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

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

or

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

For the transition period from 07/01/08 to 12/31/08

Commission File number 0-14183

ENERGY WEST, INCORPORATED

(Exact name of registrant as specified in its charter)

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

1 First Avenue South, Great Falls, Montana 59401
(Address of principal executive offices) (Zip Code)

Registrant’s telephone number, including area code (406) 791-7500

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, a non-accelerated filer, or a smaller reporting company. See definition of “accelerated filer”, “large accelerated filer”, and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer o Accelerated filer o Non-accelerated filer o Smaller reporting company 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, 2008 was $25,293,153.

The number of shares outstanding of the registrant’s common stock as of February 28, 2009 was 4,352,245 shares.

As used in this Form 10-K/T, the terms “Company,” “Energy West,” “Registrant,” “we,” “us” and “our” mean Energy West, Incorporated and its consolidated subsidiaries as a whole, unless the context indicates otherwise. Except as otherwise stated, the information is this Form 10-K is as of December 31, 2008.

TABLE OF CONTENTS

	Page
Part I		1
Item 1. Business		1
Item 1A. Risk Factors		15
Item 2. Properties		23
Item 3. Legal Proceedings		23
Item 4. Submission of Matters to a Vote of Security Holders		24
Part II		25
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		25
Item 6. Selected Financial Data		28
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations		32
Item 7A. Quantitative and Qualitative Disclosures About Market Risk		51
Item 8. Financial Statements and Supplementary Data		51
Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure		51
Item 9T. Controls and Procedures		52
Item 9B. Other Information		53
Part III		53
Item 10. Directors, Executive Officers and Corporate Governance		53
Item 11. Executive Compensation		56
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		59
Item 13. Certain Relationships and Related Transactions and Director Independence		60
Item 14. Principal Accountant Fees and Services		62
Part IV		62
Item 15. Exhibits and Financial Statement Schedules		62
Signatures		67
Exhibit 10.8
Exhibit 10.13
Exhibit 10.27
Exhibit 10.39
Exhibit 10.40
Exhibit 21
Exhibit 23.1
Exhibit 31
Exhibit 32

Forward-Looking Statements

This Form 10-K contains forward-looking statements within the meaning of the federal securities laws. Statements that are not historical facts, including statements about our beliefs and expectations, are forward-looking statements. Forward-looking statements include statements preceded by, followed by or that include the words “may,” “could,” “would,” “should,” “believe,” “expect,” “anticipate,” “plan,” “estimate,” “target,” “project,” “intend,” or similar expressions. These statements include, among others, statements regarding our current expectations, estimates and projections about future events and financial trends affecting the financial condition and operations of our business. Forward-looking statements are only predictions and not guarantees of performance and speak only as of the date they are made. We undertake no obligation to update any forward-looking statement in light of new information or future events.

i

Although we believe that the expectations, estimates and projections reflected in the forward-looking statements are based on reasonable assumptions when they are made, we can give no assurance that these expectations, estimates and projections can be achieved. We believe the forward-looking statements in this Form 10-K are reasonable; however, you should not place undue reliance on any forward-looking statement, as they are based on current expectations. Future events and actual results may differ materially from those discussed in the forward-looking statements. Factors that could cause actual results to differ materially from our expectations include, but are not limited to:

• fluctuating energy commodity prices,

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

• the impact of the Federal Energy Regulatory Commission (FERC) and state public service commission statutes, regulations, and actions, including allowed rates of return, and the resolution of other regulatory matters,

• the impact of weather conditions and alternative energy sources on our sales volumes,

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

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

• 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,

• our ability to maintain effective internal controls in accordance with Section 404 of the Sarbanes-Oxley Act of 2002,

• our ability to obtain governmental and regulatory approval of various expansion or other projects, including acquisitions and a holding company structure.

ii

PART I

Item 1. Business.

Change in Fiscal Year

The Board of Directors of Energy West, Incorporated changed its fiscal year end from June 30 to December 31. We made this change to align our fiscal year end with other companies within our industry. This Form 10-K/ T is intended to cover the transition report for the period July 1, 2008 through December 31, 2008 (the “transition period”). Subsequent to this, our Form 10-K will cover the calendar year January 1 to December 31. We refer to the period beginning July 1, 2007 and ending June 30, 2008 as “fiscal 2008”, the period beginning July 1, 2006 and ending June 30, 2007 as “fiscal 2007” and the period beginning July 1, 2005 and ending June 30, 2006 as “fiscal 2006”.

Overview

We are a natural gas utility with operations in Montana, Wyoming, North Carolina and Maine. We were originally incorporated in Montana in 1909. We currently have five reporting segments:

•     Natural Gas Operations	Annually, we distribute approximately 26 billion cubic feet of natural gas to approximately 37,000 customers through regulated utilities operating in and around Great Falls and West Yellowstone, Montana, Cody, Wyoming, Bangor, Maine and Elkin, North Carolina. The approximate population of the service territories is 177,000. The operation in Elkin, North Carolina was added October 1, 2007. The operation in Bangor, Maine was added December 1, 2007.
•     Marketing and Production Operations (EWR)	Annually, we market approximately 2.3 billion cubic feet of natural gas to commercial and industrial customers in Montana and Wyoming and manage midstream supply and production assets for transportation customers and utilities through our subsidiary, Energy West Resources, Inc. (EWR). EWR owns an average 60% gross working interest (an average 51% net revenue interest) in 160 natural gas producing wells and gas gathering assets. Energy West Propane, Inc. dba Missouri River Propane (MRP), our small Montana wholesale distribution company that sells propane to our affiliated utility, had been reported in our propane operations. It is now being reported in marketing and production operations.
•     Pipeline Operations (EWD)	We own the Shoshone interstate and the Glacier gathering natural gas pipelines located in Montana and Wyoming through our subsidiary Energy West Development, Inc. (EWD). Certain natural gas producing wells owned by our pipeline operations are being managed and reported under our marketing and production operations.
•     Propane Operations (Discontinued Operations)	Our Arizona assets were sold during fiscal year 2007, and the results of operations for the propane assets related to this sale have been reclassified as income from discontinued operations. Prior to discontinuance, we distributed approximately 5.4 million gallons annually, 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 associated assets and liabilities are shown on the consolidated balance sheet as “Assets held for sale” and “Liabilities held for sale.” MRP, our small Montana wholesale distribution company that sells propane to our affiliated utility, had been reported in propane operations. It is now being reported in our marketing and production operations.
•     Corporate and Other	This segment was not reported prior to fiscal 2008. Corporate and other was established to encompass the results of corporate acquisitions and other equity transactions. Reported in Corporate and other for the six months ended December 31, 2008 are costs associated with business development and acquisitions, and dividend income from marketable securities.

See Note 14 to our Consolidated Financial Statements for financial information for each of our segments.

1

Recent Acquisitions and Future Acquisition Strategy

As a result of our success in strengthening our core business, we are now able to focus on our growth strategy which includes the acquisition and expansion of our natural gas utility operations in small and emerging markets. We regularly evaluate gas utilities of varying sizes for potential acquisition. Our acquisition strategy includes identifying geographic areas that have low market saturation rates in terms of natural gas utilization as a result of historical reliance by customers on alternative fuels such as heating oil. We believe that significant acquisitions in Montana and Wyoming are unlikely because of market saturation levels in excess of 90%. However, we intend to look for smaller acquisitions in Montana and Wyoming that are complementary to our existing business. We believe the following transactions exemplify this acquisition strategy.

We determined that due to a historical reliance on propane and heating oil, large segments of the North Carolina and Maine markets remain highly unsaturated with penetration rates as low as 1% in some of these areas. For instance, according to the American Gas Association, the national average for natural gas saturation in the residential heating market was approximately 51% in 2005, whereas large segments of the Maine market remain unsaturated, with penetration rates of less than 3%. We believe these low penetration rates are partially the result of these geographic areas being overlooked by other gas distributors in light of this historical reliance on other energy sources and that the high market price of oil over the past several years presents an opportunity for gas distributors to capture a larger share of the energy market in these states.

In 2006 we began investigating potential acquisitions in North Carolina and Maine. On January 30, 2007, we entered stock purchase agreements with Sempra Energy, a California corporation, for the purchase of natural gas distribution companies in each of these states. On October 1, 2007, we consummated the acquisition of Frontier Natural Gas, which operates a natural gas utility in Elkin, North Carolina. The purchase price was $4.9 million in cash. On December 1, 2007, we acquired Bangor Gas Company, a natural gas utility in Bangor, Maine for a purchase price of $434,000.

Frontier Natural Gas and Bangor Gas Company provided us with a unique opportunity to gain market shares within these service areas since their distribution systems are relatively new and have considerable incremental capacity available to sustain a greater customer load. The acquisitions of Frontier Natural Gas and Bangor Gas Company provide us with substantial new assets and potential customers in those service areas, including 148 miles of transmission pipeline and 237 miles of distribution system.

We intend to continue to look for natural gas utilities to acquire. While we believe that the best opportunities for growth remain outside Montana and Wyoming, there may be acquisitions in these states that would be attractive to us because of economies of scale. For more information, see “Pending Acquisitions” on page 3.

2

Even though we are a small utility serving approximately 37,000 customers, we believe we have the operating expertise to handle a significantly greater number of customers. For example, several operational managers have joined our team who had natural gas utility experience with significantly larger companies. We intend to focus on acquisitions that will enable us to grow our customer base and fully utilize our personnel. We believe that there are opportunities to acquire financially-sound smaller natural gas utility companies that are individually owned or controlled. In addition, we intend to target larger diversified utility companies that have a natural gas distribution operating segment that they are willing to sell.

Our acquisition strategy includes combining newly acquired operations with our current operations to maximize efficiency and profitability. Upon acquiring a distribution company, management intends to centralize functions (i.e. accounting) or decentralize functions (i.e. gas marketing), as appropriate. We believe that throughout the utility industry, there has recently been too much centralization, which has led to local operating inefficiencies. Management will evaluate each acquisition and determine the right balance of centralization and decentralization. We believe our senior management’s gas utility experience and expertise will improve the acquired company’s operating efficiency and gas marketing capabilities, and as a result, its profitability.

We may acquire natural gas utilities that have related non-regulated operations such as gathering, storage and marketing operations. Although these non-regulated operations are not the focus of our acquisition strategy, we will not disregard a potential target because of these operations. Rather, upon consummation of the acquisition, we will evaluate the non-regulated operations to determine whether these operations could be complementary to our core business or whether they should be divested.

Finally, even though we intend to further grow the company, we believe it was our focus on efficiently operating our existing businesses and managing our capital investments that put us in the position to pursue acquisitions. Therefore, we intend to continue to focus on efficient and effective management while implementing our acquisition strategy. This continued focus will include:

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

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

• continuous improvement of our operational efficiencies, and

• maintenance and improvement of our positive reputation with our regulators and customers.

Pending Acquisitions

As previously disclosed, on September 12, 2008, we entered into a stock purchase agreement with Richard M. Osborne, Trustee, Rebecca Howell, Stephen G. Rigo, Marty Whelan and Thomas J. Smith (collectively, the Sellers) whereby we agreed to purchase all of the common stock of Lightning Pipeline Co. (Lightning Pipeline), Great Plains Natural Gas Company (Great Plains), Brainard Gas Corp. (Brainard) and all of the membership units of Great Plains Land Development Co., Ltd. (GPL), which companies are primarily owned by an entity controlled by Mr. Osborne and wholly-owned by the Sellers, for a purchase price of $34.3 million. Pursuant to the agreement, we will acquire Orwell Natural Gas Company (Orwell), a wholly-owned subsidiary of Lightening Pipeline and Northeast Ohio Natural Gas Corp. (NEO), a wholly-owned subsidiary of Great Plains. Orwell, NEO and Brainard are natural gas distribution companies that serve approximately 21,000 customers in Northeastern Ohio and Western Pennsylvania. This acquisition will increase our customers by more than 50%.

Mr. Osborne is chairman, chief executive officer and a director, Mr. Smith is vice president, chief financial officer and a director, and Ms. Howell is secretary of Energy West.

The $34.3 million purchase price consists of our assumption of approximately $20.9 million in debt with the remainder of the purchase price to be paid in unregistered shares of common stock of Energy West based on a price of $10.00 per share. The stock portion of the purchase price may be increased or decreased within three business days prior to closing of the transaction depending on the number of active customers of Orwell, Brainard and NEO. The Sellers have the right to elect to terminate the transaction, upon the payment of a $100,000 fee, if the average closing price of our common stock for the twenty consecutive trading days ending seven calendar days prior to closing is below $9.49 and if our common stock underperforms the American Gas Stock Index (as maintained by the American Gas Association) by more than 20%, as described in the agreement. However, we may prevent termination of the transaction in this instance by increasing the number of shares of our common stock paid to the Sellers as part of the purchase price. The agreement also contains customary representations, warranties, covenants and indemnification provisions.

3

The transaction is expected to close in the second half of 2009 but there can be no assurances that the transaction will be completed on the proposed terms or at all. The closing is subject to customary closing conditions, including the approval of applicable regulators. In addition, the transaction is subject to the approval of our shareholders for the issuance of shares of Energy West as part of the purchase price.

On December 18, 2007, we entered into a stock purchase agreement with certain shareholders of Cut Bank Gas Company, a natural gas utility serving Cut Bank, Montana, to acquire 83.16% of the outstanding shares of Cut Bank Gas for a purchase price of $500,000 paid in shares of common stock of Energy West. In addition, we will offer to purchase the remaining shares of Cut Bank Gas Company for a purchase price of $100,000 paid in shares of common stock of Energy West. The acquisition is subject to the approval of the MPSC and is expected to be completed in the second half of 2009. The acquisition is scheduled to close on the last business day of the month after all closing conditions have been satisfied, including MPSC approval, as the case may be. However, there can be no assurances the acquisition will be closed in this time frame, or at all.

New Holding Company Structure

We filed applications with the Montana Public Service Commission (MPSC) and the Wyoming Public Service Commission (WPSC) to reorganize our operations into a holding company structure. We have received approval from the WPSC and expect a response from the MPSC in the next few months. We believe that a holding company structure will provide us the flexibility to make future acquisitions through subsidiaries of the holding company rather than Energy West or our subsidiaries.

If the reorganization is approved, Energy West would become a holding company that would indirectly conduct the businesses of all of our operating subsidiaries and our operating subsidiaries would become wholly-owned subsidiaries of Energy West. In addition, the number of shares of common stock of the holding company outstanding immediately after the merger would be equal to the number of shares of common stock of Energy West outstanding prior to the merger. After the merger, each shareholder of common stock of Energy West would own a corresponding percentage of shares of common stock of the holding company with identical designations, preferences, limitations, and rights.

Recent Industry Trends

Since 2000, domestic energy markets have experienced significant price increases and decreases, and price volatility. Natural gas markets have been particularly volatile, principally due to weather and concerns over supply. Rising natural gas prices have resulted in a surge in supply-related investment that we believe has stabilized domestic production. Increasing supplies and price-induced conservation have favorably impacted natural gas prices and we believe this trend is likely to continue. Given the current environment, we expect that natural gas will maintain a favorable competitive position compared to other fossil fuels which have also experienced significant price increases. We believe that conditions are favorable for consumers to convert to natural gas from more expensive fossil fuels even if the cost of conversion includes equipment purchases. In addition, given natural gas’ clean burning attributes, we believe environmental regulations may enhance this competitive outlook.

Natural Gas Operations

Our natural gas operations are located in Montana, Wyoming, North Carolina and Maine and our revenues from the natural gas operations are generated under tariffs regulated by those states.

In many states, including Montana, Wyoming and North Carolina, the tariff rates of natural gas utilities are generally established to allow the utility to earn revenue sufficient to recover operating and maintenance costs, plus profits in amounts equal to a reasonable rate of return on their “rate base.” A gas utility’s rate base generally includes the utility’s original cost, cost of inventory and an allowance for working capital, less accumulated depreciation of installed used and useful gas pipeline and other gas distribution or transmission facilities. In Maine, our tariff rates and permitted rate of return are not based upon the concept of rate base, but are based upon historical costs of alternative fuels so that we may compete with distributors of such fuels, and if we exceed a given rate of return, excess earnings are shared with our gas customers.

4

Natural Gas — Montana

Our operations in Montana provide 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 operation’s service area has a population of approximately 59,000 in the Great Falls area, 1,400 in the West Yellowstone area, and approximately 1,500 in the Cascade area. Our Montana operations provide service to approximately 29,000 customers.

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

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

The following table shows our Montana operations’ revenues by customer class for the six months ended December 31, 2008 and 2007 and the three preceding fiscal years:

Gas Revenue
(in thousands)

	6 months ended				Years Ended
	December 31,				June 30,
	2008		2007		2008		2007		2006
Residential	$	9,704	$	7,801	$	21,692	$	19,492	$	21,863
Commercial		5,896		4,895		13,923		12,894		14,233
Transportation		1,011		1,008		2,337		2,058		1,961
Total	$	16,611	$	13,704	$	37,952	$	34,444	$	38,057

Residential revenue has been restated from prior published reports to properly reflect intercompany eliminations. The changes for the years ended June 30, 2008, 2007 and 2006 are ($451), ($205), and ($292) respectively.

Note: Higher revenues in the six months ended December 31, 2008 compared to the six months ended December 31, 2007 are due to higher gas costs which are passed on to the customers in accordance with approvals from the MPSC, and higher sales volumes.

5

The following table shows the volumes of natural gas, expressed in millions of cubic feet, or “MMcf,” sold or transported by our Montana operations for the six months ended December 31, 2008 and 2007 and the three preceding fiscal years:

Gas Volumes
(in MMcf)

	6 months ended				Years Ended
	December 31,				June 30,
	2008		2007		2008		2007		2006
Residential		891		841		2,212		2,097		1,978
Commercial		478		476		1,336		1,267		1,210
Transportation		742		749		1,652		1,526		1,524
Total Gas Sales		2,111		2,066		5,200		4,890		4,712

Note: Volumes were higher for the six months ended December 31, 2008 compared to the six months ended December 31, 2007 primarily due to colder weather.

The MPSC allows customers to choose a natural gas supplier other than our Montana operations. We provide gas transportation services to customers who purchase from other suppliers.

Our Montana operations use the Northwestern Energy (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 our Montana operations.

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

Natural Gas — Wyoming

Our operations in Wyoming provide natural gas service to customers in and around Cody, Meeteetse, and Ralston, Wyoming. This service area has a population of approximately 14,000. Our marketing and production operations supply natural gas to our Wyoming operations pursuant to an agreement through October 2010.

Our operations in Wyoming have a certificate of public convenience and necessity granted by the 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 December 31, 2008, our Wyoming operations provided service to approximately 6,300 customers, including one large industrial customer. Our Wyoming operations also offer 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 our Wyoming operations’ distribution and transmission system.

6

The following table shows our Wyoming operations’ revenues by customer class for the six months ended December 31, 2008 and 2007 and the three preceding fiscal years:

Gas Revenue
(in thousands)

	6 months ended				Years Ended
	December 31,				June 30,
	2008		2007		2008		2007		2006
Residential	$	2,227	$	1,996	$	4,982	$	4,657	$	5,883
Commercial		2,239		1,944		4,438		2,990		5,771
Industrial		914		862		2,008		4,348		5,741
Total	$	5,380	$	4,802	$	11,428	$	11,995	$	17,395

Note: Higher revenues were realized in the six months ended December 31, 2008 compared to the six months ended December 31, 2007, due primarily to higher gas costs which are passed on to the customers in accordance with approvals from the WPSC, and slightly higher sales volumes.

The following table shows volumes of natural gas, expressed in MMcf, sold by our Wyoming operations for the six months ended December 31, 2008 and 2007 and the three preceding fiscal years:

Gas Volumes
(in MMcf)

	6 months ended				Years Ended
	December 31,				June 30,
	2008		2007		2008		2007		2006
Residential		230		219		567		526		478
Commercial		286		271		613		593		567
Transportation		138		146		334		472		684
Total Gas Sales		654		636		1,514		1,591		1,729

Our Wyoming operations generate their revenues under tariffs regulated by the WPSC. The tariffs are structured to enable us to recover a base cost of gas and administrative and operating expenses to provide a sufficient rate of return to cover interest and profit. Our rate of return is subject to annual review by the WPSC. Our Wyoming operations’ tariffs include a purchased gas adjustment clause, which allows our Wyoming operations to adjust rates periodically to recover changes in gas costs.

Our Wyoming operations have 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 17.0% of the revenues of our Wyoming operations and approximately 3.2% 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 its market areas.

Our Wyoming operations transport 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 (mcf)) are approved by the WPSC.

7

Natural Gas — North Carolina

On October 1, 2007, we acquired Frontier Natural Gas, a natural gas utility in Elkin, North Carolina. The purchase price was $4.9 million in cash. Our North Carolina operations provide natural gas service to customers in Ashe, Surry, Warren, Wilkes, Watauga, and Yadkin Counties. This service area has a population of approximately 41,000 people. The major communities in our North Carolina service area are Boone, Elkin, Mount Airy, Wilkesboro, Warrenton and Yadkinville. We have certificates of public convenience and necessity granted by the North Carolina Utility Commission (NCUC) for transportation and distribution in these counties and franchise agreements with municipalities located within these counties.

Our North Carolina operations provide service to approximately 831 residential, commercial and transportation customers through 138 miles of transmission pipeline and 170 miles of distribution system. We offer transportation services to 21 customers through special pricing contracts. For the six months ended December 31, 2008, these customers have accounted for approximately 37.5% of the revenues of our North Carolina operation.

The following table shows our North Carolina operations’ revenues by customer class for the six months ended December 31, 2008 and 2007, and the fiscal year ended June 30, 2008:

Gas Revenue
(in thousands)

	6 months ended				Year Ended
	December 31,				June 30,
	2008		2007		2008
Residential	$	145	$	90	$	258
Commercial		1,764		651		2,171
Transportation		1,870		869		2,631
Total	$	3,779	$	1,610	$	5,060

Note: The six months ended December 31, 2007 includes three months of Frontier operations and the fiscal year ended June 30, 2008 includes nine months of operations.

The following table shows volumes of natural gas, expressed in MMcf, sold by our North Carolina operations for the six months ended December 31, 2008 and 2007, and the fiscal year ended June 30, 2008:

Gas Volumes
(in MMcf)

	6 months ended				Year Ended
	December 31,				June 30,
	2008		2007		2008
Residential		8		6		18
Commercial		107		49		162
Transportation		840		506		1,533
Total Gas Sales		955		561		1,713

Note: The six months ended December 31, 2007 includes three months of Frontier operations and the fiscal year ended June 30, 2008 includes nine months of operations.

Our North Carolina operations generate revenues under tariffs regulated by the NCUC. The tariffs are structured to enable us to recover a base cost of gas and administrative and operating expenses to provide a sufficient rate of return. In connection with our acquisition of Frontier Natural Gas, Energy West and NCUC agreed to extend the rate plan in place at the time of the acquisition for a period of five years. Accordingly, the staff of the NCUC will not seek to reduce our rates during that period, and we cannot seek a rate increase in North Carolina during that time absent extraordinary circumstances. The North Carolina regulatory framework, however, incorporates a purchased-gas commodity cost adjustment mechanism that allows Frontier to adjust rates periodically to recover changes in its wholesale gas costs.

8

Natural Gas — Maine

On December 1, 2007 we acquired Bangor Gas Company, a natural gas utility in Bangor, Maine, for a purchase price of $434,000. Our operations in Maine provide natural gas service to customers in Bangor, Brewer, Old Town, Orono and Veazie through 10 miles of transmission pipeline and 93 miles of distribution system. This service area has a population of approximately 60,000 people. We have certificates of public convenience and necessity granted by the Maine Public Utilities Commission (MPUC) for our Maine service territories.

Our Maine operations provide service to approximately 845 residential, commercial and industrial customers. We offer transportation services to 31 customers through special pricing contracts. These customers accounted for approximately 40.6% of the revenues of our Maine operations for the six months ended December 31, 2008.

The following table shows our Maine operations’ revenues by customer class for the six months ended December 31, 2008 and 2007, and the fiscal year ended June 30, 2008:

Gas Revenue
(in thousands)

	6 months ended				Year Ended
	December 31,				June 30,
	2008		2007		2008
Residential	$	187	$	55	$	232
Commercial		1,636		713		3,218
Transportation		672		138		778
Bucksport		575		96		671
Total	$	3,070	$	1,002	$	4,899

Note: The six months ended December 31, 2007 includes one month of Maine operations and the fiscal year ended June 30, 2008 includes seven months of operations.

The following table shows volumes of natural gas, expressed in MMcf, sold by our Maine operations for the six months ended December 31, 2008 and 2007, and the fiscal year ended June 30, 2008:

Gas Volumes
(in MMcf)

	6 months ended				Year Ended
	December 31,				June 30,
	2008		2007		2008
Residential		13		3		16
Commercial		134		47		221
Transportation		400		81		532
Bucksport		6,811		1,158		8,131
Total Gas Sales		7,358		1,289		8,900

Note: The six months ended December 31, 2007 includes one month of Maine operations and the fiscal year ended June 30, 2008 includes seven months of operations.

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Our Maine operations generate revenues under tariffs regulated by the MPUC, and as in other states, our tariffs are generally structured to enable us to realize a sufficient rate of return on investment. However, our tariffs and permitted return are not based upon a “rate base” as in other states, but on an alternative framework. Because heating oil and other alternative fuels are historically prevalent in Maine and because Bangor Gas Company entered the market in 1999 with few customers and sizeable start-up costs, the MPUC established a rate plan for Bangor Gas Company that was based upon the costs of distribution of alternative fuels. The goal of this alternative framework was to allow Bangor Gas Company to compete as a start-up gas utility with distributors of alternative fuels.

Accordingly, our rates include transportation charges and customer charges, but our rates may not exceed certain thresholds established in relation to rates for alternative fuels with which we compete. Additionally, if our cumulative profits exceed certain levels, we are then subject to a revenue sharing mechanism. Under the management of Sempra Energy prior to our acquisition in December 2007, Bangor Gas Company never exceeded that cumulative profit level; thus the revenue sharing mechanism was never triggered.

Our Maine tariffs also include a purchased gas adjustment clause, which allows our operation to adjust rates periodically to recover changes in gas costs. We are also able to negotiate individual special contracts with transportation customers. In connection with our acquisition of Bangor Gas Company, the MPUC extended the ten-year rate plan that had been established in 1999 for Bangor Gas Company for an additional three years. Accordingly, we cannot seek a new rate plan in Maine until late 2012. However, our current rate plan allows for certain periodic increases and adjustments to our tariffs.

Marketing and Production Operations

We market approximately 2.3 bcf of natural gas annually to commercial and industrial customers in Montana and Wyoming and manage midstream supply and production assets for transportation customers and utilities through our subsidiary, EWR. In order to provide a stable source of natural gas for a portion of its requirements, EWR has an ownership interest in two natural gas production properties and three gathering systems, located in north central Montana. EWR currently holds an average 60% gross working interest (average 51% net revenue interest) in 160 natural gas producing wells in operation. This production gives EWR a partial natural hedge when market prices of natural gas are greater than the cost of production. The gas production from these wells and assets provided approximately 16.7% of the volume requirements for EWR in our Montana market for the six months ended December 31, 2008. We acquired our interests in the wells by quitclaim deeds conveying interests in certain oil and gas leases for the wells from sellers who were in financial distress. We chose to purchase their interests despite the uncertain nature of the conveyance because we were able to negotiate purchase prices that, we believe, were fair and reasonable under, and accounted for, that circumstance. It is possible that our interests will be challenged in the future, but no such challenge has been made since acquiring the interests in 2002 and 2003 and we have no notice that such a challenge is forthcoming.

Additionally, EWR acquired a 19.8% ownership interest in Kykuit, a developer and operator of oil, gas and mineral leasehold estates located in Montana. We have invested a total of approximately $1.1 million in Kykuit and may invest additional funds in the future as Kykuit provides a supply of natural gas in close proximity to our natural gas operations in Montana. However, our obligations to make additional investments in Kykuit are limited under the Kykuit operating agreement. We are entitled to cease further investments in Kykuit if, in our reasonable discretion after the results of certain initial exploration activities are known, we deem the venture unworthy of further investments. Even if the venture is reasonably successful, we are obligated to invest no more than an additional $1.9 million over the life of the venture. Other investors in Kykuit include our chairman of the board, Richard M. Osborne, another board member, Steven A. Calabrese, and John D. Oil and Gas Company, a publicly held gas exploration company, which is also the managing member of Kykuit. Also, Mr. Osborne is the chairman of the board and chief executive officer, and our directors Mr. Grossi, Mr. Smail, Mr. Smith and Mr. Calabrese are also directors of John D. Oil and Gas Company.

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In furtherance of management’s focus on our core business of natural gas distribution, in fiscal 2003, our marketing and production operations exited the electricity marketing business by not renewing its electric contracts as they expired. As a result, during fiscal 2008 and 2007, we had only one remaining electric contract with a margin of $5,300 and $48,000, respectively, in each of those two years. The electricity operations are reported within continuing operations because we use the same employees with the same overhead as our marketing and production operations.

Pipeline Operations

We operate two natural gas pipelines, the “Glacier” natural gas gathering pipeline placed in service in July 2002 and the “Shoshone” transmission pipeline placed in service in March 2003. The pipelines extend from the north of Cody, Wyoming to Warren, Montana. The Shoshone pipeline is approximately 30 miles in length, is a bidirectional pipeline that transports natural gas between Montana and Wyoming. This enables us to sell natural gas to customers in Wyoming and Montana through our EWR subsidiary and gives EWR access to the AECO and CIG natural gas price indices. The Glacier gathering pipeline is approximately 40 miles in length and enables us to transport production gas for processing. We believe that our pipeline operations represent an opportunity to increase our profitability over time by taking advantage of summer/winter pricing differentials as well as Alberta Energy Company Limited and Colorado Interstate Gas natural gas index differentials and to continue transporting more production gas to market. We currently are seeking ways in which we can maximize our pipeline operations by increasing the capacity and throughput of our existing pipeline assets.

Propane Operations — (Discontinued Operations)

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

The propane industry had become increasingly consolidated and operators with access to supply on a national scale have an advantage over smaller propane distributors. Therefore, in April 2007 we sold our propane operations in Arizona. We used the proceeds from this sale to reduce our outstanding debt and strengthen our balance sheet. Our propane operations are disclosed as discontinued operations in this Form 10-K. The small Montana wholesale distribution of propane to our affiliated utility, MRP, that had been reported in our propane operations is now reported in our marketing and production operation.

Corporate and Other

Our “Corporate and Other” reporting segment was established during the second quarter of our 2008 fiscal year. It is intended primarily to encompass the results of corporate acquisitions and other equity transactions. As we continue to implement our acquisition strategy and grow, we will likely report certain income and expense items associated with potential and completed acquisitions under this reporting segment. Further, in the event we receive regulatory approval to create a holding company structure, we may report certain other income and expense items associated with the holding company in this reporting segment.

Our first significant event reported under this segment was a deferred tax asset that was the result of our recent acquisitions of two natural gas utilities. On October 1, 2007, we completed the acquisition of Frontier Natural Gas, a natural gas utility in Elkin, North Carolina for a total purchase price of approximately $4.9 million. On December 1, 2007, we completed the acquisition of Bangor Gas Company, a Maine natural gas utility, for a total purchase price of approximately $434,000.

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Under Financial Accounting Standards (FAS) 141, (FAS 141), we recorded these stock acquisitions as if the net assets of the targets were acquired. For income tax purposes, we are permitted to “succeed” to the operations of the acquired companies, and thereby continue to depreciate the assets at their historical tax cost bases. As a result, we may continue to depreciate approximately $82.0 million of capital assets using the useful lives and rates employed by Frontier Natural Gas and Bangor Gas Company. This treatment results in a potential future federal and state income tax benefit of approximately $19.0 million over a 24-year period using applicable federal and state income tax rates. Under Internal Revenue Code Section 382, our ability to recognize tax deductions as a result of this tax benefit will be limited during the first five years following the acquisitions.

Following Financial Accounting Standards (FAS) 109 (FAS 109), our balance sheet at December 31, 2008 reflects a gross deferred tax asset of approximately $19.0 million, offset by a valuation allowance of approximately $7.5 million, resulting in a net deferred tax asset associated with the acquisition of approximately $11.5 million. The excess of the net deferred tax assets received in the transactions over their respective purchase prices has been reflected as an extraordinary gain of approximately $6.8 million on the accompanying statement of income in accordance with the provisions of FAS 141.

During the six months ended December 31, 2008, we invested in marketable securities of other energy companies. We have reported $41,000 in dividend income, $585,000 in costs associated with business development and acquisitions, and <$189,000> in associated income taxes in the corporate and other segment during the six months ended December 31, 2008.

Competition

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

Our marketing and production operations’ compete principally with from other natural gas marketing firms doing business in Montana and Wyoming.

