10-K

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, 2006

or

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

For the transition period from                      to                     

Commission File number 0-14183

ENERGY WEST, INCORPORATED

(Exact name of registrant as specified in its charter)

Montana	81-0141785
(State or other jurisdiction of 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 of Regulation 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 this Form 10-K or any amendment to this Form 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” in Rule 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 in Rule 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, 2005 was $20,219,853.

The number of shares outstanding of the registrant’s common stock as of September 22, 2006 was 2,946,677 shares.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the proxy statement for the 2006 Annual Meeting of Shareholders are incorporated by reference into Part III.

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		12
Item 4.     Submission of Matters to a Vote of Security Holders		12
Part II		13
Item 5.     Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		13
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 and Executive Officers of the Registrant		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		31
Item 14.  Principal Accountant Fees and Services		31
Part IV		32
Item 15.  Exhibits and Financial Statement Schedules		32
Signatures		33
EX-21
EX-23.1
EX-23.2
EX-31
EX-32

Forward-Looking Statements

     This Annual Report on Form 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.
•	Propane Operations	Distributes 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 approximate population of the service territories is 50,000. We are in the process of selling the Arizona assets of these operations. See page 4.
•	Energy West Resources, Inc. (EWR)	Markets approximately 2.5 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 163 natural gas producing wells and gas gathering assets.
•	Pipeline Operations	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.

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

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.

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     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 requested by our company. The West Yellowstone rate order granted relief related to its share of the Montana Department of Revenue settlement as well as other operating expenses.

     The following table shows the Montana division’s revenues by customer class for the fiscal year ended June 30, 2006 and the two preceding fiscal years:

Gas Revenue
(in thousands)

			Years Ended June 30,
	2006		2005		2004
Residential	$	22,155	$	18,116	$	16,427
Commercial		14,233		11,437		9,918
Transportation		1,961		1,939		1,856
Total	$	38,349	$	31,492	$	28,201

Note: Revenue increases in fiscal 2006 compared to fiscal 2005 and fiscal 2004 are primarily due to higher gas costs, as well as rate increases related to recovering property taxes.

     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, 2006 and the two preceding fiscal years:

Gas Volumes
(in MMcf)

			Years Ended June 30,
	2006		2005		2004
Residential		1,978		2,136		2,206
Commercial		1,210		1,267		1,317
Transportation		1,524		1,493		1,443
Total Gas Sales		4,712		4,896		4,966

Note: Volumes decreased in fiscal 2006 compared to fiscal 2005 and fiscal 2004 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

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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 2007.

     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, 2006, 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 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, 2006 and the two preceding fiscal years:

Gas Revenue
(in thousands)

			Years Ended June 30,
	2006		2005		2004
Residential	$	5,883	$	4,805	$	4,149
Commercial		5,771		4,434		3,606
Industrial		5,741		4,059		3,107
Total	$	17,395	$	13,298	$	10,862

Note: Higher revenues were realized in fiscal 2006 and 2005 compared to fiscal 2004 due to higher gas costs which are passed on to the customers in accordance with approvals from the rate regulators.

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     The following table shows volumes of natural gas, expressed in MMcf, sold by the Wyoming division for the fiscal year ended June 30, 2006 and the two preceding fiscal years:

Gas Volumes
(in MMcf)

			Years Ended June 30,
	2006		2005		2004
Residential		478		519		515
Commercial		684		582		540
Industrial		567		643		568
Total Gas Sales		1,729		1,744		1,623

     The Wyoming division generates its revenues under tariffs regulated by the WPSC. The tariffs are structured to enable our company 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 33% of the revenues of the Wyoming division and approximately 10% 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.

Propane Operations

     We engage in the regulated sale of propane under the business name Energy West Arizona, or “EWA”. EWA distributes propane in the Payson, Pine, and Strawberry, Arizona area located about 75 miles northeast of Phoenix in the Arizona Rim Country. EWA’s service area includes approximately 575 square miles and has a population of approximately 50,000. EWA’s operations are subject to regulation by the Arizona Corporation Commission, or “ACC”, which regulates rates, adequacy of service, and other matters. EWA’s properties include approximately 170 miles of underground distribution pipeline and an office building leased from a third party. EWA has approximately 8,000 regulated customers. The principal competition in this area comes from bulk propane retailers that sell to customers who use propane from storage tanks located at their homes or businesses rather than using propane from EWA’s underground distribution system.

     EWA purchases propane from our unregulated subsidiary, Energy West Propane, Inc. or “EWP”, under terms reviewed periodically by the ACC. EWP engages in the bulk sale of propane through its two divisions: Energy West Propane-Arizona, which serves the Payson, Pine, and Strawberry Arizona area, and Rocky Mountain Fuels Wholesale, or “RMF”. RMF’s wholesale operations supply propane for our underground propane-vapor systems serving the cities of Cascade, Montana and Payson, Arizona and the surrounding areas. EWP had 2,347 unregulated customers as of June 30, 2006. EWP faces competition from other propane distributors and suppliers of other types of fuels that compete with propane. Competition is based primarily on price and there is a high degree of competition with other propane distributors in each of our service areas.

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

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Business”), and (ii) all of the assets and business operations of EWP that are associated with certain “non-regulated” propane assets (the “Non-Regulated Business,” and together with the Regulated Business, the “Business”).

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

     The sale is conditioned on approval by the ACC and the receipt of certain other approvals by third parties. The sale will close the first day of the month after the receipt of ACC approval. We cannot predict with certainty whether or when the closing conditions will be satisfied or whether or when this transaction will be consummated.

     The following tables show Propane Operations revenues and volumes by customer class for the fiscal year ended June 30, 2006 and the two preceding fiscal years:

Propane Revenue
(in thousands)

			Years Ended June 30,
	2006		2005		2004
Residential	$	6,986	$	6,509	$	5,456
Commercial		2,597		2,310		2,280
Total	$	9,583	$	8,819	$	7,736

Propane Volume
(in thousands of gallons)

			Years Ended June 30,
	2006		2005		2004
Residential		3,783		4,115		3,735
Commercial		1,577		1,513		2,095
Total		5,360		5,628		5,830

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 163 natural gas producing wells in operation. This production gives EWR a natural hedge when market prices of natural gas are greater than the cost of production. The gas production from the properties provided approximately 14% of EWR’s volume requirements for fiscal 2006.

     Because gas production facilities generate higher operating margins than our regulated natural gas and propane 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.

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     Prior to fiscal 2004, EWR participated in the electric market as a broker of electricity. However, in fiscal 2003, EWR exited the electricity marketing business by not renewing its electric contracts as they expired. As a result, EWR has only two remaining contracts, one with a commercial customer and the other with a supplier to obtain the electricity for the commercial customer. The terms of these contracts extend through June 2007. Accordingly, during fiscal 2006, 2005, and 2004, we had only one remaining electric contract with a margin of $48,000, $34,000, and $72,000, 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 company’s profitability over time. We currently are seeking ways in which we can expand our Pipeline Operations by (a) expanding the capacity and throughput of our existing pipeline assets, and (b) acquiring additional pipeline assets. We believe that expanded or newly acquired pipeline operations can provide higher operating margins and faster returns on investment than we can derive from other aspects of our business. We cannot provide assurance, however, that (i) we will be able to expand our existing Pipeline Operations or acquire new pipeline assets, or (ii) that the actual results of such expanded or acquired assets will be as profitable as we anticipate.

Competition

     The traditional competition we face in our distribution and sales of natural gas and propane is from suppliers of fuels other than natural gas or propane, including electricity, oil, 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 gas and/or propane for space and water heating as an energy source. We face more intense competition in West Yellowstone and Cascade, Montana and the Payson/Strawberry area of Arizona due to the cost of competing fuels than we face in the Great Falls area of Montana and our service territory in Wyoming.

     Our Propane Operations estimate that approximately 67% of the homes and businesses adjacent to the division’s distribution pipeline use the division’s propane for space heating or water heating. The principal competition we face in the distribution and sale of propane is from electricity suppliers and other propane distributors. Competition is based primarily on price and customer service. There is a high degree of competition from other propane distributors in all of the service areas

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

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Governmental Regulation

     Our utility operations are subject to regulation by the MPSC, the WPSC, the ACC, and the Federal Energy Regulatory Commission, or “FERC”. 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. In addition, final orders have been received in the Montana Division for the West Yellowstone and Great Falls service territories as a result of general rate filings made by us in fiscal 2004. The rate increases approved approximately $200,000 annually in increased revenues for West Yellowstone and approximately $800,000 in increased revenues for Great Falls. Both rate orders were effective for service rendered on and after November 1, 2004.

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.

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, 2006, we had incurred cumulative costs of approximately $2,093,000 in connection with our evaluation and remediation of the site. On May 30, 1995, we received an order from the MPSC allowing for recovery of the costs associated with the evaluation and remediation of the site through a surcharge on customer bills. As of June 30, 2006, we had recovered approximately $1,758,000 through such surcharges. As of June 30, 2006, the cost remaining to be recovered through the on going rate is $335,000. We are required to file with the MPSC every two years for approval to continue the recovery of these costs through a surcharge.

Employees

     We had a total of 100 employees as of June 30, 2006. One of these employees is employed by EWR, 20 by our Propane Operations, 69 by our Natural Gas Operations and 10 at the corporate office. Our Natural Gas Operations include 16 employees represented by two labor unions.

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.

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     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;

• Fluctuations in wholesale margins due to uncertainty in the wholesale propane markets;

• 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;

• 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 or propane contracts, and weather conditions;

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

• Disruptions to natural gas or propane 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, the MPSC, the WPSC, and the ACC 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

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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 propane vapor operations follow Statement of Financial Accounting Standards (SFAS) No. 71, “Accounting for the Effects of Certain Types of Regulation,” 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 and propane vapor operations to discontinue the 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 the financial position and results of operations of our company.

     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 recent volatility of natural gas prices in North America, 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.

     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 and propane. In order to mitigate the risk of natural gas 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

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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 environmental clean-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 estimating clean-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 company’s 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.

     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 company’s 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 on Form 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) 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)

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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 Shareholder Rights Plan, as well as, certain provisions in our charter, may prevent or delay a change of control of our company. We have adopted a Shareholder Rights Plan that serves as a strong deterrent to any unsolicited or hostile takeover attempts and, effectively, requires an interested acquirer to negotiate with our Board of Directors. Additionally, our Articles of Incorporation authorize our Board of Directors to issue preferred stock in one or more series and to fix the rights, preferences, privileges, and restrictions granted to or imposed upon any unissued shares of preferred stock and to fix the number of shares constituting any series and the designations of such series, without further vote or action by the shareholders. Our Shareholders Rights Plan and our charter could prohibit or delay mergers or other takeover or change of control of our company and may discourage attempts by other companies to acquire us, even if such a transaction would be beneficial to our stockholders.

     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.

• 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)).

• Mark-to-Market Accounting — The market value of our derivative contracts is not always readily determinable. In some cases, we use models and other valuation techniques to determine fair value. The use of these models and valuation techniques sometimes requires subjective and complex judgment. Actual results could differ from the results estimated through application of these methods.

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Item 1B. Unresolved Staff Comments.

     Not applicable.

Item 2. Properties.

     Montana — In Great Falls, Montana, we own a 9,000 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 our company. 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 163 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 “actual” 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.

     Arizona — We own approximately 170 miles of distribution mains located in and around Payson, Pine, and Strawberry. We own five acres of land in Payson, on which we maintain and operate a propane vapor system for our operations. We lease an office building in Payson under an agreement that expires in 2011. We have the right to extend the lease for another five-year term. EWP owns ten large bulk propane tanks and numerous customer tanks located in Pine, Strawberry, Payson, and Star Valley, which are used to serve customers in those communities and surrounding areas. All of these properties are included in the Arizona Assets that we are selling to SemStream, as described under Item 1, “Business – Propane Operations.”

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 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

Fiscal Year 2005	High		Low
First Quarter	$	7.10	$	6.10
Second Quarter	$	6.52	$	5.41
Third Quarter	$	7.82	$	6.05
Fourth Quarter	$	12.97	$	6.20

Holders of Record

     As of September 1, 2006, there were approximately 1,700 record owners of our common stock.

Dividend Policy

     There were no dividend payments declared or made during fiscal 2005 and 2004. Our credit agreement with LaSalle Bank restricts 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 contain restrictions respecting the payment of dividends. 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

Recent Sales of Unregistered Securities

     Not applicable.

Purchases of Equity Securities by Our Company and Affiliated Purchasers

     Not applicable.

