quarter ended March 31, 2006 increased to $21,357,000 from $17,329,000 in the third quarter ended March 31, 2005. This $4,028,000 increase was primarily due to the pass-through nature of higher commodity costs.

Gas purchases in Natural Gas Operations increased by $4,296,000, from $13,068,000 in the third quarter ended March 31, 2005 to $17,364,000 in the third quarter ended March 31, 2006. The increase reflects higher commodity prices during the current fiscal year.

Gross margin, which is defined as operating revenues less gas purchased, was approximately $3,993,000 for the third quarter ended March 31, 2006 compared to approximately $4,261,000 in the same quarter of the previous year. The decrease of $268,000 is due to warmer weather in the current fiscal year that resulted in approximately 971,000 less volume sold this past quarter than the same quarter of last year.

Natural Gas Operating Expenses.Natural Gas Segment’s operating expenses were approximately $2,355,000 for the third quarter ended March 31, 2006 as compared to $2,487,000 for third quarter ended March 31, 2005. The $132,000 reduction is due primarily to $140,000 lower overhead charges and $36,000 in lower depreciation charges. These savings are offset by $30,000 in higher taxes other than income and $14,000 higher operating expenses.

Natural Gas Other Income.Other income increased by $39,000, from $28,000 in the third quarter ended March 31, 2005 to $67,000 in the third quarter ended March 31, 2006. This was due primarily to additional service sales and other miscellaneous income.

Natural Gas Interest Expense.Interest expense is $59,000 lower in the current year third quarter compared to prior year third quarter primarily due to lower short-term borrowings partially offset by higher interest rates.

Natural Gas Income Tax Expense.Tax expense is $15,000 higher in the current year third quarter compared to prior year third quarter due to higher pretax income.

Nine Months Ended March 31, 2006 Compared to Nine Months Ended March 31, 2005

Natural Gas Revenues and Gross Margins.The Natural Gas Operations’ operating revenues in the nine months ended March 31, 2006 increased to $47,860,000 from $36,765,000 in the nine months ended March 31, 2005. This $11,095,000 increase was primarily due to the pass-through nature of higher commodity costs.

Gas purchases in Natural Gas Operations increased by $10,973,000, from $27,175,000 in the nine months ended March 31, 2005 to $38,148,000 in the nine months ended March 31, 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 $9,712,000 for the nine months ended March 31, 2006 compared to approximately $9,590,000 for the nine months ended March 31, 2005. The increase of $122,000 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 $6,936,000 for the nine months ended March 31, 2006 as compared to $7,233,000 for the nine months ended March 31, 2005. The $297,000 reduction is due to $161,000 in lower

overhead charges, $99,000 in lower depreciation charges, $75,000 decrease in payroll and other general and administrative expenses resulting from the implementation of cost-saving measures, and $15,000 in lower maintenance costs. These savings were partially offset by $53,000 in higher taxes other than income taxes.

Natural Gas Other Income. Other income increased by $227,000, from $76,000 in the nine months ended March 31, 2005 to $303,000 in the nine months ended March 31, 2006. This was due primarily to increased service sales and interest income in Great Falls.

Natural Gas Interest Expense.Interest expense is $269,000 lower in the nine months ended March 31, 2006 compared to the same period of the previous fiscal year primarily due to lower short-term borrowings and a decrease in the amortization of debt issuance costs partially offset by higher interest rates.

Natural Gas Income Tax Expense.Tax expense increased $338,000 in the nine months ended March 31, 2006 compared to the nine months ended March 31, 2005 due to higher pretax income.

