Gas Natural 10-K 2007 FY Annual report

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

Form 10-K

ANNUAL REPORT

PURSUANT TO SECTIONS 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

þ	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the fiscal year ended June 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 incorporation or organization)	(I.R.S. Employer Identification No.)

1 First Avenue South, Great Falls, Montana 59401

(Address of principal executive offices) (Zip Code)

Registrant’s telephone number, including area code

(406) 791-7500

Securities registered pursuant to Section 12(b) of the Act:

Title of Each Class	Name of Each Exchange on Which Registered
Common, par value $.15 per share	Nasdaq National Market

Securities registered pursuant to Section 12(g) of the Act:

None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  Yes o     No þ

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.  Yes o     No þ

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.  Yes þ     No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 ofRegulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of thisForm 10-K or any amendment to thisForm 10-K.  o

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” inRule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer o     Accelerated filer o     Non-accelerated filer þ

Indicate by check mark whether the registrant is a shell company (as defined inRule 12b-2 of the Exchange Act).  Yes o     No þ

The aggregate market value of the registrant’s common stock held by non-affiliates as of December 31, 2006 was $22,860,683.

The number of shares outstanding of the registrant’s common stock as of September 24, 2007 was 2,866,394 shares.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the proxy statement for the 2007 Annual Meeting of Shareholders are incorporated by reference into Part III.

As used in thisForm 10-K, 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 is thisForm 10-K is as of June 30, 2007.

TABLE OF CONTENTS

			Page
Part I				1
	Item 1.	Business		1
	Item 1A.	Risk Factors		7
	Item 1B.	Unresolved Staff Comments		11
	Item 2.	Properties		11
	Item 3.	Legal Proceedings		11
	Item 4.	Submission of Matters to a Vote of Security Holders		11
Part II				12
	Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		12
	Item 6.	Selected Financial Data		14
	Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Consolidated Operations		15
	Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		29
	Item 8.	Financial Statements and Supplementary Data		30
	Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure		30
	Item 9A.	Controls and Procedures		30
	Item 9B.	Other Information		31
Part III				31
	Item 10.	Directors, Executive Officers and Corporate Governance		31
	Item 11.	Executive Compensation		31
	Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		31
	Item 13.	Certain Relationships and Related Transactions and Director Independence		31
	Item 14.	Principal Accountant Fees and Services		31
Part IV				32
	Item 15.	Exhibits and Financial Statement Schedules		32
Signatures				35
EX-3.1(C)
EX-10.22
EX-14
EX-21
EX-23.1
EX-31
EX-32

Forward-Looking Statements

This Annual Report onForm 10-K 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 expectations or beliefs concerning future events. These forward-looking statements are often characterized by the terms “may,” “believes,” “projects,” “expects,” or “anticipates,” and do not reflect historical facts. Forward-looking statements involve risks, uncertainties and other factors that may cause our actual results, performance or achievements to be materially different from those expressed or implied by such forward-looking statements. Factors and risks that could affect our results and achievements and cause them to materially differ from those contained in the forward-looking statements include those identified under “Item 1A. Risk Factors,” as well as other factors that we currently are unable to identify or quantify, but that may exist in the future.

In addition, the foregoing factors may affect generally our business, results of operations and financial position. Forward-looking statements speak only as of the date the statement was made. We do not undertake and specifically decline any obligation to update any forward-looking statements.

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PART I

Item 1.   Business.

Overview

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.
• Energy West Resources, Inc. (EWR)	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. EWR also has an ownership interest in 165 natural gas producing wells and gas gathering assets. Wholesale propane sold to our affiliated utility and the associated expense is now reported in EWR. It had previously been reported in Propane Operations.
• 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 subsidiary are being managed and reported under the operations of EWR.
• 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 are disclosed as discontinued operations in this report. See page 4. The small Montana wholesale distribution of propane to our affiliated utility that had been reported in Propane Operations is now being reported in EWR.

See Note 10 to our Consolidated Financial Statements for financial information for each of our segments.

Recent Developments

On January 30, 2007, we entered into two stock purchase agreements between Energy West and Sempra Energy. Pursuant to the purchase agreements, we will acquire all of the capital stock of two of Sempra’s wholly owned subsidiaries, Frontier Utilities of North Carolina, Inc. and Penobscot Natural Gas Company, Inc. Frontier Utilities is the parent company of its operating subsidiary, Frontier Energy, LLC, and Penobscot Natural Gas is the parent company of its operating subsidiary, Bangor Gas Company LLC. The aggregate purchase price to be paid by us for the two companies in $5,000,000, subject to adjustment for working capital items.

The acquisition of Frontier Utilities is conditioned upon approval by the North Carolina Utilities Commission, or “NCUC”, and the acquisition of Penobscot Natural Gas is conditioned upon approval by the Maine Public Utilities Commission, or “MPUC”. Both acquisitions are also conditioned upon the receipt of certain other approvals from third parties. Each acquisition will close on the tenth business day after all closing conditions have been satisfied, including either NCUC or MPUC approval, as the case may be. On September 13, 2007, we received approval from the NCUC for the acquisition of Frontier Utilities, and anticipate a closing date on or about

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September 28, 2007. Approval from the MPUC is estimated to require approximately four months to one year to be obtained.

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

On July 27, 2007, Energy West invested $720,900 in Kykuit, and $40,050 on September 17, 2007. EWR owns 26.7% of the membership interests of Kykuit Resources, LLC, or “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., or “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.

On August 27, 2007, David A. Cerotzke assumed the newly-created position of Vice Chairman of the Board and will no longer serve as President and Chief Executive Officer of Energy West. On the same date, the Board of Directors appointed Thomas J. Smith to serve as interim President of Energy West.

Natural Gas Operations

Our natural gas operations consist of two divisions located in Montana and Wyoming. Our revenues from natural gas operations are generated under tariffs regulated by the state utility commissions of Montana and Wyoming.

Natural Gas — Montana Division

The Montana division provides natural gas service to customers in and around Great Falls and West Yellowstone, Montana and manages an underground propane vapor system in Cascade, Montana. The division’s service area has a population of approximately 80,000 in the Great Falls area, 1,300 in the West Yellowstone area, and approximately 900 in the Cascade area.

The Montana division has right of way privileges for its distribution systems either through franchise agreements or general franchise agreements within its respective service territories. The Great Falls distribution component of the Montana division also provides natural gas transportation service to certain customers who purchase natural gas from other suppliers.

The operations of the Montana division are subject to regulation by the Montana Public Service Commission, or “MPSC.” The MPSC regulates rates, adequacy of service, issuance of securities, compliance with U.S. Department of Transportation safety regulations and other matters. The Montana division received orders during fiscal 2005 from the MPSC respecting base rates in both Great Falls and West Yellowstone, Montana. These orders were effective on an interim basis on November 1, 2004 and made final effective September 1, 2005. The rate order effectively granted full recovery of the increased property tax liability resulting from the settlement reached with the Montana Department of Revenue in fiscal 2004. It also provided recovery of other operating expenses as we requested. The West Yellowstone rate order granted relief related to its share of the Montana Department of Revenue settlement as well as other operating expenses.

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The following table shows the Montana division’s revenues by customer class for the fiscal year ended June 30, 2007 and the two preceding fiscal years:

Gas Revenue

	Years Ended June 30,
	2007		2006		2005
	(In thousands)
Residential	$	19,287	$	22,155	$	18,116
Commercial		12,894		14,233		11,437
Transportation		2,058		1,961		1,939
Total	$	34,239	$	38,349	$	31,492

Higher revenue in fiscal 2006 compared to fiscal 2007 and fiscal 2005 are due to higher gas costs which are passed on to the customers in accordance with approvals from the MPSC.

The following table shows the volumes of natural gas, expressed in millions of cubic feet, or “MMcf,” sold or transported by the Montana division for the fiscal year ended June 30, 2007 and the two preceding fiscal years:

Gas Volumes

	Years Ended June 30,
	2007		2006		2005
			(In MMcf)
Residential		2,097		1,978		2,136
Commercial		1,267		1,210		1,267
Transportation		1,526		1,524		1,493
Total Gas Sales		4,890		4,712		4,896

Volumes were lower in fiscal 2006 compared to fiscal 2007 and fiscal 2005 primarily due to warmer weather.

The MPSC allows customers to choose a natural gas supplier other than the Montana division. The Montana division, however, provides gas transportation services to customers who purchase from other suppliers.

The Montana division uses the Northwestern Energy, or “NWE,” pipeline transmission system to transport supplies of natural gas for its core load and to provide transportation and balancing services to customers who have chosen to obtain natural gas from other suppliers. In 2000, we entered into a ten-year transportation agreement with NWE that fixes the cost of pipeline and storage capacity for the Montana division.

The Montana division generates its revenues under regulated tariffs designed to recover a base cost of gas and administrative and operating expenses and to provide a sufficient rate of return to cover interest and profit. The Montana division’s tariffs include a purchased gas adjustment clause, which allows the Montana division to adjust rates periodically to recover changes in gas costs.

Natural Gas — Wyoming Division

The Wyoming division provides natural gas service to customers in and around Cody, Meeteetse, and Ralston, Wyoming. This service area has a population of approximately 12,000. EWR supplies natural gas to the Wyoming division pursuant to an agreement through October 2010.

The Wyoming division has a certificate of public convenience and necessity granted by the Wyoming Public Service Commission, or “WPSC,” for transportation and distribution covering the west side of the Big Horn Basin, which extends approximately 70 miles north and south and 40 miles east and west from Cody. As of June 30, 2007, the Wyoming division provided service to approximately 6,100 customers, including one large industrial customer. The Wyoming division also offers transportation through its pipeline system. This service is designed to permit

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producers and other purchasers of gas to transport their gas to markets outside of the Wyoming division’s distribution and transmission system.

The following table shows the Wyoming division’s revenues by customer class for the fiscal year ended June 30, 2007 and the two preceding fiscal years:

Gas Revenue

	Years Ended June 30,
	2007		2006		2005
	(In thousands)
Residential	$	4,657	$	5,883	$	4,805
Commercial		2,990		5,771		4,434
Industrial		4,348		5,741		4,059
Total	$	11,995	$	17,395	$	13,298

Note: Higher revenues were realized in fiscal 2006 and 2005 compared to fiscal 2007 due to higher gas costs which are passed on to the customers in accordance with approvals from the WPSC.

The following table shows volumes of natural gas, expressed in MMcf, sold by the Wyoming division for the fiscal year ended June 30, 2007 and the two preceding fiscal years:

Gas Volumes

	Years Ended June 30,
	2007		2006		2005
	(In MMcf)
Residential		526		478		519
Commercial		593		567		582
Industrial		472		684		643
Total Gas Sales		1,591		1,729		1,744

The Wyoming division generates its revenues under tariffs regulated by the WPSC. The tariffs are structured to enable us to recover a base cost of gas and administrative and operating expenses to provide a sufficient rate of return to cover interest and profit. The Wyoming division’s tariffs include a purchased gas adjustment clause, which allows the Wyoming division to adjust rates periodically to recover changes in gas costs.

The Wyoming division has an industrial customer whose gas sales rates are subject to an industrial tariff, which provides for lower incremental prices as higher volumes are used. This customer accounted for approximately 36% of the revenues of the Wyoming division and approximately 9% of the consolidated revenues of the natural gas segment of our business. This customer’s business is cyclical and depends upon the level of housing starts in their market areas.

The Wyoming division transports gas for third parties pursuant to a tariff filed with and approved by the WPSC. The terms of the transportation tariff (currently between $.08 and $.31 per thousand cubic feet, or “Mcf”) are approved by the WPSC.

Energy West Resources

We conduct certain marketing activities involving the sale of natural gas in Montana and Wyoming through our wholly-owned subsidiary EWR. In order to provide a stable source of natural gas for a portion of its requirements, EWR and our Pipeline Operations subsidiary purchased ownership in two natural gas production properties and three gathering systems, located in north central Montana, in May 2002 and March 2003. EWR currently has 165 natural gas producing wells in operation. This production gives EWR a natural hedge when market prices of

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natural gas are greater than the cost of production. The gas production from the properties provided approximately 19% of EWR’s volume requirements for fiscal 2007.

Because gas production facilities generate higher operating margins than our regulated natural gas operations, we are seeking to acquire additional gas production properties if and when such opportunities arise. We cannot provide assurance, however, that we will be able to identify production properties that we can acquire on terms that we consider favorable.

In fiscal 2003, EWR exited the electricity marketing business by not renewing its electric contracts as they expired. As a result, during fiscal 2007, 2006, and 2005, we had only one remaining electric contract with a margin of $48,000, $48,000, and $34,000, respectively, in each of those three years. The electricity operations are reported within continuing operations because we use the same employees with the same overhead as our natural gas marketing operation.

Pipeline Operations

Our Pipeline Operations reflect operation of the “Glacier” natural gas gathering pipeline placed in service in fiscal 2001 and the “Shoshone” transmission pipeline placed in service in fiscal 2004. Both pipelines have sections located in Wyoming and Montana. The revenues and expenses associated with the pipelines are included in the “Pipeline Operations” segment.

We believe that our Pipeline Operations represent a significant opportunity to increase our profitability over time. We currently are seeking ways in which we can expand our Pipeline Operations by expanding the capacity and throughput of our existing pipeline assets.

Propane Operations — (Discontinued Operations)

Until March 31, 2007, we were engaged in the regulated sale of propane under the business name Energy West Arizona, or “EWA”, and the unregulated sale of propane under the business name Energy West Propane — Arizona, or “EWPA”, collectively known as EWP. EWP distributed propane in the Payson, Pine, and Strawberry, Arizona area located about 75 miles northeast of Phoenix in the Arizona Rim Country. EWP’s service area included approximately 575 square miles and a population of approximately 50,000.

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

SemStream purchased only the assets and business operations of EWP that pertain to the Business within the state of Arizona, and that also pertain to the Energy West Propane — Arizona division of our companyand/or EWP (collectively, the “Arizona Assets”). Pursuant to the Asset Purchase Agreement, SemStream paid a cash purchase price of $15,000,000 for the Arizona Assets, plus working capital.

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.

The gain on the sale of these assets is presented under the heading “Gain from disposal of operations”. The results of operations for the propane assets related to this sale have been reclassified as income from discontinued operations in the accompanying Statement of Income. The assets and liabilities of the discontinued operations are

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presented separately under the captions “Assets Held for Sale” and “Liabilities Held for Sale”, respectively, in the accompanying Balance Sheet at June 30, 2006, and consist of the following:

Assets and Liablilities Held for Sale

	June 30, 2006
Assets held for sale:
Accounts Receivable	$	194,746
Unbilled Gas		296,730
Propane Inventory		566,179
Materials and Supplies		111,701
Prepayments		29,096
Recoverable cost of gas purchases		1,243,931
Property, Plant and Equipment, Net		9,214,187
Total Assets held for sale		11,656,570
Liablilities held for sale:
Accounts Payable		20,203
Other Current Liabilities		148,634
Contributions in Aid of Construction		653,405
Total Liabilities held for sale		822,242
Net Assets Held for Sale	$	10,834,328

Competition

The traditional competition we face in our distribution and sales of natural gas is from suppliers of fuels other than natural gas, including electricity, oil, propane, and coal. Traditionally, the principal considerations affecting a customer’s selection of utility gas service over competing energy sources include service, price, equipment costs, reliability, and ease of delivery. In addition, the type of equipment already installed in a business and residence significantly affects the customer’s choice of energy. However, with respect to the majority of our service territory, previously installed equipment is not an issue. Households in recent years have generally preferred the installation of natural gasand/or propane for space and water heating as an energy source. We face more intense competition in West Yellowstone and Cascade, Montana due to the cost of competing fuels than we face in the Great Falls area of Montana and our service territory in Wyoming.

EWR’s principal competition is from other natural gas marketing firms doing business in Montana.

Governmental Regulation

Our continuing utility operations are subject to regulation by the MPSC, the WPSC, and the Federal Energy Regulatory Commission, or “FERC,” as to rates, service area, adequacy of service and safety standards. Such regulation plays a significant role in determining our profitability. The commissions approve rates intended to permit a reasonable rate of return on investment. Our tariffs allow gas cost to be recovered in full (barring a finding of imprudence) in regular (as often as monthly) rate adjustments. This mechanism has substantially reduced any delay between the incurrence and recovery of gas costs.

Seasonality

Our business and that of our subsidiaries in all segments is temperature-sensitive. In any given period, sales volumes reflect the impact of weather, in addition to other factors. Colder temperatures generally result in increased sales, while warmer temperatures generally result in reduced sales. We anticipate that this sensitivity to seasonal and other weather conditions will continue to be reflected in our sales volumes in future periods.

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Environmental Matters

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 continue to work with the MDEQ relating to the remediation plan for water contaminants. The MDEQ has established regulations that allow water contaminants at a site to exceed standards if it is technically impracticable to achieve 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 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 June 30, 2007, 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 June 30, 2007, we had recovered approximately $1,845,000 through such surcharges. As of June 30, 2007, the cost remaining to be recovered through the on going rate is $248,000. 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.

Employees

We had a total of 76 employees as of June 30, 2007. One of these employees is employed by EWR, 63 by our Natural Gas Operations and 12 at the corporate office. Our Natural Gas Operations include 15 employees represented by two labor unions. Negotiations were completed in July 2006 with the Laborers Union, with a contract in place until June 30, 2008. A three-year contract with Local Union #41 for the pipefitters expires June 30, 2010. We believe our relationship with both labor unions is very good.

Item 1A.   Risk Factors.

An investment in our common stock involves a substantial degree of risk. Before making an investment decision, you should give careful consideration to the following risk factors in addition to the other information contained in this report. The following risk factors, however, may not reflect all of the risks associated with our business or an investment in our common stock.

