Gas Natural 10-Q 2007 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 endedSeptember 30, 2007

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.     þ Yes      o No

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).          o Yes      þ No

The number of shares outstanding of the registrant’s common stock as of November 9, 2007 was 2,857,952 shares.

As used in this Form 10-Q, the terms “company”, “Energy West”, “Registrant”, “we”, “us”, and “our” mean Energy West, Incorporated and its consolidated subsidiaries as a whole, unless the context indicates otherwise. Except as otherwise stated, the information in this Form 10-Q is as of September 30, 2007.

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, 2007, September 30, 2006 and June 30, 2007	3
Condensed Consolidated Statements of Operations - three months ended September 30, 2007 and 2006	4
Condensed Consolidated Statements of Cash Flows - three months ended September 30, 2007 and 2006	5
Notes to Condensed Consolidated Financial Statements	6
Item 2 - Management’s Discussion and Analysis of Financial Condition and Results of Operations	16
Item 3 – Quantitative and Qualitative Disclosures about Market Risk	26
Item 4 – Controls and Procedures	27
Part II – Other Information
Item 6 – Exhibits	27
Signatures
EX-10.1
EX-10.2
EX-10.3
EX-10.4
EX-10.5
EX-10.6
EX-31.1
EX-31.2
EX-32.1
EX-32.2

1

PART I – FINANCIAL INFORMATION

ITEM 1 – FINANCIAL STATEMENTS.

2

ENERGY WEST INCORPORATED AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS, SEPTEMBER 30, 2007 AND 2006, AND JUNE 30, 2007

	September 30,				June 30,
	(unaudited)				(audited)
	2007		2006		2007
ASSETS
Current Assets:
Cash	$	1,448,603	$	463,404	$	7,010,020
Accounts and notes receivable less $81,867, $265,239 and $64,054, respectively, allowance for bad debt		2,560,927		3,254,429		3,532,083
Unbilled gas		747,467		973,013		649,939
Derivative assets		43,870		81,646		57,847
Natural gas and propane inventories		8,633,115		9,789,852		5,474,309
Materials and supplies		428,417		461,820		377,296
Prepayments and other		397,723		258,178		142,964
Income tax receivable		438,466		410,976		162,432
Recoverable cost of gas purchases		1,197,542		—		307,899
Deferred tax asset		—		—		53,370
Assets held for sale		—		12,089,040		—
Total current assets		15,896,130		27,782,358		17,768,159
Property, Plant and Equipment, Net		30,792,443		30,062,503		30,473,991
Deferred Charges		3,003,029		3,977,462		3,031,425
Other Investments		766,113		—		—
Other Assets		700,972		333,778		560,463
TOTAL ASSETS	$	51,158,687	$	62,156,101	$	51,834,038
LIABILITIES AND CAPITALIZATION
Current Liabilities:
Accounts payable	$	2,977,079	$	4,655,217	$	4,543,525
Current portion of long-term debt		—		1,090,709		—
Line of credit		—		2,900,000		—
Derivative liabilities		44,040		21,778		58,018
Deferred income taxes		225,731		2,937		—
Accrued and other current liabilities		4,205,536		4,582,892		3,092,726
Recoverable cost of gas purchases				398,349
Liabilities held for sale		—		1,305,207		—
Total current liabilities		7,452,386		14,957,089		7,694,269
Other Obligations:
Deferred income taxes		4,511,474		6,295,292		4,585,170
Deferred investment tax credits		265,893		286,955		271,158
Other long-term liabilities		4,021,496		4,340,676		3,987,731
Total		8,798,863		10,922,923		8,844,059
Long-Term Debt		13,000,000		17,495,000		13,000,000
Commitments and Contingencies (see note 12)
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, 2,856,386, 2,946,677 and 2,859,104 shares outstanding at September 30, 2007 and 2006, and June 30, 2007 respectively		428,260		442,002		428,866
Capital in excess of par value		6,078,147		7,738,599		6,082,159
Retained earnings		15,401,031		10,600,488		15,784,685
Total stockholders’ equity		21,907,438		18,781,089		22,295,710
TOTAL CAPITALIZATION		34,907,438		36,276,089		35,295,710
TOTAL LIABILITIES AND CAPITALIZATION	$	51,158,687	$	62,156,101	$	51,834,038

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

3

ENERGY WEST, INCORPORATED AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2007 AND 2006

	Three Months Ended
	September 30,
	(unaudited)
	2007			2006
REVENUES:
Natural gas operations	$	5,021,222		$	5,728,002
Gas and electric—wholesale		2,378,688			2,628,955
Pipeline operations		93,465			99,438
Total revenues		7,493,375			8,456,395
EXPENSES:
Gas purchased		2,831,652			3,528,698
Gas and electric—wholesale		1,986,336			2,169,594
Total cost of sales		4,817,988			5,698,292
GROSS MARGIN		2,675,387			2,758,103
Distribution, general, and administrative		1,602,981			1,548,870
Maintenance		154,418			122,731
Depreciation and amortization		432,689			429,485
Taxes other than income		367,895			330,546
Total expenses		2,557,983			2,431,632
OPERATING INCOME		117,404			326,471
OTHER INCOME		87,750			60,966
INTEREST EXPENSE		(200,243	)		(376,311	)
INCOME FROM CONTINUING OPERATONS BEFORE INCOME TAX EXPENSE		4,911			11,126
INCOME TAX BENEFIT (EXPENSE)		69,898			(6,329	)
INCOME FROM CONTINUING OPERATIONS		74,809			4,797
DISCONTINUED OPERATIONS:
Loss from discontiued operations		—			(322,710	)
Income tax benefit		—			123,405
LOSS FROM DISCONTINUED OPERATIONS		—			(199,305	)
NET INCOME (LOSS)	$	74,809		$	(194,508	)
BASIC INCOME (LOSS) PER COMMON SHARE:
Income from continuing operations	$	0.03		$	0.00
Income (loss) from discontinued operations	$	—		$	(0.07	)
	$	0.03		$	(0.07	)
DILUTED INCOME (LOSS) PER COMMON SHARE:
Income from continuing operations	$	0.03		$	0.00
Income (loss) from discontinued operations	$	—		$	(0.07	)
	$	0.03		$	(0.07	)
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:
Basic		2,855,065			2,939,534
Diluted		2,892,215			2,939,534

