UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

FORM 10-Q

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

For the quarterly period ended March 31, 2005

OR

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

For the transition period from                                                              to                                                             

Commission File number 0-14183

ENERGY WEST, INCORPORATED

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

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

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 checkmark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ

The number of shares outstanding of the issuer’s common stock, $.15 par value per share, as of May 10, 2005 is 2,625,064 shares.

INDEX TO FORM 10-Q FILING
FOR THE QUARTER ENDED MARCH 31, 2005

TABLE OF CONTENTS

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Part I — FINANCIAL INFORMATION

ENERGY WEST, INCORPORATED AND SUBSIDIARIES

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

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ENERGY WEST, INCORPORATED AND SUBSIDIARIES

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

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ENERGY WEST, INCORPORATED AND SUBSIDIARIES

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

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

March 31, 2005

NOTE 1 –	RESTATEMENT OF FINANCIAL RESULTS AND SUMMARY OF THE BUSINESS

Restatement of Financial Results

As previously disclosed in its Annual Report of Form 10-K, the Company has corrected its accounting and previous valuation of certain contracts of Energy West Resources, Inc. (“EWR”) and, as a result, restated the accompanying (unaudited) condensed consolidated financial statements as of March 31, 2004 and for the three and nine-month periods ended March 31, 2004.

The Company’s review of EWR’s contracts included an evaluation of a gas purchase agreement and a gas sales agreement entered into during fiscal year 2002 involving counterparties who are affiliated with each other. The gas purchase agreement had previously been reflected in the Company’s financial statements as a derivative asset. The gas sales agreement was previously classified by the Company as a normal sales contract, and therefore was not reflected on the Company’s financial statements as a derivative liability. The Company determined that a shorter period similar to that of the gas sales agreement should have been used in the determination of the fair value of the gas purchase agreement and that the gas sales agreement does not qualify for the “normal purchase and sale” exception. As a result, the condensed consolidated financial statements for the period ended March 31, 2004 have been restated to reflect a significantly reduced fair value for the gas purchase agreement and the gas sales agreement as a derivative liability at its estimated fair value.

None of the adjustments affects the Company’s cash flows or cash balances. The Company’s cumulative gain (loss) in the portfolio of contracts valued on a mark-to-market basis will be realized in later periods as contracts settle or are performed and/or as natural gas prices change.

As discussed in the table that follows, the condensed consolidated balance sheet at March 31, 2004, and the condensed consolidated statements of operations for the quarter ended March 31, 2004 and the nine months ended March 31, 2004, have been restated from amounts previously reported to reflect the reclassification and revaluation of the gas purchase and gas sale contracts discussed above.

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A summary of the significant effects of the restatement is as follows:

Basis of Presentation

The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by generally accepted accounting principles for complete financial statements. In the opinion of management, all adjustments considered necessary for a fair presentation have been included. Operating results for the three-month period ended March 31, 2005 and the nine-month period ended March 31, 2005 are not necessarily indicative of the results that may be expected for the fiscal year ending June 30, 2005. The financial statements should be read in conjunction with the audited consolidated financial statements and footnotes thereto included in the Company’s Annual Report on Form 10-K for the fiscal year ended June 30, 2004.

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Certain non-regulated, non-utility operations are conducted by three wholly owned subsidiaries of the Company: Energy West Propane, Inc. (“EWP”); Energy West Resources, Inc. (“EWR”); and Energy West Development, Inc. (“EWD”). EWP is engaged in wholesale and retail distribution of bulk propane in Arizona. EWR conducts certain marketing activities involving the sale of natural gas in Montana and Wyoming and electricity in Montana, and owns certain natural gas production properties in Montana. EWD owns a natural gas gathering system that is located in both Montana and Wyoming and an interstate natural gas transportation pipeline that runs between Montana and Wyoming. EWD also owns natural gas production properties in Montana. The Company’s reporting segments are: Natural Gas Operations, Propane Operations, EWR and Pipeline Operations. EWD began operations of an interstate natural gas transmission pipeline on July 1, 2003. The revenue and expenses associated with this transmission pipeline are included in the Pipeline Operations segment.

New Accounting Pronouncements

In December 2004, the Financial Accounting Standards Board (the “FASB”) issued a revision of Statement of Financial Accounting Standards (“SFAS”) No. 123, Accounting for Stock-Based Compensation. The revised statement requires public entities to measure liabilities incurred to employees in share-based payment transactions at fair value. This Statement is effective for public entities as of the beginning of the first interim or annual reporting period that begins after December 15, 2005. Management is currently evaluating the impact that the adoption of this standard will have on the consolidated financial statements.

Reclassification

Certain prior year amounts have been reclassified to conform to the current year presentation.

NOTE 2 – DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITY

Management of Risks Related to Derivatives

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

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

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

As of March 31, 2005, these derivative contracts were reflected on the Company’s consolidated balance sheet as derivative assets and liabilities at an approximate fair value as follows:

During the first nine months of fiscal year 2005, the Company entered into two new contracts that require mark-to-market accounting under SFAS No. 133 (see Note 4).

As discussed in Note 11, in the quarter ended March 31, 2005 the Company designated certain gas contracts as “normal purchase and normal sales.” The fair value of the contracts on the date of the designation has been recorded as a deferred gain and is being amortized over the life of the contracts.

Natural Gas and Propane Operations

In the case of the Company’s regulated divisions, gains or losses resulting from derivative contracts are subject to deferral under regulatory procedures of the public service regulatory commissions of Montana, Wyoming and Arizona. Therefore, related derivative assets and liabilities are offset with corresponding regulatory liability and asset amounts included in “Recoverable Cost of Gas Purchases,” pursuant to SFAS No. 71, Accounting for the Effects of Certain Types of Regulation. As of March 31, 2005, the Company’s regulated operations have no contracts meeting the mark-to-market accounting requirements.

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NOTE 3 – INCOME TAXES

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

NOTE 4 – LINES OF CREDIT AND LONG-TERM DEBT

The Company’s operating capital needs, as well as dividend payments and capital expenditures, are generally funded through cash flow from operating activities and short-term borrowing. Historically, to the extent cash flow has not been sufficient to fund capital expenditures, the Company has borrowed short-term funds. When the short-term debt balance significantly exceeds working capital requirements, the Company has issued long-term debt or equity securities to pay down short-term debt. The Company has 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, the Company’s short-term borrowing needs for purchases of gas inventory and capital expenditures are greatest during the summer and fall months and the Company’s short-term borrowing needs for financing customer accounts receivable are greatest during the winter months.

The Company substantially restructured its credit facilities during fiscal year 2004. On September 30, 2003, the Company established a $23.0 million revolving credit facility with LaSalle Bank National Association (“LaSalle”), replacing a previous short-term line of credit. The Montana Public Service Commission (“MPSC”) order granting approval of the LaSalle credit facility restricts the use of the proceeds to utility purposes, and requires the Company to provide monthly reports to the MPSC with respect to the financial condition of the Company. The Company continues to be subject to these MPSC requirements.

On March 31, 2004, the Company entered into a restated credit agreement with LaSalle. Pursuant to the restated credit agreement, the previous $23.0 million revolving credit facility was replaced with a $15.0 million revolving credit facility, a $6.0 million term loan maturing on March 31, 2009, and a $2.0 million term loan maturing on September 30, 2004 (collectively referred to as the “LaSalle Facility”).

As of August 30, 2004, the Company and LaSalle amended certain covenants under the LaSalle Facility as follows: (1) increased the total debt to capital ratio from .65 to .70, (2) allowed the

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exclusion of extraordinary expenses incurred by the Company for legal fees and costs of the PPL Montana, LLC (“PPLM”) litigation, expenses and costs associated with the credit facilities, proxy contest costs, and the costs of adoption of the shareholder rights plan, in determining the interest coverage ratio, and (3) waived compliance with the ratios referred to in (1) and (2) above as of June 30, 2004 in addition to a shareholder’s acquisition of more than 15% of the outstanding common stock of the Company.

As of November 30, 2004, the Company executed an agreement with LaSalle providing for (i) an extension of the revolving facility until November 28, 2005; (ii) an extension of the date to consummate infusions of new equity of at least $2.0 million and to repay the $2.0 million term loan to October 1, 2005; (iii) a conditional waiver of the deadline to deliver audited financial statements for fiscal year 2004 and the deadline to deliver financial statements for the fiscal quarter ended September 30, 2004; (iv) a waiver of the technical default that otherwise would have been caused by the restatement of financial results of prior periods; (v) modification of interest rates applicable to the $2.0 million term loan; (vi) a limitation of $1.0 million on total loans and additional capital investment from the Company to EWR; and (vii) waivers of certain financial covenant defaults as of September 30, 2004.

