Gas Natural 10Q 2006 Q4 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 December 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		81-0141785
(State or other jurisdiction of		(I.R.S. Employer
incorporation or organization)		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 filero Non-accelerated filerþ

Indicate by check mark 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 registrant’s common stock as of February 5, 2007 was 2,989,452 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 December 31, 2006, December 31, 2005 and June 30, 2006		2

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

Condensed Consolidated Statements of Cash Flows (unaudited) - six months ended December 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		12

Item 3 – Quantitative and Qualitative Disclosures about Market Risk		25

Item 4 – Controls and Procedures		26

Part II – Other Information

Item 4 – Submission of Matters to a Vote of Security Holders		27

Item 6 – Exhibits		27

Signatures
EX-31
EX-32

Part I — FINANCIAL INFORMATION

Item 1 — Financial Statements

ENERGY WEST INCORPORATED AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS, DECEMBER 31, 2006 AND 2005, AND JUNE 30, 2006


	December 31,				June 30,
	2006		2005		2006
ASSETS

Current Assets:
Cash	$	1,039,846	$	1,077,084	$	1,639,578
Accounts and notes receivable less $228,279, $363,613 and $142,372, respectively, allowance for bad debt		7,316,614		10,789,385		4,162,851
Unbilled gas		3,093,313		4,530,377		1,020,540
Derivative assets		117,617		336,864		137,865
Natural gas and propane inventories		7,984,993		8,613,129		5,424,778
Materials and supplies		566,086		506,755		455,228
Prepayments and other		462,806		403,112		290,860
Deferred income taxes		221,088		33,563		—
Income tax receivable		—		313,344		—
Recoverable cost of gas purchases		1,268,227		1,569,299		1,323,442

Total current assets		22,070,590		28,172,912		14,455,142

Property, Plant and Equipment, Net		39,682,377		38,922,268		39,104,060
Deferred Charges		3,817,757		4,419,970		4,214,178
Other Assets		341,791		163,476		157,365

*TOTAL ASSETS*	$	65,912,515	$	71,678,626	$	57,930,745


LIABILITIES AND CAPITALIZATION

Current Liabilities:
Current portion of long-term debt	$	1,061,509	$	1,056,633	$	1,058,213
Line of credit		5,050,000		11,000,000		—
Accounts payable		5,658,871		7,513,971		3,592,260
Derivative liabilities		60,582		277,742		42,664
Accrued income taxes		—		—		1,320,431
Deferred income taxes		—		—		269,163
Accrued and other current liabilities		5,243,322		3,921,701		3,860,302

Total current liabilities		17,074,284		23,770,047		10,143,033


Other Obligations:
Deferred income taxes		6,293,307		6,276,632		5,835,886
Deferred investment tax credits		281,689		302,751		292,220
Other long-term liabilities		5,141,534		5,255,737		4,889,493

Total		11,716,530		11,835,120		11,017,599

Long-Term Debt		17,318,333		18,370,493		17,605,000


Commitments and Contingencies

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, 2,959,177, 2,930,100 and 2,934,177 shares outstanding at December 31, 2006 and 2005, and June 30, 2006 respectively		443,876		439,522		440,127
Capital in excess of par value		7,842,862		7,578,531		7,634,337
Retained earnings		11,516,630		9,684,913		11,090,649

Total stockholders’ equity		19,803,368		17,702,966		19,165,113

TOTAL CAPITALIZATION		37,121,701		36,073,459		36,770,113

*TOTAL LIABILITIES AND CAPITALIZATION*	$	65,912,515	$	71,678,626	$	57,930,745

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						Six Months Ended
	December 31,						December 31,
	2006			2005			2006			2005
REVENUES:
Natural gas operations	$	14,576,541		$	20,187,548		$	20,325,889		$	26,502,915
Propane operations		3,276,628			2,530,948			4,450,492			3,528,930
Gas and electric—wholesale		3,364,979			6,108,052			5,972,588			8,977,884
Pipeline operations		99,753			102,539			199,191			210,747

Total revenues		21,317,901			28,929,087			30,948,160			39,220,476


EXPENSES:
Gas purchased		12,982,696			17,898,558			17,262,460			22,786,407
Gas and electric—wholesale		2,768,762			5,722,196			4,919,561			8,463,665
Distribution, general, and administrative		2,021,561			2,063,994			4,077,329			4,282,780
Maintenance		142,829			125,678			283,017			273,570
Depreciation and amortization		542,079			528,698			1,092,271			1,103,075
Taxes other than income		383,556			412,388			750,864			775,025

Total expenses		18,841,483			26,751,512			28,385,502			37,684,522


OPERATING INCOME		2,476,418			2,177,575			2,562,658			1,535,954

OTHER INCOME		97,275			208,133			175,488			319,155

INTEREST (EXPENSE)		(546,848	)		(596,041	)		(1,022,885	)		(1,089,455	)


INCOME BEFORE INCOME TAXES		2,026,845			1,789,667			1,715,261			765,654

INCOME TAX (EXPENSE)		(757,100	)		(672,563	)		(640,024	)		(270,123	)


NET INCOME	$	1,269,745		$	1,117,104		$	1,075,237		$	495,531


INCOME PER COMMON SHARE:
Basic	$	0.43		$	0.38		$	0.36		$	0.17
Diluted	$	0.43		$	0.38		$	0.36		$	0.17

WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:
Basic		2,952,721			2,921,129			2,946,131			2,916,846
Diluted		2,985,672			2,968,504			2,978,512			2,941,665

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)


	Six Months Ended
	December 31,
	2006			2005
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	1,075,237		$	495,531
Adjustments to reconcile net income to net cash used in operating activities:
Depreciation and amortization, including deferred charges and financing costs		1,418,870			1,442,509
Derivative assets		20,248			(217,795	)
Derivative liabilities		17,918			163,505
Deferred gain		(325,582	)		(522,521	)
Investment tax credit		(10,531	)		(10,531	)
Deferred gain on sale of assets		—			(11,814	)
Deferred income taxes		(32,830	)		468,054
Changes in assets and liabilities:
Accounts receivable		(6,070,880	)		(7,525,993	)
Natural gas and propane inventories		(2,560,216	)		(4,902,096	)
Accounts payable		2,066,612			4,403,114
Recoverable/refundable cost of gas purchases		55,215			294,176
Prepayments and other		(171,946	)		(16,807	)
Other assets & liabilities		741,468			1,045,601

Net cash used in operating activities		(3,776,417	)		(4,895,067	)


CASH FLOWS FROM INVESTING ACTIVITIES:
Construction expenditures		(1,348,117	)		(1,137,701	)
Collection of long-term notes receivable		—			174,561
Customer advances received for construction		195,152			97,296
Increase from contributions in aid of construction		—			21,981

Net cash used in investing activities		(1,152,965	)		(843,863	)


CASH FLOWS FROM FINANCING ACTIVITIES:
Repayments of long-term debt		(283,371	)		(263,160	)
Proceeds from lines of credit		6,100,000			10,000,000
Repayments of lines of credit		(1,050,000	)		(2,900,000	)
Proceeds from other short-term borrowings		212,275			—
Dividends paid		(649,254	)		(114,432	)

Net cash provided by financing activities		4,329,650			6,722,408

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		(599,732	)		983,478

CASH AND CASH EQUIVALENTS:
Beginning of period		1,639,578			93,606

End of period	$	1,039,846		$	1,077,084

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

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

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 six month periods ended December 31, 2006 are not necessarily indicative of the results that may be expected for the fiscal year ending June 30, 2007. 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, 2006.