Gas Supply Marketers and Gas Supply Contracts

We purchase gas for our natural gas operations and marketing and production operations from various gas supply marketers. For the past several years, the primary gas supply marketers for our natural gas distribution operations have been Jefferson Energy Trading, LLC (Jetco) and Tenaska Marketing Ventures. Jetco has also been a significant gas supply marketer for our marketing and production subsidiary, EWR. Other gas supply marketers are also used by EWR from time to time. EWR also supplies itself with natural gas through ownership of an average 60% gross working interest (51% net revenue interest) in 162 natural gas producing wells in operation in north central Montana. This production gives EWR a partial natural hedge when market prices of natural gas are greater than the cost of production. The gas production from these wells and assets provided approximately 23.3% of the volume requirements for EWR’s Montana market, for the six months ended December 31, 2008. In North Carolina, our primary gas supply marketer for Frontier Natural Gas is BP Energy, and in Maine, our primary gas supply marketer for Bangor Gas Company is Emera Energy Services.

We purchase and store gas for distribution later in the year. We also enter agreements to buy or sell gas at a fixed price. We may use such arrangements to protect profit margins on future obligations to deliver gas at a fixed price, or to attempt to protect against adverse effects of potential market price declines on future obligations to purchase gas at fixed prices.

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Governmental Regulation

State Regulation

Our continuing utility operations are subject to regulation by the MPSC, WPSC, NCUC and MPUC as to rates, service area, adequacy of service, and safety standards. This regulation plays a significant role in determining our profitability. These authorities regulate many aspects of our distribution operations, including construction and maintenance of facilities, operations, safety, the rates we may charge customers, the terms of service to our customers and the rate of return we are allowed to realize. The various regulatory 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. These pricing mechanisms have substantially reduced any delay between the incurrence and recovery of gas costs.

Local distribution companies periodically file rate cases with state regulatory authorities to seek permission to increase rates. We monitor our need to file rate cases with state regulators for such rate increases for our retail gas and transportation services. Through these rate cases, we are able to adjust the prices we charge customers for selling and transporting natural gas. However, in connection with our acquisitions of Frontier Natural Gas and Bangor Gas Company, the NCUC and MPUC extended the rate plans in effect at the time of acquisition for these entities for a period of five years. Accordingly, we can not seek a new rate plan in these states during that time, although the Maine rate plan does allow us to periodically increase and adjust our rates within certain parameters within our rate plan.

Franchise Agreements

In addition to being regulated by state regulatory agencies, local distribution companies are often subject to franchise agreements entered with local governments. While the number of local governments that require franchise agreements is diminishing historically, most of the local governments in our service areas still require them. Accordingly, when and where franchise agreements are required, we enter agreements for franchises with the cities and communities in which we operate authorizing us to place our facilities in the streets and public grounds. Generally, no utility may obtain a franchise until it has obtained approval from the relevant state regulatory agency to bid on a local franchise. We attempt to acquire or reacquire franchises whenever feasible. Where they are required, without a franchise, a local government could require us to cease our occupation of the streets and public grounds or prohibit us from extending our facilities into any new area of that city or community. To date, the absence of a franchise has caused no adverse effect on our operations.

In Montana, we hold a franchise in the city of Great Falls, and we are in the process of renewing our West Yellowstone franchise agreement. In Wyoming we hold franchises in the cities of Cody and Meeteetse. In North Carolina, the right to distribute gas is regulated by the NCUC, which generally divides service territories by county, and we have been granted the right by the NCUC to distribute gas in the six counties in which we operate under certificates of public convenience and necessity from the NCUC. We also have franchise agreements with all of the incorporated municipalities in those six counties to install and operate gas lines in those municipalities’ streets and right-of-ways. In Maine, we have been granted the right by the MPUC to distribute gas in our service areas under certificates of public convenience and necessity. We are not required to obtain franchise agreements for our Maine operations.

Federal Regulations

Our interstate operations are also subject to federal regulations with respect to rates, services, construction/maintenance and safety standards. This regulation plays a significant role in determining our profitability. Various aspects of the transportation of natural gas are also subject to, or affected by, federal regulation under the Natural Gas Act (NGA), the Natural Gas Policy Act of 1978 and the Natural Gas Wellhead Decontrol Act of 1989. The Federal Energy Regulatory Commission (FERC) is the federal agency vested with authority to regulate the interstate gas transportation industry. Among aspects of our business subject to FERC regulation, our Shoshone Pipeline is subject to certain FERC regulations applicable to interstate activities, including (among other things) regulations regarding rates charged. Our pipeline rates must be filed with FERC. The Shoshone Pipeline has rates on file with FERC for firm and interruptible transportation that have been determined to be just and reasonable. The operations of the Shoshone Pipeline are subject to certain standards of conduct established by FERC that require the Shoshone Pipeline to operate separately from, and without sharing confidential business information with, EWR to the maximum extent practicable. In contrast, FERC has determined that our interstate pipeline and natural gas operations in Wyoming may share operating personnel so long as our natural gas operations in Wyoming do not market natural gas.

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Under certain circumstances, gathering pipelines are exempt from regulation by FERC. Our Glacier gathering pipeline has been determined to be non-jurisdictional by FERC, and is therefore not subject to regulation by FERC.

Our interstate pipeline operations are also subject to federal safety standards promulgated by the Department of Transportation under applicable federal pipeline safety legislation, as supplemented by various state safety statutes and regulations.

EWR is authorized by FERC to sell wholesale electricity in interstate commerce. These operations are subject to the Federal Power Act. However, FERC has determined that Energy West is an exempt public utility holding company.

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

Environmental Laws and Regulations

Our business is subject to environmental risks normally incident to the operation and construction of gathering lines, pipelines, plants and other facilities for gathering, processing, treatment, storing and transporting natural gas and other products. These environmental risks include uncontrollable flows of natural gas, fluids and other substances into the environment, explosions, fires, pollution and other environmental and safety risks. The following is a discussion of certain environmental and safety concerns related to our business. It is not intended to constitute a complete discussion of the various federal, state and local statutes, rules, regulations, or orders to which our operations may be subject. For example, we, even without regard to fault, could incur liability under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980, as amended (also known as the “Superfund” law), or state counterparts, in connection with the disposal or other releases of hazardous substances and for damage to natural resources.

Our activities in connection with the operation and construction of gathering lines, pipelines, plants, storage caverns, and other facilities for gathering, processing, treatment, storing and transporting natural gas and other products are subject to environmental and safety regulation by federal and state authorities, including, without limitation, the state environmental agencies and the Environmental Protection Agency (EPA), which can increase the costs of designing, installing and operating such facilities. In most instances, the regulatory requirements relate to the discharge of substances into the environment and include measures to control water and air pollution.

Environmental laws and regulations may require the acquisition of a permit or other authorization before certain activities may be conducted. These laws also include fines and penalties for non-compliance. Further, these laws and regulations may limit or prohibit activities on certain lands lying within wilderness areas, wetlands, areas providing habitat for certain species or other protected areas. We are also subject to other federal, state, and local laws covering the handling, storage or discharge of materials used in our business and laws otherwise relating to protection of the environment, safety and health. Because the requirements imposed by environmental laws and regulations frequently change, we are unable to predict the ultimate costs of compliance with such requirements or whether the incurrence of such costs would have a material adverse effect on our operations.

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Environmental Issues

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 (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 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.

Although we incurred considerable costs to evaluate and remediate the site, we have been permitted by the MPSC to recover the vast majority of those costs. On May 30, 1995, we received an order from the MPSC allowing for recovery of the costs through a surcharge on customer bills. At December 31, 2008, we had incurred cumulative costs of approximately $2.1 million in connection with our evaluation and remediation of the site and had recovered approximately $2.0 million of these costs pursuant to the order. As of December 31, 2008, the cost remaining to be recovered through the ongoing rate was $115,000. We are required to file with the MPSC every two years for approval to continue the recovery of these costs through a surcharge. During fiscal 2007, the MPSC approved the continuation of the recovery of these costs with its order dated May 15, 2007.

We periodically conduct environmental assessments of our assets and operations. As set forth above, we continue to work with the MDEQ to address the water contamination problems associated with the former manufactured gas plant site and we believe that under EPA standards, further remediation may be technically impracticable. Further, we are not aware of any other material environmental problems requiring remediation. For these reasons, we believe that we are in material compliance with all applicable environmental laws and regulations.

Employees

We had a total of 116 employees as of December 31, 2008. Two of these employees are employed by our marketing and production operations, 101 by our natural gas operations and 13 at the corporate office. Our natural gas operations include 15 employees represented by two labor unions. Negotiations were completed in July 2008 with the Laborers Union, with a contract in place until June 30, 2010. A three-year contract with Local Union #41 for the pipefitters expires June 30, 2010. We believe our relationship with both labor unions is good.

Item 1A. Risk Factors.

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

Risks Related to Our Business

We are subject to comprehensive regulation by federal, state and local regulatory agencies that impact the rates we are able to charge, our costs and profitability.

The MPSC, WPSC, NCUC, MPUC and FERC regulate our rates, service area, adequacy of service and safety standards. These authorities regulate many aspects of our distribution operations, including the rates that we may charge customers, the terms of service to our customers, construction and maintenance of facilities, operations, safety and the rate of return that we are allowed to realize. Our ability to obtain rate increases and rate supplements to maintain the current rate of return depends upon regulatory discretion. There can be no assurance that we will be able to obtain rate increases or rate supplements or continue to receive the current authorized rates of return.

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Our gas purchase practices are subject to an annual review by state regulatory agencies which could impact our earnings and cash flow.

The regulatory agencies that oversee our utility operations may review retrospectively our purchases of natural gas on an annual basis. The purpose of these annual reviews is to reconcile the differences, if any, between the amount we paid for natural gas and the amount our customers paid for natural gas. If any costs are disallowed in this review process, these disallowed costs would be expensed in the cost of gas but would not be recovered by us in the rates charged to our customers. The various state regulatory agencies’ reviews of our gas purchase practices creates the potential for the disallowance of our recovery through the gas cost recovery pricing mechanism. Significant disallowances could affect our earnings and cash flow.

Operational issues beyond our control could have an adverse effect on our business.

We operate in geographically dispersed areas. Our ability to provide natural gas depends both on our own operations and facilities and those of third parties, including local gas producers and natural gas pipeline operators from whom we receive our natural gas supply. We cannot assure you that we will realize cost savings from our receipt of natural gas from third parties.

In addition, the loss of use or destruction of our facilities or the facilities of third parties due to extreme weather conditions, breakdowns, war, acts of terrorism or other occurrences could greatly reduce potential earnings and cash flows and increase our costs of repairs and replacement of assets. Our losses may not be fully recoverable through insurance or customer rates.

Storing and transporting natural gas involves inherent risks that could cause us to incur significant financial losses.

There are inherent hazards and operation risks in gas distribution activities, such as leaks, accidental explosions and mechanical problems that could cause the loss of human life, significant damage to property, environmental pollution, impairment of operations and substantial losses to us. The location of pipelines and storage facilities near populated areas, including residential areas, commercial business centers and industrial sites, could increase the level of damages resulting from these risks. These activities may subject us to litigation and administrative proceedings that could result in substantial monetary judgments, fines or penalties against us. To the extent that the occurrence of any of these events is not fully covered by insurance, they could adversely affect our earnings and cash flow.

Our earnings and cash flow are sensitive to decreases in customer consumption resulting from warmer than normal temperatures and customer conservation.

Our gas sales revenue is generated primarily through the sale and delivery of natural gas to residential and commercial customers who use natural gas mainly for space heating. Consequently, temperatures have a significant impact on sales and revenues. Given the impact of weather on our utility operations, our business is a seasonal business. Most of our gas sales revenue is generated in the first and fourth quarters of our fiscal year (January 1 to March 31 and October 1 to December 31) as we typically experience losses in the non-heating season, which occurs in the second and third quarters of our fiscal year (April 1 to September 30).

In addition, the average annual natural gas consumption of customers has been decreasing because, among other things, new homes and appliances are typically more energy efficient than older homes and appliances, and customers appear to be continuing a pattern of conserving energy by utilizing energy efficient heating systems, insulation, alternative energy sources, and other energy savings devices and techniques. A mild winter, as well as continued or increased conservation, in any of our service areas can have a significant adverse impact on demand for natural gas and, consequently, earnings and cash flow.

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The increased cost of purchasing natural gas during periods in which natural gas prices are rising significantly could adversely impact our earnings and cash flow.

The rates we are permitted to charge allow us to recover our cost of purchasing natural gas. In general, the various regulatory agencies allow us to recover the costs of natural gas purchased for customers on a dollar-for-dollar basis (in the absence of disallowances), without a profit component. We periodically adjust customer rates for increases and decreases in the cost of gas purchased by us for sale to our customers. Under the regulatory body-approved gas cost recovery pricing mechanisms, the gas commodity charge portion of gas rates we charge to our customers may be adjusted upward on a periodic basis. If the cost of purchasing natural gas increases and we are unable to recover these costs from our customers, we may incur increased costs associated with lost and unaccounted for gas and higher working capital requirements. In addition, any increases in the cost of purchasing natural gas may result in higher customer bad debt expense for uncollectible accounts and reduced sales volume and related margins due to lower customer consumption.

The loss of a major commercial or industrial gas customer to which we provide natural gas may negatively impact our profitability.

In fiscal 2008, we earned 3.25% of our operating margin by providing gas marketing services to unregulated commercial and industrial gas customers. External factors over which we have no control, such as the weather and economic conditions, can significantly impact the amount of gas consumed by our major commercial and industrial customers. The loss of a major customer could have an adverse impact on our earnings and cash flow.

Volatility in the price of natural gas could result in customers switching to alternative energy sources which could reduce our revenues, earnings and cash flow.

The market price of alternative energy sources such as coal, electricity, oil and steam is a competitive factor affecting the demand for our gas distribution services. Our customers may have or may acquire the capacity to use one or more of the alternative energy sources if the price of natural gas and our distribution services increase significantly. Natural gas has typically been less expensive than these alternative energy sources. However, if natural gas prices increase significantly, some of these alternative energy sources may become more economical or more attractive than natural gas which could reduce our earnings and cash flow.

The gas industry is intensely competitive and competition has increased in recent years as a result of changes in the price negotiation process within the supply and distribution chain of the gas industry, both of which could negatively impact earnings.

We compete with companies from various regions of the United States and may compete with foreign companies for domestic sales, many of whom are larger and have greater financial, technological, human and other resources. Additionally, legislative and regulatory initiatives, at both the federal and state levels, are designed to promote competition. These challenges have been compounded by changes in the gas industry that have allowed certain customers to negotiate gas purchases directly with producers or brokers. We could lose market share or our profit margins may decline in the future if we are unable to remain competitive.

Earnings and cash flow may be adversely affected by downturns in the economy.

Our operations are affected by the conditions and overall strength of the national, regional and local economies, which impact the amount of residential and industrial growth and actual gas consumption in our service territories. Our commercial customers use natural gas in the production of their products. During economic downturns, these customers may see a decrease in demand for their products, which in turn may lead to a decrease in the amount of natural gas they require for production. In addition, during periods of slow or little economic growth, energy conservation efforts often increase and the amount of uncollectible customer accounts increases. These factors may reduce earnings and cash flow.

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Changes in the regulatory environment and events in the energy markets that are beyond our control may reduce our earnings and limit our access to capital markets.

As a result of the energy crisis in California during 2000 and 2001, the bankruptcy of some energy companies, investigations by governmental authorities into energy trading activities, the collapse in market values of energy companies, the downgrading by rating agencies of a large number of companies in the energy sector and the recent volatility of natural gas prices in North America, companies in regulated and unregulated energy businesses have generally been under increased scrutiny by regulators, participants in the capital markets and debt rating agencies. In addition, the Financial Accounting Standards Board or the Securities and Exchange Commission could enact new accounting standards that could impact the way we are required to record revenues, expenses, assets and liabilities. We cannot predict or control what effect these types of events, or future actions of regulatory agencies or others in response to such events, may have on our earnings or access to the capital markets.

We acquired interests in our natural gas wells by quitclaim deed and cannot guarantee that we hold clear title to our interests or that our interests will not be challenged in the future.

We own an average 60% working interest (average 51% net revenue interest) in 162 natural gas producing wells, which provide our marketing and production operations a partial natural hedge when market prices of natural gas are greater than the cost of production. The gas production from these wells provided approximately 23.3% of the volume requirements for EWR’s Montana market for the six months ended December 31, 2008. We acquired our interests in the wells by quitclaim deed conveying interests in certain oil and gas leases for the wells. Because the sellers conveyed their interests by quitclaim, we received no warranty or representation from them that they owned their interests free and clear from adverse claims by third parties or other title defects. We have no title insurance, guaranty or warranty for our interests in the wells. Further, the wells may be subject to prior, unregistered agreements, or transfers which have not been recorded.

Accordingly, we cannot guarantee that we hold clear title to our interests or that our interests will not be challenged in the future. If our interests were challenged, expenses for curative title work, litigation or other dispute resolution mechanisms may be incurred. Loss of our interests would reduce or eliminate our production operations and reduce or eliminate the partial natural hedge that our marketing and production subsidiary currently enjoys as a result of our production capabilities. For all of these reasons, a challenge to our ownership could negatively impact our earnings, profits and results of operations.

Failure to 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.

Section 404 of the Sarbanes-Oxley Act of 2002 (Section 404) contains provisions requiring an annual assessment by management, as of the end of the fiscal year, of the effectiveness of internal control for financial reporting, as well as attestation and reporting by independent auditors on management’s assessment as well as other control-related matters. Beginning with the Form 10-K for the fiscal year ended June 30, 2008, we began complying with Section 404 and finished a report by our management on our internal control over financial reporting. Our auditors are not yet required to opine on our internal controls.

Compliance with Section 404 is both costly and challenging. Going forward, there is a risk that neither we nor our independent auditors will be able to conclude that our internal control over financial reporting is effective as required by Section 404. Further, 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 under the Sarbanes-Oxley Act for compliance with Section 404. Moreover, effective internal controls, particularly those related to revenue recognition, are necessary for us to produce reliable financial reports and are important to help prevent financial fraud. If we cannot provide reliable financial reports or prevent fraud, our business and operating results could be harmed, investors could lose confidence in our reported financial information, and the trading price of our stock could be adversely affected.

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

In preparing our financial statements in accordance with generally accepted accounting principles, our management often must make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosures at the date of the financial statements and during the reporting period. Some of those judgments can be subjective and complex, and actual results could differ from those estimates. We consider the regulatory accounting policy to be our most critical because of the uncertainties, judgments, and complexities of the underlying accounting standards and operations involved. Regulatory accounting allows for the actions of regulators to be reflected in the financial statements. Their actions may cause us to capitalize costs that would otherwise be included as an expense in the current period by unregulated companies. If future recovery of costs ceases to be probable, the assets will be written off as a charge in current period earnings.

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We are subject to numerous environmental laws and regulations that may increase our cost of operations, impact our business plans and 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 and operating costs. These laws and regulations generally require us to obtain and comply with a wide variety of environmental licenses, permits, inspections and other approvals. Both public officials and private individuals may seek to enforce applicable environmental laws and regulations. We cannot predict the outcome (financial or operational) of any related litigation that may arise.

We may be a responsible party for 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 intended 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 could have a material adverse effect on our results of operations.

We have a net deferred tax asset of $11.5 million and we cannot guarantee that we will be able to generate sufficient future taxable income to realize a significant portion of this net deferred tax asset, which could lead to a writedown (or even a loss) of the net deferred tax asset and adversely affect our operating results and financial position.

We have a net deferred tax asset of $11.5 million. The net deferred tax asset is the result of our recent acquisitions of Frontier Natural Gas and Bangor Gas Company. We may continue to depreciate approximately $82.0 million of their capital assets using the useful lives and rates employed by those companies, resulting in a potential future federal and state income tax benefit of approximately $19.0 million over a 24-year period using applicable federal and state income tax rates. Under Internal Revenue Code Section 382, our ability to recognize tax deductions as a result of this tax benefit will be limited during the first 5 years following the acquisitions.

Following FAS 109, our balance sheet at December 31, 2008 reflects a gross deferred tax asset of approximately $19.0 million, offset by a valuation allowance of approximately $7.5 million, resulting in a net deferred tax asset associated with the acquisition of approximately $11.5 million. The excess of the net deferred tax assets received in the transactions over their respective purchase prices has been reflected as an extraordinary gain of approximately $6.8 million on our income statement for the year ended June 30, 2008 in accordance with the provisions of FAS 141.

We cannot guarantee that we will be able to generate sufficient future taxable income to realize the $11.5 million net deferred tax asset over the next 24 years. Management will reevaluate the valuation allowance each year on completion of updated estimates of taxable income for future periods, and will further reduce the deferred tax asset by the new valuation allowance if, based on the weight of available evidence, it is more likely than not that we will not realize some portion or all of the recognized deferred tax assets. If the estimates indicate that we are unable to use all or a portion of the net deferred tax asset balance, we will record and charge a greater valuation allowance to income tax expense. Failure to achieve projected levels of profitability could lead to a write down in the deferred tax asset if the recovery period becomes uncertain or longer than expected and could also lead to the expiration of the deferred tax asset between now and 2032, either of which would adversely affect our operating results and financial position.

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Changes in the market price and transportation costs of natural gas could result in financial losses that would negatively impact our results of operations.

We are exposed to the impact of market fluctuations in the price and transportation costs of natural gas. We purchase and store gas for distribution later in the year. We also enter agreements to buy or sell gas at a fixed price. We may use such arrangements to protect profit margins on future obligations to deliver gas at a fixed price, or to attempt to protect against adverse effects of potential market price declines on future obligations to purchase gas at fixed prices. Further, we are exposed to losses in the event of nonperformance or nonpayment by the counterparties to our supply agreements, which could have a material adverse impact on our earnings for a given period.

Risks Related to Our Acquisition Strategy

We face a variety of risks associated with acquiring and integrating new business operations.

The growth and success of our business will depend to a great extent on our ability to acquire new assets or business operations and to integrate the operations of businesses that we have recently acquired, including Frontier Natural Gas and Bangor Gas Company, and those 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,

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

• comply with the internal control requirements of Section 404 as a result of an acquisition.

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

To the extent we are successful in making an acquisition, we may be exposed to a number of risks.

Any acquisition may involve a number of risks, including the assumption of material liabilities, the terms and conditions of any state or federal regulatory approvals required for an acquisition, the diversion of management’s attention from the management of daily operations to the integration of acquired operations, difficulties in the integration and retention of employees and difficulties in the integration of different cultures and practices, as well as in the integration of broad and geographically dispersed personnel and operations. The failure to make and integrate acquisitions successfully, including Frontier Natural Gas and Bangor Gas Company, could have an adverse effect on our ability to grow our business.

Subsequent to the consummation of an acquisition, we may be required to take write-downs or write-offs, restructuring and impairment charges or other charges that could have a significant negative impact on our financial condition, results of operations and our stock price.

We recently acquired Frontier Natural Gas and Bangor Gas Company and are in the process of completing other potential acquisitions. There could be material issues present inside a particular target business that are not uncovered in the course of due diligence performed prior to the acquisition, and there could be factors outside of the target business and outside of our control that later arise. As a result of these factors, after an acquisition is complete we may be forced to write-down or write-off assets, restructure our operations or incur impairment or other charges relating to an evaluation of goodwill and acquisition-related intangible assets that could result in our reporting losses. In addition, unexpected risks may arise and previously known risks may materialize in a manner not consistent with our preliminary risk analysis.

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Risks Related to Our Common Stock

Our ability to pay dividends on our common stock is limited.

We cannot assure you that we will continue to pay dividends at our current monthly dividend rate or at all. In particular, our ability to pay dividends in the future will depend upon, among other things, our future earnings, cash requirements and covenants under our existing credit facility and any future credit agreements to which we may be a party.

The possible issuance of future series of preferred stock could adversely affect the holders of our common stock.

Pursuant to our articles of incorporation, our board of directors has the authority to fix the rights, preferences, privileges and restrictions of unissued preferred stock and to issue those shares without any further action or vote by the shareholders. The rights of the holders of our common stock will be subject to, and may be adversely affected by, the rights of the holders of any series of preferred stock that may be issued in the future. These adverse effects could include subordination to preferred shareholders in the payment of dividends and upon our liquidation and dissolution, and the use of preferred stock as an anti-takeover measure, which could impede a change in control that is otherwise in the interests of holders of our common stock.

Organization, Structure and Management Risks

Our credit facility contains restrictive covenants that may reduce our flexibility, and adversely affect our business, earnings, cash flow, liquidity and financial condition.

The terms of our credit facility impose significant restrictions on our ability and, in some cases, the ability of our subsidiaries, to take a number of actions that we may otherwise desire to take, including:

• requiring us to dedicate a substantial portion of our cash flow from operations to the payment of principal and interest on our indebtedness, thereby reducing the availability of cash flow for working capital, capital expenditures and other business activities,

• requiring us to meet certain financial tests, which may affect our flexibility in planning for, or reacting to, changes in our business and the industries in which we operate,

• limiting our ability to sell assets, make investments or acquire assets of, or merge or consolidate with, other companies,

• limiting our ability to repurchase or redeem our stock or enter into transactions with our shareholders or affiliates, and

• limiting our ability to grant liens, incur additional indebtedness or contingent obligations or obtain additional financing for working capital, capital expenditures, acquisitions and general corporate and other activities.

These covenants place constraints on our business and may adversely affect our growth, business, earnings, cash flow, liquidity and financial condition. Our failure to comply with any of the financial covenants in the credit facility may result in an event of default which, if not cured or waived, could result in the acceleration of the debt under the credit facility or other agreements we may enter into from time to time that contain cross-acceleration or cross-default provisions. If this occurs, there can be no assurance that we would be able to refinance or otherwise repay such indebtedness, which could result in a material adverse effect on our business, earnings, cash flow, liquidity and financial condition.

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Our performance depends substantially on the performance of our executive officers and other key personnel and the ability of our new management team to fully implement our business strategy.

The success of our business depends on our ability to attract, train, retain, and motivate high quality personnel, especially highly qualified managerial personnel. Poor execution in the transition of our management team or the loss of services of key executive officers or personnel could have a material adverse effect on our business, results of operations and financial condition.

During fiscal 2008, new chief executive, operating and financial officers joined our management team. Because of these recent changes, our management team has not worked together as a group for an extended period of time and may not work together effectively to successfully implement our business strategy. If our new management team is unable to accomplish our business objectives, our ability to successfully operate the company and acquire and integrate new business operations may be severely impaired.

We have entered a limited liability operating agreement with third parties to develop and operate oil, gas and mineral leasehold estates, which exposes us to the risk associated with oil, gas and mineral exploration as well as the risks inherent in relying upon third parties in business ventures and we may enter into similar agreements in the future.

Through our subsidiary Energy West Resources, Inc. (EWR), we have entered an operating agreement with various third parties regarding Kykuit Resources, LLC (Kykuit), a developer and operator of oil, gas and mineral leasehold estates located in Montana. Through EWR, we own 19.8% of the membership interests of Kykuit, and because Kykuit’s primary purpose is oil, gas and mineral exploration, our investment in Kykuit is subject to the risks associated with that business, including the risk that little or no oil, gas or minerals will be found. We have a net investment of approximately $1.1 million in Kykuit, and we may be required to invest additional amounts of up to approximately $1.9 million. Whether or not we may be required to invest additional funds will depend on the success, or lack thereof, of Kykuit in its initial drilling. We are entitled under the Kykuit operating agreement, as amended and restated, to exercise reasonable discretion to cease further investments in the event certain initial exploratory drilling efforts are unsuccessful.

We depend upon the performance of third party participants in endeavors such as Kykuit, and their performance of their obligations to us are outside our control. If these parties do not meet or satisfy their obligations under these arrangements, the performance and success of endeavors such as Kykuit may be adversely affected. If third parties to operating agreements and similar agreements are unable to meet their obligations we may be forced to undertake the obligations ourselves or incur additional expenses in order to have some other party perform such obligations. We may also be required to enforce our rights that may cause disputes among third parties and us. If any of these events occur, they may adversely impact us, our financial performance and results of operations.

We have entered into certain transactions with persons who are our directors and may enter into additional transactions in the future.

Richard M. Osborne, our chairman of the board and chief executive officer, and Steven A. Calabrese, a director, own interests in Kykuit, a party to the joint venture arrangement involving EWR. John D. Oil and Gas Company, a publicly-held oil and gas exploration company of which Mr. Osborne is the chairman of the board and chief executive officer and Energy West directors Mr. Calabrese, Mark D. Grossi, James R. Smail and Thomas J. Smith are directors, is an owner and the managing member of Kykuit. Additionally, we lease office space in Mentor, Ohio from OsAir, Inc., of which Mr. Osborne is the president and chief executive officer. In the future, we may enter into additional transactions with our directors or entities controlled by our directors. We cannot assure you that our shareholders will view the benefits of these transactions in the same manner that we or our board of directors do.

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We have filed applications with the MPSC and the WPSC to reorganize our operations into a holding company structure, which could affect our ability to pay dividends in the future.

We have filed applications with the MPSC and have received approval by the WPSC to reorganize our operations into a holding company structure. Our reorganization may also be subject to an approval or receipt of a waiver from the MPUC and NCUC which we are seeking to obtain. We expect responses from these agencies within approximately six months of filing the applications, although we have no control over the timing of their responses. If this structure is approved by these agencies, we intend to become a holding company with no significant assets other than the stock of our operating subsidiaries. We would rely on dividends from our subsidiaries for our cash flows. Our ability to pay dividends to our shareholders and finance acquisitions would be dependent on the ability of our subsidiaries to generate sufficient net income and cash flows to pay upstream dividends to us.

Item 2. Properties.

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

In addition, we lease 1,000 square feet of office space in Mentor, Ohio that serves as the offices for our chief executive officer and our vice president of business development under a three year lease agreement.

We own a 60% gross working interest (51% net revenue interest) in 160 natural gas production wells and three gathering pipelines in north central Montana. The natural gas wells are operated by a third party and we are invoiced each month for our share of the operating and capital expenses incurred. We acquired our interests in the wells by quitclaim deeds conveying interests in certain oil and gas leases for the wells from sellers who were in financial distress. We chose to purchase their interests despite the uncertain nature of the conveyance because we were able to negotiate purchase prices that, we believe, were fair and reasonable under, and accounted for, that circumstance. It is possible that our interests will be challenged in the future, but no such challenge has been made since acquiring the interests in 2002 and 2003 and we have no notice that such a challenge is forthcoming.

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, Wyoming.

Our North Carolina operations are headquartered in Elkin, North Carolina. The facility is a 16,000 square foot building that has a combination of office, shop and warehouse space. We are subject to a lease agreement through June 2009. We own approximately 290 miles of transmission and distribution lines and related metering and related equipment.

In Bangor, Maine, we lease two office buildings under long-term lease agreements. We have approximately 100 miles of transmission and distribution lines and related metering and regulating equipment.

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

Item 3. Legal Proceedings.

We are involved in lawsuits that have arisen in the ordinary course of our business. We are contesting each of these lawsuits vigorously and believe we have defenses to the allegations that have been made.

On February 21, 2008, a lawsuit captioned Shelby Gas Association v. Energy West Resources, Inc., Case No. DV-08-008, was filed in the Ninth Judicial District Court of Toole County, Montana. Shelby Gas Association (Shelby) alleges a breach of contract by our subsidiary, EWR, to provide natural gas to Shelby. Shelby is seeking damages and injunctive relief prohibiting EWR from further breaching the contract. The case is currently in the discovery phase. We believe this lawsuit to be without merit and are vigorously defending the allegations.

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In our opinion, the outcome of these lawsuits, including the Shelby litigation, will not have a material adverse effect on our financial condition, cash flows or results of operations.

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

We held our 2008 Annual Meeting of Shareholders on December 11, 2008. The following nominees were elected to the Company’s Board of Directors to serve until our next annual meeting of shareholders.

Name	For		Withheld
Ian J. Abrams		3,765,956		193,989
W.E. ‘Gene’ Argo		3,775,190		184,755
Steven A. Calabrese		3,762,516		197,429
Mark D. Grossi		3,752,906		207,039
Richard M. Osborne		3,581,555		378,390
James R. Smail		3,763,929		196,016
Thomas J. Smith		3,764,056		195,889
James E. Sprague		3,738,966		220,979
Michael T. Victor		3,756,872		203,073

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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 trades on the Nasdaq Global Market under the symbol “EWST.” On February 1, 2008, the Board of Directors authorized a 3-for-2 stock split of the company’s $0.15 par value common stock. As a result of the split, 1,437,744 additional shares were issued, and additional paid-in capital was reduced by $215,619. All references in the accompanying financial statements to the number of common shares and per-share amounts for fiscal 2008, 2007 and 2006 have been restated to reflect the stock split.