Borrowings under the LaSalle Facility are secured by liens on substantially all of the assets of the Company and its subsidiaries. The Company’s obligations under certain other notes and industrial development revenue obligations are secured on an equal and ratable basis with LaSalle in the collateral granted to secure the borrowings under the LaSalle Facility with the exception of the first $1.0 million of debt under the LaSalle Facility.

Under the LaSalle Facility, the Company may elect to pay interest on portions of the amounts outstanding under the $15.0 million revolving line of credit at the London Interbank Offered Rate (LIBOR), plus 250 basis points, for interest periods selected by the Company. For all other balances outstanding under the $15.0 million revolving line of credit, the Company pays interest at the rate publicly announced from time to time by LaSalle as its “prime rate” (the “Prime Rate”). For the $6.0 million term loan under the LaSalle Facility, the Company may elect to pay interest at either the applicable LIBOR rate, plus 350 basis points (“bps”) or at the Prime Rate, plus 200 bps. For the $2.0 million term loan under the LaSalle Facility, the Company pays interest at the Prime Rate, plus 200 bps, through March 31, 2005; the Prime Rate, plus 300 bps, from April 1, 2005 through June 30, 2005; and the Prime Rate, plus 400 bps, from and after July 1, 2005. The Company also pays a commitment fee of 35 bps for the daily unutilized portion of the $15.0 million revolving credit facility.

During the quarter ended September 30, 2004, the Company entered into an interest rate swap agreement related to the LaSalle Facility. The interest rate swap agreement converts a declining notional amount of variable rate debt to a fixed rate of 7.40%. The amortizing notional principal amount begins at $2,933,333 on August 9, 2004 and amortizes to $2,016,666 as of March 31, 2009. The effect of the interest rate swap, therefore, is to fix the rate of interest at 7.40% for that portion of the $6.0 million term loan under the LaSalle Facility.

The LaSalle Facility requires the Company to maintain compliance with a number of financial covenants, including meeting limitations on annual capital expenditures and maintaining a total

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debt to total capital ratio and an interest coverage ratio, as defined. The LaSalle Facility also restricts the Company’s ability to pay dividends during any period to a certain percentage of cumulative earnings of the Company over that period, and restricts open positions and Value at Risk (VaR) in the Company’s wholesale operations. At March 31, 2005, the Company was in compliance with the financial covenants under the LaSalle Facility.

At March 31, 2005, the Company had approximately $1.0 million of cash on hand. In addition, at March 31, 2005, the Company had borrowed approximately $3.5 million under the LaSalle Facility revolving line of credit. The Company’s short-term borrowings under its lines of credit during the three months ended March 31, 2005 had a daily weighted average interest rate of 6.22% per annum. The Company’s net availability at March 31, 2005, was approximately $11.5 million under the LaSalle Facility revolving line of credit.

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

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

The total amount outstanding under all of the Company’s long-term debt obligations was approximately $22.3 million and $23.2 million, at March 31, 2005 and March 31, 2004, respectively. The portion of such obligations due within one year was approximately $2,978,000 and $8,538,000 at March 31, 2005, and March 31, 2004, respectively.

During November 2004, the Company sold gas held in inventory for $3,500,000 and entered into a gas purchase agreement to repurchase the same quantity of gas during January 2005 with the same counterparty for $3,580,000. The Company accounted for the agreement as a financing transaction. Accordingly, as of December 31, 2004, the proceeds from the sale were recorded as a short term borrowing, the related gas inventory was included in the Company’s gas inventory, and the Company recorded the difference between sale and repurchase price as interest expense in the accompanying unaudited condensed consolidated financial statements.

The Company also recognized the fair value of the gas purchase agreement as a derivative liability as of December 31, 2004. The fair value of the gas purchase agreement as of December 31, 2004 was $743,500 and was reflected as a reduction of revenue.

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During January 2005, the Company repurchased the gas for $3,580,000 in accordance with the terms of the gas purchase agreement. In accordance with mark-to-market accounting, the Company reversed the derivative liability upon the fulfillment of its obligation under the gas purchase agreement and reflects the related revenue of $743,500 in the unaudited condensed consolidated financial statements for the three months ending March 31, 2005. Therefore, the net effect of these two transactions for fiscal year 2005 will be an increase to interest expense of $80,000.

NOTE 5 – NOTE RECEIVABLE

On August 21, 2003, EWP sold the majority of its wholesale propane assets in Montana and Wyoming consisting of approximately $782,000 in storage and other related assets and approximately $352,000 in inventory and accounts receivable. The Company received cash of $750,000 and a promissory note for approximately $620,000 to be paid over a four year period, which is secured by the wholesale propane assets sold. The balance due on the promissory note as of March 31, 2005 was approximately $409,000, of which $254,000 is included in Long-Term Notes Receivable and the balance is included in Current Assets.

NOTE 6 – DEFERRED CHARGES

Deferred Charges consist of the following:

NOTE 7 – CONTINGENCIES

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 a storage location for certain equipment and materials. The coal gasification process utilized in the plant resulted in the production of certain by-products, which have been classified by the federal government and the State of Montana as hazardous to the environment.

The Company has completed its remediation of soil contaminants at the plant site and in April of 2002 received a closure letter from Montana Department of Environmental Quality (“MDEQ”) approving the completion of such remediation program.

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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 those standards. Although the MDEQ has not established guidance respecting the attainment of a technical waiver, the U.S. Environmental Protection Agency (“EPA”) has developed such guidance. The EPA guidance lists factors which render mediations technically impracticable. The Company has filed a request for a waiver from complying with certain standards with the MDEQ.

At March 31, 2005, the Company had incurred cumulative costs of approximately $1,963,000 in connection with its evaluation and remediation of the site. On May 30, 1995, the Company received an order from the MPSC allowing for recovery of the costs associated with the evaluation and remediation of the site through a surcharge on customer bills. As of March 31, 2005, the Company had recovered approximately $1,534,000 through such surcharges.

On April 15, 2003, the MPSC issued an Order to Show Cause Regarding the Environmental Surcharge. The MPSC determined that the initial order allowing the collection of the surcharge was intended by the MPSC to cover only a two year collection period, after which it would contemplate additional filings by the Company, if necessary. The Company responded to the Show Cause Order and the MPSC subsequently ordered the termination of the Environmental Surcharge on August 20, 2003. The Company filed a request with the commission to continue the collection of the surcharge until all expenses have been recovered. This request was approved by the MPSC and the surcharge was reinstated in September 2004. The Company is required, under the Commission’s most recent order, to file with the MPSC every two years for approval to continue the recovery of the surcharge.

Legal Proceedings

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

In addition to other litigation referred to above, the Company or its subsidiaries are involved in the following described litigation.

On August 8, 2003, the Company reached agreement with the Montana Department of Revenue (“DOR”) to settle a claim that the Company had under-reported its personal property for the years 1997 — 2002 and that additional property taxes and penalties should be assessed. The settlement amount is being paid in ten annual installments of $243,000 each, and began November 30, 2003.

The Company initially determined that it was entitled to recover the amounts paid in connection with the DOR settlement through future rate adjustments as a result of legislation permitting “automatic adjustments” to rates to recover such property tax increases. The MPSC, however, interpreted the new legislation as allowing recovery of only a portion of the higher property

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taxes. Rates recovering the portion of the higher taxes permitted under the MPSC’s interpretation of the legislation went into effect on January 1, 2004. The Company has since obtained rate relief which includes full recovery of the property tax associated with the DOR settlement.

In the early fall of 2003, a group of four former employees brought an action against the Company for damages, one of which was based on wrongful discharge, and all of which include claims of breach of contract. With respect to the breach of contract claim, the plaintiffs contend that they should have been paid more under an incentive plan in the fall of 2002 related to the Company’s financial performance in 2001.

The breach of contract claim for incentives arises from a contention that the Board of Directors’ decision to withhold the payment of one half of the incentive related to fiscal year 2001 was improper. The Board’s determination to withhold a portion of the incentive was related to the concern that the earnings reported by the Company may not be retained by the Company due to the costs of litigation and settlement or the entry of a judgment against the Company. The Board of Directors told plan participants that once the costs of litigation, settlement and/or judgment were paid that the incentive would be recalculated and if any further amounts were due participants after recalculation, they would be paid at that time. The plaintiffs contend that this was improper.

