Gas Natural 10-Q 2006 Q3 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 September 30, 2006

or

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

For the transition period from                    to                    

Commission File number 0-14183

ENERGY WEST, INCORPORATED

(Exact name of registrant as specified in its charter)

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

1 First Avenue South, Great Falls, 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 November 7, 2006 was 2,946,677 shares.

ENERGY WEST, INCORPORATED
INDEX TO FORM 10-Q

	Page No.
Part I — Financial Information
Item 1 — Financial Statements
Condensed Consolidated Balance Sheets as of September 30, 2006, September 30, 2005 and June 30, 2006		3
Condensed Consolidated Statements of Operations — three months ended September 30, 2006 and 2005		4
Condensed Consolidated Statements of Cash Flows — three months ended September 30, 2006 and 2005		5
Notes to Condensed Consolidated Financial Statements		6
Item 2 — Management’s Discussion and Analysis of Financial Condition and Results of Operations		13
Item 3 — Quantitative and Qualitative Disclosures about Market Risk		25
Item 4 — Controls and Procedures		26
Part II — Other Information
Item 6 — Exhibits		26
Signatures
EX-31
EX-32

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PART I – FINANCIAL INFORMATION

ITEM 1 – FINANCIAL STATEMENTS.

2

ENERGY WEST INCORPORATED AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS, SEPTEMBER 30, 2006 AND 2005, AND JUNE 30, 2006

	September 30,				June 30,
	2006		2005		2006
ASSETS
Current Assets:
Cash	$	463,404	$	250,303	$	1,639,578
Accounts and notes receivable less $170,302, $308,182 and $142,372, respectively, allowance for bad debt		3,587,971		4,072,636		4,162,851
Unbilled gas		1,313,432		1,406,705		1,020,540
Derivative assets		81,646		300,799		137,865
Natural gas and propane inventories		10,381,809		9,205,044		5,424,778
Materials and supplies		595,271		455,350		455,228
Prepayments and other		562,862		358,527		290,860
Deferred income taxes		—		152,334		—
Income tax receivable		410,976		1,025,397		—
Recoverable cost of gas purchases		768,578		1,275,210		1,323,442
Total current assets		18,165,949		18,502,305		14,455,142
Property, Plant and Equipment, Net		39,280,563		38,903,460		39,104,060
Deferred Charges		3,977,462		4,576,340		4,214,178
Other Assets		333,778		172,521		157,365
TOTAL ASSETS	$	61,757,752	$	62,154,626	$	57,930,745
LIABILITIES AND CAPITALIZATION
Current Liabilities:
Current portion of long-term debt	$	1,090,709	$	1,013,089	$	1,058,213
Line of credit		2,900,000		5,200,000		—
Accounts payable		4,794,572		3,969,447		3,592,260
Derivative liabilities		21,778		255,165		42,664
Accrued income taxes		—		—		1,320,431
Deferred income taxes		—		—		269,163
Accrued and other current liabilities		5,104,685		4,498,324		3,860,302
Total current liabilities		13,911,744		14,936,025		10,143,033
Other Obligations:
Deferred income taxes		6,295,292		6,307,574		5,835,886
Deferred investment tax credits		286,955		308,017		292,220
Other long-term liabilities		4,987,672		5,460,761		4,889,493
Total		11,569,919		12,076,352		11,017,599
Long-Term Debt		17,495,000		18,577,197		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, 2,946,677, 2,912,564 and 2,934,177 shares outstanding at September 30, 2006 and 2005, and June 30, 2006 respectively		442,002		436,892		440,127
Capital in excess of par value		7,738,599		7,435,309		7,634,337
Retained earnings		10,600,488		8,692,851		11,090,649
Total stockholders’ equity		18,781,089		16,565,052		19,165,113
TOTAL CAPITALIZATION		36,276,089		35,142,249		36,770,113
TOTAL LIABILITIES AND CAPITALIZATION	$	61,757,752	$	62,154,626	$	57,930,745

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

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ENERGY WEST, INCORPORATED AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2006 AND 2005

	Three Months Ended
	September 30,
	2006			2005
REVENUES:
Natural gas operations	$	5,749,348		$	6,315,367
Propane operations		1,173,864			997,982
Gas and electric—wholesale		2,607,609			2,869,832
Pipeline operations		99,438			108,208
Total revenues		9,630,259			10,291,389
EXPENSES:
Gas purchased		4,279,764			4,887,849
Gas and electric—wholesale		2,150,799			2,741,469
Distribution, general, and administrative		2,055,768			2,218,787
Maintenance		140,188			147,892
Depreciation and amortization		550,192			574,377
Taxes other than income		367,308			362,636
Total expenses		9,544,019			10,933,010
OPERATING INCOME (LOSS)		86,240			(641,621	)
OTHER INCOME		78,213			111,022
INTEREST (EXPENSE)		(476,037	)		(493,414	)
(LOSS) BEFORE INCOME TAXES		(311,584	)		(1,024,013	)
INCOME TAX BENEFIT		117,076			402,440
NET (LOSS)	$	(194,508	)	$	(621,573	)
(LOSS) PER COMMON SHARE:
Basic	$	(0.07	)	$	(0.21	)
Diluted	$	(0.07	)	$	(0.21	)
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:
Basic		2,939,534			2,912,564
Diluted		2,939,534			2,912,564

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

4

ENERGY WEST, INCORPORATED AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2006 AND 2005