Energy West, Incorporated is a regulated public utility, with certain non-regulated, non-utility operations conducted through three wholly owned subsidiaries: Energy West Resources, Inc. (“EWR”); Energy West Development, Inc. (“EWD”); and Energy West Propane, Inc. (“EWP”). EWR markets natural 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. EWP is engaged in wholesale and retail distribution of bulk propane in Arizona. In July 2006, the Company entered into an agreement to sell its Arizona propane operations. See Note 3.

The Company’s reporting segments are: Natural Gas Operations, Propane Operations, EWR and Pipeline Operations. EWD operates an interstate natural gas transmission pipeline. 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.

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 six months of fiscal 2007, 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 December 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 2007	$	60,412	$	60,582
Contracts maturing during fiscal years 2008 and 2009		57,205
Contracts maturing during fiscal years 2010 and beyond		—		—

Total	$	117,617	$	60,582

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 December 31, 2006, the Company’s regulated operations have no contracts meeting the mark-to-market accounting requirements.

NOTE 2 – INCOME TAX EXPENSES (BENEFITS)

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


	Three Months Ended						Six Months Ended
	December 31,						December 31,
	2006			2005			2006			2005
Tax expense at statutory rate of 35%	$	709,396		$	626,381		$	600,341		$	267,977
State income tax expense, net of federal tax expense		45,584			51,768			38,576			12,615
Amortization of deferred investment tax credits		(5,265	)		(5,265	)		(10,531	)		(10,531	)
Other		7,385			(321	)		11,638			62


Total income tax expense	$	757,100		$	672,563		$	640,024		$	270,123

NOTE 3 — LINES OF CREDIT AND LONG-TERM DEBT

We fund our operating cash needs, as well as dividend payments and capital expenditures, primarily through cash flow from operating activities and short-term borrowing. Historically, to the extent cash flow has not been sufficient to fund these expenditures, we have used the working capital line of credit portion of our credit facility with LaSalle Bank pursuant to the Amended and Restated Credit Agreement dated as of March 31, 2004 (collectively with all subsequent amendments and ancillary documents thereto, the “LaSalle Credit Facility”). 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.

Effective November 27, 2006, our company and LaSalle Bank extended and amended the LaSalle Credit Facility pursuant to the Reaffirmation and Sixth Amendment to Amended and Restated Credit Agreement dated as of

November 27, 2007 (the Sixth Amendment”). The Sixth Amendment provides for (i) an extension of the revolving line of credit until November 26, 2007; (ii) an increase in the commitment amount of the revolving line of credit from $15 million to $20 million; and (iii) a reduction in the interest rate calculations that we currently use for the term loan and line of credit under the LaSalle Credit Facility.

At December 31, 2006, the Company had approximately $1,040,000 of cash on hand. In addition, at December 31, 2006, the Company had borrowed approximately $5.05 million under the LaSalle Credit Facility revolving line of credit. The Company’s short-term borrowings under its lines of credit during the six months ended December 31, 2006 had a daily weighted average interest rate of 8.63% per annum. The Company’s net availability at December 31, 2006, was approximately $14.95 million under the LaSalle Credit Facility revolving line of credit.

The total amount outstanding under all of the Company’s long-term debt obligations was approximately $18.4 million and $19.4 million at December 31, 2006, and December 31, 2005, respectively. The portion of such obligations due within one year was approximately $1,062,000 and $1,057,000 at December 31, 2006, and December 31, 2005, respectively. At December 31, 2006 and 2005, we were in compliance with the financial covenants under the LaSalle Credit Facility and the Long Term Notes and Bonds.

On July 17, 2006, we entered into an Asset Purchase Agreement among our company, EWP, and SemStream, L.P. Pursuant to the Asset Purchase Agreement, our company and EWP agreed to sell, and SemStream agreed to buy, (i) all of the assets and business operations associated with our regulated propane gas distribution system operated in the cities and outlying areas of Payson, Pine, and Strawberry, Arizona (the “Regulated Business”), and (ii) all of the assets and business operations of EWP that are associated with certain “non-regulated” propane assets (the “Non-Regulated Business,” and together with the Regulated Business, the “Business”).

SemStream is purchasing only the assets and business operations of our Company and EWP that solely pertain to the Business within the state of Arizona, and that solely pertain to the Energy West Propane – Arizona division of our company and/or EWP (collectively, the “Arizona Assets”). Pursuant to the Asset Purchase Agreement, SemStream will pay a cash purchase price of $15 million for the Arizona Assets, subject to final working capital adjustments.

The sale is conditioned on approval by the Arizona Corporation Commission, or “ACC”. The sale will close the first day of the month after the receipt of ACC approval. We cannot predict with certainty whether or when the closing conditions will be satisfied or whether or when this transaction will be consummated. We plan to use the proceeds from this transaction to reduce our outstanding debt and strengthen our balance sheet. We believe that this will enable our company to take advantage of opportunities to enhance or expand our existing operations and to acquire additional businesses or assets on favorable terms as and when those opportunities arise.

NOTE 4 — DEFERRED CHARGES

Deferred Charges consist of the following:


	December 31,				June 30,
	2006		2005		2006
Regulatory asset for property taxes	$	2,186,862	$	2,419,169	$	2,303,015
Regulatory asset for income taxes		458,753		458,753		458,753
Regulatory asset for deferred environmental remediation costs		287,708		385,978		334,996
Other regulatory assets		17,953		40,249		126,263
Unamortized debt issue costs		866,481		1,115,821		991,151


Total	$	3,817,757	$	4,419,970	$	4,214,178

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

The income taxes and environmental remediation costs earn a return equal to that of the Company’s rate base. The property tax asset does not earn a return but is recovered in rates over a ten-year period starting January 1, 2004. No other regulatory assets from the schedule above earn a return or are recovered in the rate structure. Other regulatory assets include rate case costs to be amortized over the period approved by the appropriate regulatory agency.

NOTE 5 — 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 a storage location for certain equipment and materials. The coal gasification process utilized in the plant resulted in the production of certain by-products which have been classified by the federal government and the State of Montana as hazardous to the environment.

The Company has completed its remediation of soil contaminants and in April of 2002 received a closure letter from the Montana Department of Environmental Quality (“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 December 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 December 31, 2006, the Company had recovered approximately $1,675,000 through such surcharges, and the cost remaining to be recovered is $288,000. 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 non-performance 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—We are party to certain legal proceedings in the normal course of our business that, in the opinion of management, are not material to our business or financial condition.