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, 2007 AND 2006

	Three Months Ended
	September
	(unaudited)
	2007			2006
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	74,809		$	(194,508	)
Adjustments to reconcile net income (loss) to net cash used in operating activities:
Depreciation and amortization, including deferred charges and financing costs		489,931			581,691
Derivative assets		13,977			56,219
Derivative liabilities		(13,978	)		(20,886	)
Deferred gain		(61,381	)		(61,380	)
Investment tax credit		(5,265	)		(5,265	)
Deferred income taxes		205,405			(217,796	)
Changes in assets and liabilities:
Accounts and notes receivable		873,628			464,473
Natural gas and propane inventories		(3,158,806	)		(4,931,253	)
Accounts payable		(1,682,048	)		1,083,160
Recoverable/refundable cost of gas purchases		(889,643	)		477,860
Prepayments and other		(254,759	)		3,586
Net assets held for sale					50,495
Other assets & liabilities		774,543			(620,049	)
Net cash used in operating activities		(3,633,587	)		(3,333,653	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Construction expenditures		(785,761	)		(634,561	)
Other investments		(766,113	)		—
Customer advances received for construction		48,506			160,798
Increase (decrease) from contributions in aid of construction		38,619			(1,739	)
Net cash used in investing activities		(1,464,749	)		(475,502	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Repayments of long-term debt		—			(77,504	)
Proceeds from lines of credit		—			2,900,000
Repurchase of common stock		(145,892	)
Sale of common stock		141,274			106,138
Dividends paid		(458,463	)		(295,653	)
Net cash provided by (used in) financing activities		(463,081	)		2,632,981
NET DECREASE IN CASH AND CASH EQUIVALENTS		(5,561,417	)		(1,176,174	)
CASH AND CASH EQUIVALENTS:
Beginning of period		7,010,020			1,639,578
End of period	$	1,448,603		$	463,404

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

5

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

September 30, 2007

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, 2007 are not necessarily indicative of the results that may be expected for the fiscal year ending June 30, 2008. 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, 2007.

Energy West, Incorporated is a regulated public utility, with certain non-utility operations conducted through its subsidiaries. We were originally incorporated in Montana in 1909. We currently have four reporting segments:

•	Natural Gas Operations	Distributes approximately 6.4 billion cubic feet of natural gas to approximately 34,000 customers through regulated utilities operating in and around Great Falls and West Yellowstone, Montana, and Cody, Wyoming. The approximate population of the service territories is 94,000.
•	Marketing Operations	Markets approximately 1.6 billion cubic feet of natural gas to commercial and industrial customers in Montana and Wyoming and manages midstream supply and production assets for transportation customers and utilities through its subsidiary, Energy West Resources (“EWR”). EWR has an ownership interest in 165 natural gas producing wells and gas gathering assets. Missouri River Propane (“MRP”), our small Montana wholesale distribution company that sells propane to our affiliated utility, had been reported in Propane Operations. It is now being reported in marketing operations. In addition, during the first quarter of fiscal year 2008, EWR invested in 26.7% of the membership interests of Kykuit Resources, LLC (“Kykuit”), a developer and operator of oil, gas and mineral leasehold estates located in Montana. The equity method of accounting is used to account for income and losses from this investment. There was no material gain or loss in the first quarter of fiscal year 2008.
•	Pipeline Operations (EWD)	Owns the Shoshone interstate and the Glacier gathering natural gas pipelines located in Montana and Wyoming. Certain natural gas producing wells owned by our pipeline operations are being managed and reported under its marketing operations.
•	Propane Operations (Discontinued Operations)	Annually distributed approximately 5.4 million gallons of propane to approximately 8,000 customers through utilities operating underground vapor systems in and around Payson, Pine, and Strawberry, Arizona and retail distribution of bulk propane to approximately 2,300 customers in the same Arizona communities. The Arizona assets were sold during fiscal year 2007, and the results of operations for the propane assets related to this sale have been reclassified as income from discontinued operations. The associated assets and liabilities are shown on the consolidated balance sheet as “Assets held for sale” and “Liabilities held for sale”. See Note 4. MRP, our small Montana wholesale distribution company that sells propane to our affiliated utility, had been reported in propane operations. It is now being reported in its marketing operations.

6

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 2008, the Company has not entered into any new contracts requiring mark-to-market accounting under Statement of Financial Accounting Standards (“SFAS”) No. 133Accounting for Derivative Instruments and Hedging Activities(“SFAS No. 133”). However, existing derivatives as of September 30, 2007 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 2009	$	43,870	$	44,040

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, 2007, the Company’s regulated operations have no contracts meeting the mark-to-market accounting requirements.

7

NOTE 2 – INCOME TAX EXPENSE (BENEFIT)

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

	Three Months Ended
	September 30
	(unaudited)
	2007			2006
Income tax from continuing operations:
Tax expense at statutory rate of 34%	$	1,670		$	3,783
State income tax expense, net of federal tax expense		229			519
Amortization of deferred investment tax credits		(5,265	)		(5,265	)
Other		(66,533	)		7,292
Total income tax expense (benefit) from continuing operations		(69,899	)		6,329
Income tax from discontinued operations:
Tax benefit at statutory rate of 34%		—			(105,939	)
State income tax benefit, net of federal tax benefit		—			(14,520	)
Other		—			(2,946	)
Total income tax benefit from discontinued operations		—			(123,405	)
Total income tax benefit	$	(69,899	)	$	(117,076	)

Other tax benefit for fiscal year 2008 includes an adjustment for prior year actual tax expense from amounts that had been estimated and accrued.

In July 2006, the FASB issued FASB Interpretation No. 48,“Accounting for Uncertainty in Income Taxes — An Interpretation of FASB Statement No. 109”(“FIN 48”). FIN 48 prescribes detailed guidance for the financial statement recognition, measurement and disclosure of uncertain tax positions recognized in an enterprise’s financial statements in accordance with SFAS No. 109,“Accounting for Income Taxes.”Tax positions must meet a more-likely-than-not recognition threshold at the effective date to be recognized upon the adoption of FIN 48 and in subsequent periods. FIN 48 will be effective for fiscal years beginning after December 15, 2006 and the provisions of FIN 48 will be applied to all tax positions upon initial adoption of the Interpretation, which for us is our fiscal year commencing July 1, 2007. Upon the adoption of FIN 48, the Company had no unrecognized tax benefits that would have a material impact to the Company’s financial statements for any open tax years. During the first quarter of 2007, no adjustments were recognized for uncertain tax positions.