Operating Results of our Propane Operations


	Three Months Ended						Nine Months Ended
	March 31,						March 31,
Propane Gas Operations	2006			2005			2006			2005
Operating revenues	$	4,605,009		$	3,491,498		$	8,133,939		$	7,366,600
Gas Purchased		3,043,759			1,922,710			5,045,879			3,992,936

Gross Margin		1,561,250			1,568,788			3,088,060			3,373,664
Operating expenses		654,237			757,705			2,019,065			2,241,308

Operating income		907,013			811,083			1,068,995			1,132,356
Other income		31,851			42,416			92,664			145,647

Income before interest and taxes		938,864			853,499			1,161,659			1,278,003
Interest expense		117,240			147,910			352,393			447,837

Income before income taxes		821,624			705,589			809,266			830,166
Income tax (expense)		(325,618	)		(301,177	)		(318,711	)		(319,135	)

Net income	$	496,006		$	404,412		$	490,555		$	511,031

Three Months Ended March 31, 2006 Compared to Three Months Ended March 31, 2005

Propane Revenue and Gross Margins.Propane Operations’ revenues increased $1,114,000, from $3,491,000 for the third quarter ended March 31, 2005 to $4,605,000 for the third quarter ended March 31, 2006 as a result of higher propane prices. Gas purchases increased $1,121,000, from $1,923,000 in the third quarter ended March 31, 2005 to $3,044,000 in the third quarter ended March 31, 2006. This increase was due primarily to higher commodity prices. Gross margin decreased less than 1%, from $1,569,000 in the third quarter ended March 31, 2005 to $1,561,000 in the third quarter ended March 31, 2006. This was attributable to warmer weather and lower volumes. Although propane prices were higher in fiscal year 2006, they were partially offset by warmer weather and volume decreases.

Propane Operating Expenses.Operating expenses were $654,000 in the third quarter ended March 31, 2006 compared to $758,000 in the third quarter ended March 31, 2005. This decrease of $103,000 is due to decreases in general and administrative costs of $45,000, lower overhead costs of $46,000, lower taxes other than income of $7,000, and lower depreciation of $10,000. These savings were offset by an increase in maintenance of $5,000.

Propane Other Income. Other income decreased by $11,000, from $42,000 for the third quarter ended March 31, 2005 to $32,000 for the third quarter ended March 31, 2006. In the third quarter ended March 31, 2005, RMF had interest income from a note receivable generated with the sale of assets in August 2003. This note was paid in full on July 9, 2005, resulting in lower interest income.

Propane Interest Expense. Interest expense decreased by $31,000, from $148,000 in the third quarter ended March 31, 2005 to $117,000 for the third quarter ended March 31, 2006, primarily due to lower short-term borrowings partially offset by higher interest rates in fiscal year 2006.

Propane Income Tax Expense. Income tax expense increased by $25,000, from $301,000 in the third quarter ended March 31, 2005 to $326,000 in the third quarter ended March 31, 2006 due to higher pretax income.

Nine Months Ended March 31, 2006 Compared to Nine Months Ended March 31, 2005

Propane Revenue and Gross Margins. Propane Operations’ revenues increased $767,000, from $7,367,000 for the nine months ended March 31, 2005 to $8,134,000 for the nine months ended March 31, 2006 as a result of higher propane prices, offset by warmer weather and lower volumes, coupled with fewer sales to external customers in the wholesale Rocky Mountain Fuels operation. Gas purchased increased from $3,993,000 to $5,046,000 for the same period due to higher prices in the cost of propane for both the regulated utility and the wholesale propane operations. Gross margin decreased $286,000, from $3,374,000 in the nine months ended March 31, 2005 to $3,088,000 for the nine months ended March 31, 2006. This margin decrease was primarily due to warmer weather and lower volumes, coupled with reduced sales to external customers in the wholesale operation. Competitive pressures in the unregulated Arizona operation resulted in lower margins during times of high propane prices.

Propane Operating Expenses.Operating expenses were $2,241,000 in the nine months ended March 31, 2005 compared to $2,019,000 in the nine months ended March 31, 2006. This decrease of $222,000 is due to decreases in overhead, general and administrative costs of $209,000, and reduced depreciation and taxes other than income of $9,000 and $15,000 respectively. These savings were offset by an increase in maintenance costs of $11,000.