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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 firm 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 this Form 10-K. Amounts are in thousands, except per share and number of share amounts.

	2006		2005		2004			2003			2002
Operating results
Operating revenue	$	84,278	$	76,709	$	73,291		$	77,898		$	89,240
Operating expenses
Gas and electric purchases		66,369		58,332		57,911			62,520			74,590
General and administrative		8,218		9,448		10,170			11,669			8,790
Maintenance		624		596		480			497			466
Depreciation and amortization		2,184		2,313		2,332			2,393			2,059
Taxes other than income (1)		1,615		1,654		1,210			888			946
Total operating expenses		79,010		72,343		72,103			77,967			86,851
Operating income (loss)		5,268		4,366		1,188			(69	)		2,389
Other income-net		504		445		385			302			658
Total interest charges (2)		2,080		2,677		2,498			1,633			1,704
Income (loss) before taxes		3,692		2,134		(925	)		(1,400	)		1,343
Income tax expense (benefit)		1,375		753		(369	)		(543	)		516
Net Income (Loss)	$	2,317	$	1,381	$	(556	)	$	(857	)	$	827
Basic earnings (loss) per common share	$	0.79	$	0.53	$	(0.21	)	$	(0.33	)	$	0.32
Diluted earnings (loss) per common share	$	0.79	$	0.53	$	(0.21	)	$	(0.33	)	$	0.32
Dividends per common share (3)	$	0.17	$	0.00	$	0.00		$	0.41		$	0.52
Weighted average common shares
Outstanding — diluted		2,948,046		2,630,679		2,596,454			2,586,487			2,558,782
At year end:
Current assets	$	14,455	$	15,423	$	16,739		$	15,790		$	18,517
Total assets	$	57,931	$	59,433	$	61,445		$	60,027		$	57,295
Current liabilities	$	10,143	$	11,525	$	16,725		$	21,833		$	19,899
Total long-term obligations	$	17,605	$	18,677	$	21,697		$	14,834		$	15,367
Total stockholders’ equity	$	19,165	$	17,187	$	13,401		$	13,957		$	15,699
Total capitalization	$	36,770	$	35,864	$	35,098		$	28,791		$	31,066

(1)	Taxes other than income include approximately $290,000 in each of fiscal 2006, 2005, and 2004 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.
(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 2006, 2005, and 2004, 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 on page F-1 of this Annual Report.

Executive Overview

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

     We have seen measurable benefits from a renewed focus on our core business – utility service, pipelines, and natural gas production. Significant cost reductions have helped us strengthen our balance sheet, increase net income, and restore dividends to our shareholders. Earnings for the fiscal year ended June 30, 2006, increased 68% over the same period in 2005 and represent an all-time high for the core business of Energy West. We were able to achieve these positive results despite one of our warmest winters (leading to reduced sales), historically high natural gas commodity prices, and increasing interest rates.

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

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

Strategy

     The key elements of our current strategy include the following:

• Focus on the natural gas distribution and related businesses.

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

• Pursue appropriate regulatory treatment of higher commodity prices.

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

• Continue to focus on operational efficiencies.

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

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

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

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Opportunities and Challenges

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

• Our company possesses many competitive strengths, including:

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

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

– Our positive reputation with regulators and customers.

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

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

• We carefully analyze the economics of our spending to support growth. When justified under our tariffs, we work with developers, business owners, and residents to share certain construction costs to assure a fair return to our company. 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 or propane 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 and propane, continues to encourage such measures.

• We earn approximately 28% of our operating margin by providing gas marketing services to “unregulated” commercial and industrial gas customers. The loss of a major customer, or unfavorable conditions affecting an industry segment, could have a detrimental impact on our earnings. Many external factors over which we have no control can significantly impact the amount of gas consumed by industrial and commercial customers and, consequently, affect the margins we earn. To mitigate

16

these risks, we endeavor to enter into sales agreements through which we can match estimated demand with a supply that provides an acceptable margin.

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

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

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 accountings 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 Statement of Financial Accounting Standards No. 71, Accounting for the Effects of Certain Types of Regulation. Our regulated segment continues to be cost-of-service rate regulated, and we believe the application of Statement 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 segment no longer meets the criteria of regulatory accounting under Statement 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 Statement 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, the WPSC, or the ACC. 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, the WPSC, and the ACC, under which purchased gas and propane 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. 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 derivative transactions during the three fiscal years ended June 30, 2006, 2005 or 2004.

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, 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 increases in other income and decreases in depreciation, general and administrative expenses, other taxes and interest expense, partially offset by decreases in gross margin and increases in maintenance and income taxes. 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 $84,278,000 compared to $76,709,000 in fiscal 2005, an increase of $7,569,000. This increase was primarily attributable to increases in both Natural Gas and Propane

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Operations totaling $11,771,000 due to higher commodity prices that are passed through to customers. These increases were offset by a decrease of $5,764,000 in EWR Marketing Operations 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 (revenues less cost of gas and electricity and costs of goods sold) were $17,909,000 in fiscal 2006 compared to $18,377,000 in fiscal 2005, a decrease of $468,000. 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. Gross margin in the Propane Segment decreased by $387,000 due to fewer volumes sold because of the warm winter and competitive pressures in the non-regulated bulk propane business. 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 subsidiary’s margin decreased by $13,000 due to lower transport volumes.

     Expenses Other Than Costs of Gas and Electricity and Costs of Goods Sold — Expenses other than costs of gas and electricity and costs of goods sold decreased by $1,368,000 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 by a slight increase in maintenance expense. Distribution and general and administrative expenses decreased by $1,227,000 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 $129,000 and taxes other than income decreased by $39,000, while maintenance expense increased by $28,000.

     Other Income — Other income increased by $59,000 from $445,000 in fiscal 2005 to $504,000 in fiscal 2006. Natural Gas other income increased $192,000, primarily due to income generated in fiscal 2006 for services to customers over what had been provided in prior years, and other miscellaneous income. Propane other income decreased $97,000 due to the payoff on July 9, 2005 of the note receivable in RMF, which reduced interest and consulting fee income in fiscal 2006. EWR had other income generated from payments related to the settlement of a contract dispute that were $34,000 greater in fiscal 2005 than in fiscal 2006.

     Interest Expense — Interest expense decreased by $597,000, or 22%, from $2,677,000 in fiscal 2005 to $2,080,000 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 — Income tax expense increased by $622,000 from $753,000 in fiscal 2005 to $1,375,000 in fiscal 2006 due to increased pre-tax income.

Fiscal Year Ended June 30, 2005 Compared to Fiscal Year Ended June 30, 2004

     Net Income (Loss) — We recorded net income of $1,381,000 in fiscal 2005 compared to a net loss of $556,000 in fiscal 2004, an improvement of $1,937,000. The improvement was the result of increases in margin and other income and decreases in overhead, depreciation, and general and administrative expenses, partially offset by increases in maintenance, interest, income taxes, and other taxes. The principal changes that contributed to the improvement from a net loss in fiscal 2004 to net income in fiscal 2005 are explained below.

     Revenues — Our revenues for fiscal 2005 were $76,709,000 compared to $73,291,000 in fiscal 2004, an increase of $3,418,000. This increase was primarily attributable to increases in both Natural Gas and Propane Operations totaling $6,813,000 due to increased rates related to higher commodity costs, property tax recovery, and approved rate cases in Montana, as well as an increase of $23,000 in Pipeline operations due to an increase of gathering revenue on the Glacier gathering line. These increases were offset by a decrease of $3,418,000 in EWR Marketing Operations, primarily due to the loss of trading revenues of $8,679,000 offset by increases of $5,261,000 primarily from increases in revenue from retail customers and favorable changes in the valuation of derivative contracts.

     Gross Margin — Gross margins (revenues less cost of gas and electricity and costs of goods sold) were $18,377,000 in fiscal 2005 compared to $15,380,000 in fiscal 2004, an increase of $2,997,000. Gross margins were

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up in all segments in fiscal 2005 compared to fiscal 2004. Significant increases in gross margins for our segments were (1) $1,851,000 in EWR primarily as a result of the change in the valuation of derivative contracts of $1,760,000 and net increases in production, electric and gas margin of $91,000; (2) $307,000 in the Propane Operation, where revenues in all propane operations increased at a slightly greater rate than costs increased, which resulted in higher gross margin; (3) $817,000 in Natural Gas Operations due to rate increases in Montana and Wyoming; and (4) $23,000 in Pipeline Operations due to an increase of gathering revenue on the Glacier line.

     Expenses Other Than Costs of Gas and Electricity and Costs of Goods Sold — Expenses other than costs of gas and electricity and costs of goods sold decreased by $182,000 from fiscal 2004 to fiscal 2005 due to a decrease in distribution, general and administrative, and depreciation expenses, partially offset by increases in maintenance and taxes other than taxes on income.

     Distribution and general and administrative expenses decreased by $723,000 as a result of cost saving measures in payroll and other associated costs in fiscal 2005, as well as the elimination of non-recurring costs that took place in fiscal 2004. Some of these costs in fiscal 2004 included proxy contest expenses of $570,000 and shareholder rights plan expenses of $227,000. Debt issuance costs incurred in fiscal 2004 were amortized as interest expense. Please see the table below.

     Maintenance and depreciation expenses increased $98,000 for fiscal 2005 as compared to fiscal 2004, primarily in Natural Gas Operations.

     Taxes other than taxes on income increased by $444,000 due to the Montana Department of Revenue audit of assessed personal property values in 2004. This resulted in recognition of additional property tax expense each year for the next 10 years. The MPSC has allowed rate recovery for the increased property tax expense. This allowance is reflected in higher revenue for fiscal 2005.

     Certain Expenses Incurred During Fiscal Years 2005 and 2004 — Our consolidated results of operations were negatively affected by certain costs and expenses that occurred during fiscal 2005 and 2004. These expenses, summarized in the table below, include expenses associated with the proxy contest and shareholder rights plan in fiscal 2004, the costs associated with the restatement of previous years’ earnings during fiscal 2005, and expenses associated with restructuring our credit facilities during fiscal 2005 and 2004. Although future expenses associated with our credit facilities and other capital-related expenses can be expected in the normal course, we cannot provide assurance with respect to future levels of expenses related to capital needs.

	2005		2004		Total
Proxy Contest Expenses			$	570,000	$	570,000
Debt Issuance Expenses	$	336,000		663,000	$	999,000
Shareholder Rights Plan				227,000	$	227,000
Accounting and legal restatement costs		388,000			$	388,000
Total	$	724,000	$	1,460,000	$	2,184,000

     Other Income — Other income increased by $60,000 from $385,000 in fiscal 2004 to $445,000 in fiscal 2005 due primarily to recognition of interest income from a tax refund of prior years.

     Interest Expense — Interest expense increased by $178,000, or 7%, from $2,499,000 in fiscal 2004 to $2,677,000 in fiscal 2005 due to higher overall corporate borrowings and higher interest rates.

     Income Tax Benefit (Expense) — Income tax expense increased by $1,122,000 from a tax benefit of $369,000 in fiscal 2004 to a tax expense of $753,000 in fiscal 2005 due to increased pre-tax income.

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Operating Results of our Natural Gas Operations

	Years Ended June 30
	2006			2005			2004
	(in thousands)
Natural Gas Operations
Operating revenues	$	55,745		$	44,792		$	39,063
Gas Purchased		43,453			32,796			27,883
Gross Margin		12,292			11,996			11,180
Operating expenses		9,160			9,666			9,843
Operating income		3,132			2,330			1,337
Other (income)		(358	)		(166	)		(97	)
Income before interest and taxes		3,490			2,496			1,434
Interest expense		1,425			1,775			1,623
Income (loss) before income taxes		2,065			721			(189	)
Income tax benefit (expense)		(741	)		(216	)		26
Net income (loss)	$	1,324		$	505		$	(163	)

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 $55,745,000 from $44,792,000 in fiscal 2005. This $10,953,000 increase was due to higher gas commodity costs and increased rates.

     Gas purchases in Natural Gas Operations increased by $10,957,000 from $32,496,000 in fiscal 2005 to $43,453,000 in fiscal 2006. The increase in gas cost reflects higher gas commodity prices during fiscal 2006.

     Gross margin, which is defined as operating revenues less cost of gas purchased, 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 was $350,000 lower 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 Benefit (Expense) — Income tax expenses were $525,000 higher in fiscal 2006 than fiscal 2005 due to higher income before taxes.