The Company recognizes interest accrued related to unrecognized tax benefits in interest expense and penalties in operating expense. No interest and penalties related to unrecognized tax benefits were accrued at September 30, 2007.

The tax years 2002 through 2006 remain open to examination by the major taxing jurisdictions in which we operate, although no material changes to unrecognized tax positions are expected within the next twelve months.

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 credit facility with LaSalle Bank, N.A. (“LaSalle”). 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.

8

On June 29, 2007, the Company replaced its existing credit facility and long-term notes with a new $20.0 million revolving credit facility with LaSalle, and issued $13.0 million of 6.16% Senior unsecured notes. The prior LaSalle credit facility had been secured, on an equal and ratable basis with our previously outstanding long-term debt, by substantially all of our assets.

LaSalle Line of Credit— On June 29, 2007, the Company established its new five-year unsecured credit facility with LaSalle, replacing a previous $20 million one-year facility with LaSalle which was scheduled to expire in November 2007. The new credit facility includes an annual commitment fee equal to 0.20% of the unused portion of the facility and interest on amounts outstanding at the London Interbank Offered Rate, plus 120 to 145 basis points, for interest periods selected by the Company.

Long-term Debt—$13.0 million 6.16% Senior Unsecured Notes— On June 29, 2007, the Company authorized the sale of $13.0 million aggregate principal amount of its 6.16% Senior Unsecured Notes, due June 29, 2017. The proceeds of these notes were used to refinance our existing notes. With this refinancing, we expensed the remaining debt issue costs of $991,000 in fiscal 2007, and incurred approximately $400,000 in new debt issue costs to be amortized over the life of the new note.

Debt Covenants— The Company’s 6.16% Senior Unsecured Note and LaSalle credit facility agreements contain various covenants, which include, among others, limitations on total dividends and distributions made in the immediately preceding 60-month period to 75% of aggregate consolidated net income for such period, restrictions on certain indebtedness, limitations on asset sales, and maintenance of certain debt-to-capital and interest coverage ratios. At September 30, 2007, the Company believes it is in compliance with the financial covenants under its new debt agreements, and was in compliance with its’ existing covenants at September 30, 2006.

At September 30, 2007, the Company had approximately $1.4 million of cash on hand. In addition, at September 30, 2007, the Company had no borrowings under the LaSalle Facility revolving line of credit. The Company’s net availability at September 30, 2007, was $20.0 million under the LaSalle Facility revolving line of credit.

The total amount outstanding under all of the Company’s long-term debt obligations was $13.0 million and approximately $17.5 million at September 30, 2007, and September 30, 2006, respectively. The portion of such obligations due within one year was $0 and $1.1 million at September 30, 2007, and September 30, 2006, respectively.

NOTE 4 – DISCONTINUED OPERATIONS

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 in the same geographic area (the “Non-Regulated Business,” and together with the Regulated Business, the “Business”).

Pursuant to the Purchase and Sale Agreement, the sale was conditioned on approval by the Arizona Corporation Commission, or “ACC”, with the closing to occur on the first day of the month after receipt of ACC approval. This approval was received on March 13, 2007, and the closing date of the transaction was April 1, 2007.

SemStream purchased only the assets and business operations of our Company and EWP that pertain to the Business within the state of Arizona, and that also 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 paid a cash purchase price of $15.0 million for the Arizona Assets, plus final working capital adjustments of approximately $3.0 million.

The assets and liabilities of the discontinued operations are presented separately under the captions “Assets Held for Sale” and “Liabilities Held for Sale”, respectively, in the accompanying Balance Sheets at September 30, 2006 and consist of the following:

9

Assets and Liablilities Held for Sale

	September 30, 2006
	(unaudited)
Assets held for sale:
Accounts receivable	$	333,541
Unbilled gas		340,419
Propane inventory		591,957
Materials and supplies		133,451
Prepayments		304,684
Recoverable cost of gas purchases		1,166,928
Property, plant and equipment, net		9,218,060
Total assets held for sale		12,089,040
Liablilities held for sale:
Accounts payable		139,355
Other current liabilities		518,855
Contributions in aid of construction		646,997
Total liabilities held for sale		1,305,207
Net assets held for sale	$	10,783,833

The following table details the line item “Income from Discontinued Operations” that appears on the face of the Statements of Operations for the three-month period ending September 30, 2006, as well as for the Propane Operations data appearing in Item 2.

	September 30, 2006
	(unaudited)
DISCONTINUED OPERATIONS:
REVENUES:
Propane operations	$	1,173,864
COST OF SALES:
Gas purchased		732,271
GROSS MARGIN		441,593
EXPENSES:
Distribution, general, and administrative		506,898
Maintenance		17,457
Depreciation and amortization		120,707
Taxes other than income		36,762
Total expenses		681,824
OPERATING LOSS		(240,231	)
OTHER INCOME		17,247
INTEREST (EXPENSE)		(99,726	)
LOSS FROM DISCONTINUED OPERATIONS BEFORE INCOME TAXES		(322,710	)
INCOME TAX BENEFIT		123,405
LOSS FROM DISCONTINUED OPERATIONS	$	(199,305	)

10

NOTE 5 — DEFERRED CHARGES

Deferred Charges consist of the following:

	Three Months Ended				Year Ended
	September 30,				June 30,
	(unaudited)				(audited)
	2007		2006		2007
Regulatory asset for property taxes	$	1,937,060	$	2,244,939	$	2,013,623
Regulatory asset for income taxes		452,645		458,753		452,646
Regulatory asset for deferred environmental remediation costs		242,080		324,989		247,617
Other regulatory assets		—		19,965		—
Unamortized debt issue costs		371,245		928,816		317,539
Total	$	3,003,030	$	3,977,462	$	3,031,425

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 6 — 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 (the “EPA”) has developed such 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, 2007, we had incurred cumulative costs of approximately $2.1 million in connection with our evaluation and remediation of the site. On May 30, 1995, we received an order from the Montana Public Service Commission (“MPSC”) allowing for recovery of the costs associated with the evaluation and remediation of the site through a surcharge on customer bills. As of September 30, 2007, we had recovered approximately $1.9 million through such surcharges. As of September 30, 2007, the cost remaining to be recovered through the on-going rate is $242,000.

We are required to file with the MPSC every two years for approval to continue the recovery of these costs through a surcharge. During fiscal 2007, the MPSC approved the continuation of the recovery of these costs with its order dated May 15, 2007.

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. Our marketing operation’s subsidiary 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.

