Gas Natural 10Q 2005 Q4 Quarterly report

FORM 10-Q

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549


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

For the quarterly period ended December 31, 2005


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

For the transition period from to

Commission File number 0-14183

ENERGY WEST, INCORPORATED

(Exact name of registrant as specified in its charter)


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

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

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yesþ Noo

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Yeso Noþ

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filero Accelerated filero Non-accelerated filerþ

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yeso Noþ

The number of shares outstanding of the issuer’s common stock, $.15 par value per share, as of February 8, 2006 was 2,931,158 shares.

ENERGY WEST, INCORPORATED
INDEX TO FORM 10-Q


	Page No.
Part I — Financial Information

Item 1 — Financial Statements

Condensed Consolidated Balance Sheets (unaudited) as of December 31, 2005, December 31, 2004 and June 30, 2005		2

Condensed Consolidated Statements of Operations (unaudited) — three months ended December 31, 2005 and 2004 and six months ended December 31, 2005 and 2004		3

Condensed Consolidated Statements of Cash Flows (unaudited) — six months ended December 31, 2005 and 2004		4

Notes to Condensed Consolidated Financial Statements		5

Item 2 — Management’s Discussion and Analysis of Financial Condition and Results of Operations		14

Item 3 — Quantitative and Qualitative Disclosures about Market Risk		32

Item 4 — Controls and Procedures		33

Part II — Other Information

Item 4 — Submission of Matters to a Vote of Security Holders		34

Item 6 — Exhibits		34

Signatures
Exhibit 10.1
Exhibit 31
Exhibit 32

Part I — FINANCIAL INFORMATION

Item 1 — Financial Statements

ENERGY WEST, INCORPORATED AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)


	December 31,				June 30,
	2005		2004		2005
ASSETS
Current assets:
Cash and cash equivalents	$	1,077,084	$	4,979,766	$	93,606
Accounts and notes receivable, less $363,618 $257,143, and $294,646, respectively, allowance for bad debt		10,789,385		7,951,611		5,791,888
Unbilled gas		4,530,377		5,114,155		1,092,320
Derivative assets		336,864		124,131		119,069
Natural gas and propane inventories		8,613,129		7,896,274		3,711,033
Materials and supplies		506,755		411,662		440,959
Prepayments and other		403,112		324,837		386,306
Deferred income taxes		33,563		1,036,532		—
Income tax receivable		313,344		999,451		1,924,648
Recoverable cost of gas purchases		1,569,299		564,575		1,863,475


Total current assets		28,172,912		29,402,994		15,423,304

Property, plant and equipment, net		38,922,268		38,874,483		38,942,123
Note receivable		—		253,944		174,561
Deferred charges		4,419,970		5,062,031		4,725,924
Other assets		163,476		165,187		167,481

*TOTAL ASSETS*	$	71,678,626	$	73,758,639	$	59,433,393


LIABILITIES AND CAPITALIZATION

Current Liabilities:
Current portion of long-term debt	$	1,056,633	$	2,977,891	$	1,013,089
Line of credit		11,000,000		14,629,304		3,900,000
Accounts payable		7,513,971		3,768,601		2,651,047
Derivative liabilities		277,742		2,304,963		114,237
Deferred income tax		—		—		96,214
Accrued and other current liabilities		3,921,701		8,138,341		3,750,177


Total current liabilities		23,770,047		31,819,100		11,524,764


Other obligations:
Deferred income taxes		6,276,632		4,763,007		6,267,858
Deferred investment tax credits		302,751		323,813		313,282
Other long-term liabilities		5,255,737		4,606,799		5,463,667


Total other obligations		11,835,120		9,693,619		12,044,807

Long-term debt		18,370,493		19,400,793		18,677,197


Commitments and contingencies

Stockholders’ equity:
Common stock; $.15 par value, 5,000,000 shares authorized, 2,930,100; 2,599,438 and 2,912,564 shares outstanding at December 31, 2005, 2004, and June 30, 2005 respectively		439,522		389,923		436,892
Preferred stock; $.15 par value, 1,500,000 shares authorized, no shares outstanding		—		—		—
Capital in excess of par value		7,578,531		5,083,232		7,435,309
Retained earnings		9,684,913		7,371,972		9,314,424


Total stockholders’ equity		17,702,966		12,845,127		17,186,625


TOTAL CAPITALIZATION		36,073,459		32,245,920		35,863,822


*TOTAL LIABILITIES AND CAPITALIZATION*	$	71,678,626	$	73,758,639	$	59,433,393

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

ENERGY WEST, INCORPORATED AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)


	Three Months Ended				Six Months Ended
	December 31,				December 31,
	2005		2004		2005		2004
REVENUES:
Natural gas operations	$	20,187,548	$	14,228,550	$	26,502,915	$	19,436,226
Propane operations		2,530,948		3,022,491		3,528,930		3,875,102
Gas and electric—wholesale		6,108,052		5,763,054		8,977,884		11,657,898
Pipeline operations		102,539		101,931		210,747		186,286