Fiscal Year Ended June 30, 2005 Compared to Fiscal Year Ended June 30, 2004

     Natural Gas Revenues and Gross Margins — The Natural Gas Operations’ operating revenues in fiscal 2005 increased to $44,792,000 from $39,063,000 in fiscal 2004. This $5,729,000 increase was primarily due to higher gas costs and increased rates related to property tax recovery and approved rate cases in Montana.

     Gas purchases in Natural Gas Operations increased by $4,913,000 from $27,883,000 in fiscal 2004 to $32,796,000 in fiscal 2005. The increase in gas cost reflects higher commodity prices during fiscal 2005.

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     Gross margin, which is defined as operating revenues less gas purchased, was approximately $11,996,000 for fiscal 2005 compared to approximately $11,180,000 in fiscal 2004. The increase of $816,000 is primarily due to higher revenues, as explained above.

     Natural Gas Operating Expenses — The Natural Gas Operations’ operating expenses were approximately $9,666,000 in fiscal 2005 as compared to $9,843,000 for fiscal 2004. The $177,000 decrease is due mainly to $499,000 lower overhead charges and $50,000 lower depreciation expense. Payroll and other general and administrative costs were $142,000 lower due to implementation of cost-saving measures. Increased costs include $493,000 in higher property tax expenses for Montana due to increased valuations and amortization of a 2004 property tax settlement over ten years and $87,000 higher automotive and property insurance expenses.

     Natural Gas Other Income — Other income increased by $69,000 from $97,000 in fiscal 2004 to $166,000 in fiscal 2005. This was due primarily to cost savings associated with service sales in Great Falls as well as tax refund interest.

     Natural Gas Interest Expense — Interest expense is $152,000 higher in fiscal 2005 than fiscal 2004, primarily due to higher short and long-term interest rates.

     Natural Gas Income Tax Benefit (Expense) — Income tax expenses were $242,000 higher in fiscal 2005 than fiscal 2004 due to higher income before taxes.

Operating Results of our Propane Operations

	Years Ended June 30
	2006			2005			2004
	(in thousands)
Propane Operations
Operating revenues	$	9,583		$	8,820		$	7,736
Gas Purchased		5,927			4,777			4,000
Gross Margin		3,656			4,043			3,736
Operating expenses		2,677			2,969			3,039
Operating income		979			1,074			697
Other (income)		(113	)		(210	)		(181	)
Income before interest and taxes		1,092			1,284			878
Interest expense		435			571			573
Income before income taxes		657			713			305
Income tax (expense)		(260	)		(271	)		(2	)
Net income	$	397		$	442		$	303

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

     Propane Revenue and Gross Margins — Propane Operations’ revenues increased $763,000 from $8,820,000 in fiscal 2005 to $9,583,000 in fiscal 2006 as a result of higher propane prices in fiscal 2006. Cost of propane sold increased from $4,777,000 to $5,927,000 for the same period, also due to increases in the cost of propane for both the regulated utility and the wholesale propane operations. Gross margin decreased by $387,000 from $4,043,000 in fiscal 2005 to $3,656,000 in fiscal 2006. Although revenue increased in the unregulated segment, competitive pressures and increased costs of propane did not allow us to maintain our margins.

     Propane Operating Expenses — Operating expenses were $2,677,000 for fiscal 2006 compared to $2,969,000 for fiscal 2005. This decrease of $292,000 is attributed to a restructuring of the compensation/benefits package, which reduced general and administrative costs by $220,000, including the effects of the curtailment of

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additional contributions to the Retiree Health Plan. Depreciation and other taxes showed a combined decrease of $28,000 and overhead costs decreased by $85,000. Maintenance expenses offset these with an increase of $42,000.

     Propane Other Income — Other income decreased by $97,000 from $210,000 in fiscal 2005 to $113,000 in fiscal 2006. The decrease was due to the early payoff of a note receivable on which we expected to receive interest.

     Propane Interest Expense — Interest expense decreased by $136,000 from $571,000 in fiscal 2005 to $435,000 in fiscal 2006. This decrease was due to an accelerated payoff of debt.

     Propane Income Tax Benefit (Expense) — Income tax expense decreased by $11,000 from $271,000 in fiscal 2005 to $260,000 in fiscal 2006 due to lower pretax income.

Fiscal Year Ended June 30, 2005 Compared to Fiscal Year Ended June 30, 2004

     Propane Revenue and Gross Margins — Propane Operations’ revenues increased $1,084,000 from $7,736,000 in fiscal 2004 to $8,820,000 in fiscal 2005 as a result of higher propane prices in fiscal 2005. Cost of propane sold increased from $4,000,000 to $4,777,000 for the same period, also due to increases in the cost of propane for both the regulated utility and the wholesale propane operations. Gross margin increased by $307,000 from $3,736,000 in fiscal 2004 to $4,043,000 in fiscal 2005. Although costs increased, revenues in all propane operations increased at a slightly greater rate, resulting in higher gross margin.

     Propane Operating Expenses — Operating expenses were $2,969,000 for fiscal 2005 compared to $3,039,000 for fiscal 2004. This decrease of $70,000 is due to decreases in operating costs of $132,000, a decrease in depreciation and maintenance expense of $4,000, a decrease in overhead costs of approximately $133,000, and a decrease in taxes other than income of $53,000 primarily related to the property tax settlement with the Montana Department of Revenue in fiscal 2004, offset by the gain on the sale of assets of $252,000 in fiscal 2004. The settlement amount was expensed in fiscal 2004 in the unregulated companies.

     Propane Other Income — Other income increased by $29,000 from $181,000 in fiscal 2004 to $210,000 in fiscal 2005. Increases in interest income were coupled with increases in other miscellaneous income.

     Propane Interest Expense — Interest expense decreased by $2,000 from $573,000 in fiscal 2004 to $571,000 in fiscal 2005.

     Propane Income Tax Expense — Income tax expense increased by $269,000 from $2,000 in fiscal 2004 to $271,000 in fiscal 2005 due to higher pretax income generated from increased margins coupled with lower operating costs. In fiscal 2004, permanent differences in tax assets and liabilities was generated from the sale of assets, resulting in lower taxes.

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Operating Results of our EWR Operations

					Years Ended June 30
	2006				2005				2004
					(in thousands)
Energy West Resources (“EWR”)
Operating revenues		$	18,540			$	22,674			$	26,091
Gas Purchased			16,990				20,760				26,028
Gross Margin			1,550				1,914				63
Operating expenses			657				1,173				1,096
Operating income			893				741				(1,033	)
Other (income) loss			(33	)			(67	)			13
Income before interest and taxes			926				808				(1,046	)
Interest expense			178				275				253
Income (loss) before income taxes			748				533				(1,299	)
Income tax benefit (expense)			(289	)			(211	)			444
Net income (loss)		$	459			$	322			$	(855	)

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

     EWR Revenues and Gross Margins — Revenues in EWR decreased $4,134,000 from $22,674,000 in fiscal 2005 to $18,540,000 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 $1,550,000 represents a decrease of $364,000 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 $516,000 from $1,173,000 for fiscal 2005 to $657,000 for fiscal 2006. The majority of this decrease can be attributed to general and administrative costs being $460,000 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 in fiscal 2006 as compared to fiscal 2005. The income included here was attained from the settlement of a contract dispute.

     EWR Interest Expense — Interest expense decreased $96,000 in fiscal 2006 as a result of minimal use of our line of credit.

     EWR Income Tax Expense — Income tax expense increased from $211,000 in fiscal 2005 to $289,000 in fiscal 2006 because of higher pre-tax income.

Fiscal Year Ended June 30, 2005 Compared to Fiscal Year Ended June 30, 2004

     EWR Revenues and Gross Margins — Revenues in EWR decreased $3,417,000 from $26,091,000 in fiscal 2004 to $22,674,000 in fiscal 2005. Fiscal 2005 revenues declined as a result of $8,679,000 lower trading revenue, offset by (1) a $3,472,000 increase in retail gas and electric margins, (2) a favorable change in valuation of derivative contracts for $1,546,000, (3) a deferred gain of $214,000, and (4) a $30,000 increase in gathering revenue in fiscal 2005.

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     EWR’s fiscal 2005 gross margin of $1,914,000 represents an increase of $1,851,000 from gross margin earned in fiscal 2004. This represents a $1,760,000 increase in the valuation of derivative contracts and a net increase in margin of $91,000 related to production, electricity and gas marketing activities. The amount of the $1,760,000 change in the derivative contract valuation that was attributable to fiscal 2005 is $516,000. The amount of the change in the derivative contract valuation that was attributable to fiscal 2004 was $(1,244,000).

     EWR Operating Expenses — Operating expenses of EWR increased approximately $77,000, from $1,096,000 for fiscal 2004 to $1,173,000 for fiscal 2005. This increase is due primarily to a reduction in overhead charges, partially offset by an increase in general and administrative charges.

     EWR Other Income (Expense) — Other income (expense) increased by $80,000 due to income of $58,000 from the settlement of a contract dispute, $9,000 of interest earned on an income tax refund, and $13,000 savings in other expenses not incurred in 2005.

     EWR Interest Expense — Interest expense increased by $22,000 in fiscal 2005 as compared to fiscal 2004 due to an increase in borrowings.

     EWR Income Tax Benefit (Expense) — Income tax benefit (expense) changed from a tax benefit of $444,000 in fiscal 2004 to an expense of $211,000 in fiscal 2005 due to changes in income before taxes.

Operating Results of our Pipeline Operations

	Years Ended June 30
	2006			2005			2004
	(in thousands)
Pipeline Operations
Operating revenues	$	411		$	424		$	401
Gas Purchased		0			0			0
Gross Margin		411			424			401
Operating expenses		149			202			214
Operating income		262			222			187
Other (income)		0			(2	)		(121	)
Income before interest and taxes		262			224			308
Interest expense		41			56			50
Income before income taxes		221			168			258
Income tax (expense)		(85	)		(55	)		(99	)
Net income	$	136		$	113		$	159

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. There also was a small decrease in overhead costs and an increase in depreciation.

     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 Benefit (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.

Fiscal Year Ended June 30, 2005 Compared to Fiscal Year Ended June 30, 2004

     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 increased from $401,000 in fiscal 2004 to $424,000 in fiscal 2005. The increase of $23,000 was due an increase in gathering volumes on the Glacier gathering line.

     Pipeline Operating Expenses — Operating expenses decreased from $214,000 in fiscal 2004 to $202,000 in fiscal 2005. The $12,000 decrease was due to a reduction in payroll and related expenses.

     Pipeline Other Income — Other income decreased from $121,000 in fiscal 2004 to $2,000 in fiscal 2005. Fiscal 2004 included the sale of non-operating real estate assets located in Montana, which resulted in a gain of $121,000.

     Pipeline Interest Expense — Interest expense increased from $50,000 in fiscal 2004 to $56,000 in fiscal 2005 due to higher interest rates.

     Pipeline Income Tax Benefit (Expense) — Income tax expense decreased from $99,000 in fiscal 2004 to $55,000 in fiscal 2005. The decrease is due to lower pre-tax income in fiscal 2005 compared to fiscal 2004.

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 $15,000,000 credit facility at LaSalle Bank, shown as line of credit on the accompanying balance sheet and described under “Liquidity and Capital Resources,” below. Our use of the LaSalle credit facility decreased to $0 at June 30, 2006, compared with $3,900,000 at June 30, 2005. In addition, we had $1,000,000 in temporary investments as of June 30, 2006. This $4,900,000 improvement in our cash position is primarily due to increased net income, decreased receivables and deferred gas costs, and an increase in accounts payable.

     We made capital expenditures of $2,473,000, $2,796,000, and $2,317,000 during fiscal 2006, 2005, and 2004, respectively. We finance our capital expenditures on an interim basis by the use of our operating cash flow and use of the revolving line of credit portion of the LaSalle credit facility. We may periodically repay our short-term borrowings under our LaSalle credit facility by using the net proceeds from the sale of long-term debt and equity securities.

     Long-term debt decreased to $17,605,000 at June 30, 2006, compared with $18,677,000 at June 30, 2005. This $1,072,000 decrease resulted primarily from the ability to generate a positive cash flow as detailed above.