11

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 7 — SEGMENTS OF OPERATIONS

	Three Months Ended
	September 30
	(unaudited)
	2007			2006
Gross margin (operating revenue less cost of gas purchased):
Natural gas operations	$	2,189,570		$	2,199,304
EWR		392,352			459,361
Pipeline operations		93,465			99,438
	$	2,675,387		$	2,758,103
Operating income (loss):
Natural gas operations	$	(146,060	)	$	(60,001	)
EWR		236,412			326,725
Pipeline operations		27,052			59,747
	$	117,404		$	326,471
Net income (loss):
Natural gas operations	$	(110,707	)	$	(204,775	)
EWR		169,341			177,859
Pipeline operations		16,175			31,713
Discontinued Operations		—			(199,305	)
	$	74,809		$	(194,508	)

NOTE 8 — ACCRUED AND OTHER CURRENT LIABILITIES

     Accrued and other current liabilities consist of the following:

	September 30,				June 30,
	(unaudited)				(audited)
	2007		2006		2007
Property tax settlement—current portion	$	243,000	$	243,000	$	243,000
Payable to employee benefit plans		32,936		66,588		132,131
Accrued vacation		227,072		261,678		224,588
Customer deposits		415,711		384,315		394,128
Accrued interest		165,476		462,270		9,069
Accrued taxes other than income		677,408		621,191		506,448
Deferred short-term gain		243,519		243,519		243,519
Customer prepayments from levelized billing		1,471,902		1,263,642		605,031
Other		728,511		1,036,689		734,812
Total	$	4,205,536	$	4,582,892	$	3,092,726

September 30, 2006 information presented differs from prior presentations due to the reclassification of certain propane items from “Accrued and other current liabilities” to “Liabilities held for sale”.

12

NOTE 9 — OTHER LONG TERM LIABILITIES

     Other long-term liabilities consist of the following:

	September 30,				June 30,
	(unaudited)				(audited)
	2007		2006		2007
Asset retirement obligation	$	697,836	$	659,690	$	688,371
Contribution in aid of construction		1,351,083		1,295,772		1,313,907
Customer advances for construction		653,727		438,643		605,221
Accumulated postretirement obligation		—		141,200		—
Deferred gain — long-term *		20,682		264,202		82,063
Regulatory liability for income taxes		83,161		83,161		83,161
Property tax settlement		1,215,008		1,458,008		1,215,008
Total	$	4,021,496	$	4,340,676	$	3,987,731

September 30, 2006 information presented differs from prior presentations due to the reclassification of certain propane items from “Accrued and other current liabilities” to “Liabilities held for sale”.

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

NOTE 10 – STOCK OPTIONS 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, 2007, there are 104,000 options outstanding, 68,000 shares issued under this plan have been exercised, and the maximum number of shares available for future grants under this plan is 28,000 shares. Additionally, our 1992 Stock Option Plan (the “1992 Option Plan”), which expired in September 2002, provided for the issuance of up to 100,000 shares of our common stock pursuant to options issuable to certain key employees. Under the 2002 Option Plan and the 1992 Option Plan (collectively, “the Option Plans”), 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, 100% of the fair market value if the employee owns more than 10% of our outstanding common stock). Pursuant to the Option Plans, the options vest over four to five years and are exercisable over a five to ten-year period from date of issuance. When the 1992 Option Plan expired in September 2002, 12,600 shares remained unissued and were no longer available for issuance.

SFAS No. 123 Disclosures— Effective July 1, 2005, we have adopted the provisions of SFAS No. 123Accounting for Stock-Based Compensation. The fair value of each option grant is estimated on the date of grant using the Black-Scholes option pricing.

In the fiscal quarters ended September 30, 2007 and 2006, 0 and 10,000 options were granted, respectively. At September 30, 2007 and 2006, a total of 104,000 and 155,500 options were outstanding, respectively.

13

	Three Months Ended
	September 30,
	2007			2006
Expected dividend rate		4.00	%		2.00	%
Risk free interest rate		5.00			4.87
Weighted average expected lives, in years		2.00			3.15
Price volatility		29.70	%		31.00	%
Total intrinsic value of options exercised	$	44,249		$	24,500
Total cash received from options exercised	$	40,841		$	106,125

A summary of the status of our stock option plans as of September 30, 2007, and June 30, 2007 and 2006 and changes during the periods ended on these dates is presented below.

				Weighted		Aggregate
	Number of			Average		Intrinsic
	Shares			Exercise Price		Value
Outstanding June 30, 2005		126,000		$	8.35
Granted		48,500		$	10.11
Exercised		(2,500	)	$	8.49
Expired		(26,500	)	$	0.00
Outstanding June 30, 2006		145,500		$	8.34
Granted		30,000		$	10.55
Exercised		(62,500	)	$	8.20
Expired		(3,000	)	$	0.00
Outstanding June 30, 2007		110,000		$	8.97
Granted		0		$	0.00
Exercised		(6,000	)	$	6.81
Expired		0		$	0.00
Outstanding September 30, 2007		104,000		$	9.10	$	197,853
Exerciseable September 30, 2007		65,000		$	8.37	$	435,192

The weighted average fair value of options granted during the quarters ending September 30, 2007 and 2006 was $0 and $2.09, respectively. There were no new options granted in the first quarter of fiscal year 2008.

The following information applies to options outstanding at September 30, 2007:

14

					Weighted
					Average
			Weighted		Remaining				Weighted
			Average		Contractual				Average
Grant	Number		Exercise		Life		Number		Exercise
Date	Outstanding		Price		(Years)		Exercisable		Price
11/21/2002		7,500	$	8.49		0.1		7,500	$	8.49
7/1/2004		10,000	$	6.47		6.8		0	$	6.47
4/1/2005		20,000	$	6.62		7.5		10,000	$	6.62
7/1/2005		15,000	$	9.85		7.8		20,000	$	9.85
10/4/2005		16,500	$	10.51		8.0		10,000	$	10.51
1/6/2006		5,000	$	9.52		3.3		7,500	$	9.52
7/1/2006		10,000	$	9.02		8.8		5,000	$	9.02
12/4/2006		20,000	$	11.32		9.2		5,000	$	11.32
		104,000						65,000

NOTE 11 – NEW ACCOUNTING PRONOUNCEMENTS

In March 2006, the FASB issued SFAS No. 156,Accounting for Servicing of Financial Assets—an amendment to FASB Statement No. 140(“SFAS 156”). SFAS 156 requires that all separately recognized servicing rights be initially measured at fair value, if practicable. In addition, this statement permits an entity to choose between two measurement methods (amortization method or fair value measurement method) for each class of separately recognized servicing assets and liabilities. This new accounting standard is effective January 1, 2007. We do not expect the adoption of SFAS 156 to have an impact on our results of operations or financial condition.