	Three Months Ended
	September
	2006			2005
CASH FLOWS FROM OPERATING ACTIVITIES:
Net (loss)	$	(194,508	)	$	(621,573	)
Adjustments to reconcile net (loss) to net cash (used in) operating activities:
Depreciation and amortization, including deferred charges and financing costs		702,307			749,404
Derivative assets		56,219			(181,730	)
Derivative liabilities		(20,886	)		140,928
Deferred gain		(325,582	)		(139,501	)
Investment tax credit		(5,265	)		(5,265	)
Deferred gain on sale of assets		—			(5,907	)
Deferred income taxes		(217,796	)		380,225
Changes in assets and liabilities:
Accounts and notes receivable		(562,355	)		2,165,516
Natural gas and propane inventories		(4,993,084	)		(5,494,011	)
Accounts payable		1,202,311			858,586
Recoverable/refundable cost of gas purchases		554,864			588,265
Prepayments and other		(272,002	)		27,778
Other assets & liabilities		873,022			862,161
Net cash used in operating activities		(3,202,755	)		(675,124	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Construction expenditures		(765,459	)		(581,854	)
Collections on notes receivable		—			174,561
Customer advances received for construction		160,798			20,000
Increase (decrease) from contributions in aid of construction		(1,739	)		19,114
Net cash used in investing activities		(606,400	)		(368,179	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Repayments of long-term debt		(77,504	)		(100,000	)
Proceeds from lines of credit		2,900,000			2,200,000
Repayments of lines of credit		—			(900,000	)
Sale of common stock		106,138			—
Dividends paid		(295,653	)		—
Net cash provided by financing activities		2,632,981			1,200,000
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		(1,176,174	)		156,697
CASH AND CASH EQUIVALENTS:
Beginning of period		1,639,578			93,606
End of period	$	463,404		$	250,303

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

5

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

September 30, 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 month period ended September 30, 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.

The Company conducts certain non-regulated, non-utility operations 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 three 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 September 30, 2006 were reflected on the Company’s consolidated balance sheet as derivative assets and liabilities at an approximate fair value as follows:

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	Assets		Liabilities
Contracts maturing during fiscal year 2007	$	21,607	$	21,778
Contracts maturing during fiscal years 2008 and 2009		60,039		—
Contracts maturing during fiscal years 2010 and beyond		—		—
Total	$	81,646	$	21,778

Natural Gas and Propane Operations — In the case of the Company’s regulated divisions, gains or losses resulting from derivative contracts are subject to deferral under regulatory procedures of the public service regulatory commissions of Montana, Wyoming and Arizona. Therefore, related derivative assets and liabilities are offset with corresponding regulatory liability and asset amounts included in “Recoverable Cost of Gas Purchases” pursuant to SFAS No. 71, Accounting for the Effects of Certain Types of Regulation. As of September 30, 2006, the Company’s regulated operations have no contracts meeting the mark-to-market accounting requirements.

NOTE 2 — INCOME TAX BENEFITS

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

	Three Months Ended
	September 30
	2006			2005
Tax benefit at statutory rate of 34%	$	105,939		$	358,404
State income tax benefit, net of federal tax benefit		14,520			39,153
Amortization of deferred investment tax credits		5,265			5,265
Other		(8,648	)		(382	)
Total income tax benefit	$	117,076		$	402,440

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 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.

We maintain a $15.0 million revolving line of 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. At September 30, 2006, the term loan had an outstanding balance of $5.0 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.

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

The LaSalle credit facility requires us to maintain compliance with a number of financial covenants, including meeting limitations on annual capital expenditures, maintaining a total debt to total capital ratio of not more than .70-to-1.00, and maintaining an interest coverage ratio of no less than 2.00-to-1.00. The LaSalle credit facility also restricts our ability to pay dividends during any period to a certain percentage of our cumulative earnings over that period, and restricts open positions and Value at Risk in our wholesale operations. At September 30, 2006 and 2005, we were in compliance with the financial covenants under the LaSalle credit facility.

At September 30, 2006, the Company had approximately $463,000 of cash on hand. In addition, at September 30, 2006, the Company had borrowed approximately $2.9 million under the LaSalle Facility revolving line of credit. The Company’s short-term borrowings under its lines of credit during the three months ended September 30, 2006 had a daily weighted average interest rate of 8.25% per annum. The Company’s net availability at September 30, 2006, was approximately $12.1 million under the LaSalle Facility revolving line of credit.

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

Under the terms of the Long Term Notes and Bonds, we are subject to certain restrictions, including restrictions on total dividends and distributions, liens and secured indebtedness, and asset sales. We also are restricted from incurring additional long-term indebtedness if we do not meet certain debt to interest and debt to capital ratios. At September 30, 2006 and 2005, we were in compliance with the financial covenants under the Long Term Notes and Bonds.

In the event that our obligations under the LaSalle credit facility were declared immediately due and payable as a result of an event of default, such acceleration also could result in events of default under our Series 1993 Notes and Series 1997 Notes. In such circumstances, an event of default under either series of notes would occur if (a) we were given notice to that effect either by the trustee under the indenture governing such series of notes, or the holders of at least 25% in principal amount of the notes of such series then outstanding, and (b) within 10 days after such notice from the trustee or the note holders, the acceleration of our obligations under the LaSalle credit facility has not been rescinded or annulled and the obligations under the LaSalle credit facility have not been discharged. There is no similar cross-default provision with respect to the Cascade County, Montana Series 1992B Industrial Development Revenue Bonds and the related Loan Agreement between our company and Cascade County, Montana. If our obligations were accelerated under the terms of any of the LaSalle credit facility, the Series 1993 Notes or the Series 1997 Notes, such acceleration (unless rescinded or cured) could result in a loss of liquidity and cause a material adverse effect on our company and our financial condition.