NOTE 6 — SEGMENTS OF OPERATIONS


	Three Months Ended				Six Months Ended
	December 31				December 31
	2006		2005		2006			2005
Gross margin (operating revenue less cost of gas sold):
Natural gas operations	$	3,853,052	$	3,740,347	$	6,052,356		$	5,718,628
Propane operations		1,017,421		1,079,591		1,461,565			1,526,810
EWR		596,217		385,856		1,053,027			514,219
Pipeline operations		99,753		102,539		199,191			210,747

		5,566,443		5,308,333		8,766,139			7,970,404


Operating income:
Natural gas operations		1,609,038		1,442,599		1,549,037			1,137,146
Propane operations		355,806		413,699		106,100			161,982
EWR		480,873		261,839		817,073			115,693
Pipeline operations		30,701		59,438		90,448			121,133

		2,476,418		2,177,575		2,562,658			1,535,954


Net income (loss):
Natural gas operations		828,719		765,320		623,944			417,283
Propane operations		157,392		189,962		(48,231	)		(5,451	)
EWR		271,280		132,755		455,457			23,236
Pipeline operations		12,354		29,067		44,067			60,463

	$	1,269,745	$	1,117,104	$	1,075,237		$	495,531

NOTE 7 — ACCRUED AND OTHER CURRENT LIABILITIES

Accrued and other current liabilities consists of the following:


	December 31,				June 30,
	2006		2005		2006
Property tax settlement—current portion	$	243,000	$	243,000	$	243,000
Payable to employee benefit plans		130,748		114,713		275,377
Accrued vacation		264,525		265,513		258,831
Customer deposits		496,298		479,985		465,188
Accrued interest		160,668		164,670		140,648
Accrued taxes other than income		593,132		230,971		467,947
Deferred short-term gain		243,519		639,165		243,519
Customer prepayments from levelized billing		1,439,877		909,561		844,344
Other		1,671,555		874,123		921,448

Total	$	5,243,322	$	3,921,701	$	3,860,302

NOTE 8 — OTHER LONG TERM LIABILITIES

Other long-term liabilities consist of the following:


	December 31,				June 30,
	2006		2005		2006
Asset retirement obligation	$	668,663	$	634,595	$	650,717
Contribution in aid of construction		2,354,682		1,469,429		1,954,980
Customer advances for construction		472,997		775,233		277,845
Accumulated postretirement obligation		144,201		377,145		139,200
Deferred gain — long-term *		202,822		446,341		325,582
Deferred gain on sale leaseback of assets		—		11,825		—
Regulatory liability for income taxes		83,161		83,161		83,161
Property tax settlement		1,215,008		1,458,008		1,458,008

Total	$	5,141,534	$	5,255,737	$	4,889,493


*		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 9 – STOCK OPTIONS AND SHAREHOLDER RIGHTS PLANS

2002 Stock Option Plan— The Energy West Incorporated 2002 Stock Option Plan (the “Option Plan”) provides for the issuance of up to 200,000 shares of our common stock to be issued to certain key employees. As of December 31, 2006, there are 150,500 options outstanding, 27,500 shares issued under this plan have been exercised, and the maximum number of shares available for future grants under this plan is 22,000 shares. Under the Option Plan, the option price may not be less than 100% of the common stock fair market value on the date of grant (in the event of incentive stock options, 110% of the fair market value if the employee owns more than 10% of our outstanding common stock). Pursuant to the Option Plan, the options vest over four to five years and are exercisable over a five to ten-year period from date of issuance.

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 quarter ended December 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 first six months of fiscal 2007 was approximately $38,045, or approximately $0.01 per share.

The fair value of each option grant is estimated on the date of grant using the Black-Scholes option pricing model with the following weighted average assumptions for the quarter ended December 2006: 2% expected dividend rate, expected dividends at $.46 per year, volatility of 32%, a risk-free interest rate of 5.0%; and expected lives of four to ten years. A summary of the status of our stock option plans as of December 31, 2006 and changes during the first two quarters ended December 31, 2006 is presented below.


				Weighted
	Number of			Average
	Shares			Exercise Price
Outstanding June 30, 2006		145,500		$	8.34
Granted		30,000		$	10.55
Exercised		(25,000	)	$	8.49
Expired		—			—


Outstanding December 31, 2006		150,500		$	8.76

The following information applies to options outstanding at December 31, 2006:


			Weighted
			Average
			Remaining				Weighted
			Contractual				Average
Grant	Number		Life		Number		Exercise
Date	Outstanding		(Years)		Exercisable		Price
11/21/2002		23,500		0.9		23,500	$	8.49
7/1/2004		30,000		7.5		22,500	$	6.47
4/1/2005		20,000		8.3		10,000	$	6.62
7/1/2005		20,000		8.5		10,000	$	9.85
10/4/2005		22,000		8.8		11,000	$	10.51
1/6/2006		5,000		4.0		—	$	9.52
7/1/2006		10,000		9.5		2,500	$	9.02
12/4/2006		20,000		9.9		2,500	$	11.32


		150,500				82,000

NOTE 9 — SUBSEQUENT EVENTS

On January 30, 2007, the Company entered into two stock purchase agreements (together, the “Purchase Agreements”) between the Company and Sempra Energy. Pursuant to the Purchase Agreements, the Company will acquire all of the capital stock of two of Sempra’s wholly owned subsidiaries, Frontier Utilities of North Carolina, Inc. and Penobscot Natural Gas Company, Inc. Frontier Utilities is the parent company of its operating subsidiary, Frontier Energy, LLC, and Penobscot Natural Gas is the parent company of its operating subsidiary, Bangor Gas Company LLC. The aggregate purchase price to be paid by the Company for the two companies in $5.0 million, subject to adjustment for working capital items.

The acquisition of Frontier Utilities is conditioned upon approval by the North Carolina Utilities Commission (“NCUC”), and the acquisition of Penobscot Natural Gas is conditioned upon approval by the Maine Public Utilities Commission (“MPUC”). Both acquisitions are also conditioned upon the receipt of certain other approvals from third parties. Each acquisition will close on the tenth business day after all closing conditions have been satisfied,

including either NCUC or MPUC approval, as the case may be, which are estimated to require approximately four months to one year to be obtained.

The Purchase Agreements contain representations and warranties, covenants, indemnifications, and conditions to closing that are customary for transactions of this type. The final purchase prices to be paid at closing are subject to adjustments, customary for transactions of this nature, pursuant to the terms of the Purchase Agreements.

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

This quarterly report on Form 10-Q contains 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 company’s expectations or beliefs concerning future events. Forward-looking statements generally include words such as “anticipates,” “believes,” “expects,” “planned,” “scheduled” or similar expressions and statements. Our operating capital requirements, 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 our 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 our company from time to time, including statements contained in filings with the Securities and Exchange Commission and its reports to shareholders, involve known and unknown risks and other factors that may cause our 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, 2006 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 the company except as required by law.

OPERATING RESULTS OF OUR COMPANY

Executive Overview

Energy West has operated natural gas distribution businesses since 1909, which are still our primary source of revenue. Our focus is on smaller and emerging utility markets. We are located in a region of active natural gas production and have been able to expand our operations and income through “unregulated” subsidiaries in gas acquisition, marketing, and transportation. We believe that our experience and reputation in the utility business gives us an advantage in finding unique opportunities in the unregulated sector.