The Company is indemnified against the wrongful discharge claim brought by one of the plaintiffs under our employment practices insurance policy. The Company’s insurer has taken the position that the breach of contract claim is not indemnified. To date, the Company’s insurer has paid for the defense of the claim (exclusive of the deductible). The Company believes that the Board of Directors acted lawfully and that the Company has no liability under either of the grounds asserted by the plaintiffs. Nevertheless, the Company can give no assurance that the Company will prevail in this litigation.

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NOTE 8 – SEGMENTS OF OPERATIONS

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NOTE 9 – ACCRUED AND OTHER CURRENT LIABILITIES

     Accrued and other current liabilities consist of the following:

NOTE 10 – OTHER LONG TERM LIABILITIES

Other long-term liabilities consist of the following:

NOTE 11 – GAS CONTRACT RECLASSIFICATION

On January 3, 2005, EWR elected to reclassify certain sale contracts which had previously been classified as mark-to-market derivative contracts under SFAS No. 133. The contracts were reclassified as “normal purchase and sale” contracts. The deferred gain on these contracts as of January 3, 2005 was $1,238,765. This amount will be amortized into revenue over the remaining life of the existing sales contracts, which is approximately four years. The unamortized deferred gain as of March 31, 2005 is $1,081,372. The gain recognized through March 31, 2005 was

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$157,393. The Deferred Gain is reflected in the balance sheet as $112,509 of current other liabilities and $968,863 of other long term liabilities.

ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion of our financial condition and results of operations should be read in conjunction with the condensed consolidated financial statements and Notes thereto and other financial information included elsewhere in this Quarterly Report and our Annual Report on Form 10-K for the year ended June 30, 2004. The following gives effect to the restatement of the unaudited condensed consolidated financial statements as of March 31, 2004 and for the three- and nine-month periods ended March 31, 2004 as described in Note 1 to the unaudited condensed consolidated financial statements. Results of operations for interim periods are not necessarily indicative of results to be attained for any future period.

Forward Looking Statements

The following Management’s Discussion and Analysis and other portions of this Quarterly Report on Form 10-Q contain various “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended, which represent the Company’s expectations or beliefs concerning future events. Forward-looking statements such as “anticipates,” “believes,” “expects,” “planned,” “scheduled” or similar expressions and statements regarding the required restructuring of our debt, our operating capital requirements, negotiations with our lender, recovery of property tax payments, the Company’s environmental remediation plans, litigation, and similar statements that are not historical are forward-looking statements that involve risks and uncertainties. Although the Company believes these forward-looking statements are based on reasonable assumptions, statements made regarding future results are subject to a number of assumptions, uncertainties and risks that could cause future results to be materially different from the results stated or implied in this document.

Such forward-looking statements, as well as other oral and written forward-looking statements made by or on behalf of the Company from time to time, including statements contained in the Company’s filings with the Securities and Exchange Commission and its reports to shareholders, involve known and unknown risks and other factors which may cause the Company’s actual results in future periods to differ materially from those expressed in any forward-looking statements. Factors and risks that could affect the Company’s results and achievements and cause them to differ materially from those contained in the forward-looking statements include those identified in the section titled “Risk Factors,” as well as other factors that the Company is unable to identify or quantify, but that may exist in the future. Forward-looking statements speak only as of the date the statement was made. The Company does not undertake to update any forward looking statements that may be made from time to time by or on behalf of the Company except as required by law.

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COMPANY OVERVIEW

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

RESULTS OF OPERATIONS

Three-Month Period Ended March 31, 2005 Compared to Three-Month Period Ended March 31, 2004

Net Income

Our net income for the third quarter of fiscal year 2005 was $2,186,000 compared to net income of $586,000 in the third quarter of fiscal year 2004, an increase of $1,600,000. This increase was primarily due to increased revenues and higher gross margins without a commensurate increase in operating expenses. Each of these figures is discussed in greater detail below. EWR had a net income increase of $1,499,000, which included a $1,229,000 favorable change in value of

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derivatives posted in the third quarter. The Natural Gas Operations had a net income increase of $116,000, and the Pipeline Operations had a net income increase of $27,000, while the Propane Operations showed a decrease in net income of $42,000.

Revenues

Our revenues for the third quarter of fiscal year 2005 were $27,838,000 compared to $24,447,000 in the third quarter of fiscal year 2004, an increase of $3,391,000. This was due primarily to a significant increase in revenues attributable to the Natural Gas Operations. The increase in revenues of the Natural Gas Operations was $3,555,000 due primarily to a $3,205,000 rise in gas costs and $350,000 in rate relief from the 2004 general rate filing. EWR gas revenues decreased by $385,000 due to a combination of factors including a favorable change in value of derivatives of $1,229,000, and $157,000 in amortization of the deferred gain established in January 2005 when EWR reclassified two derivative contracts as “normal sales and purchases,” higher sales prices and decreased volumes. Propane Operations also experienced an increase in revenues of $198,000 due to higher sales prices, offset by slightly lower volumes.

Gross Margin

Gross margin, which is defined as revenue less gas purchases and costs of gas and electricity (wholesale), increased $2,764,000 from $4,789,000 in the third quarter of fiscal year 2004 to $7,553,000 in the third quarter of fiscal year 2005. EWR’s margin increased $2,465,000 due to a favorable change in value of derivatives of $1,386,000, and increases in gas, electricity, and production margin. Natural Gas margins increased $350,000 primarily due to rate relief related to the 2004 general rate filing in Great Falls. The Pipeline Operation experienced a gross margin increase of $23,000 due to the increased volumes on the Glacier line. The Propane Operations’ margins decreased $74,000 due primarily to increases in propane prices.

Expenses Other Than Gas Purchased

Expenses other than gas purchased increased by $243,000, from $3,228,000 in the third quarter of fiscal year 2004 to $3,470,000 in the third quarter of fiscal year 2005. The primary reasons for this increase were (1) increases of $178,000 due to higher labor and professional service fees related primarily to the restatement of the June 30, 2004 financial statements and the implementation of Sarbanes Oxley, offset by decreases in general and administrative expenses of $4,000 and (2) increases in depreciation expense of $81,000, partially offset by decreases in taxes other than income of $13,000, due to recognition of property tax expense in the Propane segment in fiscal year 2004, offset partially by higher property tax expense in fiscal year 2005. The increases in property taxes are being recovered through rates.

Other Income

Other income for the third quarter of fiscal year 2005 was $77,000 compared to $51,000 for the third quarter of fiscal year 2004, an increase of $26,000. EWR settled a dispute resulting in $6,000 of other income. Other Propane income decreased $4,000 primarily due to less interest

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income generated from the sale of propane assets that occurred on August 21, 2003. Other Natural Gas income had an increase of $24,000.

Interest Expense

Interest expense for the third quarter of fiscal year 2005 was $641,000 compared to $718,000 for the third quarter of fiscal year 2004, a decrease of $77,000 due to a combination of factors including higher interest rates, lower borrowings, (the line of credit at March 31, 2004 was $9,229,000 compared to $3,500,000 at March 31, 2005) and less amortization of short term debt costs. Amortization of short-term debts costs recognized in the third quarter of fiscal year 2004 were $174,000. There was no short-term debt costs amortization in the third quarter of fiscal year 2005; however, the incremental increase in amortization for long-term debt costs for fiscal year 2005 was $42,000.

Income Tax Expense

Income tax expense for the third quarter of fiscal year 2005 was $1,332,000 compared to $307,000 for the third quarter of fiscal year 2004, an increase of $1,025,000. This increase was due to higher pretax income in the third quarter of fiscal year 2005.

Nine-Month Period Ended March 31, 2005 Compared to Nine-Month Period Ended March 31, 2004

Net Income

Our net income for the first nine months of fiscal year 2005 was $1,631,000 compared to net income of $291,000 in the first nine months of fiscal year 2004, an increase of $1,340,000. This increase was primarily due to increased revenues and higher gross margins, without a commensurate increase in operating expenses. Each of these figures is discussed in greater detail below. EWR had a net income increase of $898,000. The Natural Gas Operations had a net income increase of $373,000, and the Propane Operations had a net income increase of $124,000, while the Pipeline segment showed a decrease in net income of $55,000.

Revenues

Our revenues for the first nine months of fiscal year 2005 were $62,594,000 compared to $59,560,000 in the first nine months of fiscal year 2004, an increase of $3,034,000. The increase in Natural Gas Operations’ revenues of $5,662,000 was primarily due to a $4,992,000 rise in gas costs and $670,000 in rate relief from the 2004 general rate filing. The Propane Operations experienced an increase of $750,000 due to higher sales volumes and prices. EWR revenues decreased by $3,382,000 due to a decrease in volumes sold, offset by favorable changes in prices, a favorable change in the value of derivatives, amortization of the deferred gain, and increases in electric and production revenue.