     Cash increased to $1,640,000 at June 30, 2006, compared with $94,000 at June 30, 2005. This $1,546,000 increase in cash for the year ended June 30, 2006 is compared with the $1,229,000 decrease and $616,000 decrease in cash for the years ended June 30, 2005 and June 30, 2004, respectively, as shown in the following table:

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	Years Ended June 30,
	2006			2005			2004
Cash provided by (used in) operating activities	$	9,158,000		$	1,344,000		$	(5,872,000	)
Cash used in investing activities		(2,212,000	)		(2,466,000	)		(1,146,000	)
Cash (used in) provided by financing activities		(5,401,000	)		(107,000	)		6,402,000
Increase (decrease) in cash	$	1,545,000		$	(1,229,000	)	$	(616,000	)

     For the year ended June 30, 2006, cash provided by operating activities increased $7,814,000 as compared to the year ended June 30, 2005, primarily because of the increase in net income of $754,000, decreases in accounts receivable and recoverable cost of gas purchases of $2,467,000 and $1,615,000, respectively, and an increase in accounts payable of $981,000.

     For the year ended June 30, 2006, cash used in investing activities decreased $254,000 as compared to the year ended June 30, 2005, primarily because of a reduction in capital expenditures. For the year ended June 30, 2005, cash used in investing activities decreased $1,320,000 as compared to the year ended June 30, 2004, due primarily to a $479,000 increase in capital expenditures and no significant proceeds from the sale of assets in fiscal 2005.

     For the year ended June 30, 2006, cash flows from financing activities decreased by $5,294,000 as compared to the year ended June 30, 2005, primarily because we paid off the line of credit with LaSalle Bank. We also paid $495,000 in dividends in fiscal 2006. For the year ended June 30, 2005, cash flows from financing activities decreased by $6,509,000 as compared to the year ended June 30, 2004, primarily due to $8,000,000 borrowings of long-term notes net of $1,526,000 debt issuance expenses during fiscal 2004.

Governmental Regulation

     Our utility operations are subject to regulation by the MPSC, the WPSC, and 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 our company 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 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 the working capital line of credit portion of the LaSalle credit facility. We have greater need for short-term borrowing during periods when internally generated funds are not sufficient to cover all capital and operating requirements, including costs of gas purchased and capital expenditures. In general, our short-term borrowing needs for purchases of gas inventory and capital expenditures are greatest during the summer and fall months and our short-term borrowing needs for financing customer accounts receivable are greatest during the winter months.

     We maintain a $15.0 million revolving line of credit facility with LaSalle Bank National Association, as Agent for certain banks. The LaSalle credit facility is accompanied by a $6.0 million term loan maturing on March 31, 2009. At June 30, 2006, the term loan had an outstanding balance of $5.1 million. Borrowings under the LaSalle credit facility are secured by liens on substantially all of our assets. Our obligations under certain other notes and industrial development revenue obligations are secured on an equal and ratable basis with LaSalle in the collateral granted to secure the borrowings under the LaSalle credit facility, with the exception of the first $1.0 million of debt under the LaSalle credit facility.

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

	First		Second		Third		Fourth
	Quarter		Quarter		Quarter		Quarter
Year Ended June 30, 2006
Minimum borrowing	$	3,100,000	$	5,200,000	$	0	$	0
Maximum borrowing	$	5,200,000	$	12,250,000	$	12,050,000	$	0
Average borrowing	$	4,167,000	$	9,489,000	$	5,619,000	$	0
Year Ended June 30, 2005
Minimum borrowing	$	7,729,000	$	12,688,000	$	3,500,000	$	2,700,000
Maximum borrowing	$	13,129,000	$	14,629,000	$	13,929,000	$	3,900,000
Average borrowing	$	10,196,000	$	13,982,000	$	8,110,000	$	3,167,000
Year Ended June 30, 2004
Minimum borrowing	$	6,105,000	$	12,102,000	$	9,229,000	$	4,729,000
Maximum borrowing	$	8,602,000	$	12,629,000	$	13,229,000	$	6,729,000
Average borrowing	$	7,482,000	$	12,277,000	$	10,563,000	$	5,563,000

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

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

     At June 30, 2006, we had approximately $1,640,000 of cash on hand. In addition, at June 30, 2006, we had no borrowings under the $15.0 million revolving line of credit portion of the LaSalle credit facility. Our short-term borrowings under our lines of credit during fiscal 2006 had a daily weighted average interest rate of 7.05% per annum. At June 30, 2006, we had no outstanding letters of credit related to gas and electricity purchase contracts. As discussed above, our short-term borrowing needs for purchases of gas inventory and capital expenditures are greatest during the summer and fall months. Our availability normally increases in January as monthly heating bills are paid and gas purchases are no longer necessary.

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

     Under the terms of the Long Term Notes and Bonds, we are subject to certain restrictions, including restrictions on total dividends and distributions, liens and secured indebtedness, and asset sales. We also are

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restricted from incurring additional long-term indebtedness if we do not meet certain debt to interest and debt to capital ratios. At June 30, 2006 and 2005, we were in compliance with the financial covenants under the Long Term Notes and Bonds.

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

     The total amount outstanding under all of our long term debt obligations was approximately $17.6 million and $18.7 million, at June 30, 2006 and June 30, 2005, respectively. The portion of such obligations due within one year was approximately $1,058,000 and $1,013,000 at June 30, 2006, and June 30, 2005, respectively.

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

Contractual Obligations

     Our major financial market risk exposure is to changing interest rates. Changing interest rates will affect interest paid on our variable-rate debt. Our policy is to manage interest rates through the use of a combination of fixed-rate and floating-rate debt. On August 9, 2004, we entered into a fixed-for-floating interest rate swap transaction on our five-year floating interest rate term note. If we were to designate it as a hedge, this transaction would qualify as a fair value hedge under SFAS No. 133. We have elected not to designate it as a hedge and have not recorded it as a fair value hedge.

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     The table below presents contractual balances of our consolidated long-term and short-term debt at the expected maturity dates as well as the fair value of those instruments on June 30, 2006. The interest rates presented below represent the weighted-average interest rates for the year ended June 30, 2006. The fair value of the interest rate swap as of June 30, 2006 was $95,371 and is recorded as an asset on the accompanying financial statements.

			1 year						After
Contractual Obligations	Total		or less		2-3 years		4-5 years		5 years
Interest payments (a)	$	6,798,806	$	1,397,415	$	2,438,654	$	1,793,162	$	1,169,575
Long Term Debt (b)		18,663,214		1,058,214		5,515,000		260,000		11,830,000
Operating Lease Obligations		457,848		144,624		205,224		108,000		—
Transportation and Storage Obligation (c)	$	15,724,771		4,367,715		8,517,792		2,839,264		—
Total Obligations	$	41,644,639	$	6,967,968	$	16,676,670	$	5,000,426	$	12,999,575

(a)	Our long-term debt, notes payable and customers’ deposits all require interest payments. Interest payments are projected based on actual interest payments incurred in fiscal 2006 until the underlying debts mature.
(b)	See Note 7 of the Notes to Consolidated Financial Statements for a description of this debt. The cash obligations represent the maximum annual amount of redemptions to be made to certain holders or their beneficiaries through the debt maturity date.
(c)	Transportation and storage obligations represent annual commitments with suppliers for periods extending up to four years. These costs are recoverable in customer rates.

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 and propane pipeline systems. In fiscal 2006, 2005, and 2004, our total capital expenditures were approximately $2,473,000, $2,796,000, and $2,317,000, respectively, including purchases of natural gas production properties. Expenditures for fiscal 2006, 2005, and 2004 were limited to essential needs only. We anticipate that our expenditures in fiscal 2007 also will be limited to essential needs only.

     We estimate future cash requirements for capital expenditures will be as follows:

			Estimated
			Future Cash
	Actual		Requirements
	2006		2007
	(In thousands)
Natural Gas Operations	$	1,744	$	1,867
Propane Operations		607		851
Energy West Resources		115		0
Pipeline Operations		7		0
Total capital expenditures	$	2,473	$	2,718

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 Activities and 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.

30

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.

     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.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

     Our company is subject to certain market risks, including commodity price risk (i.e., natural gas and propane prices) and interest rate risk. The adverse effects of potential changes in these market risks are discussed below. The sensitivity analyses presented do not consider the effects that such adverse changes may have on overall economic activity nor do they consider additional actions management may take to mitigate our exposure to such changes. Actual results may differ. See the Notes to our Consolidated Financial Statements for a description of our accounting policies and other information related to these financial instruments.

Commodity Price Risk

     Our company seeks 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 our company will consider to those related to physical natural gas deliveries. Therefore, management believes that our results of operations are not significantly exposed to changes in natural gas prices.

Interest Rate Risk

     Our results of operations are affected by fluctuations in interest rates (e.g. interest expense on debt). Our company mitigates this risk by entering into long-term debt agreements with fixed interest rates. Some of our notes payable, however, are subject to variable interest rates, which we may mitigate by entering into interest rate swaps. A hypothetical 100 basis point change in market rates applied to the balance of the notes payable would change interest expense by approximately $26,000 annually.

Credit Risk

     Credit risk relates to the risk of loss that our company would incur as a result of non-performance by counterparties of their contractual obligations under the various instruments with our company. Credit risk may be concentrated to the extent that one or more groups of counterparties have similar economic, industry or other characteristics that would cause their ability to meet contractual obligations to be similarly affected by changes in market or other conditions. In addition, credit risk includes not only the risk that a counterparty may default due to circumstances relating directly to it, but also the risk that a counterparty may default due to circumstances that relate

31

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 on page F-1 of this Annual Report on Form 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 on Form 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 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 on Form 10-K, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) were effective at the reasonable assurance level. They are not aware of any significant changes in our disclosure controls or in other factors that could significantly affect these controls subsequent to the date of their evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. During the most recent fiscal period, there have not been any changes in our internal control over financial reporting that have materially affected, or that are reasonably likely to materially affect, our internal control over financial reporting.

Item 9B. Other Information.

Not applicable.

PART III

Item 10. Directors and Executive Officers of the Registrant.

     Information required by this item is incorporated by reference to the material appearing under the headings “Election of Directors,” “Executive Officers and Compensation,” and “Section 16(a) Beneficial Ownership Reporting Compliance” in the Proxy Statement for our 2006 Annual Meeting.

Item 11. Executive Compensation.

     Information required by this item is incorporated by reference to the material appearing under the headings “Election of Directors” and “Executive Officers and Compensation” in the Proxy Statement for our 2006 Annual Meeting.

32

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 Stockholders and Management” in the Proxy Statement for our 2006 Annual Meeting.

Item 13. Certain Relationships and Related Transactions.

     There are no transactions with management or business relationships with others that require disclosure under Item 404 of Regulation S-K.

Item 14. Principal Accounting 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 2006 Annual Meeting.

33

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
Report of Independent Registered Public Accounting Firm — Deloitte and Touche LLP		F-3
Consolidated Balance Sheets		F-4
Consolidated Statements of Operations		F-5
Consolidated Statements of Stockholders’ Equity		F-6
Consolidated Statements of Cash Flows		F-7
Notes to Consolidated Financial Statements		F-9
Schedule II — Valuation and Qualifying Accounts

(b) Exhibits. The Exhibits required to be filed by Item 601 of Regulation S-K are listed under the heading “Exhibit Index,” below.

(c) Financial Statement Schedules:

Schedule II

Valuation and Qualifying Accounts
Energy West, Incorporated
June 30, 2006

	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, 2004	$	213,013	$	163,041		($75,240	)	$	300,814
Year Ended June 30, 2005	$	300,814	$	168,369		($174,537	)	$	294,646
Year Ended June 30, 2006	$	294,646	$	281,156		($433,430	)	$	142,372

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

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/ David A. Cerotzke

David A. Cerotzke

President and Chief Executive Officer

(principal executive officer)

Date: September 28, 2006

KNOW ALL THESE PERSONS BY THESE PRESENTS, that each person whose signature appears below constitutes and appoints, jointly and severally, David Cerotzke and John Allen, 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 on Form 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/ David A. Cerotzke David A. Cerotzke	President, Chief Executive Officer, and Director (principal executive officer)	September 28, 2006
/s/ Wade F. Brooksby	Chief Financial Officer (principal financial officer and principal accounting officer)	September 28, 2006
Wade F. Brooksby
/s/ W.E. Argo	Director	September 28, 2006
W.E. Argo
/s/ Mark D. Grossi	Director	September 28, 2006
Mark D. Grossi
/s/ Richard M. Osborne	Director	September 28, 2006
Richard M. Osborne
/s/ Terry M. Palmer	Director	September 28, 2006
Terry M. Palmer
/s/ Richard J. Schulte	Director	September 28, 2006
Richard J. Schulte
/s/ Thomas J. Smith	Director	September 28, 2006
Thomas Smith

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
Report of Independent Registered Public Accounting Firm —Deloitte and Touche LLP		F-3
Consolidated Balance Sheets as of June 30, 2006 and 2005		F-4
Consolidated Statements of Operations for the Years Ended June 30, 2006, 2005, and 2004		F-5
Consolidated Statements of Changes in Stockholders’ Equity for the Years Ended June 30, 2006, 2005, and 2004		F-6
Consolidated Statements of Cash Flows for the Years Ended June 30, 2006, 2005, and 2004		F-7
Notes to Consolidated Financial Statements		F-9

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of
Energy West, Incorporated
Great Falls, Montana

     We have audited the accompanying consolidated balance sheets of Energy West, Incorporated and subsidiaries as of June 30, 2006 and 2005, and the related consolidated statements of operations, stockholders’ equity, and cash flows for the years then ended. Our audit also included the financial statement schedule as of, and for the years ending June 30, 2006 and 2005 listed in the index at 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 and financial statement schedule based on our audit.