Propane Other Income. Other income decreased by $53,000, from $146,000 for the nine months ended March 31, 2005 to $93,000 for the nine months ended March 31, 2006. In the nine months ended March 31, 2005, RMF had interest income from a note receivable generated with the sale of assets in August 2003. This note was paid in full on July 9^th, 2005, resulting in lower interest income in fiscal year 2006.

Propane Interest Expense.Interest expense decreased by $96,000, from $448,000 in the nine months ended March 31, 2005 to $352,000 for the nine months ended March 31, 2006, primarily due to lower short-term borrowings and a decrease in the amortization of debt issuance costs.

Propane Income Tax Expense.Income tax expense decreased less than $1,000 for the nine months ended March 31, 2006, compared to the same period in the previous year. Pretax income remained relatively constant, decreasing by less than $21,000.

Operating Results of our EWR Operations


	Three Months Ended						Nine Months Ended
	March 31,						March 31,
Energy West Resources (“EWR”)	2006			2005			2006			2005
Operating revenues	$	6,093,338		$	6,501,734		$	15,071,222		$	18,159,632
Gas Purchased		5,432,770			4,894,793			13,896,435			16,423,272

Gross Margin		660,568			1,606,941			1,174,787			1,736,360
Operating expenses		140,368			179,453			538,894			960,388

Operating income		520,200			1,427,488			635,893			775,972
Other income		6,105			6,105			28,504			62,640

Income before interest and taxes		526,305			1,433,593			664,397			838,612
Interest expense		46,133			11,671			146,966			215,977

Income before income taxes		480,172			1,421,922			517,431			622,635
Income tax (expense)		(184,881	)		(548,044	)		(198,904	)		(240,694	)

Net income	$	295,291		$	873,878		$	318,527		$	381,941

Three Months Ended March 31, 2006 Compared to Three Months Ended March 31, 2005

EWR Revenues and Gross Margins.Revenues decreased $409,000 from $6,502,000 in the third quarter ended March 31, 2005 to $6,093,000 in the third quarter ended March 31, 2006. Decreased revenues were primarily due to a decrease of $961,000 from the change in the valuation of derivative contracts, a $97,000 decrease in the amortization of the deferred gain, and

$10,000 and $5,000 decreases in production and electric revenue respectively. The decreases were offset by increased gas revenue of $664,000 due to more volumes and higher sales prices.

Third quarter fiscal year 2006 gross margin of $661,000 represents a decrease of $946,000 over the gross margin earned in the third quarter fiscal year 2005. This is primarily due to a $1,058,000 decrease in the valuation of derivative contracts related to the one-time sale in November 2004, which resulted in a shift of revenue from second quarter fiscal year 2005 to third quarter fiscal year 2005. The decrease is offset by increases of $49,000, $45,000 and $18,000 in production, gas and electricity margins respectively.

EWR Operating Expenses.Operating expenses decreased $39,000, from $179,000 for third quarter ended March 31, 2005 to $140,000 for the third quarter ended March 31, 2006. This decrease is due primarily to a reduction of $55,000 in salary and benefits and $39,000 in various other general and administrative charges. The decrease was offset by an increase of $55,000 in professional and outside services.

EWR Other Income.Other income remained constant.

EWR Interest Expense.Interest expense increased by $34,000 primarily due to lower short-term borrowings partially offset by higher interest rates.

EWR Income Tax Expense.Tax expense decreased due to lower pretax income in the third quarter of fiscal year 2006 compared to fiscal year 2005.

Nine Months Ended March 31, 2006 Compared to Nine Months Ended March 31, 2005

EWR Revenues and Gross Margins.Revenues decreased $3,088,000 from $18,160,000 in the nine months ended March 31, 2005 to $15,071,000 in the nine months ended March 31, 2006. The decreased revenues were due to $2,277,000 lower revenue from the sale of storage gas, $733,000 reduced gas revenue from lower volumes, reductions of $8,000 and $5,000 in production and electric revenue respectively, and a $247,000 change in the value of derivative contracts. These reductions were offset by $182,000 increase in amortization of the deferred gain. There were no material mark-to-market adjustments in the nine months ended March 31, 2006.