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Gross Margin

Gross margin, which is defined as revenue less gas purchases and costs of gas and electricity (wholesale), increased $2,441,000, from $12,561,000 in the first nine months of fiscal year 2004 to $15,002,000 in the first nine months of fiscal year 2005. EWR’s margin increased by $1,585,000 due to higher prices, a $1,255,000 increase due to a favorable change in the value of derivatives, increases in production margin and decreases in electric margin. Natural Gas margins increased $670,000 primarily due to rate relief related to the 2004 general rate filing in Great Falls offset by warmer than normal weather in fiscal year 2005. The Propane Operations margin increased $182,000 due primarily to increases in volumes and prices in Arizona offset by the loss of margins due to the sale of the wholesale propane assets owned by RMF in August 2003. EWD experienced a gross margin increase of $3,000 due to an increase in volumes shipped on the Glacier line.

Expenses Other Than Gas Purchased

Expenses other than gas purchased decreased by $49,000, from $10,615,000 in the first nine months of fiscal year 2004 to $10,566,000 in the first nine months of fiscal year 2005. The primary reasons for this decrease were decreases of $558,000 for legal and professional fees incurred during the first nine months of fiscal year 2005, which includes fees related to the accounting restatement, compared to fees related to the proxy contest, bank financing and litigation costs related to the litigation between EWR and PPL Montana, LLC incurred in the first nine months of fiscal year 2004, offset by a net increase in depreciation and maintenance expense of $101,000, increases in taxes other than income of $325,000, primarily due to higher property tax expense (which are recovered in rates), and increases in general and administrative expenses of $83,000.

Other Income

Other Income for the first nine months of fiscal year 2005 was $284,000 compared to $309,000 for the first nine months of fiscal year 2004, a decrease of $25,000. Pipeline Operations had a decrease of $121,000 due to the sale of certain non-operating real estate assets located in Montana during the first nine months of fiscal year 2004. EWR had an increase of $64,000 from a contract settlement. Other income in the Propane Operations increased $22,000 primarily due to interest income generated from the sale of propane assets that occurred on August 21, 2003. Natural Gas Operations had an increase in other income of $11,000.

Interest Expense

Interest expense for the first nine months of fiscal year 2005 was $2,115,000 compared to $1,812,000 for the first nine months of fiscal year 2004, an increase of $303,000, due to higher overall borrowings and increased interest rates in fiscal year 2005.

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Income Tax Expense

Income tax expense for the first nine months of fiscal year 2004 was $152,000 compared to income tax expense of $974,000 for the first nine months of fiscal year 2005, an increase of $822,000. This increase was due to a higher pretax income in the first nine months of fiscal year 2005, compared to the first nine months of fiscal year 2004.

OPERATING RESULTS OF THE COMPANY’S NATURAL GAS OPERATIONS

Three-Month Period Ended March 31, 2005 Compared to Three-Month Period Ended March 31, 2004

Natural Gas Revenues and Gross Margin

Operating revenues for the third quarter of fiscal year 2005 were approximately $17,329,000 compared to approximately $13,774,000 for the third quarter of fiscal year 2004, an increase of approximately $3,555,000. The increase in revenues is primarily due to a $3,205,000 rise in gas costs and $350,000 in rate relief from general rate and gas tracker filings.

Gas costs increased to $13,068,000 in the third quarter of fiscal year 2005 from $9,863,000 in the third quarter of fiscal year 2004, an increase of approximately $3,205,000 or 32%, due to higher commodity cost compared to the same quarter of the previous year.

Gross margin, which is defined as operating revenues less gas purchased, was approximately $4,261,000 for the third quarter of fiscal year 2005, compared to a gross margin of approximately $3,911,000 for the third quarter of fiscal year 2004. The increase of $350,000 in gross margin is primarily due to rate relief from the 2004 general rate filing in the Great Falls area.

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Natural Gas Operating Expenses

Operating expenses increased $207,000, from $2,280,000 in the third quarter of fiscal year 2004 to $2,487,000 in the third quarter of fiscal year 2005. The increase in operating expenses is primarily a result of approximately $127,000 higher labor and professional service fees related to the restatement of the June 30, 2004 financial statements and the implementation of Sarbanes-Oxley requirements. Also a factor is increased taxes other than income of approximately $43,000 primarily related to property taxes in Great Falls, which is recovered through rates. The remaining $37,000 is primarily attributable to higher uncollectible accounts in the third quarter of fiscal year 2005.

Nine-Month Period Ended March 31, 2005 Compared to Nine-Month Period Ended March 31, 2004

Natural Gas Revenues and Gross Margin

Natural gas operating revenues in the first nine months of fiscal year 2005 were approximately $36,765,000 compared to approximately $31,103,000 for the first nine months of fiscal year 2004, an increase of approximately 18%. The increase is primarily due to a $4,992,000 rise in gas costs and $670,000 in rate relief from general rate and gas tracker filings.

Gas costs increased from $22,183,000 for the first nine months of fiscal year 2004 to $27,175,000 for the first nine months of fiscal year 2005, an increase of $4,992,000. This increase is due to higher prices of natural gas compared to the first nine months of fiscal year 2004.

Gross margin, which is defined as operating revenues less gas purchased, was approximately $9,590,000 for the first nine months of fiscal year 2005, compared to a gross margin of approximately $8,920,000 for the first nine months of fiscal year 2004. The increase in margin is primarily related to rate relief generated from the 2004 general rate case in Great Falls offset by warmer than normal weather in fiscal year 2005.

Natural Gas Operating Expenses

Operating expenses from Natural Gas Operations decreased approximately $178,000, from $7,411,000 for first nine months of fiscal year 2004 to $7,233,000 for the first nine months of fiscal year 2005. The decrease in operating expenses is related primarily to decreases of $376,000 for legal and financing activities associated with costs for a proxy contest, financing activities, and PPLM lawsuit incurred in the prior year, $179,000 in general administrative and maintenance costs primarily due to salary reductions of $104,000, a reduction in insurance expense of $57,000, as well as other cost saving measures, and a $9,000 decrease in depreciation. Offsetting these decreases is an increase in taxes other than income of $386,000 primarily related to property tax increases in Great Falls, which is being recovered through rates.

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Natural Gas Other Income

Other income increased from $65,000 for the first nine months of fiscal year 2004 to $76,000 for the first nine months of fiscal year 2005, a change of $11,000.

OPERATING RESULTS OF THE COMPANY’S PROPANE OPERATIONS

Three-Month Period Ended March 31, 2005 Compared to Three-Month Period Ended March 31, 2004

Propane Operating Revenues and Gross Margin

Revenues for the third quarter of fiscal year 2005 were $3,491,000 compared to $3,293,000 for the third quarter of fiscal year 2004, an increase of $198,000. This increase was attributable to higher prices in the propane market, offset by a 4.7% decrease in volumes due in part to an approximate 2% decrease in degree days, or slightly warmer weather in the Arizona market. RMF sold its wholesale propane assets during the first quarter of fiscal year 2004 and discontinued sales in the northwestern United States. RMF maintained one customer in Arizona after the sale, but had no sales in fiscal year 2004 due to a shortage of inventory in Arizona. In the third quarter of fiscal year 2005 however, RMF had sales of $35,000 to this customer in Arizona. Cost of sales for the third quarter of fiscal year 2005 were $1,923,000 compared to $1,651,000 in the third quarter of fiscal year 2004. This increase of $272,000 was due to higher prices in the propane market. These factors combined to create a gross margin decrease in the Propane Operations of $74,000, from $1,643,000 in the third quarter of fiscal year 2004 to $1,569,000 in the third quarter of fiscal year 2005.

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Propane Operating Expenses

Propane operating expenses for the third quarter of fiscal year 2005 were $758,000 compared to $761,000 for the third quarter of fiscal year 2004. This savings of $3,000 was attributable to a $1,000 increase in general and administrative expenses, a $3,000 decrease in maintenance expense, a $3,000 increase in depreciation expense, a $60,000 decrease in taxes other than income taxes due to the expensing in the propane segment in the prior year of the property tax settlement with the Department of Revenue, and a $56,000 increase in overhead expense due to higher labor and professional service fees related primarily to the restatement of the June 30, 2004 financial statements and the implementation of Sarbanes-Oxley.

Propane Other Income

Other income decreased $4,000 from $46,000 in the third quarter fiscal year 2004 to $42,000 in the third quarter fiscal year 2005, primarily due to reduced interest income generated on the note receivable from the sale of propane assets that occurred on August 21, 2003.