Our results of operations could fluctuate due to a variety of factors outside of our control, including the following:

•  Fluctuating energy commodity prices;

•  The possibility that regulators may not permit us to pass through all of our increased costs to our customers;

•  Changes in general economic conditions in the United States and changes in the industries in which we conduct business;

•  Our business and that of our subsidiaries in all segments is temperature-sensitive. In any given period, sales volumes reflect the impact of weather, in addition to other factors;

•  Changes in federal or state laws and regulations to which we are subject, including tax, environmental, and employment laws and regulations;

•  The impact of the FERC and state public service commission statutes, regulations, and actions, including allowed rates of return, and the resolution of other regulatory matters;

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•  Our ability to obtain governmental and regulatory approval of various expansion or other projects;

•  The costs and effects of legal and administrative claims and proceedings against us or our subsidiaries;

•  Conditions of the capital markets we utilize to access capital;

•  The ability to raise capital in a cost-effective way;

•  The ability to meet financial covenants imposed by lenders;

•  The effect of changes in accounting policies, if any;

•  The ability to manage our growth;

•  The ability to control costs;

•  The ability of each business unit to successfully implement key systems, such as service delivery systems;

•  Our ability to develop expanded markets and product offerings and our ability to maintain existing markets;

•  The ability of customers of the energy marketing and trading business to obtain financing for various projects;

•  The ability of customers of the energy marketing and trading business to obtain governmental and regulatory approval of various projects;

•  Future utilization of pipeline capacity, which can depend on energy prices, competition from alternative fuels, the general level of natural gas and propane demand, decisions by customers not to renew expiring natural gas contracts, and weather conditions;

•  Global and domestic economic repercussions from terrorist activities and the government’s response thereto; and

•  Disruptions to natural gas supplies or prices caused by man-made or natural disasters, such as tropical storms or hurricanes.

We are subject to comprehensive regulation by several federal, state, and local regulatory agencies, which significantly influence our operating environment and may affect our ability to recover costs from utility customers.  We are required to have numerous permits, approvals, and certificates from the agencies that regulate our business. FERC, state and federal environmental agencies, and state public service commissions regulate many aspects of our utility operations, including siting and construction of facilities, customer service, and the rates that we can charge customers. We believe that we have obtained the necessary permits, approvals, and certificates for our existing operations. However, we are unable to predict the impact on our business and operating results from the future regulatory activities of any of these agencies. Changes in regulations or the imposition of additional regulations could have an adverse impact on our results of operations.

Legislative and regulatory initiatives, at both the federal and state levels, are designed to promote competition. Changes in the gas industry have allowed certain customers to negotiate gas purchases directly with producers or brokers. Although open access in the gas industry has not had a negative impact on the earnings or cash flow of our regulated segment to date, we may lose market share or our profit margins may decline in the future if we are unable to remain competitive in this market.

Our regulated natural gas and our discontinued propane vapor operations follow Statement of Financial Accounting Standards (SFAS) No. 71, “Accounting for the Effects of Certain Types of Regulation,” (“SFAS No. 71”) and our financial statements reflect the effects of the different rate-making principles followed by the various jurisdictions regulating our business. The application of SFAS No. 71 can result in the regulated segment of our business recording costs that have been or are expected to be allowed in the ratemaking process in a period different from the period in which the costs would be charged to expense by an unregulated enterprise. Additionally, regulators can impose liabilities upon our regulated business segment for amounts previously collected from customers and for amounts that are expected to be refunded to customers. Although we currently do not anticipate the occurrence of any circumstances or events that would cause our natural gas operations to discontinue the

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application of SFAS No. 71, the accounting impact of such an event would be an extraordinary, non-cash charge to operations that could be material to our financial position and results of operations.

Our business and that of our subsidiaries in all segments is temperature-sensitive.  In any given period, sales volumes reflect the impact of weather, in addition to other factors. Colder temperatures generally result in increased sales, while our results of operations can be adversely affected by milder weather. We anticipate that this sensitivity to seasonal and other weather conditions will continue to be reflected in our sales volumes in future periods.

The use of derivative contracts in the normal course of our business and changing interest rates and market conditions could result in financial losses that negatively impact our results of operations.  We are exposed to the impact of market fluctuations in the price and transportation costs of natural gas. In order to mitigate the risk of market price volatility related to firm commitments to purchase or sell natural gas, from time to time we have entered into hedging arrangements. We may use such arrangements 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 are exposed to losses in the event of nonperformance or nonpayment by counterparties. We use a risk management process to assess and monitor the financial exposure of all counterparties. Despite the fact that the majority of trading counterparties are rated as investment grade by the credit rating agencies, there is still a possibility that one or more of these companies could default, resulting in a material adverse impact on our earnings for a given period.

We are subject to numerous environmental laws and regulations that may increase our cost of operations, impact our business plans, or expose us to environmental liabilities.  Environmental regulations that may affect our present and future operations include regulation of air emissions, water quality, wastewater discharges, solid waste, and hazardous waste. These laws and regulations can result in increased capital expenditures or operating costs. These laws and regulations generally require us to obtain and comply with a wide variety of environmental licenses, permits, inspections, and other approvals. Both public officials and private individuals may seek to enforce applicable environmental laws and regulations. We cannot predict the outcome (financial or operational) of any related litigation that may arise.

We may be a responsible party for environmentalclean-up at sites identified by a regulatory body in the future. If that occurs, we cannot predict with certainty the amount and timing of all future expenditures related to environmental matters because of the difficulty of estimatingclean-up costs. There is also uncertainty in quantifying liabilities under environmental laws that impose joint and several liability on all potentially responsible parties.

We cannot be sure that existing environmental regulations will not be revised or that new regulations seeking to protect the environment will not be adopted or become applicable to us. Revised or additional regulations that result in increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from our customers, could have a material adverse effect on our results of operations.

We will face a variety of risks associated with acquiring and integrating new business operations.  The growth and success of our business will depend to a great extent on our ability to acquire new assets or business operations and to integrate the operations of businesses that we may acquire in the future. We cannot provide assurance that we will be able to:

•  Identify suitable acquisition candidates or opportunities;

•  Acquire assets or business operations on commercially acceptable terms;

•  Effectively integrate the operations of any acquired assets or businesses with our existing operations;

•  Manage effectively the combined operations of the acquired businesses;

•  Achieve our operating and growth strategies with respect to the acquired assets or businesses; or

•  Reduce our overall selling, general, and administrative expenses associated with the acquired assets or businesses.

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The integration of the management, personnel, operations, products, services, technologies, and facilities of any businesses that we acquire in the future could involve unforeseen difficulties. These difficulties could disrupt our ongoing businesses, distract our management and employees, and increase our expenses, which could have a material adverse affect on our business, financial condition, and operating results.

Our performance depends substantially on the performance of our executive officers and other key personnel.  The success of our business in the future will depend on our ability to attract, train, retain, and motivate high quality personnel, especially highly qualified managerial personnel. The loss of services of key executive officers or personnel could have a material adverse effect on our business, results of operations or financial condition.

Failure to achieve and maintain effective internal controls in accordance with Section 404 of the Sarbanes-Oxley Act could have a material adverse effect on our business and stock price.  Pursuant to Section 404 of the Sarbanes-Oxley Act of 2002, it is expected that beginning with our Annual Report onForm 10-K for fiscal year ending June 30, 2008, we will be required to furnish a report by our management on our internal control over financial reporting. The internal control report must contain (i) a statement of management’s responsibility for establishing and maintaining adequate internal control over financial reporting, (ii) a statement identifying the framework used by management to conduct the required evaluation of the effectiveness of our internal control over financial reporting, (iii) management’s assessment of the effectiveness of our internal control over financial reporting as of the end of our most recent fiscal year, including a statement as to whether or not internal control over financial reporting is effective, and (iv) beginning with our Annual Report onForm 10-K for the fiscal year ending June 30, 2009, a statement that our independent auditors have issued an attestation report on management’s assessment of internal control over financial reporting.

In order to achieve compliance with Section 404 of the Sarbanes-Oxley Act within the prescribed period, we have initiated a process to document and evaluate our internal control over financial reporting, which will be both costly and challenging. In this regard, management has dedicated internal resources and will engage outside consultants if necessary. The project team will adopt a detailed work plan to (i) assess and document the adequacy of internal control over financial reporting, (ii) take steps to improve control processes where appropriate, (iii) validate through testing that controls are functioning as documented, and (iv) implement a continuous reporting and improvement process for internal control over financial reporting. There is a risk that neither we nor our independent auditors will be able to conclude the attestation expected at June 30, 2009 that our internal controls over financial reporting are effective as required by Section 404 of the Sarbanes-Oxley Act.

During the course of our testing we may identify deficiencies that we may not be able to remediate in time to meet the deadlines imposed by the Sarbanes-Oxley Act for compliance with the requirements of Section 404. In addition, if we fail to achieve and maintain the adequacy of our internal controls, as such standards are modified, supplemented or amended from time to time, we may not be able to ensure that we can conclude on an ongoing basis that we have effective internal controls over financial reporting in accordance with Section 404 of the Sarbanes-Oxley Act. Moreover, effective internal controls, particularly those related to revenue recognition, are necessary for us to produce reliable financial reports and are important to helping prevent financial fraud. If we cannot provide reliable financial reports or prevent fraud, our business and operating results could be harmed, investors could lose confidence in our reported financial information, and the trading price of our stock could be adversely affected.

Our actual results of operations could differ from estimates used to prepare our financial statements.

In preparing our financial statements in accordance with generally accepted accounting principles, our management often must make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses, and related disclosures at the date of the financial statements and during the reporting period. Some of those judgments can be subjective and complex, and actual results could differ from those estimates. We consider the following accounting policies to be our most critical because of the uncertainties, judgments, and complexities of the underlying accounting standards and operations involved:

•  Regulatory Accounting — Regulatory accounting allows for the actions of regulators to be reflected in the financial statements. Their actions may cause us to capitalize costs that would otherwise be included as an expense in the current period by unregulated companies. If future recovery of costs ceases to be probable, the assets will be written off as a charge in current period earnings.

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•  Derivative Accounting — Derivative accounting requires evaluation of rules that are complex and subject to varying interpretations. Our evaluation of these rules, as they apply to our contracts, will determine whether we use accrual accounting or fair value (mark-to-market) accounting. Mark-to-market accounting requires us to record changes in fair value in earnings or, if certain hedge accounting criteria are met, in common stock equity (as a component of other comprehensive income (loss)).

Events in the energy markets that are beyond our control may have negative impacts on our business.  For example, the energy crisis in California during the summer of 2001, the bankruptcy filing by Enron Corporation, and investigations by governmental authorities into energy trading activities, greatly increased the amount of public and regulatory scrutiny of companies generally in the regulated and unregulated utility businesses. The capital markets and credit ratings agencies also have increased their level of scrutiny. We believe that we are complying with all applicable laws, but it is difficult to predict or control what effect these or related issues may have on our business or our access to the capital markets.

Item 1B.   Unresolved Staff Comments.

Not applicable.

Item 2.   Properties.

Montana — In Great Falls, Montana, we own an 11,000 square foot office building, which serves as our headquarters, and a 3,000 square foot service and operating center (with various outbuildings), which supports day-to-day maintenance and construction operations. We own approximately 400 miles of underground distribution lines, or “mains,” and related metering and regulating equipment in and around Great Falls, Montana. In West Yellowstone, Montana, we own an office building and a liquefied natural gas plant that provides natural gas through approximately 13 miles of underground mains owned by us. We own approximately 10 miles of underground mains in the town of Cascade, as well as two large propane storage tanks.

Combined, EWR and our Pipeline Operations subsidiary own an interest in 165 natural gas production wells and three gathering pipelines in north central Montana. The natural gas wells are operated by a third party and we are invoiced each month for our share of the operating and capital expenses incurred.

Wyoming — In Cody, Wyoming, we lease office and service buildings under long-term lease agreements. We own approximately 500 miles of transmission and distribution mains and related metering and regulating equipment, all of which are located in or around Cody, Meeteetse, and Ralston.

Our Pipeline Operations subsidiary owns two pipelines in Wyoming and Montana. One is currently being operated as a gathering system. The other pipeline is operating as a FERC regulated natural gas interstate transmission line. The pipelines extend from north of Cody, Wyoming to Warren, Montana.

Item 3.   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.

Item 4.   Submission of Matters to a Vote of Security Holders.

Not applicable.

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PART II

Item 5.   Market for Registrant’s Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities.

Our Common Stock

Our Common Stock is quoted for trading on the Nasdaq National Market under the symbol “EWST.” The following table sets forth, for the quarters indicated, the range of high and low prices of our common stock as reported by the Nasdaq National Market.

Fiscal Year 2007	High		Low
First Quarter	$	11.94	$	9.02
Second Quarter	$	12.00	$	10.78
Third Quarter	$	15.00	$	11.10
Fourth Quarter	$	16.22	$	13.51

Fiscal Year 2006	High		Low
First Quarter	$	13.89	$	8.20
Second Quarter	$	11.60	$	8.59
Third Quarter	$	11.00	$	8.57
Fourth Quarter	$	11.00	$	8.70

Holders of Record

As of September 7, 2007, there were approximately 334 record owners of our common stock. We estimate that an additional 1,350 shareholders own stock in their accounts at brokerage firms and other financial institutions.

Dividend Policy

Our credit agreement with LaSalle Bank, N.A., or “LaSalle,” restricted our ability to pay dividends during any period to a certain percentage of our cumulative earnings over that period. Our 1997 and 1993 promissory notes also contained restrictions respecting the payment of dividends. There were no cash dividends paid between April 2003 and September 2005. Our Board reinstated the payment of the quarterly dividend beginning in October 2005. Quarterly dividend payments per common share were:

October 28, 2005	$	0.04
January 31, 2006	$	0.05
May 31, 2006	$	0.08
August 28, 2006	$	0.10
November 2, 2006	$	0.12
February 13, 2007	$	0.14
May 3, 2007	$	0.15
September 25, 2007	$	0.16

Recent Sales of Unregistered Securities

Not applicable.

Purchases of Equity Securities by Our Company and Affiliated Purchasers

					Total Number of		Maximum Number of
					Shares Purchased		Shares that may yet be
	Total Shares		Average Price		as Part of Publicly		Purchased Under the
Period	Purchased		Paid per Share		Announced Plans		Stock Repurchase Plan
May 30, 2007 — June 30, 2007		146,348	$	15.00		146,348		152,652

On February 13, 2007, the Board of Directors of Energy West, Incorporated approved a stock repurchase plan whereby the company intends to buy back up to 299,000 shares of the company’s common stock. We began this stock buyback on May 30, 2007. The stock repurchases included 145,000 shares from Mr. Mark Grossi, a director of Energy West, Incorporated

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Performance Graph

The graph below matches our cumulative five-year total shareholder return on common stock with the cumulative total returns of the S&P 500 index and the S&P Utilities index. The graph tracks the performance of a $100 investment in our common stock and in each of the indexes (with the reinvestment of all dividends) from6/30/2002 to6/30/2007.

COMPARISON OF 5 YEAR CUMULATIVE TOTAL RETURN*

Among ENERGY WEST Incorporated, The S&P 500 Index

And The S&P Utilities Index

*  $100 invested on6/30/02 in stock or index-including reinvestment of dividends. Fiscal year ending June 30.

Copyright^© 2007, Standard & Poor’s, a division of The McGraw-Hill Companies, Inc. All rights reserved. www.researchdatagroup.com/S&P.htm

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Item 6.   Selected Financial Data.

The selected financial data presented below are derived from our historical consolidated financial statements, which were audited by our independent registered public accounting firms in each of those years. The selected financial data should be read in conjunction with Management’s Discussion and Analysis of Financial Condition and Results of Operations and our Consolidated Financial Statements and the related notes included elsewhere in thisForm 10-K. Amounts are in thousands, except per share and number of share amounts. Certain prior period revenues and expenses have been reclassified as income from discontinued operations.

	2007		2006		2005		2004			2003
Operating results
Operating revenue	$	59,373	$	74,696	$	67,889	$	58,664		$	59,357
Operating expenses
Gas and electric purchases		43,806		60,398		53,510		46,981			47,962
General and administrative		6,198		6,389		7,309		8,020			8,986
Maintenance		567		505		521		399			411
Depreciation and amortization		1,692		1,672		1,790		1,812			1,797
Taxes other than income(1)		1,697		1,453		1,479		1,058			701
Total operating expenses		53,960		70,417		64,609		58,270			59,857
Operating income (loss)		5,413		4,279		3,280		394			(500	)
Otherincome-net		241		391		235		204			114
Total interest charges(2)		2,124		1,649		2,113		1,933			1,238
Income (loss) before taxes		3,530		3,021		1,402		(1,335	)		(1,624	)
Income tax expense (benefit)		1,273		1,109		475		(412	)		(618	)
Discontinued operations (net of tax)		3,955		405		454		367			149
Net Income (Loss)	$	6,212	$	2,317	$	1,381	$	(556	)	$	(857	)
Basic earnings (loss) per common share	$	2.10	$	0.79	$	0.53	$	(0.36	)	$	(0.39	)
Diluted earnings (loss) per common share	$	2.08	$	0.79	$	0.53	$	(0.21	)	$	(0.33	)
Dividends per common share(3)	$	0.51	$	0.17	$	0.00	$	0.00		$	0.41
Weighted average common shares Outstanding — diluted		2,989,382		2,948,046		2,630,679		2,596,454			2,586,487
At year end:
Current assets	$	17,768	$	23,669	$	15,423	$	16,739		$	15,790
Total assets	$	51,834	$	57,931	$	59,433	$	61,445		$	60,027
Current liabilities	$	7,694	$	10,796	$	11,525	$	16,725		$	21,833
Total long-term obligations	$	13,000	$	17,605	$	18,677	$	21,697		$	14,834
Total stockholders’ equity	$	22,296	$	19,165	$	17,187	$	13,401		$	13,957
Total capitalization	$	35,296	$	36,770	$	35,864	$	35,098		$	28,791

(1)	Taxes other than income include approximately $290,000 increases in property tax in fiscal 2004, 2005 and another $250,000 in 2007 for additional personal property taxes assessed by the Montana Department of Revenue.
(2)	Total interest charges reflect the costs associated with the addition of $6,000,000 of long-term debt and a $2,000,000 bridge loan incurred in March 2004. In May 2005, we paid off the $2,000,000 bridge loan and during fiscal 2006 we reduced the line of credit significantly, thus reducing interest in fiscal 2006. In fiscal 2007, we refinanced our long-term debt, resulting in the $991,000 expensing of debt issue costs related to the refinanced debt.
(3)	There were no cash dividends paid between April 2003 and September 2005.

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Item 7.   Management’s Discussion and Analysis of Financial Condition and Results of Consolidated Operations.

For a description of our significant accounting policies and an understanding of the significant factors that influenced our performance during fiscal 2007, 2006, and 2005, this Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with the Consolidated Financial Statements, including the related notes, beginning onpage F-1 of this Annual Report.