The total amount outstanding under all of the Company’s long-term debt obligations was approximately $18.6 million and $19.6 million at September 30, 2006, and September 30, 2005, respectively. The portion of such obligations due within one year was approximately $1,090,000 and $1,010,000 at September 30, 2006, and September 30, 2005, respectively.

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

8

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:

	Three Months Ended
	September 30,				June 30,
	2006		2005		2006
Regulatory asset for property taxes	$	2,244,939	$	2,477,247	$	2,303,015
Regulatory asset for income taxes		458,753		458,753		458,753
Regulatory asset for deferred environmental remediation costs		324,989		408,824		334,996
Other regulatory assets		19,965		53,361		126,263
Unamortized debt issue costs		928,816		1,178,155		991,151
Total	$	3,977,462	$	4,576,340	$	4,214,178

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

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

NOTE 5 — CONTINGENCIES

Environmental Contingency— We own property on which we operated a manufactured gas plant from 1909 to 1928. We currently use this site as an office facility for 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.

We have completed our remediation of soil contaminants at the plant site. In April 2002 we received a closure letter from the Montana Department of Environmental Quality, or “MDEQ,” approving the completion of such remediation program.

We and our consultants worked 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 those standards. Although the MDEQ has not established guidance respecting the attainment of a technical waiver, the U.S. Environmental Protection Agency, or “EPA,” has developed such

9

guidance. The EPA guidance lists factors that render remediation technically impracticable. We have filed with the MDEQ a request for a waiver from complying with certain standards.

At September 30, 2006, we had incurred cumulative costs of approximately $2,093,000 in connection with our evaluation and remediation of the site. On May 30, 1995, we received an order from the MPSC allowing for recovery of the costs associated with the evaluation and remediation of the site through a surcharge on customer bills. As of September 30, 2006, we had recovered approximately $1,768,000 through such surcharges. As of September 30, 2006, the cost remaining to be recovered through the on going rate is $325,000. We are required to file with the MPSC every two years for approval to continue the recovery of these costs through a 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—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
	September 30
	2006			2005
Gross margin (operating revenue less cost of gas purchased):
Natural gas operations	$	2,199,304		$	1,978,281
Propane operations		444,144			447,219
EWR		456,810			128,363
Pipeline operations		99,438			108,208
	$	3,199,696		$	2,662,071
Operating income (loss):
Natural gas operations	$	(60,001	)	$	(305,453	)
Propane operations		(249,706	)		(251,717	)
EWR		336,200			(146,146	)
Pipeline operations		59,747			61,695
	$	86,240		$	(641,621	)
Net (loss):
Natural gas operations	$	(204,775	)	$	(348,037	)
Propane operations		(205,623	)		(195,413	)
EWR		184,177			(109,519	)
Pipeline operations		31,713			31,396
	$	(194,508	)	$	(621,573	)

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NOTE 7 — ACCRUED AND OTHER CURRENT LIABILITIES

      Accrued and other current liabilities consists of the following:

	September 30,				June 30,
	2006		2005		2006
Property tax settlement—current portion	$	243,000	$	243,000	$	243,000
Payable to employee benefit plans		66,588		148,783		275,377
Accrued vacation		261,678		262,669		258,831
Customer deposits		470,680		443,840		465,188
Accrued interest		462,270		382,369		140,648
Accrued taxes other than income		747,670		680,396		467,947
Deferred short-term gain		243,519		321,639		243,519
Customer prepayments from levelized billing		1,569,653		1,142,433		844,344
Other		1,039,627		873,195		921,448
Total	$	5,104,685	$	4,498,324	$	3,860,302

NOTE 8 — OTHER LONG TERM LIABILITIES

      Other long-term liabilities consist of the following

	September 30,				June 30,
	2006		2005		2006
Asset retirement obligation	$	659,690	$	626,534	$	650,717
Contribution in aid of construction		1,942,768		1,466,562		1,954,980
Customer advances for construction		438,643		697,937		277,845
Accumulated postretirement obligation		141,200		360,105		139,200
Deferred gain — long-term *		264,202		507,722		325,582
Deferred gain on sale leaseback of assets		—		17,732		—
Regulatory liability for income taxes		83,161		83,161		83,161
Property tax settlement		1,458,008		1,701,008		1,458,008
Total	$	4,987,672	$	5,460,761	$	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 September 30, 2006, there are 143,000 options outstanding, 15,000 shares issued under this plan have been exercised, and the maximum number of shares available for future grants under this plan is 42,000 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.

11

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 September 30, 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 quarter of fiscal 2007 was approximately $15,000, or approximately $0.01 per share.

The Company uses the Black Scholes methodology, with a price volatility assumption of 32% based upon historical stock prices for the last 12 months, an expected life of seven years, 2% expected dividend rate, and a risk free interest rate of 5.0%.

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 September 2006, expected dividends at $.40 per year, volatility of 32%; 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 September 30, 2006 and changes during the quarter ended September 30, 2006 is presented below.