Nine-Month Period Ended March 31, 2005 Compared to Nine-Month Period Ended March 31, 2004

Propane Revenues and Gross Margin

Revenues for the first nine months of fiscal year 2005 were $7,367,000 compared to $6,617,000 for the first nine months of fiscal year 2004, an increase of $750,000 or 11%. The Arizona operations experienced an increase in volumes of 12% and cooler weather, shown by a 7% increase in degree days. RMF volumes decreased 5% due to the sale of wholesale propane assets on August 21, 2003, which resulted in the loss of customers in the northwestern United States. Coupled with the volume fluctuations were higher propane prices resulting in higher revenues per volume sold. Cost of sales for the first nine months of fiscal year 2005 were $3,993,000 compared to $3,425,000 in the first nine months of fiscal year 2004. This increase of $568,000 is due to increased prices and volumes. These factors combined to create a gross margin increase in the Propane Operations of $182,000, from $3,192,000 in the first nine months of fiscal year 2004 to $3,374,000 in the first nine months of fiscal year 2005.

Propane Operating Expenses

Propane operating expenses for the first nine months of fiscal year 2005 were $2,241,000 compared to $2,234,000 for the first nine months of fiscal year 2004. The sale of RMF’s operating assets in August 2003 resulted in an offset to expenses of $185,000 in 2004 not repeated in fiscal year 2005. This increase was offset by a $95,000 decrease from professional services in fiscal year 2004 that were related to the proxy contest, financing costs, and PPLM litigation, a $9,000 decrease in depreciation and maintenance, and a $74,000 decrease in taxes other than income taxes, due to the expensing in the propane segment of part of the property tax settlement with the Department of Revenue.

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Propane Other Income

Other income increased $21,000 from $124,000 in the first nine months of fiscal year 2004 to $145,000 in the first nine months of fiscal year 2005, due primarily to interest income on the note receivable generated from the sale of propane assets that occurred on August 21, 2003.

OPERATING RESULTS OF THE COMPANY’S EWR MARKETING OPERATIONS

Three-Month Period Ended March 31, 2005 Compared to Three-Month Period Ended March 31, 2004

EWR Gas Revenues and Gross Margin

Revenues decreased by $384,000 from $7,286,000 in the third quarter of fiscal year 2004 to $6,902,000 in the third quarter of fiscal year 2005. Gas revenues decreased by $1,815,000 due to a 32% decrease in volumes sold offset by a $.58 increase in sales prices. The decreases were offset by $1,228,607 due to a favorable change in the value of derivatives, $157,000 in amortization of the deferred gain established in January 2005 when EWR reclassified two derivative contracts as “normal sales and purchases”, an increase of $6,000 in electric revenue and an increase of $39,000 in production gathering revenue.

Purchases decreased by $2,849,000, from $8,144,000 in the third quarter of fiscal year 2004 to $5,295,000 in the third quarter of fiscal year 2005. Gas cost decreased by $2,823,000 due primarily to a 35% decrease in volumes purchased, electricity cost decreased by $19,000 and production cost decreased by $7,000. The volume decrease was due to two factors, having storage gas and less wholesale trading.

Gross margin increased by $2,465,000 from ($858,000) in the third quarter of fiscal year 2004 to $1,607,000. The increase of $1,386,000 is a result of the change in derivative values, a $1,007,000 increase in gas margin due to higher sales prices and lower average gas cost due to having storage gas for the winter block, a $46,000 increase in production margin due to lower

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production costs primarily in repairs, and a $26,000 increase in electricity margin due to favorable prices.

EWR Operating Expenses

Operating expenses increased by $49,000, from $130,000 in the third quarter of fiscal year 2004 to $179,000 in the third quarter of fiscal year 2005. This increase is due to an increase in depreciation and depletion of $80,000, a $19,000 increase in bad debt expenses, and a $13,000 increase in salary and employee benefits. The increase is offset by a decrease of $55,000 in professional services, $3,000 in overhead, and $5,000 in various general and administrative accounts.

EWR Other Income

Other income increased $6,000 due to the settlement of a contract dispute.

Nine-Month Period Ended March 31, 2005 Compared to Nine-Month Period Ended March 31, 2004

EWR Gas Revenues and Gross Margin

Revenues decreased by $3,382,000 from $21,542,000 for the first nine months of fiscal year 2004 to $18,160,000 for the first nine months of fiscal year 2005. Gas revenues decreased by $4,578,000 primarily due to a 28% decrease in volumes sold offset by a $.50 increase in sales prices, and a $73,000 decrease in electric revenue. The decease is offset by an increase of $1,098,000 as a result of the change in the value of the derivatives, $157,000 in amortization of the deferred gain established in January 2005 when EWR reclassified two derivative contracts as “normal sales and purchases”, and a $14,000 increase in production revenue.

Purchases decreased by $4,965,000 from $21,391,000 for the first nine months of fiscal year 2004 to $16,426,000 for the first nine months of fiscal year 2005. The decreases were $4,947,000 in gas cost due to a 31% decrease in volumes purchased offset by a $.46 increase in gas cost, and $24,000 in electricity costs. The decreases were offset by an increase of $6,000 in production expenses.

Margin increased by $1,585,000 from $151,000 for the first nine months of fiscal year 2004 to $1,736,000 for the first nine months of fiscal year 2005. This increase is due to a favorable change of $1,255,000 in the value of derivatives, a $371,000 increase in gas margin due to higher sales prices and an increase in production margin of $8,000. The increase is offset by a $49,000 decrease in electric margin due primarily to the termination of an agreement under which the Company provided billing services.

EWR Operating Expense

Operating expenses increased by $154,000, from $806,000 in the first nine months of fiscal year 2004 to $960,000 in the first nine months of fiscal year 2005. This increase is due to an increase

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in professional services of $260,000 resulting from the review of the gas purchase and gas sale contracts and related accounting restatement, and a $43,000 increase in depletion and depreciation. The increases were offset by decreases of $69,000 in overhead, $45,000 in salary and employee benefits, $14,000 in cost of letters of credit, $8,000 in telephone expenses, $8,000 in insurance, and $5,000 in other general and administrative expenses.

EWR Other Income

Other income increased by $64,000 primarily due to the settlement of a contract dispute.

OPERATING RESULTS OF THE COMPANY’S PIPELINE OPERATIONS

Three-Month Period Ended March 31, 2005 Compared to Three-Month Period Ended March 31, 2004

Pipeline Gross Margin

Gross margin from Pipeline Operations increased by $23,000 from $93,000 in the third quarter of fiscal 2004 to $116,000 in the second quarter of fiscal year 2005. This increase is due to increased volumes on the Glacier line.

Pipeline Operating Expenses

Operating expenses decreased by $11,000, from $57,000 in the third quarter of fiscal year 2004 to $46,000 in the third quarter of fiscal year 2005. This decrease was due to decreases of $8,000 in administrative services, $2,000 in maintenance expense, $2,000 in outside services, and $2,000 in other general and administrative charges. The decrease was offset by a $3,000 increase in property taxes.

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Pipeline Other Income

EWD had no other income in the second quarter of fiscal year 2004 or in fiscal year 2005.

Nine-Month Period Ended March 31, 2005 Compared to Nine-Month Period Ended March 31, 2004

Pipeline Gross Margin

Gross margin from Pipeline Operations increased by $3,000 from $299,000 for the first nine months of fiscal year 2004 to $302,000 for the first nine months of fiscal year 2005. The increase is due an increase of volumes being shipped on the Glacier line.

Pipeline Operating Expense

Operating expenses from the Pipeline Operations decreased by $33,000 from $164,000 for the first nine months of fiscal year 2004 to $131,000 for the first nine months of fiscal year 2005. This decrease was due primarily to decreases of $17,000 in corporate overhead expenses, $16,000 in administrative expenses, $14,000 in labor, $5,000 in salary, $3,000 in outside services, and $2,000 in various general and administrative expenses. The decrease was partially offset by a $17,000 increase in property taxes, $6,000 for maintenance on the Glacier line and a $1,000 increase in depreciation.

Pipeline Other Income

Other income for the first nine months of fiscal year 2004 included the sale of certain non-operating real estate assets located in Montana, which resulted in a gain of $121,000.

CASH FLOWS ANALYSIS FOR THE NINE MONTHS ENDED MARCH 31, 2005 COMPARED TO THE NINE MONTHS ENDED MARCH 31, 2004

CASH FLOWS USED IN OPERATING ACTIVITIES

Cash flows used in operations during the nine months ended March 31, 2005 were improved approximately $8.2 million compared to the nine months ended March 31, 2004. Our change in operating cash flows was driven by the following events and factors:

	-	Increase in net income for the nine months ended March 31, 2005,
	-	Settlement payment of $2.2 million to PPL in the first quarter of fiscal year 2004,
	-	Increase in cash flows resulting from fluctuations on accounts payable,
	-	Decrease in cash flows resulting from fluctuations in accounts receivable,

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	-	The timing of inventory purchases – higher inventory balances at the beginning of fiscal year 2005 compared to fiscal year 2004 allowed for more sales of inventory in the first nine months of fiscal year 2005,
	-	Increase in cash flows resulting from fluctuations in recoverable / refundable cost of gas purchases.