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 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, and restore dividends to our shareholders. Earnings from continuing operations for the fiscal year ended June 30, 2007, increased 18% over the same period in 2006 and represent an all-time high for the core business of Energy West. This was after an increase of 100% from continuing operations for the fiscal year ended June 30, 2006 over the same period in 2005. For 2006, we were able to achieve these positive results despite one of our warmest winters (leading to reduced sales), historically high natural gas commodity prices, and increasing interest rates.

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. We refinanced our long-term debt, as well as reduced our total debt and short-term borrowings in an effort to reduce our interest expense. This resulted in additional interest expense for fiscal year 2007 due to the expensing of debt issue costs associated with our old debt, but should result in a decrease of our long-term interest and amortization of debt issue costs in the future. 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 $15,000,000 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 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.

Strategy

The key elements of our current strategy include the following:

•  Focus on the natural gas distribution and related businesses and expanding our operations in small regional and emerging markets;

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

•  Pursue appropriate regulatory treatment of higher commodity prices;

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

•  Continue to focus on operational efficiencies;

•  Manage cash flow to reduce our existing debt;

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

•  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:

•  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. 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 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

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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.

Critical Accounting Policies and Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates, assumptions, and at times difficult, subjective or complex judgments. Changes in these estimates, assumptions and judgments, in and of themselves, could materially impact our financial statements. The following are the accounting estimates that we believe are the most critical in nature. See Note 1 of the Notes to Consolidated Financial Statements for a discussion of our significant accounting policies.

Regulatory Accounting

Our accounting policies historically reflect the effects of the rate-making process in accordance with SFAS No. 71. Our regulated natural gas segment continues to be cost-of-service rate regulated, and we believe the application of SFAS No. 71 to that segment continues to be appropriate. We must reaffirm this conclusion at each balance sheet date. If, as a result of a change in circumstances, we determine that the regulated natural gas segment no longer meets the criteria of regulatory accounting under SFAS No. 71, that segment will have to discontinue regulatory accounting and write off the respective regulatory assets and liabilities. Such a write-off could have a material impact on our consolidated financial statements.

The application of SFAS No. 71 results in recording regulatory assets and liabilities. Regulatory assets represent the deferral of incurred costs that are probable of future recovery in customer rates. In some cases, we record regulatory assets before we have received approval for recovery from the MPSC or the WPSC. We must use judgment to conclude that costs deferred as regulatory assets are probable of future recovery. We base this conclusion on certain factors, including changes in the regulatory environment, recent rate orders issued by regulatory agencies, and the status of any potential new legislation. Regulatory liabilities represent revenues received from customers to fund expected costs that have not yet been incurred or for probable future refunds to customers.

We use our best judgment when recording regulatory assets and liabilities. Regulatory commissions, however, can reach different conclusions about the recovery of costs, and those conclusions could have a material impact on our consolidated financial statements. We believe it is probable that we will recover the regulatory assets that have been recorded.

Accumulated Provisions for Doubtful Accounts

We encounter risks associated with the collection of our accounts receivable. As such, we record a provision for those accounts receivable that are considered to be uncollectible. In order to calculate the appropriate provision, we primarily utilize the historical accounts receivable write-off amounts. The underlying assumptions used for the provision can change from period to period and the provision could potentially cause a material impact to our income statement and working capital. The actual weather, commodity prices, and other internal and external economic conditions, such as the mix of the customer base between residential, commercial and industrial, may vary significantly from our assumptions and may impact our operating income.

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Unbilled Revenues and Gas Costs

We estimate the gas service that has been rendered from the latest date of each meter reading cycle to the month end. This estimate of unbilled usage is based on projected base load usage for each day unbilled plus projected weather sensitive usage for each degree day during the unbilled period. Unbilled revenues and gas costs are calculated from the estimate of unbilled usage multiplied by the rates in effect at month end. Actual usage patterns may vary from these assumptions and may impact our operating income.

Recoverable/Refundable Costs of Gas and Propane Purchases

We account for purchased gas costs in accordance with procedures authorized by the MPSC and the WPSC, under which purchased gas costs that are different from those provided for in present rates are accumulated and recovered or credited through future rate changes.

Derivatives

We account for certain derivative contracts that are used to manage risk in accordance with SFAS No. 133,Accounting for Derivative Instruments and Hedging Activities. Contracts that are required to be valued as derivatives under SFAS No. 133 are reflected at “fair value” under the mark-to-market method of accounting. The market prices or fair values used in determining the value of our portfolio are management’s best estimates utilizing information such as closing exchange rates, over-the-counter quotes, historical volatility, and the potential impact on market prices of liquidating positions in an orderly manner over a reasonable amount of time under current market conditions. As additional information becomes available or actual amounts are determinable, the recorded estimates may be revised. As a result, operating results can be affected by revisions to prior estimates. Operating results also can be affected by changes in underlying factors used in the determination of fair value of the portfolio, such as the following:

•  There is variability in “mark-to-market” earnings due to changes in the commodity price for gas. Our portfolio is valued based on current and expected future gas prices. Changes in these prices can cause fluctuations in earnings.

•  We discount derivative assets and liabilities using risk-free interest rates adjusted for credit standing in accordance with SFAS No. 133, which is more fully described in Statement of Financial Accounting Concepts No. 7, “Using Cash Flow Information and Present Value in Accounting Measurement”.

Other activities consist of the purchasing or selling of gas for utility operations, which fall under the normal purchases and sales exception, and, from time to time, entering into transactions to hedge risk associated with these purchases. These activities require that management make certain judgments regarding election of the normal purchases and sales exceptions and qualification of hedge accounting by identifying hedge relationships and assessing hedge effectiveness. There were no new derivative transactions during the three fiscal years ended June 30, 2007, 2006 or 2005.

Results of Consolidated Operations

The following discussion of financial condition and results of operations should be read in conjunction with the Consolidated Financial Statements and Notes thereto and other financial information included elsewhere in this Annual Report.

Fiscal Year Ended June 30, 2007 Compared to Fiscal Year Ended June 30, 2006

Net Income — Our net income for fiscal 2007 was $6,212,000 compared to net income of $2,317,000 for fiscal 2006, an improvement of $3,895,000. The improvement was the result of an increase in margin from continuing operations of $1,269,000, and an increase in income from discontinued operations of $3,549,000. These increases were offset in part by a decrease in other income of $149,000, and increases in operating expenses, interest expense and income taxes of $135,000, $475,000, and $164,000, respectively. The principal changes that contributed to the improvement in net income from fiscal 2006 to fiscal 2007 are explained below.

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Revenues — Our revenues for fiscal 2007 were $59,373,000 compared to $74,696,000 in fiscal 2006, a decrease of $15,323,000. This decrease was primarily attributable to a decrease in commodity prices. Revenues in the Natural Gas segment decreased $9,013,000 due to lower commodity prices that are passed through to customers, and EWR revenues decreased $6,287,000 due to the loss of two large customers and lower commodity prices. Revenue from Pipeline Operations decreased $23,000 as a result of lower transport volumes.

Gross Margin — Gross margins (revenues less cost of sales) were $15,566,000 in fiscal 2007 compared to $14,297,000 in fiscal 2006, an increase of $1,269,000. Gross margin in the Natural Gas segment increased by $606,000 due to higher volumes sold because of a colder winter. EWR’s gross margin increased by $686,000, due to new business in our Wyoming market and the renegotiation of expiring contracts on more favorable terms, offset in part by a decrease in mark-to-market revenue and the loss of two large customers. Our Pipeline Operations’ margin decreased by $13,000 due to lower transport volumes.

Expenses Other Than Costs of Sales — Expenses other than costs of sales increased by $135,000 from fiscal 2006 to fiscal 2007 due to an increase in property tax expense of $244,000, an increase in maintenance expense of $62,000, and an increase in depreciation expense of $21,000. These increases were partly offset by a $192,000 decrease in distribution, general and administrative expenses. This decrease was related to cost savings measures in payroll and other associated costs, including a $139,000 reduction due to the curtailment of additional contributions to the Retiree Health Plan.

Other Income — Other income decreased by $149,000 from $391,000 in fiscal 2006 to $242,000 in fiscal 2007. Other income in the Natural Gas segment decreased $129,000, primarily due to decreased income generated in fiscal 2007 for services to customers compared to what had been provided in prior years. EWR had other income of $32,000 in fiscal 2006 compared to $1,000 in fiscal 2007 primarily generated from payments related to the final settlement of a contract dispute. Pipeline Operations other income increased $11,000.

Interest Expense — In fiscal year 2007, we refinanced our long term debt, resulting in the expensing of $991,000 of unamortized debt issue costs. This was $742,000 more than the amount amortized in fiscal 2006. This increase in interest due to amortization of debt issue costs was offset by decreased short-term interest expense due to lower short-term borrowings, and resulted in a net increase in interest expense of $475,000, or 29%, from $1,649,000 in fiscal 2006 to $2,124,000 in fiscal 2007.

Income Tax Expense — Income tax expense from continuing operations increased by $164,000 from $1,109,000 in fiscal 2006 to $1,273,000 in fiscal 2007 due to increased pre-tax income from continuing operations.

Discontinued Operations

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 Missouri River Propane, or “MRP”, our unregulated Montana wholesale operation that supplies propane to our affiliated company reported in the Natural Gas segment. MRP is now being reported in our EWR segment.

Income from Discontinued Operations Before Income Tax — Income from operations increased $304,000, from $671,000 in fiscal year 2006 to $975,000 in fiscal year 2007 primarily due to the timing of the sale of the Arizona assets. Fiscal 2006 included a full year of revenues and associated expense, while fiscal 2007 included only nine months of revenue and associated expenses. Since the utility business is weather sensitive and cyclical, we typically experience losses in the fourth quarter of our fiscal year. If we had not disposed of the Arizona assets, it is likely that net income before income taxes would have been comparable to prior years.

Gain from Disposal of Operations — On April 1, 2007 we sold our Arizona propane assets for $15,000,000 plus working capital, resulting in a pre-tax gain of $5,479,000.

Income Tax (Expense) — Income tax expense increased by $2,234,000 from $266,000 in fiscal 2006 to $2,500,000 in fiscal 2007 due to higher pre-tax income, including the gain on sale of assets.

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Fiscal Year Ended June 30, 2006 Compared to Fiscal Year Ended June 30, 2005

Net Income — Our net income for fiscal 2006 was $2,317,000 compared to net income of $1,381,000 for fiscal 2005, an improvement of $936,000. The improvement was the result of an increase in other income of $156,000, and decreases in operating and interest expense of $1,079,000 and $464,000, respectively. These were offset by decrease in margin from continuing operations of $82,000, a decrease in income from discontinued operations of $48,000, and an increase in income taxes from continuing operations of $634,000. The principal changes that contributed to the improvement in net income from fiscal 2005 to fiscal 2006 are explained below.

Revenues — Our revenues for fiscal 2006 were $74,696,000 compared to $67,889,000 in fiscal 2005, an increase of $6,807,000. This increase was primarily attributable to an increase in the Natural Gas Operations of $10,898,000 due to higher commodity prices that are passed through to customers. These increases were offset by a decrease of $4,078,000 in the marketing operations of EWR due to lower gas sales and a decrease of $13,000 in revenue from Pipeline Operations caused by lower transport volumes.

Gross Margin — Gross margins were $14,297,000 in fiscal 2006 compared to $14,379,000 in fiscal 2005, a decrease of $82,000. Gross margin in the Natural Gas segment increased by $295,000 due to the implementation in Great Falls of the rate design portion of the rate order effective September 1, 2005, which transferred more margin to the basic charge from the volumetric charges, offset by lower margins due to lower volumes sold because of the very warm winter. EWR’s gross margin decreased by $364,000, of which $268,000 was due to lower gas sales and $116,000 was caused by a decrease in the value of derivative contracts. Our Pipeline Operations’ margin decreased by $13,000 due to lower transport volumes.

Expenses Other Than Costs of Sales — Expenses other than cost of sales decreased by $1,079,000 from fiscal 2005 to fiscal 2006 due to decreases in distribution, general and administrative expenses, depreciation expenses, and taxes other than taxes on income, offset partly by a slight increase in maintenance expense. Distribution and general and administrative expenses decreased by $920,000 for fiscal 2006 as compared to fiscal 2005. This decrease was related to cost savings measures in payroll and other associated costs in fiscal 2006, including a $290,000 reduction due to the curtailment of additional contributions to the Retiree Health Plan. Depreciation expense decreased by $118,000 and taxes other than income decreased by $25,000, while maintenance expense decreased by $16,000.

Other Income — Other income increased by $156,000 from $235,000 in fiscal 2005 to $391,000 in fiscal 2006. Other income in the Natural Gas segment increased $192,000, primarily due to income generated in fiscal 2006 for services to customers, and other miscellaneous income. EWR had other income generated from payments related to the settlement of a contract dispute that were $35,000 greater in fiscal 2005 than in fiscal 2006.

Interest Expense — Interest expense decreased by $464,000, or 28%, from $2,113,000 in fiscal 2005 to $1,649,000 in fiscal 2006 due to improved cash flow from operations and the amortization of debt issuance costs related to securing the LaSalle short-term credit facility in fiscal 2005. These reductions were partially offset by higher interest rates.

Income Tax Expense from Continuing Operations — Income tax expense increased by $634,000 from $475,000 in fiscal 2005 to $1,109,000 in fiscal 2006 due to increased pre-tax income.

Discontinued Operations

Income from Discontinued Operations Before Income Tax — Income from operations decreased $61,000, from $732,000 in fiscal year 2005 to $671,000 in fiscal year 2006 due to a variety of factors including high prices and lower margins in the unregulated portion of the segment, offset by cost savings in expenses, and reduced interest expense due to lower borrowings.

Income Tax (Expense) — Income tax expense decreased by $12,000 from $278,000 in fiscal 2005 to $266,000 in fiscal 2006 due to lower pretax income.

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Operating Results of our Natural Gas Operations

	Years Ended June 30
	2007			2006			2005
	(In thousands)
Natural Gas Operations
Operating revenues	$	46,439		$	55,453		$	44,555
Gas Purchased		33,542			43,161			32,559
Gross Margin		12,897			12,292			11,996
Operating expenses		9,307			9,160			9,666
Operating income		3,590			3,132			2,330
Other (income)		(229	)		(358	)		(166	)
Income before interest and taxes		3,819			3,490			2,496
Interest expense		1,897			1,425			1,775
Income before income taxes		1,922			2,065			721
Income tax (expense)		(653	)		(741	)		(216	)
Net income	$	1,269		$	1,324		$	505

Fiscal Year Ended June 30, 2007 Compared to Fiscal Year Ended June 30, 2006

Natural Gas Revenues and Gross Margins — The Natural Gas Operations’ operating revenues in fiscal 2007 decreased to $46,439,000 from $55,453,000 in fiscal 2006. This $9,014,000 decrease was due to lower gas commodity costs and decreased rates, even with higher volumes in the Montana market.

Gas purchases in the Natural Gas Operations decreased to $33,542,000 in fiscal 2007 from $43,161,000 in fiscal 2006. This $9,576,000 decrease in gas cost reflects lower gas commodity prices during fiscal 2007.

Gross margin increased to $12,897,000 in fiscal 2007 from approximately $12,292,000 for fiscal 2006. This increase of $605,000 corresponds with the colder weather and higher volumes in the Montana regulated utility.

Natural Gas Operating Expenses — The Natural Gas Operations’ operating expenses increased to approximately $9,307,000 in fiscal 2007 from to $9,160,000 for fiscal 2006. The $147,000 increase is attributed to $154,000 lower general and administrative charges, including the effects of the curtailment of additional contributions to the Retiree Health Plan, offset by increased depreciation and maintenance expense of $59,000 and $20,000 respectively, and a $222,000 increase in property tax expense.

Natural Gas Other Income — Other income decreased to $229,000 in fiscal 2007 from $358,000 in fiscal 2006. This $130,000 decrease was primarily due to additional income generated in fiscal 2006 for services to customers compared to what has been provided in fiscal 2007.

Natural Gas Interest Expense — Interest expense increased to $1,827.000 in fiscal 2007 from $1,425,000 in fiscal 2006. This $471,000 increase was primarily due to the write-off of debt issue costs associated with the refinancing of long term debt, offset by decreased short term borrowings and the associated interest.

Natural Gas Income Tax Benefit (Expense) — Income tax expenses decreased $88,000 from $741,000 in fiscal 2006 to $653,000 in fiscal 2007, due to lower income before taxes.

Fiscal Year Ended June 30, 2006 Compared to Fiscal Year Ended June 30, 2005

Natural Gas Revenues and Gross Margins — The Natural Gas Operations’ operating revenues in fiscal 2006 increased to $55,452,000 from $44,555,000 in fiscal 2005. This $10,897,000 increase was due to higher gas commodity costs and increased rates.

Gas purchases in the Natural Gas Operations increased by $10,957,000 from $32,559,000 in fiscal 2005 to $43,161,000 in fiscal 2006. The increase in gas cost reflects higher gas commodity prices during fiscal 2006.

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Gross margin was approximately $12,292,000 for fiscal 2006 compared to approximately $11,996,000 in fiscal 2005. The increase of $296,000 corresponds with the higher revenues and rate increases explained above.

Natural Gas Operating Expenses — The Natural Gas Operations’ operating expenses were approximately $9,160,000 in fiscal 2006 as compared to $9,666,000 for fiscal 2005. The $506,000 decrease can be attributed to lower general and administrative charges, including the effects of the curtailment of additional contributions to the Retiree Health Plan, lower depreciation expense, and lower expenses for outside professional services.

Natural Gas Other Income — Other income increased $192,000 from $166,000 in fiscal 2005 to $358,000 in fiscal 2006, primarily due to additional income generated in fiscal 2006 for services to customers over what had been provided in prior years and other miscellaneous income.

Natural Gas Interest Expense — Interest expense decreased $350,000, from $1,775,000 in fiscal 2005 to $1,425,000 in fiscal 2006, primarily due to improved cash flow from operations that enabled us to limit the use of our line of credit.

Natural Gas Income Tax Expense — Income tax expenses increased $525,000, from $216,000 in fiscal 2005 to $741,000 in fiscal 2006, due to higher income before taxes.