				Weighted
	Number of			Average
	Shares			Exercise Price
Outstanding June 30, 2006		145,500			$8.34
Granted		10,000			$9.02
Exercised		(12,500	)		$8.49
Expired		—
Outstanding September 30, 2006		143,000			$8.38

The following information applies to options outstanding at September 30, 2006:

							Weighted
							Average
					Weighted		Remaining				Weighted
					Average		Contractual				Average
Grant	Exercise		Number		Exercise		Life		Number		Exercise
Date	Price		Outstanding		Price		(Years)		Exercisable		Price
11/21/2002		$  8.49		36,000		$  8.49		1.1		36,000		$  8.49
7/1/2004		$  6.47		30,000		$  6.47		7.5		22,500		$  6.47
4/1/2005		$  6.62		20,000		$  6.62		8.5		10,000		$  6.62
7/1/2005		$  9.85		20,000		$  9.85		8.8		10,000		$  9.85
10/4/2005		$10.51		22,000		$10.51		9.0		5,500		$10.51
1/6/2006		$  9.52		5,000		$  9.52		4.3		0		$  9.52
7/1/2006		$  9.02		10,000		$  9.02		9.8		2,500		$  9.02
				143,000						86,500

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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 regarding 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.

EXECUTIVE OVERVIEW

Energy West has operated natural gas distribution businesses since 1909 and it is still our primary source of revenue. 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 loss for the fiscal quarter ended September 30, 2006 improved 69% over the net loss for the same period last year. Our strong balance sheet also allows us to pursue a wider range of attractive opportunities for growth.

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.

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Strategy

The key elements of our current strategy include the following:

• Focus on the natural gas distribution and related businesses.

• 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.

Opportunities and Challenges

Our business and industry provides us with numerous opportunities for growth and profitability, including the following:

• Our company possesses many competitive strengths, including:

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

– Investment grade financial strength and resources of our natural gas and propane suppliers.

– Our positive reputation with regulators and customers.

– Our corporate infrastructure, which provides a platform for additional projects with limited incremental expenses.

• Prospects for continuing our residential and commercial customer growth are excellent. The pace of new home and commercial construction remains steady in the communities we serve. We believe demand for natural gas will remain strong because it provides a clean, easy to use, and efficient source of fuel for heating and cooking.

• We carefully analyze the economics of our spending to support growth. When justified under our tariffs, we work with developers, business owners, and residents to share certain construction costs to assure a fair return to our company. We also manage non-revenue-generating spending in order 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 in other gas producing areas near our pipeline properties located in southeast Montana and northwest Wyoming to increase revenues and margins.

Despite the opportunities listed above and recent positive trends in our business, we continue to address certain challenges, including the following:

• Our relatively small size makes us vulnerable to earnings variations as a result of a variety of factors, including the following:

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– loss of one of our natural gas suppliers;

– loss of key personnel; or

– significant litigation or other one-time expenses.

• Our 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, continues to encourage such measures.

• We earn approximately 20% of our operating margin by 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. To mitigate these risks, 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 increased by the effects of the weather. Conversely, in a warm year, our earnings are lower. Peak requirements also drive the need to reinforce our systems to increase capacity, which in turn, increases costs.

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

Fiscal Quarter Ended September 30, 2006 Compared to Fiscal Quarter Ended September 30, 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, 2006. The following gives effect to the unaudited Condensed Consolidated Financial Statements as of September 30, 2006 and for the three month period ended September 30, 2006. Results of operations for interim periods are not necessarily indicative of results to be attained for any future period.

Net (Loss)— Our net loss for the first quarter of fiscal year 2007 was $195,000 compared to a net loss of $622,000 in the first quarter of fiscal year 2006, a decrease of $427,000. The decrease in our net loss was primarily due to higher gross margins in Natural Gas and EWR operating segments, lower operating expenses in all segments, and a decrease in interest expense. The increases in gross margin and the reductions in expenses were partially offset by a decrease in income tax benefit due to lower pretax losses.

Revenues— Our revenues for the first quarter of fiscal year 2007 were $9,630,000 compared to $10,291,000 in the first quarter of fiscal year 2006, a decrease of $661,000. The decrease was primarily attributable to: (1) decreases in EWR retail gas revenues of $191,000 and mark to market revenues of $78,000, caused by lower index prices in the first quarter of fiscal year 2007 versus fiscal year 2006, (2) natural gas revenue decrease of $566,000 due primarily to slightly lower volumes, coupled with lower rates, (3) decreased revenues in Pipeline operations of $9,000 due to a decrease in gathering volumes on the Glacier line and (4) propane revenue increase of $176,000 due primarily to a $.55 per therm surcharge implemented July 1, 2006. This surcharge was approved by the ACC for the collection of prior under-collected gas costs.

Gross Margin— Gross margin, which is defined as revenue less gas purchased and costs of gas and electricity (wholesale), increased $538,000, from $2,662,000 in the first quarter of fiscal year 2006 to $3,200,000 in the first quarter of fiscal year 2007. EWR’s margin increased $328,000 due to (1) a $142,000 increase in margin from gas

15

production as a result of replacing the low fixed price contract with an index priced contract and (2) a $264,000 increase in margin from retail gas sales due to replacing several fixed price sales contracts with more favorable index priced contracts. These were offset by a decrease in mark to market revenues of $78,000.

The Pipeline Operations’ margins decreased $9,000 due to lower volumes on the Glacier line. The Natural Gas Operations’ margins increased $225,000 primarily due to a change in the rate design put into effect September 1, 2005. This rate design changed the structure of our rates, increasing the customer charge, and smoothing out our revenue stream. This had the result of increasing our first quarter fiscal year 2007 gross margin over the first quarter of fiscal year 2006. Over the course of the year, this gross margin change is neutral. The Propane Operations’ margins decreased $3,000, or less than 1%.