Margins decreased by $561,000 from $1,736,000 for the first nine months of fiscal year 2005 to $1,175,000 for the first nine months of fiscal year 2006. This is primarily due to a $595,000 decrease in gas margin due to lower sales volumes and higher gas prices and a $64,000 decrease in the valuation of derivative contracts and deferred gain. These decreases were offset by increases of $63,000 in production margin and $35,000 in electric margin.

EWR Operating Expenses.Operating expenses decreased approximately $421,000 during the nine months ended March 31, 2006 compared to the first nine months ended March 31, 2005. This decrease is due primarily to $215,000 reduction in outside services, $111,000 savings in salaries and benefits, $54,000 savings in various other general and administrative charges, and a $41,000 decrease in depletion and depreciation.

EWR Other Income. Other income was higher by $34,000 in fiscal year 2005 due to the settlement of a contract dispute in the nine months ended March 31, 2005.

EWR Interest Expense.Interest expense decreased $69,000 in the first nine months ended March 31, 2006 compared to the first nine months ended March 31, 2005 due to a decrease in short-term borrowings and amortization of debt issue costs.

EWR Income Tax Expense.Tax expense decreased due to lower pretax income.

Operating Results of our Pipeline Operations


	Three Months Ended						Nine Months Ended
	March 31,						March 31,
Pipeline Operations	2006			2005			2006			2005
Operating revenues	$	100,340		$	116,095		$	311,087		$	302,381
Gas Purchased		—			—			—			—

Gross Margin		100,340			116,095			311,087			302,381
Operating expenses		40,021			46,462			129,635			131,350

Operating income		60,319			69,633			181,452			171,031
Other income		—			—			—			—

Income before interest		60,319			69,633			181,452			171,031
and taxes
Interest expense		10,994			14,596			33,853			43,904

Income before income taxes		49,325			55,037			147,599			127,127
Income tax (expense)		(18,972	)		(23,598	)		(56,783	)		(52,348	)

Net income	$	30,353		$	31,439		$	90,816		$	74,779

Three Months Ended March 31, 2006 Compared to Three Months Ended March 31, 2005

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 decreased $16,000 due to a decrease in transportation flows.

Pipeline Operating Expenses. Operating expenses decreased by $6,000 due to cost savings measures.

Pipeline Interest Expense.Interest expense decreased due to a decrease in short-term borrowings partially offset by higher interest rates.

Pipeline Income Tax Expense.Tax expense decreased due to lower pretax income.

Nine Months Ended March 31, 2006 Compared to Nine Months Ended March 31, 2005

Pipeline Revenues and Gross Margins.Pipeline Operations’ margin increased $9,000 due to an increase in gathering volumes on the Glacier gathering line.

Pipeline Operating Expenses.Operating expense has remained constant in the nine months ending March 31, 2006 as compared to the nine months ending March 31, 2005.

Pipeline Interest Expense.Interest expense decreased due to lower short-term borrowings, and the reduction of amortization of debt issue costs in fiscal year 2006.

Pipeline Income Tax Expense.Tax expense increased due to a higher pretax income in the nine months ended March 31, 2006 compared to the nine months ended March 31, 2005.

Consolidated Cash Flow Analysis

Sources and Uses of Cash

Operating activities provide our primary source of cash. Cash provided by operating activities consist of net income 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 credit facility at LaSalle Bank, shown as line of credit on the accompanying balance sheet. Our use of the LaSalle credit facility decreased to $1,490,000 at March 31, 2006, compared with $3,500,000 at March 31, 2005. This $2,010,000 improvement reflects our generation of net income of $2,141,000 in the nine months ended March 31, 2006 as compared to net income of $1,631,000 in the nine months ended March 31, 2005, a $900,000 refund of income taxes collected from a carry back of net operating losses in prior years, a $1,240,000 increase in accounts receivable and a $1,584,000 increase in accounts payable. We finance our capital expenditures on an interim basis through this LaSalle credit facility.