In July 2006, the FASB issued Interpretation No. 48,Accounting for Uncertainty in Income Taxes—an interpretation of FASB Statement No. 109 (“FIN 48”).This interpretation clarifies the application of SFAS 109 by defining a criterion than an individual tax position must meet for any part of the benefit of that position to be recognized in an enterprise’s financial statements and also provides guidance on measurement, derecognition, classification, interest and penalties, accounting in interim periods and disclosure. FIN 48 is effective for our fiscal year commencing July 1, 2007. We have completed our review and assessment of the impact of adoption of FIN 48. This is discussed in Note 2 – Income Tax Expense (Benefit).

In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements (“SFAS 157”). SFAS 157 defines fair value, establishes a framework and gives guidance regarding the methods used for measuring fair value, and expands disclosures about fair value measurements. SFAS 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. We are currently evaluating the impact of adopting SFAS 157 on our consolidated financial statements.

In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities (“SFAS 159”). SFAS 159 provides the option to report certain financial assets and liabilities at fair value, with the intent to mitigate volatility in financial reporting that can occur when related assets and liabilities are recorded on different bases. SFAS 159 also amends SFAS No. 115, Accounting for Certain Investments in Debt and Equity Securities,” by providing the option to record unrealized gains and losses on held-for-sale and held-to-maturity securities currently. The effective date of FAS 159 is for fiscal years beginning after November 15, 2007. The implementation of FAS 159 is not expected to have a material impact on our results of operations or financial position.

We have reviewed all other recently issued, but not yet effective, accounting pronouncements and do not believe any such pronouncements will have a material impact on our financial statements.

15

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

Such forward-looking statements, as well as other oral and written forward-looking statements made by or on behalf of us 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 our Annual Report on Form 10-K for the fiscal year ended June 30, 2007 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 us except as required by law.

Recent Events

On October 1, 2007, the Company consummated the acquisition of Frontier Utilities of North Carolina, Inc. (“Frontier Utilities”), which operates a natural gas utility in Elkin, North Carolina though its subsidiary, Frontier Energy, LLC. The purchase price was $4.5 million in cash, subject to adjustment for taxes and working capital. In addition, the Company entered into a stock purchase agreement to acquire all of the capital stock of Penobscot Natural Gas Company, Inc. (“Penobscot Natural Gas”) in February 2007 for a purchase price of $0.5 million, subject to adjustment for taxes and working capital. Penobscot Natural Gas is the parent company of Bangor Gas Company LLC, which operates a natural gas utility in Bangor, Maine. The acquisition of Penobscot Natural Gas is conditioned upon approval by the Maine Public Utilities Commission. We anticipate that the consummation of the acquisition of Penobscot Natural Gas will take place on or about December 1, 2007. To date, we have expended approximately $530,000 in exploratory, legal and other costs related to these acquisitions. This amount is recorded as Other Assets on the balance sheet.

On July 27, 2007, we invested $726,063 in Kykuit, and $40,050 on September 17, 2007. EWR owns 26.7% of the membership interests of Kykuit, a developer and operator of oil, gas and mineral leasehold estates located in Montana. Richard M. Osborne, our Chairman of the Board, and Steven A. Calabrese, one of our directors, also own interests in Kykuit. John D. Oil and Gas Company, a publicly-held oil and gas exploration company of which Mr. Osborne is the Chairman of the Board and Chief Executive Officer and Mr. Calabrese a director, is an owner and the managing member of Kykuit.

On August 3, 2007, Kykuit assumed a Lease Purchase and Sale Agreement dated March 21, 2007 with Hemus, Ltd. (“Hemus”) and the First Amendment to Lease Purchase and Sale Agreement dated July 24, 2007, collectively, the “Purchase Agreement.” The Purchase Agreement effected the sale by Hemus of a 75% interest in certain oil, gas and mineral leasehold estates located in Montana to Kykuit on August 3, 2007. Also effective August 3, 2007, Kykuit and Hemus executed a Joint Venture Development Agreement pursuant to which Kykuit agreed to develop and operate all of the leasehold interests covered by the Purchase Agreement. The purchase price paid by Kykuit pursuant to the Purchase Agreement and Assignment totaled $2,476,721.

Executive Overview

Our primary source of revenue and operating margin has been derived from the distribution of natural gas and propane to end-use residential, commercial, and industrial customers. The revenue from propane has ceased with the sale of our propane assets as of April 1, 2007. We also derive revenues by providing gas supply and load

16

management services to certain industrial and commercial customers through our gas marketing subsidiary on an “unregulated” basis.

We continue to focus on expanding and improving our core business – utility service, pipelines, and natural gas production. Significant cost reductions have helped us strengthen our balance sheet, increase net income, restore dividends to our shareholders and keep rates to our customers low. Earnings from continuing operations improved from a net loss of $195,000 in the first quarter of fiscal year 2007 to a net gain of $75,000 in the first quarter of fiscal year 2008. This was the result of operating efficiencies, and refinancing of our long-term debt in June 2007, reducing our interest costs, and a credit to tax expense to adjust prior year tax estimates to actual expense with the completion of the tax return.

We strive 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. 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. This sale was complete on April 1, 2007. We used the proceeds from this transaction to reduce our outstanding debt and strengthen our balance sheet. We believe that this will enable us 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 such as the acquisitions of Frontier Utilities and Penobscot Natural Gas discussed above in Recent Events.

Strategy

     The key elements of our current strategy include the following:

• the acquisition and expansion of our natural gas utility operations in small and emerging markets,

• cost-effective expansion of our existing 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 these customers,

• appropriate regulatory treatment of increases in the cost of natural gas,

• continuous improvement of our operational efficiencies,

• managing cash flow to reduce our existing debt, and

• maintaining and improving our positive reputation with our regulators and customers.

Opportunities and Challenges

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

• We possess many competitive strengths, including:

– Our demonstrated ability to operate successfully in smaller regional and emerging markets;

–  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 suppliers;

–  Our positive reputation with regulators and customers; and

–  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. 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.

17

• 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 us. Non-revenue-generating spending is also managed to assure that we use the most economically attractive solutions, while providing for a safe and reliable system.