The following table sets forth, for the quarters indicated, the range of high and low prices of our common stock from the Nasdaq Monthly Statistical Reports, adjusted for the 3 for 2 stock split effectuated February 1, 2008.

Six Months Ended December 31, 2008	High		Low
First Quarter	$	10.70	$	7.27
Second Quarter	$	8.48	$	5.92

Fiscal Year 2008	High		Low
First Quarter	$	9.49	$	8.14
Second Quarter	$	9.80	$	8.19
Third Quarter	$	9.68	$	7.59
Fourth Quarter	$	11.21	$	7.40

Fiscal Year 2007	High		Low
First Quarter	$	7.96	$	6.01
Second Quarter	$	8.00	$	7.19
Third Quarter	$	10.00	$	7.40
Fourth Quarter	$	10.81	$	9.01

Holders of Record

As of February 28, 2009, there were approximately 194 record owners of our common stock. We estimate that an additional 2180 shareholders own stock in their accounts at brokerage firms and other financial institutions.

Dividend Policy

Our credit agreement with Bank of America, N.A. (Bank of America) (fka LaSalle Bank, N.A.) restricts our ability to pay dividends during any period to a certain percentage of our cumulative earnings over that period. Our 2010 promissory note also contains restrictions respecting the payment of dividends. Quarterly dividend payments, adjusted for the stock split, per common share were:

February 13, 2007	$	0.093
May 3, 2007	$	0.100
September 25, 2007	$	0.106
November 19, 2007	$	.107

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On October 22, 2007, we amended our credit facility with Bank of America to begin paying monthly, rather than quarterly, cash dividends on our common shares. We began to pay a monthly dividend on December 28, 2007. Monthly dividend payments per common share (adjusted for the stock split) were:

December 28, 2007	$	0.036
January 28, 2008	$	0.036
February 28, 2008	$	0.036
March 28, 2008	$	0.036
April 30, 2008	$	0.036
May 30, 2008	$	0.036
June 30, 2008	$	0.040
July 31, 2008	$	0.040
August 29, 2008	$	0.040
September 30, 2008	$	0.040
October 30, 2008	$	0.040
December 1, 2008	$	0.040
December 30, 2008	$	0.040

Restrictions on Payment of Dividends

Our loan with Bank of America restricts our ability to pay dividends. Payment of future cash dividends, if any, and their amounts, will be dependent upon a number of factors, including those restrictions, our earnings, financial requirements, number of shares of capital stock outstanding and other factors deemed relevant by our board of directors. We are permitted to pay dividends no more frequently than once each calendar month. Further, we are forbidden from paying dividends in certain circumstances. For instance, we may not pay a dividend if the dividend, when combined with dividends over the previous five years, would exceed 75% of our net income over those years. For the purposes of this restriction, extraordinary gain, such as the $6.8 million of extraordinary gain associated with the purchase of Frontier Natural Gas and Bangor Gas Company, is not included in net income. Further, if we have purchased or redeemed any of our capital stock during the previous five years, payments for these purchases or redemptions would be included as payments of dividends in determining whether it is permissible to pay the proposed dividend under this restriction.

In addition, we may not pay a dividend if we are in default, or if payment would cause us to be in default, under the terms of our unsecured credit agreement. We also may not pay a dividend if payment would cause our earnings before interest and taxes (EBIT), to be less than twice our interest expense. For the purpose of this restriction, EBIT and interest expense are measured over a four-quarter time period that ends with the most recently completed fiscal quarter. Similarly, we may not pay a dividend if payment would cause our total debt to exceed 65% of our capital. For the purpose of this restriction, total debt and capital are measured for the most recently completed fiscal quarter.

In addition to our Bank of America credit facility, we also have unsecured senior notes outstanding that also contain restrictions on dividend payments. Under our unsecured senior notes, we may not pay a dividend if payment would cause our total payments of dividends for the five years prior to the proposed payment to exceed our consolidated net income for those five years.

Recent Sales of Unregistered Securities

Not applicable.

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Purchases of Equity Securities by Our Company and Affiliated Purchasers

					Total number of		Maximum number of
					shares purchased as		shares that may yet be
	Total Shares		Average price		part of publicly		purchased under the
Period	Purchased		paid per share		announced plans		stock repurchase plan
May 30, 2007 – June 30, 2007		219,522	$	10.00		219,522
July 1, 2007 – June 30, 2008		16,780	$	9.50		16,780
July 1, 2008 – December 31, 2008		53,416	$	7.60		53,416
		289,718				289,718		158,782

All shares adjusted for 3-for-2 stock split effectuated February 1, 2008.

On February 13, 2007, our Board of Directors approved a stock repurchase plan whereby we intend to buy back up to 448,500 shares of our common stock. We began this stock buyback on May 30, 2007. The stock repurchases included 217,500 shares from Mr. Mark Grossi, one of our directors. During the six months ended December 31, 2008, we repurchased an additional 53,416 shares of common stock.

Performance Graph

The graph below matches our cumulative five-year total shareholder return on common stock with the cumulative total returns of the S&P 500 index and the S&P Utilities index. The graph tracks the performance of a $100 investment in our common stock and in each of the indexes (with the reinvestment of all dividends) from December 31, 2003 to December 31, 2008.

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Item 6. Selected Financial Data.

The selected financial data presented below are derived from our historical consolidated financial statements, which were audited by our independent registered public accounting firms in each of those periods. 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/T. Amounts are in thousands, except per share and number of share amounts. Certain prior period revenues and expenses have been reclassified as income from discontinued operations.

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	Six months ended December 31,
	2008			2007
	(in thousands, except per share)
Operating results
Operating revenue	$	38,757		$	28,313
Operating expenses
Gas and electric purchases		27,230			19,895
General and administrative		5,717			4,602
Maintenance		320			326
Depreciation and amortization		1,023			889
Taxes other than income		1,285			864
Total operating expenses		35,575			26,576
Operating income (loss)		3,182			1,737
Other income (expense)		(420	)		191
Total interest charges		677			530
Income (loss) before taxes		2,085			1,398
Income tax expense (benefit)		926			274
Discontinued operations (net of tax)		—			—
Net Income (Loss) before extraordinary item		1,159			1,124
Extraordinary Gain		—			6,819
Net Income	$	1,159		$	7,943
Basic earnings (loss) per common share	$	0.27		$	1.85
Diluted earnings (loss) per common share	$	0.27		$	1.85
Dividends per common share	$	0.28		$	0.25
Weighted average common shares Outstanding — diluted		4,331,726			4,304,559
At year end:
Current assets	$	31,484
Total assets	$	75,818
Current liabilities	$	30,114
Total long-term debt	$	13,000
Total stockholders’ equity	$	30,082
Total capitalization	$	43,082

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	Fiscal year ended June 30,
	(in thousands, except per share)
	2008		2007		2006		2005		2004
Operating results
Operating revenue	$	76,833	$	59,373	$	74,696	$	67,889	$	58,664
Operating expenses Gas and electric purchases		56,170		43,806		60,398		53,510		46,981
General and administrative		10,662		6,198		6,389		7,309		8,020
Maintenance		650		567		505		521		399
Depreciation and amortization		1,865		1,692		1,672		1,790		1,812
Taxes other than income (1)		2,080		1,697		1,453		1,479		1,058
Total operating expenses		71,427		53,960		70,417		64,609		58,270
Operating income (loss)		5,406		5,413		4,279		3,280		394
Other income-net		316		241		391		235		204
Total interest charges (2)		1,077		2,124		1,649		2,113		1,933
Income (loss) before taxes		4,645		3,530		3,021		1,402		(1,335	)
Income tax expense (benefit)		1,333		1,273		1,109		475		(412	)
Discontinued operations (net of tax)		—		3,955		405		454		367
Net Income (Loss) before extraordinary item		3,312		6,212		2,317		1,381		(556	)
Extraordinary Gain		6,819
Net Income	$	10,131	$	6,212	$	2,317	$	1,381	$	(556	)
Basic earnings (loss) per common share	$	2.35	$	1.40	$	0.53	$	0.35	$	(0.14	)
Diluted earnings (loss) per common share	$	2.35	$	1.39	$	0.52	$	0.35	$	(0.14	)
Dividends per common share (3)	$	0.47	$	0.34	$	0.11	$	—	$	—
Weighted average common shares Outstanding — diluted		4,316,244		4,484,073		4,422,069		3,946,019		3,894,681
At year end:
Current assets	$	16,340	$	18,830	$	23,669	$	15,423	$	16,739
Total assets	$	58,377	$	51,582	$	56,629	$	57,986	$	60,219
Current liabilities	$	11,962	$	8,756	$	10,796	$	11,525	$	16,725
Total long-term debt	$	13,000	$	13,000	$	17,605	$	18,677	$	21,697
Total stockholders’ equity	$	30,649	$	22,296	$	19,165	$	17,187	$	13,401
Total capitalization	$	43,649	$	35,296	$	36,770	$	35,864	$	35,098

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(1)	Taxes other than income include approximately $290,000 increases in property tax in fiscal 2004, 2005 and another $250,000 in 2007 for additional personal property taxes assessed by the Montana Department of Revenue. The 2008 increase results from personal property taxes on our acquired companies in Maine and North Carolina.
(2)	Total interest charges reflect the costs associated with the addition of $6,000,000 of long-term debt and a $2,000,000 bridge loan incurred in March 2004. In May 2005, we paid off the $2,000,000 bridge loan and during fiscal 2006 we reduced the line of credit significantly, thus reducing interest in fiscal 2006. In fiscal 2007, we refinanced our long-term debt, resulting in the $991,000 expensing of debt issue costs related to the refinanced debt.
(3)	There were no cash dividends paid between April 2003 and September 2005.

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

This discussion should be read in conjunction with the consolidated financial statements, notes and tables included elsewhere in this Form 10-K. Management’s discussion and analysis contains forward-looking statements that are provided to assist in the understanding of anticipated future performance. However, future performance involves risks and uncertainties which may cause actual results to differ materially from those expressed in the forward-looking statements. See “Forward-Looking Statements.”

Executive Overview

Our primary source of revenue and operating margin has been the distribution of natural gas to end-use residential, commercial, and industrial customers. We have natural gas distribution operations in Montana, Wyoming, and we recently acquired distribution operations in North Carolina and Maine. We also market and distribute natural gas in Montana and Wyoming and conduct interstate pipeline operations in Montana and Wyoming. Formerly we conducted propane operations in Arizona, but those operations were sold in 2007.

We have five reporting segments: natural gas operations, marketing and production operations, pipeline operations, discontinued operations and corporate and other. Information regarding our Arizona propane operations is reported under discontinued operations. Our corporate and other reporting segment was recently established to report various income and expense items associated with corporate acquisitions and other equity transactions, including a deferred tax asset we received in connection with the acquisitions of our North Carolina and Maine distribution operations.

Critical Accounting Policies and Estimates

Our discussion and analysis of our financial condition and results of operation are based upon consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and disclosure of contingent assets and liabilities, if any, at the date of the financial statements. We analyze our estimates, including those related to regulatory assets and liabilities, income taxes and contingencies and litigation. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances. Actual results may differ from these estimates. We believe the following critical accounting policies affect our more significant judgments and estimates used in the preparation of our consolidated financial statements. See a complete list of significant accounting policies in Note 1 of the notes to the consolidated financial statements included herein.

Regulatory Accounting

Our accounting policies historically reflect the effects of the rate-making process in accordance with Statements of Financial Accounting Standards (SFAS) No. 71 “Accounting for the Effects of Certain Types of Regulation” (SFAS No. 71). Our regulated natural gas segment continues to be cost-of-service rate regulated, and we believe the application of SFAS No. 71 to that segment continues to be appropriate. We must reaffirm this conclusion at each balance sheet date. If, as a result of a change in circumstances, we determine that the regulated natural gas segment no longer meets the criteria of regulatory accounting under SFAS No. 71, that segment will have to discontinue regulatory accounting and write off the respective regulatory assets and liabilities.

The application of SFAS No. 71 results in recording regulatory assets and liabilities. Regulatory assets represent the deferral of incurred costs that are probable of future recovery in customer rates. In some cases, we record regulatory assets before we have received approval for recovery from the state regulatory agencies. 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. At December 31, 2008, our total regulatory assets were $4.2 million and our total regulatory liabilities were $1.1 million. A write-off of the regulatory assets and liabilities could have a material impact on our consolidated financial statements.

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Our natural gas segment contains regulated utility businesses in the states of Montana, Wyoming, Maine and North Carolina and the regulation varies from state to state. If future recovery of costs, in any such jurisdiction, ceases to be probable, we would be required to charge these assets to current earnings. However, there are no current or expected proposals or changes in the regulatory environment that impact the probability of future recovery of these assets. In addition, deregulation would be a change that occurs over time, due to legal processes and procedures, which could moderate the impact to our consolidated financial statements.

Our most significant regulatory asset/liability relates to the recoverable/refundable costs of gas purchases. We account for purchased gas costs in accordance with procedures authorized by the state regulatory agencies, under which purchased gas costs that are different from those provided for in present rates are accumulated and recovered or credited through future rate changes.

Our gas cost recoveries are monitored closely by the regulatory commissions in all of the states in which we operate. The gas cost recoveries are adjusted monthly in three of the four states in which we operate, and annually in the fourth. In addition, all of the states in which we operate require us to submit gas procurement plans, which we follow closely. These plans are reviewed annually by each of the regulatory commissions. The adjustment of gas cost recoveries and the gas procurement plans reduce the risk of disallowance of recoverable gas costs. The regulatory commissions have not disallowed any of our recoverable gas costs or other costs included in our regulatory assets in the last three years. Therefore, we believe it is highly probable that we will recover the regulatory assets that have been recorded.

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.

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.

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.

Each month the estimated unbilled revenue amounts are recorded as revenue and a receivable, and the prior month’s estimate is reversed. Likewise, the associated gas costs are recorded as cost of revenue and a payable and the prior month’s estimate is reversed. Actual price and usage patterns may vary from these assumptions and may impact revenues recognized and costs recorded. The critical component of calculating unbilled revenues is estimating the usage on a calendar month basis. Our estimated volumes used in the unbilled revenue calculation have varied from our actual monthly metered volumes by less than plus or minus 10% on December 31, 2008 and on June 30 of each of the last three fiscal years. A variance of 10% on our gross margin at December 31, 2008 would have been $65,000.

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Fair Value of Financial Instruments

Our financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable, and bank borrowings. The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable approximate fair value due to the highly liquid nature of these short-term instruments. The allowance for doubtful accounts receivable is assessed quarterly based on sales and the breakout of aged receivables. In June, when the revenue cycle is low, specific customer accounts are chosen for write off. After this adjustment is made, the adequacy of the allowance is considered once again, based on the aging of total accounts receivable and is adjusted if needed. The fair values of the bank borrowings approximate the carrying amounts as of December 31, 2008 and at June 30, 2008 and 2007, and were determined based upon variable interest rates currently available to us for borrowings with similar terms.

Recoverable/Refundable Costs of Gas and Propane Purchases

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

Deferred Tax Asset and Income Tax Accruals

Judgment, uncertainty, and estimates are a significant aspect of the income tax accrual process that accounts for the effects of current and deferred income taxes. Uncertainty associated with the application of tax statutes and regulations and the outcomes of tax audits and appeals require that judgment and estimates be made in the accrual process and in the calculation of effective tax rates.

Effective tax rates (ETR) are also highly impacted by assumptions. ETR calculations are revised every quarter based on best available year-end tax assumptions (income levels, deductions, credits, etc.) by legal entity; adjusted in the following year after returns are filed, with the tax accrual estimates being trued-up to the actual amounts claimed on the tax returns; and further adjusted after examinations by taxing authorities have been completed.

In accordance with the interim reporting rules under Accounting Principles Board 28, a tax expense or benefit is recorded every quarter to adjust our tax expense to the estimated annual effective rate.

We have a net deferred tax asset of $11.5 million. The net deferred tax asset is the result of our recent acquisitions of Frontier Natural Gas and Bangor Gas Company. We may continue to depreciate approximately $82.0 million of their capital assets using the useful lives and rates employed by those companies, resulting in a potential future federal and state income tax benefit of approximately $19.0 million over the 24-year period using applicable federal and state income tax rates. Under Internal Revenue Code Section 382, our ability to recognize tax deductions as a result of this tax benefit will be limited during the first five years following the acquisitions.

Following SFAS No. 109, our balance sheet at December 31, 2007 reflects a gross deferred tax asset of approximately $19.0 million, offset by a valuation allowance of approximately $7.5 million, resulting in a net deferred tax asset associated with the acquisition of approximately $11.5 million. The excess of the net deferred tax assets received in the transactions over their respective purchase prices has been reflected as an extraordinary gain of approximately $6.8 million on our income statement for the twelve months ended June 30, 2008 in accordance with the provisions of SFAS No. 141.

We cannot guarantee that we will be able to generate sufficient future taxable income to realize the $11.5 million net deferred tax asset over the next 24 years. Management will reevaluate the valuation allowance each year on completion of updated estimates of taxable income for future periods, and will further reduce the deferred tax asset by the new valuation allowance if, based on the weight of available evidence, it is more likely than not that we will not realize some portion or all of the deferred tax assets. If the estimates indicate that we are unable to use all or a portion of the net deferred tax asset balance, we will record and charge a greater valuation allowance to income tax expense. Our calculation of the valuation allowance is based on projections of our taxable income in future years. Because of the Internal Revenue Code limitation discussed above, we estimate that less than 10% of the tax benefit will be available to us during the next five years. The valuation allowance is based on the assumption that no tax benefit will be realized after year ten, which means that the majority of the benefit will be realized in years six through ten. Failure to achieve projected levels of profitability could lead to a write-down in the deferred tax asset if the recovery period becomes uncertain or longer than expected and could also lead to the expiration of the deferred tax asset between now and 2032, either of which would adversely affect our operating results and financial position.

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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.

Six Months Ended December 31, 2008 Compared to Six Months Ended December 31, 2007

Net Income — Our net income for the six months ended December 31, 2008 was approximately $1.2 million compared to net income of $7.9 million for the six months ended December 31, 2007, a decrease of $6.7 million, or 85%. This decrease was primarily due to the recognition of an extraordinary gain of $6.8 million in the six months ended December 31, 2007. This gain resulted from the recognition of a deferred tax asset of $11.5 million from the purchase of assets in Maine and North Carolina. (See Note 3 to our Consolidated Financial Statements for further discussion of the deferred tax asset and the extraordinary gain).

Net income from continuing operations for the six months ended December 31, 2008 was approximately $1.2 million compared to net income of $1.1 million for the six months ended December 31, 2007, an increase of approximately $100,000 or 9%. The principal changes that contributed to this improvement in net income from continuing operations are explained below.

Revenues — Our revenues for the six months ended December 31, 2008 were approximately $38.7 million compared to $28.3 million in the six months ended December 31, 2007, an increase of $10.4 million or 36%. The increase was primarily attributable to: (1) a natural gas revenue increase of $7.7 million, of which $4.2 million was due to a full six months of revenue from the recently acquired gas operations in Maine and North Carolina, with the remaining $3.5 million being caused by higher natural gas commodity prices passed through in rates in our existing natural gas operations and (2) an increase in our marketing and production operation’s revenue of $2.7 million, due primarily to higher natural gas commodity prices.

Gross Margin — Gross margin was approximately $11.5 million in the six months ended December 31, 2008 compared to $8.4 million in the six months ended December 31, 2007, an increase of $3.1 million or 37%. Our natural gas operation’s margins increased $2.3 million, of which $2.1 million was due to a full six months of margin contributed by the recently acquired gas operations in Maine and North Carolina. Gross margin from our marketing and production operations increased $836,000, due to a $333,000 increase in margin from gas production, a $624,000 increase in margin from gas marketing, offset by a $121,000 decrease in mark to market revenue.

Expenses Other Than Cost of Sales — Expenses other than cost of sales increased by approximately $1.7 million in the six months ended December 31, 2008 from the six months ended December 31, 2007. On-going expenses related to the full six months of operations in Maine and North Carolina account for $1.5 million of this increase. The remaining $200,000 is due primarily to increases in property taxes and increases in distribution, general and administrative expenses..

Other Income (Loss) — Other income (loss) was a loss of $420,000 for the six months ended December 31, 2008 compared to income of $190,000 for the six months ended December 31, 2007, a decrease of $610,000. Other income in our natural gas operations decreased $30,000, due to lower income from services to customers in our Great Falls, Montana service area of $47,000 offset by an increase of $17,000 from the full six months of operations in Maine and North Carolina. In the six months ended December 31, 2008, other income (loss) also included $41,000 of dividends from marketable securities and acquisition expenses of $585,000 written off as part of the transition to SFAS 141 Revised.

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Interest Expense — Interest expense increased by $147,000 to $677,000 in the six months ended December 31, 2008 from approximately $530,000 in the six months ended December 31, 2007. This increase is due to increased borrowings on our line of credit , caused by the higher costs of gas placed in storage and increased capital expenditures related to the operations in North Carolina and Maine.

Income Tax Expense — Income tax expense from continuing operations increased by $589,000 to $926,000 for the six months ended December 31, 2008 from $274,000 in the six months ended December 31, 2007, due to increased pre-tax income from continuing operations.

Extraordinary Gain

The extraordinary gain of $6.8 million reported in the six months ended December 31, 2007 is related to the acquisitions of Frontier Utilities and Penobscot Natural Gas. We recognized a deferred tax asset, net of valuation allowance, from these acquisitions. The difference between the deferred tax asset, net of a valuation reserve, and our total purchase consideration resulted in the non-taxable extraordinary gain (See Note 3 to our Consolidated Financial Statements).

Discontinued Operations

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

There was no income or loss from discontinued operations for the six months ended December 31, 2008 or the six months ended December 31, 2007.

Fiscal Year Ended June 30, 2008 Compared to Fiscal Year Ended June 30, 2007

Net Income — Our net income for fiscal 2008 was approximately $10.1 million compared to net income of $6.2 million for fiscal 2007, an increase of $3.9 million or 63%. This improvement was primarily due to the recognition of an extraordinary gain of $6.8 million in the second quarter of fiscal 2008. This gain resulted from the recognition of a deferred tax asset of $11.5 million from the purchase of assets in Maine and North Carolina. We expect to realize tax benefits in future years, and therefore recorded a deferred tax asset, (net of valuation reserve) and a corresponding gain, reduced by the total consideration paid for the companies. (See Note 3 to our Consolidated Financial Statements for further discussion of the deferred tax asset.) Coupled with the extraordinary gain were increases due to net income from the recently acquired gas operations in North Carolina of $831,000, from existing natural gas operations of $476,000 and from our gas marketing and production operation of $246,000. These improvements were partially offset by a net loss from the recently acquired gas operations in Maine of $166,000. In addition, net income of $6.2 million in 2007 included $4.0 million of income from discontinued operations.

The principal changes that contributed to the improvement in net income in fiscal 2008 from fiscal 2007 are explained below.

Revenues — Our revenues for fiscal 2008 were approximately $76.8 million compared to $59.4 million in fiscal 2007, an increase of $17.4 million or 29%. The increase was primarily attributable to: (1) a natural gas revenue increase of $12.9 million, of which $10.0 million was due to revenue from the recently acquired gas operations in Maine and North Carolina, with the remaining $2.9 million being caused by higher natural gas commodity prices passed through in rates in our existing natural gas operations and (2) an increase in our marketing and production operation’s revenue of $4.6 million, due primarily to higher sales volumes in our Wyoming market, offset by a decrease in electricity revenue of $180,000.

Gross Margin — Gross margin was approximately $20.7 million in fiscal 2008 compared to $15.6 million in fiscal 2007, an increase of $5.1 million or 33%. Gross margin from our marketing and production operations increased $10,000, due to a $210,000 increase in margin from gas production, offset by decreases in margins from gas marketing and electricity sales of $157,000 and $43,000 respectively. Our natural gas operation’s margins increased $5.1 million, of which $4.8 million was contributed by the recently acquired gas operations in Maine and North Carolina.

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Expenses Other Than Cost of Sales — Expenses other than cost of sales increased by approximately $5.1 million in fiscal 2008 from fiscal 2007. On-going expenses related to operations in Maine and North Carolina account for $3.7 million of this increase. The remaining $1.3 million is due to increases in our distribution, general and administrative costs, including expenses related to the realignment of our management team and other outside legal and consultant fees.

Other Income — Other income was approximately $316,000 in fiscal 2008 compared to $242,000 in fiscal 2007, an increase of $74,000. Other income in our natural gas operations increased $16,000, primarily due to increased income generated in fiscal 2008 for services to customers compared to what had been provided in prior years. Other income in our marketing and production operations remained consistent with last year. Pipeline operations other income decreased $11,000. In fiscal 2008, other income also included $9,000 of dividends from marketable securities and $61,000 of gains from the sale of marketable securities.

Interest Expense — Interest expense decreased by $1.0 million to $1.1 million in fiscal 2008 from approximately $2.1 million in fiscal 2007. This decrease is primarily due to the write-off in fiscal 2007 of debt issue costs associated with the refinancing of long term debt, combined with a decrease in both short-term and long-term borrowings in fiscal 2008.

Income Tax Expense — Income tax expense from continuing operations increased by $60,000 to $1.33 million in fiscal 2008 from $1.27 million in fiscal 2007 due to increased pre-tax income from continuing operations.

Extraordinary Gain

The extraordinary gain of $6.8 million reported in fiscal 2008 is related to the acquisitions of Frontier Utilities and Penobscot Natural Gas. We recognized a deferred tax asset, net of valuation allowance, from these acquisitions. The difference between the deferred tax asset, net of a valuation reserve, and our total purchase consideration resulted in the non-taxable extraordinary gain (See Note 3 to our Condensed Consolidated Financial Statements).

Discontinued Operations

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

Income from discontinued operations before income tax — There was no gain or loss from propane operations in fiscal year 2008 due to the timing of the sale of propane assets. In fiscal 2007, there was income before income taxes of approximately $975,000 from propane operations.

Gain from Disposal of Operations — There was no gain from disposal of operations in fiscal 2008 due to the timing of the sale of the propane assets. On April 1, 2007 we sold our Arizona propane assets for $15.0 million plus working capital, resulting in a pre-tax gain of approximately $5.5 million during fiscal 2007.

Income Tax Expense from discontinued operations— Income tax expense decreased by approximately $2.5 million in fiscal 2008 from fiscal 2007, due to the timing of the sale of propane assets.

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

Net Income — Our net income for fiscal 2007 was approximately $6.2 million compared to net income of $2.3 million for fiscal 2006, an improvement of $3.9 million. The improvement was the result of an increase in margin from continuing operations of $1.3 million, and an increase in income from discontinued operations of $3.5 million. These increases were offset in part by a decrease in other income of $149,000, and increases in operating expenses, interest expense and income taxes of $135,000, $475,000, and $164,000, respectively. The principal changes that contributed to the improvement in net income in fiscal 2007 from fiscal 2006 are explained below.

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Revenues — Our revenues for fiscal 2007 were approximately $59.4 million compared to $74.7 million in fiscal 2006, a decrease of $15.3 million. This decrease was primarily attributable to a decrease in commodity prices. Revenues in our natural gas operations decreased $9.0 million due to lower commodity prices that are passed through to customers, and revenues in our marketing and production operations decreased $6.3 million due to the loss of two large customers and lower commodity prices. Revenue from our pipeline operations decreased $23,000 as a result of lower transport volumes.

Gross Margin — Gross margins (revenues less cost of sales) were approximately $15.6 million in fiscal 2007 compared to $14.3 million in fiscal 2006, an increase of $1.3 million. Gross margin in the Natural Gas segment increased by $606,000 due to higher volumes sold because of a colder winter. Gross margin in our marketing and production operations increased by $686,000, due to new business in our Wyoming market and the renegotiation of expiring contracts on more favorable terms, offset in part by a decrease in mark-to-market revenue and the loss of two large customers. Our pipeline operations’ margin decreased by $13,000 due to lower transport volumes.

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

Other Income — Other income decreased by $149,000 to $241,000 in fiscal 2007 from $391,000 in fiscal 2006. Other income in our natural gas operations decreased $129,000, primarily due to decreased income generated in fiscal 2007 for services to customers compared to what had been provided in prior years. Our marketing and production operations had other income of $1,000 in fiscal 2007 compared to $32,000 in fiscal 2006 primarily generated from payments related to the final settlement of a contract dispute. Our pipeline operations’ other income increased $11,000.

Interest Expense — In fiscal 2007, we refinanced our long term debt, resulting in the expensing of $991,000 of unamortized debt issue costs. This was $742,000 more than the amount amortized in fiscal 2006. This increase in interest due to amortization of debt issue costs was offset by decreased short-term interest expense due to lower short-term borrowings, and resulted in a net increase in interest expense of $475,000, or 29%, to $2.1 million in fiscal 2007 from $1.6 million in fiscal 2006.

Income Tax Expense — Income tax expense from continuing operations increased by $164,000 to $1.3 million in fiscal 2007 from $1.1 million in fiscal 2006 due to increased pre-tax income from continuing operations.

Discontinued Operations

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

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

Gain from Disposal of Operations — On April 1, 2007 we sold our Arizona propane assets for $15.0 million plus working capital, resulting in a pre-tax gain of approximately $5.5 million.

Income Tax (Expense) — Income tax expense increased by $2.2 million to $2.5 million in fiscal 2007 from $266,000 in fiscal 2006 due to higher pre-tax income, including the gain on sale of assets.

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Operating Results of our Natural Gas Operations

For comparative purposes, the following table separates results of operations for our new acquisitions in Maine and North Carolina from the other natural gas operations, for fiscal 2008. Our ownership of Frontier Utilities of North Carolina began October 1, 2007. Our ownership of Penobscot Natural Gas in Bangor, Maine began December 1, 2007. The results of these two operations are combined in the New Acquisitions column below. The Total Less New Acquisitions is comparable to fiscal 2007 results.

For comparision of the six months ended December 31, 2008 and 2007, the results of Frontier Utilities and Penobscot Natural Gas are not presented separately in the table, but are discussed in the narrative below.

	(in thousands)						(in thousands)
	Six Months Ended December 31,						Years Ended June 30,
	2008			2007			2008									2007			2006
													Total Less
										New			New
							Total			Acquisitions			Acquisitions
Natural Gas Operations
Operating revenues	$	28,840		$	21,118		$	59,339		$	9,960		$	49,379		$	46,439		$	55,453
Gas Purchased		19,460			13,972			41,337			5,159			36,178			33,542			43,161
Gross Margin		9,380			7,146			18,002			4,801			13,201			12,897			12,292
Operating expenses		7,879			6,247			13,954			3,681			10,273			9,307			9,160
Operating income		1,501			899			4,048			1,120			2,928			3,590			3,132
Other (income)		(160	)		(190	)		(245	)		7			(252	)		(229	)		(358	)
Income before interest and taxes		1,661			1,089			4,293			1,113			3,180			3,819			3,490
Interest expense		584			462			933			30			903			1,897			1,425
Income before income taxes		1,077			627			3,360			1,083			2,277			1,922			2,065
Income tax (expense)		(519	)		(120	)		(1,091	)		(417	)		(674	)		(653	)		(741	)
Net income	$	558		$	507		$	2,269		$	666		$	1,603		$	1,269		$	1,324

Six Months Ended December 31, 2008 Compared to Six Months Ended December 31, 2007

Natural Gas Revenues and Gross Margins — Operating revenues for the six months ended December 31, 2008 increased to approximately $28.8 million from approximately $21.1 million in the six months ended December 31, 2007. $4.2 million of this $7.7 million increase was due to a full six months of revenue from Frontier and Penobscot for the six months ended December 31, 2008. The remaining $3.5 million increase is caused by higher gas commodity costs in our existing gas operations passed through as increased rates.

Gas purchases in natural gas operations increased to approximately $19.5 million in the six months ended December 31, 2008 from approximately $14.0 million in the six months ended December 31, 2007. $2.1 million of this $5.5 million increase is the result of the full six months of gas purchases from Frontier and Penobscot in the period ending December 31, 2008. The remaining $3.4 million results from higher gas commodity prices in our existing natural gas operations.

Gross margin increased to approximately $9.4 million in the six months ended December 31, 2008 from approximately $7.1 million for the six months ended December 31, 2007. $2.1 million of this $2.3 million increase is the result of the full six months of operations from Frontier and Penobscot in the period ending December 31, 2008.The remaining $200,000 increase is due to increased sales volumes in our existing natural gas operations, primarily in December 2008.

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Natural Gas Operating Expenses — Operating expenses increased to approximately $7.9 million in the six months ended December 31, 2008 from $6.2 million in the six months ended December 31, 2007. $1.5 million of this $1.7 million increase is the result of the full six months of operations from Frontier and Penobscot in the period ending December 31, 2008. The remaining $200,000 increase is due primarily to increases in distribution, general and administrative expenses and property taxes.