Long-term debt decreased to $18,270,000 at March 31, 2006, compared with $19,333,000 at March 31, 2005. This $1,063,000 decrease resulted primarily from the scheduled principal payments of $480,000 on the Series 1993 notes, $95,000 on the Series 1992B notes and $400,000 on the term loan as provided for in the debt agreements.

Cash increased by $391,000 at March 31, 2006, from June 30, 2005, compared with the $341,000 decrease in cash for the nine months ended March 31, 2005, as shown in the following table:


	March 31,
	2006			2005
Provided by operating activities	$	5,009,019		$	1,584,692
Used in investing activities		(1,551,919	)		(2,038,378	)
Provided by (used in) financing activities		(3,065,676	)		113,053


Increase (decrease) in cash	$	391,424			($340,633	)

For the nine months ended March 31, 2006, cash provided by operating activities increased approximately $3,424,000 as compared to the nine months ended March 31, 2005. This was due to an increase in net income of $510,000, decrease in depreciation expense of $163,000, decrease in deferred income taxes of $204,000, decrease in accounts receivable of $834,000, a decrease in the value of derivative assets of $60,000, a decrease in gas inventories of $3,495,000, an increase in accounts payable of $2,084,000 an increase in derivative liabilities of $1,508,000, a decrease in deferred gain of $1,663,000, an increase in recoverable gas costs of $1,274,000, a decrease in prepaid items of $350,000, and an increase in cash used for other assets and liabilities of $4,111,000.

For the nine months ended March 31, 2006, cash used in investing activities decreased $487,000 as compared to the nine months ended March 31, 2005 due to a decrease in construction expense of $327,000, an increase in cash received from long term notes receivable of $175,000, a decrease of $46,000 in contribution in aid of construction, and an increase in customer advances of $34,000.

For the nine months ended March 31, 2006, cash used by financing activities increased by $3,179,000 as compared to the nine months ended March 31, 2005, due primarily to our ability to pay down the line of credit. We also had a short term borrowing of $3,500,000 in fiscal year 2005 which did not repeat in fiscal year 2006.

Liquidity and Capital Resources

Our operating working capital needs, as well as dividend payments and capital expenditures, are generally funded through cash flow from operating activities and short-term borrowing. 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 $15.0 to $20.0 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 March 31, 2006 had an outstanding balance of $5.2 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 of debt under the LaSalle credit facility.

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	$	5,200,000	$	0
Maximum borrowing	$	5,200,000	$	12,250,000	$	12,050,000
Average borrowing	$	4,167,000	$	9,489,000	$	5,619,000

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 Facility we may elect to pay interest on portions of the amounts outstanding under the revolving line of credit at the London interbank offered rate (LIBOR), plus 200 basis points or at the Prime Rate, for interest periods selected by us. For the $6.0 million term loan under the LaSalle Facility, we may elect to pay interest at either the applicable LIBOR

rate plus 300 basis points or at the Prime Rate. We also pay a commitment fee of 25 basis points for the daily unutilized portion of the revolving credit facility.

During the quarter ended September 30, 2004, we entered into an interest rate swap agreement related to the LaSalle Facility. The interest rate swap agreement converts a declining notional amount of variable rate debt to a fixed rate of 7.40%. The amortizing notional principal amount begins at $2,933,333 on August 9, 2004 and amortizes to $2,016,666 as of March 31, 2009. The effect of the interest rate swap, therefore, is to fix the rate of interest at 7.40% for that portion on the $6.0 million term loan under the LaSalle Facility.