• We are analyzing drilling opportunities within our gas production property located in north central Montana and drilling activities 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 primary markets in Montana and Wyoming historically have not experienced the rapid population growth rates experienced by other areas in the United States in recent years.

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

–  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 5.4% 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 three 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, 2007 Compared to Fiscal Quarter Ended September 30, 2006

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, 2007. The following gives effect to the unaudited Condensed Consolidated Financial Statements as of September 30, 2007 and for the three month period ended September 30, 2007. Results of operations for interim periods are not necessarily indicative of results to be attained for any future period.

Net Income (Loss)— Our net income for the first quarter of fiscal year 2008 was approximately $75,000 compared to a net loss of approximately $195,000 in the first quarter of fiscal year 2007, an improvement of $270,000. This improvement was primarily due to the elimination of the net loss in propane or discontinued operations of

18

approximately $199,000, and a decrease in interest expense due to the refinancing of our long-term debt. These improvements were coupled with a credit to tax expense of $78,000 from prior year tax return adjustments.

Revenues— Our revenues for the first quarter of fiscal year 2008 were approximately $7.5 million compared to approximately $8.5 million in the first quarter of fiscal year 2007, a decrease of $1.0 million. The decrease was primarily attributable to: (1) a decrease in our marketing operations’ production revenue of $70,000 caused by lower volumes produced in the first quarter of fiscal year 2008 versus fiscal year 2007 and a decrease in our marketing operations’ retail gas revenues of $141,000, caused by lower index prices in our Wyoming market, (2) a natural gas revenue decrease of $707,000 due primarily to slightly lower volumes, and (3) decreased revenues in our pipeline operations of $6,000 due to a decrease in gathering volumes on the Glacier line.

Gross Margin— Gross margin decreased $83,000, from approximately $2.8 million in the first quarter of fiscal year 2007 to approximately $2.7 million in the first quarter of fiscal year 2008. Our marketing operations’s margin decreased $67,000 due to a $174,000 decrease in margin from gas production as a result of lower volumes produced and higher gathering expenses. This was offset partially by an increase in gross margin from retail gas sales of $115,000 due to increased sales in our Wyoming market.

Our pipeline operations’ margins decreased $6,000 due to lower volumes on the Glacier line. Our natural gas operations’ margins decreased $10,000 due to slightly lower volumes.

Expenses Other Than Cost of Goods Sold— Expenses other than cost of sales increased by $126,000 in the first quarter of fiscal year 2008 as compared to the first quarter of fiscal year 2007. The primary reasons for this increase were (1) increases in the Company’s general and administrative costs of $54,000, including increases in wage and employee benefits with the addition of personnel and increases in costs for outside services, (2) increases in depreciation and amortization of $3,000, (3) increases in maintenance of $31,000, and (4) increases of $38,000 for taxes other than income.

Other Income— Other income increased by $27,000 from $61,000 in the first quarter of fiscal year 2007 to $88,000 in the first quarter of fiscal year 2008, all attributable to our natural gas operations.

Interest Expense— Interest expense decreased by approximately $176,000 during the first quarter of fiscal year 2008 from the first quarter of fiscal year 2007 due to a decrease in both short-term and long-term borrowings, and a decrease in amortization of debt issue costs due to the refinancing of our long-term debt.

Income Tax Benefits— Income tax benefits decreased $47,000 in the first quarter of fiscal year 2008 as compared to the first quarter of fiscal year 2007 due to a change from net loss before tax of $312,000 in 2007 to a net gain of $5,000 before tax in fiscal year 2008, coupled with an adjustment to tax expense of $78,000 for prior year actual tax expense from amounts that had been estimated and accrued.

Discontinued Operations

Formerly reported as our propane operations, we sold our Arizona propane assets as of April 1, 2007. A small portion of our propane operations was income and expense associated with Missouri River Propane (“MRP”), our unregulated Montana wholesale operation that supplies propane to our affiliated company reported in our natural gas operations. MRP is now being reported in our marketing operations.

Loss discontinued operations before income tax— There was no gain or loss from propane operations in fiscal year 2008 due to the timing of the sale of assets. In fiscal year 2007, there was a loss before income taxes of $323,000.

Income Tax Benefit— Income tax benefit decreased by $123,000 due to the timing of the sale of assets.

19

Operating Results of our Natural Gas Operations

	Three Months Ended
	September 30,
	2007			2006
Natural Gas Operations
Operating revenues	$	5,021,222		$	5,728,002
Gas purchased		2,831,652			3,528,698
Gross margin		2,189,570			2,199,304
Operating expenses		2,335,630			2,259,305
Operating loss		(146,060	)		(60,001	)
Other income		87,750			60,966
Income (loss) before interest and taxes		(58,310	)		965
Interest (expense)		(187,810	)		(331,611	)
Loss before income taxes		(246,120	)		(330,646	)
Income tax benefit		135,413			125,871
Net loss	$	(110,707	)	$	(204,775	)

Fiscal Quarter Ended September 30, 2007 Compared to Fiscal Quarter Ended September 30, 2006

Natural Gas Revenues and Gross Margins— The Natural Gas Operations’ operating revenues in the first quarter of fiscal year 2008 decreased to approximately $5.0 million from approximately $5.7 million in the first quarter of fiscal year 2007. This $707,000 decrease was primarily due to lower volumes in the first quarter of fiscal year 2008 compared to the first quarter of fiscal year 2007, coupled with overall lower rates.

Gas purchases in Natural Gas Operations decreased by $787,000 from approximately $3.5 million in the first quarter of fiscal year 2007 to approximately $2.8 million in the first quarter of fiscal year 2008. The decrease in gas cost reflects lower commodity prices during the current fiscal year, coupled with slightly lower volumes.

Gross margin was approximately $2.2 million for the first quarter of fiscal year 2008 compared to approximately $2.2 million in the first quarter of fiscal year 2007. The decrease of $10,000 is primarily due to slightly lower volumes in the current fiscal year.

Natural Gas Operating Expenses— Natural Gas Segment’s operating expenses were approximately $2.3 million for the first quarter of fiscal year 2008 as compared to approximately $2.3 million for first quarter of fiscal year 2007. The $77,000 increase is due to an $8,000 increase in payroll and other general and administrative expenses, and increases in maintenance and taxes other than income taxes of $30,000 and $38,000, respectively.