As of March 31, the amount of our total outstanding debt has decreased to approximately $26,280,731 from a total of $41,512,719 at December 31, 2004. This decrease is due to our paying down the outstanding balance on our line of credit by $11,129,000. Despite this, higher interest rates will continue to unfavorably impact operating cash flows. We are currently in the process of issuing additional equity, the proceeds of which will be used to retire debt.

We are attempting to improve operating cash flows by improving the efficiency of the core businesses, increasing revenues through utility rates, retiring debt and restructuring existing debt obligations.

CASH FLOWS USED IN INVESTING ACTIVITIES

Cash flows used in investing activities in the nine months ended March 31, 2005 increased approximately $1.5 million from the nine months ended March 31, 2004. These changes are primarily due to (1) increased construction expenditures of $721,000 and (2) the prior year period included approximately $840,000 in proceeds from the sale of wholesale propane assets.

CASH FLOWS FROM FINANCING ACTIVITIES

Cash flows from financing activities decreased approximately $9.5 million in the nine months ended March 31, 2005 from the nine months ended March 31, 2004 primarily due to decreased advances and increased repayments against the line of credit under the LaSalle Facility and proceeds from short-term borrowing.

LIQUIDITY AND CAPITAL RESOURCES

Our operating capital needs, as well as dividend payments and capital expenditures, are generally funded through cash flow from operating activities and short-term borrowing. Historically, to the extent cash flow has not been sufficient to fund capital expenditures, the Company has borrowed short-term funds. When the short-term debt balance significantly exceeds working capital requirements, we have issued long-term debt or equity securities to pay down short-term debt. We have greater need for short-term borrowing during periods when internally generated funds are not sufficient to cover all capital and operating requirements, including costs of gas purchased and capital expenditures. In general, our short-term borrowing needs for purchases of gas inventory and capital expenditures are greatest during the summer and fall months and our short-term borrowing needs for financing customer accounts receivable are greatest during the winter months.

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We substantially restructured our credit facilities during fiscal year 2004. On September 30, 2003, we established a $23.0 million revolving credit facility with LaSalle Bank National Association ( “LaSalle”), replacing a previous short-term line of credit. The MPSC order granting approval of the $23.0 million credit facility imposes restrictions on the use of the proceeds to utility purposes, and requires us to provide monthly reports to the MPSC with respect to our financial condition. We continue to be subject to these MPSC requirements.

On March 31, 2004, we entered into a restated credit agreement with LaSalle. Pursuant to the restated credit agreement, the previous $23.0 million revolving credit facility was replaced with a $15.0 million short-term revolving credit facility, a $6.0 million term loan maturing on March 31, 2009, and a $2.0 million term loan maturing on September 30, 2004 (collectively referred to as the “LaSalle Facility”).

As of August 30, 2004, we amended certain covenants under the LaSalle Facility as follows: (1) increased the total debt to capital ratio from .65 to .70, (2) allowed the exclusion of extraordinary expenses incurred by the Company for legal fees and costs of the PPLM litigation, expenses and costs associated with the credit facilities, proxy contest costs, and the costs of adoption of the shareholder rights plan, in determining the interest coverage ratio, and (3) waived compliance with the ratios referred to in (1) and (2) above as of June 30, 2004 in addition to a shareholder’s acquisition of more than 15% of our outstanding common stock.

During the quarter ended September 30, 2004, we entered into an interest-rate swap agreement related to the LaSalle Facility. The interest-rate swap agreement converts a declining notional amount of variable rate debt to a fixed rate of 7.40%. The amortizing notional principal amount begins at $2,933,333 on August 9, 2004 and amortizes to $2,016,666 as of March 31, 2009. The effect of the interest rate swap, therefore, is to fix the rate of interest at 7.40% for that portion of our term loan under the LaSalle Facility.

As of November 30, 2004, we executed an agreement with LaSalle providing for (i) an extension of the revolving facility until November 28, 2005; (ii) an extension of the date to consummate infusions of new equity of at least $2.0 million and to repay the $2.0 million term loan to October 1, 2005; (iii) a conditional waiver of the deadline to deliver audited financial statements for fiscal year 2004 and the deadline to deliver financial statements for the fiscal quarter ended September 30, 2004; (iv) a waiver of the technical default that otherwise would have been caused by the restatement of financial results of prior periods; (v) modification of interest rates applicable to the $2.0 million term loan; (vi) a limitation of $1.0 million on total loans and additional capital investment from the Company to EWR; and (vii) waivers of certain financial covenant defaults as of September 30, 2004.

Borrowings under the LaSalle Facility are secured by liens on substantially all of our assets and those of our subsidiaries. Our obligations under certain other notes and industrial development revenue obligations are secured on an equal and ratable basis with LaSalle in the collateral granted to secure the borrowings under the LaSalle Facility with the exception of the first $1.0 million of debt under the LaSalle Facility.

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Under the LaSalle Facility we may elect to pay interest on portions of the amounts outstanding under the $15.0 million revolving line of credit at the London Interbank Offered Rate (LIBOR), plus 250 basis points, for interest periods that we select. For all other balances outstanding under the $15.0 million revolving line of credit, we pay interest at the rate publicly announced from time to time by LaSalle Bank as its “Prime Rate.” For the $6.0 million term loan under the LaSalle Facility, we may elect to pay interest at either the applicable LIBOR rate, plus 350 basis points, or at the Prime Rate plus 200 basis points. Pursuant to the November 30, 2004 amendment to the LaSalle Facility, the interest rate on the $2.0 million term loan will be the Prime Rate, plus 200 basis points, through March 31, 2005; the Prime Rate, plus 300 basis points, from April 1, 2005 through June 30, 2005; and the Prime Rate, plus 400 basis points, from and after July 1, 2005. We also pay a commitment fee of 35 basis points for the daily unutilized portion of the $15.0 million revolving credit facility.

The LaSalle Facility requires us to maintain compliance with a number of financial covenants, including meeting limitations on annual capital expenditures, maintaining a total debt to total capital ratio and an interest coverage ratio. The LaSalle Facility also restricts our ability to pay dividends during any period to a certain percentage of our cumulative earnings over that period, and restricts open positions and Value at Risk (VaR) in our wholesale operations. At March 31, 2005, the Company was in compliance with the financial covenants under the LaSalle Facility.

In June 2003, our Board of Directors suspended the payment of dividends to allow for strengthening our balance sheet. No determination has been made with respect to resumption of cash dividend payments.

At March 31, 2005, we had approximately $1.0 million of cash on hand. In addition, at March 31, 2005, we had borrowed approximately $3.5 million under the LaSalle Facility revolving line of credit. Our short-term borrowings under our lines of credit during the first quarter of fiscal year 2005 had a daily weighted average interest rate of 6.22% per annum. Our net availability at March 31, 2005, was approximately $11.5 million under the LaSalle Facility revolving line of credit. As discussed above, our short-term borrowing needs for purchases of gas inventory and capital expenditures are greatest during the summer and fall months. Our cash availability normally increases in January as monthly heating bills are paid and gas purchases to build inventory are no longer necessary.

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

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

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

The total amount outstanding under all of our long term debt obligations was approximately $22.3 million at March 31, 2005. The portion of such obligations due within one year was approximately $3.0 million at March 31, 2005.

We are currently in the process of raising equity capital to fund the repayment of the $2.0 million term loan, which matures on October 1, 2005.

A table of our long-term debt obligations, as well as other long-term commitments and contingencies, as of March 31, 2005, are listed below according to maturity dates.

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CONTRACTS ACCOUNTED FOR AT FAIR VALUE

Management of Risks Related to Derivatives

We, along with our subsidiaries, are subject to certain risks related to changes in certain commodity prices and risks of counterparty performance. We have established policies and procedures to manage such risks. We have a Risk Management Committee, comprised of Company officers and management to oversee our risk management program as defined in our 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 we, along with our subsidiaries, have entered into hedging arrangements. Such arrangements may be used to protect profit margins on future obligations to deliver gas at a fixed price, or to protect against adverse effects of potential market price declines on future obligations to purchase gas at fixed prices.