     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 audits 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, 2006 and 2005, and the results of their operations and their cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion the financial statement schedule as of, and for the years ended June 30, 2006 and 2005, 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 21, 2006

F-2

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of
Energy West, Incorporated
Great Falls, Montana

We have audited the accompanying consolidated statements of operations, stockholders’ equity, and cash flows of Energy West, Incorporated and subsidiaries for the year ended June 30, 2004. Our audit also included the financial statement schedule for the year ended June 30, 2004, listed in the Index at 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 the financial statements and financial statement schedule based on our audit.

We conducted our audit 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 audit provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the results of operations and cash flows of Energy West, Incorporated and subsidiaries for the year ended June 30, 2004, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule for the year ended June 30, 2004, 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/ DELOITTE AND TOUCHE LLP

Salt Lake City, Utah
December 16, 2004

 F-3 

ENERGY WEST INCORPORATED AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS, JUNE 30, 2006 AND 2005

	2006		2005
ASSETS
Current Assets:
Cash	$	1,639,578	$	93,606
Accounts receivable less $142,372 and $294,646 respectively, allowance for bad debt		4,162,851		5,791,888
Unbilled gas		1,020,540		1,092,320
Derivative assets		137,865		119,069
Natural gas and propane inventories		5,424,778		3,711,033
Materials and supplies		455,228		440,959
Prepayment and other		290,860		386,306
Income tax receivable		—		1,924,648
Recoverable cost of gas purchases		1,323,442		1,863,475
Total current assets		14,455,142		15,423,304
Property, Plant and Equipment, Net		39,104,060		38,942,123
Note Receivable		—		174,561
Deferred Charges		4,214,178		4,725,924
Other Assets		157,365		167,481
TOTAL ASSETS	$	57,930,745	$	59,433,393
LIABILITIES AND CAPITALIZATION
Current Liabilities:
Current portion of long-term debt	$	1,058,213	$	1,013,089
Line of credit		—		3,900,000
Accounts payable		3,592,260		2,651,047
Derivative liabilities		42,664		114,237
Accrued income taxes		1,320,431		—
Deferred income taxes		269,163		96,214
Accrued and other current liabilities		3,860,302		3,750,177
Total current liabilities		10,143,033		11,524,764
Other Obligations:
Deferred income taxes		5,835,886		6,267,858
Deferred investment tax credits		292,220		313,282
Other long-term liabilities		4,889,493		5,463,667
Total		11,017,599		12,044,807
Long-Term Debt		17,605,000		18,677,197
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, 2,934,177 and 2,912,564 shares outstanding at June 30, 2006 and 2005, respectively		440,127		436,892
Capital in excess of par value		7,634,337		7,435,309
Retained earnings		11,090,649		9,314,424
Total stockholder’s equity		19,165,113		17,186,625
TOTAL CAPITALIZATION		36,770,113		35,863,822
TOTAL LIABILITIES AND CAPITALIZATION	$	57,930,745	$	59,433,393

See notes to consolidated financial statements

F-4

ENERGY WEST INCORPORATED AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS
FOR THE YEARS ENDED JUNE 30, 2006, 2005, AND 2004

	2006			2005			2004
REVENUES:
Natural gas operations	$	55,744,531		$	44,791,564		$	39,062,689
Propane operations		9,582,600			8,819,980			7,736,379
Gas and electric—wholesale		18,539,793			22,673,382			26,090,845
Pipeline operations		411,237			424,038			401,269
Total revenues		84,278,161			76,708,964			73,291,182
EXPENSES:
Gas purchased		49,379,651			37,572,841			31,883,566
Gas and electric—wholesale cost of goods sold		16,989,654			20,759,637			26,027,876
Distribution, general, and administrative		8,219,283			9,446,567			10,169,560
Maintenance		624,085			596,312			480,086
Depreciation and amortization		2,183,740			2,313,238			2,332,073
Taxes other than income		1,614,684			1,653,936			1,209,916
Total expenses		79,011,097			72,342,531			72,103,077
OPERATING INCOME		5,267,064			4,366,433			1,188,105
NON-OPERATING INCOME		504,342			445,207			385,277
INTEREST EXPENSE		(2,080,030	)		(2,677,298	)		(2,498,623	)
INCOME (LOSS) BEFORE INCOME TAXES		3,691,376			2,134,342			(925,241	)
INCOME TAX (EXPENSE) BENEFIT		(1,374,706	)		(752,873	)		368,921
NET INCOME (LOSS)	$	2,316,670		$	1,381,469		$	(556,320	)
EARNINGS (LOSS) PER COMMON SHARE:
Basic	$	0.79		$	0.53		$	(0.21	)
Diluted	$	0.79		$	0.53		$	(0.21	)
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:
Basic		2,924,512			2,630,679			2,596,454
Diluted		2,948,046			2,630,679			2,596,454

See notes to consolidated financial statements.

F-5

ENERGY WEST INCORPORATED AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY
FOR THE YEARS ENDED JUNE 30, 2006, 2005, AND 2004

					Capital in
	Common		Common		Excess of		Retained
	Shares		Stock		Par Value		Earnings			Total
BALANCE AT JUNE 30, 2003		2,595,250	$	389,295	$	5,056,425	$	8,511,025		$	13,956,745
Sales of common stock at $5.95 to $7.25 per share under the Company’s dividend reinvestment plan		3,256		488		21,262		—			21,750
Net loss								(556,320	)		(556,320	)
401k stock match		—		—		—		(21,750	)		(21,750	)
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
Sale of stock @ $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

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

	2006			2005			2004
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	2,316,670		$	1,381,469		$	(556,320	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation and amortization, including deferred charges and financing costs		2,880,957			3,016,716			3,467,774
Derivative assets		(18,796	)		80,179			424,387
Derivative liabilities		(71,573	)		(331,674	)		819,747
Deferred gain		(643,280	)		(269,903	)		—
Gain on sale of assets		—			(9,201	)		(333,987	)
Investment tax credit		(21,062	)		(21,062	)		(21,062	)
Deferred gain on sale of assets		(23,639	)		(23,628	)		(23,628	)
Deferred income taxes		330,034			1,772,533			209,612
Changes in assets and liabilities:
Accounts and notes receivable		2,545,161			77,789			1,090,118
Natural gas and propane inventories		(1,713,745	)		1,472,013			(4,144,356	)
Accounts payable		481,399			(500,217	)		(5,230,702	)
Recoverable/refundable cost of gas purchases		540,033			(1,075,068	)		278,702
Prepayments and other		95,445			(15,926	)		(17,397	)
Other assets		1,380,640			(21,924	)		539,349
Other liabilities		1,080,149			(4,187,677	)		(2,374,106	)
Net cash provided by (used in) operating activities		9,158,393			1,344,419			(5,871,869	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Construction expenditures		(2,472,972	)		(2,795,565	)		(2,316,695	)
Acquisition of producing natural gas properties		174,561			—			—
Proceeds from sale of assets		—			32,605			946,233
Customer advances received for construction		106,406			74,348			65,579
Increase (decrease) from contributions in aid of construction		(19,911	)		221,909			158,735
Net cash (used in) investing activities		(2,211,916	)		(2,466,703	)		(1,146,148	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Repayments of long-term debt		(1,027,073	)		(2,979,706	)		(696,831	)
Proceeds from lines of credit		14,850,000			10,100,000			32,932,346
Repayments of lines of credit		(18,750,000	)		(12,930,062	)		(32,307,630	)
Proceeds from long-term debt		—			—			8,000,000
Proceeds from other short-term borrowing		—			3,500,000			—
Debt issuance cost								(1,525,934	)
Sale of common stock		21,228			2,202,956			—
Dividends paid		(494,660	)		—			—
Net cash provided by (used in) financing activities		(5,400,505	)		(106,812	)		6,401,951
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		1,545,972			(1,229,096	)		(616,066	)
CASH AND CASH EQUIVALENTS:
Beginning of year		93,606			1,322,702			1,938,768
End of year	$	1,639,578		$	93,606		$	1,322,702

See notes to consolidated financial statements (Continued)

F-7

ENERGY WEST INCORPORATED AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED JUNE 30, 2006, 2005, AND 2004

	2006		2005		2004
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Cash paid during the period for interest	$	1,047,633	$	2,290,133	$	1,858,023
Cash paid during the period for income taxes		8,000		447,000		—
SUPPLEMENTAL SCHEDULE OF NONCASH INVESTING AND FINANCING ACTIVITIES:
Assets sold for notes receivable issued		—		—		620,333
Shares issued to satisify deferred board compensation		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		21,750
Capitalized interest		18,855		34,160		24,602

See notes to consolidated financial statements (concluded)

F-8

ENERGY WEST, INCORPORATED AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
For the years ended June 30, 2006, 2005, and 2004

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 and around Payson, Arizona and Cascade, Montana. Our West Yellowstone, Montana operation is supplied by liquefied natural gas.

Our non-regulated operations include wholesale distribution of bulk propane in Arizona and the retail distribution of bulk propane in Arizona. 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.

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”). 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, Propane Operations, EWR, and Pipeline 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 and Propane Inventories — Natural gas inventory and propane inventory are 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.

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 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, 2006 and June 30, 2005, the Company had unrecovered purchase gas costs of $1,323,442 and $1,863,475 respectively.

F-9

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, 2006, 2005, and 2004, 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, the Company recorded $57,374 ($35,308 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. At June 30, 2006, there was $172,123 of total unrecognized compensation cost related to stock-based compensation. That cost is expected to be recognized over a period of three years.

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 Employees and 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 years ended June 30, 2005 and 2004, reported net income and per share amounts for years ended June 30, 2005 and 2004, 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 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 periods in 2005 and 2004.

F-10

	2006			2005			2004
Net income (loss), as reported for the year ended 2006	$	2,316,670		$	1,381,469		$	(556,320	)
Add: stock-based employee compensation expense included in reported net income, net of related tax effects		35,308			0			0
Deduct: compensation expense determined under fair value based method for all awards, net of related tax effects		(35,308	)		(51,450	)		(19,160	)
Pro forma net income (loss)	$	2,316,670		$	1,330,019		$	(575,480	)
Earnings per share:
Basic—as reported	$	0.79		$	0.53		$	(0.21	)
Basic—pro forma	$	0.79		$	0.51		$	(0.22	)
Diluted—as reported	$	0.79		$	0.53		$	(0.21	)
Diluted—pro forma	$	0.79		$	0.51		$	(0.22	)

In the fiscal years ended June 30, 2006 and 2005, 48,500 and 70,000 options were granted, respectively. In the fiscal year ended June 30, 2004, no options were granted. At June 30, 2006 and 2005, a total of 145,500 and 126,000 options were outstanding, respectively.

	2006			2005			2004
Expected dividend rate		2.00	%		0.00	%		0.00	%
Risk free interest rate		4.87			3.90			4.70
Weighted average expected lives, in years		3.40			4.26			3.40
Price volatility		39.00	%		54.00	%		54.00	%
Total intrinsic value of options exercised	$	4,087		$	0		$	0
Total cash received from options exercised	$	21,228		$	0		$	0

Comprehensive Income — During the years ended June 30, 2006, 2005, and 2004, the Company had no components of comprehensive income (loss) other than net income (loss).

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.

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 operations. 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

F-11

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, 2005 and 2004, the Company had elected the normal treatment for the majority of its contracts. As of June 30, 2006 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. Debt reacquisition costs for refinanced debt are amortized over the remaining life of the 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.

Earnings Per Share — Net income (loss) 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 145,500 and 126,000 shares of common stock were outstanding at June 30, 2006 and June 30, 2005, respectively. These options were excluded in the computation of diluted earnings (loss) per share for fiscal 2005 as the options were anti-dilutive.