Natural Gas Other Income — Other income decreased to approximately $160,000 in the six months ended December 31, 2008 from $190,000 in the six months ended December 31, 2007. Other income from Frontier and Penobscot increased by $17,000, offset by a $47,000 decrease caused by lower service sales in our Great Falls, Montana operation.

Natural Gas Interest Expense — Interest expense increased to approximately $584,000 in the six months ended December 31, 2008 from $462,000 in the six months ended December 31, 2007. This $122,000 increase is due to increased borrowings on our line of credit , caused by the higher costs of gas placed in storage and increased capital expenditures related to Frontier and Penobscot.

Natural Gas Income Tax Benefit (Expense) — Income tax expenses increased to approximately $519,000 in the six months ended December 31, 2008 from $120,000 in the six months ended December 31, 2007. $198,000 of this $399,000 increase is due to higher taxable income from the full six months of operations from Frontier and Penobscot in the period ended December 31, 2008. The remainder is due to an adjustment to tax expense in the six months ended December 31, 2007 for prior year actual tax expense from amounts that had been estimated and accrued.

Fiscal Year Ended June 30, 2008 Compared to Fiscal Year Ended June 30, 2007

Natural Gas Revenues and Gross Margins —Operating revenues without new acquisitions in fiscal 2008 increased to approximately $49.4 million from $46.4 million in fiscal 2007. This $3.0 million increase is caused by higher gas commodity costs passed through as increased rates.

Gas purchases in the natural gas operations (without new acquisitions) increased to $36.2 million in fiscal 2008 from $33.5 million in fiscal 2007. This $2.7 million increase results from higher gas commodity prices, primarily during the 4^th quarter of fiscal 2008.

Gross margin (without new acquisitions) increased to $13.2 million in fiscal 2008 from approximately $12.9 million for fiscal 2007. This $304,000 increase is due to increased sales volumes, primarily in the fourth quarter of fiscal 2008.

Natural Gas Operating Expenses —Operating expenses (without new acquisitions) increased to approximately $10.3 million in fiscal 2008 from $9.3 million in fiscal 2007. This $1.0 million increase is due primarily to increases in distribution, general and administrative expenses, including expenses associated with the realignment of our management team, and increases in outside legal and consulting fees.

Natural Gas Other Income — Other income (without new acquisitions) increased to approximately $252,000 in fiscal 2008 from $229,000 in fiscal 2007. This $23,000 increase was primarily due to increased service sales in Great Falls, Montana and Cody, Wyoming.

Natural Gas Interest Expense — Interest expense (without new acquisitions) decreased to approximately $0.9 million in fiscal 2008 from $1.9 million in fiscal 2007. This $1.0 million decrease was primarily due to the write-off in fiscal 2007 of debt issue costs associated with the refinancing of long term debt, combined with a decrease in both short-term and long-term borrowings in fiscal 2008.

Natural Gas Income Tax Benefit (Expense) — Income tax expenses (without new acquisitions) increased to approximately $674,000 in fiscal 2008 from $653,000 in fiscal 2007, due to an adjustment to tax expense for prior year actual tax expense from amounts that had been estimated and accrued, offset by higher taxable income.

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

Natural Gas Revenues and Gross Margins —Operating revenues in fiscal 2007 decreased to approximately $46.4 million from $55.5 million in fiscal 2006. This $9.1 million decrease was due to lower gas commodity costs and decreased rates, even with higher volumes in the Montana market.

Gas purchases in our natural gas operations decreased to approximately $33.5 million in fiscal 2007 from $43.2 million in fiscal 2006. This $9.7 million decrease in gas cost reflects lower gas commodity prices during fiscal 2007.

Gross margin increased to approximately $12.9 million in fiscal 2007 from $12.3 million for fiscal 2006. This increase of $605,000 corresponds with the colder weather and higher volumes in the Montana regulated utility.

Natural Gas Operating Expenses —Operating expenses increased to approximately $9.3 million in fiscal 2007 from $9.2 million for fiscal 2006. The $147,000 increase is attributed to $154,000 lower general and administrative charges, including the effects of the curtailment of additional contributions to the Retiree Health Plan, offset by increased depreciation and maintenance expense of $59,000 and $20,000 respectively, and a $222,000 increase in property tax expense.

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

Natural Gas Interest Expense — Interest expense increased to $1.9 million in fiscal 2007 from $1.4 million in fiscal 2006. This $471,000 increase was primarily due to the write-off of debt issue costs associated with the refinancing of long term debt, offset by decreased short term borrowings and the associated interest.

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

Operating Results of our Marketing and Production Operations (EWR)

	(in thousands)						(in thousands)
	Six Months Ended December 31						Years Ended June 30
	2008			2007			2008			2007			2006
Energy West Resources
Operating revenues	$	9,692		$	7,008		$	17,124		$	12,545		$	18,832
Gas Purchased		7,770			5,923			14,833			10,264			17,238
Gross Margin		1,922			1,085			2,291			2,281			1,594
Operating expenses		369			321			631			559			711
Operating income		1,553			764			1,660			1,722			883
Other (income)		37			0			(1	)		(2	)		(33	)
Income before interest and taxes		1,516			764			1,661			1,724			916
Interest expense		83			59			125			185			182
Income before income taxes		1,433			704			1,536			1,539			734
Income tax (expense)		(551	)		(135	)		(344	)		(593	)		(284	)
Net income	$	882		$	570		$	1,192		$	946		$	450

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Six Months Ended December 31, 2008 Compared to Six Months Ended December 31, 2007

With the sale of our Arizona propane assets, we have reclassified our former propane operation, Missouri River Propane, into our marketing and production operations. This is a small unregulated propane supply operation that provides propane to our affiliated regulated company accounted for in our natural gas operations. Results from this operation include a net loss for the six months ended December 31, 2008 and 2007 of $1,000 and $16, respectively.

Marketing and Production Revenues and Gross Margins — Revenues in EWR increased $2.7 million to $9.7 million for the six months ended December 31, 2008 from approximately $7.0 million for the six months ended December 31, 2007. Retail gas and propane revenues increased by approximately $2.2 million, due primarily to higher natural gas commodity prices in July, August and September of 2008. Production revenue increased by $549,000 due to an increase in the average price received for volumes produced.

Our marketing and production operations’ gross margin of $1.92 million for the six months ended December 31, 2008 represents an increase of $836,000 from gross margin of $1.08 million earned in the six months ended December 31, 2007. Gross margin from gas production increased by $333,000 due to higher prices received for volumes produced. The margin from gas marketing increased by $624,000 due to relative lower costs of natural gas purchased to supply our sales contracts. These increases are offset by a $121,000 decrease in mark to market revenue.

Marketing and Production Operating Expenses — Operating expenses increased approximately $48,000 to $369,000 for the six months ended December 31, 2008 from $321,000 for the six months ended December 31, 2007. This change is caused primarily by increases in salaries, professional services, and depletion expense.

Marketing and Production Interest Expense — Interest expense increased by $23,000 to $83,000 in the six months ended December 31, 2008 from $60,000 in the six months ended December 31, 2007, due primarily to an increase in short term interest due to higher gas costs for gas placed in storage.

Marketing and Production Income Tax Expense — Income tax expense increased to $551,000 in the six months ended December 31, 2008 from $135,000 in the six months ended December 31, 2007, due to higher taxable income.

Fiscal Year Ended June 30, 2008 Compared to Fiscal Year Ended June 30, 2007

With the sale of our Arizona propane assets, we have reclassified our former propane operation, Missouri River Propane, into our marketing and production operations. This is a small unregulated propane supply operation that provides propane to our affiliated regulated company accounted for in our natural gas operations. Results from this operation include net income for fiscal 2008 of $8,000 and a net loss for fiscal 2007 of $15,000.

Marketing and Production Revenues and Gross Margins — Revenues in EWR increased $4.6 million to $17.1 million in fiscal 2008 from approximately $12.5 million in fiscal 2007. Retail gas and propane revenues increased by approximately $4.5 million, due primarily to higher sales volumes in our Wyoming market. Production revenue increased by $261,000 due to an increase in the average index price received for volumes produced. These increases are offset by a decrease in electricity sales of $180,000 due to the expiration of our last remaining electricity customer contract in June 2007.

Our marketing and production operations’ fiscal 2008 gross margin of $2.29 million represents an increase of $10,000 from gross margin of $2.28 million earned in fiscal 2007. Gross margin from gas production increased by $210,000 due to higher index prices received for volumes produced. This is offset by a decrease in margin from gas marketing of $157,000 due to higher gas supply costs and a decrease in margin from electricity sales of $43,000.

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Marketing and Production Operating Expenses — Operating expenses increased approximately $72,000 to $631,000 for fiscal 2008 from $559,000 for fiscal 2007. This change is caused primarily by increases in legal fees, salaries and depletion expense.

Marketing and Production Other Income — Other income decreased by $1,000 to $1,000 in fiscal 2008 from $2,000 in fiscal 2007.

Marketing and Production Interest Expense — Interest expense decreased by $60,000 to $125,000 in fiscal 2008 from $185,000 in fiscal 2007 due primarily to a decrease in amortization of debt issue costs due to the refinancing of our long-term debt.

Marketing and Production Income Tax Expense — Income tax expense decreased to $344,000 in fiscal 2008 from $593,000 in fiscal 2007 due to an adjustment in tax expense for prior year actual tax expense from amounts that had been estimated and accrued, offset by higher taxable income.

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

With the sale of our Arizona propane assets, we have reclassified our former propane operation, Missouri River Propane, into our marketing and production operations. This is a small unregulated propane supply operation that provides propane to our affiliated regulated company accounted for in our natural gas operations. Results from this operation include losses for fiscals 2007 and 2006 of $15,000 and $9,000 respectively.

Marketing and Production Revenues and Gross Margins — Revenues decreased $6.3 million to $12.5 million in fiscal 2007 from approximately $18.8 million in fiscal 2006. Retail gas revenues decreased by approximately $6.1 million, with $4.5 million of the decrease due to the loss of two large customers and the remainder due to lower index prices for natural gas in fiscal 2007 as compared to fiscal 2006. Mark-to-market revenues decreased by $156,000 in fiscal 2007 versus fiscal 2006.

Marketing and Production’s fiscal 2007 gross margin of $2.3 million represents an increase of $687,000 from gross margin of $1.6 million earned in fiscal 2006. Gross margin from gas production increased by $367,000 due to renegotiation of contracts from low fixed prices to an index based price. Gross margin from retail gas sales increased by $532,000 due to new business in our Wyoming market and the re-negotiation of expiring contracts on more favorable terms. These increases are offset by the $156,000 decrease in mark-to-market revenue mentioned above and the loss of the two large customers.

Marketing and Production Operating Expenses — Operating expenses decreased approximately $152,000 to $559,000 for fiscal 2007 from $711,000 for fiscal 2006. Approximately $115,000 of this savings is due to a wrongful termination settlement expensed in the first quarter of fiscal 2006. The remainder is due to reductions in general administrative expenses.

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

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

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

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Operating Results of our Pipeline Operations

	Six Months Ended December 31						Years Ended June 30
	(in thousands)						(in thousands)
	2008			2007			2008			2007			2006
Pipeline Operations
Operating revenues	$	226		$	187		$	370		$	388		$	411
Gas Purchased		—			—			—			—			—
Gross Margin		226			187			370			388			411
Operating expenses		97			113			233			289			149
Operating income		129			74			137			99			262
Other (income)		—			—			—			(11	)		—
Income before interest and taxes		129			74			137			110			262
Interest expense		9			9			17			42			41
Income before income taxes		120			65			120			68			221
Income tax (expense)		(46	)		(19	)		(40	)		(26	)		(85	)
Net income	$	74		$	46		$	80		$	42		$	136

There have been no material changes in pipeline operations during the six months ended December 31, 2008 compared to the six months ended December 31, 2007, or in fiscal 2008 compared to fiscal 2007, or in fiscal 2007 compared to fiscal 2006, as illustrated in the table above.

Results of our Discontinued Operations

	Year Ended June 30
	2007			2006
	(in thousands)
Discontinued Operations:
Income from discontinued operations before income tax	$	976		$	671
Gain from disposal of operations		5,479			—
Income tax (expense)		(2,500	)		(266	)
Income from discontinued operations	$	3,955		$	405

There was no income or expenses from discontinued operations during the six months ended December 31, 2008 or fiscal 2008.

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

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

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

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

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

Results of our Corporate and Other Operations

	Six months ended December 31,						Year Ended June 30
	2008			2007			2008
	(in thousands)			(in thousands)			(in thousands)
Corporate and Other
Operating revenues	$	—		$	—		$	—
Gas Purchased		—			—			—
Gross Margin		—			—			—
Operating expenses		—			—			441
Operating income		—			—			(441	)
Other (income)		544			—			(70	)
Income before interest and taxes		(544	)		—			(371	)
Interest expense		—			—			—
Income before income taxes		(544	)		—			(371	)
Income tax (expense)		189			—			142
Income before extraordinary item		(355	)		—			(229	)
Extraordinary gain		—			(6,819	)		(6,819	)
Net income	$	(355	)	$	6,819		$	6,590

During fiscal 2008, corporate and other operations was created to accumulate revenues and expenses that were not allocable to our utilities or other operations. Therefore, it does not have standard revenues, purchase costs or gross margin.

Six Months Ended December 31, 2008 Compared to Six Months Ended December 31, 2007

For the six months ended December 31, 2008, corporate and other operations included acquisition expenses of $585,000, written off as part of the transition to SFAS 141 Revised, offset by $41,000 of dividend income.

For the six months ended December 31, 2007, results of corporate and other operations included a $6.8 million extraordinary gain related to the purchases of Frontier Utilities of North Carolina, Inc., and Penobscot Natural Gas, Inc.

Fiscal Year Ended June 30, 2008

Results of corporate and other operations include a $6.8 million extraordinary gain related to the purchases of Frontier Utilities of North Carolina, Inc., and Penobscot Natural Gas, Inc. Also included in corporate and other operations are $65,000 in gains from the sale of marketable securities, $9,000 in dividends from marketable securities, and $441,000 in costs associated with an equity offering that did not occur.

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Consolidated Cash Flow Analysis

Sources and Uses of Cash

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

Our ability to maintain liquidity depends upon our $20.0 million credit facility with Bank of America, shown as line of credit on the accompanying balance sheets. Our use of the Bank of America revolving line of credit was $17.6 million and $6.5 million at December 31, 2008 and 2007, respectively. This change in our cash position is primarily due to increased costs for gas put in storage, increases in our capital expenditures due to expansion in our North Carolina and Maine markets, and the purchase of marketable securities.

We made capital expenditures for continuing operations of $4.7 million and $1.3 million for the six months ended December 31, 2008 and 2007 respectively and $3.9 million, $2.4 million, and $1.9 million during fiscal 2008, 2007, and 2006, respectively. We finance our capital expenditures on an interim basis by the use of our operating cash flow and use of the Bank of America revolving line of credit.

We periodically repay our short-term borrowings under the Bank of America revolving line of credit by using the net proceeds from the sale of long-term debt and equity securities. Long-term debt was $13.0 million at December 31, 2008, and 2007.

On April 1, 2007 we sold certain of our assets related to our Arizona propane business for cash of approximately $15.0 million plus net working capital.

Cash increased to $1,065,000 at December 31, 2008, compared with $796,000 at June 30, 2008. This $269,000 increase in cash for the six months ended December 31, 2008 is compared with the $5.1 million decrease for the six months ended December 31, 2007, and the $6.2 million decrease, $5.4 million increase and $1.5 million increase in cash for the years ended June 30, 2008, June 30, 2007 and June 30, 2006, respectively, as shown in the following table:

	Six Months Ended December 31,						Years Ended June 30,
	2008			2007			2008			2007			2006
Cash (used in) provided by operating activities	$	(8,102,000	)	$	(4,105,000	)	$	5,437,000		$	(905,000	)	$	9,137,000
Cash (used in) provided by investing activities		(7,673,000	)		(6,526,000	)		(9,798,000	)		15,453,000			(2,190,000	)
Cash provided by (used in) financing activities		16,044,000			5,526,000			(1,853,000	)		(9,178,000	)		(5,401,000	)
Increase (decrease) in cash	$	269,000		$	(5,105,000	)	$	(6,214,000	)	$	5,370,000		$	1,546,000

For the six months ended December 31, 2008, cash used in operating activities increased $4.0 million as compared to the six months ended December 31, 2007. Items affecting the use of cash included a decrease in deferred taxes of $7.2 million, a decrease in accounts payable of $2.1 million and an increase in amounts paid for inventory of $1.8 million.

For the year ended June 30, 2008, cash from operating activities increased $6.3 million as compared to the year ended June 30, 2007, primarily because of a deferred tax gain of $6.8 million from the purchase of gas utilities in North Carolina and Maine, and the sale of the Arizona propane assets, which affected 2007 but not 2008. The proceeds from the sale are recorded as cash flows from the sale of assets in investing activities, described below. Other items affecting the use of cash included an increase in payables of $1.0 million and an increase of accounts receivable of $1.3 million. For the year ended June 30, 2007, cash from operating activities decreased $10.0 million as compared to the year ended June 30, 2006, primarily because of the sale of the Arizona propane assets, with both assets and liabilities held for sale decreasing, as well as deferred taxes. The proceeds from the sale are recorded as cash flows from the sale of assets in investing activities, described below. Other items affecting the use of cash included a decrease in other liabilities of $4.1 million, an increase in other assets of $2.1 million, an increase in recoverable cost of gas of $1.3 million, and an increase in net assets held for sale of $1.5 million.

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For the six months ended December 31, 2008, cash used in investing activities increased $1.1 million as compared to the six months ended December 31, 2007, primarily due to an increase in construction expenditures of $3.1 million, the purchase of marketable securities of $2.9 million in the 2008 period, offset by the purchase of the North Carolina and Maine properties of $4.6 million in the 2007 period.

For the year ended June 30, 2008, cash used in investing activities decreased $25.3 million as compared to the year ended June 30, 2007, due primarily to the sale of Arizona assets in 2007 and the purchase of Maine and North Carolina assets in 2008. Additionally, there were increases of $1.5 million in capital expenditures and $1.3 million in the purchase of marketable securities.

For the year ended June 30, 2007, cash provided by investing activities increased $17.6 million as compared to the year ended June 30, 2006, primarily due to the proceeds of $17.9 million from the sale of propane assets and increases in customer advances of $212,000, partially offset by an increase in capital expenditures.

For the six months ended December 31, 2008, cash provided by financing activities increased by $10.5 million as compared to the six months ended December 31, 2007. The net increase in our line of credit of $11.0 million accounts for this increase and is due primarily to much higher prices paid for gas placed in storage. We paid $1.0 million in dividends in the six months ended December 31, 2008 compared to $1.1 million for the six months ended December 31, 2007. The sale of common stock resulted in cash proceeds of $223,000 in the 2007 period, and the repurchase of common stock used $406,000 in the 2008 period compared to $151,000 in the 2007 period.

For the year ended June 30, 2008, cash used in financing activities decreased by $7.3 million as compared to the year ended June 30, 2007. We paid $2.0 million in dividends in fiscal 2008 compared to $1.5 million in fiscal 2007. The sale of common stock resulted in cash proceeds of $334,000, and the repurchase of common stock used $162,000. For the year ended June 30, 2007, cash used in financing activities increased by $3.8 million as compared to the year ended June 30, 2006. We refinanced our long-term debt and paid off a five-year note with Bank of America, which resulted in a net use of cash of $5.7 million. We paid $1.5 million in dividends in fiscal 2007 compared to $495,000 in fiscal 2006. The sale of common stock resulted in cash proceeds of $597,000, and the repurchase of common stock used $2.3 million.

Liquidity and Capital Resources

We fund our operating cash needs, as well as dividend payments and capital expenditures, primarily through cash flow from operating activities and short-term borrowing. Historically, to the extent cash flow has not been sufficient to fund these expenditures, we have used our working capital line of credit. We have greater need for short-term borrowing during periods when internally generated funds are not sufficient to cover all capital and operating requirements, including costs of gas purchased and capital expenditures. In general, our short-term borrowing needs for purchases of gas inventory and capital expenditures are greatest during the summer and fall months and our short-term borrowing needs for financing customer accounts receivable are greatest during the winter months.

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

Long-term Debt — $13.0 million 6.16% Senior Unsecured Notes — On June 29, 2007, we issued $13.0 million aggregate principal amount of our 6.16% Senior Unsecured Notes, due June 29, 2017. The proceeds of these notes were used to refinance our existing notes. With this refinancing, we expensed the remaining debt issue costs of $991,000 in fiscal 2007, and incurred approximately $463,000 in new debt issue costs to be amortized over the life of the new note.

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

The following table represents borrowings under the Bank of America revolving line of credit for each of the fiscal quarters in the six months ending December 31, 2008 and 2007.

	First		Second
	Quarter		Quarter
Six Months Ended December 31, 2008
Minimum borrowing	$	—	$	11,285,000
Maximum borrowing	$	11,685,000	$	18,695,000
Average borrowing	$	5,286,000	$	14,733,000
Six Months Ended December 31, 2007
Minimum borrowing	$	—	$	3,775,000
Maximum borrowing	$	—	$	7,525,000
Average borrowing	$	—	$	4,558,000

The following table represents borrowings under the Bank of America revolving line of credit for each of the fiscal quarters in the years ending June 30, 2008, 2007 and 2006.

	First		Second		Third		Fourth
	Quarter		Quarter		Quarter		Quarter
Year Ended June 30, 2008
Minimum borrowing	$	—	$	3,275,000	$	—	$	—
Maximum borrowing	$	—	$	7,525,000	$	6,525,000	$	—
Average borrowing	$	—	$	4,558,000	$	2,256,000	$	—
Year Ended June 30, 2007
Minimum borrowing	$	—	$	2,900,000	$	—	$	—
Maximum borrowing	$	2,900,000	$	6,200,000	$	3,502,000	$	6,700,000
Average borrowing	$	282,000	$	4,384,000	$	392,000	$	485,000
Year Ended June 30, 2006
Minimum borrowing	$	3,100,000	$	5,200,000	$	—	$	—
Maximum borrowing	$	5,200,000	$	12,250,000	$	12,050,000	$	—
Average borrowing	$	4,167,000	$	9,489,000	$	5,619,000	$	—

Our 6.16% Senior Unsecured Note and Bank of America credit facility agreements contain various covenants, which include, among others, limitations on total dividends and distributions made in the immediately preceding 60-month period to 75% of aggregate consolidated net income for such period, restrictions on certain indebtedness, limitations on asset sales, and maintenance of certain debt-to-capital and interest coverage ratios. At December 31, 2008 and 2007, we believe we are in compliance with the financial covenants under our debt agreements or have received waivers for any defaults.

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At December 31, 2008, we had approximately $1.1 million of cash on hand. In addition, at December 31, 2008, we had $17.6 million of borrowings under the $20.0 million Bank of America revolving line of credit. Our short-term borrowings under our line of credit during the six months ended December 31, 2008 had a daily weighted average interest rate of 4.20% per annum. At December 31, 2008, we had outstanding letters of credit related to supply contracts totaling $1.2 million. These letters of credit reduce our available borrowings on our line of credit.

The $17.6 million of borrowings plus the $1.2 million in outstanding letters of credit, placed our total borrowings at $18.8 million, at December 31, 2008, leaving our borrowing capacity at $1.2 million. As discussed above, this level of borrowings is due primarily to increased costs for gas put in storage, increases in our capital expenditures due to expansion in our North Carolina and Maine markets, and the purchase of marketable securities.

As explained above, the cash flow from our business is seasonal and the line of credit balance in December normally represents the high point of borrowings in our annual cash flow cycle. We expect our cash flow to increase and our borrowings to decrease, beginning in January, as monthly heating bills are paid and the gas we paid for and placed in storage in the summer months is used to supply our customers.

The total amount outstanding under all of our long term debt obligations was approximately $13.0 million at December 31, 2008. The portion of such obligations due within one year was $0 at December 31, 2008.

Capital Expenditures

We conduct ongoing construction activities in all of our utility service areas in order to support expansion, maintenance, and enhancement of our gas pipeline systems. We are actively expanding our systems in North Carolina and Maine to meet the high customer interest in natural gas service in those two service areas. For the six months ended December 31, 2008 and 2007, our total capital expenditures were approximately $4.7 million and $1.4 million, respectively. We estimate future cash requirements for capital expenditures will be as follows:

							Estimated
					Actual		Future Cash
	Six months ended December 31,				Fiscal		Requirements
	2008		2007		2008		2009
	(In thousands)				(In thousands)
Natural Gas Operations	$	4,813	$	1,151	$	3,577	$	5,100
Energy West Resources		69		197		250		—
Pipeline Operations				37		41
Total capital expenditures	$	4,882	$	1,385	$	3,868	$	5,100

We fund our operating cash needs, as well as dividend payments and capital expenditures, primarily through cash flow from operating activities and short-term borrowing. Historically, to the extent cash flow has not been sufficient to fund these expenditures; we have used our working capital line of credit.

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Contractual Obligations

The table below presents contractual balances of our consolidated long-term and short-term debt at the expected maturity dates as of December 31, 2008.

			1 year						After
Contractual Obligations	Total		or less		2-3 years		4-5 years		5 years
Interest payments (a)	$	6,806,800	$	800,800	$	1,601,600	$	1,601,600	$	2,802,800
Long Term Debt (b)		13,000,000		—		—		—		13,000,000
Operating Lease Obligations		241,328		133,367		35,191		10,273		62,497
Transportation and Storage Obligation (c)		9,921,338		4,759,770		2,066,472		1,001,748		2,093,348
Total Obligations	$	29,969,466	$	5,693,937	$	3,703,263	$	2,613,621	$	17,958,645

(a)	Our long-term debt interest payments are projected based on actual interest rates on long-term debt until the underlying debts mature.
(b)	See Note 11 of the Notes to Consolidated Financial Statements for a description of this debt.
(c)	Transportation and storage obligations represent annual commitments with suppliers for periods extending up to nine years. These costs are recoverable in customer rates.

See Note 16 of the Notes to Consolidated Financial Statements for other commitments and contingencies.

Off-Balance-Sheet Arrangements

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

New Accounting Pronouncements

In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements (“SFAS157”). SFAS 157 defines fair value, establishes a framework and gives guidance regarding the methods used for measuring fair value, and expands disclosures about fair value measurements. SFAS 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. On January 1, 2008 we elected to implement this statement with the one-year deferral. The adoption of SFAS No. 157 did not have a material impact on our financial position, results of operations or cash flows. Beginning January 1, 2009, we will adopt the provisions for non-financial assets and non-financial liabilities that are not required or permitted to be measured at fair value on a recurring basis. We are in the process of evaluating this standard with respect to our effect on non-financial assets and liabilities and have not yet determined the impact that it will have on our financial statements upon full adoption in 2009.

In December 2007, the FASB issued SFAS No. 141 (revised 2007), Business Combinations, (“SFAS 141R”). SFAS141R requires an acquirer to recognize and measure the assets acquired, liabilities assumed and any non-controlling interests in the acquiree at the acquisition date, measured at their fair values as of that date, with limited exception. In addition, SFAS141R requires that acquisition-related costs will be generally expensed as incurred and also expands the disclosure requirements for business combinations. The effective date of SFAS 141R is for fiscal years beginning after December 15, 2008. We have adopted SFAS 141R on our consolidated financial statements, effective January 1, 2009. In addition, we have recorded as expense in the six months ended December 31, 2008, $585,000 of acquisition costs related to acquisitions in progress as part of the transition to SFAS 141R.

In December 2007, the FASB issued SFAS No. 160, Accounting for Noncontrolling Interests (“SFAS 160”). SFAS 160 amends Accounting Research Bulletin (ARB) No. 51 and establishes standards of accounting and reporting on non-controlling interests in consolidated statements, provides guidance on accounting for changes in the parent’s ownership interest in a subsidiary, and establishes standards of accounting of the deconsolidation of a subsidiary due to the loss of control. The effective date of SFAS 160 is for fiscal years beginning after December 15, 2008. We are currently evaluating the impact of adopting SFAS 160 on our consolidated financial statements.

In March 2008, the FASB issued FAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities” (“FAS 161”). FAS 161 amends and expands the disclosure requirements of FAS 133, “Accounting for Derivative Instruments and Hedging Activities” and requires qualitative disclosures about objectives and strategies for using derivatives, quantitative disclosures about fair value amounts of gains and losses on derivative instruments, and disclosures about credit-risk-related contingent features in derivative agreements. This statement is effective for financial statements issued for fiscal periods beginning after November 15, 2008. Earlier adoption is not permitted. We do not believe the adoption of FAS 161 will have a material impact on our consolidated financial statements.

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In May 2008, the FASB issued Statement of Financial Accounting Standards No. 162, The Hierarchy of Generally Accepted Accounting Principles (“SFAS 162”). SFAS 162 identifies the sources of accounting principles and the framework for selecting the principles to be used in the preparation of financial statements that are presented in conformity with U.S. generally accepted accounting principles. The Statement becomes effective 60 days following the SEC’s approval of the Public Company Accounting Oversight Board amendments to the auditing literature. The adoption of SFAS 162 will not have an impact on the Company’s financial position, results of operations or cash flows.

In April 2008, the FASB issued FASB Staff Position (“FSP”) FAS 142-3, “Determination of Useful Life of Intangible Assets” (“FSP FAS 142-3”). FSP FAS 142-3 amends the factors that should be considered in developing the renewal or extension assumptions used to determine the useful life of a recognized intangible asset under FAS 142, “Goodwill and Other Intangible Assets.” FSP FAS 142-3 also requires expanded disclosure related to the determination of intangible asset useful lives. FSP FAS 142-3 is effective for fiscal years beginning after December 15, 2008. Earlier adoption is not permitted. We do not believe the adoption of FAS FSP 142-3 will have a material impact on our consolidated financial statements.

In June 2008, the FASB issued FSP No. EITF 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities,” (FSP EITF 03-6-1). FSP EITF 03-6-1 states that unvested share-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities and shall be included in the computation of earnings per share pursuant to the two-class method. FSP EITF 03-6-1 becomes effective for the Company on January 1, 2009. Management has determined that the adoption of FSP EITF 03-6-1 will not have an impact on the Financial Statements.

Item 7A. Quantitative and Qualitative Disclosures about Market Risk

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

Commodity Price Risk

We seek to protect ourself against natural gas price fluctuations by limiting the aggregate level of net open positions that are exposed to market price changes. We manage such open positions with policies that are designed to limit the exposure to market risk, with regular reporting to management of potential financial exposure. Our risk management committee has limited the types of contracts we will consider to those related to physical natural gas deliveries. Therefore, management believes that although revenues and cost of sales are impacted by changes in natural gas prices, our margin is not significantly impacted by these changes.

Credit Risk

Credit risk relates to the risk of loss that we would incur as a result of non-performance by counterparties of their contractual obligations under the various instruments with us. Credit risk may be concentrated to the extent that one or more groups of counterparties have similar economic, industry or other characteristics that would cause their ability to meet contractual obligations to be similarly affected by changes in market or other conditions. In addition, credit risk includes not only the risk that a counter-party may default due to circumstances relating directly to it, but also the risk that a counterparty may default due to circumstances that relate to other market participants that have a direct or indirect relationship with such counterparty. We seek to mitigate credit risk by evaluating the financial strength of potential counterparties. However, despite mitigation efforts, defaults by counterparties may occur from time to time. To date, no such default has occurred.

Item 8. Financial Statements and Supplementary Data.

Our Consolidated Financial Statements begin on page F-1 of this Annual Report on Form 10-K/T.

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

Not applicable.

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Item 9A(T). Controls and Procedures.

Evaluation of Disclosure Controls and Procedures

As of December 31, 2008, we evaluated the effectiveness of the design and operation of our disclosure controls and procedures as defined in Rule 13a-15(e) of the Securities Exchange Act of 1934, as amended. The evaluation was carried out under the supervision of and with the participation of our management, including our principal executive officer and principal financial officer. Based upon this evaluation, our chief executive officer and chief financial officer each concluded that our disclosure controls and procedures were effective as of December 31, 2008.

Management’s Report on Internal Control over Financial Reporting

Management of Energy West is responsible for establishing and maintaining an adequate system of internal control over financial reporting as such term is defined in Exchange Act Rule 13a-15(f). Our internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of our consolidated financial statements for external purposes in accordance with U.S. generally accepted accounting principles defined in the Exchange Act.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements and even when determined to be effective, can only provide reasonable assurance with respect to financial statement preparation and presentation. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

We carried out an evaluation under the supervision and with the participation of our management, including our chief executive officer and chief financial officer, of the effectiveness of our internal control over financial reporting. In making this evaluation, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission for the “Internal Control — Integrated Framework.” Based on that evaluation, our management concluded that our internal control over financial reporting was effective as of December 31, 2008.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting during our last fiscal quarter, the last fiscal quarter of calendar year 2008, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Attestation Report of Independent Registered Public Accounting Firm

This Form 10-K/T does not include an attestation report of our registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by our registered public accounting firm pursuant to temporary rules of the Securities and Exchange Commission that permit us to provide only management’s report on internal control over financial reporting in this Form 10-K/T.