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

Quoted market prices for our natural gas derivative contracts are generally not available. Therefore, to determine the net present value of natural gas derivative contracts, we use internally developed valuation models that incorporate independently available current and forecasted pricing information.

As of March 31, 2005, these agreements were reflected on our consolidated balance sheet as derivative assets and liabilities at an approximate fair value as follows:

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During the first nine months of fiscal year 2005, we entered in to two new contracts that require mark-to-market accounting under SFAS No. 133 (see Note 4).

Regulated Operations

In the case of our regulated divisions, gains or losses resulting from derivative contracts are subject to deferral under regulatory procedures approved by the public service regulatory commissions of the States of Montana and Wyoming. Therefore, related derivative assets and liabilities are offset with corresponding regulatory liability and asset amounts included in “Recoverable Cost of Gas Purchases,” pursuant to SFAS No. 71, Accounting for the Effects of Certain Types of Regulation.

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. Accordingly, you should only consider investing in our common stock if you can afford to lose your entire investment.

Our quarterly results of operations could fluctuate due to factors outside of our control.

Factors that could cause our results of operations to fluctuate in the future include the following:

	•	Fluctuating energy commodity prices, including prices for fuel and purchased power;
	•	The possibility that regulators may not permit us to pass through all increased costs to customers;
	•	Fluctuations in wholesale margins due to uncertainty in the wholesale propane and power markets;
	•	Changes in general economic conditions in the United States and changes in the industries in which we conduct business;
	•	Changes in federal or state laws and regulations to which we are subject, including tax, environmental and employment laws and regulations;
	•	The impact of the 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;
	•	Our ability to obtain governmental and regulatory approval of various expansion or other projects;
	•	The costs and effects of legal and administrative claims and proceedings against us or our subsidiaries;
	•	Conditions of the capital markets we utilize to access capital to finance operations;

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	•	The ability to raise capital in a cost-effective way;
	•	The ability to meet financial covenants imposed by lenders to be able to draw down on revolving lines of credit;
	•	The effect of changes in accounting policies, if any;
	•	The ability to manage our growth;
	•	The ability to control costs;
	•	The ability of each business unit to successfully implement key systems, such as service delivery systems;
	•	Our ability to develop expanded markets and product offerings and our ability to maintain existing markets;
	•	The ability of customers of the energy marketing and trading business to obtain financing for various projects;
	•	The ability of customers of the energy marketing and trading business to obtain governmental and regulatory approval of various projects;
	•	Future utilization of pipeline capacity, which can depend on energy prices, competition from alternative fuels, the general level of natural gas and propane demand, decisions by customers not to renew expiring natural gas or propane contracts, and weather conditions; and
	•	Global and domestic economic repercussions from terrorist activities and the government’s response thereto.

We are subject to complex government regulation which may have a negative impact on our business and our results of operations.

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

The regulatory structure in which we operate is in transition. Legislative and regulatory initiatives, at both the federal and state levels, are designed to promote competition. The changes in the gas industry have allowed certain customers to negotiate gas purchases directly with producers or brokers. To date, open access in the gas industry has not had a negative impact on

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earnings or cash flow of our regulated segment. Our regulated natural gas and propane vapor operations follow Statement of Financial Accounting Standards (SFAS) No. 71 “Accounting for the Effects of Certain Types of Regulation,” and the 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). If our natural gas and propane vapor operations were to discontinue the application of SFAS No. 71, the accounting impact would be an extraordinary, non-cash charge to operations that could be material to the financial position and results of operations of the Company. However, we are unaware of any circumstances or events in the foreseeable future that would cause us to discontinue the application of SFAS No. 71.

Recent events in the energy markets that are beyond our control may have negative impacts on our business.

As a result of the energy crisis in California during the summer of 2001, the recent volatility of natural gas prices in North America, the filing of bankruptcy by the Enron Corporation, and investigations by governmental authorities into energy trading activities, companies generally in the regulated and unregulated utility businesses have been under an increased amount of public and regulatory scrutiny. The capital markets and credit ratings agencies also have increased their level of scrutiny. We believe that we are complying with all applicable laws, but it is difficult or impossible to predict or control what effect these or related issues may have on our business or our access to the capital markets.

Our results of operations can be adversely affected by milder weather.

Our business is temperature-sensitive. In any given period, sales volumes reflect the impact of weather, in addition to other factors, with colder temperatures generally resulting in increased sales by the Company. We anticipate that this sensitivity to seasonal and other weather conditions will continue to be reflected in our sales volumes in future periods. As a result, unusually mild weather could diminish our results of operations and harm our financial condition.

The use of derivative contracts in the normal course of our business and changing interest rates and market conditions could result in financial losses that negatively impact our results of operations.

Our operations include managing market risks related to commodity prices. We are exposed to the impact of market fluctuations in the price and transportation costs of natural gas and propane. In order to mitigate the risk of natural gas market price volatility related to firm commitments to purchase or sell natural gas, from time to time we have entered into hedging arrangements. Such

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arrangements may be used to protect profit margins on future obligations to deliver gas at a fixed price, or to protect against adverse effects of potential market price declines on future obligations to purchase gas at fixed prices.

We are exposed to losses in the event of nonperformance or nonpayment by counterparties. We use a risk management process to assess and monitor the financial exposure of all counterparties. Despite the fact that the majority of trading counterparties are rated as investment grade by the credit rating agencies, there is still a possibility that one or more of these companies could default, resulting in a material adverse impact on our earnings for a given period.

On March 11, 2005, the Audit Committee of our Board of Directors received a letter from our auditor dated February 11, 2005, notifying the Committee of a matter involving our internal control and our operation which they consider a material weakness under standards established by the American Institute of Certified Public Accountants. The auditors indicated that they determined that we inappropriately accounted for a financing arrangement with an embedded derivative as a sale and purchase of inventory and they claimed that this occurred as a result of a weakness in the design of our internal control system. Our auditors recommended that we should strengthen our policies and procedures related to identifying and accounting for derivative instruments, contracts qualifying for the normal purchase and sales exception under Statement of Financial Accounting Standard No. 133, Accounting for Derivative Instruments and Hedging Activities, and unusual financing arrangements. The Audit Committee is currently evaluating this information and determining what action, if any, is indicated.

We are subject to numerous environmental laws and regulations which may increase our cost of operations, impact our business plans, or expose us to environmental liabilities.

We are subject to numerous environmental regulations affecting many aspects of our present and future operations, including air emissions, water quality, wastewater discharges, solid waste, and hazardous waste. These laws and regulations can result in increased capital, operating, and other 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.

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

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

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We depend upon our executive officers and key personnel.

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

Competition for talented personnel is intense, and there is no assurance that we will be able to continue to attract, train, retain or motivate other highly qualified technical and managerial personnel in the future. In addition, market conditions may require us to pay higher compensation to qualified personnel than we currently anticipate. Any inability to attract and retain qualified personnel in the future could have a material adverse effect on our business, prospects, financial condition, and results of operations.

Failure to achieve and maintain effective internal controls in accordance with Section 404 of the Sarbanes-Oxley Act could have a material adverse effect on our business and stock price.

Pursuant to Section 404 of the Sarbanes-Oxley Act of 2002, beginning with our Annual Report on Form 10-K for the fiscal year ending June 30, 2007, we will be required to furnish a report by our management on our internal control over financial reporting. The internal control report must contain (i) a statement of management’s responsibility for establishing and maintaining adequate internal control over financial reporting, (ii) a statement identifying the framework used by management to conduct the required evaluation of the effectiveness of our internal control over financial reporting, (iii) management’s assessment of the effectiveness of our internal control over financial reporting as of the end of our most recent fiscal year, including a statement as to whether or not internal control over financial reporting is effective, and (iv) a statement that the Company’s independent auditors have issued an attestation report on management’s assessment of internal control over financial reporting.

In order to achieve compliance with Section 404 of the Act within the prescribed period, beginning in our next fiscal year, we have initiated a process to document and evaluate our internal control over financial reporting, which will be both costly and challenging. In this regard, management will need to dedicate internal resources, engage outside consultants and adopt a detailed work plan to (i) assess and document the adequacy of internal control over financial reporting, (ii) take steps to improve control processes where appropriate, (iii) validate through testing that controls are functioning as documented and (iv) implement a continuous reporting and improvement process for internal control over financial reporting. We can provide no assurance as to our, or our independent auditors’, conclusions at June 30, 2007 with respect to the effectiveness of our internal control over financial reporting under Section 404 of the Act. There is a risk that neither we nor our independent auditors will be able to conclude at June 30, 2007 that our internal controls over financial reporting are effective as required by Section 404 of the Act.

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

Certain provisions in our charter, under applicable Montana law as well as our Shareholder Rights Plan, may prevent or delay a change of control of our company.