Natural Gas Other Income— Other income increased by $27,000 from $61,000 in the first quarter of fiscal year 2007 to $88,000 in the first quarter of fiscal year 2008. This was due primarily to increased service sales in Great Falls and Cody.

Natural Gas Interest Expense— Interest expense was $144,000 lower in the first quarter of fiscal year 2008 due to a decrease in both short-term and long-term borrowings, and a decrease in amortization of debt issue costs due to the refinancing of our long-term debt.

Natural Gas Income Tax Benefit— Income tax benefits are $10,000 lower in the first quarter of fiscal year 2008 due to lower pretax loss, coupled with an adjustment to tax expense for prior year actual tax expense from amounts that had been estimated and accrued.

20

Operating Results of our Marketing Operations

	Three Months Ended
	September 30,
	2007			2006
Energy West Resources
Operating revenues	$	2,378,688		$	2,628,955
Gas purchased		1,986,336			2,169,594
Gross margin		392,352			459,361
Operating expenses		155,940			132,636
Income before interest and taxes		236,412			326,725
Interest (expense)		(8,428	)		(36,479	)
Income before income taxes		227,984			290,246
Income tax (expense)		(58,643	)		(112,387	)
Net income	$	169,341		$	177,859

Fiscal Quarter Ended September 30, 2007 Compared to Fiscal Quarter Ended September 30, 2006

Marketing Revenues and Gross Margins— Revenues in EWR decreased $250,000 from approximately $2.6 million in the first quarter of fiscal year 2007 to approximately $2.4 million in the first quarter of fiscal year 2008. Retail gas revenues decreased by $141,000. Higher sales volumes in our Wyoming market combined with lower sales volumes in our Montana market caused our sales mix to be weighted more heavily to the Wyoming market where the index price for natural gas was much lower in the first quarter of fiscal year 2008 as compared to the first quarter of fiscal year 2007. Production revenues decreased by $70,000 primarily because of a 13.5% decrease in volumes produced in the first quarter of fiscal year 2008 versus the first quarter of fiscal year 2007. Revenue from electricity sales decreased by $39,000 due to the expiration of our last remaining electricity customer contract.

The gross margin in our marketing operations’ first quarter of fiscal year 2008 of $392,000 represents a decrease of $67,000 from gross margin earned in the first quarter of fiscal year 2007. Gross margin from gas production decreased by $174,000 due to the decrease in volumes produced and higher gathering expenses in the first quarter of fiscal year 2008 as compared to the first quarter of fiscal year 2007. This was partially offset by an increase in gross margin from retail gas sales of $115,000 due to increased sales in our Wyoming market.

Marketing Operating Expenses— Operating expenses in EWR increased approximately $23,000, from $133,000 for first quarter of fiscal year 2007 to $156,000 for the first quarter of fiscal year 2008. Increases in professional services, depreciation and depletion account for this change.

Marketing Interest Expense— Interest expense decreased by $28,000 due to a decrease in both short-term and long-term borrowings, and a decrease in amortization of debt issue costs due to the refinancing of our long-term debt.

Marketing Income Tax Expense— Income tax expense in the first quarter of fiscal year 2008 is $58,000, a $54,000 decrease from $112,000 in the first quarter of fiscal year 2007 due to lower pretax income, coupled with an adjustment to tax expense for prior year actual tax expense from amounts that had been estimated and accrued.

21

Operating Results of our Pipeline Operations

	Three Months Ended
	September 30,
	2007			2006
Pipeline Operations
Operating revenues	$	93,465		$	99,438
Gas purchased		—			—
Gross margin		93,465			99,438
Operating expenses		66,413			39,691
Income before interest and taxes		27,052			59,747
Interest (expense)		(4,005	)		(8,221	)
Income before income taxes		23,047			51,526
Income tax (expense)		(6,872	)		(19,813	)
Net income	$	16,175		$	31,713

Fiscal Quarter Ended September 30, 2007 Compared to Fiscal Quarter Ended September 30, 2006

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 $99,000 in the first quarter of fiscal year 2007 to $93,000 in the first quarter of fiscal year 2008. The decrease of $6,000 was due to a decrease in gathering volumes on the Glacier gathering line.

Pipeline Operating Expenses— Operating expenses increased approximately $26,000 from $40,000 in the first quarter of fiscal year 2007 to $66,000 in the first quarter of fiscal year 2008. Increases in general and administrative costs of $26,000 consisted primarily of costs associated with our FERC regulated Shoshone pipeline.

Pipeline Interest Expense— Interest expense decreased from $8,000 in the first quarter of fiscal year 2007 to $4,000 in the first quarter of fiscal year 2008 due to a decrease in both short-term and long-term borrowings, and a decrease in amortization of debt issue costs due to the refinancing of our long-term debt.

Pipeline Income Tax Expense— Income tax expense decreased from $20,000 in the first quarter of fiscal year 2007 to $7,000 in the first quarter of fiscal year 2008 due to a decrease in pretax income coupled with an adjustment to tax expense for prior year actual tax expense from amounts that had been estimated and accrued.

Discontinued Operations

	Three Months Ended
	September 30,
	2007		2006
Discontinued Operations:
Loss from discontinued operations before income tax	$	—	$	(322,710	)
Income tax benefit		—		123,405
Loss from discontinued operations	$	—	$	(199,305	)

Fiscal Quarter Ended September 30, 2007 Compared to Fiscal Quarter Ended September 30, 2006

Formerly reported as Propane Operations, we have sold our Arizona propane assets as of April 1, 2007. A small portion of our propane operation as previously reported was income and expense associated with MRP. MRP is now being reported in our EWR segment.

22

Loss from discontinued operations before income tax— There was no gain or loss from propane operations in fiscal year 2008 due to the timing of the sale of assets. In fiscal year 2007, there was a loss before income taxes of $323,000.

Income Tax (Expense)— Income tax expense decreased by $123,000 due to the timing of the sale of assets.

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 $20.0 million credit facility with LaSalle Bank, shown as line of credit on the accompanying balance sheets. Our use of the LaSalle credit facility decreased to $0 at September 30, 2007, compared with $2.9 million at September 30, 2006. This $2.9 million improvement reflects the fact that we generated net income of $75,000 in the first quarter fiscal year 2008 as compared to a net loss of $195,000 in the first quarter of fiscal year 2007, and decreased receivables and inventories. 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. On April 1, 2007 we sold certain of our assets related to our Arizona propane business for cash of approximately $15.0 million plus net working capital. We used 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 $13.0 million at September 30, 2007, compared with $17.5 million at September 30, 2006. This $4.5 million decrease resulted from scheduled principal payments on our notes, and the refinancing of our debt in June 2007. We used a portion on the proceeds from the sale of propane assets to further reduce our long-term debt.