Credit Risk — Our primary market areas are Montana, Wyoming, and 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.

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 Obligation effective 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 $650,717 and $618,473 represents the estimated future liability as of June 30, 2006 and June 30, 2005 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.

F-12

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

     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 Activities and 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.

     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.

2. 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, 2006, an independent reservoir engineer estimated the net gas reserves at 4.4 Bcf (unaudited) and a $9,653,000 net present value after applying a 10% discount (unaudited). The net book value of the gas properties totals $1,547,945 and is included in the Property, Plant and Equipment, Net in the accompanying consolidated financial statements.

The wells are depleting based upon production at approximately 7% per year as of June 30, 2006. For the period ended June 30, 2006, EWR’s portion of the daily gas production was approximately 660 Mcf per day, or approximately 9% of EWR’s present volume requirements.

F-13

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, 2006, EWD’s portion of the daily gas production was approximately 290 Mcf per day, or approximately 5% of EWR’s present volume requirements.

EWR and EWD’s combined portion of the estimated daily gas production from the reserves is approximately 950 Mcf, or approximately 14% 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 Statement of Financial Accounting Standard (“SFAS”) No. 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, 2006 and 2005:

	2006			2005
Gas transmission and distribution facilities	$	56,122,235		$	53,943,812
Land		325,770			332,506
Buildings and leasehold improvements		3,250,007			3,250,007
Transportation equipment		2,376,065			2,237,542
Computer equipment		4,969,189			4,939,845
Other equipment		4,574,667			4,643,354
Construction work-in-progress		137,881			188,048
Producing natural gas properties		2,082,903			2,046,352
		73,838,717			71,581,466
Accumulated depreciation, depletion, and amortization		(34,734,657	)		(32,639,343	)
Total	$	39,104,060		$	38,942,123

F-14

4. Deferred Charges

Deferred charges consist of the following as of June 30, 2006 and 2005:

	2006		2005
Regulatory asset for property tax	$	2,303,015	$	2,561,265
Regulatory asset for income taxes		458,753		458,753
Regulatory assets for deferred environmental remediation costs		334,996		413,218
Other regulatory assets		126,263		52,198
Unamortized debt issue costs		991,151		1,240,490
Total	$	4,214,178	$	4,725,924

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

The property tax asset is recovered in rates over a ten-year period starting January 1, 2004. The 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.

5. Accrued and Other Current Liabilities

Accrued and other current liabilities consist of the following as of June 30, 2006 and 2005:

	2006		2005
Property tax settlement—current portion	$	243,000	$	243,000
Payable to employee benefit plans		275,377		481,514
Accrued vacation		258,831		267,859
Customer deposits		465,188		418,148
Accrued interest		140,648		97,987
Accrued taxes other than income		467,947		507,288
Deferred short-term gain		243,519		399,760
Deferred payments from levelized billing		844,344		459,814
Other		921,448		874,807
Total	$	3,860,302	$	3,750,177

F-15

6. Other Long-Term Liabilities

Other long-term liabilities consist of the following as of June 30, 2006 and 2005:

	2006		2005
Asset retirement obligation	$	650,717	$	618,473
Contribution in aid of construction		1,954,980		1,447,448
Customer advances for construction		277,845		677,936
Accumulated postretirement obligation		139,200		342,900
Deferred gain on sale leaseback of assets		—		23,639
Deferred gain — long-term *		325,582		569,102
Regulatory liability for income taxes		83,161		83,161
Property tax settlement		1,458,008		1,701,008
Total	$	4,889,493	$	5,463,667

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

7. Line of Credit and Long-Term Debt

LaSalle Line of Credit — On March 31, 2004, the Company entered into a modification of its existing credit facility (the “LaSalle credit facility”) with LaSalle Bank National Association (“LaSalle”). Among other things, such modification converted $8,000,000 of revolving loans into a $6,000,000, five-year term loan and a $2,000,000 term loan due on November 30, 2004, (collectively the “Term Loan”) and reduced the maximum amount of the line of credit, which expires on November 28, 2006, from $23,000,000 to $15,000,000. The $2,000,000 term loan was repaid May 26, 2005 with the proceeds of a sale of equity securities by the Company. The LaSalle credit facility is secured, on an equal and ratable basis with our other long-term debt, by substantially all of our assets.

Long-term Debt — Long-term debt at June 30, 2006 and 2005 consists of the following:

	2006			2005
Series 1997 notes payable	$	7,840,000		$	7,853,984
Series 1993 notes payable		4,840,000			5,355,000
Series 1992B industrial development revenue obligations		880,000			975,000
Term loan		5,100,000			5,500,000
Capital lease		3,213			6,302
Total long-term debt		18,663,213			19,690,286
Less current portion of long-term debt		(1,058,213	)		(1,013,089	)
Long-term debt	$	17,605,000		$	18,677,197

Borrowings under the LaSalle credit facility are secured by liens on substantially all of the assets of the Company and its subsidiaries. Our obligations under the 1997 Notes, 1993 Notes and 1992B Notes, described below, are secured on an equal and ratable basis in the collateral granted to secure the borrowings under the LaSalle credit facility, with the exception of the first $1.0 million of debt under the LaSalle credit facility.

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

F-16

the 1997 notes then outstanding, plus accrued interest, will be due and payable on June 1, 2012. At our option, the notes may 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. As of June 30, 2006, the Company had not redeemed any of the notes under this issue, except for $160,000 in redemptions as a result of redemption rights exercisable upon the deaths of holders of the notes.

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 may 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. As of June 30, 2006, the Company had not redeemed prior to their scheduled maturity any of the notes under this issue.

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. As of June 30, 2006, the Company had not redeemed prior to their scheduled maturity any of the 1992B Bonds.

Term Loan — On March 31, 2004, the Company entered into a modification of its LaSalle credit facility. The modification 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 term loan that was repaid May 26, 2005 with proceeds of a placement of equity securities by the Company. Under the LaSalle credit facility, the Company pays interest (i) on its line of credit borrowings at either (a) the London Interbank Offered Rate (LIBOR) plus 250 basis points (bps) or, if the Company elects, (b) the rate publicly announced from time to time by the Lender as its “prime rate” (“Prime”); (ii) on its $6,000,000 term loan at either (a) LIBOR plus 350 bps or, if the Company elects, (b) Prime plus 200 bps; and (iii) on its $2,000,000 term loan at Prime plus 200 bps through March 31, 2005 and at the Prime Rate plus 300 bps from April 1, 2005 through May 26, 2005. The LaSalle credit facility also has a commitment fee of 35 bps per annum due on the daily unutilized portion of the facility. The $2,000,000 term loan was repaid May 26, 2005 with the proceeds of a sale of equity securities by the Company.

Aggregate Annual Maturities — The scheduled maturities of long-term debt at June 30, 2006 are as follows:

											Total
	Term		Series		Series		Series		Capital		Long-Term
	Loan		1997		1993		1992B		Lease		Debt
Year ending June 30:
2007	$	400,000	$	—	$	550,000	$	105,000	$	3,213	$	1,058,213
2008		400,000		—		590,000		110,000				1,100,000
2009		400,000		—		—		115,000		—		515,000
2010		3,900,000		—		—		125,000		—		4,025,000
2011		0		—		—		135,000		—		135,000
Thereafter		0		7,840,000		3,700,000		290,000		—		11,830,000
Total	$	5,100,000	$	7,840,000	$	4,840,000	$	880,000	$	3,213	$	18,663,213

F-17

The estimated fair value of our fixed rate long-term debt, based on quoted market prices for the same or similar issues, is approximately $14,667,537 and $16,456,080 as of June 30, 2006 and 2005, respectively.

Debt Covenants — Our long-term debt obligation agreements contain various covenants, including limiting total dividends and distributions made in the immediately preceding 60-month period to aggregate consolidated net income for such period, restricting senior indebtedness, limiting asset sales, maintaining certain financial debt and interest ratios, and others. At June 30, 2006 and 2005, we were in compliance with the financial covenants under the LaSalle credit facility and Long Term Notes and Bonds.

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 short-term loan under the LaSalle credit facility.

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, 2006, 2005, and 2004 were $272,300, $479,868, and $512,220, respectively. The Company also sponsors 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. 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 benefits are paid from the assets held in the VEBA Trust account. The Company is not required to fund the Retiree Health Plan.

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, 2006, 2005 and 2004. In addition, the Company makes matching contributions in the form of Company stock equal to 10% of each participant’s elective deferrals. The Company contributed shares of our stock valued at $19,436, $20,185, and $21,750 in fiscal 2006, 2005, and 2004, respectively.

F-18

The following table sets forth the funded status of the Retiree Health Plan and amounts recognized in the consolidated financial statements as of June 30, 2006 and 2005 and for the years ended June 30, 2006, 2005, and 2004:

	2006			2005
Change in benefit obligation:
Projected benefit obligation Benefit obligation at beginning of year	$	941,200		$	776,600
Service costs		41,800			37,600
Interest costs		40,100			45,600
Actuarial (gains) losses		(222,000	)		170,100
Benefits paid		(63,900	)		(88,700	)
Curtailments		(395,700	)		—
Benefit obligation at end of year		341,500			941,200
Change in plan assets:
Fair value of plan assets at beginning of year		359,900			444,500
Actual return on plan assets		11,700			4,100
Benefits paid		(63,900	)		(88,700	)
Fair value of plan assets at end of year		307,700			359,900
Benefit obligation in excess of plan assets		33,800			581,300
Unrecognized transition obligation		—			(157,000	)
Unrecognized prior service cost		—			(108,700	)
Unrecognized gains		105,400			27,300
Net liability recognized	$	139,200		$	342,900

	2006			2005			2004
Components of net periodic benefit cost:
Service costs	$	41,800		$	37,600		$	33,200
Interest costs		40,100			45,600			41,300
Expected return on plan assets		(29,100	)		(36,400	)		(37,500	)
Amortization of transition obligation		19,600			19,600			19,600
Amortization of unrecognized prior service costs		17,900			17,900			17,900
Additional pension expense (income) due to curtailment/settlement		(289,600	)		—			—
Actuarial gains		(4,400	)		(10,500	)		(15,200	)
Postretirement benefit expense	$	(203,700	)	$	73,800		$	59,300

During fiscal 2006, the Company discontinued the contributions to the Retiree Health Plan. Therefore the Company eliminated the $289,600 accrual for future contribution to the plan.

F-19

	2006			2005
Weighted-average assumptions as of June 30:
Discount rate		6.00	%		5.00	%
Expected return on plan assets		8.50	%		8.50	%
Health care inflation rate		9.00	%		9.50	%
	Grading to 5.5%			Grading to 5.5%

A one-percentage-point increase or decrease in the assumed health care cost trend rate would not significantly affect the APBO, service cost or interest cost.

Included in the postretirement benefit expense amounts were $74,900 in 2006, $63,553 in 2005 and $55,100 in 2004 related to regulated operations. The MPSC allows for recovery of these costs over a 20-year period beginning on November 4, 1997 for the utility operations in Montana. Management believes it is probable that its regulators in Wyoming will allow recovery of these costs based upon recent industry rate decisions addressing this issue. The plan assets are held in a VEBA trust fund.

9. Income Taxes

Significant components of our deferred tax assets and liabilities as of June 30, 2006 and 2005 are as follows:

	2006						2005
	Current			Long-Term			Current			Long-Term
Deferred tax asset:
Allowances for doubtful accounts	$	52,340		$	—		$	119,181		$	—
Unamortized investment tax credit		—			18,533			—			23,351
Contributions in aid of construction		—			539,395			—			359,936
Other nondeductible accruals		100,591			—			160,411			—
Deferred gain (loss) on sale of assets		—			—			—			9,692
Recoverable purchase gas costs		322,428			—			20,344			—
Derivatives		177,713			—			395,253			—
Deferred incentive and pension accrual		—			65,420			—			—
Other		—			326,870			5,177			437,112
Total		653,072			950,218			700,366			830,091
Deferred tax liabilities:
Recoverable purchase gas costs		912,969			—			796,118			—
Property, plant, and equipment		—			6,281,038			—			6,468,105
Debt issue costs		—			69,453			—			88,769
Deferred rate case costs		—			—			—			28,607
Covenant not to compete		—			46,616			—			50,859
Other		9,266			388,997			462			461,609
Total		922,235			6,786,104			796,580			7,097,949
Net deferred tax asset (liabilities)	$	(269,163	)	$	(5,835,886	)	$	(96,214	)	$	(6,267,858	)

F-20

Income tax expense (benefit) for the years ended June 30, 2006, 2005, and 2004 consists of the following:

	2006			2005			2004
Current income taxes:
Federal	$	1,273,148		$	(1,226,388	)	$	(453,156	)
State		142,514			(361,267	)		(104,315	)
Total current income taxes		1,415,662			(1,587,655	)		(557,471	)
Deferred income taxes:
Federal		(17,891	)		1,938,492			138,344
State		(2,003	)		423,098			71,268
Total deferred income taxes		(19,894	)		2,361,590			209,612
Total income taxes before credits		1,395,768			773,935			(347,859	)
Investment tax credit, net		(21,062	)		(21,062	)		(21,062	)
Total income tax expense (benefit)	$	1,374,706		$	752,873		$	(368,921	)

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

	2006			2005			2004
Tax expense at statutory rate of 34%	$	1,255,067		$	743,846		$	(323,834	)
State income tax, net of federal tax benefit		92,737			97,575			(41,266	)
Amortization of deferred investment tax credits		(21,062	)		(21,062	)		(21,062	)
Other		47,964			(67,486	)		17,241
Total	$	1,374,706		$	752,873		$	(368,921	)

F-21

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.