By focusing on our core businesses we have been able to increase efficiency in our regulated operations and develop attractive projects that now are yielding increased income and dividends for shareholders. The net income for the fiscal quarter ended December 31, 2006 improved 14% over the net income for the same period last year, with a 118% increase in our year-to-date earnings. Our strong balance sheet also allows us to pursue a wider range of attractive opportunities for growth, such as the recently announced acquisition of utilities serving Bangor, Maine and six counties in North Carolina.

We sought to mitigate the effect of higher commodity prices through increased use of both underground storage and our pipeline network. Our utility business concentrated on enhancing productivity in our operations and reducing our general, administrative, and overhead expenses as well as our interest expense. Our improved profitability has afforded us the opportunity to keep rates to our customers low and to increase the dividend payments to our shareholders since resuming dividend payments in October 2005.

In July 2006, we entered into an agreement to sell certain of our assets related to our Arizona propane business for cash of approximately $15.0 million plus net working capital. Although we cannot predict with certainty the regulatory process, we anticipate approval of the sale by the ACC sometime in the third quarter of fiscal 2007. We plan to use the proceeds from this transaction to reduce our outstanding debt and strengthen our balance sheet. We believe that this will enable our company to take advantage of opportunities to enhance or expand our existing operations and to acquire additional businesses or assets on favorable terms as and when those opportunities arise.

Strategy

The key elements of our current strategy include the following:

	•		Focus on the growing natural gas distribution business in areas that fit our core strengths in smaller and emerging markets.

	•		Acquire additional gas production, gathering, and pipeline assets or operations, which provide higher operating margins than our regulated business operations.

	•		Pursue appropriate regulatory treatment of higher commodity prices.

	•		Seek cost-effective expansion of our customer base by prudently managing capital expenditures and ensuring that new customers provide sufficient margins for an appropriate return on the additional resources and investment required to serve the customers.

	•		Continue to focus on operational efficiencies.

	•		Manage cash flow to reduce our existing debt or avoid additional debt financing.

	•		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.

In summary, in future periods we intend to maintain the increased earnings that we have built during the last two years and we will continue to sharpen our focus on opportunities and strategies that improve shareholder value.

QUARTERLY RESULTS OF CONSOLIDATED OPERATIONS

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

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, 2006. The following gives effect to the unaudited Condensed Consolidated Financial Statements as of December 31, 2006 and for the three month period ended December 31, 2006. Results of operations for interim periods are not necessarily indicative of results to be attained for any future period.

Net Income— The Company’s net income for the quarter ended December 31, 2006 was approximately $1,270,000 compared to a net income of approximately $1,117,000 in the quarter ended December 31, 2005, an increase of $153,000. This increase was primarily due to higher gross margins in Natural Gas and EWR, lower operating expenses in all segments except Pipeline, and a decrease in interest expense. The increases in gross margin for Natural Gas and EWR and the reductions in expenses were partially offset by a decrease in gross margin in Propane Operations, lower other income in all segments, and an increase in income tax expense due to higher pretax income.

Revenues— The Company’s revenues for the quarter ended December 31, 2006 were approximately $21,318,000 compared to approximately $28,929,000 in the quarter ended December 31, 2005, a decrease of $7,611,000. The decrease was primarily attributable to: (1) natural gas revenue decreases of $5,611,000 due to lower prices for natural gas passed through to customers; and (2) EWR revenue decreases of $2,743,000 due to a decrease in the valuation of derivative contracts, much lower index prices and the loss of two large customers. These decreases in revenue were offset by an increase in revenue of $746,000 for the propane segment due to higher propane prices and a surcharge for the recovery of under-collected gas costs put into effect July 1, 2006.

Gross Margin— Gross margin, which is defined as revenue less gas purchased and gas and electricity-wholesale, increased $258,000, from approximately $5,308,000 in the quarter ended December 31, 2005 to approximately $5,566,000 in the quarter ended December 31, 2006.

EWR gross margin increased $210,000 due to new business in our Wyoming market and the renegotiation of expiring contracts on more favorable terms, offset by a decrease in mark-to-market revenue and the loss of two large customers. Natural Gas Operations’ gross margin increased $113,000 primarily due to a higher basic charge, an increase in the MPSC allowed recovery of inventory costs, and higher volumes to traditional customers due to colder weather. Propane Operations’ gross margin decreased $62,000 primarily due to warmer weather and higher propane prices in the unregulated operations.

Expenses Other Than Costs of Gas and Electricity and Costs of Goods Sold— Expenses other than gas purchased decreased approximately $41,000 in the quarter ended December 31, 2006 as compared to the quarter ended December 31, 2005. The reasons for this decrease were (1) decreases in the Company’s general and administrative costs of $69,000, and (2) decreases in taxes other than income taxes of $29,000, offset by (3) increases in overhead, maintenance and depreciation of $27,000, $17,000 and $13,000 respectively.

Other Income— Other income decreased by $111,000, from approximately $208,000 in the quarter ended December 31, 2005 to approximately $97,000 in the quarter ended December 31, 2006. Natural Gas other income decreased $93,000 primarily due to service sales and other miscellaneous income in fiscal 2006 not repeated in fiscal 2007. Propane other income decreased $10,000 and EWR other income decreased $8,000 due to income from the settlement of a contract dispute in fiscal 2006.

Interest Expense— Interest expense decreased by approximately $49,000 during the quarter ended December 31, 2006 from the quarter ended December 31, 2005 due to lower short-term borrowings.

Income Tax Expense— Income tax expense increased approximately $85,000 in the quarter ended December 31, 2006 as compared to the quarter ended December 31, 2005 due to increased net income.

Six Months Ended December 31, 2006 Compared To Six Months Ended December 31, 2005

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, 2006. The following gives effect to the unaudited Condensed Consolidated Financial Statements as of December 31, 2006 and for the six month period ended December 31, 2006. Results of operations for interim periods are not necessarily indicative of results to be attained for any future period.

Net Income— The Company’s net income for the six months ended December 31, 2006 was approximately $1,075,000 compared to net income of approximately $496,000 for the six months ended December 31, 2005, an increase of $580,000. The increase in the Company’s net income was primarily due to higher gross margins in Natural Gas and EWR, lower operating expenses in all segments except EWD, and a decrease in interest expense. The increases in gross margin and the reductions in expenses were partially offset by (1) an increase in income tax expense due to higher pretax income, and (2) lower other income.

Revenues— The Company’s revenues for the six months ended December 31, 2006 were approximately $30,948,000 compared to approximately $39,220,000 in the six months ended December 31, 2005, a decrease of $8,272,000. The decrease was primarily attributable to natural gas revenue decreases of $6,177,000 due to lower prices for natural gas passed through to customers and lower EWR revenue of $3,005,000 due to a decrease in the valuation of derivative contracts, much lower index prices and the loss of two large customers. Revenues also reflect an increase of $922,000 in the Propane segment due to higher propane prices, and a surcharge for the recovery of under-collected gas costs put into effect July 1, 2006.