Expenses Other Than Costs of Gas and Electricity and Costs of Goods Sold— Expenses other than gas purchased decreased by $190,000 in the first quarter of fiscal year 2007 as compared to the first quarter of fiscal year 2006. The primary reasons for this decrease were (1) decreases in the Company’s general and administrative costs of $261,000, created by cost savings measures in all areas, including reductions in wage and employee benefits, (2) decreases in depreciation and amortization of $24,000, and (3) decreases in maintenance of $8,000, offset by (4) increases of $99,000 and $5,000 in overhead and taxes other than income, respectively. The increase in overhead is primarily due to the one-time charge of $130,000 in September 2006 for the costs related to an employment separation agreement.

Other Income— Other income decreased by $33,000 from $111,000 in the first quarter of fiscal year 2006 to $78,000 in the first quarter of fiscal year 2007. Natural Gas other income decreased $5,000, from $66,000 in the first quarter of fiscal year 2006 to $61,000 in the first quarter of fiscal year 2007 due to slightly higher income generated in the first quarter of fiscal year 2006 for services to customers. Propane other income decreased $14,000 due to the payoff on July 9^th, 2005 of the note receivable in Rocky Mountain Fuels (“RMF”), which resulted in interest and consulting income in the first quarter of fiscal year 2006, and recognition of deferred gain in EWP-Arizona in the first quarter of fiscal year 2006. Neither item was repeated in the first quarter of fiscal year 2007. EWR other income decreased $14,000 due to income from the settlement of a contract dispute in the first quarter of fiscal year 2006, not repeated in fiscal year 2007.

Interest Expense— Interest expense decreased by approximately $17,000 during the first quarter of fiscal year 2007 from the first quarter of fiscal year 2006 due to lower short-term borrowings.

Income Tax Benefits— Income tax benefits decreased $285,000 in the first quarter of fiscal year 2007 as compared to the first quarter of fiscal year 2006 due to the decreased net loss in the first quarter of fiscal year 2007.

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Operating Results of our Natural Gas Operations

	Three Months Ended
	September 30,
	2006			2005
Natural Gas Operations
Operating revenues	$	5,749,348		$	6,315,367
Gas purchased		3,550,044			4,337,086
Gross margin		2,199,304			1,978,281
Operating expenses		2,259,305			2,283,734
Operating (loss)		(60,001	)		(305,453	)
Other income		60,966			65,779
Income (loss) before interest and taxes		965			(239,674	)
Interest (expense)		(331,611	)		(329,161	)
Loss before income taxes		(330,646	)		(568,835	)
Income tax benefit		125,871			220,798
Net (loss)		($204,775	)		($348,037	)

Fiscal Quarter Ended September 30, 2006 Compared to Fiscal Quarter Ended September 30, 2005

Natural Gas Revenues and Gross Margins— The Natural Gas Operations’ operating revenues in the first quarter of fiscal year 2007 decreased to $5,749,000 from $6,315,000 in the first quarter of fiscal year 2006. This $566,000 decrease was primarily due to lower volumes in the first quarter of fiscal year 2007 compared to the first quarter of fiscal year 2006, coupled with lower rates.

Gas purchases in Natural Gas Operations decreased by $787,000 from $4,337,000 in the first quarter of fiscal year 2006 to $3,550,000 in the first quarter of fiscal year 2007. The decrease in gas cost reflects lower commodity prices during the current fiscal year.

Gross margin, which is defined as operating revenues less gas purchased, was approximately $2,199,000 for the first quarter of fiscal year 2007 compared to approximately $1,978,000 in the first quarter of fiscal year 2006. The increase of $221,000 is primarily due to a change in the rate design put into effect September 1, 2005. This rate design changed the structure of our rates, increasing the customer charge, and evening out our revenue stream. This had the result of increasing our gross margin for the first quarter of fiscal year 2007 over the first quarter of fiscal year 2006. Over the course of the year, this change in gross margin is neutral.

Natural Gas Operating Expenses— Natural Gas Segment’s operating expenses were approximately $2,259,000 for the first quarter of fiscal year 2007 as compared to $2,284,000 for first quarter of fiscal year 2006. The $34,000 reduction is due to a $104,000 decrease in payroll and other general and administrative expenses resulting from the implementation of cost-saving measures, and $2,000 in lower maintenance charges, partially offset by increases in depreciation, administrative charges, and taxes other than income taxes of $3,000, $71,000 and $9,000, respectively.

Natural Gas Other Income— Other income decreased by $5,000 from $66,000 in the first quarter of fiscal year 2006 to $61,000 in the first quarter of fiscal year 2007. This was due primarily to slightly decreased service sales in Great Falls.

Natural Gas Interest Expense— Interest expense was $2,000 lower in the first quarter of fiscal year 2007 primarily due to lower short-term borrowings.

Natural Gas Income Tax Benefit— Income tax benefits are $95,000 lower in the first quarter of fiscal year 2007 due to lower pretax loss.