The following tables set forth summarized financial information for our Natural Gas Operations, Propane Operations, EWR, and Pipeline 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):

F-22

	Natural Gas			Propane						Pipeline
Year Ended June 30, 2006	Operations			Operations			EWR			Operations			Eliminations			Consolidated
Operating revenue:
Natural gas operations	$	56,044,531		$	—		$	—		$	—		$	(300,000	)	$	55,744,531
Propane operations		—			9,874,736									(292,136	)		9,582,600
Marketing and wholesale		—			—			32,587,643			—			(14,047,850	)		18,539,793
Pipeline operations		—			—			—			411,237			—			411,237
Total operating revenue		56,044,531			9,874,736			32,587,643			411,237			(14,639,986	)		84,278,161
Gas purchased		43,752,966			6,218,821									(592,136	)		49,379,651
Gas and electric — wholesale		—			—			31,037,504						(14,047,850	)		16,989,654
Distribution, general, and administrative		5,830,719			1,846,786			456,708			85,070			—			8,219,283
Maintenance		504,473			119,469			143			—			—			624,085
Depreciation and amortization		1,394,169			537,687			195,820			56,064			—			2,183,740
Taxes other than income		1,430,101			173,127			3,854			7,602			—			1,614,684
Operating expenses		52,912,428			8,895,890			31,694,029			148,736			(14,639,986	)		79,011,097
Operating income		3,132,103			978,846			893,614			262,501			—			5,267,064
Other income		358,213			113,665			32,464			—			—			504,342
Interest (expense)		(1,425,186	)		(435,215	)		(178,339	)		(41,290	)		—			(2,080,030	)
Income before income taxes		2,065,130			657,296			747,739			221,211						3,691,376
Income taxes (expense)		(740,624	)		(260,446	)		(288,556	)		(85,080	)		—			(1,374,706	)
Net income	$	1,324,506		$	396,850		$	459,183		$	136,131		$	—		$	2,316,670
Capital expenditures and natural gas properties	$	1,744,046		$	607,378		$	114,747		$	6,801					$	2,472,972
Total assets	$	38,877,712		$	12,354,813		$	5,269,075		$	1,044,213		$	384,932		$	57,930,745

F-23

	Natural Gas			Propane						Pipeline
Year Ended June 30, 2005	Operations			Operations			EWR			Operations			Eliminations			Consolidated
Operating revenue:
Natural gas operations	$	45,091,564		$	—		$	—		$	—		$	(300,000	)	$	44,791,564
Propane operations		—			9,056,729									(236,749	)		8,819,980
Marketing and wholesale		—			—			38,352,126			—			(15,678,744	)		22,673,382
Pipeline operations		—			—			—			424,038			—			424,038
Total operating revenue		45,091,564			9,056,729			38,352,126			424,038			(16,215,493	)		76,708,964
Gas purchased		33,095,465			5,014,125									(536,749	)		37,572,841
Gas and electric — wholesale		—			—			36,438,381			—			(15,678,744	)		20,759,637
Distribution, general, and administrative		6,242,841			2,152,870			937,314			113,542			—			9,446,567
Maintenance		518,686			77,430			196			—			—			596,312
Depreciation and amortization		1,488,353			550,452			220,845			53,588			—			2,313,238
Taxes other than income		1,416,037			188,553			14,711			34,635			—			1,653,936
Operating expenses		42,761,382			7,983,430			37,611,447			201,765			(16,215,493	)		72,342,531
Operating income		2,330,182			1,073,299			740,679			222,273			—			4,366,433
Other income		165,806			210,477			67,064			1,860			—			445,207
Interest (expense)		(1,774,989	)		(571,321	)		(274,885	)		(56,103	)		—			(2,677,298	)
Income before income taxes		720,999			712,455			532,858			168,030			—			2,134,342
Income taxes (expense)		(216,073	)		(270,652	)		(210,712	)		(55,436	)		—			(752,873	)
Net income	$	504,926		$	441,803		$	322,146		$	112,594		$	—		$	1,381,469
Capital expenditures and natural gas properties	$	1,945,601		$	613,447		$	193,881		$	42,636			—		$	2,795,565
Total assets	$	39,628,060		$	12,026,924		$	6,965,714		$	1,136,303		$	(323,608	)	$	59,433,393

F-24

	Natural Gas			Propane						Pipeline
Year Ended June 30, 2004	Operations			Operations			EWR			Operations			Eliminations			Consolidated
Operating revenue:
Natural gas operations	$	39,362,689		$	—		$	—		$	—		$	(300,000	)	$	39,062,689
Propane operations		—			7,963,609									(227,230	)		7,736,379
Marketing and wholesale		—			—			51,097,486			—			(25,006,641	)		26,090,845
Pipeline operations		—			—			—			401,269			—			401,269
Total operating revenue		39,362,689			7,963,609			51,097,486			401,269			(25,533,871	)		73,291,182
Gas purchased		28,183,288			4,227,508			—			—			(527,230	)		31,883,566
Gas and electric — wholesale		—			—			51,034,517			—			(25,006,641	)		26,027,876
Distribution, general, and administrative		6,996,914			2,165,617			860,425			146,604			—			10,169,560
Maintenance		395,572			84,514			—			—			—			480,086
Depreciation and amortization		1,538,546			547,234			213,172			33,121			—			2,332,073
Taxes other than income		911,496			241,379			22,260			34,781			—			1,209,916
Operating expenses		38,025,816			7,266,252			52,130,374			214,506			(25,533,871	)		72,103,077
Operating income (loss)		1,336,873			697,357			(1,032,888	)		186,763			—			1,188,105
Other income		96,354			180,748			(12,678	)		120,853			—			385,277
Interest (expense)		(1,622,797	)		(572,522	)		(253,601	)		(49,703	)		—			(2,498,623	)
Income (loss) before income taxes		(189,570	)		305,583			(1,299,167	)		257,913			—			(925,241	)
Income taxes benefit (expense)		26,386			(2,475	)		444,322			(99,312	)		—			368,921
Net income (loss)	$	(163,184	)	$	303,108		$	(854,845	)	$	158,601		$	—		$	(556,320	)
Capital expenditures and natural gas properties	$	1,631,549		$	515,213		$	74,634		$	95,299			—		$	2,316,695
Total assets	$	47,260,442		$	12,434,754		$	8,880,950		$	1,117,398		$	(8,248,467	)	$	61,445,077

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, 2006, there are 145,500 options outstanding and the maximum number of shares available for future grants under this plan is 54,500 shares. Additionally, our 1992 Stock Option Plan (the “1992 Option Plan”), which expired in September 2002, provided for the issuance of up to 100,000 shares of our common stock pursuant to options issuable to certain key employees. Under the 2002 Option Plan and the 1992 Option Plan (collectively, “the Option Plans”), the option price may not be less than 100% of the common stock fair market value on the date of grant (in the event of incentive stock options, 100% of the fair market value if the employee owns more than 10% of our outstanding common stock). Pursuant to the Option Plans, the options vest over four to five years and are exercisable over a five to ten-year period from date of issuance. When the 1992 Option Plan expired in September 2002, 12,600 shares remained unissued and were no longer available for issuance.

F-25

SFAS No. 123 Disclosures — Effective July 1, 2005, we have adopted the provisions of SFAS No. 123 “Accounting 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. The following assumptions were applied for the SFAS No. 123 provision information included in Note 1.

	2006			2005			2004
Expected dividend rate		2.00	%		0.00	%		0.00	%
Risk free interest rate		4.87			3.90			4.70
Weighted average expected lives, in years		3.40			4.26			3.40
Price volatility		39.00	%		54.00	%		54.00	%
Total intrinsic value of options exercised	$	4,087		$	0		$	0
Total cash received from options exercised	$	21,228		$	0		$	0

A summary of the status of our stock option plans as of June 30, 2006, 2005, and 2004, and changes during the years ended on these dates is presented below.

				Weighted		Aggregate
	Number of			Average		Intrinsic
	Shares			Exercise Price		Value
Outstanding July 1, 2003		130,420		$	8.62
Granted		—
Exercised		—
Expired		(53,420	)	$	8.82
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	$	98,325
Exerciseable June 30, 2006		84,000		$	8.12	$	75,610

F-26

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

							Weighted
							Average
					Weighted		Remaining				Weighted
					Average		Contractual				Average
Grant	Exercise		Number		Exercise		Life		Number		Exercise
Date	Price		Outstanding		Price		(Years)		Exercisable		Price
11/21/2002	$	8.49		48,500	$	8.49		1.4		48,500	$	8.49
7/1/2004	$	6.47		30,000	$	6.47		8.0		15,000	$	6.47
4/1/2005	$	6.62		20,000	$	6.62		8.8		10,000	$	6.62
7/1/2005	$	9.85		20,000	$	9.85		9.0		5,000	$	9.85
10/4/2005	$	10.51		22,000	$	10.51		9.3		5,500	$	10.51
1/6/2006	$	9.52		5,000	$	9.52		4.5		0	$	9.52
				145,500	$	8.34				84,000	$	8.12

     The weighted-average grant date fair value per stock option granted during the years ended June 30, 2006 and 2005 was $10.12 and $6.53, respectively. For the years ended June 30, 2006, 2005, and 2004, all stock options granted have an exercise price equal to the fair market value of the Company’s stock at the date of grant.

Shareholder Rights — On June 3, 2004, our Board of Directors declared a dividend of one Right to purchase one one-thousandth share of our Series A Participating Preferred Stock for each outstanding share of Common Stock of the Company. Each Right entitles the registered holder to purchase from the Company one one-thousandth of a share of Series A Participating Preferred Stock at an exercise price of $24.00, subject to adjustment (the “Purchase Price”). The Rights generally will be exercisable only if a person or group acquires beneficial ownership of 20.8% or more of our common stock or commences a tender or exchange offer upon consummation of which such person or group would beneficially own 20.8% or more of our common stock. Any person or group owning 20.8% or more of our common stock on June 3, 2004 will not cause the Rights to become exercisable unless such person or group acquires additional common stock. Once exercisable, then each holder of a Right that has not theretofore been exercised will thereafter have the right to receive, upon exercise, Common Shares having a value equal to two times the Purchase Price.

F-27

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, 2006 is as follows:

Year ending June 30:
2007	$	4,258,896
2008		4,258,896
2009		4,258,896
2010		2,839,264
2011		0
Total	$	15,615,952

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, 2006, 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, 2006, the Company had recovered approximately $1,758,000 through such surcharges. As of June 30, 2006, the cost remaining to be recovered is $335,000.

We are required to file with the MPSC every two years for approval to continue the recovery of these costs through a surcharge.

Derivative Contingencies — Among the risks involved in natural gas marketing is the risk of nonperformance by counterparties to contracts for purchase and sale of natural gas. EWR is party to certain contracts for purchase or sale of natural gas at fixed prices for fixed time periods. Some of these contracts are recorded as derivatives, valued on a mark-to-market basis.

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 years 1997-2002. The settlement amount is being paid in ten annual installments of $243,000 each,

F-28

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:
2007	$	144,624
2008		144,624
2009		60,600
2010		54,000
2011		54,000
Total	$	457,848

Lease expense resulting from operating leases for the years ended June 30, 2006, 2005, and 2004 totaled $142,599, $142,599, and $171,765, respectively.