Item 9B. Other Information.

Not applicable.

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PART III

Item 10. Directors, Executive Officers and Corporate Governance

Board of Directors. The names, ages, positions, business experience and principal occupations and employment of each member of the board of directors is set forth below. Each director is expected to serve until our next annual meeting of shareholders.

Name	Age	Position	Director Since
Ian Abrams	63	Director	2008
W.E. ‘Gene’ Argo	67	Director	2002
Steven A. Calabrese	48	Director	2006
Mark D. Grossi	55	Director	2005
Richard M. Osborne	63	Chairman of the Board, Chief Executive Officer and Director	2003
James R. Smail	62	Director	2007
Thomas J. Smith	64	Vice President, Chief Financial Officer and Director	2003
James E. Sprague	48	Director	2006
Michael T. Victor	47	Director	2008

Ian Abrams has been a director since February 2008. He is president of Reserve Ventures, a private real estate investment company for industrial and vacant real estate. He has previously founded, developed and sold several successful business ventures, including a scrap iron and metal business and a transmode container business for the service, repair and trucking of containers. Mr. Abrams serves on the board of North Coast Community Homes, Inc., a non-profit company that develops and maintains housing for individuals with mental retardation and developmental disabilities.

W. E. ‘Gene’ Argo has been a director of Energy West since 2002. He retired in 2004 as the president and general manager of Midwest Energy, Inc., a gas and electric cooperative in Hays, Kansas, in which capacity he had served since 1992.

Steven A. Calabrese has served as a director since 2006. He is the managing partner of Calabrese, Racek and Markos, Inc., which operates a number of commercial real estate companies in Cleveland, Ohio and Tampa, Florida. The firms specialize in evaluation, market research and reporting, management, construction and development services for commercial and industrial real estate. He is also a director of PVF Capital Corp., a publicly-held holding company for Park View Federal Savings Bank in Solon, Ohio, and John D. Oil and Gas Company, a publicly-held oil and gas exploration company in Mentor, Ohio.

Mark D. Grossi has served as a director since 2005. He was employed as executive vice president of Charter One Financial, Inc., a publicly-traded bank holding company, and executive vice president and chief retail banking officer of its subsidiary, Charter One Bank, N.A., from 1992 through 2004. Mr. Grossi is chairman of the board of directors of PVF Capital Corp., a publicly-held holding company for Park View Federal Savings Bank in Solon, Ohio, and a director of John D. Oil and Gas Company, a publicly-held oil and gas exploration company in Mentor, Ohio.

Richard M. Osborne has been a director since 2003, chairman of the board since 2005 and chief executive officer since November 2007. He is the president and chief executive officer of OsAir, Inc., a company he founded in 1963, which operates as a property developer and manufacturer of industrial gases for pipeline delivery, and chairman of each of Northeast Ohio Natural Gas Corporation and Orwell Natural Gas Company, natural gas distribution companies in Mentor, Ohio. Since 1998, Mr. Osborne has been chairman of the board, chief executive officer and a director of John D. Oil and Gas Company, a publicly-held oil and gas exploration company in Mentor, Ohio.

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Thomas J. Smith has served as a director since December 2003 and was appointed our vice president and chief financial officer in November 2007. He also served as our interim president from August 2007 to November 2007. From 1998 to 2006, he was the president, chief operating officer and a director of John D. Oil and Gas Company, a publicly-held oil and gas exploration company in Mentor, Ohio, of which he remains a director. Since 2003, he has been president, treasurer and secretary of Northeast Ohio Natural Gas Corporation, a natural gas distribution company in Mentor, Ohio, and since 2002 he has been president, treasurer and secretary of Orwell Natural Gas Company, a natural gas distribution company in Mentor, Ohio. He is also a director of Corning Natural Gas Corporation, a public utility company in Corning, New York.

James R. Smail has been a director since 2007. For the past thirty years, he has served as chairman of the board of J.R. Smail, Inc., an oil and gas production company he founded. He is also the chairman of the board and owner of The Monitor Bank of Big Prairie, Ohio, an Ohio state-chartered commercial bank. Mr. Smail is a director of John D. Oil and Gas Company, a publicly-held oil and gas exploration company in Mentor, Ohio.

James E. Sprague has served as a director since 2006. He is a certified public accountant and has been employed by Walthall, Drake & Wallace LLP, an accounting firm, since 1987 and is currently a partner and part owner of the firm.

Michael T. Victor has served as a director since December 2008. Since 2006, he has been the president of Lake Erie College, a private liberal arts college located in Painesville, Ohio. From 2002 through 2005, he served as dean of the Walker School of Business, Communication and Hotel, Restaurant and Institutional Management at Mercyhurst College, a private liberal arts college located in Erie, Pennsylvania. Mr. Victor also serves as trustee of the Ohio Foundation of Independent Colleges and Universities.

Executive Officers. The names, ages, positions and certain other information concerning our current executive officers is set forth below.

Name	Age		Position
Kevin J. Degenstein		49	President and Chief Operating Officer
Thomas J. Smith*		64	Vice President and Chief Financial Officer and Director
David C. Shipley		48	Vice President of Eastern Operations
Jed D. Henthorne		49	Vice President of Administration

* Biographical information for Mr. Smith can be found under “Board of Directors.”

Kevin J. Degenstein was appointed president and chief operating officer in June 2008. Previously, he served as our senior vice president of operations since 2006. Prior to joining Energy West, Mr. Degenstein was employed by EN Engineering, an engineering consulting firm, as vice president of distribution from 2002 until 2003 and vice president of technology from 2004 until 2006.

David C. Shipley has served as vice president of eastern operations since May 2007. He also serves as president of our east coast companies in Maine and North Carolina. Prior to joining Energy West, Mr. Shipley was employed by Nicor Gas, a natural gas utility in Illinois, from 1985 to 2007 serving in various management capacities including management and supervision of underground natural gas storage, construction and maintenance, customer service field operations, research and development, quality control, workload management, alliance development and procurement.

Jed D. Henthorne was appointed vice president of administration in 2006. He has been employed by Energy West since 1988 and has served in professional and management capacities related to customer service, information technology and accounting.

Section 16(a) Beneficial Ownership Reporting Compliance. Section 16(a) of the Securities Exchange Act of 1934, as amended, requires our directors and executive officers, and persons who own more than 10% of our common stock, to file with the Securities and Exchange Commission (the SEC) initial reports of ownership and reports of changes in ownership of our common stock. Our officers, directors and greater than 10% shareholders are required by the SEC to furnish us with copies of all Section 16(a) forms they file. In the transition period from July 1, 2008 to December 31, 2008, Ian Abrams did not timely file a Form 4 reporting five awards of shares of our common stock acquired under our deferred compensation plan for directors. Based solely on review of copies of reports furnished to us or written representations that no reports were required, we believe that all other Section 16(a) filing requirements were met in the last fiscal year.

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Code of Business Conduct and Ethics. Energy West has adopted a corporate code of ethics that applies to all our employees and directors, including our principal executive officer, principal financial officer, principal accounting officer, and persons performing similar functions. Our code of business conduct fully complies with the requirements of the Sarbanes-Oxley Act of 2002. Specifically, the code is reasonably designed to deter wrongdoing and promote:

• honest and ethical conduct, including the ethical handling of actual or apparent conflicts of interest between personal and professional relationships,

• full, fair, accurate, timely and understandable disclosure in public reports,

• compliance with applicable governmental laws rules and regulations,

• prompt internal reporting of code violations to an appropriate person identified in the code, and

• accountability for adherence to the code.

A copy of the code is available on our website at www.ewst.com. Any amendments or waivers to the code that apply to our principal executive officer, principal financial officer, principal accounting officer, and persons performing similar functions will be promptly disclosed to our shareholders.

Audit Committee Report. In accordance with its written charter that was approved and adopted by our board, our audit committee assists the board in fulfilling its responsibility of overseeing the quality and integrity of our accounting, auditing and financial reporting practices. A copy of the audit committee charter is available on our website at www.ewst.com. The audit committee is directly responsible for the appointment of Energy West’s independent public accounting firm and is charged with reviewing and approving all services performed for Energy West by the independent accounting firm and for reviewing the accounting firm’s fees. The audit committee reviews the independent accounting firm’s internal quality control procedures, reviews all relationships between the independent accounting firm and Energy West in order to assess the accounting firm’s independence, and monitors compliance with our policy regarding non-audit services, if any, rendered by the independent accounting firm. In addition, the audit committee ensures the regular rotation of the lead audit partner. The audit committee reviews management’s programs to monitor compliance with our policies on business ethics and risk management. The audit committee establishes procedures to receive and respond to complaints received by Energy West regarding accounting, internal accounting controls or auditing matters and allows for the confidential, anonymous submission of concerns by employees.

The audit committee is comprised of Mr. Sprague, the committee’s chairman, Mr. Grossi and Mr. Smail. The committee met five times in the transition period July 1, 2008 to December 31, 2008. The audit committee’s current composition satisfies the regulations of Nasdaq governing audit committee composition, including the requirement that all audit committee members be “independent directors” as defined in Nasdaq listing standards. In addition, each member of the audit committee is able to read and understand financial statements, including balance sheets, income statements and cash flow statements. The board has determined that Mr. Sprague is an “audit committee financial expert” under applicable SEC rules through his experience as a certified public accountant and his position as a partner in the accounting firm of Walthall, Drake & Wallace LLP. In addition, Mr. Sprague is deemed to be “financially sophisticated” under applicable Nasdaq rules. The audit committee reviews and reassesses its charter at least annually and will obtain the approval of the board for any proposed changes to its charter.

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The audit committee oversees management’s implementation of internal controls and procedures for financial reporting designed to ensure the integrity and accuracy of our financial statements and to ensure that we are able to timely record, process and report the information required for public disclosure. In fulfilling its oversight responsibilities, the audit committee reviewed and discussed the audited financial statements with management and Hein & Associates LLP, our independent accounting firm. The audit committee also discussed with Hein & Associates the matters required by Statement on Auditing Standards No. 61, “Communication with Audit Committees.” The audit committee reviewed with Hein & Associates, which is responsible for expressing an opinion on the conformity of our audited financial statements with accounting principles generally accepted in the United States, its judgment as to the quality, not just the acceptability, of our accounting principles and other matters as are required to be discussed with the audit committee pursuant to generally accepted auditing standards.

In discharging its oversight responsibility as to the audit process, the audit committee obtained from our independent accounting firm a formal written statement describing all relationships between the independent accounting firm and us that might bear on the accounting firm’s independence consistent with Independence Standards Board Standard No. 1, “Independence Discussions with Audit Committees,” and discussed with the accounting firm any relationships that may impact its objectivity and independence. In considering the accounting firm’s independence, the audit committee also considered whether the non-audit services performed by the accounting firm on our behalf were compatible with maintaining the independence of the accounting firm.

In reliance upon (1) the audit committee’s reviews and discussions with management and Hein & Associates, (2) management’s assessment of the effectiveness of our internal control over financial reporting, and (3) the receipt of an opinion from Hein & Associates, dated March 31, 2009, stating that the Energy West’s financial statements for the transition period ended December 31, 2008 are presented fairly, in all material respects, in conformity with U.S. generally accepted accounting principles, the audit committee recommended to our board that these audited financial statements be included in this Form 10-K/T for the transition period ended December 31, 2008, for filing with the SEC.

Audit Committee

James E. Sprague, Chairman
Mark D. Grossi
James R. Smail

ITEM 11. Executive Compensation

Summary Compensation Table. The following table summarizes the compensation paid by us to our chairman and chief executive officer and our most highly compensated executive officers. For convenience, we have summarized the compensation paid in the calendar year January 1, 2008 to December 31, 2008 as opposed to the six month period covered by this transition report.

							Option		All Other
Name and			Salary		Bonus		Awards		Compensation		Total
Principal Position	Year		($)		($)		($)		($)		($)
Richard M. Osborne		2008		—		—		—		24,000		24,000
Chairman and Chief Executive Officer(1)
Kevin J. Degenstein,		2008		170,771		25,000		—		7,775		203,546
President and Chief Operating Officer
David C. Shipley,		2008		132,750		32,500		—		23,037		188,287
Vice President of Eastern Operations(2)
James W. Garrett, Former		2008		170,000		—		—		5,494		175,494
Vice President of Business Development(3)

(1)	Mr. Osborne does not receive compensation for service as our chairman and chief executive officer. “All other compensation” consists of fees paid to Mr. Osborne for service as a director.
(2)	Mr. Shipley was appointed as our vice president of eastern operations in May 2007. “All other compensation” consists of relocation expenses.
(3)	Mr. Garrett resigned as our vice president of business development effective January 31, 2009.

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Employment and Separation Agreements.

Kevin J. Degenstein. On August 25, 2006, we entered into an employment agreement with Mr. Degenstein to serve as our senior vice president of operations. On June 12, 2008, Mr. Degenstein was named our president and chief operating officer. The term of Mr. Degenstein’s employment agreement commenced on September 18, 2006 and will continue until terminated as a result of Mr. Degenstein’s death or disability, by Energy West for “cause” (as defined in the employment agreement), by Energy West( without “cause,” or by Mr. Degenstein, either with or without “good reason,” as defined in the employment agreement.

Mr. Degenstein is eligible to receive a base salary of $150,000 per year pursuant to his employment agreement, subject to increase at the discretion of the board. For the fiscal year 2009, the compensation committee of the board agreed to increase Mr. Degenstein’s annual salary to $182,000 as a result of Mr. Degenstein’s performance and his promotion to president and chief operating officer. The compensation committee also determined that Mr. Degenstein will be eligible to receive a bonus of up to 50% of his annual salary depending on Energy West’s net income, subject to modification upon the recommendation of our chief executive officer with the approval of the compensation committee or the entire board.

Mr. Degenstein is eligible to receive option grants under Energy West’s stock option plans and to participate in all other savings, retirement, and welfare plans that are applicable generally to our employees and senior executive officers. The compensation committee has approved the award to Mr. Degenstein of options to purchase 10,000 shares of Energy West’s common stock in each of 2008, 2009, and 2010, with each individual option grant to be approved by the committee on the date of grant. Mr. Degenstein is also entitled to receive vacation and fringe benefits in accordance with Energy West’s plans, practices, programs, and policies.

Upon termination of employment for any reason, we will pay Mr. Degenstein a lump sum of cash equal to his unpaid salary through the date of termination plus accrued but unpaid vacation pay. In addition, we will provide benefit continuation or conversion rights, as provided under our benefit plans, and vested benefits under our benefit plans. If the employment agreement is terminated by Energy West without cause or terminated by Mr. Degenstein for “good reason” (if Energy West changes his title, materially reduces his duties or authority, assigns duties inconsistent with his duties, requires him to report internally other than to the president or chief executive officer, or requires him to relocate from the Great Falls area), Mr. Degenstein will be entitled to severance compensation equal to his annual base salary payable monthly for 12 months following the date of termination. Payment of these severance benefits is expressly conditioned upon receipt by Energy West of an enforceable waiver and release from Mr. Degenstein in a form reasonably satisfactory to Energy West.

The employment agreement also includes provisions that (1) prohibit Mr. Degenstein from disclosing Energy West’s confidential information, (2) require him to avoid conflicts of interest and disclose to the board any facts that might involve a conflict of interest with Energy West, and (3) prohibit him from soliciting employees, customers, or clients of Energy West during the term of the agreement and for a period of two years following the termination of the agreement.

David C. Shipley. On April 13, 2007, we entered into an employment agreement with Mr. Shipley to serve as our vice president of eastern operations. The term of Mr. Shipley’s employment began on May 18, 2007 and will continue until terminated as a result of Mr. Shipley’s death or disability, by Energy West for “cause” (as defined in the employment agreement), by Energy West without “cause,” or by Mr. Shipley, either with or without “good reason,” as defined below.

Pursuant to the employment agreement, Mr. Shipley will receive a base salary of $130,000, subject to review and increase annually at the discretion of the board. For the fiscal year 2009, the compensation committee of the board agreed to increase Mr. Shipley’s annual salary to $134,000. Mr. Shipley is also eligible to receive a discretionary bonus targeted at 20% of his annual base salary, based on performance criteria determined by the board.

Mr. Shipley is eligible to receive option grants under Energy West’s stock option plans and to participate in all other savings, retirement, and welfare plans that are applicable generally to our employees and senior executive officers. Mr. Shipley is also entitled to receive vacation and fringe benefits in accordance with Energy West’s plans, practices, programs and policies.

Upon termination of employment for any reason, we will pay Mr. Shipley a lump sum of cash equal to his unpaid salary through the date of termination plus accrued but unpaid vacation pay. In addition, we will provide benefit continuation or conversion rights, as provided under our benefit plans, and vested benefits under our benefit plans. If the employment agreement is terminated by Energy West without cause or terminated by Mr. Shipley for “good reason” (if Energy West diminishes his title, materially reduces his duties or authority, assigns duties inconsistent with his duties, requires him to report internally other than to the president or chief executive officer, or requires him to relocate from the North Carolina area), Mr. Shipley will be entitled to severance compensation equal to his annual base salary payable monthly for 12 months following the date of termination, medical benefits at active employee rates for 12 months following the date of termination and up to $10,000 for outplacement services. If such termination occurs within 24 months of the commencement of Mr. Shipley’s employment, Energy West will reimburse Mr. Shipley for moving expenses incurred during the six month period following termination up to a maximum of $20,000. Payment of these severance benefits is expressly conditioned upon receipt by Energy West of an enforceable waiver and release from Mr. Shipley in a form reasonably satisfactory to Energy West.

The employment agreement also includes provisions that (1) prohibit Mr. Shipley from disclosing Energy West’s confidential information, (2) require him to avoid conflicts of interest and disclose to the board any facts that might involve a conflict of interest with Energy West, and (3) prohibit him from soliciting employees, customers, or clients of Energy West during the term of the agreement and for a period of two years following the termination of Mr. Shipley’s employment for any reason.

None of the other current executive officers in our summary compensation table have employment, termination or change in control agreements.

Benefit Plans.

401(k) Plan. We maintain a tax-qualified profit sharing plan under Section 401(k) of the Internal Revenue Code that covers substantially all of our employees. The plan generally provides for voluntary employee pre-tax contributions of employee compensation, a profit sharing contribution of 3% allocated to each employee based on compensation and a discretionary profit sharing contribution of up to 7% of employee compensation. Profit sharing contributions are approved by our board of directors. The plan also provides a company matching contribution in the form of shares of Energy West common stock equal to 10% of each employee’s elective deferrals in the plan. In the transition period July 1, 2008 to December 31, 2008, we made total profit sharing contributions of $170,766 and contributed shares of our common stock valued at $17,493.

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Employee Stock Ownership Plan. We maintain an Employee Stock Ownership Plan (ESOP) that covers substantially all of our employees. The ESOP receives contributions of our common stock from Energy West each year as determined by our board of directors. The contribution, if any, is recorded based on the current market price of our common stock. We did not make any contributions to the ESOP in the transition period July 1, 2008 to December 31, 2008.

Retiree Health Plan. We sponsored a defined post-retirement health benefit plan providing health and life insurance benefits to eligible retirees. The plan pays eligible retirees (post-65 years of age) $125 per month in lieu of contracting for health and life insurance benefits. The amount of this payment is fixed and will not increase with medical trends or inflation. In addition, the plan allows retirees between the ages of 60 and 65 and their spouses to remain on the same medical plan as active employees by contributing 125% of the current COBRA rate to retain this coverage. The 25% in excess of the current COBRA rate is held in a VEBA trust account, and benefits for this plan are paid from assets held in the VEBA trust account. In 2006, we discontinued contributions to the plan and are no longer required to fund the plan. As of December 31, 2008, the value of the plan assets was $6,197,405. The assets remaining in the VEBA trust account will be used to fund the plan until these assets are exhausted.

Dividend Reinvestment Policy. We have a policy that provides for any employee who owns shares of our common stock in our 401(k) plan or ESOP the opportunity to reinvest any dividends for additional shares of our common stock.

Outstanding Equity Awards at December 31, 2008.

The following table summarizes information with respect to the stock options held by our most highly compensated executive officers as of December 31, 2008.

	Number of		Number of
	Securities		Securities
	Underlying		Underlying
	Unexercised		Unexercised		Option		Option
	Options		Options		Exercise Price		Expiration
Name	Exercisable		Unexercisable		($)		Date
James W. Garrett		7,500		7,500		9.93		12/1/2017	(1)
Kevin J. Degenstein		2,500		7,500		7.10		12/1/2018	(2)

(1)	The option is exercisable as follows: 25% of the shares on 12/1/2007; 25% of the shares on 12/1/2008; 25% of the shares on 12/1/2009 and 25% of the shares on 12/1/2010.
(2)	The option is exercisable as follows: 25% of the shares on 12/1/2008; 25% of the shares on 12/1/2009; 25% of the shares on 12/1/2010 and 25% of the shares on 12/1/2011.

Director Compensation. We pay each board member except Thomas J. Smith, who serves as our vice president and chief financial officer, a monthly fee of $2,000 regardless of board or committee meetings held. Directors may elect to participate in Energy West’s deferred compensation plan for directors which allows directors to receive these fees in Energy West stock, either currently or on a deferred basis. We also reimburse all directors for expenses incurred in connection with their service as directors, including travel, meals and lodging.

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The following table summarizes information with respect to the compensation paid to our directors in the calendar year January 1, 2008 to December 31, 2008. The table does not include directors who are also our most highly compensated executive officers, namely Richard M. Osborne.

	Fees Earned or		Stock		All Other
	Paid in Cash		Awards(1)		Compensation		Total
Name	($)		($)		($)		($)
Ian Abrams		14,000		10,000		—		24,000
W.E. ‘Gene’ Argo		24,000		—		—		24,000
Steven A. Calabrese		24,000		—		—		24,000
Michael I. German(2)		18,000						18,000
Mark D. Grossi		24,000		—		—		24,000
James R. Smail		24,000		—		—		24,000
Thomas J. Smith(3)		—		—		—		—
James E. Sprague		24,000		—		—		24,000
Michael T. Victor(4)		—		—		—		—

(1)	Mr. Abrams elected to receive compensation in shares of our common stock as of September 2008. Amounts reflect the number of shares issued using the closing market price on the date of issuance to fulfill the monthly fee to Mr. Abrams.
(2)	Mr. German was not nominated for re-election to our board of directors at our 2008 annual meeting of shareholders held on December 11, 2008.
(3)	Mr. Smith, our chief financial officer, does not receive compensation for serving as a director.
(4)	Mr. Victor was elected director at our 2008 annual meeting of shareholders held on December 11, 2008.

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

Security Ownership of Principal Shareholders and Management. The following table sets forth, as of February 28, 2009, information regarding the beneficial ownership of our common stock by each shareholder known by us to be the beneficial owner of more than 5% of the stock, each director, each current and former executive officer in our summary compensation table, and all our current directors and officers as a group.

	Beneficial Ownership(1)
Names and Address(2)	Shares		Stock Options(3)		Total		Percentage
Richard M. Osborne(4)		922,271		—		922,271		21.2	%
Steven A. Calabrese(5)		211,496		—		211,496		4.9	%
James R. Smail(6)		32,550		—		32,550			*
Thomas J. Smith		9,750		—		9,750			*
Ian Abrams		6,600		—		6,600
Mark D. Grossi(7)		4,860		—		4,860			*
W.E. ‘Gene’ Argo		1,275		—		1,275			*
James E. Sprague		465		—		465			*
Kevin J. Degenstein(8)		347		2,500		2,847			*
David C. Shipley(8)		118		—		118			*
Michael T. Victor		—		—		—		—
James W. Garrett		1,000		7,500		8,500			*
2653 Dodd Rd. Willoughby Hills OH 44094
All directors and executive officers as a group		1,205,799		10,000		1,215,799		27.9	%
(13 individuals)

* Less than 1%

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(1)	Unless otherwise indicated, we believe that all persons named in the table have sole investment and voting power over the shares of stock owned.
(2)	Unless otherwise indicated, the address of each of the beneficial owners identified is c/o Energy West, Incorporated, 1 First Avenue South, Great Falls, Montana 59401.
(3)	Shares of common stock the beneficial owners have the right to acquire through stock options that are or will become exercisable within 60 days.
(4)	Shares owned by the Richard M. Osborne Trust, an Ohio trust of which Mr. Osborne is sole trustee.
(5)	Includes (1) 57,580 shares held by the Steven A. Calabrese Profit Sharing Trust, an Ohio trust of which Mr. Calabrese is co-trustee, (2) 16,646 shares held by CCAG Limited Partnership, an Ohio limited partnership of which Mr. Calabrese is the president and only member of the board of directors, and (3) 17,100 shares held by Mr. Calabrese’s minor children. Mr. Calabrese disclaims beneficial ownership of the shares held by his minor children.
(6)	Shares are held by J.R. Smail, Inc., an Ohio corporation of which Mr. Smail is chairman and sole shareholder.
(7)	Shares are held by Westwood Douglas LLC, a limited liability company of which Mr. Grossi is managing member and beneficial owner.
(8)	Shares are held in our 401(k) plan. Pursuant to the terms of the plan, each participant has the right to direct the voting of the shares held by the plan.

Equity Compensation Plan Information. The Energy West, Incorporated 2002 Stock Option Plan provides for the issuance of up to 300,000 shares of common stock to certain key employees. As of December 31, 2008, there were 29,500 options outstanding and the maximum number of shares available for future grants under the plan was 63,500 shares. Additionally, our 1992 Stock Option Plan, which expired in September 2002, provided for the issuance of up to 100,000 shares of common stock pursuant to options issuable to certain key employees. Under 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, 110% of the fair market value if the employee owns more than 10% of our outstanding common stock). Options granted under these plans vest over four to five years and are exercisable over a five to ten year period from the date of issuance. When the 1992 plan expired in September 2002, 12,600 shares remained unissued and were no longer available for issuance.

						Number of
						securities
						remaining available
	Number of					for future issuance
	securities					under equity
	to be issued upon		Weighted-average			compensation plans
	exercise of		exercise price of			(excluding securities
	outstanding options,		outstanding options,			reflected in the first
Plan category	warrants and rights		warrants and rights			column)
Equity compensation plans approved by security holders*		177,453		$	8.42		65,547
Equity compensation plans not approved by security holders		—			—		—
Total		177,453		$	8.42		65,547

* Includes 150,000 shares available for future issuance to our directors pursuant to a policy that permitted directors to defer payment of fees in stock for service as a director, 147,953 shares of which have been issued or allocated for issuance pursuant to the policy.

Item 13. Certain Relationships and Related Transactions and Director Independence

Certain Relationships and Related Transactions. Through our subsidiary, Energy West Resources, Inc., we own a 19.8% interest in Kykuit Resources, LLC, a developer of oil, gas and mineral leases in which it holds ownership interests. Certain related persons also have interests in Kykuit.

• Richard M. Osborne, our chairman of the board and chief executive officer, has invested approximately $518,000 and owns an 18.2% membership interest in Kykuit.

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• Steven A. Calabrese, a member of our board of directors, has an interest in Kykuit as a result of his involvement with CCAG Limited Partnership (CCAG) and R.C. Enterprises & Development, LLC (R.C. Enterprises). CCAG and R.C. Enterprises are members of Kykuit, each owning approximately a 5.5% membership interest in Kykuit and each having invested approximately $156,750. Mr. Calabrese’s interest arises from his position as president of TGF Corporation, the general partner of CCAG, and as managing member of R.C. Enterprises.

• John D. Oil and Gas Company, a publicly-held oil and gas exploration company, is the managing member of Kykuit and owns 19% of the membership interests. Mr. Osborne is the chairman of the board and chief executive officer of John D. Oil and Gas Company, and Energy West directors Mr. Calabrese, Mark D. Grossi, James R. Smail and Thomas J. Smith are directors of John D. Oil and Gas Company.

Our investment in Kykuit was ratified by disinterested and independent directors Ian Abrams and W.E. Argo as well as all other members of our board of directors.

On February 25, 2008, we entered a lease agreement, effective as of January 1, 2008, with OsAir, Inc. whereby we agreed to lease approximately 1,028 square feet of space located in Mentor, Ohio from OsAir. The lease has a term of three years. Mr. Osborne is the president and chief executive officer of OsAir, Inc. The lease was approved at a meeting of our board of directors by disinterested and independent director W.E. Argo as well as the other members of the board.

On September 12, 2008, we entered into a stock purchase agreement with Richard M. Osborne, Trustee, Rebecca Howell, Stephen G. Rigo, Marty Whelan and Thomas J. Smith whereby we agreed to purchase all of the common stock of Lightning Pipeline Co., Great Plains Natural Gas Company, Brainard Gas Corp. and all of the membership units of Great Plains Land Development Co., Ltd., which companies are primarily owned by an entity controlled by Mr. Osborne and wholly-owned by the sellers, for a purchase price of $34.3 million. Pursuant to the agreement, we will acquire Orwell Natural Gas Company, a wholly-owned subsidiary of Lightening Pipeline and Northeast Ohio Natural Gas Corp., a wholly-owned subsidiary of Great Plains. Orwell, NEO and Brainard are natural gas distribution companies that serve approximately 21,000 customers in Northeastern Ohio and Western Pennsylvania. This acquisition will increase our customers by more than 50%.

Mr. Osborne is chairman, chief executive officer and a director, Mr. Smith is vice president, chief financial officer and a director, and Ms. Howell is secretary of Energy West. The agreement was negotiated on behalf of Energy West by a special committee comprised solely of independent directors with the assistance of independent financial and legal advisors. The special committee received a fairness opinion from Houlihan Smith & Company, Inc. The agreement was approved by our board of directors, upon unanimous recommendation of the special committee. For more information regarding the purchase agreement, see “Pending Acquisitions” in this Form 10-K/T.

We believe that the terms of the transactions and the agreements described above are on terms at least as favorable as those which we could have obtained from unrelated parties. In accordance with our policy adopted by the board of directors, on-going and future transactions with related parties will be

• on terms at least as favorable as those that we would be able to obtain from unrelated parties,

• for bona fide business purposes, and

• reviewed and approved by the audit committee or other independent directors in accordance with the Montana Business Corporation Act after full disclosure of the existence and nature of the conflicting interest in the related party transaction by the director involved in the transaction.

Director Independence. The board of directors has determined and confirmed that each of Mr. Abrams, Mr. Argo, Mr. Calabrese, Mr. Grossi, Mr. Smail, Mr. Sprague and Mr. Victor do not have a material relationship with Energy West that would interfere with the exercise of independent judgment and are independent pursuant to applicable laws and regulations and the listing standards of Nasdaq.

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Item 14. Principal Accountant Fees and Services

The following is a summary of the aggregate fees billed to us for the six months ended December 31, 2008 and the fiscal years ended June 30, 2008 and June 30, 2007 by our independent registered public accountant, Hein & Associates LLP.

	Six Months
	Ended		Year ended		Year Ended
	December 31, 2008		June 30, 2008		June 30, 2007
Audit Fees	$	184,000	$	277,000	$	137,280
Audit-Related Fees		-0-		19,000		21,923
Tax Fees		6,300		34,000		40,588
All Other Fees		-0-		-0-		12,159
Total	$	190,300	$	330,000	$	211,950

Audit Fees. These fees are for professional services rendered by Hein & Associates for the audit of our annual consolidated financial statements, the review of financial statements included in our quarterly reports on Form 10-Q, and services that are typically rendered in connection with statutory and regulatory filings or engagements.

Audit-Related Fees. These included fees related to derivative contracts. From time to time, in order to mitigate the risk of natural gas market price volatility related to firm commitments to purchase or sell natural gas, we enter into hedging arrangements in the form of derivative contracts. Quoted market prices for natural gas derivative contracts of Energy West and our subsidiaries are generally not available. Therefore, to determine the fair value of natural gas derivative contracts, we use internally developed valuation models that incorporate independently available current and forecasted pricing information. These also included fees related to the Federal Energy Regulatory Commission audit of a subsidiary company.

Tax Fees. These are fees for professional services rendered by Hein & Associates with respect to advisory services related to the preparation of income tax returns.

All Other Fees. These are fees for advisory services related to the sale of assets and acquisitions.

The audit committee pre-approved all services performed by Hein & Associates and authorized us to pay the fees billed to us by Hein & Associates in the six months ended December 31, 2008, fiscal 2008 and 2007.

PART IV

Item 15. Exhibits and Financial Statement Schedules.

(a) Financial Statements:

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

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(b) Exhibit Index.