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Operating Results of our Propane Operations

	Three Months Ended
	September 30,
	2006			2005
Propane Operations
Operating revenues	$	1,173,864		$	997,982
Gas purchased		729,720			550,763
Gross margin		444,144			447,219
Operating expenses		693,850			698,936
Operating (loss)		(249,706	)		251,717
Other income		17,247			31,094
Loss before interest and taxes		(232,459	)		(220,623	)
Interest (expense)		(100,529	)		(106,606	)
Loss before income taxes		(332,988	)		(327,229	)
Income tax benefit		123,365			131,816
Net (loss)		($209,623	)		($195,413	)

Fiscal Quarter Ended September 30, 2006 Compared to Fiscal Quarter Ended September 30, 2005

Propane Revenue and Gross Margins— Propane Operations’ revenues increased $176,000 from $998,000 for the first quarter of fiscal year 2006 to $1,174,000 for the first quarter of fiscal year 2007 as a result of the implementation on July 1, 2006 of a $.55 per therm surcharge for the collection of prior under-recovered gas costs. Gas purchased increased from $551,000 to $730,000 for the same period due also to the recognition of costs associated with prior under-recovered costs. Gross margin decreased $3,000, from $447,000 for the first quarter of fiscal year 2006 to $444,000 for the first quarter of fiscal year 2004. Although costs increased due to the collection of the surcharge, revenues also increased at the same rate, resulting in no change to gross margin.

Propane Operating Expenses— Operating expenses were $694,000 in the first quarter of fiscal year 2007 compared to $699,000 in the first quarter of fiscal year 2006. This decrease of $5,000 is due to decreases in general and administrative costs of $27,000, maintenance of $5,000, and depreciation of $14,000, offset by increases in administrative allocations of $38,000 and taxes other than income taxes of $4,000.

Propane Other Income— Other income decreased by $14,000 from $31,000 for the first quarter of fiscal year 2006 to $17,000 for the first quarter of fiscal year 2007. In the first quarter of fiscal year 2006, RMF had both interest income from a note receivable generated with the sale of assets in August 2003. Included with this sale was a contract for consulting fees. This note was paid in full in July 2005, resulting in approximately $7,000 of interest and consulting income in fiscal year 2006 that was not repeated in fiscal year 2007. The payoff also included the elimination of consulting fee income for RMF. In addition, EWP Arizona recognized gain from a sale leaseback in the first quarter of fiscal year 2006 that was not repeated in the first quarter of fiscal year 2007.

Propane Interest Expense— Interest expense decreased by $6,000 from $107,000 in the first quarter of fiscal year 2006 to $101,000 for the first quarter of fiscal year 2007, primarily due to lower short-term borrowings.

Propane Income Tax Benefit— Pretax loss for both the first quarter of fiscal year 2006 and the first quarter of fiscal year 2007 was constant, resulting in a comparable tax benefit.

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Operating Results of our EWR Operations

	Three Months Ended
	September 30,
	2006			2005
Energy West Resources (“EWR”)
Operating revenues	$	2,607,609		$	2,869,832
Gas purchased		2,150,799			2,741,469
Gross margin		456,810			128,363
Operating expenses		120,610			274,509
Operating income (loss)		336,200			(146,146	)
Other income		—			14,149
Income (loss) before interest and taxes		336,200			(131,997	)
Interest (expense)		(35,676	)		(47,276	)
Income (loss) before income taxes		300,524			(179,273	)
Income tax (expense) benefit		(116,347	)		69,754
Net income (loss)	$	184,177			($109,519	)

Fiscal Quarter Ended September 30, 2006 Compared to Fiscal Quarter Ended September 30, 2005

EWR Revenues and Gross Margins— Revenues in EWR decreased $262,000 from $2,870,000 in the first quarter of fiscal year 2006 to $2,608,000 in the first quarter of fiscal year 2007. Retail gas revenues decreased by $191,000 and mark to market revenues decreased by $78,000. Both of these decreases are explained by the much lower index prices for natural gas in the first quarter of fiscal year 2007 versus the first quarter of fiscal year 2006.

EWR’s first quarter of fiscal year 2007 gross margin of $457,000 represents an increase of $328,000 from gross margin earned in the first quarter of fiscal year 2006. Gross margin from gas production increased by $142,000 because the price received for the gas produced was re-negotiated from a low fixed price to an index based price. Gross margin from retail gas sales increased by $264,000. Several fixed price sales contracts expired in the second half of fiscal year 2006 and were replaced by more favorable index based contracts, resulting in higher margins. These increases are offset by the $78,000 decrease in mark to market revenue mentioned above.

EWR Operating Expenses— Operating expenses in EWR decreased approximately $154,000, from $275,000 for first quarter of fiscal year 2006 to $121,000 for the first quarter of fiscal year 2007. Approximately $115,000 of this savings is due to a wrongful termination settlement expensed in the first quarter of fiscal year 2006. The remainder includes reductions in depreciation, taxes other than income taxes, and general administrative expenses.

EWR Other Income— Other income decreased by $14,000 due to income from the settlement of a contract dispute in the first quarter of fiscal year 2006 that was not repeated in the first quarter of fiscal year 2007.

EWR Interest Expense— Interest expense decreased by $12,000 due to a decrease in short-term borrowings.

EWR Income Tax Benefit (Expense)— Income tax expense in the first quarter of fiscal year 2007 is $116,000, a $186,000 increase from the tax benefit of $70,000 in the first quarter of fiscal year 2006 due to higher pretax income. The first quarter of fiscal year 2006 had a pretax loss, resulting in a tax benefit.

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Operating Results of our Pipeline Operations

	Three Months Ended
	September 30,
	2006			2005
Pipeline Operations
Operating revenues	$	99,438		$	108,208
Gas purchased		—			—
Gross margin		99,438			108,208
Operating expenses		39,691			46,513
Operating income		59,747			61,695
Other income (loss)		—			—
Income before interest and taxes		59,747			61,695
Interest (expense)		(8,221	)		(10,371	)
Income before income taxes		51,526			51,324
Income tax (expense)		(19,813	)		(19,928	)
Net income	$	31,713		$	31,396

Fiscal Quarter Ended September 30, 2006 Compared to Fiscal Quarter Ended September 30, 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 from $108,000 in the first quarter of fiscal year 2006 to $99,000 in the first quarter of fiscal year 2007. The decrease of $8,000 was due to a decrease in gathering volumes on the Glacier gathering line.