Gross Margin— Gross margin increased $796,000, from approximately $7,970,000 in the six months ended December 31, 2005 to approximately $8,766,000 in the six months ended December 31, 2006. EWR’s gross margin

increased $539,000 due to new business in our Wyoming market and the renegotiation of expiring contracts on more favorable terms, offset by a decrease in mark-to-market revenue and the loss of two large customers.

Pipeline Operations’ gross margin decreased approximately $12,000 due to a decrease in volumes on the Glacier gathering line. Natural Gas Operations’ gross margin increased $334,000 primarily due to higher basic charges, an increase in the MPSC allowed recovery of inventory costs, and higher volumes to traditional customers due to colder weather. Propane Operations’ gross margin decreased $65,000 primarily due to warmer weather and higher propane costs in the non-regulated propane operations, as well as reduced sales to external customers through Rocky Mountain Fuels.

Expenses Other Than Costs of Gas and Electricity and Costs of Goods Sold— Expenses other than gas purchased decreased approximately $231,000 in the six months ended December 31, 2006 as compared to the six months ended December 31, 2005. The primary reasons for this decrease were (1) decreases in the Company’s general and administrative costs of $331,000, (2) decreases in depreciation and amortization of $11,000, and (3) decreases in taxes other than income taxes of $24,000, offset by (4) increases in overhead and maintenance of $126,000 and $9,000, respectively.

Other Income— Other income decreased by $144,000, from approximately $319,000 in the six months ended December 31, 2005 to approximately $175,000 in the six months ended December 31, 2006. Natural Gas other income decreased $98,000 primarily due to service sales and other miscellaneous income in fiscal 2006 not repeated in fiscal 2007. Propane other income decreased $24,000 and EWR other income decreased $23,000 due to income generated from settlement of a contract dispute during the six months ended December 31, 2005.

Interest Expense— Interest expense decreased approximately $66,000 during the six months ended December 31, 2006 from the six months ended December 31, 2005 due to lower short-term borrowings.

Income Tax Expense— Income tax expense increased approximately $370,000 in the six months ended December 31, 2006 as compared to the six months ended December 31, 2005 due to increased pretax income in the current fiscal year.

Operating Results of our Natural Gas Operations


	Three Months Ended						Six Months Ended
	December 31,						December 31,
Natural Gas Operations	2006			2005			2006			2005
Operating revenues	$	14,576,541		$	20,187,548		$	20,325,889		$	26,502,915
Gas purchased		10,723,489			16,447,201			14,273,533			20,784,287

Gross margin		3,853,052			3,740,347			6,052,356			5,718,628
Operating expenses		2,244,014			2,297,748			4,503,319			4,581,482

Operating income		1,609,038			1,442,599			1,549,037			1,137,146
Other income		77,402			170,164			138,368			235,943


Income before interest and taxes		1,686,440			1,612,763			1,687,405			1,373,089

Interest (expense)		(379,041	)		(401,449	)		(710,652	)		(730,610	)


Income before income taxes		1,307,399			1,211,314			976,753			642,479
Income tax (expense)		(478,680	)		(445,994	)		(352,809	)		(225,196	)


Net income	$	828,719		$	765,320		$	623,944		$	417,283

Three Months Ended December 31, 2006 Compared To Three Months Ended December 31, 2005

Natural Gas Revenues and Gross Margins— The Natural Gas Operations’ operating revenues in the quarter ended December 31, 2006 decreased to approximately $14,577,000 from approximately $20,188,000 in the quarter ended December 31, 2005. This $5,611,000 decrease was primarily due to lower gas costs passed through to customers.

Gas purchases in Natural Gas Operations decreased by $5,723,000, from approximately $16,447,000 in the quarter ended December 31, 2005 to approximately $10,723,000 in the quarter ended December 31, 2006. The decrease in gas cost reflects lower commodity prices during the current fiscal year.

Gross margin was approximately $3,853,000 for the quarter ended December 31, 2006 compared to approximately $3,740,000 in the quarter ended December 31, 2005. The increase of $113,000 is due to (1) a $53,000 increase in the MPSC allowed recovery of inventory costs, (2) a 1% increase in customers resulting in a $13,000 increase in basic charge, and (3) higher margins on traditional customers due to colder weather. Although total volumes were 1.4% lower this quarter than the same quarter last year, sales to lower margin customers decreased, and sales to higher margin customers increased.

Natural Gas Operating Expenses— Natural Gas Segment’s operating expenses were approximately $2,244,000 for the quarter ended December 31, 2006 as compared to approximately $2,298,000 for quarter ended December 31, 2005. The $54,000 reduction is due to a $111,000 decrease in payroll and other general and administrative expenses resulting from the implementation of cost-saving measures, and $31,000 in lower taxes other than income taxes. These savings were offset by increased depreciation charges of $13,000, increased overhead charges of $65,000 and increased maintenance charges of $10,000. During the current fiscal year, a severance package resulted in the shifting of salary expense to overhead expense.

Natural Gas Other Income— Other income decreased by $93,000, from approximately $170,000 in the quarter ended December 31, 2005 to approximately $77,000 in the quarter ended December 31, 2006. This was due primarily to service sales and other miscellaneous income in fiscal 2006 that were not repeated in fiscal 2007.

Natural Gas Interest Expense— Interest expense is approximately $22,000 lower in the current year second quarter compared to prior year second quarter primarily due to lower short-term borrowings.

Natural Gas Income Tax Expense— Tax expense is approximately $33,000 higher in the current year second quarter compared to prior year second quarter due to higher pretax income.

Six Months Ended December 31, 2006 Compared to Six Months Ended December 31, 2005

Natural Gas Revenues and Gross Margins— The Natural Gas Operations’ operating revenues in the six months ended December 31, 2006 decreased to approximately $20,326,000 from approximately $26,503,000 in the six months ended December 31, 2005. This $6,177,000 decrease was primarily due to lower gas costs passed through to customers during the current fiscal year.

Gas purchases in Natural Gas Operations decreased by $6,511,000, from approximately $20,784,000 in the six months ended December 31, 2005 to approximately $14,274,000 in the six months ended December 31, 2005. The decrease in gas cost reflects lower commodity prices during the current fiscal year.

Gross margin was approximately $6,052,000 for the six months ended December 31, 2006 compared to approximately $5,719,000 in the six months ended December 31, 2005. The increase of $334,000 is primarily due to a $130,000 increase in the MPSC allowed recovery of inventory costs, a $155,000 increase in basic charge from the restructuring of rates, and higher margins on traditional customers due to colder weather. Although total volumes were 3.6% lower this year than last year, sales to lower margin customers decreased, and sales to higher margin customers increased in the current fiscal year.

Natural Gas Operating Expenses— Natural Gas Segment’s operating expenses were approximately $4,503,000 for the six months ended December 31, 2006 as compared to approximately $4,581,000 for the six months ended December 31, 2005. The $78,000 reduction is due to a $215,000 decrease in payroll and other general and

administrative expenses resulting from the implementation of cost-saving measures, and $22,000 in lower taxes other than income taxes. These savings were partially offset by increases of $136,000, $7,000 and $16,000 in overhead, maintenance and depreciation expenses, respectively.