Operating Results of our EWR Operations

	Years Ended June 30
	2007			2006			2005
	(In thousands)
Energy West Resources
Operating revenues	$	12,545		$	18,832		$	22,910
Gas Purchased		10,264			17,238			20,951
Gross Margin		2,281			1,594			1,959
Operating expenses		559			711			1,230
Operating income		1,722			883			729
Other (income)		(2	)		(33	)		(67	)
Income before interest and taxes		1,724			916			796
Interest expense		185			182			282
Income before income taxes		1,539			734			514
Income tax (expense)		(593	)		(284	)		(204	)
Net income	$	946		$	450		$	310

Fiscal Year Ended June 30, 2007 Compared to Fiscal Year Ended June 30, 2006

With the sale of our Arizona propane assets, we have reclassified our former propane operation, Missouri River Propane, into our EWR Operations segment. This is a small unregulated propane supply operation that provides propane to our affiliated regulated company accounted for in our Natural Gas segment. Net losses from this operation for the fiscal years 2007, 2006 and 2005 were $12,000, $9,000 and $15,000 respectively.

EWR Revenues and Gross Margins — Revenues in EWR decreased $6,336,000 from $18,832,000 in fiscal 2006 to $12,545,000 in fiscal 2007. Retail gas revenues decreased by approximately $6,108,000, with $4,525,000 of the decrease due to the loss of two large customers and the remainder due to lower index prices for natural gas in fiscal 2007 as compared to fiscal 2006. Mark-to-market revenues decreased by $156,000 in fiscal 2007 versus fiscal 2006.

EWR’s fiscal 2007 gross margin of $2,281,000 represents an increase of $687,000 from gross margin of $1,594,000 earned in fiscal 2006. Gross margin from gas production increased by $367,000 due to renegotiation of contracts from low fixed prices to an index based price. Gross margin from retail gas sales increased by $532,000 due to new business in our Wyoming market and the re-negotiation of expiring contracts on more favorable terms.

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These increases are offset by the $156,000 decrease in mark-to-market revenue mentioned above and the loss of the two large customers.

EWR Operating Expenses — Operating expenses of EWR decreased approximately $152,000 from $711,000 for fiscal 2006 to $559,000 for fiscal 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 is due to reductions in general administrative expenses.

EWR Other Income — Other income decreased by $31,000 from $33,000 in fiscal 2006 to $2,000 in fiscal 2007. The income included in 2006 was attained from the settlement of a contract dispute.

EWR Interest Expense — Interest expense increased $3,000 from $182,000 in fiscal 2006 to $185,000 in fiscal 2007 as a result of amortization of debt issue costs in the current fiscal year, offset by minimal use of our line of credit.

EWR Income Tax Expense — Income tax expense increased from $284,000 in fiscal 2006 to $593,000 in fiscal 2007 because of higher pre-tax income.

Fiscal Year Ended June 30, 2006 Compared to Fiscal Year Ended June 30, 2005

EWR Revenues and Gross Margins — Revenues in EWR decreased $4,078,000 from $22,910,000 in fiscal 2005 to $18,832,000 in fiscal 2006. A decrease of $3,825,000 in gas sales due to the loss of three large customers made up the majority of the total decrease in revenues. Electric sales and production and gathering revenue showed decreases of $155,000 and $38,000, respectively. The change in revenue for derivative contract valuation was $284,000 less for fiscal 2006 than in fiscal 2005.

EWR’s fiscal 2006 gross margin of $1,594,000 represents a decrease of $365,000 from gross margin earned in fiscal 2005. Some of the difference is related to the $116,000 derivative contract valuation mentioned above. The remainder was related to the production, marketing, and gathering activities.

EWR Operating Expenses — Operating expenses of EWR decreased approximately $519,000 from $1,230,000 for fiscal 2005 to $711,000 for fiscal 2006. The majority of this decrease can be attributed to general and administrative costs being $462,000 lower in fiscal 2006, including the effects of the curtailment of additional contributions to the Retiree Heath Plan. Most of the expense reductions occurred in outside services and payroll/benefits. Depreciation also decreased by $25,000.

EWR Other Income — Other income decreased by $34,000 from $67,000 in fiscal 2005 to $33,000 in fiscal 2006. The income included here was attained from the settlement of a contract dispute.

EWR Interest Expense — Interest expense decreased $100,000 from $282,000 in fiscal 2006 to $182,000 in fiscal 2006 as a result of minimal use of our line of credit.

EWR Income Tax Expense — Income tax expense increased from $204,000 in fiscal 2005 to $284,000 in fiscal 2006 because of higher pre-tax income.

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Operating Results of our Pipeline Operations

	Years Ended June 30
	2007			2006			2005
	(In thousands)
Pipeline Operations
Operating revenues	$	388		$	411		$	424
Gas Purchased		0			0			0
Gross Margin		388			411			424
Operating expenses		289			149			202
Operating income		99			262			222
Other (income)		(11	)		0			(2	)
Income before interest and taxes		110			262			224
Interest expense		42			41			56
Income before income taxes		68			221			168
Income tax (expense)		(26	)		(85	)		(55	)
Net income	$	42		$	136		$	113

Fiscal Year Ended June 30, 2007 Compared to Fiscal Year Ended June 30, 2006

Pipeline Revenues and Gross Margins — Pipeline Operations revenue consists only of gathering and transmission revenues related to the pipelines located in Wyoming and Montana. Pipeline Operations’ margin decreased from $411,000 in fiscal 2006 to $388,000 in fiscal 2007. The decrease of $23,000 was from a slight decrease in flow volumes.

Pipeline Operating Expenses — Operating expenses increased from $149,000 in fiscal 2006 to $289,000 in fiscal 2007. The $140,000 increase was the result of increases in audit and legal expenses associated with our FERC regulated line, and additional maintenance costs in the current fiscal year. A property tax accrual adjustment in fiscal 2006 resulted in $16,000 less property tax expense recognized in fiscal 2006 than fiscal 2007.

Pipeline Other Income — Other income increased from $0 in fiscal 2006 to $11,000 in fiscal 2007 because no activities that produce other income took place in fiscal 2006.

Pipeline Interest Expense — Interest expense remained fairly constant at $41,000 and $42,000 in fiscal 2006 and 2007, respectively, in Pipeline operations.

Pipeline Income Tax (Expense) — Income tax expense decreased from $85,000 in fiscal 2006 to $26,000 in fiscal 2007. The decrease is due to lower pre-tax income in fiscal 2007 compared to fiscal 2006.

Fiscal Year Ended June 30, 2006 Compared to Fiscal Year Ended June 30, 2005

Pipeline Revenues and Gross Margins — Pipeline Operations revenue consists only of gathering and transmission revenues related to the pipelines located in Wyoming and Montana. Pipeline Operations’ margin decreased from $424,000 in fiscal 2005 to $411,000 in fiscal 2006. The decrease of $13,000 was from a slight decrease in flow volumes.

Pipeline Operating Expenses — Operating expenses decreased from $202,000 in fiscal 2005 to $149,000 in fiscal 2006. The $53,000 decrease was the result of a reduction in payroll/benefits of $25,000 and a tax accrual adjustment of $27,000.

Pipeline Other Income — Other income decreased from $2,000 in fiscal 2005 to $0 in fiscal 2006 because no activities that produce other income took place in fiscal 2006.

Pipeline Interest Expense — Interest expense decreased from $56,000 in fiscal 2005 to $41,000 in fiscal 2006 due to minimal use of our line of credit.

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Pipeline Income Tax (Expense) — Income tax expense increased from $55,000 in fiscal 2005 to $85,000 in fiscal 2006. The increase is due to higher pre-tax income in fiscal 2006 compared to fiscal 2005.

Discontinued Operations

	Years Ended June 30
	2007			2006			2005
	(In thousands)
Discontinued Operations:
Income from discontinued operations before income tax	$	976		$	671		$	732
Gain from disposal of operations		5,479
Income tax (expense)		(2,500	)		(266	)		(278	)
Income from discontinued operations	$	3,955		$	405		$	454

Fiscal Year Ended June 30, 2007 Compared to Fiscal Year Ended June 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.

Income from discontinued operations before income tax — Income from operations increased $305,000, from $671,000 in fiscal year 2006 to $976,000 in fiscal year 2007 primarily due to the timing of the sale of assets. Fiscal 2006 included a full year of revenues and associated expense, while fiscal 2007 included only nine months of revenue and associated expenses. Since the utility business is weather sensitive and cyclical, we typically experience losses in the fourth quarter of our fiscal year. If we had not disposed of the Arizona assets, it is likely that net income before income taxes would have been comparable to prior years.

Gain from disposal of operations — The gain of $5,479,000 recognized in fiscal 2007 is from the sale of propane assets on April 1, 2007.

Income Tax (Expense) — Income tax expense increased by $2,234,000 from $266,000 in fiscal 2006 to $2,500,000 in fiscal 2007 due to higher pretax income and the gain on disposal of operations.

Fiscal Year Ended June 30, 2006 Compared to Fiscal Year Ended June 30, 2005

Income from discontinued operations before income tax — Income from operations decreased $61,000, from $732,000 in fiscal year 2005 to $671,000 in fiscal year 2006 due to a variety of factors including high prices and lower margins in the unregulated portion of the segment, offset by cost savings in expenses, and reduced interest expense due to lower borrowings.

Income Tax (Expense) — Income tax expense decreased by $12,000 from $278,000 in fiscal 2005 to $266,000 in fiscal 2006 due to lower pretax income.

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 partially upon our $20,000,000 credit facility at LaSalle shown as line of credit on the accompanying balance sheet and described under “Liquidity and Capital Resources,” below. Our use of the LaSalle line of credit was $0 at both June 30, 2007, and 2006. In addition, we had temporary investments recorded with cash balances on the accompanying balance sheets of $5,500,000 and $1,000,000 at June 30, 2007 and 2006, respectively. This improvement in our cash position is primarily due to increased net income, decreased receivables, an increase in accounts payable, as well as the proceeds from the sale of Arizona assets.

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We made capital expenditures for continuing operations of $2,407,000, $1,866,000, and $2,188,000 during fiscal 2007, 2006, and 2005, respectively. We finance our capital expenditures on an interim basis by the use of our operating cash flow and use of the LaSalle revolving line of credit.

Long-term debt decreased to $13,000,000 at June 30, 2007, compared with $17,605,000 at June 30, 2006. This $4,605,000 decrease resulted from the payoff of the LaSalle 2004 $6,000,000 note with proceeds from the sale of Arizona assets, and the refinancing of our remaining long-term debt.

Cash increased to $7,010,000 at June 30, 2007, compared with $1,640,000 at June 30, 2006. This $5,370,000 increase in cash for the year ended June 30, 2007 is compared with the $1,545,000 increase and $1,229,000 decrease in cash for the years ended June 30, 2006 and June 30, 2005, respectively, as shown in the following table:

	Years Ended June 30,
	2007			2006			2005
Cash provided by (used in) operating activities	$	(1,271,000	)	$	8,529,000		$	737,000
Cash used in investing activities		15,819,000			(1,583,000	)		(1,859,000	)
Cash provided by (used in) financing activities		(9,178,000	)		(5,401,000	)		(107,000	)
Increase (decrease) in cash	$	5,370,000		$	1,545,000		$	(1,229,000	)

For the year ended June 30, 2007, cash from operating activities decreased $9,800,000 as compared to the year ended June 30, 2006, primarily because of the sale of the Arizona propane assets, with both assets and liabilities held for sale decreasing, as well as deferred taxes. The proceeds from the sale are recorded as cash flows from the sale of assets in investing activities, described below. Other items affecting the use of cash included a decrease in other liabilities of $2,086,000, an increase of accounts receivable of $510,000, and an increase in amounts paid for inventory of $615,000. For the year ended June 30, 2006, cash provided by operating increased by $7,792,000 as compared to the year ended June 30, 2005, primarily because of the increase in net income of $935,000, decreases in accounts receivable and recoverable cost of gas purchases of $1,451,000 and $1,034,000 respectively, and an increase of accounts payable of $549,000.

For the year ended June 30, 2007, cash provided by investing activities increased $17,402,000 as compared to the year ended June 30, 2006, primarily due to the proceeds of $17,899,000 from the sale of propane assets and increases in customer advances of $212,000, partially offset by an increase in capital expenditures. For the year ended June 30, 2006, cash used in investing activities decreased $276,000 as compared to the year ended June 30, 2005, due primarily to a $322,000 decrease in capital expenditures, offset by decreases in contributions in aid of construction.

For the year ended June 30, 2007, cash used in financing activities increased by $3,770,000 as compared to the year ended June 30, 2006. We refinanced our long-term debt and paid off a five-year note with LaSalle, which resulted in a net use of cash of $5,663,000. We paid $1,518,000 in dividends in fiscal 2007 compared to $495,000 in fiscal 2006. The sale of common stock resulted in cash proceeds of $597,000, and the repurchase of common stock used $2,276,000. In fiscal 2006, the primary use of cash from financing activities was the payoff of the line of credit of $3,9000,000, dividends paid of $495,000, and repayment of long-term debt of $1,027,000. For the year ended June 30, 2005, cash used for financing activities included $2,980,000 repayment of long-term debt and $2,830,000 repayment of line of credit, offset by proceeds from short-term borrowing of $3,500,000, and proceeds from the sale of common stock of $2,203,000.

Governmental Regulation

Our utility operations are subject to regulation by the MPSC, the WPSC, and, until the sale of the Arizona operations, the ACC. Such regulation plays a significant role in determining our cash flows. The commissions approve rates that are intended to permit a reasonable rate of return on investment. Our tariffs allow us to pass the cost of gas through to our customers. There is some delay, however, between the time that the gas costs are incurred by us and the time that we recover such costs from our customers as part of our gas cost recovery mechanism. The MPSC final order was effective September 1, 2005 and is estimated to provide additional gross margin of

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approximately $800,000 annually. In addition, a final order for the West Yellowstone general rate filing was approved for approximately $200,000 annually and became effective on November 1, 2004.

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.

One June 29, 2007, we replaced our existing credit facility and long-term notes with a new $20,000,000 revolving credit facility, and issued $13,000,000 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, we established our new five-year unsecured credit facility with LaSalle, replacing a previous $20,000,000 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, 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
Year Ended June 30, 2006
Minimum borrowing	$	3,100,000	$	5,200,000	$	—	$	—
Maximum borrowing	$	5,200,000	$	12,250,000	$	12,050,000	$	—
Average borrowing	$	4,167,000	$	9,489,000	$	5,619,000	$	—
Year Ended June 30, 2005
Minimum borrowing	$	7,729,000	$	12,688,000	$	3,500,000	$	2,700,000
Maximum borrowing	$	13,129,000	$	14,629,000	$	13,929,000	$	3,900,000
Average borrowing	$	10,196,000	$	13,982,000	$	8,110,000	$	3,167,000

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 preceding60-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 June 30, 2007 and 2006, we believe we are in compliance with the financial covenants under our debt agreements.

At June 30, 2007, we had approximately $7,010,000 of cash on hand. In addition, at June 30, 2007, we had no borrowings under the $20,000,000 LaSalle revolving line of credit. Our short-term borrowings under our lines of credit during fiscal 2007 had a daily weighted average interest rate of 8.56% per annum. At June 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

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

The total amount outstanding under all of our long term debt obligations was approximately $13,000,000 and $17,600,000, at June 30, 2007 and June 30, 2006, respectively. The portion of such obligations due within one year was $0 at June 30, 2007, and approximately $1,058,000 at June 30, 2006.

In July 2006, we entered into an agreement to sell certain of our assets related to our Arizona propane business for cash of approximately $15,000,000, 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 us to take advantage of opportunities to enhance or expand our existing operations and to acquire additional businesses or assets on favorable terms if and when those opportunities arise.

Contractual Obligations

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

			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		97,224		90,624		6,600		—		—
Transportation and Storage Obligation(c)	$	11,493,080		4,367,715		7,125,365		—		—
Total Obligations	$	32,598,304	$	5,259,139	$	8,733,565	$	1,601,600	$	17,004,000

(a)	Our long-term debt interest payments are projected based on actual interest rates on long-term debt until the underlying debts mature.
(b)	See Note 7 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.

See Note 12 of the Notes to Consolidated Financial Statements for other commitments and contingencies.

Capital Expenditures

We conduct ongoing construction activities in all of our utility service areas in order to support expansion, maintenance, and enhancement of our gas pipeline systems. In fiscal 2007, 2006, and 2005, our total capital expenditures were approximately $2,406,000, $1,866,000, and $2,188,000, respectively. Expenditures for fiscal 2007, 2006, and 2005 were limited to essential needs only. We estimate future cash requirements for capital expenditures will be as follows:

			Estimated
			Future Cash
	Actual		Requirements
	2007		2008
	(In thousands)
Natural Gas Operations	$	2,024	$	2,059
Energy West Resources		361		—
Pipeline Operations		21		—
Total capital expenditures	$	2,406	$	2,059

28

New Accounting Pronouncements

In February 2006, the FASB issued SFAS No. 155,Accounting for Certain Hybrid Financial Instruments(“SFAS 155”), which amends SFAS No. 133,Accounting for Derivative Instruments and Hedging Activitiesand SFAS No. 140,Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities. SFAS 155 simplifies the accounting for certain derivatives embedded in other financial instruments by allowing them to be accounted for as a whole if the holder elects to account for the whole instrument on a fair value basis. The statement also clarifies and amends certain other provisions of SFAS No. 133 and SFAS No. 140. SFAS 155 is effective for all financial instruments acquired, issued, or subject to a remeasurement event occurring in fiscal years beginning after September 15, 2006. We do not expect the adoption of SFAS 155 to have an impact on our results of operations or financial condition.

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. At this time, we have not completed our review and assessment of the impact of adoption of FIN 48.

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.

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 7A.   Quantitative and Qualitative Disclosures about Market Risk

We are subject to certain market risks, including commodity price risk (i.e., natural gas 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

29

consider additional actions management may take to mitigate our exposure to such changes. Actual results may differ. See the Notes to our Consolidated Financial Statements for a description of our accounting policies and other information related to these financial instruments.

Commodity Price Risk

We seek to protect itself against natural gas price fluctuations by limiting the aggregate level of net open positions that are exposed to market price changes. We manage such open positions with policies that are 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 although revenues and cost of sales are impacted by changes in natural gas prices, our margin is not significantly impacted by these changes.