The LaSalle 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. The LaSalle 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 March 31, 2006, we had approximately $500,000 of cash on hand. In addition, at March 31, 2006, we had borrowed $1.5 million under the revolving line of credit. Our short-term borrowings under our line of credit during the nine months ended March 31, 2006 had a daily weighted average interest rate of 7.46% per annum. Our net availability at March 31, 2006, was $13.5 million under the LaSalle Facility revolving line of credit.

In addition to the LaSalle 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 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, asset sales, and from incurring additional long-term indebtedness if it does not meet certain debt to interest and debt to capital ratios. Dividends and distributions during the period are limited to the cumulated net income for the prior sixty months. During the three months and nine months ended March 31, 2006, we were in compliance with all financial covenants.

The total amount outstanding under all of our long-term debt obligations was approximately $18.3 million and $22.3 million, at March 31, 2006 and March 31, 2005, respectively. The portion of such obligations due within one year was approximately $1,000,000 and $3,000,000 at March 31, 2006, and March 31, 2005, respectively.

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. Under SFAS No. 133 we have elected not to designate the swap as a 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 March 31, 2006. The fair value of the interest rate swap was $82,112 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)	$	6,285,024	$	1,038,453	$	1,939,455	$	1,825,516	$	1,481,600
Long Term Debt (b)		19,293,534		1,023,336		2,166,214		4,260,000		11,843,984
Operating Lease Obligations		223,498		103,618		119,880		—		—
Transportation and Storage Obligation (c)		16,735,086		1,091,929		8,544,997		7,098,160		—

Total Obligations	$	42,537,142	$	3,257,336	$	12,770,546	$	13,183,676	$	13,325,584

(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)		Transportation and Storage Obligations represent annual commitments with suppliers for periods extending up to four years. These costs are recoverable in customer rates.

Contracts Accounted for at Fair Value

Management of Risks Related to Derivatives.We are subject to certain risks related to changes in certain commodity prices and risks of counterparty performance. We have established policies and procedures to manage such risks. We have a Risk Management Committee (RMC), comprised of Company officers and management to oversee our 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 we 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.

We account for certain of such purchases or sale agreements in accordance with SFAS No. 133. Under SFAS 133, such contracts are reflected in our 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 our 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 are generally not available. Therefore, to determine the net present value of natural gas derivative contracts, we use internally developed valuation models that incorporate independently available current and forecasted pricing information.

As of March 31, 2006, these agreements were reflected on our consolidated balance sheet as derivative assets and liabilities at an approximate fair value as follows:


	Assets		Liabilities
Contracts maturing during fiscal year 2006	$	48,837	$	49,002
Contracts maturing during fiscal years 2007 and 2008		—		—
Contracts maturing during fiscal years 2009 and beyond		82,112		—

Total	$	130,949	$	49,002

Regulated Operations. In the case of our 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.

We are 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

We seek to protect our company 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 we 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.

Interest Rate Risk

Our results of operations are affected by fluctuations in interest rates (e.g. interest expense on debt). We mitigate 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 $80,000 annually.

Credit Risk

Credit risk relates to the risk of loss that the we would incur as a result of non-performance by counterparties of their contractual obligations under the various instruments with our 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. We seek 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 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

10		Amendment to Employment Agreement entered into as of January 5, 2006, between Energy West, Inc. and David Cerotzke

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.


May 15, 2006	ENERGY WEST, INCORPORATED
	/s/ Wade F. Brooksby
	Wade F. Brooksby
	Chief Financial Officer (principal financial officer and principal accounting officer)

Index to Exhibits


Exhibit
Number		Description

10		Amendment to Employment Agreement entered into as of January 5, 2006, between Energy West, Inc. and David Cerotzke

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

Positive
Negative
Uncertain
Constraining
Legalese
Litigous
Readability	H.S. freshman Avg

Gas Natural Inactive 10-Q2006 Q1 Quarterly report

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