Natural Gas Other Income— Other income decreased by $98,000, from approximately $236,000 in the six months ended December 31, 2005 to approximately $138,000 in the six months ended December 31, 2006. This was due primarily to service sales in Great Falls and other miscellaneous income in fiscal 2006 that were not repeated in fiscal 2007.

Natural Gas Interest Expense— Interest expense is approximately $20,000 lower in the six months ended December 31, 2006 compared to the six months ended December 31, 2005 primarily due to lower short-term borrowings.

Natural Gas Income Tax Expense— Tax expense increased approximately $128,000 in the six months ended December 31, 2006 compared to the six months ended December 31, 2005 due to higher pretax income.

Operating Results of our Propane Operations


	Three Months Ended						Six Months Ended
	December 31,						December 31,
Propane Operations	2006			2005			2006			2005
Operating revenues	$	3,276,628		$	2,530,948		$	4,450,492		$	3,528,930
Gas purchased		2,259,207			1,451,357			2,988,927			2,002,120

Gross margin		1,017,421			1,079,591			1,461,565			1,526,810
Operating expenses		661,615			665,892			1,355,465			1,364,828

Operating income		355,806			413,699			106,100			161,982
Other income		19,893			29,719			37,140			60,813


Income before interest and taxes		375,699			443,418			143,240			222,795

Interest (expense)		(120,134	)		(128,547	)		(220,663	)		(235,153	)


Income (loss) before income taxes		255,565			314,871			(77,423	)		(12,358	)
Income tax (expense) benefit		(98,173	)		(124,909	)		29,192			6,907


Net income (loss)	$	157,392		$	189,962		$	(48,231	)	$	(5,451	)

Three Months Ended December 31, 2006 Compared To Three Months Ended December 31, 2005

Propane Revenue and Gross Margins— Propane Operations’ revenues increased $746,000, from approximately $2,531,000 for the quarter ended December 31, 2005 to approximately $3,277,000 for the quarter ended December 31, 2006 as a result of higher prices in the Arizona regulated and unregulated operations, and the implementation on July 1, 2006 of a $.55/therm surcharge for the recovery of under-collected gas costs. Gas purchases increased $808,000, from $1,451,000 in the quarter ended December 31, 2005 to $2,259,000 in the quarter ended December 31, 2006. This increase was due primarily to higher propane prices in the current fiscal year. Gross margin decreased $62,000, from $1,080,000 in the quarter ended December 31, 2005 to $1,018,000 in the quarter ended December 31, 2006. This was attributable to higher costs of propane in the Arizona unregulated operation that were not recoverable through rates.

Propane Operating Expenses— Operating expenses were approximately $662,000 in the quarter ended December 31, 2006 compared to approximately $666,000 in the quarter ended December 31, 2005. This decrease of $4,000 is due to lower overhead costs of $28,000, and lower depreciation of $8,000. These savings were offset by increases in maintenance costs of $7,000, higher taxes other than income taxes of $6,000, and an increase in general and administrative costs of $19,000

Propane Other Income— Other income decreased by $10,000, from approximately $30,000 for the quarter ended December 31, 2005 to approximately $20,000 for the quarter ended December 31, 2006. Income on a sale/leaseback of $5,000 was recorded in the second quarter of fiscal 2006. This transaction was complete at the end of fiscal year 2006. In addition, Rocky Mountain Fuels (“RMF”) recognized income in fiscal year 2006 for contract fees related to the sale of the RMF assets in August 2004.

Propane Interest Expense— Interest expense decreased by $8,000, from approximately $129,000 in the quarter ended December 31, 2005 to approximately $120,000 for the quarter ended December 31, 2006, primarily due to lower short-term borrowings.

Propane Income Tax Expense— Income tax expense decreased by $27,000, from approximately $125,000 in the quarter ended December 31, 2005 to approximately $98,000 in the quarter ended December 31, 2006 due to lower pretax income.

Six Months Ended December 31, 2006 Compared to Six Months Ended December 31, 2005

Propane Revenue and Gross Margins— Propane Operations’ revenues increased $922,000, from approximately $3,529,000 for the six months ended December 31, 2005 to approximately $4,450,000 for the six months ended December 31, 2006 as a result of higher prices in the Arizona regulated and unregulated operations, and the implementation on July 1, 2006 of a $.55/therm surcharge for the recovery of under-collected gas costs. Gas purchased increased from $2,002,000 to $2,989,000 for the same period due to higher propane prices in the current fiscal year. Gross margin decreased $65,000, from $1,527,000 in the six months ended December 31, 2005 to $1,462,000 for the six months ended December 31, 2005. This was attributable to higher propane costs in the Arizona unregulated operation that were not recoverable through rates.

Propane Operating Expenses— Operating expenses were approximately $1,365,000 in the six months ended December 31, 2005 compared to approximately $1,355,000 in the six months ended December 31, 2006. This decrease of $10,000 is due to a decrease in depreciation expense of $22,000. This savings was offset by increases in overhead, general and administrative costs of $2,000 and maintenance and taxes other than income taxes of $10,000.

Propane Other Income— Other income decreased by $24,000, from approximately $61,000 for the six months ended December 31, 2005 to approximately $37,000 for the six months ended December 31, 2006. Income on a sale/leaseback of $12,000 was recorded in fiscal 2006. This transaction was complete at the end of fiscal 2006. In addition, RMF recognized $8,000 income in fiscal 2006 for contract fees related to the sale of the RMF assets in August 2004. This sales transaction was completed in August 2005. Other income reductions also included reduced sales for other services of approximately $4,000.

Propane Interest Expense— Interest expense decreased by $14,000, from approximately $235,000 in the six months ended December 31, 2005 to approximately $221,000 for the six months ended December 31, 2006, primarily due to lower short-term borrowings.

Propane Income Tax Benefit— Income tax benefit was approximately $7,000 in the six months ended December 31, 2005, compared to an income tax benefit of approximately $29,000 in the six months ended December 31, 2006 due to higher pretax loss in fiscal year 2007.

Operating Results of our EWR Operations


	Three Months Ended						Six Months Ended
	December 31,						December 31,
	2006			2005			2006			2005
Energy West Resources (“EWR”)

Operating revenues	$	3,364,979		$	6,108,052		$	5,972,588		$	8,977,884
Gas purchased		2,768,762			5,722,196			4,919,561			8,463,665

Gross margin		596,217			385,856			1,053,027			514,219
Operating expenses		115,344			124,017			235,954			398,526

Operating income		480,873			261,839			817,073			115,693
Other income (expense)		(20	)		8,250			(20	)		22,399


Income before interest and taxes		480,853			270,089			817,053			138,092

Interest (expense)		(39,023	)		(53,557	)		(74,699	)		(100,833	)


Income before income taxes		441,830			216,532			742,354			37,259
Income tax (expense)		(170,550	)		(83,777	)		(286,897	)		(14,023	)


Net income	$	271,280		$	132,755		$	455,457		$	23,236

Three Months Ended December 31, 2006 Compared To Three Months Ended December 31, 2005

EWR Revenues and Gross Margins— Revenues decreased $2,743,000 from approximately $6,108,000 in the quarter ended December 31, 2005 to approximately $3,365,000 in the quarter ended December 31, 2006. Mark-to-market revenues decreased by $78,000 due to the much lower index prices for natural gas in the second quarter of fiscal year 2007 versus the second quarter of fiscal year 2006. Retail gas revenues decreased by $2,652,000, which consisted of (1) approximately $1,875,000 due to the loss of two large customers, and (2) a $777,000 decrease due to lower index prices.