Cash decreased by $5.6 million from June 30, 2007 to September 30, 2007, compared with the $1.2 million decrease in cash for the first quarter ended September 30, 2006, as shown in the following table:

	September 30,
	2007			2006
Cash used in operating activities	$	(3,633,587	)	$	(3,333,653	)
Cash used in investing activities		(1,464,749	)		(475,502	)
Cash provided by (used in )financing activities		(463,081	)		2,632,981
Decrease in cash	$	(5,561,417	)	$	(1,176,174	)

Cash used in operating activities was approximately $300,000 lower in the three months ended September 30, 2007, than the three months ended September 30, 2006. This was due to an overall decrease in other assets net of liabilities of $569,000, offset by an increase in net income of $269,000.

Cash used in investing activities was approximately $989,000 higher in the three months ended September 30, 2007, than the three months ended September 30, 2006. This was due to a 26.7% investment interest of $766,000 in Kykuit, a decrease in customer advances received for construction and contributions in aid of construction of $72,000, and an increase of $151,000 for construction expenditures.

Cash used in financing activities was approximately $3.1 million more in the three months ended September 30, 2007 than in the three months ended September 30, 2006 due to increased dividends paid of $163,000, decreased borrowings on the line of credit of $2.9 million, increased sale of common stock and adjustments for intrinsic value of options exercised of $35,000, decreased payment of long-term debt of $78,000, and an increase of repurchase of common stock of $146,000.

23

LIQUIDITY AND CAPITAL RESOURCES

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 our working capital line of credit. 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.

On June 29, 2007, we replaced our existing credit facility and long-term notes with a new $20.0 million revolving credit facility, and issued $13.0 million of 6.16% senior unsecured notes. The prior LaSalle credit facility had been secured, on an equal and ratable basis with our previously outstanding long-term debt, by substantially all of our assets.

Long-term Debt—$13.0 million 6.16% Senior Unsecured Notes— On June 29, 2007, we authorized the sale of $13.0 million aggregate principal amount of our 6.16% Senior Unsecured Notes, due June 29, 2017. The proceeds of these notes were used to refinance our existing notes. With this refinancing, we expensed the remaining debt issue costs of $991,000 in fiscal 2007, and incurred approximately $400,000 in new debt issue costs to be amortized over the life of the new note.

LaSalle Line of Credit— On June 29, 2007, we established our new five-year unsecured credit facility with LaSalle, replacing a previous $20.0 million one-year facility with LaSalle which was scheduled to expire in November 2007. The new credit facility includes an annual commitment fee equal to 0.20% of the unused portion of the facility and interest on amounts outstanding at the London Interbank Offered Rate, plus 120 to 145 basis points, for interest periods selected by us.

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

	First		Second		Third		Fourth
	Quarter		Quarter		Quarter		Quarter
Year Ended June 30, 2008
Minimum borrowing	$	—
Maximum borrowing	$	—
Average borrowing	$	—
Year Ended June 30, 2007
Minimum borrowing	$	—	$	2,900,000	$	—	$	—
Maximum borrowing	$	2,900,000	$	6,200,000	$	3,502,000	$	6,700,000
Average borrowing	$	282,000	$	4,384,000	$	392,000	$	485,000

     Our 6.16% Senior Unsecured Note and LaSalle credit facility agreements contain various covenants, which include, among others, limitations on total dividends and distributions made in the immediately preceding 60-month period to 75% of aggregate consolidated net income for such period, restrictions on certain indebtedness, limitations on asset sales, and maintenance of certain debt-to-capital and interest coverage ratios. At September 30, 2007 and 2006, we believe we were in compliance with the financial covenants under our debt agreements.

     At September 30, 2007, we had approximately $1.4 million of cash on hand. In addition, at September 30, 2007, we had no borrowings under the $20.0 million LaSalle revolving line of credit. At September 30, 2007, we had no outstanding letters of credit related to gas and electricity purchase contracts. 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 storage related gas purchases are no longer necessary.

     The total amount outstanding under all of our long term debt obligations was $13.0 million and $17.5 million at September 30, 2007 and September 30, 2006, respectively. The portion of such obligations due within one year was $0 at September 30, 2007, and approximately $1.1 million at September 30, 2006.

24

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.

The table below presents contractual balances of our consolidated long-term and short-term debt at the expected maturity dates as of September 30, 2007.

Payments Due by Period

									��
			1 year							After
Contractual Obligations	Total		or less		2-3 years		4-5 years			5 years
Interest payments (a)	$	8,008,000	$	800,800	$	1,601,600	$	1,601,600		$	4,004,000
Long Term Debt (b)		13,000,000		—		—		—			13,000,000
Operating Lease Obligations		75,520		75,520		—		—			—
Transportation and Storage Obligation (c)		10,401,151		4,367,715		6,033,436		—			—
Total Obligations	$	31,484,671	$	5,244,035	$	7,635,036	$	1,601,600		$	17,004,000

(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.
(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.”

25

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 September 30, 2007, 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 2009	$	43,870	$	44,040

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

Energy West does not have any off-balance-sheet arrangements, other than those currently disclosed that have or are reasonably likely to have a current or future effect on financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to investors.

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, may be 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

26

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 6 — EXHIBITS

Exhibit
Number	Description
10.1*	Stock Purchase Agreement dated January 30, 2007, by and between Energy West, Incorporated and Sempra Energy, a California corporation.
10.2*	Amendment Number One to Stock Purchase Agreement, dated April 11, 2007 by and between Energy West, Incorporated and Sempra Energy, a California corporation.
10.3*	Amendment Number Two to Stock Purchase Agreement dated August 7, 2007 by and between Energy West, Incorporated and Sempra Energy, a California corporation.
10.4*	Stock Purchase Agreement dated January 30, 2007, by and between Energy West, Incorporated and Sempra Energy, a California corporation.
10.5*	Amendment Number One to Stock Purchase Agreement, dated August 2, 2007 by and between Energy West, Incorporated and Sempra Energy, a California corporation.
10.6*	Amendment to Operating Agreement of Kykuit Resources, LLC dated October 24, 2007.
31.1*	Certification of Interim President pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1*	Certification of Interim President pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2*	Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

* Filed or furnished herewith.

27

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