3.1(a)		Restated Articles of Incorporation. Filed as 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 and incorporated herein by reference
3.1(b)		Articles of Amendment to the Articles of Incorporation dated January 28, 2008. Filed as Exhibit 3.1 to the Registrant’s Current Report on Form 8-K dated February 1, 2008 and incorporated herein by reference
3.1(c)		Articles of Amendment to the Articles of Incorporation dated December 5, 2007. Filed as Exhibit 3.1(e) to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended December 31, 2007 and incorporated herein by reference
3.1(d)		Articles of Amendment to the Articles of Incorporation dated May 29, 2007. Filed as Exhibit 3.1 to the Registrant’s Current Report on Form 8-K, filed on June 4, 2007, and incorporated herein by reference
3.2		Amended and Restated Bylaws. Filed as Exhibit 3.2 to the Registrant’s Current Report on Form 8-K on March 5, 2004 and incorporated herein by reference
3.2(a)		Amendment No. 3 to Amended and Restated Bylaws dated August 12, 2008. Filed as Exhibit 3.1 to the Registrant’s Current Report on Form 8-K dated August 12, 2008 and incorporated herein by reference
3.2(b)		Amendment No. 2 to Amended and Restated Bylaws dated April 10, 2008. Filed as Exhibit 3.1 to the Registrant’s Current Report on Form 8-K dated April 10, 2008 and incorporated herein by reference
3.2(c)		Amendment No. 1 to Amended and Restated Bylaws dated November 14, 2007. Filed as Exhibit 3.1 to the Registrant’s Current Report on Form 8-K dated November 14, 2007 and incorporated herein by reference
10.1		Satisfaction and Discharge of Indenture dated June 22, 2007, between the Registrant and HSBC Bank USA, National Association, as Successor Trustee for the Series 1997 Notes. Filed as Exhibit 10.1 to the Registrant’s Current Report on Form 8-K, filed July 5, 2007, and incorporated herein by reference
10.2		Satisfaction and Discharge of Indenture dated June 22, 2007, between the Registrant and US Bank National Association, as Successor Trustee for the Series 1993 Notes. Filed as Exhibit 10.2 to the Registrant’s Current Report on Form 8-K, filed July 5, 2007, and incorporated herein by reference.
10.3		Discharge of Obligor under Indenture dated June 22, 2007, between the Registrant and HSBC Bank USA, National Association, as Successor Trustee for the Series 1992-B Bonds. Filed as Exhibit 10.3 to the Registrant’s Current Report on Form 8-K, filed July 5, 2007, and incorporated herein by reference
10.4		Note Purchase Agreement dated June 29, 2007, between the Registrant and various Purchasers relating to 6.16% Senior Unsecured Notes due June 29, 2017. Filed as Exhibit 10.4 to the Registrant’s Current Report on Form 8-K, filed July 5, 2007, and incorporated herein by reference
10.5		Credit Agreement dated as of June 29, 2007, by and among the Registrant and various financial institutions and LaSalle Bank National Association. Filed as Exhibit 10.5 to the Registrant’s Current Report on Form 8-K, filed July 5, 2007, and incorporated herein by reference.
10.6		Amendment dated October 22, 2007 to the Credit Agreement among the Registrant, various financial institutions and LaSalle Bank National Association, as agent. Filed as Exhibit 10.1 to the Registrant’s Current Report on Form 8-K dated October 22, 2007 and incorporated herein by reference
10.7	†	Energy West, Incorporated 2002 Stock Option Plan. Filed as Appendix A to the Registrant’s Proxy Statement on Schedule 14A, filed on October 30, 2002, and incorporated herein by reference
10.8	*†	First Amendment to Energy West Incorporated 2002 Stock Option Plan
10.9	†	Employee Stock Ownership Plan Trust Agreement. Filed as Exhibit 10.2 to Registration Statement on Form S-1 (File No. 33-1672) is incorporated herein by reference
10.10	†	Management Incentive Plan. Filed as 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, and incorporated herein by reference

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10.11	†	Energy West Senior Management Incentive Plan. Filed as Exhibit 10.19 to the Registrant’s Annual Report on Form 10-K for the year ended June 30, 2002, filed on September 30, 2002, and incorporated herein by reference
10.12	†	Energy West Incorporated Deferred Compensation Plan for Directors. Filed as Exhibit 10.20 to the Registrant’s Annual Report on Form 10-K for the year ended June 30, 2002, filed on September 30, 2002, and incorporated herein by reference
10.13	*†	Amended and Restated Energy West Incorporated Deferred Compensation Plan for Directors
10.14		Amended and Restated Operating Agreement of Kykuit Resources, LLC, dated October 24, 2007. Filed as Exhibit 10.6 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2007 and incorporated herein by reference
10.15		First Amendment to Amended and Restated Operating Agreement of Kykuit Resources, LLC, dated December 17, 2007. Filed as Exhibit 10.2 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended December 31, 2007 and incorporated herein by reference
10.16		Stock Purchase Agreement dated January 30, 2007 between the Registrant and Sempra Energy. Filed as Exhibit 10.1 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2007 and incorporated herein by reference
10.17		Amendment No. 1 to Stock Purchase Agreement dated April 11, 2007 between the Registrant and Sempra Energy. Filed as Exhibit 10.2 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2007 and incorporated herein by reference
10.18		Amendment No. 2 to Stock Purchase Agreement dated August 7, 2007 between the Registrant and Sempra Energy. Filed as Exhibit 10.3 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2007 and incorporated herein by reference
10.19		Amendment No. 3 to Stock Purchase Agreement, dated November 28, 2007, by and between the Registrant and Sempra Energy. Filed as Exhibit 10.1 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended December 31, 2007 and incorporated herein by reference
10.20		Stock Purchase Agreement dated January 30, 2007 between the Registrant and Sempra Energy. Filed as Exhibit 10.4 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2007 and incorporated herein by reference
10.21		Amendment Number 1 to Stock Purchase Agreement dated August 2, 2007 between the Registrant and Sempra Energy. Filed as Exhibit 10.5 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2007 and incorporated herein by reference
10.22		Stock Purchase Agreement dated December 18, 2007 between the Registrant, Dan F. Whetstone, Pamela R. Lowry, Paula A. Poole, William J. Junkermier and Roger W. Junkermier. Filed as Exhibit 10.1 to the Registrant’s Current Report on Form 8-K dated December 17, 2007 and incorporated herein by reference
10.23		First Amendment to Stock Purchase Agreement dated as of November 11, 2008, between Dan F. Whetstone, Pamela R. Lowry, Paula A. Poole, William J. Junkermier, Roger W. Junkermiern and Energy West, Incorporated. Filed as Exhibit 10.1 to the Registrant’s Current Report on Form 8-K dated November 11, 2008 and incorporated herein by reference
10.24		Non-Competition and Non-Disclosure Agreement dated December 18, 2007 between the Registrant and Daniel F. Whetstone. Filed as Exhibit 10.2 to the Registrant’s Current Report on Form 8-K dated December 17, 2007 and incorporated herein by reference
10.25		Lease Agreement dated February 25, 2008 between OsAir, Inc. and the Registrant. Filed as Exhibit 10.1 to the Registrant’s Current Report on Form 8-K dated February 25, 2008 and incorporated herein by reference
10.26	†	Employment Agreement dated November 16, 2007 between James W. Garrett and the Registrant. Filed as Exhibit 10.1 to the Registrant’s Current Report on Form 8-K dated November 14, 2007 and incorporated herein by reference
10.27	*†	First Amendment to Employment Agreement dated as of December 31, 2008, between Energy West, Incorporated and James W. Garrett

64

10.28		Gas Sales Agreement dated as of July 1, 2008 between John D. Oil & Gas Marketing Co., LLC, Northeast Ohio Natural Gas Corp., Orwell Natural Gas Company and Brainard Gas Corp. Filed as Exhibit 10.25 to the Registrant’s Annual Report on 10-K for the year ended June 30, 2008 and incorporated herein by reference
10.29		Natural Gas Transportation Service Agreement dated as of July 1, 2008 between Orwell-Trumbull Pipeline Co., LLC, Orwell Natural Gas Company and Brainard Gas Corp. Filed as Exhibit 10.26 to the Registrant’s Annual Report on 10-K for the year ended June 30, 2008 and incorporated herein by reference
10.30		Transportation Service Agreement dated as of July 1, 2008 between Cobra Pipeline Co., Ltd., Northeast Ohio Natural Gas Company, Orwell Natural Gas Company and Brainard Gas Corp. Filed as Exhibit 10.27 to the Registrant’s Annual Report on 10-K for the year ended June 30, 2008 and incorporated herein by reference
10.31		First Amendment dated July 1, 2008 to the Orwell-Trumbull Pipeline Co., LLC Operations Agreement between Orwell Natural Gas Company and Orwell-Trumbull Pipeline Co., LLC. Filed as Exhibit 10.28 to the Registrant’s Annual Report on 10-K for the year ended June 30, 2008 and incorporated herein by reference
10.32		Orwell-Trumbull Pipeline Co., LLC Operations Agreement dated January 1, 2008 between Orwell Natural Gas Company and Orwell-Trumbull Pipeline Co., LLC. Filed as Exhibit 10.29 to the Registrant’s Annual Report on 10-K for the year ended June 30, 2008 and incorporated herein by reference
10.33		Triple Net Lease Agreement dated as of July 1, 2008 between Station Street Partners, LLC and Orwell Natural Gas Company. Filed as Exhibit 10.30 to the Registrant’s Annual Report on 10-K for the year ended June 30, 2008 and incorporated herein by reference
10.34		Triple Net Lease Agreement dated as of July 1, 2008 between OsAir, Inc. and Orwell Natural Gas Company. Filed as Exhibit 10.31 to the Registrant’s Annual Report on 10-K for the year ended June 30, 2008 and incorporated herein by reference.
10.35		Triple Net Lease Agreement dated as of July 1, 2008 between Richard M. Osborne, Trustee and Orwell Natural Gas Company. Filed as Exhibit 10.32 to the Registrant’s Annual Report on 10-K for the year ended June 30, 2008 and incorporated herein by reference
10.36		Triple Net Lease Agreement dated as of July 1, 2008 between OsAir, Inc. and Northeast Ohio Natural Gas Company. Filed as Exhibit 10.33 to the Registrant’s Annual Report on 10-K for the year ended June 30, 2008 and incorporated herein by reference
10.37		Stock purchase agreement dated September 12, 2008, between Energy West, Incorporated, and Richard M. Osborne, trustee, Rebecca Howell, Stephen G. Rigo, Marty Whelan, and Thomas J. Smith, filed as exhibit 10.1 to the registrant’s current report on Form 8-K dated September 17, 2008, and incorporated herein by reference Filed as Exhibit 10.34 to the Registrant’s Annual Report on 10-K for the year ended June 30, 2008 and incorporated herein by reference
10.38	†	Employment Agreement dated August 25, 2006 between Energy West, Incorporated and Kevin J. Degenstein, filed as Exhibit 10.1 to the Registrant’s Current Report on Form 8-K dated September 18, 2006 and incorporated herein by reference
10.39	†	First Amendment to Employment Agreement dated as of December 31, 2008, between Energy West, Incorporated and Kevin J. Degenstein
10.40	†*	Employment Agreement dated April 13, 2007 between Energy West, Incorporated and David C. Shipley
14		Code of Business Conduct, filed as Exhibit 14 to the Registrant’s Annual Report on 10-K for the year ended June 30, 2006 and incorporated herein by reference.
21	*	Company Subsidiaries
23.1	*	Consent of Hein & Associates 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

†	Management agreement or compensatory plan or arrangement
*	Filed herewith

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(c) Financial Statement Schedules:

Schedule II

Valuation and Qualifying Accounts
Energy West, Incorporated
December 31, 2008

	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, 2007	$	121,453	$	210,956	$	(268,355	)	$	64,054
Year Ended June 30, 2008	$	64,054	$	174,531	$	(102,186	)	$	136,399
Six Months Ended December 31, 2007 (unaudited)	$	64,054	$	57,055	$	14,790		$	135,899
Six Months Ended December 31, 2008	$	136,399	$	58,085	$	13,458		$	207,942

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

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SIGNATURES

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

ENERGY WEST, INCORPORATED
 

/s/ Richard M. Osborne  

Richard M. Osborne 

Chief Executive Officer
(principal executive officer) 

Date: March 31, 2009

KNOW ALL THESE PERSONS BY THESE PRESENTS, that each person whose signature appears below constitutes and appoints Thomas J. Smith, 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/ Richard M. Osborne Richard M. Osborne	Chief Executive Officer  (Principal Executive Officer)	March 31, 2009
/s/ Thomas J. Smith Thomas J. Smith	Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer)	March 31, 2009
/s/ W.E. Argo W.E. Argo	Director	March 31, 2009
/s/ Mark D. Grossi Mark D. Grossi	Director	March 31, 2009
/s/ Ian Abrams Ian Abrams	Director	March 31, 2009
/s/ Steven A. Calabrese Steven A. Calabrese	Director	March 31, 2009
/s/ James E. Sprague James E. Sprague	Director	March 31, 2009
/s/ James R. Smail James R. Smail	Director	March 31, 2009
/s/ Michael T. Victor Michael T. Victor	Director	March 31, 2009

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CONSOLIDATED FINANCIAL STATEMENTS
OF
ENERGY WEST, INCORPORATED AND SUBSIDIARIES

TABLE OF CONTENTS

	Page
Report of Independent Registered Public Accounting Firm—Hein & Associates LLP		F-2
Consolidated Balance Sheets as of December 31, 2008 and June 30, 2008 and 2007		F-3
Consolidated Statements of Income for the Six Months Ended December 31, 2008 and 2007 (unaudited), and the Years Ended June 30, 2008, 2007, and 2006		F-4
Consolidated Statements of Changes in Stockholders’ Equity and Comprehensive Income for the Six Months Ended December 31, 2008, and the Years Ended June 30, 2008, 2007 and 2006		F-5
Consolidated Statements of Cash Flows for the Six Months Ended December 31, 2008 and 2007 (unaudited), and the Years Ended June 30, 2008, 2007 and 2006		F-6
Notes to Consolidated Financial Statements		F-8

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

We have audited the consolidated balance sheets of Energy West, Incorporated and subsidiaries as of December 31, 2008, and June 30, 2008 and 2007, and the related consolidated statements of income, stockholders’ equity and comprehensive income and cash flows for the six months ended December 31, 2008, and the years ended June 30, 2008, 2007 and 2006. Our audits also included the financial statement schedule as of, and for the six months ending December 31, 2008, and the two years in the period ending June 30, 2008 and 2007 listed in the index as Item 15. We did not audit the schedule as of and for the six months ending December 31, 2007. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

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

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Energy West, Incorporated and subsidiaries as of December 31, 2008 and June 30, 2008 and 2007, and the results of their operations and their cash flows for the six months ended December 31, 2008, and the years ended June 30, 2008, 2007 and 2006, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

We were not engaged to examine management’s assessment of the effectiveness of Energy West Incorporated’s internal over financial reporting as of December 31, 2008, included in the accompanying Management’s Report in Internal Control over Financial Reporting and, accordingly, we do not express an opinion there on.

/s/ HEIN & ASSOCIATES LLP

Denver, Colorado
March 31, 2009

F-2

ENERGY WEST INCORPORATED AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

	DECEMBER 31,			JUNE 30,
	(audited)			(audited)
	2008			2008		2007
ASSETS
Current Assets:
Cash and cash equivalents	$	1,065,529		$	796,302	$	7,010,020
Marketable securities		3,376,875			910,778		—
Accounts receivable less $207,942, $136,399 and $64,054 respectively, allowance for bad debt		7,430,694			5,108,796		3,532,083
Unbilled gas		4,839,138			1,252,638		649,939
Derivative assets		—			145,428		57,847
Natural gas and propane inventories		9,891,802			5,505,337		5,474,309
Materials and supplies		1,175,596			955,467		377,296
Prepayment and other		422,514			193,581		142,964
Income tax receivable		1,014,806			417,164		162,432
Recoverable cost of gas purchases		2,041,280			1,054,875		1,369,584
Deferred tax asset		225,953			—		53,370
Total current assets		31,484,187			16,340,366		18,829,844
Property, Plant and Equipment, Net		34,904,442			31,051,419		29,160,084
Deferred Charges		2,558,156			2,761,656		3,031,425
Deferred Tax Assets — Long term		5,693,310			6,825,575		—
Other Investments		1,081,423			1,118,264		—
Other Assets		97,447			279,810		560,463
TOTAL ASSETS	$	75,818,965		$	58,377,090	$	51,581,816
LIABILITIES AND CAPITALIZATION
Current Liabilities:
Bank overdraft	$	773,199		$	532,901	$	—
Accounts payable		5,783,927			7,439,748		4,543,525
Line of credit		17,551,276			—		—
Derivative liabilities		—			146,206		58,018
Accrued income taxes		35,236			—		—
Deferred income taxes		—			18,039		—
Overrecovered gas purchases		1,022,853			522,347		1,061,685
Accrued and other current liabilities		4,947,448			3,302,712		3,092,726
Total current liabilities		30,113,939			11,961,953		8,755,954
Other Obligations:
Deferred income taxes		—			—		4,585,170
Deferred investment tax credits		239,565			250,096		271,158
Other long-term liabilities		2,383,323			2,516,262		2,673,824
Total other obligations		2,622,888			2,766,358		7,530,152
Long-Term Debt		13,000,000			13,000,000		13,000,000
Commitments and Contingencies (note 16)
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, 4,296,603, 4,347,769 and 4,288,657 shares outstanding at December 31, 2008 and June 30, 2008 and 2007, respectively		652,503			652,165		643,299
Treasury stock		(8,012	)		—		—
Capital in excess of par value		5,926,028			6,280,649		5,867,726
Accumulated other comprehensive income (loss)		(319,147	)		—		—
Retained earnings		23,830,766			23,715,965		15,784,685
Total stockholders’ equity		30,082,138			30,648,779		22,295,710
TOTAL CAPITALIZATION		43,082,138			43,648,779		35,295,710
TOTAL LIABILITIES AND CAPITALIZATION	$	75,818,965		$	58,377,090	$	51,581,816

See notes to consolidated financial statements

F-3

ENERGY WEST INCORPORATED AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

	SIX MONTHS ENDED						YEARS ENDED
	DECEMBER 31,						JUNE 30,
	(audited)			(unaudited)			(audited)
	2008			2007			2008			2007			2006
REVENUES:
Natural gas operations	$	28,840,123		$	21,118,295		$	59,338,996		$	46,439,506		$	55,452,395
Gas and electric—wholesale		9,691,560			7,008,122			17,124,081			12,545,359			18,831,929
Pipeline operations		226,157			186,855			370,171			388,175			411,237
Total revenues		38,757,840			28,313,272			76,833,248			59,373,040			74,695,561
COST OF SALES:
Gas purchased		19,459,908			13,972,427			41,337,397			33,541,993			43,160,830
Gas and electric—wholesale		7,770,347			5,922,616			14,833,353			10,264,633			17,237,396
Total cost of sales		27,230,255			19,895,043			56,170,750			43,806,626			60,398,226
GROSS MARGIN		11,527,585			8,418,229			20,662,498			15,566,414			14,297,335
Distribution, general, and administrative		5,717,406			4,601,908			10,661,878			6,197,529			6,389,130
Maintenance		319,798			325,915			650,553			566,683			504,671
Depreciation and amortization		1,023,381			889,371			1,865,294			1,692,486			1,671,647
Taxes other than income		1,284,557			863,613			2,080,144			1,696,936			1,453,375
Total expenses		8,345,142			6,680,807			15,257,869			10,153,634			10,018,823
OPERATING INCOME		3,182,443			1,737,422			5,404,629			5,412,780			4,278,512
OTHER INCOME (EXPENSE)		(420,349	)		190,093			315,779			241,519			390,677
INTEREST (EXPENSE)		(677,056	)		(529,711	)		(1,076,345	)		(2,124,155	)		(1,648,897	)
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE		2,085,038			1,397,804			4,644,063			3,530,144			3,020,292
INCOME TAX (EXPENSE)		(926,457	)		(273,828	)		(1,332,688	)		(1,272,664	)		(1,109,043	)
INCOME FROM CONTINUING OPERATIONS		1,158,581			1,123,976			3,311,375			2,257,480			1,911,249
DISCONTINUED OPERATIONS:
Gain from disposal of operations		—			—			—			5,479,166			—
Income from discontinued operations		—			—			—			975,484			671,084
Income tax (expense)		—			—			—			(2,499,875	)		(265,663	)
INCOME FROM DISCONTINUED OPERATIONS		—			—			—			3,954,775			405,421
INCOME BEFORE EXTRAORDINARY ITEM		1,158,581			1,123,976			3,311,375			6,212,255			2,316,670
EXTRAORDINARY GAIN		—			6,819,182			6,819,182			—			—
NET INCOME	$	1,158,581		$	7,943,158		$	10,130,557		$	6,212,255		$	2,316,670
BASIC INCOME PER COMMON SHARE:
Income from continuing operations	$	0.27		$	0.26		$	0.77		$	0.51		$	0.43
Income from discontinued operations		—			—			—			0.89			0.09
Income from extraordinary gain		—			1.59			1.58			—			—
	$	0.27		$	1.85		$	2.35		$	1.40		$	0.53
DILUTED INCOME PER COMMON SHARE:
Income from continuing operations	$	0.27		$	0.26		$	0.77		$	0.51		$	0.43
Income from discontinued operations		—			—			—			0.88			0.09
Income from extraordinary gain		—			1.58			1.58			—			—
	$	0.27		$	1.85		$	2.35		$	1.39		$	0.52
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:
Basic		4,330,200			4,287,437			4,314,748			4,437,807			4,386,768
Diluted		4,331,726			4,304,559			4,316,244			4,484,073			4,422,069

See notes to consolidated financial statements.

F-4

CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY AND COMPREHENSIVE INCOME
FOR THE YEARS ENDED JUNE 30, 2007, 2008, AND THE SIX MONTHS ENDED DECEMBER 31, 2008

															Accumulated
												Capital in			Other
	Common			Common			Treasury		Treasury			Excess of			Comprehensive			Retained
	Shares			Stock			Shares		Stock			Par Value			Income (Loss)			Earnings			Total
BALANCE AT JULY 1, 2005		4,368,846		$	655,338			—	$	—		$	7,216,863		$	—		$	9,314,424		$	17,186,625
Sales of common stock at $6.03 to $7.67 per share under the Company’s dividend reinvestment plan		960			144								6,020						(10,780	)		(4,616	)
Stock contributions at $6.03 to $7.67 to the 401(k) plan		2,915			426								39,195						(39,621	)		—
Stock compensation		24,795			3,720								131,530									135,250
Exercise of stock options @ $5.66		3,750			563								20,665									21,228
Net income																			2,316,670			2,316,670
Dividends paid @ $0.11																			(490,044	)		(490,044	)
BALANCE AT JUNE 30, 2006		4,401,266		$	660,191			—	$	—		$	7,414,273		$	—		$	11,090,649		$	19,165,113
Stock Compensation		13,163			1,974								83,111									85,085
Repurchase of Stock — stock buyback program		(219,522	)		(32,928	)							(2,162,133	)								(2,195,061	)
Costs associated with stock buyback													(81,280	)								(81,280	)
Stock option liability													115,603									115,603
Exercise of stock options @ $4.31 to $7.00		93,750			14,062								498,152									512,214
Net income																			6,212,255			6,212,255
Dividends paid @ $0.34																			(1,518,219	)		(1,518,219	)
BALANCE AT JUNE 30, 2007		4,288,657		$	643,299			—	$	—		$	5,867,726		$	—		$	15,784,685		$	22,295,710
Stock compensation		3,750			563								248,528									249,091
Repurchase of Stock — stock buyback program		(16,780	)		(2,517	)							(156,821	)								(159,338	)
Costs associated with stock buyback													(2,313	)								(2,313	)
Exercise of stock options @ $4.31 to $10.00		109,500			16,424								611,491									627,915
Intrinsic value of stock exercised — tax effect													80,933									80,933
Return of stock at market price in exchange for stock options		(37,500	)		(5,625	)							(368,874	)								(374,499	)
Rounding adjustments for stock split issuance		142			21								(21	)								(0	)
Net income																			10,130,557			10,130,557
Dividends paid @ $0.47																			(2,199,277	)		(2,199,277	)
BALANCE AT JUNE 30, 2008		4,347,769		$	652,165			—	$	—		$	6,280,649		$	—		$	23,715,965		$	30,648,779
Comprehensive Income:
Net income																			1,158,581			1,158,581
Net unrealized losses on available-for-sale securities																(319,147	)					(319,147	)
Total comprehensive income																						839,434
Stock compensation		2,250			338								35,655									35,993
Repurchase of Stock — stock buyback program		(53,416	)		—			53,416		(8,012	)		(398,027	)								(406,039	)
Intrinsic value of stock exercised — tax effect													7,751									7,751
Dividends paid @ $0.47																			(1,043,780	)		(1,043,780	)
BALANCE AT DECEMBER 31, 2008		4,296,603		$	652,503			53,416	$	(8,012	)	$	5,926,028		$	(319,147	)	$	23,830,766		$	30,082,138

See notes to consolidated financial statements.

F-5

ENERGY WEST INCORPORATED AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

	SIX MONTHS ENDED						YEARS ENDED
	DECEMBER 31,						JUNE 30,
	(audited)			(unaudited)			(audited)
	2008			2007			2008			2007			2006
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	1,158,581		$	7,943,158		$	10,130,557		$	6,212,255		$	2,316,670
Adjustments to reconcile net income to
Net cash provided by (used in) operating activities:
Depreciation and amortization, including deferred charges and financing costs		1,204,233			934,567			2,037,070			3,011,727			2,356,448
Stock-based compensation		35,993			—			249,090			—			—
Derivative assets		145,428			(6,339	)		(87,581	)		80,018			(18,796	)
Derivative liabilities		(146,206	)		6,339			88,188			15,354			(71,573	)
Deferred gain		(82,062	)		120,758			—			(325,582	)		(643,280	)
Gain on sale of assets		—			—			—			(5,479,166	)		—
Investment tax credit		(10,531	)		(10,531	)		(21,062	)		(21,062	)		(21,062	)
Deferred gain on sale of assets		—			—			—			—			(23,639	)
Deferred income taxes		491,286			(6,701,691	)		(176,719	)		(1,573,249	)		(259,022	)
Extraordinary gain		—			—			(6,819,182	)		—			—
Changes in assets and liabilities:
Accounts receivable		(5,908,400	)		(5,650,941	)		(779,559	)		509,893			1,450,570
Natural gas and propane inventories		(4,386,465	)		(2,596,296	)		(31,027	)		(615,710	)		(1,615,395	)
Accounts payable		(1,520,915	)		563,691			1,925,899			971,466			549,217
Recoverable/refundable cost of gas purchases		(485,900	)		(111,595	)		(260,137	)		(228,388	)		1,034,494
Prepayments and other		(228,933	)		(419,585	)		(25,069	)		118,800			(37,572	)
Equity in income of Kykuit		36,841			—			—			—			—
Net assets held for sale		—			—			—			(1,219,927	)		240,355
Other assets		18,378			450,573			(309,466	)		(275,609	)		1,895,776
Accrued and other liabilities		1,576,528			1,373,063			(483,719	)		(2,086,253	)		1,983,484
Net cash provided by (used in) operating activities		(8,102,144	)		(4,104,829	)		5,437,283			(905,433	)		9,136,675
CASH FLOWS FROM INVESTING ACTIVITIES:
Construction expenditures		(4,534,120	)		(1,384,540	)		(3,869,832	)		(2,406,910	)		(1,865,594	)
Construction expenditures — discontinued operations								—			(365,845	)		(607,378	)
Purchase of marketable securities		(2,985,898	)		—			(1,301,524	)		—			—
Sale of marketable securities		—			—			390,746			—			—
Purchase of fixed assets — Acquisition of Bangor and Frontier		—			(4,601,599	)		(5,357,850	)		—			—
Acquisition of cash purchased in acquisition		—			—			960,464			—			—
Collection of note receivable		—			—			—			—			174,561
Proceeds from sale of assets		—			—			—			17,899,266			—
Other investments		(242,606	)		(644,777	)		(875,658	)		—			—
Customer advances received for construction		90,093			65,972			129,641			327,376			115,305
Increase (decrease) from contributions in aid of construction		—			38,874			125,678			—			(7,093	)
Net cash provided by (used in) investing activities		(7,672,591	)		(6,526,070	)		(9,798,335	)		15,453,887			(2,190,199	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Repayments of long-term debt		—			—			—			(18,663,213	)		(1,027,073	)
Repayments of other short-term borrowings		(1,309	)		—			—			—			—
Proceeds from lines of credit		22,100,000			8,475,495			14,075,495			11,012,000			14,850,000
Repayments of lines of credit		(4,605,000	)		(1,950,000	)		(14,075,495	)		(11,012,000	)		(18,750,000	)
Proceeds from long-term debt		—			—			—			13,000,000			—
Repurchase of common stock		(406,038	)		(150,911	)		(161,651	)		(2,276,192	)		—
Debt issuance cost		—			—			—			(317,539	)		—
Sale of common stock		—			221,890			334,350			597,151			21,229
Dividends paid		(1,043,691	)		(1,070,334	)		(2,025,365	)		(1,518,219	)		(494,660	)
Net cash provided by (used in) financing activities		16,043,962			5,526,140			(1,852,666	)		(9,178,012	)		(5,400,504	)
NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS		269,227			(5,104,759	)		(6,213,718	)		5,370,442			1,545,972
CASH AND CASH EQUIVALENTS:
Beginning of year		796,302			7,010,020			7,010,020			1,639,578			93,606
End of year	$	1,065,529		$	1,905,261		$	796,302		$	7,010,020		$	1,639,578

See notes to consolidated financial statements.

F-6

ENERGY WEST INCORPORATED AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS

	SIX MONTHS ENDED				YEARS ENDED
	DECEMBER 31,				JUNE 30,
	(audited)		(unaudited)				(audited)
	2008		2007		2008		2007		2006
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Cash paid during the period for interest	$	624,549	$	472,755	$	922,359	$	1,410,114	$	1,047,633
Cash paid during the period for income taxes		444,000		—		1,929,499		5,474,500		8,000
SUPPLEMENTAL SCHEDULE OF NONCASH INVESTING AND FINANCING ACTIVITIES:
Shares issued to satisify deferred board compensation		—		—		—		84,046		135,242
Acquisition of Kykuit investment		—		—		242,606		—		—
Construction expenditures included in accounts payable		338,000		—		—		—		—
Shares issued under the Company’s 401k reinvestment plan		—		—		—		—		19,436
Capitalized interest		11,322		11,428		11,512		21,414		18,855
Repurchase of stock — noncash		—		—		374,499		—		—
Accrued dividends		174,001		155,261		173,911		—		—

See notes to consolidated financial statements.

F-7

ENERGY WEST, INCORPORATED AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
For the six months ended December 31, 2008 and 2007, and the years ended June 30, 2008 and 2007

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, Cody, Wyoming, Bangor, Maine and Elkin, North Carolina, and the distribution and sale of propane to the public through underground propane vapor systems in Cascade, Montana, and, until April 1, 2007, in and around Payson, Arizona. Our West Yellowstone, Montana operation is supplied by liquefied natural gas.

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

Basis of Presentation — Effective December 31, 2008, the Company changed its fiscal year end form June 30 to December 31. This change is being made in order to align the Company’s fiscal year end with other companies within the industry. The resulting six-month period ended December 31, 2008 may be referred to herein as the “Transition Period.” The six-month period ended December 31, 2007 is unaudited. The Company refers to the period beginning July 1, 2007 and ending June 30, 2008 as “fiscal 2008”, the period beginning July 1, 2006 and ending June 30, 2007 as “fiscal 2007” and the period beginning July 1, 2005 and ending June 30, 2006 as “ fiscal 2006”.

The accompanying unaudited consolidated financial statements of Energy West, Incorporated and its subsidiaries (collectively, the “Company”) for the consolidated statements of income, stockholders equity and comprehensive income, and cash flows for the six months ended December 31, 2007 have been prepared in accordance with accounting principles generally accepted in the United States of America for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by generally accepted accounting principles for complete financial statements. In the opinion of management, all adjustments considered necessary for a fair presentation have been included and are of a normal and recurring nature.

Reclassifications — Certain reclassifications of prior year reported amounts have been made for comparative purposes. The results of operations for the propane assets related to the sale of the Arizona assets have been reclassified as income from discontinued operations. Cash flows used in discontinued operations for construction expenditures were reclassified for the years ending June 30, 2007 and 2006 to reflect the expenditures as an investing activity.

Principles of Consolidation — The consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries, Energy West Propane (EWP), EWR, Energy West Development (EWD or Pipeline Operations), Frontier Utilities of North Carolina (FUNC) and Penobscot Natural Gas (PNB). 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 five business segments: Natural Gas Operations, EWR, Pipeline Operations, Discontinued Operations, formerly reported as Propane Operations, and Corporate and Other. Summarized financial information for these five segments is set forth in Note 14.