Pipeline Operating Expenses— Operating expenses decreased $7,000 from $47,000 in the first quarter of fiscal year 2006 to $40,000 in the first quarter of fiscal year 2007. Decreases in general and administrative costs of $4,000 coupled with savings in taxes other than income taxes of $4,000 were offset by an increase of $1,000 in overhead costs.

Pipeline Interest Expense— Interest expense decreased from $10,000 in the first quarter of fiscal year 2006 to $8,000 in the first quarter of fiscal year 2007 due to a decrease in short-term borrowings.

Pipeline Income Tax (Expense)— Income tax expense remained constant at $20,000 in the first quarter of both fiscal year 2006 and 2007. Pretax income also remained constant.

Consolidated Cash Flow Analysis

Sources and Uses of Cash

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

Our ability to maintain liquidity depends upon our $15,000,000 credit facility with LaSalle Bank, shown as line of credit on the accompanying balance sheets. Our use of the LaSalle credit facility decreased to $2,900,000 at September 30, 2006, compared with $5,200,000 at September 30, 2005. This $2,300,000 improvement reflects the fact that we generated a net loss of $195,000 in the first quarter fiscal year 2007 as compared to a net loss of $622,000 in the first quarter of fiscal year 2006. Several other items contributed to our favorable cash position, including a decrease in recoverable cost of gas purchases of $507,000, an increase in levelized billing payments of

20

$427,000, and an $825,000 increase in accounts payable. We finance our capital expenditures on an interim basis through the LaSalle credit facility. 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 operation and to acquire additional businesses or assets on favorable terms as and when those opportunities arise.

Long-term debt decreased to $17,495,000 at September 30, 2006, compared with $18,577,000 at September 30, 2005. This $1,082,000 decrease resulted primarily from the scheduled principal payments of $515,000 on the Series 1993 notes, $90,000 on the Series 1992B notes and $400,000 on the term loan as provided for in the debt agreements.

Cash decreased by $1,176,000 from June 30, 2006 to September 30, 2006, compared with the $157,000 increase in cash for the first quarter ended September 30, 2005, as shown in the following table:

	September 30,
	2006			2005
Cash (used in) operating activities		($3,202,755	)	($	675,124	)
Cash (used in) investing activities		(606,400	)		(368,179	)
Cash provided by financing activities		2,632,981			1,200,000
Increase/(decrease) in cash		($1,176,174	)	$	156,697

Comparing cash used in operating activities for the quarter ended September 30, 2006, to the quarter ended September 30, 2005, cash used by operating activities increased $2,529,000. This was due to a decrease in net loss of $427,000, decrease in depreciation expense of $47,000, decrease in deferred income taxes of $598,000, decrease in accounts receivable of $2,728,000, an increase in the value of derivative assets of $237,000, a decrease in gas inventories of $501,000, an increase in accounts payable of $343,000 a decrease in derivative liabilities of $162,000, an decrease of deferred gain of $186,000, a decrease in recoverable gas costs of $33,000, a decrease in prepaid items of $300,000, and increase in cash used for other assets and liabilities of $10,000.

Comparing cash used in investing activities for the quarter ended September 30, 2006, to the quarter ended September 30, 2005, cash used by investing activities increased $237,000. This was due primarily to increased construction expenditures of $184,000, and reduced receipts from cash received from long term notes receivable of $175,000, offset by increases in cash received for advances for construction and contributions in aid of $122,000.

Comparing cash provided by financing activities for the quarter ended September 30, 2006, to the quarter ended September 30, 2005, cash provided by investing activities increased $1,433,000 due to increased advances on the line of credit of $1,600,000, and proceeds from the sale of stock of $106,000, and reduced payment of long-term debt of $23,000, offset by dividends paid of $296,000. The increased advances on the line of credit were not due to increased total borrowing. Our line of credit balance increased from $0 at June 30, 2006, to $2,900,000 at September 30,2006, compared to an increase of $1,300,000, from $3,900,000 at June 30, 2005 to $5,200,000 at September 30, 2005.

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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.

We maintain a $15.0 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 had an outstanding balance of $5.03 million at September 30, 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 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
Maximum borrowing	$	2,900,000
Average borrowing	$	282,000
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 250 basis points, for interest periods we select. For all other balances outstanding under the LaSalle credit facility, we pay interest at the rate publicly announced from time to time by LaSalle as its “Prime Rate.” For the term loan with LaSalle, we may elect to pay interest at either the applicable LIBOR rate plus 350 basis points or at the Prime Rate plus 200 basis points.

The LaSalle credit facility requires us to maintain compliance with a number of financial covenants, including meeting limitations on annual capital expenditures, maintaining a total debt to total capital ratio of not more than .70 to 1.00, and maintaining an interest coverage ratio of no less than 2.00 to 1.00. The LaSalle credit facility also restricts our ability to pay dividends during any period to a certain percentage of our cumulative earnings over that period, and restricts open positions and Value at Risk (VaR) in our wholesale operations. At September 30, 2005 and at September 30, 2006, we were in compliance with the financial covenants under the LaSalle credit facility.