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. In the past, some of our notes payable were subject to variable interest rates, which we mitigated by entering into interest rate swaps. A hypothetical 100 basis point change in market rates applied to the balance of the notes payable could change interest expense by approximately $26,000 annually.

Credit Risk

Credit risk relates to the risk of loss that we would incur as a result of non-performance by counterparties of their contractual obligations under the various instruments with us. 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 counter-party may default due to circumstances relating directly to it, but also the risk that a counterparty may default due to circumstances that relate to other market participants that have a direct or indirect relationship with such counterparty. We seek to mitigate credit risk by evaluating the financial strength of potential counterparties. However, despite mitigation efforts, defaults by counterparties may occur from time to time. To date, no such default has occurred.

Item 8.   Financial Statements and Supplementary Data.

Our Consolidated Financial Statements begin onpage F-1 of this Annual Report onForm 10-K.

Item 9.   Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.

Not applicable.

Item 9A.   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 Annual Report onForm 10-K, is recorded, processed, summarized and reported within the time periods specified by the Securities and Exchange Commission. Disclosure controls also are 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 Annual 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

30

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 Annual Report onForm 10-K, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures (as defined inRules 13a-15(e) and15d-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.

Item 9B.   Other Information.

Not applicable.

PART III

Item 10.   Directors, Executive Officers and Corporate Governance.

Information required by this item is incorporated by reference to the material appearing under the headings “The Board of Directors,” “Executive Officers ,” “Section 16(a) Beneficial Ownership Reporting Compliance,” “Code of Ethics,” and “Audit Committee Report” in the Proxy Statement for our 2007 Annual Meeting.

Item 11.   Executive Compensation.

Information required by this item is incorporated by reference to the material appearing under the headings “Director Compensation” “Compensation Discussion and Analysis,” and “Executive Compensation,” “Compensation Committee Interlocks and Insider Participation” and “Compensation Committee Report” in the Proxy Statement for our 2007 Annual Meeting.

Item 12.   Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.

Information required by this item is incorporated by reference to the material appearing under the heading “Security Ownership of Principal Shareholders and Management,” and “Equity Compensation Plan Information” in the Proxy Statement for our 2007 Annual Meeting.

Item 13.   Certain Relationships and Related Transactions and Director Independence.

Information required by this item is incorporated by reference to the material appearing under the heading “Certain Relationships and Related Transactions” and “Director Independence” in the Proxy Statement for our 2007 Annual Meeting.

Item 14.   Principal Accountant Fees and Services.

Information required by this item is incorporated by reference to the material appearing under the heading “Principal Accountant Fees and Services” in the Proxy Statement for our 2007 Annual Meeting.

31

PART IV

Item 15.   Exhibits and Financial Statement Schedules.

(a)   Financial Statements:

	Page
Report of Independent Registered Public Accounting Firm — Hein & Associates LLP		F-2
Consolidated Balance Sheets		F-3
Consolidated Statements of Income		F-4
Consolidated Statements of Stockholders’ Equity		F-5
Consolidated Statements of Cash Flows		F-6
Notes to Consolidated Financial Statements		F-8
Schedule II — Valuation and Qualifying Accounts		34

(b)   Exhibit Index.

Exhibit
Number	Description
3.1(a)	Restated Articles of Incorporation. Exhibit 3.1 to Amendment No. 1 to the Registrant’s Annual Report onForm 10-K/A for the year ended June 30, 1996, as filed on July 8, 1997, is incorporated herein by reference.
3.1(b)	Articles of Amendment to the Articles of Incorporation dated June 3, 2004. Exhibit 3.2 to the Registrant’s Current Report onForm 8-K, as filed on June 4, 2007, is incorporated herein by reference.
3.1(c)**	Articles of Amendment to the Articles of Incorporation dated October 31, 2005.
3.1(d)	Articles of Amendment to the Articles of Incorporation dated May 29, 2007. Exhibit 3.1 to the Registrant’s Current Report onForm 8-K, as filed on June 4, 2007, is incorporated herein by reference.
3.2	Amended and Restated Bylaws. Exhibit 3.2 to the Registrant’s Current Report onForm 8-K, as filed on March 5, 2004, is incorporated herein by reference.
10.1(a)	Satisfaction and Discharge of Indenture dated June 22, 2007, between the Registrant and HSBC Bank USA, National Association, as Successor Trustee for the Series 1997 Notes. Exhibit 10.1 to the Registrant’s Current Report onForm 8-K, as filed July 5, 2007, is incorporated herein by reference.
10.1(b)	Satisfaction and Discharge of Indenture dated June 22, 2007, between the Registrant and US Bank National Association, as Successor Trustee for the Series 1993 Notes. Exhibit 10.2 to the Registrant’s Current Report onForm 8-K, as filed July 5, 2007, is incorporated herein by reference.
10.1(c)	Discharge of Obligor under Indenture dated June 22, 2007, between the Registrant and HSBC Bank USA, National Association, as Successor Trustee for theSeries 1992-B Bonds. Exhibit 10.3 to the Registrant’s Current Report onForm 8-K, as filed July 5, 2007, is incorporated herein by reference.
10.1(d)	Note Purchase Agreement dated June 29, 2007, between the Registrant and various Purchasers relating to 6.16% Senior Unsecured Notes due June 29, 2017. Exhibit 10.4 to the Registrant’s Current Report onForm 8-K, as filed July 5, 2007, is incorporated herein by reference.
10.1(e)	Credit Agreement dated as of June 29, 2007, by and among the Registrant and various financial institutions and LaSalle Bank National Association. Exhibit 10.5 to the Registrant’s Current Report onForm 8-K, as filed July 5, 2007, is incorporated herein by reference.
10.2*	Energy West, Incorporated 2002 Stock Option Plan. Appendix A to the Registrant’s Proxy Statement on Schedule 14A, as filed on October 30, 2002, is incorporated herein by reference.
10.3*	Employee Stock Ownership Plan Trust Agreement. Exhibit 10.2 to Registration Statement onForm S-1 (FileNo. 33-1672) is incorporated herein by reference.
10.4*	Management Incentive Plan. Exhibit 10.12 to the Registrant’s Annual Report onForm 10-K/A for the year ended June 30, 1996, filed on July 8, 1997, is incorporated herein by reference.
10.5*	Energy West Senior Management Incentive Plan. Exhibit 10.19 to the Registrant’s Annual Report onForm 10-K for the year ended June 30, 2002, as filed on September 30, 2002, is incorporated herein by reference.

32

Exhibit
Number	Description
10.6*	Energy West Incorporated Deferred Compensation Plan for Directors. Exhibit 10.20 to the Registrant’s Annual Report onForm 10-K for the year ended June 30, 2002, as filed on September 30, 2002, is incorporated herein by reference.
10.10*	Employment Agreement entered into as of June 23, 2004, between the Company and David Cerotzke. Exhibit 10.16 to the Registrant’s Annual Report onForm 10-K for the year ended June 30, 2004, as filed on December 17, 2004, is incorporated herein by reference.
10.11*	Employment Agreement entered into as of June 23, 2004, between the Company and John Allen. Exhibit 10.17 to the Registrant’s Annual Report onForm 10-K for the year ended June 30, 2004, as filed on December 17, 2004, is incorporated herein by reference.
10.12*	Form of the agreement used to grant options under the 2002 Stock Option Plan. Exhibit 10.17 to the Registrant’s Annual Report onForm 10-K for the year ended June 30, 2005, as filed on September 27, 2005, is incorporated herein by reference.
10.13	Propane Supply Agreement dated April 1, 2005 between SemStream, L.P. and Energy West Propane, Inc. Exhibit 10.18 to the Registrant’s Annual Report onForm 10-K for the year ended June 30, 2005, as filed on September 27, 2005, is incorporated herein by reference.
10.14*	First Amendment to Employment Agreement between the Company and David Cerotzke entered into as of January 5, 2006. Exhibit 10.21 to the Registrant’s Annual Report onForm 10-Q for the quarter ended March 31, 2006 is incorporated herein by reference.
10.15	Asset Purchase Agreement, dated as of July 17, 2006, by and between the Registrant 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 onForm 8-K dated July 17, 2006 is incorporated herein by reference.
10.16*	Employment Agreement between the Registrant and Kevin J. Degenstein, effective September 18, 2006. Exhibit 10.2 to the Registrant’s Current ReportForm 8-K dated September 18, 2006 is incorporated herein by reference.
10.19*	Separation Agreement dated September 18, 2006, between the Registrant and Tim Good. Exhibit 10.3 to the Registrant’s Current Report onForm 8-K dated September 28, 2006 is incorporated herein by reference.
10.20*	Separation Agreement dated September 27, 2006, between the Registrant and John C. Allen. Exhibit 10.4 to the Registrant’s Current Report onForm 8-K dated September 28, 2006 is incorporated herein by reference.
10.21	Stock Purchase Agreement dated as of May 30, 2007 by and among Mark D. Grossi Living Trust U/A DTD. Feb. 17, 2006, Mark D. Grossi, TTEE, Mark D. Grossi, a Trustee of Seller and the Registrant. Exhibit 10.1 to the Registrant’s Current Report onForm 8-K dated June 4, 2007 is incorporated herein by reference.
10.22**	Operating Agreement of Kykuit Resources, LLC
14**	Code of Business Conduct
21**	Company Subsidiaries
23.1**	Consent of Hein & Associates LLP
31**	Certifications pursuant to SEC ReleaseNo. 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

(c)   Financial Statement Schedules:

33

Schedule II

Valuation and Qualifying Accounts
Energy West, Incorporated
June 30, 2007

	Balance at		Charged to		Write-Offs			Balance
	Beginning		Costs &		Net of			at End of
Description	of Period		Expenses		Recoveries			Period
Allowance for bad debts
Year Ended June 30, 2005	$	272,093	$	132,249	$	(137,638	)	$	266,704
Year Ended June 30, 2006	$	266,704	$	225,856	$	(371,107	)	$	121,453
Year Ended June 30, 2007	$	121,453	$	210,956	$	(268,355	)	$	64,054

All other schedules are omitted because they are not applicable or the required information is shown in the financial statements or notes thereto.

*	Indicates management contract or compensatory plan or arrangement.
**	Filed herewith.

34

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/  Thomas J. Smith

Thomas J. Smith

Interim President

(principal executive officer)

Date: September 27, 2007

KNOW ALL THESE PERSONS BY THESE PRESENTS, that each person whose signature appears below constitutes and appoints, jointly and severally, Thomas J. Smith and David A. Cerotzke, his true and lawful attorney-in-fact and agents, with full power of substitution, for him in any and all capacities, to sign any and all amendments to this Report onForm 10-K, and to file the same, with exhibits thereto and other documents in connection therewith, with the Securities and Exchange Commission, hereby ratifying and confirming all that said attorney-in-fact or his substitute, may do or cause to be done by virtue hereof.

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.

/s/  Thomas J. Smith Thomas J. Smith	Interim President and Director (Principal Executive Officer)	September 27, 2007
/s/  Wade F. Brooksby Wade F. Brooksby	Chief Financial Officer and Secretary (Principal Financial Officer and Principal Accounting Officer)	September 27, 2007
/s/  David A. Cerotzke David A. Cerotzke	Director	September 27, 2007
/s/  W.E. Argo W.E. Argo	Director	September 27, 2007
/s/  Mark D. Grossi Mark D. Grossi	Director	September 27, 2007
/s/  Richard M. Osborne Richard M. Osborne	Chairman of the Board	September 27, 2007
/s/  Steven A. Calabrese Steven A. Calabrese	Director	September 27, 2007
/s/  James E. Sprague James E. Sprague	Director	September 27, 2007
/s/  James R. Smail James R. Smail	Director	September 27, 2007

35

CONSOLIDATED FINANCIAL STATEMENTS
OF

ENERGY WEST, INCORPORATED AND SUBSIDIARIES

TABLE OF CONTENTS

	Page
Report of Independent Registered Public Accounting Firm — Hein & Associates LLP		F-2
Consolidated Balance Sheets as of June 30, 2007 and 2006		F-3
Consolidated Statements of Income for the Years Ended June 30, 2007, 2006, and 2005		F-4
Consolidated Statements of Changes in Stockholders’ Equity for the Years Ended June 30, 2007, 2006, and 2005		F-5
Consolidated Statements of Cash Flows for the Years Ended June 30, 2007, 2006, and 2005		F-6
Notes to Consolidated Financial Statements		F-8

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders

Energy West, Incorporated

Great Falls, Montana

We have audited the consolidated balance sheets of Energy West, Incorporated and subsidiaries as of June 30, 2007 and 2006, and the related consolidated statements of income, stockholders’ equity and cash flows for each of the three years in the period ended June 30, 2007. Our audits also included the financial statement schedule as of, and for the three years in the period ended June 30, 2007 listed in the index as Item 15. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Energy West, Incorporated and subsidiaries as of June 30, 2007 and 2006, and the results of their operations and their cash flows for each of the three years in the period ended June 30, 2007, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

/s/ HEIN & ASSOCIATES LLP

Denver, Colorado

September 27, 2007

F-2

ENERGY WEST INCORPORATED AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS,

June 30, 2007 and 2006

	2007		2006
ASSETS
Current Assets:
Cash	$	7,010,020	$	1,639,578
Accounts receivable less $64,054 and $121,453 respectively, allowance for bad debt		3,532,083		3,968,105
Unbilled gas		649,939		723,810
Derivative assets		57,847		137,865
Natural gas and propane inventories		5,474,309		4,858,599
Materials and supplies		377,296		343,527
Prepayment and other		142,964		261,764
Income tax receivable		162,432		—
Recoverable cost of gas purchases		307,899		79,511
Deferred tax asset		53,370		—
Assets held for sale		—		11,656,570
Total current assets		17,768,159		23,669,329
Property, Plant and Equipment, Net		30,473,991		29,889,873
Deferred Charges		3,031,425		4,108,173
Other Assets		560,463		263,370
TOTAL ASSETS	$	51,834,038	$	57,930,745
LIABILITIES AND CAPITALIZATION
Current Liabilities:
Accounts payable	$	4,543,525	$	3,572,055
Current portion of long-term debt		—		1,058,213
Derivative liabilities		58,018		42,664
Accrued income taxes		—		1,320,431
Deferred income taxes		—		269,163
Accrued and other current liabilities		3,092,726		3,711,669
Liabilities held for sale		—		822,242
Total current liabilities		7,694,269		10,796,437
Other Obligations:
Deferred income taxes		4,585,170		5,835,886
Deferred investment tax credits		271,158		292,220
Other long-term liabilities		3,987,731		4,236,089
Total		8,844,059		10,364,195
Long-Term Debt		13,000,000		17,605,000
Commitments and Contingencies (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, 2,859,104 and 2,934,177 shares outstanding at June 30, 2007 and 2006, respectively		428,866		440,127
Capital in excess of par value		6,082,159		7,634,337
Retained earnings		15,784,685		11,090,649
Total stockholders’ equity		22,295,710		19,165,113
TOTAL CAPITALIZATION		35,295,710		36,770,113
TOTAL LIABILITIES AND CAPITALIZATION	$	51,834,038	$	57,930,745

See notes to consolidated financial statements

F-3

ENERGY WEST INCORPORATED AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

For the Years Ended June 30, 2007, 2006, and 2005

	2007			2006			2005
REVENUES:
Natural gas operations	$	46,439,506		$	55,452,395		$	44,554,815
Gas and electric — wholesale		12,545,359			18,831,929			22,910,131
Pipeline operations		388,175			411,237			424,038
Total revenues		59,373,040			74,695,561			67,888,984
COST OF SALES:
Gas purchased		33,541,993			43,160,830			32,558,716
Gas and electric — wholesale		10,264,633			17,237,396			20,951,529
Total cost of sales		43,806,626			60,398,226			53,510,245
GROSS MARGIN		15,566,414			14,297,335			14,378,739
Distribution, general, and administrative		6,197,529			6,389,130			7,308,697
Maintenance		566,683			504,671			520,997
Depreciation and amortization		1,692,486			1,671,647			1,789,700
Taxes other than income		1,696,936			1,453,375			1,478,848
Total expenses		10,153,634			10,018,823			11,098,242
OPERATING INCOME		5,412,780			4,278,512			3,280,497
OTHER INCOME		241,519			390,677			234,708
INTEREST (EXPENSE)		(2,124,155	)		(1,648,897	)		(2,112,757	)
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE		3,530,144			3,020,292			1,402,448
INCOME TAX (EXPENSE)		(1,272,664	)		(1,109,043	)		(474,735	)
INCOME FROM CONTINUING OPERATIONS		2,257,480			1,911,249			927,713
DISCONTINUED OPERATIONS:
Gain from disposal of operations		5,479,166			—			—
Income from discontinued operations		975,484			671,084			731,893
Income tax (expense)		(2,499,875	)		(265,663	)		(278,137	)
INCOME FROM DISCONTINUED OPERATIONS		3,954,775			405,421			453,756
NET INCOME	$	6,212,255		$	2,316,670		$	1,381,469
BASIC INCOME PER COMMON SHARE:
Income from continuing operations	$	0.76		$	0.65		$	0.35
Income from discontinued operations		1.34			0.14			0.17
	$	2.10		$	0.79		$	0.53
DILUTED INCOME PER COMMON SHARE:
Income from continuing operations	$	0.76		$	0.65		$	0.35
Income from discontinued operations		1.32			0.14			0.17
	$	2.08		$	0.79		$	0.53
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:
Basic		2,958,538			2,924,512			2,630,679
Diluted		2,989,382			2,948,046			2,630,679

See notes to consolidated financial statements.