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, and in the determination of depreciable lives of utility plant. The deferred tax asset, valuation allowance and related extraordinary gain require a significant amount of judgment and are significant estimates. The estimates are based on projected future tax deductions, future taxable income, estimated limitations under the Internal Revenue Code, an estimated valuation allowance, and other assumptions.

F-8

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

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

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), the North Carolina Utilities Commission (NCUC), the Maine Public Utilities Commission (MPUC) and, until April 1, 2007 with the sale of our Arizona Propane operations, the Arizona Corporation Commission (ACC). Purchased gas and propane costs that are different from those provided for in present rates, and approved by the applicable commissions, are accumulated and recovered or credited through future rate changes. As of December 31, 2008 and the years ending June 30, 2008 and 2007, the Company had unrecovered purchase gas costs of $2,041,280, $1,054,874 and $1,369,584 respectively, and over-recovered purchase gas costs of $1,022,853, $522,347 and $1,061,685 respectively.

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

Contributions in Aid and Advances Received for Construction — Contributions in aid of construction are contributions received from customers for construction that are not refundable and are amortized over the life of the assets. 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 December 31, 2008, and June 30, 2008 and 2007, 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 the six months ended December 31, 2008 and 2007 and the twelve months ended June 30, 2008 and 2007, the Company recorded $17,355, $150,980 (unaudited), $213,286, and $58,229, respectively, ($10,680, $92,913 (unaudited), $131,256 and $35,811 net of related tax effects) of compensation expense for stock options granted after July 1, 2005, and for the unvested portion of previously granted stock options that remained outstanding as of July 1, 2005.

F-9

In the six months ended December 31, 2008 and 2007, 10,000, and 15,000 options were granted, respectively. In the fiscal years ended June 30, 2008, 2007 and 2006 30,000, 45,000 and 72,750 options were granted, respectively. At December 31, 2008, and 2007, and at June 30, 2008, 2007 and 2006 a total of 29,500, 45,000 (unaudited), 19,500, 165,000, 218,250 options were outstanding, respectively.

	Six Months Ended						Twelve Months Ended
	December 31,						June 30,
	2008			2007			2008			2007			2006
					(unaudited)
Expected dividend rate		5.81	%		3.06	%		4.47	%		4.00	%		2.00	%
Risk free interest rate		1.87	%		3.70	%		3.61	%		5.10	%		4.87	%
Weighted average expected lives, in years		3.50			3.50			2.50			2.26			3.40
Price volatility		73.24	%		31.16	%		31.16	%		30.00	%		39.00	%
Total intrinsic value of options exercised	$	—		$	300,340		$	419,890		$	218,609		$	4,087
Total cash received from options exercised	$	—		$	115,805		$	293,930		$	512,175		$	21,228

Comprehensive Income — Comprehensive income includes net income and other comprehensive income, which for the Company is primarily comprised of unrealized holding gains or losses on our available-for-sale securities that are excluded from the statement of operations in computing net loss and reported separately in shareholders’ equity. Comprehensive income and its components are as follows:

	Six months ended					Twelve months ended
	December 31					June 30
	2008			2007		2008		2007		2006
					(unaudited)
Net income	$	1,158,581		$	7,943,158	$	10,130,557	$	6,212,255	$	2,316,670
Other comprehensive income
Change in unrealized gain/loss on available-for-sale securities, Net of $199,454 of income taxes		(319,147	)		—		—		—		—
Comprehensive income	$	839,434		$	7,943,158	$	10,130,557	$	6,212,255	$	2,316,670

F-10

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 income. 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 “normal” sale and the appropriate election has been made. As of December 31, 2008 and June 30, 2008 and 2007, the Company has no derivative instruments designated and qualifying as SFAS No. 133 hedges.

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

Cash and Cash Equivalents — All highly liquid investments with original maturities of three months or less at the date of acquisition are considered to be cash equivalents. The company maintains cash balances at several banks. Accounts at each institution are insured by the Federal Deposit Insurance Corporation up to $250,000. Deposits exceeding federal insurable limits as of December 31, 2008 were $341,291.

Earnings Per Share — Net income per common share is computed by both the basic method, which uses the weighted average number of our common shares outstanding, and the diluted method, which includes the dilutive common shares from stock options, as calculated using the treasury stock method. The only potentially dilutive securities are the stock options described in Note 15. Options to purchase 19,500, 67,500 (unaudited),19,500 and 165,000 shares of common stock were outstanding at December 31, 2008 and 2007 and June 30, 2008 and 2007, respectively. Earnings per share of prior periods have been adjusted for the 3-for-2 stock split effectuated February 1, 2008.

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

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

F-11

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.

On July 1, 2007, the Company adopted FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes, an Interpretation of FASB Statement No. 109, Accounting for Income Taxes” (“FIN 48”). FIN 48 clarifies the accounting for uncertainty in income taxes by establishing standards for measurement and recognition in financial statements of positions taken by an entity in its income tax returns and provides guidance on derecognition of income tax assets and liabilities, classification of current and deferred income tax assets and liabilities, accounting for interest and penalties, accounting for income taxes in interim periods and income tax disclosures. The adoption of FIN 48 resulted in no impact to our consolidated financial statements and we have no unrecognized tax benefits that would impact our effective rate.

The Company recognizes interest and penalties related to unrecognized tax benefits in income tax expenses. As of December 31, 2008 and June 30, 2008 and 2007, the Company had no unrecognized tax benefits, recognized no interest and penalties and had no interest or penalties accrued related to unrecognized tax benefits.

The Company, or one or more of its subsidiaries, files income tax returns in the U.S. federal jurisdiction and various state jurisdictions. With few exceptions, the Company is no longer subject to U.S. federal tax or state and local income tax examinations by tax authorities for tax years prior to June 30, 2004. Currently, the Company is not being examined by any taxing authorities.

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 6 for a discussion of the fair value of the fixed rate long-term debt.

Asset Retirement Obligations (ARO) — The Company follows SFAS No. 143, “Accounting for Asset Retirement Obligations,” which requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it was incurred if a reasonable estimate of fair value could be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The increase in carrying value of a property associated with the capitalization of an asset retirement cost is included in “Property, plant and equipment, net” in the accompanying consolidated balance sheets. The Company depreciates the amount added to prove oil and gas property costs. The asset retirement liability is allocated to operating expense using a systematic and rational method. As of December 31, 2008, and June 30, 2008 and 2007, the Company has recorded a net asset of $256,153, $276,964 and $318,586 and a related liability of $746,199, $726,231 and $688,371, respectively. In the future, the Company may have other asset retirement obligations arising from its business operations.

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

The information below reconciles the value of the asset retirement obligation for the periods presented:

Balance — July 1, 2006	$	650,717
Accretion		37,654
Balance — June 30, 2007	$	688,371
Accretion		37,860
Balance — June 30, 2008	$	726,231
Accretion		19,968
Balance — December 31, 2008	$	746,199

Equity Method Investments — During fiscal year 2008, our marketing and production operations segment acquired a 19.8% ownership interest in Kykuit Resources, LLC, (Kykuit), a developer and operator of oil, gas and mineral leasehold estates located in Montana. We have invested a total of approximately $1.1 million in Kykuit and may invest additional funds in the future as Kykuit provides a supply of natural gas in close proximity to our natural gas operations in Montana. However, our obligations to make additional investments in Kykuit are limited under the Kykuit operating agreement. We are entitled to cease further investments in Kykuit if, in our reasonable discretion after the results of certain initial exploration activities are known, we deem the venture unworthy of further investments. Even if the venture is reasonably successful, we are obligated to invest no more than an additional $1.9 million over the life of the venture. Other investors in Kykuit include our chairman of the board, Richard M. Osborne, another board member, Steven A. Calabrese, and John D. Oil and Gas Company, a publicly held gas exploration company, which is also the managing member of Kykuit. Also, Mr. Osborne is the chairman of the board and chief executive officer, and Mr. Grossi, Mr. Smail, Mr. Smith and Mr. Calabrese are directors of John D. Oil and Gas Company.

F-12

We are accounting for the investment in Kykuit using the equity method. The Company’s investment in Kykuit at December 31, 2008 and June 30, 2008 and 2007 was approximately $1.1 million, $1.1 million, and $0 including undistributed losses of $37,000, $0, and $0, respectively.

New Accounting Pronouncements — In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements (“SFAS 157”). SFAS 157 defines fair value, establishes a framework and gives guidance regarding the methods used for measuring fair value, and expands disclosures about fair value measurements. SFAS 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. On January 1, 2008 we elected to implement this statement with the one-year deferral. The adoption of SFAS No. 157 did not have a material impact on our financial position, results of operations or cash flows. Beginning January 1, 2009, we will adopt the provisions for non-financial assets and non-financial liabilities that are not required or permitted to be measured at fair value on a recurring basis. We are in the process of evaluating this standard with respect to our effect on non-financial assets and liabilities and have not yet determined the impact that it will have on our financial statements upon full adoption in 2009.

In December 2007, the FASB issued SFAS No. 141 (revised 2007), Business Combinations, (“SFAS 141R”). SFAS141R requires an acquirer to recognize and measure the assets acquired, liabilities assumed and any non-controlling interests in the acquiree at the acquisition date, measured at their fair values as of that date, with limited exception. In addition, SFAS141R requires that acquisition-related costs will be generally expensed as incurred and also expands the disclosure requirements for business combinations. The effective date of SFAS 141R is for fiscal years beginning after December 15, 2008. We have adopted SFAS 141R on our consolidated financial statements, effective January 1, 2009. In addition, we have recorded as expense in the six months ended December 31, 2008, $585,000 of acquisition costs related to acquisitions in progress as part of the transition to SFAS 141R.

In December 2007, the FASB issued SFAS No. 160, Accounting for Noncontrolling Interests (“SFAS 160”). SFAS 160 amends Accounting Research Bulletin (ARB) No. 51 and establishes standards of accounting and reporting on non-controlling interests in consolidated statements, provides guidance on accounting for changes in the parent’s ownership interest in a subsidiary, and establishes standards of accounting of the deconsolidation of a subsidiary due to the loss of control. The effective date of SFAS 160 is for fiscal years beginning after December 15, 2008. We are currently evaluating the impact of adopting SFAS 160 on our consolidated financial statements.

In March 2008, the FASB issued FAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities” (“FAS 161”). FAS 161 amends and expands the disclosure requirements of FAS 133, “Accounting for Derivative Instruments and Hedging Activities” and requires qualitative disclosures about objectives and strategies for using derivatives, quantitative disclosures about fair value amounts of gains and losses on derivative instruments, and disclosures about credit-risk-related contingent features in derivative agreements. This statement is effective for financial statements issued for fiscal periods beginning after November 15, 2008. Earlier adoption is not permitted. We do not believe the adoption of FAS 161 will have a material impact on our consolidated financial statements.

In May 2008, the FASB issued Statement of Financial Accounting Standards No. 162, The Hierarchy of Generally Accepted Accounting Principles (“SFAS 162”). SFAS 162 identifies the sources of accounting principles and the framework for selecting the principles to be used in the preparation of financial statements that are presented in conformity with U.S. generally accepted accounting principles. The Statement becomes effective 60 days following the SEC’s approval of the Public Company Accounting Oversight Board amendments to the auditing literature. The adoption of SFAS 162 will not have an impact on the Company’s financial position, results of operations or cash flows.

In April 2008, the FASB issued FASB Staff Position (“FSP”) FAS 142-3, “Determination of Useful Life of Intangible Assets” (“FSP FAS 142-3”). FSP FAS 142-3 amends the factors that should be considered in developing the renewal or extension assumptions used to determine the useful life of a recognized intangible asset under FAS 142, “Goodwill and Other Intangible Assets.” FSP FAS 142-3 also requires expanded disclosure related to the determination of intangible asset useful lives. FSP FAS 142-3 is effective for fiscal years beginning after December 15, 2008. Earlier adoption is not permitted. We do not believe the adoption of FAS FSP 142-3 will have a material impact on our consolidated financial statements.

In June 2008, the FASB issued FSP No. EITF 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities,” (FSP EITF 03-6-1). FSP EITF 03-6-1 states that unvested share-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities and shall be included in the computation of earnings per share pursuant to the two-class method. FSP EITF 03-6-1 becomes effective for the Company on January 1, 2009. Management has determined that the adoption of FSP EITF 03-6-1 will not have an impact on the Financial Statements.

2. Discontinued Operations

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

F-13

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

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

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

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

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

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

F-14

3. Acquisitions and Extraordinary Gain

On October 1, 2007, the Company completed the acquisition of Frontier Utilities of North Carolina, Inc. (“Frontier Utilities”), which operates a natural gas utility in and around Elkin, North Carolina through its subsidiary, Frontier Natural Gas. The purchase price was $4.5 million in cash, plus adjustment for taxes and working capital, resulting in a total purchase price of approximately $4.9 million. On December 1, 2007, the Company completed the acquisition of Penobscot Natural Gas Company, Inc. (“Penobscot Natural Gas”) for a purchase price of approximately $226,000, plus adjustment for working capital, resulting in a total purchase price of approximately $434,000. Penobscot Natural Gas is the parent company of Bangor Gas Company LLC, which operates a natural gas utility in and around Bangor, Maine.

The results of operations for Frontier Utilities and Penobscot Natural Gas have been included in the consolidated financial statements since the dates of acquisition.

Under Financial Accounting Standards (“FAS”) 141, the Company has recorded these stock acquisitions as if the net assets of the targets were acquired. For income tax purposes, the Company is permitted to “succeed” to the operations of the acquired companies, whereby the Company may continue to depreciate the assets at their historical tax cost bases. As a result, the Company may continue to depreciate approximately $82.0 million of capital assets using the useful lives and rates employed by both Frontier Utilities and Penobscot Natural Gas. This treatment results in a potential future federal and state income tax benefit of approximately $19.0 million over an estimated 24-year period using applicable federal and state income tax rates. Under Internal Revenue Code Section 382, our ability to recognize tax deductions as a result of this tax benefit will be limited during the first 5 years following the acquisitions.

The following tables summarize the estimated fair values of the assets acquired and liabilities assumed at the date of acquisition.

	October 1, 2007
Frontier Utilities of North Carolina, Inc.
Current assets	$	957,439
Property and equipment		—
Noncurrent assets		4,522,076
Total assets acquired		5,479,515
Current liabilities		666,524
Long-term debt		—
Other long-term obligations		—
Total liabilities assumed		666,524
Net assets acquired:	$	4,812,991

	December 1, 2007
Penobscot Natural Gas, Inc.
Current assets	$	1,281,199
Property and equipment		—
Noncurrent assets		197,545
Total assets acquired		1,478,744
Current liabilities		726,035
Long-term debt		—
Total liabilities assumed		726,035
Net assets acquired:	$	752,709

F-15

The following table summarizes unaudited pro forma results of operations (in thousands) for the six months ended December 31, 2007 and the years ended June 30, 2008 and 2007, as if the acquisitions had occurred on July 1, 2007 and July 1, 2007 and 2006, respectively. There have been no adjustments made to the historical results of Frontier Utilities of North Carolina, Inc. or Penobscot Natural Gas, Inc.

	Six Months Ended		Year Ended June 30,
	December 31, 2007		2008		2007
	(in thousands)		(in thousands)
Pro forma revenues	$	30,977	$	79,497	$	71,505
Pro forma income before extraordinary items		850		3,037		4,973
Pro forma net income		7,669		9,856		4,973
Pro forma earnings per share — basic
Income before extraordinary items	$	0.198	$	0.700	$	1.120
Net income	$	1.789		2.280		1.120
Pro forma earnings per share — diluted
Income before extraordinary items	$	0.198	$	0.700	$	1.120
Net income	$	1.782		2.280		1.110

The pro forma information is presented for informational purposes only and is not necessarily indicative of the results of operations that actually would have been achieved had the acquisition been consummated as of that time, nor is it intended to be a projection of future results.

Following FAS 109, our balance sheet at December 31, 2008 reflects a gross deferred tax asset of approximately $19.0 million, offset by a valuation allowance of approximately $7.5 million, resulting in a net deferred tax asset associated with the acquisition of approximately $11.5 million.

The excess of the net deferred tax assets received in the transactions over the total purchase consideration has been reflected in fiscal 2008 as an extraordinary gain of approximately $6.8 million on the accompanying statement of income in accordance with the provisions of FAS 141.

4. 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 December 31, 2008, management of the company estimated the net gas reserves at 2.4 Bcf (unaudited) and a $4,358,000 net present value after applying a 10% discount (unaudited), considering reserve estimates provided by an independent reservoir engineer. The net book value of the gas properties totals $1,955,978 and is included in the “Property, plant and equipment, net” in the accompanying consolidated financial statements.

Beginning in fiscal 2007, the Company engaged in a limited drilling program of developmental wells on these existing properties. As of December 31, 2008, this program is complete. Five wells had been drilled and were capitalized as part of the drilling program, with two wells finding production and being tied in to the gathering system. The reserves from these wells are included in the reserves listed above.

The wells are depleting based upon production at approximately 10% per year as of December 31, 2008. For the six months ended December 31, 2008, EWR’s portion of the daily gas production was approximately 245 Mcf per day, or approximately 12.0% of EWR’s present volume requirements.

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

For the six months ended December 31, 2008, EWD’s portion of the daily gas production was approximately 97 Mcf per day, or approximately 4.7% of EWR’s present volume requirements.

F-16

EWR and EWD’s combined portion of the estimated daily gas production from the reserves is approximately 341 Mcf, or approximately 16.7% 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 SFAS No. 69, Disclosures About the Oil and Gas Producing Properties.

5. Marketable Securities

Securities investments that the Company has the positive intent and ability to hold to maturity are classified as held-to-maturity securities and recorded at amortized cost in investments and other assets. Securities investments not classified as either held-to-maturity or trading securities are classified as available-for-sale securities. Available-for-sale securities are recorded at fair value in investments and other assets on the balance sheet, with the change in fair value during the period excluded from earnings and recorded net of tax as a component of other comprehensive income.

The following is a summary of available-for-sale securities at December 31, 2008:

	December 31, 2008
	Investment		Unrealized			Estimated
	at cost		Gains (losses)			Fair Value
Common stock	$	3,895,476	$	(518,601	)	$	3,376,875

As of December 31, 2008 unrealized loss on available-for-sale securities of $319,147 (net of $199,454 in taxes) was included in accumulated other comprehensive income in the accompanying Consolidated Balance Sheets. There were no unrealized gains or losses during the 12 months ended June 30, 2008 and 2007.

6. Fair Value Measurements

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements,” (SFAS 157), which is effective for fiscal years beginning after November 15, 2007 and for interim periods within those years. This statement defines fair value, establishes a framework for measuring fair value and expands the related disclosure requirements. The statement indicates, among other things, that a fair value measurement assumes that the transaction to sell an asset or transfer a liability occurs in the principal market for the asset or liability or, in the absence of a principal market, the most advantageous market for the asset or liability based upon an exit price model.

Valuation Hierarchy

In accordance with SFAS 157, the following table represents the Company’s fair value hierarchy for its financial assets measured at fair value on a recurring basis as of December 31, 2008:

	December 31, 2008
	Level I		Level 2		Level 3		TOTAL
Available-for-sale securities		3,376,875		—		—		3,376,875
Total assets at fair value	$	3,376,875	$	—	$	—	$	3,376,875

F-17

7. Property, Plant and Equipment

Property, plant and equipment consist of the following as of December 31, 2008 and June 30, 2008 and 2007:

	December 31,			June 30,
	2008			2008			2007
Gas transmission and distribution facilities	$	49,362,905		$	46,187,291		$	44,666,105
Land		153,891			137,037			139,132
Buildings and leasehold improvements		2,945,258			2,940,816			2,907,975
Transportation equipment		1,628,103			1,696,286			1,581,196
Computer equipment		3,200,370			3,560,478			4,481,310
Other equipment		3,497,776			3,351,006			3,752,790
Construction work-in-progress		2,494,646			1,136,504			258,029
Producing natural gas properties		3,677,872			3,677,872			2,381,883
		66,960,821			62,687,290			60,168,420
Accumulated depreciation, depletion, and amortization		(32,056,379	)		(31,635,871	)		(31,008,336	)
Total	$	34,904,442		$	31,051,419		$	29,160,084

Property, plant and equipment includes contributions in aid of construction of $1,418,460, $1,423,714 and $1,313,907 at December 31, 2008, and June 30, 2008 and 2007 respectively.

8. Deferred Charges

Deferred charges consist of the following as of December 31, 2008 and June 30, 2008 and 2007:

	December 31,		June 30,
	2008		2008		2007
Regulatory asset for property tax	$	1,554,244	$	1,707,370	$	2,013,623
Regulatory asset for income taxes		452,646		452,646		452,646
Regulatory assets for deferred environmental remediation costs		114,960		149,625		247,617
Rate case costs		18,538		11,525		—
Unamortized debt issue costs		417,768		440,490		317,539
Total	$	2,558,156	$	2,761,656	$	3,031,425

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

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

F-18

9. Accrued and Other Current Liabilities

Accrued and other current liabilities consist of the following as of December 31, 2008, and June 30, 2008 and 2007:

	December 31,		June 30,
	2008		2008		2007
Property tax settlement—current portion	$	235,772	$	235,772	$	243,000
Payable to employee benefit plans		57,617		119,269		132,131
Accrued vacation		464,153		310,472		224,588
Customer deposits		501,248		498,880		394,128
Accrued interest		4,897		276		9,069
Accrued taxes other than income		457,084		474,775		506,448
Deferred short-term gain		—		—		243,519
Deferred payments from levelized billing		2,075,860		554,765		605,031
Other		1,150,817		1,108,503		734,812
Total	$	4,947,448	$	3,302,712	$	3,092,726

10. Other Long-Term Liabilities

Other long-term liabilities consist of the following as of December 31, 2008 and June 30, 2008 and 2007:

	December 31,		June 30,
	2008		2008		2007
Asset retirement obligation	$	746,199	$	726,231	$	688,371
Customer advances for construction		824,955		734,862		605,221
Deferred gain — long-term		—		—		82,063
Regulatory liability for income taxes		83,161		83,161		83,161
Property tax settlement		729,008		972,008		1,215,008
Total	$	2,383,323	$	2,516,262	$	2,673,824

11. Credit Facility and Long-Term Debt

On June 29, 2007, the Company replaced its existing credit facility and long-term notes with a new $20,000,000 revolving credit facility with Bank of America and issued $13,000,000 of 6.16% Senior unsecured notes. The prior Bank of America credit facility had been secured, on an equal and ratable basis with our previously outstanding long-term debt, by substantially all of our assets.

Bank of America Line of Credit The new credit facility includes an annual commitment fee equal to 0.20% of the unused portion of the facility and interest on amounts outstanding at the London Interbank Offered Rate, plus 120 to 145 basis points, for interest periods selected by the Company. At December 31, 2008, we had outstanding letters of credit related to supply contracts totaling $1.2 million. These letters of credit reduce the available borrowings on our line of credit.

For the six months ended December 31, 2008, the weighted average interest rate on the facility was 4.20%.

F-19

$13,000,000 6.16% Senior Unsecured Notes — On June 29, 2007, the Company authorized the sale of $13,000,000 aggregate principal amount of its 6.16% Senior Unsecured Notes, due June 29, 2017. The proceeds of these notes were used to refinance our existing notes — the Series 1997 Notes, the Series 1993 Notes, and the Series 1992B Industrial Development Revenue Obligations. With this refinancing, we expensed the remaining debt issue costs of $991,000 in fiscal 2007, and incurred approximately $463,000 in new debt issue costs to be amortized over the life of the note.

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

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

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

Term Loan — In 2004, in addition to the Series 1997 and 1993 Notes and the 1992B Bonds discussed above, the Company had a revolving credit agreement with Bank of America. In March 2004, the Company converted $8,000,000 of existing revolving loans into a $6,000,000, five-year term loan with principal payments of $33,333 each month and a $2,000,000 short-term loan. On May 26, 2005, the Company completed the sale of 287,500 common shares at a price of $8.00 per share for net proceeds of $2,202,956 after deducting $97,044 of issuance expenses. $2,000,000 of the equity proceeds were immediately used to pay off the $2,000,000 short-term loan. The remaining balance of the $6,000,000 five-year term loan was paid in full on April 2, 2007 with proceeds from the sale of the Arizona propane assets.

F-20

Debt Covenants — The Company’s 6.16% Senior Unsecured Note and Bank of America credit facility agreements contain various covenants, which include, among others, limitations on total dividends and distributions made in the immediately preceding 60-month period to 75% of aggregate consolidated net income for such period, restrictions on certain indebtedness, limitations on asset sales, and maintenance of certain debt-to-capital and interest coverage ratios. At December 31, 2008 and June 30, 2008 and 2007, the Company believes it was in compliance with the financial covenants under its debt agreements.

12. 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 six months ended December 31, 2008 and 2007, and the years ended June 30, 2008, 2007 and 2006 were $170,766, $123,232 (unaudited), $130,107, $132,131, and $272,300 respectively.

The Company makes matching contributions in the form of Company stock equal to 10% of each participant’s elective deferrals in our 401k Plan. The Company contributed shares of our stock valued at $24,735, $21,690, and 19,436 in the fiscal years ended June 30 2008, 2007 and 2006, respectively. The Company contributed shares of our stock valued at $17,493 and $10,908 (unaudited) during the six months ended December 31, 2008 and 2007, respectively. In addition, a portion of our 401k Plan consists of an Employee Stock Ownership Plan (“ESOP”) that covers most of our employees. The ESOP receives contributions of our common stock from the Company each year as determined by the Board of Directors. The contribution is recorded based on the current market price of our common stock. The Company made no contributions for the six months ended December 31, 2008 and 2007 or the fiscal years ended June 30, 2008 and 2007.

The Company has sponsored a defined postretirement health benefit plan (the “Retiree Health Plan”) providing health and life insurance benefits to eligible retirees. The Plan pays eligible retirees (post-65 years of age) up to $125 per month in lieu of contracting for health and life insurance benefits. The amount of this payment is fixed and will not increase with medical trends or inflation. In addition, our Retiree Health Plan allows retirees between the ages of 60 and 65 and their spouses to remain on the same medical plan as active employees by contributing 125% of the current COBRA rate to retain this coverage. The 25% in excess of the current COBRA rate is held in the VEBA trust account, and benefits for this plan are paid from assets held in the VEBA Trust account. During fiscal 2006, the Company discontinued contributions and is no longer required to fund the Retiree Health Plan. As of December 31, 2008, the value of plan assets is $300,616. The assets remaining in the trust will be used to fund the plan until these assets are exhausted. Therefore, the Company has eliminated any accrual for future contributions to the plan.

F-21

13. Income Taxes

Significant components of our deferred tax assets and liabilities as of December 31, 2008, and June 30, 2008 and 2007 are as follows:

	December 31,						June 30,
	2008						2008						2007
	Current			Long-Term			Current			Long-Term			Current			Long-Term
Deferred tax asset:
Allowances for doubtful accounts	$	79,323		$	—		$	58,047		$	—		$	23,827		$	—
Unamortized investment tax credit		—			(17,502	)		—			2,806			—			10,907
Contributions in aid of construction		—			334,460			—			349,538			—			318,455
Property, plant, and equipment		—			8,858,733			—			14,432,180			—			—
Other nondeductible accruals		203,893			26,265			359			—			77,445			—
Recoverable purchase gas costs		—			—			—			—			—			—
Derivatives		31,561			—			31,561			—			93,657			—
Deferred incentive and pension accrual		—			4,147			—			60,875			—			14,997
Unrealized loss on securities held for sale		199,454			—			—			—			—			—
Net operating loss (NOL) carryforwards					3,660,736
Other		10,383			972,409			92,588			511,596			—			533,298
Total		524,614			13,839,248			182,555			15,356,995			194,929			877,657
Deferred tax liabilities:
Recoverable purchase gas costs		418,575			—			234,297			—			189,294			—
Property, plant, and equipment		—			—			—			—			—			5,110,398
Debt issue costs		—			—			—			—			—			—
Property tax liability		—			403,341			—			190,134			—			214,028
Covenant not to compete		—			36,010			—			2,624,737			—			42,374
Other		(119,914	)		236,701			(33,703	)		71,133			(47,735	)		96,027
Total		298,661			676,502			200,594			2,886,004			141,559			5,462,827
Net deferred tax asset (liabilities)		225,953			13,163,196			(18,039	)		12,470,991			53,370			(4,585,170	)
Less valuation allowance		—			(7,469,886)	)		—			(5,645,416	)		—			—
Net deferred tax asset (liabilities)	$	225,953		$	5,693,310		$	(18,039	)	$	6,825,575		$	53,370		$	(4,585,170	)

F-22

Income tax expense for the six months ended December 31, 2008 and 2007 and the years ended June 30, 2008 and 2007 consists of the following:

	December 31,						June 30,
	2008			2007			2008			2007			2006
				(unaudited)
Current income taxes:
Federal	$	(120,435	)	$	232,406		$	1,058,405		$	957,135		$	1,281,537
State		(39,303	)		18,847			52,121			164,240			131,331
Total current income taxes		(159,738	)		251,253			1,110,526			1,121,375			1,412,868
Deferred income taxes:
Federal		944,144			27,146			241,244			137,881			(240,349	)
State		152,582			5,960			1,980			34,470			(42,414	)
Total deferred income taxes		1,096,726			33,106			243,224			172,351			(282,763	)
Total income taxes before credits		936,988			284,359			1,353,750			1,293,726			1,130,105
Investment tax credit, net		(10,531	)		(10,531	)		(21,062	)		(21,062	)		(21,062	)
Total income tax expense	$	926,457		$	273,828		$	1,332,688		$	1,272,664		$	1,109,043

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

	December 31,						June 30,
	2008			2007			2008			2007			2006
				(unaudited)
Tax expense at statutory rate of 34%	$	708,913		$	475,253		$	1,578,981		$	1,200,249		$	1,026,763
State income tax, net of federal tax benefit		92,993			65,138			179,835			154,620			132,271
Amortization of deferred investment tax credits		(10,531	)		(10,531	)		(21,062	)		(21,062	)		(21,062	)
Other		135,082			(256,032	)		(405,066	)		(61,143	)		(28,929	)
Total	$	926,457		$	273,828		$	1,332,688		$	1,272,664		$	1,109,043

Income tax from discontinued operations was $0, $2,499,875, and $265,663 in fiscal years ended June 30, 2008, 2007 and 2006, respectively.