At September 30, 2006, we had approximately $463,000 of cash on hand. In addition, at September 30, 2006, we had borrowed approximately $2.9 million under the LaSalle credit facility. Our short-term borrowings under our

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lines of credit during the first quarter of fiscal year 2007 had a daily weighted average interest rate of 8.25% per annum. At September 30, 2006, we had no outstanding letters of credit related to electricity and gas purchase contracts. We had net availability at September 30, 2006, of approximately $12,100,000 under the LaSalle credit facility revolving line of credit. As discussed above, our short-term borrowing needs for purchases of gas inventory and capital expenditures are greatest during the summer and fall months. Our availability normally increases in January as monthly heating bills are paid and gas purchases are no longer necessary.

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

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

In the event that our obligations under the LaSalle credit facility were declared immediately due and payable as a result of an event of default, such acceleration also could result in events of default under our Series 1993 Notes and Series 1997 Notes. In such circumstances, an event of default under either series of notes would occur if (a) we were given notice to that effect either by the trustee under the indenture governing such series of notes, or the holders of at least 25% in principal amount of the notes of such series then outstanding, and (b) within 10 days after such notice from the trustee or the note holders, the acceleration of our obligations under the LaSalle credit facility has not been rescinded or annulled and the obligations under the LaSalle credit facility have not been discharged. There is no similar cross-default provision with respect to the Cascade County, Montana Series 1992B Industrial Development Revenue Bonds and the related Loan Agreement between the Company and Cascade County, Montana. If our obligations were accelerated under the terms of any of the LaSalle credit facility, the Series 1993 Notes or the Series 1997 Notes, such acceleration (unless rescinded or cured) could result in a loss of liquidity and cause a material adverse effect on the Company and our financial condition.

The total amount outstanding under all of our long term debt obligations was approximately $18.6 million and $19.6 million at September 30, 2006 and September 30, 2005, respectively. The portion of such obligations due within one year was approximately $1.09 million and $1.01 million at September 30, 2006, and September 30, 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. The fair value of the interest rate swap was $60,039 and is recorded as a derivative asset on the accompanying financial statements.

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The table below presents contractual balances of our consolidated long-term and short-term debt at the expected maturity dates as well as the fair value of those instruments on September 30, 2006.

Payments Due by Period

			1 year						After
Contractual Obligations	Total		or less		2-3 years		4-5 years		5 years
Interest payments (a)	$	6,813,706	$	1,412,315	$	2,438,654	$	1,793,162	$	1,169,575
Long Term Debt (b)		18,585,709		1,090,709		5,415,000		260,000		11,820,000
Operating Lease Obligations		421,692		144,624		182,568		94,500		—
Transportation and Storage Obligation (c)		14,660,047		4,367,715		8,517,792		1,774,540		—
Total Obligations	$	40,481,154	$	7,015,363	$	16,554,014	$	3,922,202	$	12,989,575

(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)	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 – Our company and its subsidiaries are subject to certain risks related to changes in certain commodity prices and risks of counterparty performance. Our company has established policies and procedures to manage such risks. Our company has 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.

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As of September 30, 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	$	21,607	$	21,778
Contracts maturing during fiscal years 2008 and 2009		60,039		—
Contracts maturing during fiscal years 2010 and beyond		—		—
Total	$	81,646	$	21,778

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 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 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.

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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 6 — EXHIBITS

Exhibit
Number	Description
10.1	Asset Purchase Agreement, dated as of July 17, 2006, by and between Energy West, Incorporated and Energy West Propane, Inc., each entity being a Montana corporation, and SemStream, L.P., a Delaware limited partnership. Exhibit 10.1 to the registrant’s Current Report on Form 8-K dated July 17, 2006, is incorporated herein by reference.
10.2	Employment Agreement between Energy West, Incorporated and Kevin J. Degenstein, effective September 18, 2006. Exhibit 10.2 to the registrant’s Current Report on Form 8-K dated September 18, 2006, is incorporated herein by reference.
10.3	Separation Agreement dated September 18, 2006, between Energy West, Incorporated and Tim Good. Exhibit 10.3 to the registrant’s Current Report on Form 8-K dated September 28, 2006, is incorporated herein by reference.
10.4	Separation Agreement dated September 27, 2006, between Energy West, Incorporated and John C. Allen. Exhibit 10.4 to the registrant’s Current Report on Form 8-K dated September 28, 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

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SIGNATURES

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

	ENERGY WEST, INCORPORATED
	/s/ Wade F. Brooksby
	Wade F. Brooksby
November 14, 2006	Chief Financial Officer (principal financial officer and principal accounting officer)

Exhibit Index

Exhibit
Number	Description
10.1	Asset Purchase Agreement, dated as of July 17, 2006, by and between Energy West, Incorporated and Energy West Propane, Inc., each entity being a Montana corporation, and SemStream, L.P., a Delaware limited partnership. Exhibit 10.1 to registrant’s Current Report on Form 8-K dated July 17, 2006, is incorporated herein by reference.
10.2	Employment Agreement between Energy West, Incorporated and Kevin J. Degenstein, effective September 18, 2006. Exhibit 10.2 to the registrant’s Current Report on Form 8-K dated September 18, 2006, is incorporated herein by reference.
10.3	Separation Agreement dated September 18, 2006, between Energy West, Incorporated and Tim Good. Exhibit 10.3 to the registrant’s Current Report on Form 8-K dated September 28, 2006, is incorporated herein by reference.
10.4	Separation Agreement dated September 27, 2006, between Energy West, Incorporated and John C. Allen. Exhibit 10.4 to the registrant’s Current Report on Form 8-K dated September 28, 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