EWR’s second quarter fiscal year 2007 gross margin of approximately $596,000 represents an increase of $210,000 from the gross margin of approximately $386,000 earned in the second quarter of fiscal year 2006. Gross margin from gas production increased by $77,000 due to renegotiation of contracts from low fixed prices to an index based price. Gross margin from retail gas sales increased by $210,000 due to new business in our Wyoming market and the renegotiation of expiring contracts on more favorable terms. These increases were offset by the $78,000 decrease in mark-to-market revenue and the loss of two large customers mentioned above.

EWR Operating Expenses— Operating expenses decreased approximately $9,000, from approximately $124,000 for the quarter ended December 31, 2005 to approximately $115,000 for the quarter ended December 31, 2006. This decrease is due primarily to a reduction in general, administrative and overhead costs of $17,000, offset by an increase in maintenance of $9,000.

EWR Other Income— Other income decreased by approximately $8,000 due to income from the settlement of a contract dispute in the quarter ended December 31, 2005.

EWR Interest Expense— Interest expense decreased approximately $15,000 due to lower short-term borrowings.

EWR Income Tax Expense— Tax expense increased due to increased pretax income in the quarter ended December 31, 2006.

Six Months Ended December 31, 2006 Compared to Six Months Ended December 31, 2005

EWR Revenues and Gross Margins— Revenues decreased $3,005,000 from approximately $8,978,000 in the six months ended December 31, 2005 to approximately $5,973,000 in the six months ended December 31, 2006. Mark-to-market revenues decreased by $156,000 due to the much lower index prices for natural gas in the first half of fiscal 2007 versus the first half of fiscal 2006. Retail gas revenues decreased by $2,843,000. Approximately

$1,875,000 of this decrease is due to the loss of two large customers, with the remaining decrease due to lower index prices.

Gross margin increased $539,000 from approximately $514,000 in the first six months of fiscal 2006 to approximately $1,053,000 in the first six months of fiscal 2007. Gross margin from gas production increased by $219,000 due to renegotiation of contracts from low fixed prices to an index based price. Gross margin from retail gas sales increased by $475,000 due to new business in our Wyoming market and the re-negotiation of expiring contracts on more favorable terms. These increases are offset by the $156,000 decrease in mark-to-market revenue mentioned above and the loss of two large customers.

EWR Operating Expenses— Operating expenses in EWR decreased $163,000, from approximately $399,000 for first six months of fiscal 2006 to approximately $236,000 for the first six months of fiscal 2007. Approximately $115,000 of this savings is due to a wrongful termination settlement expensed in the first quarter of fiscal 2006. The remainder includes reductions in depreciation, taxes other than income taxes, and general administrative expenses.

EWR Other Income— Other income decreased approximately $22,000 due to income from the settlement of a contract dispute in the quarter ended December 31, 2005.

EWR Interest Expense— Interest expense decreased approximately $26,000 due to a decrease in short-term borrowings.

EWR Income Tax Expense— Tax expense increased due to increased pretax income.

Operating Results of our Pipeline Operations


	Three Months Ended						Six Months Ended
	December 31,						December 31,
	2006			2005			2006			2005
Pipeline Operations

Operating revenues	$	99,753		$	102,539		$	199,191		$	210,747
Gas purchased		—			—			—			—

Gross margin		99,753			102,539			199,191			210,747
Operating expenses		69,052			43,101			108,743			89,614

Operating income		30,701			59,438			90,448			121,133
Other income		—			—			—			—


Income before interest and taxes		30,701			59,438			90,448			121,133

Interest (expense)		(8,650	)		(12,488	)		(16,871	)		(22,859	)


Income before income taxes		22,051			46,950			73,577			98,274
Income tax (expense)		(9,697	)		(17,883	)		(29,510	)		(37,811	)


Net income	$	12,354		$	29,067		$	44,067		$	60,463

Three Months Ended December 31, 2006 Compared To Three Months Ended December 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’ gross margin has remained relatively constant in the quarter ended December 31, 2006 as compared to the quarter ended December 31, 2005.

Pipeline Operating Expenses— Operating expenses increased approximately $26,000 due to an increase of $29,000 in maintenance, depreciation, and various general and administrative costs offset by $3,000 savings in taxes other than income taxes.

Pipeline Interest Expense— Interest expense decreased approximately $4,000 due to a decrease in short-term borrowings

Pipeline Income Tax Expense— Tax expense decreased approximately $8,000 due to lower pretax income.

Six Months Ended December 31, 2006 Compared to Six Months Ended December 31, 2005

Pipeline Revenues and Gross Margins—Pipeline Operations’ margin decreased approximately $12,000 due a decrease in gathering volumes on the Glacier gathering line.

Pipeline Operating Expenses— Operating expenses increased approximately $19,000 due to an increase of $26,000 in maintenance, depreciation, and various general and administrative costs offset by $7,000 savings in taxes other than income taxes.

Pipeline Interest Expense— Interest expense decreased approximately $6,000 due to a decrease in short-term borrowings.

Pipeline Income Tax Expense— Tax expense decreased approximately $8,000 due to a lower pretax income in the six months ended December 31, 2005.

Consolidated Cash Flow Analysis

Sources and Uses of Cash

Operating activities provide our primary source of cash. We finance our capital expenditures on an interim basis through our $20,000,000 credit facility with LaSalle Bank, shown as line of credit on the accompanying balance sheets. Our use of the LaSalle Credit Facility decreased to $5,050,000 at December 31, 2006, compared with $11,000,000 at December 31, 2005. This $5,950,000 improvement in our line of credit is primarily due to increased net income, and decreased receivables and inventories.

We periodically repay our short-term borrowings under the LaSalle Credit Facility by using the net proceeds from the sale of long-term debt and equity securities. In July 2006, we entered into an agreement to sell certain of our assets related to our Arizona propane business for cash of approximately $15.0 million plus net working capital. We plan to use the proceeds from this transaction to reduce our outstanding debt and strengthen our balance sheet. We believe that this will enable our company to take advantage of opportunities to enhance or expand our existing operations and to acquire additional businesses or assets on favorable terms as and when those opportunities arise.

Long-term debt decreased to approximately $17,318,000 at December 31, 2006, compared with approximately $18,370,000 at December 31, 2005. This $1,052,000 decrease resulted primarily from the scheduled principal payments of $515,000 on the Series 1993 notes, $105,000 on the Series 1992B notes and $433,000 on the term loan as provided for in the debt agreements.