F-4

ENERGY WEST INCORPORATED AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY

For the Years Ended June 30, 2007, 2006, and 2005

							Capital in
	Common			Common			Excess of			Retained
	Shares			Stock			Par Value			Earnings			Total
BALANCE AT JUNE 30, 2004		2,598,506		$	389,783		$	5,077,687		$	7,932,955		$	13,400,425
Stock contributions to 401(k) plan and deferred board stock compensation at $6.10 to $8.58 per share		26,558			3,984			197,791			—			201,775
Sale of common stock at $8.00 per share, net of issuance costs		287,500			43,125			2,159,831			—			2,202,956
Net income											1,381,469			1,381,469
BALANCE AT JUNE 30, 2005		2,912,564		$	436,892		$	7,435,309		$	9,314,424		$	17,186,625
Sales of common stock at $9.05 to $11.51 per share under the Company’s dividend reinvestment plan		640			96			6,068			(10,780	)		(4,616	)
Stock contributions at $9.05 to $11.51 to the 401(k) plan		1,943			284			39,337			(39,621	)		—
Stock Compensation		16,530			2,480			132,770			—			135,250
Exercise of stock options @ $8.49		2,500			375			20,853			—			21,228
Net income											2,316,670			2,316,670
Dividends @ $.17											(490,044	)		(490,044	)
BALANCE AT JUNE 30, 2006		2,934,177		$	440,127		$	7,634,337		$	11,090,649		$	19,165,113
Stock Compensation		8,775			1,316			83,769			—			85,085
Repurchase of Stock — stock buyback program		(146,348	)		(21,952	)		(2,173,109	)					(2,195,061	)
Costs associated with stock buyback								(81,280	)					(81,280	)
Stock option liability								115,603						115,603
Exercise of stock options @ $6.47 to 10.51		62,500			9,375			502,839			—			512,214
Net income											6,212,255			6,212,255
Dividends paid @ $.51											(1,518,219	)		(1,518,219	)
BALANCE AT JUNE 30, 2007		2,859,104		$	428,866		$	6,082,159		$	15,784,685		$	22,295,710

See notes to consolidated financial statements

F-5

ENERGY WEST INCORPORATED AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Years Ended June 30, 2007, 2006, and 2005

	2007			2006			2005
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	6,212,255		$	2,316,670		$	1,381,469
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation and amortization, including deferred charges and financing costs		3,011,727			2,356,448			2,493,177
Derivative assets		80,018			(18,796	)		80,179
Derivative liabilities		15,354			(71,573	)		(331,674	)
Deferred gain		(325,582	)		(643,280	)		(269,903	)
Gain on sale of assets		(5,479,166	)		—			(9,201	)
Investment tax credit		(21,062	)		(21,062	)		(21,062	)
Deferred gain on sale of assets		—			(23,639	)		(23,628	)
Deferred income taxes		(1,573,249	)		(259,022	)		2,361,589
Changes in assets and liabilities:
Accounts and notes receivable		509,893			1,450,570			65,083
Natural gas and propane inventories		(615,710	)		(1,615,395	)		800,254
Accounts payable		971,466			549,217			(337,825	)
Recoverable/refundable cost of gas purchases		(228,388	)		1,034,494			(514,288	)
Prepayments and other		118,800			(37,572	)		(19,490	)
Net assets held for sale		(1,585,772	)		(367,023	)		(189,016	)
Other assets		(275,609	)		1,895,776			(498,408	)
Other liabilities		(2,086,253	)		1,983,484			(4,230,788	)
Net cash provided by (used in) operating activities		(1,271,278	)		8,529,297			736,468
CASH FLOWS FROM INVESTING ACTIVITIES:
Construction expenditures		(2,406,910	)		(1,865,594	)		(2,187,614	)
Collection of note receivable		—			174,561			—
Proceeds from sale of assets		17,899,266			—			32,605
Customer advances received for construction		327,376			115,305			74,348
Increase (decrease) from contributions in aid of construction		—			(7,093	)		221,909
Net cash provided by (used in) investing activities		15,819,732			(1,582,821	)		(1,858,752	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Repayments of long-term debt		(18,663,213	)		(1,027,073	)		(2,979,706	)
Proceeds from lines of credit		11,012,000			14,850,000			10,100,000
Repayments of lines of credit		(11,012,000	)		(18,750,000	)		(12,930,062	)
Proceeds from long-term debt		13,000,000			—			—
Repurchase of common stock		(2,276,192	)		—			—
Proceeds from other short-term borrowing		—			—			3,500,000
Debt issuance cost		(317,539	)		—			—
Sale of common stock		597,151			21,229			2,202,956
Dividends paid		(1,518,219	)		(494,660	)		—
Net cash (used in) financing activities		(9,178,012	)		(5,400,504	)		(106,812	)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		5,370,442			1,545,972			(1,229,096	)
CASH AND CASH EQUIVALENTS:
Beginning of year		1,639,578			93,606			1,322,702
End of year	$	7,010,020		$	1,639,578		$	93,606

See notes to consolidated financial statements

F-6

ENERGY WEST INCORPORATED AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Years Ended June 30, 2006, 2005, and 2004

	2007		2006		2005
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Cash paid during the period for interest	$	1,410,114	$	1,047,633	$	2,290,133
Cash paid during the period for income taxes	$	5,474,500	$	8,000	$	447,000
SUPPLEMENTAL SCHEDULE OF NONCASH INVESTING AND FINANCING ACTIVITIES:
Shares issued to satisify deferred board compensation	$	84,046	$	135,242	$	201,775
Reclass of derivative liability to deferred gain		—		—		1,238,765
Shares issued under the Company’s 401k reinvestment plan		—		19,436		20,185
Capitalized interest	$	21,414	$	18,855	$	34,160

See notes to consolidated financial statements

F-7

ENERGY WEST, INCORPORATED AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended June 30, 2007, 2006, and 2005

1.   Summary of Business and Significant Accounting Policies

Nature of Business — Energy West, Incorporated (the “Company”) is a regulated public entity with certain non-regulated operations conducted through its subsidiaries. Our regulated utility operations involve the distribution and sale of natural gas to the public in and around Great Falls and West Yellowstone, Montana and Cody, Wyoming, and the distribution and sale of propane to the public through underground propane vapor systems in Cascade, Montana, and, until April 1, 2007, in and around Payson, Arizona. Our West Yellowstone, Montana operation is supplied by liquefied natural gas.

Our non-regulated operations included wholesale distribution of bulk propane in Arizona, and the retail distribution of bulk propane in Arizona, until the sale of the Arizona operations on April 1, 2007. The Company also markets gas and electricity in Montana and Wyoming through its non-regulated subsidiary, Energy West Resources (“EWR”).

Basis of Presentation — The accompanying consolidated financial statements have been prepared on a going concern basis, which contemplates the realization of assets and the satisfaction of liabilities in the normal course of business. Certain reclassifications of prior year reported amounts have been made for comparative purposes. The results of operations for the propane assets related to the sale of the Arizona assets have been reclassified as income from discontinued operations. The associated assets and liabilities are shown on the consolidated balance sheet of June 30, 2006, as “Assets held for sale” and “Liabilities held for sale”.

Principles of Consolidation — The consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries, Energy West Propane (“EWP”), EWR, and Energy West Development (“EWD” or Pipeline Operations). The consolidated financial statements also include our proportionate share of the assets, liabilities, revenues, and expenses of certain producing natural gas properties that were acquired in fiscal years 2002 and 2003. All intercompany transactions and accounts have been eliminated.

Segments — The Company reports financial results for four business segments: Natural Gas Operations, EWR, Pipeline Operations, and Discontinued Operations, formerly reported as Propane Operations. Summarized financial information for these four segments is set forth in Note 10.

Use of Estimates in Preparing Financial Statements — The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from these estimates. The Company has used estimates in measuring certain deferred charges and deferred credits related to items subject to approval of the various public service commissions with jurisdiction over the Company. Estimates are also used in the development of discount rates and trend rates related to the measurement of postretirement benefit obligations and accrual amounts, allowances for doubtful accounts, asset retirement obligations, valuing derivative instruments, estimating litigation reserves, and in the determination of depreciable lives of utility plant.

Natural Gas Inventories — Natural gas inventory is stated at the lower of weighted average cost or net realizable value except for Energy West Montana — Great Falls, which is stated at the rate approved by the Montana Public Service Commission (“MPSC”), which includes transportation and storage costs.

Accumulated Provisions for Doubtful Accounts — We encounter risks associated with the collection of our accounts receivable. As such, we record a provision for those accounts receivable that are considered to be uncollectible. In order to calculate the appropriate provision, we primarily utilize the historical accounts receivable write-off amounts. The underlying assumptions used for the provision can change from period to period and the provision could potentially cause a material impact to our income statement and working capital. The actual weather, commodity prices, and other internal and external economic conditions, such as the mix of the customer

F-8

ENERGY WEST, INCORPORATED AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

base between residential, commercial and industrial, may vary significantly from our assumptions and may impact our operating income.

Recoverable/Refundable Costs of Gas and Propane Purchases — The Company accounts for purchased gas and propane costs in accordance with procedures authorized by the MPSC, the Wyoming Public Service Commission (“WPSC”), and, until April 1, 2007 with the sale of our Arizona Propane operations, the Arizona Corporation Commission (“ACC”). Purchased gas and propane costs that are different from those provided for in present rates, and approved by the applicable commissions, are accumulated and recovered or credited through future rate changes. As of June 30, 2007 and June 30, 2006, the Company had unrecovered purchase gas costs of $307,899 and $79,511 respectively.

Property, Plant, and Equipment — Property, plant and equipment are recorded at original cost when placed in service. Depreciation and amortization on assets are generally recorded on a straight-line basis over the estimated useful lives, as applicable, at various rates. These assets are depreciated and amortized over three to forty years.

Contributions in Aid and Advances Received for Construction — Contributions in aid of construction are contributions received from customers for construction that are not refundable. Customer advances for construction includes advances received from customers for construction that are to be refunded wholly or in part.

Natural Gas Reserves — EWR owns an undivided interest in certain producing natural gas reserves on properties located in northern Montana. EWD also owns an undivided interest in certain natural gas producing properties located in northern Montana. The Company is depleting these reserves using the units-of-production method. The production activities are being accounted for using the successful efforts method. The oil and gas producing properties are included at cost in Property, Plant and Equipment, Net in the accompanying consolidated financial statements. The Company is not the operator of any of the natural gas producing wells on these properties. The production of the gas reserves is not considered to be significant to the operations of the Company as defined by Statement of Financial Accounting Standard (“SFAS”) No. 69, Disclosures About Oil and Gas Producing Properties.

Impairment of Long-Lived Assets — The Company evaluates its long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets or intangibles may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to future undiscounted net cash flows expected to be generated by the asset. If such assets are considered to be impaired, the impairment to be recognized is measured by the amount by which the carrying amount of the assets exceeds the fair value of the assets. As of June 30, 2007, 2006, and 2005, management does not consider the value of any of its long-lived assets to be impaired.

Stock-Based Compensation — On July 1, 2005, the Company adopted the provision of SFAS No. 123(R),“Share-Based Payment” (“SFAS No. 123(R)”). Accordingly, during fiscal year 2006 and 2007, the Company recorded $57,374, and $58,229, respectively, ($35,308 and $35,811 net of related tax effects) of compensation expense for stock options granted after July 1, 2005, and for the unvested portion of previously granted stock options that remained outstanding as of July 1, 2005.

F-9

ENERGY WEST, INCORPORATED AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Pro-Forma Disclosures — The Company elected to use the modified prospective transition method as permitted by SFAS No. 123(R) and therefore have not restated financial results for prior periods. The Company previously accounted for awards granted under the stock option plan under the intrinsic value method prescribed by Accounting Principles Opinion No. 25,Accounting for Stock Issued to Employeesand related interpretations, as permitted by SFAS No. 123,Accounting for Stock-Based Compensation,as amended by SFAS No. 148, “Accounting for Stock-Based Compensation — Transition and Disclosure, an Amendment of SFAS No. 123,”and provided pro forma disclosures required by those statements as if the fair value based method of accounting had been applied. Had compensation cost for issuance of such stock options been recognized based on the fair values of awards on the grant dates, in accordance with the method described in SFAS No. 123(R) for the year ended June 30, 2005, reported net income and per share amounts for years ended June 30, 2005 would have been as shown in the following table. The reported and pro forma net income and per share amounts for the year ended June 30, 2006 and 2007 are the same since stock-based compensation is calculated under the provisions of SFAS No. 123(R). The amounts for the year ended June 30, 2006 are included in the following table only to provide the detail for comparative presentation to the comparable period in 2005.

	2006			2005
Net income, as reported for the year ended June 30,	$	2,316,670		$	1,381,469
Add: stock-based employee compensation expense included in reported net income, net of related tax effects		35,308
Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects		(35,308	)		(51,450	)
Pro forma net income	$	2,316,670		$	1,330,019
Earnings per share:
Basic — as reported	$	0.79		$	0.53
Basic — pro forma	$	0.79		$	0.51
Diluted — as reported	$	0.79		$	0.53
Diluted — pro forma	$	0.79		$	0.51

In the fiscal years ended June 30, 2007, 2006 and 2005, 30,000, 48,500 and 70,000 options were granted, respectively. At June 30, 2007, 2006 and 2005, a total of 110,000, 145,500 and 126,000 options were outstanding, respectively.

	2007			2006			2005
Expected dividend rate		4.00	%		2.00	%		0.00	%
Risk free interest rate		5.10			4.87			3.90
Weighted average expected lives, in years		2.26			3.40			4.26
Price volatility		30.00	%		39.00	%		54.00	%
Total intrinsic value of options exercised	$	218,609		$	4,087		$	0
Total cash received from options exercised	$	512,175		$	21,228		$	0

Comprehensive Income — During the years ended June 30, 2007, 2006, and 2005, the Company had no components of comprehensive income other than net income.

Revenue Recognition — Revenues are recognized in the period that services are provided or products are delivered. The Company records gas distribution revenues for gas delivered to residential and commercial customers but not billed at the end of the accounting period. The Company periodically collects revenues subject to possible refunds pending final orders from regulatory agencies. When this occurs, appropriate reserves for such revenues collected subject to refund are established.

F-10

ENERGY WEST, INCORPORATED AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Derivatives — The accounting for derivative financial instruments that are used to manage risk is in accordance with SFAS No. 133,Accounting for Derivative Instruments and Hedging Activities, as amended by SFAS No. 138,Accounting for Certain Derivative Instruments and Certain Hedging Activities, which the Company adopted July 1, 2000, and SFAS No. 149,Amendment of Statement 133 on Derivatives and Hedging Activities, which the Company adopted July 1, 2003. Derivatives are recorded at estimated fair value and gains and losses from derivative instruments are included as a component of gas and electric — wholesale revenues in the accompanying consolidated statements of income. For fiscal 2004, the Company recognized a reduction of approximately $1,244,000 in “gas and electric — wholesale” revenues from derivative instruments. During fiscal 2005, the Company had an increase in revenues of $1,546,000 due to the change in the fair value of the derivative instruments and $214,000 in amortization of the deferred gain established in January 2005 when EWR reclassified two derivative contracts as “normal sales and purchases”. Pursuant to SFAS No. 133, as amended, contracts for the purchase or sale of natural gas at fixed prices and notional volumes must be valued at fair value unless the contracts qualify for treatment as a “normal” purchase or sale and the appropriate election has been made. As of June 30, 2006, and 2005, the Company had elected the normal treatment for the majority of its contracts. As of June 30, 2007, the Company has no derivative instruments designated and qualifying as SFAS No. 133 hedges.

Debt Issuance and Reacquisition Costs — Debt premium, discount, and issue costs are amortized over the life of each debt issue. Costs associated with refinanced debt are amortized over the remaining life of the new debt.

Cash and Cash Equivalents — All highly liquid investments with maturities of three months or less at the date of acquisition are considered to be cash equivalents. From time to time, the company has balances in excess of the FDIC insured amounts.

Earnings Per Share — Net income per common share is computed by both the basic method, which uses the weighted average number of our common shares outstanding, and the diluted method, which includes the dilutive common shares from stock options, as calculated using the treasury stock method. The only potentially dilutive securities are the stock options described in Note 11. Options to purchase 110,000, 145,500 and 126,000 shares of common stock were outstanding at June 30, 2007, 2006 and 2005, respectively. These options were excluded in the computation of diluted earnings per share for fiscal 2005 as the options were anti-dilutive.

Credit Risk — Our primary market areas are Montana, Wyoming, and, until April 1, 2007, Arizona. Exposure to credit risk may be impacted by the concentration of customers in these areas due to changes in economic or other conditions. Customers include individuals and numerous industries that may be affected differently by changing conditions. Management believes that its credit review procedures, loss reserves, customer deposits, and collection procedures have adequately provided for usual and customary credit related losses.

Effects of Regulation — The Company follows SFAS No. 71,Accounting for the Effects of Certain Types of Regulation, and its consolidated financial statements reflect the effects of the different rate-making principles followed by the various jurisdictions regulating the Company. The economic effects of regulation can result in regulated companies recording costs that have been or are expected to be allowed in the ratemaking process in a period different from the period in which the costs would be charged to expense by an unregulated enterprise. When this occurs, costs are deferred as assets in the balance sheet (regulatory assets) and recorded as expenses in the periods when those same amounts are reflected in rates. Additionally, regulators can impose liabilities upon a regulated company for amounts previously collected from customers and for amounts that are expected to be refunded to customers (regulatory liabilities).

Income Taxes — The Company files its income tax returns on a consolidated basis. Rate-regulated operations record cumulative increases in deferred taxes as income taxes recoverable from customers. The Company uses the deferral method to account for investment tax credits as required by regulatory commissions. Deferred income taxes are determined using the asset and liability method, under which deferred tax assets and liabilities are measured based upon the temporary differences between the financial statement and income tax bases of assets and liabilities, using current tax rates.

F-11

ENERGY WEST, INCORPORATED AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Financial Instruments — The fair value of all financial instruments with the exception of fixed rate long-term debt approximates carrying value because they have short maturities or variable rates of interest that approximate prevailing market interest rates. See Note 7 for a discussion of the fair value of the fixed rate long-term debt.

Asset Retirement Obligations (“ARO”) — The Company adopted SFAS No. 143,Accounting for Asset Retirement Obligationeffective July 1, 2002, and has recorded an asset and an asset retirement obligation in the accompanying consolidated balance sheet in “Property, plant and equipment, net,” and in “Other long-term liabilities.” The asset retirement obligation of $688,371 and $650,717 represents the estimated future liability as of June 30, 2007 and June 30, 2006 respectively, to plug and abandon existing oil and gas wells owned by EWR and EWD. EWR and EWD will depreciate the asset amount and increase the liability over the estimated useful life of these assets. In the future, the Company may have other asset retirement obligations arising from its business operations.

The Company has identified but not recognized ARO liabilities related to gas transmission and distribution assets resulting from easements over property not owned by the Company. These easements are generally perpetual and only require retirement action upon abandonment or cessation of use of the property for the specified purpose. The ARO liability is not estimable for such easements as the Company intends to utilize these properties indefinitely. In the event the Company decides to abandon or cease the use of a particular easement, an ARO liability would be recorded at that time.