We have adopted a Shareholder Rights Plan. This Plan serves as a strong deterrent to any unsolicited or hostile takeover attempts and, effectively, requires an interested acquirer to negotiate with our Board of Directors.

Additionally, our Articles of Incorporation authorize our Board of Directors to issue preferred stock in one or more series and to fix the rights, preferences, privileges and restrictions granted to or imposed upon any unissued shares of preferred stock and to fix the number of shares constituting any series and the designations of such series, without further vote or action by the shareholders.

Montana law, our charter and our Shareholder Rights Plan, could prohibit or delay mergers or other takeover or change of control of our Company and may discourage attempts by other companies to acquire us, even if such a transaction would be beneficial to our stockholders.

Actual results could differ from estimates used to prepare our financial statements.

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

	•	Regulatory Accounting — Regulatory accounting allows for the actions of regulators, such as the MPSC, and FERC, 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 would be written off as a charge in current period earnings.
	•	Derivative Accounting — Derivative accounting requires evaluation of rules that are complex and subject to varying interpretations. Our evaluation of these rules, as they

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apply to our contracts, will determine whether we use accrual accounting or fair value (mark-to-market) accounting. Mark-to-market accounting requires that changes in fair value be recorded in earnings or, if certain hedge accounting criteria are met, in common stock equity (as a component of other comprehensive income (loss)).

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

ITEM 3. THE QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are subject to certain market risks, including commodity price risk (i.e., natural gas and propane prices) and interest rate risk. The adverse effects of potential changes in these market risks are discussed below. The sensitivity analyses presented do not consider the effects that such adverse changes may have on overall economic activity nor do they consider additional actions management may take to mitigate our exposure to such changes. Actual results may differ. See Note 1 to the consolidated financial statements set forth in our Annual Report on Form 10-K for the year ended June 30, 2004 for a description of our accounting policies and other information related to these financial instruments.

Commodity Price Risk

We seek to protect ourselves against natural gas price fluctuations by limiting the aggregate level of net open positions that are exposed to market price changes. Open positions are to be managed with policies designed to limit the exposure to market risk, with regular reporting to management of potential financial exposure. Our risk management committee has limited the types of contracts we will consider to those related to physical natural gas deliveries. Therefore, management believes that our results of operations are not significantly exposed to changes in natural gas prices.

Interest Rate Risk

Our results of operations are affected by fluctuations in interest rates (e.g. interest expense on debt). We mitigate this risk by entering into long-term debt agreements with fixed interest rates and by utilizing interest rate swaps to fix the interest rate on variable rate debt agreements. Our notes payable, however, are subject to variable interest rates. A hypothetical 100 basis point change in market rates applied to the balance of the notes payable would change interest expense by approximately $150,000 annually.

Credit Risk

Credit risk relates to the risk of loss that we would incur as a result of non-performance by counterparties of their contractual obligations under the various instruments with the Company. Credit risk may be concentrated to the extent that one or more groups of counterparties have

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similar economic, industry or other characteristics that would cause their ability to meet contractual obligations to be similarly affected by changes in market or other conditions. In addition, credit risk includes not only the risk that a counterparty may default due to circumstances relating directly to it, but also the risk that a counterparty may default due to circumstances which relate to other market participants which 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.

ITEM 4. CONTROLS AND PROCEDURES

Disclosure controls and procedures are designed with an objective of ensuring that information required to be disclosed in our periodic reports filed with the Securities and Exchange Commission, such as this Quarterly Report on Form 10-Q, is recorded, processed, summarized and reported within the time periods specified by the Securities and Exchange Commission. Disclosure controls also are designed with an objective of ensuring that such information is accumulated and communicated to our management, including our chief executive officer and chief financial officer, in order to allow timely consideration regarding required disclosures.

The evaluation of our disclosure controls by our chief executive officer and our chief financial officer included a review of the controls’ objectives and design, the operation of the controls, and the effect of the controls on the information presented in this Quarterly Report. Our management, including our chief executive officer and chief financial officer, does not expect that disclosure controls can or will prevent or detect all errors and all fraud, if any. A control system, no matter how well designed and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Also, projections of any evaluation of the disclosure controls and procedures to future periods are subject to the risk that the disclosure controls and procedures may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Based on their review and evaluation as of the end of the period covered by this Form 10-Q, and subject to the inherent limitations all as described above, our chief executive officer and chief financial officer have concluded that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) contain certain material weaknesses and are not wholly effective. Specifically, we have identified material weaknesses concerning our technical ability to properly identify, analyze and record transactions involving derivative instruments under SFAS No. 133.

A material weakness is a significant deficiency, or a combination of significant deficiencies, that results in more than a remote likelihood that a material misstatement of the annual or interim financial statements will not be prevented or detected.

During fiscal year 2004 and the first part of fiscal year 2005, we implemented changes in our internal controls over financial reporting to address the material weakness. Specifically, we implemented procedures respecting the contracting for gas under natural gas purchase and sale agreements, including establishing a separation between the deal-making function and the

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accounting and contract administration functions, and we established record systems and procedures that require reconciliation of actual performance by the contracting parties against the prices, quantities and other material terms specified in the agreements, and redundant documentation for every agreement regarding its classification pursuant to SFAS No. 133. These procedures are designed to make sure that all material obligations entered into on our behalf or on behalf of our subsidiaries receive proper review and that those agreements are enforced and performed according to their terms and conditions. These procedures are also designed to make sure that we comply with applicable accounting requirements.

We intend to provide our accounting staff with additional training on the identification and accounting for derivative instruments, contracts qualifying for the normal purchase and sales exception under SFAS No. 133, and unusual financing arrangements. In addition to these steps, we continue to evaluate how we can further strengthen our policies and procedures related to identifying and accounting for derivative instruments.

We believe that we will be able to improve our financial reporting and disclosure controls and procedures and remedy the material weakness identified above.

PART II — OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

From time to time, we are involved in litigation relating to claims arising from our operations in the normal course of business. We utilize various risk management strategies, including maintaining liability insurance against certain risks, employee education and safety programs and other processes intended to reduce liability risk.

In addition to other litigation referred to above, we or our subsidiaries are involved in the following described litigation.

On August 8, 2003, we reached agreement with the Montana Department of Revenue (“DOR”) to settle a claim that we had under-reported our personal property for the years 1997 - 2002 and that additional property taxes and penalties should be assessed. The settlement amount is being paid in ten annual installments of $243,000 each, beginning November 30, 2003. As of March 31, 2005, approximately $2,187,000 remained payable.

We initially determined that we were entitled to recover the amounts paid in connection with the DOR settlement through future rate adjustments as a result of legislation permitting “automatic adjustments” to rates to recover such property tax increases. The MPSC, however, interpreted the new legislation as allowing recovery of only a portion of the higher property tax rates. Rates recovering the portion of the higher taxes permitted under the MPSC’s interpretation of the legislation went into effect on January 1, 2004. We have since obtained rate relief which includes full recovery of the property tax associated with the DOR settlement.

In the early fall of 2003, a group of four former employees brought an action against the Company for damages, one of which was based on wrongful discharge, and all of which include

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claims of breach of contract. With respect to the breach of contract claim, the plaintiffs contend that they should have been paid more under an incentive plan in the fall of 2002 related to the Company’s financial performance in 2001.

The breach of contract claim for incentives arises from a contention that our Board of Directors’ decision to withhold the payment of one half of the incentive related to fiscal year 2001 was improper. The Board’s determination to withhold a portion of the incentive was related to the concern that we may not be able to retain our reported earnings due to the costs of litigation and settlement or the entry of a judgment against the Company. The Board of Directors told plan participants that once the costs of litigation, settlement and/or judgment were paid that the incentive would be recalculated and if any further amounts were due participants after recalculation, they would be paid at that time. The plaintiffs contend that this was improper.

We are indemnified against the wrongful discharge claim brought by one of the plaintiffs under our employment practices insurance policy. Our insurer has taken the position that the breach of contract claim is not indemnified. To date, our insurer has paid for the defense of the claim (exclusive of the deductible). We believe that our Board of Directors acted lawfully and that we have no liability under either of the grounds asserted by the plaintiffs. Nevertheless, we can give no assurance that we will prevail in this litigation.

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ITEM 3. DEFAULTS UPON SENIOR SECURITIES

For a discussion of this item see “Liquidity and Capital Resources” in Part I, Item 2 above.

ITEM 6. EXHIBITS

The following exhibits are either attached hereto or incorporated herein by reference as indicated:

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SIGNATURES

Pursuant to the requirements 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.

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EXHIBIT INDEX

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