Cash decreased approximately $600,000 from June 30, 2006 to December 31, 2006, compared with the approximate $983,000 increase in cash from June 30, 2005 to December 31, 2005, as shown in the following table:


	December 31,
	2006			2005
Cash (used in) operating activities	$	(3,776,417	)	$	(4,895,067	)
Cash (used in) investing activities		(1,152,965	)		(843,863	)
Cash provided by financing activities		4,329,650			6,722,408


Increase/(decrease) in cash	$	(599,732	)	$	983,478

Cash used in operating activities was approximately $1,119,000 lower in the six months ended December 31, 2006, than the six months ended December 31, 2005. This was due to an increase in net income of $580,000, decrease in depreciation expense of $24,000, and an overall increase in other assets net of liabilities of $563,000.

Cash used in investing activities was approximately $309,000 higher in the six months ended December 31, 2006, than the six months ended December 31, 2005. This was due primarily to increased construction expenditures of $210,000 and reduced receipts from cash received from long term notes receivable of $175,000, offset by increases in cash received for contributions in aid of constructions and advances for construction of $76,000.

Cash provided by financing activities was approximately $2,393,000 less in the six months ended December 31, 2006 than in the six months ended December 31, 2005 due to decreased net advances on the line of credit of $2,050,000, dividends paid of $535,000, and increased payment of long-term debt of $20,000, offset by proceeds from the sale of stock of $212,000.

Liquidity And Capital Resources

We generally fund our operating capital needs, as well as dividend payments and capital expenditures, 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.

Effective November 27, 2006, our company and LaSalle Bank extended and amended the LaSalle Credit Facility. The Sixth Amendment provides for (i) an extension of the revolving line of credit until November 26, 2007; (ii) an increase in the commitment amount of the revolving line of credit from $15 million to $20 million; and (iii) a reduction in the interest rate calculations that we currently use for the term loan and line of credit under the LaSalle Credit Facility. The term loan had an outstanding balance of $4.93 million at December 31, 2006. 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 Bank 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, 2007
Minimum borrowing	$	0	$	2,900,000
Maximum borrowing	$	2,900,000	$	6,200,000
Average borrowing	$	282,000	$	4,384,000

Year Ended June 30, 2006
Minimum borrowing	$	3,100,000	$	5,200,000	$	0	$	0
Maximum borrowing	$	5,200,000	$	12,250,000	$	12,050,000	$	0
Average borrowing	$	4,167,000	$	9,489,000	$	5,619,000	$	0

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

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 150 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” plus 50 basis points. For the term loan with LaSalle Bank, we may elect to pay interest at either the applicable LIBOR rate plus 200 basis points or at the Prime Rate plus 100 basis points.

At December 31, 2006, we had approximately $1,040,000 of cash on hand. In addition, at December 31, 2006, we had borrowed approximately $5.05 million under the LaSalle Credit Facility. Our short-term borrowings under our lines of credit during the first six months of fiscal 2007 had a daily weighted average interest rate of 8.63% per annum. At December 31, 2006, we had no outstanding letters of credit related to electricity and gas purchase contracts. We had net availability at December 31, 2006, of approximately $14,950,000 under the LaSalle Credit Facility revolving line of credit. At December 31, 2006, we were in compliance with the financial covenants under the LaSalle Credit Facility.

In addition to the LaSalle Credit Facility, we have outstanding (i) $8.0 million of Series 1997 notes bearing interest at an annual rate of 7.5%; (ii) $7.8 million of Series 1993 notes bearing interest at annual rates ranging from 6.20% to 7.60%; and (iii) 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% (collectively “Long Term Notes and Bonds”). 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 Bank.

The total amount outstanding under all of our long-term debt obligations was approximately $18.4 million and $19.4 million at December 31, 2006, and December 31, 2005, respectively. The portion of such obligations due within one year was approximately $1,062,000 and $1,057,000 at December 31, 2006, and December 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. 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. At December 31, 2006, the fair value of the interest rate swap was $57,205. This amount is recorded as a derivative asset on the accompanying financial statements.

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 December 31, 2006.

Payments Due by Period


			1 year						After
Contractual Obligations	Total		or less		2-3 years		4-5 years		5 years
Interest payments (a)	$	6,446,096	$	1,706,710	$	2,230,903	$	1,783,308	$	725,175

Long Term Debt (b)		18,379,842		1,061,509		5,363,333		275,000		11,680,000

Operating Lease Obligations		385,536		144,624		159,912		81,000		—

Transportation and Storage Obligation (c)		13,568,118		4,340,510		8,517,792		709,816		—


Total Obligations	$	38,779,592	$	7,253,353	$	16,271,940	$	2,849,124	$	12,405,175


(a)		Our long-term debt, notes payable and customers’ deposits all require interest payments. Interest payments are projected based on debt service schedules provided at debt issuance.

(b)		Represents long-term debt outstanding under the LaSalle Credit Facility and the Long-Term Notes and Bonds. 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 – Our Company and its subsidiaries 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 our 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.

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 of our company and its subsidiaries 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 December 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 2007	$	60,412	$	60,582
Contracts maturing during fiscal years 2008 and 2009		57,205		—
Contracts maturing during fiscal years 2010 and beyond		—		—

Total	$	117,617	$	60,582

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.

Off-Balance Sheet Arrangements

The Company has no off balance sheet arrangements.

ITEM 3 — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Our 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 our financial statements for a description of our accounting policies and other information related to these financial instruments.

Commodity Price Risk

We seek to protect ourselves against natural gas price fluctuations by limiting the aggregate level of net open positions that are exposed to market price changes. We manage open positions 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 that 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 our interest expense by approximately $26,000 annually.

Credit Risk

Credit risk relates to the risk of loss that our company would incur as a result of non-performance by counterparties of their contractual obligations under 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 that 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 principal executive officer and principal 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 principal executive officer and principal 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 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

We held our 2006 Annual Meeting of Shareholders on December 5, 2006. The following nominees were elected to the Company’s Board of Directors to serve for a one year term unless they resign .


Name	For		Withhold
W. E. Argo		2,650,965		91,485
Steven A. Calabrese		2,622,405		120,045
David A. Cerotzke		2,627,615		115,045
Mark D. Grossi		2,626,619		115,831
Richard M. Osborne		2,596,350		146,100
Thomas J. Smith		2,620,619		121,831
James E. Sprague		2,616,823		125,627

Additionally, the Company’s shareholders voted upon a proposal to ratify the appointment of Hein & Associates LLP as our independent auditors for the fiscal year ending June 30, 2007.


For	Withhold		Abstain
2,699,394		39,033		4,053

ITEM 6 — EXHIBITS


Exhibit
Number		Description

10.1		Reaffirmation and Sixth Amendment to Amended and Restated Credit Agreement, dated as of November 27, 2006, by and among Registrant, its subsidiaries and LaSalle Bank National Association. Exhibit 10.1 to the registrant’s Current Report on Form 8-K dated December 4, 2006, is incorporated herein by reference.

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
February 13, 2007	Chief Financial Officer (principal financial officer and principal accounting officer)

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Readability	H.S. freshman Avg

Gas Natural Inactive 10-Q2006 Q4 Quarterly report

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