F-23

14. Segments of Operations

The following tables set forth summarized financial information for the Company’s natural gas operations, marketing and production operations, pipeline operations, discontinued (formerly propane) operations, and corporate and other operations. The Company classifies its segments to provide investors with the view of the business through management’s eyes. The Company primarily separates its state regulated utility businesses from the non-regulated marketing and production business and from the federally regulated pipeline business. The Company has regulated utility businesses in the states of Montana, Wyoming, North Carolina and Maine and these businesses are aggregated together to form our natural gas operations. Transactions between reportable segments are accounted for on the accrual basis, and eliminated prior to external financial reporting. Inter-company eliminations between segments consist primarily of gas sales from the marketing and production operations to the natural gas operations, inter-company accounts receivable, accounts payable, equity, and subsidiary investment:

Six Months Ended December 31, 2008

	Natural Gas						Pipeline			Corporate and
	Operations			EWR			Operations			Other			Eliminations			Consolidated
Operating revenue:
Natural gas operations	$	29,158,035		$	—		$	—		$	—		$	(317,912	)	$	28,840,123
Marketing and wholesale		—			14,623,793			—			—			(4,932,233	)		9,691,560
Pipeline operations		—			—			226,157			—			—			226,157
Total operating revenue		29,158,035			14,623,793			226,157			—			(5,250,145	)		38,757,840
Gas purchased		19,777,820			—			—			—			(317,912	)		19,459,908
Gas and electric — wholesale		—			12,702,580			—			—			(4,932,233	)		7,770,347
Distribution, general, and administrative		5,460,205			205,087			52,114			—			—			5,717,406
Maintenance		317,112			40			2,646			—			—			319,798
Depreciation and amortization		841,405			152,767			29,209			—			—			1,023,381
Taxes other than income		1,260,475			11,155			12,927			—			—			1,284,557
Operating expenses		27,657,017			13,071,629			96,896			—			(5,250,145	)		35,575,397
Operating income		1,501,018			1,552,164			129,261			—			—			3,182,443
Other income		160,326			(36,516	)		94			(544,253	)		—			(420,349	)
Interest (expense)		(584,484	)		(83,300	)		(9,272	)		—			—			(677,056	)
Income from continuing operations before income taxes		1,076,860			1,432,348			120,083			(544,253	)		—			2,085,038
Income taxes (expense)		(518,933	)		(550,701	)		(45,943	)		189,120			—			(926,457	)
Net income	$	557,927		$	881,647		$	74,140		$	(355,133	)	$	—		$	1,158,581
Capital expenditures and natural gas properties	$	4,648,150		$	68,700		$	—		$	—		$	—		$	4,716,850
Total assets	$	59,748,521		$	7,819,863		$	717,977		$	28,468,131		$	(20,935,527	)	$	75,818,965
Equity Method investments	$	—		$	1,081,423		$	—		$	—		$	—		$	1,081,423

F-24

Six Months Ended December 31, 2007 (unaudited)

	Natural Gas						Pipeline			Corporate and
	Operations			EWR			Operations			Other		Eliminations			Consolidated
Operating revenue:
Natural gas operations	$	21,417,728		$	—		$	—		$	—	$	(299,433	)	$	21,118,295
Marketing and wholesale		—			10,519,272			—			—		(3,511,150	)		7,008,122
Pipeline operations		—			—			186,855			—		—			186,855
Total operating revenue		21,417,728			10,519,272			186,855			—		(3,810,583	)		28,313,272
Gas purchased		14,271,860			—			—			—		(299,433	)		13,972,427
Gas and electric — wholesale		—			9,433,766			—			—		(3,511,150	)		5,922,616
Distribution, general, and administrative		4,341,105			188,163			72,640			—		—			4,601,908
Maintenance		323,332			595			1,988			—		—			325,915
Depreciation and amortization		737,472			123,713			28,186			—		—			889,371
Taxes other than income		845,191			8,222			10,200			—		—			863,613
Operating expenses		20,518,960			9,754,459			113,014			—		(3,810,583	)		26,575,850
Operating income		898,768			764,813			73,841			—		—			1,737,422
Other income		189,990			67			36			—		—			190,093
Interest (expense)		(461,980	)		(59,054	)		(8,677	)		—		—			(529,711	)
Income from continuing operations before income taxes		626,778			705,826			65,200			—		—			1,397,804
Income taxes (expense)		(119,284	)		(135,452	)		(19,092	)		—		—			(273,828	)
Net income before extraordinary item		507,494			570,374			46,108			—		—			1,123,976
Extraordinary gain		—									6,819,182					6,819,182
Net income	$	507,494		$	570,374		$	46,108		$	6,819,182	$	—		$	7,943,158
Capital expenditures and natural gas properties	$	1,150,194		$	197,258		$	37,088		$	—	$	—		$	1,384,540

F-25

Year Ended June 30, 2008

	Natural Gas						Pipeline			Corporate and
	Operations			EWR			Operations			Other			Eliminations			Consolidated
Operating revenue:
Natural gas operations	$	60,093,090		$	—		$	—		$	—		$	(754,094	)	$	59,338,996
Marketing and wholesale		—			29,395,960			—			—			(12,271,879	)		17,124,081
Pipeline operations		—			—			370,171			—			—			370,171
Total operating revenue		60,093,090			29,395,960			370,171			—			(13,025,973	)		76,833,248
Gas purchased		42,091,491			—			—			—			(754,094	)		41,337,397
Gas and electric — wholesale		—			27,105,232			—			—			(12,271,879	)		14,833,353
Distribution, general, and administrative		9,710,294			370,374			140,087			441,123			—			10,661,878
Maintenance		641,211			1,094			8,248			—			—			650,553
Depreciation and amortization		1,566,359			242,551			56,384			—			—			1,865,294
Taxes other than income		2,035,403			16,704			28,037			—			—			2,080,144
Operating expenses		56,044,758			27,735,955			232,756			441,123			(13,025,973	)		71,428,619
Operating income		4,048,332			1,660,005			137,415			(441,123	)		—			5,404,629
Other income		245,487			578			17			69,697			—			315,779
Interest (expense)		(933,655	)		(124,827	)		(17,863	)		—			—			(1,076,345	)
Income from continuing operations before income taxes		3,360,164			1,535,756			119,569			(371,426	)		—			4,644,063
Income taxes (expense)		(1,091,105	)		(343,646	)		(40,007	)		142,070			—			(1,332,688	)
Net income before extraordinary item		2,269,059			1,192,110			79,562			(229,356	)		—			3,311,375
Extraordinary gain		—									6,819,182						6,819,182
Net income	$	2,269,059		$	1,192,110		$	79,562		$	6,589,826		$	—		$	10,130,557
Capital expenditures and natural gas properties	$	3,578,307		$	250,091		$	41,434		$	—		$	—		$	3,869,832
Total assets	$	49,414,217		$	7,486,996		$	988,318		$	25,713,911		$	(25,226,352	)	$	58,377,090
Equity Method Investments	$	—		$	1,118,264		$	—		$	—		$	—		$	1,118,264

F-26

Year Ended June 30, 2007

	Natural Gas						Pipeline			Discontinued
	Operations			EWR			Operations			Operations			Eliminations			Consolidated
Operating revenue:
Natural gas operations	$	47,074,560		$	—		$	—		$	—		$	(635,054	)	$	46,439,506
Marketing and wholesale		—			22,466,030			—			—			(9,920,671	)		12,545,359
Pipeline operations		—			—			388,175			—			—			388,175
Total operating revenue		47,074,560			22,466,030			388,175			—			(10,555,725	)		59,373,040
Gas purchased		34,177,047			—			—			—			(635,054	)		33,541,993
Gas and electric — wholesale		—			20,185,304			—			—			(9,920,671	)		10,264,633
Distribution, general, and administrative		5,676,195			315,279			206,055			—			—			6,197,529
Maintenance		563,912			297			2,474			—			—			566,683
Depreciation and amortization		1,414,003			222,110			56,373			—			—			1,692,486
Taxes other than income		1,652,661			20,529			23,746			—			—			1,696,936
Operating expenses		43,483,818			20,743,519			288,648			—			(10,555,725	)		53,960,260
Operating income		3,590,742			1,722,511			99,527			—			—			5,412,780
Other income		228,515			1,592			11,412			—			—			241,519
Interest (expense)		(1,896,650	)		(185,365	)		(42,140	)		—			—			(2,124,155	)
Income from continuing operations before income taxes		1,922,607			1,538,738			68,799			—			—			3,530,144
Income taxes (expense)		(653,130	)		(593,078	)		(26,456	)		—			—			(1,272,664	)
Income from continuing operations		1,269,477			945,660			42,343			—			—			2,257,480
Discontinued operations:
Gain from disposal of operations		—			—			—			5,479,166			—			5,479,166
Income from discontinued operations		—			—			—			975,484			—			975,484
Income tax (expense)		—			—			—			(2,499,875	)		—			(2,499,875	)
Income from discontinued operations		—			—			—			3,954,775			—			3,954,775
Net income	$	1,269,477		$	945,660		$	42,343		$	3,954,775		$	—		$	6,212,255
Capital expenditures and natural gas properties	$	2,024,443		$	361,379		$	21,088		$	—		$	—		$	2,406,910
Total assets	$	38,260,280		$	5,882,390		$	1,003,145		$	—		$	6,436,001		$	51,581,816
Equity Method Investments	$	—		$	—		$	—		$	—		$	—		$	—

F-27

Year Ended June 30, 2006

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

F-28

15. Stockholders’ Equity

Our common stock trades on the Nasdaq Global Market under the symbol “EWST.” On February 1, 2008, the Board of Directors authorized a 3-for-2 stock split of the company’s $0.15 par value common stock. As a result of the split, 1,437,744 additional shares were issued, and additional paid-in capital was reduced by $215,619. All references in the accompanying financial statements to the number of common shares and per-share amounts for fiscal 2008, 2007 and 2006 have been restated to reflect the stock split.

Purchases of Equity Securities by Our Company and Affiliated Purchasers

					Total number of		Maximum number of
					shares purchased as		shares that may yet be
	Total Shares		Average price		part of publicly		purchased under the
Period	Purchased		paid per share		announced plans		stock repurchase plan
May 30, 2007 – June 30, 2007		219,522	$	10.00		219,522
July 1, 2007 – June 30, 2008		16,780	$	9.50		16,780
July 1, 2008 – December 31, 2008		53,416	$	7.60		53,416
		289,718				289,718		158,782

All shares adjusted for 3-for-2 stock split effectuated February 1, 2008.

On February 13, 2007, our Board of Directors approved a stock repurchase plan whereby the company intends to buy back up to 448,500 shares of the company’s common stock. We began this stock buyback on May 30, 2007. The stock repurchases included 217,500 shares from Mr. Mark Grossi, one of our directors. During the six months ended December 31, 2008, we repurchased 53,416 shares of common stock.

2002 Stock Option Plan — The Energy West Incorporated 2002 Stock Option Plan (the “Option Plan”) provides for the issuance of up to 300,000 shares of our common stock to be issued to certain key employees. As of December 31, 2008, there are 29,500 options outstanding and the maximum number of shares available for future grants under this plan is 63,500 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.

During fiscal year 2008, 54,375 stock options were exercised in a noncash transaction for the exercise price of $333,988. As part of the transaction, 37,500 shares were canceled and returned to authorized/unissued stock at a value of $374,499. These shares were accepted by the Company as total payment of the exercise price and the employee’s share of related payroll taxes.

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.

F-29

A summary of the status of our stock option plans as of December 31, 2008, and June 30, 2008 and 2007, and changes during the six months and years ended on these dates is presented below.

				Weighted		Aggregate
	Number of			Average		Intrinsic
	Shares			Exercise Price		Value
Outstanding June 30, 2005		189,000		$	5.56
Granted		72,750		$	6.74
Exercised		(3,750	)	$	5.66
Expired		(39,750	)	$	—
Outstanding June 30, 2006		218,250		$	5.56
Granted		45,000		$	7.03
Exercised		(93,750	)	$	5.47
Expired		(4,500	)	$	—
Outstanding June 30, 2007		165,000		$	5.98
Granted		30,000		$	6.59
Exercised		(109,500	)	$	3.82
Expired		(66,000	)	$	—
Outstanding June 30, 2008		19,500		$	9.10
Granted		10,000		$	7.10
Exercised		—		$	—
Expired		—		$	—
Outstanding December 31, 2008		29,500		$	8.42	$	20,210
Exerciseable December 31, 2008		10,000		$	9.22	$	2,900

The weighted average fair value of options granted during the six months ended December 31, 2008 and years ended June 30, 2008, 2007 and 2006 was $2.52, $2.33, $2.50, and $3.11, respectively. At December 31, 2008, there was $36,382 of total unrecognized compensation cost related to stock-based compensation. That cost is expected to be recognized over a period of three years.

F-30

The following information applies to options outstanding at December 31, 2008:

							Weighted
							Average
					Weighted		Remaining				Weighted
					Average		Contractual				Average
Grant	Exercise		Number		Exercise		Life		Number		Exercise
Date	Price		Outstanding		Price		(Years)		Exercisable		Price
1/6/2006	$	6.35		4,500	$	6.35		2.01		—	$	6.35
12/1/2007	$	9.93		15,000	$	9.93		8.92		7,500	$	9.93
12/1/2008	$	7.10		10,000	$	7.10		9.92		2,500	$	7.10
				29,500						10,000

The weighted-average exercise price per stock option granted during the six months ended December 31, 2008 and 2007 (unaudited) and the years ended June 30, 2008 and 2007 was $7.10 $9.88 (unaudited), $9.88, and $7.04, respectively. For the six months ended December 31, 2008 and 2007, and the years ended June 30, 2008 and 2007, all stock options granted have an exercise price equal to the fair market value of the Company’s stock at the date of grant.

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

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

F-31

16. 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 December 31, 2008 is as follows:

Year ending December 31:
2009	$	4,258,896
2010		1,064,724
Total	$	5,323,620

The Company’s operating unit, Bangor Gas Company, LLC entered into an agreement with Maritimes and Northeast Pipeline for the transportation and storage of natural gas. Future obligations due to Maritimes and Northeast Pipeline consist of the following:

Year ending December 31:
2009	$	500,874
2010		500,874
2011		500,874
2012		500,874
2013		500,874
Thereafter		2,093,348
Total	$	4,597,718

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 December 31, 2008, we had incurred cumulative costs of approximately $2.1 million in connection with our evaluation and remediation of the site. On May 30, 1995, we received an order from the Montana Public Service Commission (“MPSC”) allowing for recovery of the costs associated with the evaluation and remediation of the site through a surcharge on customer bills. As of December 31, 2008, we had recovered approximately $2.0 million through such surcharges. As of December 31, 2008, the cost remaining to be recovered through the on-going rate is $115,000.

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

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

Litigation — The Company is involved in lawsuits that have arisen in the ordinary course of business. The Company is contesting each of these lawsuits vigorously and believes it has defenses to the allegations that have been made.

F-32

On February 21, 2008, a lawsuit captioned Shelby Gas Association v. Energy West Resources, Inc., Case No. DV-08-008, was filed in the Ninth Judicial District Court of Toole County, Montana. Shelby Gas Association (Shelby) alleges a breach of contract by the Company’s subsidiary, EWR, to provide natural gas to Shelby. Shelby is seeking damages and injunctive relief prohibiting EWR from further breaching the contract. The case is currently in the discovery phase. The Company believes this lawsuit to be without merit and is vigorously defending the allegations.

In the Company’s opinion, the outcome of these lawsuits, including the Shelby litigation, will not have a material adverse effect on the Company’s financial condition, cash flows or results of operations.

We are party to certain other legal proceedings in the normal course of our business, that, in the opinion of management, are not material to our business or financial condition. 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, 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:
December 31, 2009		133,367
December 31, 2010		25,420
December 31, 2011		9,771
December 31, 2012		7,126
December 31, 2013		3,147
Thereafter		62,497
	$	241,328

Lease expense from continuing operations resulting from operating leases for the six months ended December 31, 2008 and 2007 and the years ended June 30, 2008, 2007 and 2006 totaled $149,563, $78,603 (unaudited), $233,947, $90,624 and $90,624, respectively.

17. Financial Instruments and Risk Management

Management of Risks Related to Derivatives — The Company and its subsidiaries are subject to certain risks related to changes in certain commodity prices and risks of counterparty performance. The Company has established policies and procedures to manage such risks. The Company has a Risk Management Committee comprised of Company officers and management to oversee our risk management program as defined in its risk management policy. The purpose of the risk management program is to minimize adverse impacts on earnings resulting from volatility of energy prices, counterparty credit risks, and other risks related to the energy commodity business.

In order to mitigate the risk of natural gas market price volatility related to firm commitments to purchase or sell natural gas or electricity, from time to time the Company and its subsidiaries have entered into hedging arrangements. Such arrangements may be used to protect profit margins on future obligations to deliver gas at a fixed price, or to protect against adverse effects of potential market price declines on future obligations to purchase gas at fixed prices.

The Company accounts for certain of such purchases or sale agreements in accordance with SFAS No. 133. Under SFAS 133, such contracts are reflected in our financial statements as derivative assets or derivative liabilities and valued at “fair value,” determined as of the date of the balance sheet. Fair value accounting treatment is also referred to as “mark-to-market” accounting. Mark-to-market accounting results in disparities between reported earnings and realized cash flow, because changes in the derivative values are reported in our Consolidated Statement of Income as an increase or (decrease) in “Revenues — Gas and Electric — Wholesale” without regard to whether any cash payments have been made between the parties to the contract. If such contracts are held to maturity, the cash flow from the contracts and their hedges are realized over the life of the contracts. SFAS No. 133 requires that contracts for purchase or sale at fixed prices and volumes must be valued at fair value (under mark-to-market accounting) unless the contracts qualify for treatment as a “normal purchase or normal sale.”

F-33

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 December 31, 2008, all of the Company’s contracts for purchase or sale at fixed prices and volumes qualified for treatment as a “normal purchase or a normal sale.”

18. Pending Acquisitions

As previously disclosed, on September 12, 2008, we entered into a stock purchase agreement with Richard M. Osborne, Trustee, Rebecca Howell, Stephen G. Rigo, Marty Whelan and Thomas J. Smith (collectively, the “Sellers”) whereby we agreed to purchase all of the common stock of Lightning Pipeline Co. (“Lightning Pipeline”), Great Plains Natural Gas Company (“Great Plains”), Brainard Gas Corp. (“Brainard”) and all of the membership units of Great Plains Land Development Co., Ltd. (“GPL”), which companies are primarily owned by an entity controlled by Mr. Osborne and wholly-owned by the Sellers, for a purchase price of $34.3 million. Pursuant to the agreement, we will acquire Orwell Natural Gas Company (“Orwell”), a wholly-owned subsidiary of Lightening Pipeline and Northeast Ohio Natural Gas Corp. (“NEO”), a wholly-owned subsidiary of Great Plains. Orwell, NEO and Brainard are natural gas distribution companies that serve approximately 21,000 customers in Northeastern Ohio and Western Pennsylvania. This acquisition will increase our customers by more than 50%.

Mr. Osborne is chairman, chief executive officer and a director, Mr. Smith is vice president, chief financial officer and a director, and Ms. Howell is secretary of Energy West. The $34.3 million purchase price consists of our assumption of approximately $20.9 million in debt with the remainder of the purchase price to be paid in unregistered shares of common stock of Energy West based on a price of $10.00 per share. The stock portion of the purchase price may be increased or decreased within three business days prior to closing of the transaction depending on the number of active customers of Orwell, Brainard and NEO. The Sellers have the right to elect to terminate the transaction, upon the payment of a $100,000 fee, if the average closing price of our common stock for the twenty consecutive trading days ending seven calendar days prior to closing is below $9.49 and if our common stock underperforms the American Gas Stock Index (as maintained by the American Gas Association) by more than 20%, as described in the agreement. However, we may prevent termination of the transaction in this instance by increasing the number of shares of our common stock paid to the Sellers as part of the purchase price. The agreement also contains customary representations, warranties, covenants and indemnification provisions.

The transaction is expected to close in the second half of 2009 but there can be no assurances that the transaction will be completed on the proposed terms or at all. The closing is subject to customary closing conditions, including the approval of applicable regulators.

F-34

19. Quarterly Information (Unaudited)

Quarterly results (unaudited) for the six months ended December 31, 2008 and 2007 and the years ended June 30, 2008 and 2007 are as follows (in thousands, except per share data):

Six Months Ended December 31, 2008

	For the quarters ended
	September 30		December 31
	2008		2008
Revenues	$	13,987	$	24,771
Gross margin	$	4,544	$	6,984
Operating income	$	711	$	2,471
Income (loss) before extraordinary items	$	386	$	773
Extraordinary gain	$	0	$	0
Net income (loss)	$	386	$	773
Basic earnings (loss) before extraordinary items per common share	$	0.09	$	0.18
Basic earnings (loss) per common share — extraordinary gain	$	0.00	$	0.00
Basic earnings (loss) per common share — net income	$	0.09	$	0.18
Diluted earnings (loss) per share	$	0.09	$	0.18
Diluted earnings (loss) per share — extraordinary gain	$	0.00	$	0.00
Diluted earnings (loss) per share — net income	$	0.09	$	0.18

F-35

Year Ended June 30, 2008

	For the quarters ended
	September 30		December 31		March 31		June 30
	2007		2007		2008		2008
Revenues	$	6,951	$	20,171	$	30,878	$	18,833
Gross margin	$	2,675	$	5,742	$	7,639	$	4,606
Operating income	$	117	$	1,620	$	3,553	$	114
Income (loss) before extraordinary items	$	75	$	1,049	$	2,307	$	(120	)
Extraordinary gain	$	0	$	6,819	$	0	$	0
Net income (loss)	$	75	$	7,868	$	2,307	$	(120	)
Basic earnings (loss) before extraordinary items per common share	$	0.02	$	0.24	$	0.53	$	(0.03	)
Basic earnings (loss) per common share — extraordinary gain	$	0.00	$	1.59	$	0.00	$	0.00
Basic earnings (loss) per common share — net income	$	0.02	$	1.83	$	0.53	$	(0.03	)
Diluted earnings (loss) per share	$	0.02	$	0.24	$	0.53	$	(0.03	)
Diluted earnings (loss) per share — extraordinary gain	$	0.00	$	1.58	$	0.00	$	0.00
Diluted earnings (loss) per share — net income	$	0.02	$	1.83	$	0.53	$	(0.03	)

Year Ended June 30, 2007

	For the quarters ended
	September 30			December 31		March 31		June 30
	2006			2006		2007		2007
Revenues	$	8,456		$	18,041	$	21,516	$	11,360
Gross margin	$	3,200		$	5,566	$	6,935	$	3,225
Operating income	$	326		$	2,121	$	2,358	$	606
Income (loss) from continuing operations	$	4		$	1,113	$	1,293	$	(152	)
Discontinued operations	$	(199	)	$	157	$	636	$	3,360
Net income (loss)	$	(195	)	$	1,270	$	1,929	$	3,208
Basic earnings (loss) per common share — continuing operations	$	0.00		$	0.25	$	0.29	$	(0.03	)
Basic earnings (loss) per common share — discontinued operations	$	(0.05	)	$	0.04	$	0.14	$	0.76
Basic earnings (loss) per common share — net income	$	(0.04	)	$	0.29	$	0.43	$	0.72
Diluted earnings (loss) per share — continuing operations	$	0.00		$	0.25	$	0.28	$	(0.03	)
Diluted earnings (loss) per share — discontinued operations	$	(0.04	)	$	0.04	$	0.14	$	0.75
Diluted earnings (loss) per share — net income	$	(0.04	)	$	0.28	$	0.42	$	0.71

Certain revenue items have been restated from prior published reports.

F-36

EXHIBIT INDEX

3.1	(a)	Restated Articles of Incorporation. Filed as 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 and incorporated herein by reference
3.1	(b)	Articles of Amendment to the Articles of Incorporation dated January 28, 2008. Filed as Exhibit 3.1 to the Registrant’s Current Report on Form 8-K dated February 1, 2008 and incorporated herein by reference
3.1	(c)	Articles of Amendment to the Articles of Incorporation dated December 5, 2007. Filed as Exhibit 3.1(e) to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended December 31, 2007 and incorporated herein by reference
3.1	(d)	Articles of Amendment to the Articles of Incorporation dated May 29, 2007. Filed as Exhibit 3.1 to the Registrant’s Current Report on Form 8-K, filed on June 4, 2007, and incorporated herein by reference
3.2		Amended and Restated Bylaws. Filed as Exhibit 3.2 to the Registrant’s Current Report on Form 8-K on March 5, 2004 and incorporated herein by reference
3.2	(a)	Amendment No. 3 to Amended and Restated Bylaws dated August 12, 2008. Filed as Exhibit 3.1 to the Registrant’s Current Report on Form 8-K dated August 12, 2008 and incorporated herein by reference
3.2	(b)	Amendment No. 2 to Amended and Restated Bylaws dated April 10, 2008. Filed as Exhibit 3.1 to the Registrant’s Current Report on Form 8-K dated April 10, 2008 and incorporated herein by reference
3.2	(c)	Amendment No. 1 to Amended and Restated Bylaws dated November 14, 2007. Filed as Exhibit 3.1 to the Registrant’s Current Report on Form 8-K dated November 14, 2007 and incorporated herein by reference
10.1		Satisfaction and Discharge of Indenture dated June 22, 2007, between the Registrant and HSBC Bank USA, National Association, as Successor Trustee for the Series 1997 Notes. Filed as Exhibit 10.1 to the Registrant’s Current Report on Form 8-K, filed July 5, 2007, and incorporated herein by reference
10.2		Satisfaction and Discharge of Indenture dated June 22, 2007, between the Registrant and US Bank National Association, as Successor Trustee for the Series 1993 Notes. Filed as Exhibit 10.2 to the Registrant’s Current Report on Form 8-K, filed July 5, 2007, and incorporated herein by reference.
10.3		Discharge of Obligor under Indenture dated June 22, 2007, between the Registrant and HSBC Bank USA, National Association, as Successor Trustee for the Series 1992-B Bonds. Filed as Exhibit 10.3 to the Registrant’s Current Report on Form 8-K, filed July 5, 2007, and incorporated herein by reference
10.4		Note Purchase Agreement dated June 29, 2007, between the Registrant and various Purchasers relating to 6.16% Senior Unsecured Notes due June 29, 2017. Filed as Exhibit 10.4 to the Registrant’s Current Report on Form 8-K, filed July 5, 2007, and incorporated herein by reference
10.5		Credit Agreement dated as of June 29, 2007, by and among the Registrant and various financial institutions and LaSalle Bank National Association. Filed as Exhibit 10.5 to the Registrant’s Current Report on Form 8-K, filed July 5, 2007, and incorporated herein by reference.
10.6		Amendment dated October 22, 2007 to the Credit Agreement among the Registrant, various financial institutions and LaSalle Bank National Association, as agent. Filed as Exhibit 10.1 to the Registrant’s Current Report on Form 8-K dated October 22, 2007 and incorporated herein by reference
10.7	†	Energy West, Incorporated 2002 Stock Option Plan. Filed as Appendix A to the Registrant’s Proxy Statement on Schedule 14A, filed on October 30, 2002, and incorporated herein by reference
10.8	*†	First Amendment to Energy West Incorporated 2002 Stock Option Plan

10.9	†	Employee Stock Ownership Plan Trust Agreement. Filed as Exhibit 10.2 to Registration Statement on Form S-1 (File No. 33-1672) is incorporated herein by reference
10.10	†	Management Incentive Plan. Filed as 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, and incorporated herein by reference
10.11	†	Energy West Senior Management Incentive Plan. Filed as Exhibit 10.19 to the Registrant’s Annual Report on Form 10-K for the year ended June 30, 2002, filed on September 30, 2002, and incorporated herein by reference
10.12	†	Energy West Incorporated Deferred Compensation Plan for Directors. Filed as Exhibit 10.20 to the Registrant’s Annual Report on Form 10-K for the year ended June 30, 2002, filed on September 30, 2002, and incorporated herein by reference
10.13	*†	Amended and Restated Energy West Incorporated Deferred Compensation Plan for Directors
10.14		Amended and Restated Operating Agreement of Kykuit Resources, LLC, dated October 24, 2007. Filed as Exhibit 10.6 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2007 and incorporated herein by reference
10.15		First Amendment to Amended and Restated Operating Agreement of Kykuit Resources, LLC, dated December 17, 2007. Filed as Exhibit 10.2 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended December 31, 2007 and incorporated herein by reference
10.16		Stock Purchase Agreement dated January 30, 2007 between the Registrant and Sempra Energy. Filed as Exhibit 10.1 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2007 and incorporated herein by reference
10.17		Amendment No. 1 to Stock Purchase Agreement dated April 11, 2007 between the Registrant and Sempra Energy. Filed as Exhibit 10.2 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2007 and incorporated herein by reference
10.18		Amendment No. 2 to Stock Purchase Agreement dated August 7, 2007 between the Registrant and Sempra Energy. Filed as Exhibit 10.3 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2007 and incorporated herein by reference
10.19		Amendment No. 3 to Stock Purchase Agreement, dated November 28, 2007, by and between the Registrant and Sempra Energy. Filed as Exhibit 10.1 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended December 31, 2007 and incorporated herein by reference
10.20		Stock Purchase Agreement dated January 30, 2007 between the Registrant and Sempra Energy. Filed as Exhibit 10.4 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2007 and incorporated herein by reference
10.21		Amendment Number 1 to Stock Purchase Agreement dated August 2, 2007 between the Registrant and Sempra Energy. Filed as Exhibit 10.5 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2007 and incorporated herein by reference
10.22		Stock Purchase Agreement dated December 18, 2007 between the Registrant, Dan F. Whetstone, Pamela R. Lowry, Paula A. Poole, William J. Junkermier and Roger W. Junkermier. Filed as Exhibit 10.1 to the Registrant’s Current Report on Form 8-K dated December 17, 2007 and incorporated herein by reference
10.23		First Amendment to Stock Purchase Agreement dated as of November 11, 2008, between Dan F. Whetstone, Pamela R. Lowry, Paula A. Poole, William J. Junkermier, Roger W. Junkermiern and Energy West, Incorporated. Filed as Exhibit 10.1 to the Registrant’s Current Report on Form 8-K dated November 11, 2008 and incorporated herein by reference
10.24		Non-Competition and Non-Disclosure Agreement dated December 18, 2007 between the Registrant and Daniel F. Whetstone. Filed as Exhibit 10.2 to the Registrant’s Current Report on Form 8-K dated December 17, 2007 and incorporated herein by reference
10.25		Lease Agreement dated February 25, 2008 between OsAir, Inc. and the Registrant. Filed as Exhibit 10.1 to the Registrant’s Current Report on Form 8-K dated February 25, 2008 and incorporated herein by reference

10.26	†	Employment Agreement dated November 16, 2007 between James W. Garrett and the Registrant. Filed as Exhibit 10.1 to the Registrant’s Current Report on Form 8-K dated November 14, 2007 and incorporated herein by reference
10.27	*†	First Amendment to Employment Agreement dated as of December 31, 2008, between Energy West, Incorporated and James W. Garrett
10.28		Gas Sales Agreement dated as of July 1, 2008 between John D. Oil & Gas Marketing Co., LLC, Northeast Ohio Natural Gas Corp., Orwell Natural Gas Company and Brainard Gas Corp. Filed as Exhibit 10.25 to the Registrant’s Annual Report on 10-K for the year ended June 30, 2008 and incorporated herein by reference
10.29		Natural Gas Transportation Service Agreement dated as of July 1, 2008 between Orwell-Trumbull Pipeline Co., LLC, Orwell Natural Gas Company and Brainard Gas Corp. Filed as Exhibit 10.26 to the Registrant’s Annual Report on 10-K for the year ended June 30, 2008 and incorporated herein by reference
10.30		Transportation Service Agreement dated as of July 1, 2008 between Cobra Pipeline Co., Ltd., Northeast Ohio Natural Gas Company, Orwell Natural Gas Company and Brainard Gas Corp. Filed as Exhibit 10.27 to the Registrant’s Annual Report on 10-K for the year ended June 30, 2008 and incorporated herein by reference
10.31		First Amendment dated July 1, 2008 to the Orwell-Trumbull Pipeline Co., LLC Operations Agreement between Orwell Natural Gas Company and Orwell-Trumbull Pipeline Co., LLC. Filed as Exhibit 10.28 to the Registrant’s Annual Report on 10-K for the year ended June 30, 2008 and incorporated herein by reference
10.32		Orwell-Trumbull Pipeline Co., LLC Operations Agreement dated January 1, 2008 between Orwell Natural Gas Company and Orwell-Trumbull Pipeline Co., LLC. Filed as Exhibit 10.29 to the Registrant’s Annual Report on 10-K for the year ended June 30, 2008 and incorporated herein by reference
10.33		Triple Net Lease Agreement dated as of July 1, 2008 between Station Street Partners, LLC and Orwell Natural Gas Company. Filed as Exhibit 10.30 to the Registrant’s Annual Report on 10-K for the year ended June 30, 2008 and incorporated herein by reference
10.34		Triple Net Lease Agreement dated as of July 1, 2008 between OsAir, Inc. and Orwell Natural Gas Company. Filed as Exhibit 10.31 to the Registrant’s Annual Report on 10-K for the year ended June 30, 2008 and incorporated herein by reference.
10.35		Triple Net Lease Agreement dated as of July 1, 2008 between Richard M. Osborne, Trustee and Orwell Natural Gas Company. Filed as Exhibit 10.32 to the Registrant’s Annual Report on 10-K for the year ended June 30, 2008 and incorporated herein by reference
10.36		Triple Net Lease Agreement dated as of July 1, 2008 between OsAir, Inc. and Northeast Ohio Natural Gas Company. Filed as Exhibit 10.33 to the Registrant’s Annual Report on 10-K for the year ended June 30, 2008 and incorporated herein by reference
10.37		Stock purchase agreement dated September 12, 2008, between Energy West, Incorporated, and Richard M. Osborne, trustee, Rebecca Howell, Stephen G. Rigo, Marty Whelan, and Thomas J. Smith, filed as exhibit 10.1 to the registrant’s current report on Form 8-K dated September 17, 2008, and incorporated herein by reference Filed as Exhibit 10.34 to the Registrant’s Annual Report on 10-K for the year ended June 30, 2008 and incorporated herein by reference
10.38	†	Employment Agreement dated August 25, 2006 between Energy West, Incorporated and Kevin J. Degenstein, filed as Exhibit 10.1 to the Registrant’s Current Report on Form 8-K dated September 18, 2006 and incorporated herein by reference
10.39	*†	First Amendment to Employment Agreement dated as of December 31, 2008, between Energy West, Incorporated and Kevin J. Degenstein
10.40	†*	Employment Agreement dated April 13, 2007 between Energy West, Incorporated and David C. Shipley
14		Code of Business Conduct, filed as Exhibit 14 to the Registrant’s Annual Report on 10-K for the year ended June 30, 2006 and incorporated herein by reference.
21	*	Company Subsidiaries
23.1	*	Consent of Hein & Associates 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

†	Management agreement or compensatory plan or arrangement.
*	Filed herewith.