Changes in the asset retirement obligation can be reconciled as follows:

Balance — July 1, 2005	$	618,473
Accretion		32,244
Balance — June 30, 2006		650,717
Accretion		37,654
Balance — June 30, 2007	$	688,371

New Accounting Pronouncements — In February 2006, the FASB issued SFAS No. 155,Accounting for Certain Hybrid Financial Instruments(“SFAS 155”), which amends SFAS No. 133,Accounting for Derivative Instruments and Hedging Activitiesand SFAS No. 140,Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities. SFAS 155 simplifies the accounting for certain derivatives embedded in other financial instruments by allowing them to be accounted for as a whole if the holder elects to account for the whole instrument on a fair value basis. The statement also clarifies and amends certain other provisions of SFAS No. 133 and SFAS No. 140. SFAS 155 is effective for all financial instruments acquired, issued, or subject to a remeasurement event occurring in fiscal years beginning after September 15, 2006. We do not expect the adoption of SFAS 155 to have an impact on our results of operations or financial condition.

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

F-12

ENERGY WEST, INCORPORATED AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

year commencing July 1, 2007. At this time, we have not completed our review and assessment of the impact of adoption of FIN 48.

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.

The company has 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.

2.   Discontinued Operations

Until March 31, 2007, we were engaged in the regulated sale of propane under the business name Energy West Arizona, or “EWA”, and the unregulated sale of propane under the business name Energy West Propane — Arizona, or “EWPA”, collectively known as EWP. EWP distributed propane in the Payson, Pine, and Strawberry, Arizona area located about 75 miles northeast of Phoenix in the Arizona Rim Country. EWP’s service area included approximately 575 square miles and a population of approximately 50,000.

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

SemStream purchased only the assets and business operations of EWP that pertain to the Business within the state of Arizona, and that also pertain to the Energy West Propane — Arizona division of our companyand/or EWP (collectively, the “Arizona Assets”). Pursuant to the Asset Purchase Agreement, SemStream paid a cash purchase price of $15,000,000 for the Arizona Assets, plus working capital.

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.

F-13

ENERGY WEST, INCORPORATED AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The gain on the sale of these assets is presented under the heading “Gain from disposal of operations”. The results of operations for the propane assets related to this sale have been reclassified as income from discontinued operations in the accompanying Statement of Income, and consist of the following:

	Years Ended June 30
	2007			2006			2005
	(In thousands)
Propane Operations — (Discontinued operations)
Operating revenues	$	10,266		$	9,583		$	8,820
Propane purchased		6,906			5,971			4,822
Gross Margin		3,360			3,612			3,998
Operating expenses		2,104			2,623			2,912
Operating income		1,256			989			1,086
Other (income)		(51	)		(114	)		(210	)
Income before interest and taxes		1,307			1,103			1,296
Interest expense		333			431			564
Income before income taxes		974			672			732
Income tax (expense)		(378	)		(266	)		(278	)
Income from discontinued operations		596			406			454
Gain from disposal of operations		5,479			—			—
Income tax (expense)		(2,120	)		—			—
Net Income	$	3,955		$	406		$	454

The small Montana wholesale distribution of propane to our affiliated utility that had been reported in Propane Operations is now being reported in EWR.

F-14

ENERGY WEST, INCORPORATED AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 Sheet at June 30, 2006, and consist of the following:

Assets and Liabilities Held for Sale

	June 30, 2006
Assets held for sale:
Accounts Receivable	$	194,746
Unbilled Gas		296,730
Propane Inventory		566,179
Materials and Supplies		111,701
Prepayments		29,096
Recoverable cost of gas purchases		1,243,931
Property, Plant and Equipment, Net		9,214,187
Total Assets held for sale		11,656,570
Liablilities held for sale:
Accounts Payable		20,203
Other Current Liabilities		148,634
Contributions in Aid of Construction		653,405
Total Liabilities held for sale		822,242
Net Assets Held for Sale	$	10,834,328

3.   Natural Gas Wells

In order to provide a stable source of natural gas for a portion of its requirements, EWR and EWD purchased ownership in two natural gas production properties and three gathering systems located in north central Montana. The purchases were made in May 2002 and March of 2003. The Company is depleting the cost of the gas properties using the units-of-production method. As of June 30, 2007, an independent reservoir engineer estimated the net gas reserves at 4.5 Bcf (unaudited) and a $9,658,000 net present value after applying a 10% discount (unaudited). The net book value of the gas properties totals $1,740,868 and is included in the “Property, plant and equipment, net” in the accompanying consolidated financial statements.

In fiscal 2007, the Company engaged in a limited drilling program of developmental wells on these existing properties. As of June 30, 2007, four wells had been drilled and were capitalized as part of the drilling program, with two wells finding production and being tied in to the gathering system. The reserves from these wells are included in the reserves listed above.

The wells are depleting based upon production at approximately 7% per year as of June 30, 2007. For the period ended June 30, 2007, EWR’s portion of the daily gas production was approximately 630 Mcf per day, or approximately 14% of EWR’s present volume requirements.

In March 2003, EWD acquired working interests in a group of producing natural gas properties consisting of 47 wells and a 75% ownership interest in a gathering system located in northern Montana.

For the period ended June 30, 2007, EWD’s portion of the daily gas production was approximately 280 Mcf per day, or approximately 5% of EWR’s present volume requirements.

F-15

ENERGY WEST, INCORPORATED AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

EWR and EWD’s combined portion of the estimated daily gas production from the reserves is approximately 910 Mcf, or approximately 19% of our present volume requirements. The wells are operated by an independent third party operator who also has an ownership interest in the properties. In 2002 and 2003 the Company entered into agreements with the operator of the wells to purchase a portion of the operator’s share of production. The production of the gas reserves is not considered to be significant to the operations of the Company as defined by SFASNo. 69,Disclosures About the Oil and Gas Producing Properties.

3.   Property, Plant and Equipment

Property, plant and equipment consist of the following as of June 30, 2007 and 2006:

	2007			2006
Gas transmission and distribution facilities	$	45,980,012		$	43,841,527
Land		139,132			139,132
Buildings and leasehold improvements		2,907,975			2,894,975
Transportation equipment		1,581,196			1,522,452
Computer equipment		4,481,310			4,969,189
Other equipment		3,752,790			3,686,676
Constructionwork-in-progress		258,029			70,127
Producing natural gas properties		2,381,883			2,082,903
		61,482,327			59,206,981
Accumulated depreciation, depletion, and amortization		(31,008,336	)		(29,317,108	)
Total	$	30,473,991		$	29,889,873

4.   Deferred Charges

Deferred charges consist of the following as of June 30, 2007 and 2006:

	2007		2006
Regulatory asset for property tax	$	2,013,623	$	2,303,015
Regulatory asset for income taxes		452,646		458,753
Regulatory assets for deferred environmental remediation costs		247,617		334,996
Other regulatory assets		—		20,258
Unamortized debt issue costs		317,539		991,151
Total	$	3,031,425	$	4,108,173

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

The property tax asset is recovered in rates over a ten-year period starting January 1, 2004. The income taxes and environmental remediation costs earn a return equal to that of the Company’s rate base. No other assets listed above earn a return or are recovered in the rate structure. Other regulatory assets are amortized over fiscal 2006.

F-16

ENERGY WEST, INCORPORATED AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

5.   Accrued and Other Current Liabilities

Accrued and other current liabilities consist of the following as of June 30, 2007 and 2006:

	2007		2006
Property tax settlement — current portion	$	243,000	$	243,000
Payable to employee benefit plans		132,131		275,377
Accrued vacation		224,588		258,831
Customer deposits		394,128		381,713
Accrued interest		9,069		140,648
Accrued taxes other than income		506,448		402,819
Deferred short-term gain		243,519		243,519
Deferred payments from levelized billing		605,031		844,344
Other		734,812		921,448
Total	$	3,092,726	$	3,711,699

6.   Other Long-Term Liabilities

Other long-term liabilities consist of the following as of June 30, 2007 and 2006:

	2007		2006
Asset retirement obligation	$	688,371	$	650,718
Contribution in aid of construction		1,313,907		1,301,575
Customer advances for construction		605,221		277,845
Accumulated postretirement obligation		—		139,200
Deferred gain — long-term*		82,063		325,582
Regulatory liability for income taxes		83,161		83,161
Property tax settlement		1,215,008		1,458,008
Total	$	3,987,731	$	4,236,089

* 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 Million British thermal unit (“MMBtu”).

7.   Credit Facility and Long-Term Debt

On June 29, 2007, the Company replaced its existing credit facility and long-term notes with a new $20,000,000 revolving credit facility with LaSalle Bank, N.A. (“LaSalle”), and issued $13,000,000 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 $20,000,000 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.

F-17

ENERGY WEST, INCORPORATED AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Long-term Debt — Long-term debt at June 30, 2007 and 2006 consists of the following:

	2007		2006
6.16% Senior Unsecured Notes	$	13,000,000	$	—
Series 1997 notes payable		—		7,840,000
Series 1993 notes payable		—		4,840,000
Series 1992B industrial development revenue obligations		—		880,000
Term loan		—		5,100,000
Capital lease		—		3,213
Total long-term debt		13,000,000		18,663,213
Less current portion of long-term debt		—		(1,058,213	)
Long-term debt	$	13,000,000	$	17,605,000

$13,000,000 6.16% Senior Unsecured Notes — On June 29, 2007, the Company authorized the sale of $13,000,000 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 — the Series 1997 Notes, the Series 1993 Notes, and the Series 1992B Industrial Development Revenue Obligations. With this refinancing, we expensed the remaining debt issue costs of $991,000 in fiscal 2007, and incurred approximately $318,000 in new debt issue costs to be amortized over the life of the note.

Series 1997 Notes Payable — On August 1, 1997, the Company issued $8,000,000 of Series 1997 notes bearing interest at the rate of 7.5%, payable semiannually on June 1 and December 1 of each year. All principal amounts of the 1997 notes then outstanding, plus accrued interest, were due and payable on June 1, 2012. At our option, the notes could be redeemed at any time prior to maturity, in whole or part, at 101% of face value if redeemed before June 1, 2005, and at 100% of face value if redeemed thereafter, plus accrued interest. On June 27, 2007, the Company redeemed the notes under this issue at 100% of face value plus accrued interest.

Series 1993 Notes Payable — On June 24, 1993, the Company issued $7,800,000 of Series 1993 notes bearing interest at rates ranging from 6.20% to 7.60%, payable semiannually on June 1 and December 1 of each year. The 1993 notes mature serially in increasing amounts on June 1 of each year beginning in 1999 and extending to June 1, 2013. At our option, the notes could be redeemed at any time prior to maturity, in whole or part, at redemption prices declining from 103% to 100% of face value, plus accrued interest. On June 27, 2007, the Company redeemed the Series 1993 notes at 100% of face value plus accrued interest.

Series 1992B Industrial Development Revenue Obligations — On September 15, 1992, Cascade County, Montana issued $1,800,000 of Series 1992B Industrial Development Revenue Bonds (the “1992B Bonds”) bearing interest at rates ranging from 3.35% to 6.50%, and loaned the proceeds to the Company. The Company is required to pay the loan, with interest, in amounts and on a schedule to repay the 1992B Bonds. Interest is payable semiannually on April 1 and October 1 of each year. The 1992B Bonds began maturing serially in increasing amounts on October 1, 1993, and continuing on each October 1 thereafter until October 1, 2012. At our option, 1992B Bonds may be redeemed in whole or in part on any interest payment date at redemption prices declining from 101% to 100% of face value, plus accrued interest. On June 27, 2007, the Company redeemed the 1992B Bonds at 100% of face value plus accrued interest.

Term Loan — In 2004, in addition to the Series 1997 and 1993 Notes and the 1992B Bonds discussed above, the Company had a revolving credit agreement with LaSalle. In March 2004, the Company converted $8,000,000 of existing revolving loans into a $6,000,000, five-year term loan with principal payments of $33,333 each month and a $2,000,000 short-term loan. On May 26, 2005, the Company completed the sale of 287,500 common shares at a price of $8.00 per share for net proceeds of $2,202,956 after deducting $97,044 of issuance expenses. $2,000,000 of the equity proceeds were immediately used to pay off the $2,000,000 short-term loan. The remaining balance of the

F-18

ENERGY WEST, INCORPORATED AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

$6,000,000 five-year term loan was paid in full on April 2, 2007 with proceeds from the sale of the Arizona propane assets.

Aggregate Annual Maturities — The scheduled maturities of long-term debt at June 30, 2007 are as follows:

	Series 2007
Year ending June 30:
2007	$	—
2008		—
2009		—
2010		—
2011		—
Thereafter		13,000,000
Total	$	13,000,000

The estimated fair value of our fixed rate long-term debt, based on an estimate of market prices for similar issues is approximately $12,700,000 and $14,667,537 as of June 30, 2007 and 2006, respectively.

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 preceding60-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 June 30, 2007 and 2006, the Company believes it is in compliance with the financial covenants under its debt agreements.

8.   Employee Benefit Plans

The Company has a defined contribution plan (the “401k Plan”) which covers substantially all of its employees. Total contributions to the 401k Plan for the years ended June 30, 2007, 2006, and 2005 were $132,131, $272,300, $479,868, respectively.

The Company makes matching contributions in the form of Company stock equal to 10% of each participant’s elective deferrals in our 401k Plan. The Company contributed shares of our stock valued at $21,690, $19,436, and $20,185, in fiscal 2007, 2006, and 2005, respectively. In addition, a portion of our 401k Plan consists of an Employee Stock Ownership Plan (“ESOP”) that covers most of our employees. The ESOP receives contributions of our common stock from the Company each year as determined by the Board of Directors. The contribution is recorded based on the current market price of our common stock. The Company made no contributions for the fiscal years ended June 30, 2007, 2006 and 2005.

The Company has sponsored a defined postretirement health benefit plan (the “Retiree Health Plan”) providing health and life insurance benefits to eligible retirees. The Plan pays eligible retirees (post-65 years of age) $125 per month in lieu of contracting for health and life insurance benefits. The amount of this payment is fixed and will not increase with medical trends or inflation. In addition, our Retiree Health Plan allows retirees between the ages of 60 and 65 and their spouses to remain on the same medical plan as active employees by contributing 125% of the current COBRA rate to retain this coverage. The 25% in excess of the current COBRA rate is held in the VEBA trust account, and benefits for this plan are paid from assets held in the VEBA Trust account. During fiscal 2006, the Company discontinued contributions and is no longer required to fund the Retiree Health Plan. As of June 30, 2007, the value of plan assets is $311,189. The assets remaining in the trust will be used to fund the plan until these assets are exhausted. Therefore, the Company has eliminated any accrual for future contributions to the plan.

F-19

ENERGY WEST, INCORPORATED AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

9.   Income Taxes

Significant components of our deferred tax assets and liabilities as of June 30, 2007 and 2006 are as follows:

	2007						2006
	Current			Long-Term			Current			Long-Term
Deferred tax asset:
Allowances for doubtful accounts	$	23,827		$	—		$	52,340		$	—
Unamortized investment tax credit		—			10,907			—			18,533
Contributions in aid of construction		—			318,455			—			539,395
Other nondeductible accruals		77,445			—			100,591			—
Recoverable purchase gas costs		—			—			322,428			—
Derivatives		93,657			—			177,713			—
Deferred incentive and pension accrual		—			14,997			—			65,420
Other		—			533,298			—			326,870
Total		194,929			877,657			653,072			950,218
Deferred tax liabilities:
Recoverable purchase gas costs		189,294			—			912,969			—
Property, plant, and equipment		—			5,110,398			—			6,281,038
Debt issue costs		—			—			—			69,453
Property tax liability		—			214,028			—			263,373
Covenant not to compete		—			42,374			—			46,616
Other		(47,735	)		96,027			9,266			125,624
Total		141,559			5,462,827			922,235			6,786,104
Net deferred tax asset (liabilities)	$	53,370		$	(4,585,170	)	$	(269,163	)	$	(5,835,886	)

Income tax expense for the years ended June 30, 2007, 2006, and 2005 consists of the following:

	2007			2006			2005
Current income taxes:
Federal	$	957,135		$	1,281,537		$	(1,198,224	)
State		164,240			131,331			(322,221	)
Total current income taxes		1,121,375			1,412,868			(1,520,445	)
Deferred income taxes:
Federal		137,881			(240,349	)		1,814,618
State		34,470			(42,414	)		201,624
Total deferred income taxes		172,351			(282,763	)		2,016,242
Total income taxes before credits		1,293,726			1,130,105			495,797
Investment tax credit, net		(21,062	)		(21,062	)		(21,062	)
Total income tax expense	$	1,272,664		$	1,109,043		$	474,735

F-20

ENERGY WEST, INCORPORATED AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Income tax expense differs from the amount computed by applying the federal statutory rate to pre-tax income for the following reasons:

	2007			2006			2005
Tax expense at statutory rate of 34%	$	1,200,249		$	1,026,763		$	476,833
State income tax, net of federal tax benefit		154,620			132,271			61,427
Amortization of deferred investment tax credits		(21,062	)		(21,062	)		(21,061	)
Other		(61,143	)		(28,929	)		(42,464	)
Total	$	1,272,664		$	1,109,043		$	474,735

Income tax from discontinued operations was $2,499,875, $265,663 and $278,137 in fiscal year 2007, 2006 and 2005, respectively.

10.   Segments of Operations

The results of our regulated and unregulated propane business are analyzed by our chief operating decision maker, and decisions on how to allocate resources and assess performance are done for the combined regulated and unregulated operations taken as a whole.

While some discrete financial information is available and used to report the regulated aspects to appropriate government agencies, both the unregulated and the regulated business use the same officers and employees, use essentially the same assets, and are managed together at the same location. As a result, management does not believe that the unregulated business could be satisfactorily analyzed for performance without consideration of the regulated component. Therefore, the results of the two components are combined by management prior to assessing performance. By combining the regulated and unregulated components, we are providing the user of the financial statements the view of the business through management’s eyes.