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

Quoted market prices for natural gas derivative contracts of 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.

As of June 30, 2006, these agreements were reflected on the consolidated balance sheet as derivative assets and liabilities at an approximate fair value as follows:

F-29

	Assets		Liabilities
Contracts maturing during fiscal year 2007	$	42,494	$	42,664
Contracts maturing during fiscal years 2008 and 2009		95,371
Contracts maturing during fiscal years 2010 and beyond
Total	$	137,865	$	42,664

14. Subsequent Events

On July 17, 2006, the Company entered into an Asset Purchase Agreement among our company, EWP, and SemStream, L.P. Pursuant to the Asset Purchase Agreement, the Company and EWP agreed to sell, and SemStream agreed to buy, (i) all of the assets and business operations associated with the Company’s’ 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 that are used in conjunction with the Regulated Business, but that are not part of the Regulated Business (the “Non-Regulated Business,” and together with the Regulated Business, the “Business”).

On August 25, 2006, the Company renewed its agreement with its gas suppliers for a full requirements contract for both the commodity and services needed to supply approximately 3.2 Bcf of natural gas to the Company’s regulated gas customers in Montana and Wyoming.

On September 19, 2006, LaSalle Bank proposed terms for an extension of the existing credit facilities. However the proposal is not a commitment by the Bank and should not be relied on as such. Final approval for the credit renewal is subject to approval by the Bank’s Loan Committee.

15. Quarterly Information (Unaudited)

Quarterly results (unaudited) for the years ended June 30, 2006 and 2005 are as follows (in thousands, except per share data):

F-30

	First			Second		Third		Fourth
Year Ended June 30, 2006	Quarter			Quarter		Quarter		Quarter
Revenues	$	10,291		$	28,929	$	32,156	$	12,902
Operating income (loss)	$	(641	)	$	2,178	$	3,126	$	605
Net income (loss)	$	(622	)	$	1,117	$	1,646	$	175
Basic earnings (loss) per common share	$	(0.21	)	$	0.38	$	0.56	$	0.06
Diluted earnings (loss) per share	$	(0.21	)	$	0.38	$	0.55	$	0.06

	First			Second		Third		Fourth
Year Ended June 30, 2005	Quarter			Quarter		Quarter		Quarter
Revenues	$	11,867		$	23,116	$	27,438	$	14,116
Operating income (loss)	$	(1,182	)	$	1,536	$	4,082	$	(70	)
Net income (loss)	$	(1,122	)	$	566	$	2,186	$	(249	)
Basic earnings (loss) per common share	$	(0.43	)	$	0.22	$	0.84	$	(0.10	)
Diluted earnings (loss) per share	$	(0.43	)	$	0.22	$	0.84	$	(0.10	)

F-31

EXHIBIT INDEX

Exhibit
Number	Description
3.1	Restated Articles of Incorporation. Exhibit 3.1 to Amendment No. 1 to the Registrant’s Annual Report on Form 10-K/A for the year ended June 30, 1996, as filed on July 8, 1997, is incorporated herein by reference.
3.2	Amended and Restated Bylaws. Exhibit 3.2 to the Registrant’s Current Report on Form 8-K as filed on March 5, 2004, is incorporated herein by reference.
4.1	Form of Indenture (including form of Note) relating to the Series 1997 Notes. Exhibit 4.1 to the Registrant’s Registration Statement on Form S-2 (File No. 333-31907), is incorporated herein by reference.
4.2	Form of Indenture (including form of Note) relating to the Series 1993 Notes. Exhibit 4.1 to the Registrant’s Registration Statement on Form S-2 (File No. 33-62680), is incorporated herein by reference.
4.3	Loan Agreement, dated as of September 1, 1992, relating to the Series 1992A and Series 1992B Industrial Development Revenue Bonds. Exhibit 4.2 to the Registrant’s Registration Statement on Form S-2 (File No. 33-62680), is incorporated herein by reference.
4.4	Preferred Stock Rights Agreement, dated as of June 3, 2004, between Registrant and Computershare Trust Company, Inc., including the Terms of Series A Participating Preferred Stock, the form of Rights Certificate and the Summary of Rights attached thereto as Exhibits A, B and C, respectively. Exhibit 4.1 to the Registrant’s Registration Statement on Form 8-A as filed on June 3, 2004, is incorporated herein by reference.
10.1(a)	Amended and Restated Credit Agreement, dated March 31, 2004, by and among Registrant, its subsidiaries and LaSalle Bank National Association. Exhibit 10.1 to the Registrant’s Current Report on Form 8-K as filed on April 1, 2004, is incorporated herein by reference.
10.1(b)	Waiver and First Amendment to Credit Agreement dated as of August 30, 2004 by and among the Registrant, its subsidiaries and LaSalle. Exhibit 10.1 to the Registrant’s Current Report on Form 8-K as filed on September 3, 2004, is incorporated herein by reference.
10.1(c)	Second Amendment to Credit Agreement dated as of September 10, 2004 by and among the Registrant, its subsidiaries and LaSalle. Exhibit 10.1 to the Registrant’s Current Report on Form 8-K as filed on September 16, 2004, is incorporated herein by reference.
10.1(d)	Letter Agreement to Credit Agreement entered into on October 20, 2004, by and among the Registrant, its subsidiaries and LaSalle. Exhibit 10.1 to the Registrant’s Current Report on Form 8-K as filed on October 24, 2004, is incorporated herein by reference.
10.1(e)	Letter Agreement to Credit Agreement entered into on November 2, 2004, by and among the Registrant, its subsidiaries and LaSalle. Exhibit 10.1 to the Registrant’s Current Report on Form 8-K as filed on November 5, 2004, is incorporated herein by reference.
10.1(f)	Third Amendment to Credit Agreement dated as of November 2, 2004, by and among the Registrant, its subsidiaries and LaSalle. Exhibit 10.2 to the Registrant’s Current Report on Form 8-K as filed on November 5, 2004 is incorporated herein by reference.
10.1(g)	Fourth Amendment to Credit Agreement dated as of November 30, 2004, by and among the Registrant, its subsidiaries and LaSalle. Exhibit 10.1 to the Registrant’s Current Report on Form 8-K as filed on December 6, 2004, is incorporated herein by reference.

10.1(h)	Fifth Amended and Restated Credit Agreement dated December 14, 2005, by and among the Registrant, its subsidiaries, and LaSalle Bank National Association. Exhibit 10.1 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended December 31, 2005, 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 on Form S-1 (File No. 33-1672), is incorporated herein by reference.
10.4*	Management Incentive Plan. Exhibit 10.12 to the Registrant’s Annual Report on Form 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 on Form 10-K for the year ended June 30, 2002, as filed on September 30, 2002, is incorporated herein by reference.
10.6*	Energy West Incorporated Deferred Compensation Plan for Directors. Exhibit 10.20 to the Registrant’s Annual Report on Form 10-K for the year ended June 30, 2002, as filed on September 30, 2002, is incorporated herein by reference.
10.7*	Amended and Restated Advisory Agreement, dated October 3, 2003, by and among Energy West, Incorporated, D.A. Davidson & Co. and DAMG Capital LLC. Exhibit 10.11 to the Registrant’s Annual Report on Form 10-K for the year ended June 30, 2003, as filed on October 9, 2003, is incorporated herein by reference.
10.8*	Letter Agreement dated June 5, 2003 between DAMG Capital LLC and the Company. Exhibit 10.12 to the Registrant’s Annual Report on Form 10-K for the year ended June 30, 2003, as filed on October 9, 2003, is incorporated herein by reference.
10.9*	Letter Agreement dated June 5, 2003 between D.A. Davidson & Co. and the Company. Exhibit 10.13 to the Registrant’s Annual Report on Form 10-K for the year ended June 30, 2003, as filed on October 9, 2003, is incorporated herein by reference.
10.10*	Agreement dated November 20, 2003 between and among J. Michael Gorman, Lawrence P. Haren, Richard M. Osborne, Thomas J. Smith, Turkey Vulture Fund XIII, Ltd., an Ohio limited liability company and, Energy West, Incorporated. Exhibit 10.1 to the Registrant’s Current Report on Form 8-K as filed on November 21, 2003, is incorporated herein by reference.
10.11*	Separation Agreement, Release and Waiver of Claims between Energy West, Incorporated and Edward J. Bernica dated October 24, 2003. Exhibit 10.1 to the Registrant’s Current Report on Form 8-K as filed on October 27, 2003, is incorporated herein by reference.
10.12*	Employment Agreement entered into as of June 23, 2004, between the Company and David Cerotzke. Exhibit 10.16 to the Registrant’s Annual Report on Form 10-K for the year ended June 30, 2004, as filed on December 17, 2004, is incorporated herein by reference.
10.13*	Employment Agreement entered into as of June 23, 2004, between the Company and John Allen. Exhibit 10.17 to the Registrant’s Annual Report on Form 10-K for the year ended June 30, 2004, as filed on December 17, 2004, is incorporated herein by reference.
10.14*	Form of the agreement used to grant options under the 2002 Stock Option Plan. Exhibit 10.17 to the Registrant’s Annual Report on Form 10-K for the year ended June 30, 2005, as filed on September 27, 2005, is incorporated herein by reference.
10.15	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 on Form 10-K for the year ended June 30, 2005, as filed on September 27, 2005, is incorporated herein by reference.

10.16*	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 on Form 10-Q for the quarter ended March 31, 2006, is incorporated herein by reference.
21**	Company Subsidiaries
23.1**	Consent of Hein & Associates LLP
23.2**	Consent of Deloitte & Touche LLP
31**	Certifications pursuant to SEC Release No. 33-8238, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32**	Certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

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

EX-21

Exhibit 21

List of Subsidiaries

Energy West Resources, Inc., a Montana corporation
Energy West Propane, Inc., a Montana corporation
Energy West Development, Inc., a Montana corporation

EX-23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors
Energy West, Incorporated

We consent to the incorporation by reference in the registration statement of Energy West, Incorporated on Form S-8 (File No. 333-123341) filed on March 16, 2005 of our report dated September 21, 2006 relating to our audit of the consolidated financial statement, which report appears in Energy West, Incorporated’s Annual Report on Form 10-K for the year ended June 30, 2006.

/s/ HEIN & ASSOCIATES LLP

Denver, Colorado
September 26, 2006

EX-23.2

Exhibit 23.2

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statement No. 333-123341 on Form S-8 of our report dated December 16, 2004, relating to the consolidated financial statements and financial statement schedule of Energy West, Incorporated and subsidiaries for the year ended June 30, 2004, appearing in this Annual Report on Form 10-K of Energy West, Incorporated and subsidiaries for the year ended June 30, 2006.

/s/ DELOITTE & TOUCHE LLP

Salt Lake City, Utah
September 28, 2006

EX-31

Exhibit 31

CERTIFICATION PURSUANT TO SECTION 302 OF SARBANES-OXLEY

I, David A. Cerotzke, certify that:

1. I have reviewed this Annual Report on Form 10-K of Energy West, Incorporated;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:

     a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

     b. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

     c. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

     a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

     b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: September 28, 2006

/s/ David A. Cerotzke

David A. Cerotzke

President and Chief Executive Officer

(principal executive officer)

Exhibit 31

CERTIFICATION PURSUANT TO SECTION 302 OF SARBANES-OXLEY

I, Wade F. Brooksby, certify that:

1. I have reviewed this Annual Report on Form 10-K of Energy West, Incorporated;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:

     a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

     b. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

     c. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

     a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

     b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: September 28, 2006

/s/ Wade F. Brooksby

Wade F. Brooksby

Chief Financial Officer

(principal financial officer and principal accounting officer)

EX-32

Exhibit 32

CERTIFICATIONS OF THE
PRINCIPAL EXECUTIVE OFFICER AND PRINCIPAL FINANCIAL OFFICER
PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

          In connection with the Annual Report of Energy West, Incorporated (the “Company”) on Form 10-K for the year ended June 30, 2006 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, David A. Cerotzke, President and Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that:

     (1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

     (2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: September 28, 2006	/s/ David A. Cerotzke
	David A. Cerotzke
	President and Chief Executive Officer
	(Principal Executive Officer)

          In connection with the Annual Report of Energy West, Incorporated (the “Company”) on Form 10-K for the year ended June 30, 2006 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Wade F. Brooksby, Principal Financial Officer of the Company, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that:

     (1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

     (2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: September 28, 2006	/s/ Wade F. Brooksby
	Wade F. Brooksby
	Principal Financial Officer
	(Principal Financial Officer and Principal Accounting Officer)