F-21

ENERGY WEST, INCORPORATED AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following tables set forth summarized financial information for our Natural Gas Operations, EWR, Pipeline, and Discontinued (formerly Propane) Operations (inter-company eliminations between segments primarily consist of gas sales from EWR to Natural Gas Operations, inter-company accounts receivable, accounts payable, equity, and subsidiary investment):

	Natural Gas						Pipeline			Discontinued
Year Ended June 30, 2007	Operations			EWR			Operations			Operations			Eliminations			Consolidated
Operating revenue:
Natural gas operations	$	47,074,560		$	—		$	—		$	—		$	(635,054	)	$	46,439,506
Marketing and wholesale		—			22,466,030			—			—			(9,920,671	)		12,545,359
Pipeline operations		—			—			388,175			—			—			388,175
Total operating revenue		47,074,560			22,466,030			388,175			—			(10,555,725	)		59,373,040
Gas purchased		34,177,047			—			—			—			(635,054	)		33,541,993
Gas and electric — wholesale		—			20,185,304			—			—			(9,920,671	)		10,264,633
Distribution, general, and administrative		5,676,195			315,279			206,055			—			—			6,197,529
Maintenance		563,912			297			2,474			—			—			566,683
Depreciation and amortization		1,414,003			222,110			56,373			—			—			1,692,486
Taxes other than income		1,652,661			20,529			23,746			—			—			1,696,936
Operating expenses		43,483,818			20,743,519			288,648			—			(10,555,725	)		53,960,260
Operating income		3,590,742			1,722,511			99,527			—			—			5,412,780
Other income		228,515			1,592			11,412			—			—			241,519
Interest (expense)		(1,896,650	)		(185,365	)		(42,140	)		—			—			(2,124,155	)
Income from continuing operations before income taxes		1,922,607			1,538,738			68,799			—			—			3,530,144
Income taxes (expense)		(653,130	)		(593,078	)		(26,456	)		—			—			(1,272,664	)
Income from continuing operations		1,269,477			945,660			42,343			—			—			2,257,480
Dincontinued operations:
Gain from disposal of operations		—			—			—			5,479,166			—			5,479,166
Income from discontinued operations		—			—			—			975,484			—			975,484
Income tax (expense)		—			—			—			(2,499,875	)		—			(2,499,875	)
Income from discontinued operations		—			—			—			3,954,775			—			3,954,775
Net income	$	1,269,477		$	945,660		$	42,343		$	3,954,775		$	—		$	6,212,255
Capital expenditures and natural gas properties	$	2,024,443		$	361,379		$	21,088		$	—		$	—		$	2,406,910
Total assets	$	38,512,502		$	5,882,390		$	1,003,145		$	—		$	6,436,001		$	51,834,038

F-22

ENERGY WEST, INCORPORATED AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

	Natural Gas						Pipeline			Discontinued
Year Ended June 30, 2006	Operations			EWR			Operations			Operations			Eliminations			Consolidated
Operating revenue:
Natural gas operations	$	56,044,531		$	—		$	—		$	—		$	(592,136	)	$	55,452,395
Marketing and wholesale		—			32,879,779			—			—			(14,047,850	)		18,831,929
Pipeline operations		—			—			411,237			—			—			411,237
Total operating revenue		56,044,531			32,879,779			411,237			—			(14,639,986	)		74,695,561
Gas purchased		43,752,966			—			—			—			(592,136	)		43,160,830
Gas and electric — wholesale		—			31,285,246			—			—			(14,047,850	)		17,237,396
Distribution, general, and administrative		5,830,719			473,341			85,070			—			—			6,389,130
Maintenance		504,473			198			—			—			—			504,671
Depreciation and amortization		1,394,169			221,814			56,064			—			—			1,672,047
Taxes other than income		1,430,101			15,672			7,602			—			—			1,453,375
Operating expenses		52,912,428			31,996,271			148,736			—			(14,639,986	)		70,417,449
Operating income		3,132,103			883,508			262,501			—			—			4,278,112
Other income		358,213			32,464			—			—			—			390,677
Interest (expense)		(1,425,186	)		(182,422	)		(41,290	)		—			—			(1,648,898	)
Income from continuing operations before income taxes		2,065,130			733,550			221,211			—			—			3,019,891
Income taxes (expense)		(740,624	)		(283,339	)		(85,080	)		—			—			(1,109,043
Income from continuing operations		1,324,506			450,211			136,131			—			—			1,910,848
Dincontinued operations:
Income from discontinued operations		—			—			—			671,485			—			671,485
Income tax (expense)		—			—			—			(265,663	)		—			(265,663	)
Income from discontinued operations		—			—			—			405,822			—			405,822
Net income	$	1,324,506		$	450,211		$	136,131		$	405,822		$	—		$	2,316,670
Capital expenditures and natural gas properties	$	1,744,046		$	114,747		$	6,801		$	—		$	—		$	1,865,594
Total assets	$	38,887,681		$	5,424,107		$	1,044,214		$	12,199,782		$	525,278		$	58,081,062

F-23

ENERGY WEST, INCORPORATED AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

	Natural Gas						Pipeline			Discontinued
Year Ended June 30, 2005	Operations			EWR			Operations			Operations			Eliminations			Consolidated
Operating revenue:
Natural gas operations	$	45,091,564		$	—		$	—		$	—		$	(536,749	)	$	44,554,815
Marketing and wholesale		—			38,588,875			—			—			(15,678,744	)		22,910,131
Pipeline operations		—			—			424,038			—			—			424,038
Total operating revenue		45,091,564			38,588,875			424,038			—			(16,215,493			67,888,984
Gas purchased		33,095,465			—			—						(536,749	)		32,558,716
Gas and electric — wholesale		—			36,630,273			—			—			(15,678,744	)		20,951,529
Distribution, general, and administrative		6,242,841			952,313			113,542			—			—			7,308,696
Maintenance		518,686			2,311			—			—			—			520,997
Depreciation and amortization		1,488,353			247,759			53,588			—			—			1,789,700
Taxes other than income		1,416,037			28,176			34,635			—			—			1,478,848
Operating expenses		42,761,382			37,860,832			201,765			—			(16,215,493	)		64,608,486
Operating income		2,330,182			728,043			222,273			—			—			3,280,498
Other income		165,806			67,042			1,860			—			—			234,708
Interest (expense)		(1,774,989	)		(281,665	)		(56,103	)		—			—			(2,112,757	)
Income from continuing operations before income taxes		720,999			513,420			168,030			—			—			1,402,449
Income taxes (expense)		(216,073	)		(203,227	)		(55,436	)		—			—			(474,736	)
Income from continuing operations		504,926			310,193			112,594			—			—			927,713
Dincontinued operations:
Income from discontinued operations		—			—			—			731,893			—			731,893
Income tax (expense)		—			—			—			(278,137	)		—			(278,137	)
Income from discontinued operations		—			—			—			453,756			—			453,756
Net income	$	504,926		$	310,193		$	112,594		$	453,756		$	—		$	1,381,469
Capital expenditures and natural gas properties	$	2,024,938		$	125,646		$	37,030		$	—		$	—		$	2,187,614
Total assets	$	40,041,269		$	6,182,487		$	1,098,165		$	11,900,502		$	210,970		$	59,433,393

11.   Stock Option 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 June 30, 2007, there are 110,000 options outstanding and the maximum number of shares available for future grants under this plan is 25,000 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

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ENERGY WEST, INCORPORATED AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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. See Note 1 for the related pro forma disclosures, in accordance with SFAS No. 148,Accounting for Stock-Based Compensation — Transition and Disclosure. The fair value of each option grant is estimated on the date of grant using the Black-Scholes option pricing.

A summary of the status of our stock option plans as of June 30, 2007, 2006, and 2005, and changes during the years ended on these dates is presented below.

				Weighted		Aggregate
	Number of			Average		Intrinsic
	Shares			Exercise Price		Value
Outstanding June 30, 2004		77,000		$	8.49
Granted		70,000		$	7.02
Exercised		—			—
Expired		(21,000	)	$	8.49
Outstanding June 30, 2005		126,000		$	8.35
Granted		48,500		$	10.11
Exercised		(2,500	)	$	8.49
Expired		(26,500	)	$	8.37
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	$	663,020
Exerciseable June 30, 2007		51,000		$	8.37	$	337,785

The weighted average fair value of options granted during the years ended June 30, 2007, 2006, and 2005 was $2.50, $3.11, and $2.99, respectively. At June 30, 2007, there was $139,943 of total unrecognized compensation cost related to stock-based compensation. That cost is expected to be recognized over a period of three years.

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ENERGY WEST, INCORPORATED AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

							Weighted
							Average
					Weighted		Remaining				Weighted
					Average		Contractual				Average
	Exercise		Number		Exercise		Life		Number		Exercise
Grant Date	Price		Outstanding		Price		(Years)		Exercisable		Price
11/21/2002	$	8.49		8,500	$	8.49		0.4		8,500	$	8.49
7/1/2004	$	6.47		15,000	$	6.47		7.0		7,500	$	6.47
4/1/2005	$	6.62		20,000	$	6.62		7.8		15,000	$	6.62
7/1/2005	$	9.85		15,000	$	9.85		8.0		5,000	$	9.85
10/4/2005	$	10.51		16,500	$	10.51		8.3		7,500	$	10.51
1/6/2006	$	9.52		5,000	$	9.52		3.5		0	$	9.52
7/1/2006	$	9.02		10,000	$	9.02		9.0		2,500	$	9.02
12/4/2006	$	11.32		20,000	$	11.32		9.6		5,000	$	11.32
				110,000						51,000

The weighted-average grant date fair value per stock option granted during the years ended June 30, 2007, 2006 and 2005 was $10.55, $10.12 and $6.53, respectively. For the years ended June 30, 2007, 2006, and 2005, all stock options granted have an exercise price equal to the fair market value of the Company’s stock at the date of grant.

Termination of Preferred Stock Rights Agreement by Amendment of Final Expiration Date — Expiration of the Preferred Stock Purchase Rights—  On April 23, 2007, the Company’s Board of Directors approved Amendment No. 2 (“Amendment No. 2”) to the Company’s Preferred Stock Rights Agreement, dated June 3, 2004, as previously amended by Amendment No. 1 thereto dated May 25, 2005 (the “Rights Agreement”). Amendment No. 2 accelerates the Final Expiration Date of the Rights Agreement so as to cause the Rights Agreement, as well as the Preferred Stock Purchase Rights (the “Rights”) defined by the Rights Agreement, to expire, terminate and cease to exist at 5:00 p.m., New York time (EST) on May 25, 2007. Amendment No. 2 became effective April 24, 2007.

The Rights Agreement was designed and approved by the Board of Directors to deter coercive tactics by an acquirer in connection with any unsolicited attempt to acquire or take over the Company in a manner or on terms not approved by the Board of Directors. Under the Rights Agreement, any “Acquiring Person” (as defined in the Rights Agreement) was generally precluded from acquiring additional shares of common stock without becoming subject to significant dilution as a result of triggering the dilutive provisions of the Rights Agreement, commonly known as a “poison pill.” Amendment No. 2 terminated the Rights Agreement on May 25, 2007, thus permitting Acquiring Persons after that date to acquire additional shares of Common Stock of the Company without being subject to such dilution.

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ENERGY WEST, INCORPORATED AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

12.   Commitments and Contingencies

Commitments — In 2000, the Company entered into a ten year transportation agreement with Northwestern Energy that fixed the cost of pipeline and storage capacity. Based on original contract prices, the minimum obligation under this agreement at June 30, 2007 is as follows:

Year Ending June 30:
2008	$	4,258,896
2009		4,258,896
2010		2,839,264
2011		—
Total	$	11,357,056

Environmental Contingency — The Company owns property on which it operated a manufactured gas plant from 1909 to 1928. The site is currently used as an office facility for Company field personnel and storage location for certain equipment and materials. The coal gasification process utilized in the plant resulted in the production of certain by-products that have been classified by the federal government and the State of Montana as hazardous to the environment.

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

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

At June 30, 2007, the Company had incurred cumulative costs of approximately $2,093,000 in connection with its evaluation and remediation of the site. On May 30, 1995, the Company received an order from the MPSC allowing for recovery of the costs associated with the evaluation and remediation of the site through a surcharge on customer bills. As of June 30, 2007, the Company had recovered approximately $1,845,000 through such surcharges. As of June 30, 2007, the cost remaining to be recovered is $248,000.

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. 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.

Litigation — From time to time the Company is involved in litigation relating to claims arising from its operations in the normal course of business. The Company utilizes various risk management strategies, including maintaining liability insurance against certain risks, employee education and safety programs, and other processes intended to reduce liability risk.

The Company reached agreement with the Montana Department of Revenue (“DOR”) to settle personal property tax claims for the years1997-2002. The settlement amount is being paid in ten annual installments of

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ENERGY WEST, INCORPORATED AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

$243,000 each, beginning November 30, 2003. The Company has obtained rate relief that includes full recovery of the property tax associated with the DOR settlement.

Operating Leases — The Company leases certain properties including land, office buildings, and other equipment under non-cancelable operating leases through fiscal 2009. The future minimum lease payments on these leases are as follows:

Year Ended June 30:
2008	$	90,624
2009		6,600
Total	$	97,224

Lease expense from continuing operations resulting from operating leases for the years ended June 30, 2007, 2006, and 2005 totaled $90,624 each year.

13.   Financial Instruments and Risk Management

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 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 the Company and its subsidiaries have entered into hedging arrangements. Such arrangements may be used to protect profit margins on future obligations to deliver gas at a fixed price, or to protect against adverse effects of potential market price declines on future obligations to purchase gas at fixed prices.

The Company accounts for certain of such purchases or sale agreements in accordance with SFAS No. 133. Under SFAS 133, such contracts are reflected in 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 Income as an increase or (decrease) in “Revenues — Gas and Electric — Wholesale” without regard to whether any cash payments have been made between the parties to the contract. If such contracts are held to maturity, the cash flow from the contracts and their hedges are realized over the life of the contracts. SFAS No. 133 requires that contracts for purchase or sale at fixed prices and volumes must be valued at fair value (under mark-to-market accounting) unless the contracts qualify for treatment as a “normal purchase or sale.”

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

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ENERGY WEST, INCORPORATED AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

As of June 30, 2007, these agreements were reflected on the consolidated balance sheet as derivative assets and liabilities at an approximate fair value as follows:

Derivative Assets and Liabilities

	Assets		Liabilities
Contracts maturing during fiscal year 2008	$	57,847	$	58,018
Contracts maturing during fiscal years 2009 and beyond		—		—
Total	$	57,847	$	58,018

14.   Subsequent Events

Stock Purchase Agreement — On January 30, 2007, the Company entered into two stock purchase agreements (together, the “Purchase Agreements”) between the Company and Sempra Energy. Pursuant to the Purchase Agreements, the Company will acquire all of the capital stock of two of Sempra’s wholly owned subsidiaries, Frontier Utilities of North Carolina, Inc. and Penobscot Natural Gas Company, Inc. Frontier Utilities is the parent company of its operating subsidiary, Frontier Energy, LLC, and Penobscot Natural Gas is the parent company of its operating subsidiary, Bangor Gas Company LLC. The aggregate purchase price to be paid by the Company for the two companies in $5,000,000, subject to adjustment for working capital items.

The acquisition of Frontier Utilities is conditioned upon approval by the North Carolina Utilities Commission, or “NCUC”, and the acquisition of Penobscot Natural Gas is conditioned upon approval by the Maine Public Utilities Commission, or “MPUC”. Both acquisitions are also conditioned upon the receipt of certain other approvals from third parties. Each acquisition will close on the tenth business day after all closing conditions have been satisfied, including either NCUC or MPUC approval, as the case may be. On September 13, 2007, we received approval from the NCUC for the acquisition of Frontier Utilities, and anticipate a closing date on or about September 28, 2007. Approval from the MPUC is estimated to require approximately four months to one year to be obtained.

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

On July 27, 2007, Energy West invested $720,900 in Kykuit, and $40,050 on September 17, 2007. EWR owns 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. 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.

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ENERGY WEST, INCORPORATED AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

15.   Quarterly Information (Unaudited)

Quarterly results (unaudited) for the years ended June 30, 2007 and 2006 are as follows (in thousands, except per share data):

	First			Second		Third		Fourth
Year Ended June 30, 2007	Quarter			Quarter		Quarter		Quarter
Revenues	$	8,456		$	18,041	$	21,516	$	11,360
Operating income	$	326		$	2,121	$	2,358	$	606
Income (loss) from continuing operations	$	4		$	1,113	$	1,293	$	(152	)
Discontinued operations	$	(199	)	$	157	$	636	$	3,360
Net income (loss)	$	(195	)	$	1,270	$	1,929	$	3,208
Basic earnings (loss) per common share — continuing operations	$	0.00		$	0.38	$	0.43	$	(0.05	)
Basic earnings (loss) per common share — discontinued operations	$	(0.07	)	$	0.05	$	0.21	$	1.15
Basic earnings (loss) per common share — net income	$	(0.07	)	$	0.43	$	0.64	$	1.10
Diluted earnings (loss) per share — continuing operations	$	0.00		$	0.38	$	0.43	$	(0.05	)
Diluted earnings (loss) per share — discontinued operations	$	(0.07	)	$	0.05	$	0.21	$	1.13
Diluted earnings (loss) per share — net income	$	(0.07	)	$	0.43	$	0.64	$	1.08

	First			Second		Third		Fourth
Year Ended June 30, 2006	Quarter			Quarter		Quarter		Quarter
Revenues	$	9,296		$	26,409	$	27,575	$	11,416
Operating income (loss)	$	(399	)	$	1,759	$	2,230	$	689
Income (loss) from continuing operations	$	(433	)	$	923	$	1,156	$	264
Discontinued Operations	$	(189	)	$	194	$	490	$	(89	)
Net income (loss)	$	(622	)	$	1,117	$	1,646	$	175
Basic earnings (loss) per common share — continuing operations	$	(0.15	)	$	0.31	$	0.39	$	0.09
Basic earnings (loss) per common share — discontinued operations	$	(0.06	)	$	0.07	$	0.17	$	(0.03	)
Basic earnings (loss) per common share — net income	$	(0.21	)	$	0.38	$	0.56	$	0.06
Diluted earnings (loss) per share — continuing operations	$	(0.15	)	$	0.31	$	0.38	$	0.09
Diluted earnings (loss) per share — discontinued operations	$	(0.06	)	$	0.07	$	0.16	$	(0.03	)
Diluted earnings (loss) per share — net income	$	(0.21	)	$	0.38	$	0.55	$	0.06

Certain items related to discontinued operations have been restated from prior published reports.

F-30