Total revenues		28,929,087		23,116,026		39,220,476		35,155,512


EXPENSES:
Gas purchased		17,898,558		12,318,308		22,786,407		16,177,664
Gas and electric—wholesale		5,722,196		5,572,474		8,463,665		11,528,479
Distribution, general, and administrative		2,063,994		2,557,149		4,282,780		4,852,833
Maintenance		125,678		160,837		273,570		293,631
Depreciation and amortization		528,698		587,954		1,103,075		1,182,270
Taxes other than income		412,388		383,634		775,025		767,443


Total expenses		26,751,512		21,580,356		37,684,522		34,802,320


OPERATING INCOME		2,177,575		1,535,670		1,535,954		353,192

OTHER INCOME		208,133		141,295		319,155		207,470

INTEREST EXPENSE		596,041		721,945		1,089,455		1,474,189


INCOME (LOSS) BEFORE INCOME TAXES		1,789,667		955,020		765,654		(913,527	)

INCOME TAX EXPENSE (BENEFIT)		672,563		388,623		270,123		(358,230	)


NET INCOME (LOSS)	$	1,117,104	$	566,397	$	495,531	$	(555,297	)


INCOME (LOSS) PER COMMON SHARE:
Basic	$	0.38	$	0.22	$	0.17	$	(0.21	)
Diluted	$	0.38	$	0.22	$	0.17	$	(0.21	)

WEIGHTED AVERAGE COMMON SHARES
OUTSTANDING:
Basic		2,921,129		2,598,937		2,916,846		2,598,937
Diluted		2,968,504		2,598,937		2,941,665		2,598,937

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

ENERGY WEST, INCORPORATED AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)


	Six Months Ended
	December 31,
	2005			2004
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	495,531		$	(555,297	)
Adjustments to reconcile net income (loss) to net cash used in operating activities:
Depreciation and amortization, including deferred charges and financing costs		1,442,509			1,599,010
Derivative assets		(217,795	)		75,117
Derivative liabilities		163,505			620,287
Deferred gain		(522,521	)		—
Investment tax credit		(10,531	)		(10,531	)
Deferred gain on sale of assets		(11,814	)		(11,814	)
Deferred income taxes		468,054			(276,006	)
Changes in assets and liabilities:
Accounts and notes receivable		(7,525,993	)		(6,183,152	)
Natural gas and propane inventories		(4,902,096	)		(2,713,228	)
Accounts payable		4,403,114			157,522
Recoverable/refundable cost of gas purchases		294,176			223,831
Prepayments and other		(16,807	)		45,542
Other assets & liabilities		1,045,601			1,028,919

Net cash used in operating activities		(4,895,067	)		(5,999,800	)


CASH FLOWS FROM INVESTING ACTIVITIES:
Construction expenditures		(1,137,701	)		(1,507,112	)
Collection of long-term notes receivable		174,561			—
Customer advances received for construction		97,296			26,260
Increase from contributions in aid of construction		21,981			29,782

Net cash used in investing activities		(843,863	)		(1,451,070	)


CASH FLOWS FROM FINANCING ACTIVITIES:
Repayments of long-term debt		(263,160	)		(291,308	)
Proceeds from lines of credit		10,000,000			8,900,000
Repayments of lines of credit		(2,900,000	)		(1,000,758	)
Proceeds from other short-term borrowings		—			3,500,000
Dividends paid		(114,432	)		—

Net cash provided by financing activities		6,722,408			11,107,934


NET INCREASE IN CASH AND CASH EQUIVALENTS		983,478			3,657,064

CASH AND CASH EQUIVALENTS:
Beginning of period		93,606			1,322,702

End of period	$	1,077,084		$	4,979,766

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

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

December 31, 2005

Basis of Presentation

The accompanying unaudited condensed consolidated financial statements of Energy West, Incorporated and its subsidiaries (collectively, the “Company”) have been prepared in accordance with accounting principles generally accepted in the United States of America for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by generally accepted accounting principles for complete financial statements. In the opinion of management, all adjustments considered necessary for a fair presentation have been included. Operating results for the three and six month periods ended December 31, 2005 are not necessarily indicative of the results that may be expected for the fiscal year ending June 30, 2006. 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, 2005.

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 markets gas in Montana and Wyoming and, on a limited basis, 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.

In order to conform to the current year presentation, certain reclassifications have been made for prior reporting periods. The reclassifications had no effect on net income or cash flow.

Note 1 — Derivative Instruments and Hedging Activity

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

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

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

During the six months ended December 31, 2005, the Company has not entered into any new contracts that have required fair value accounting under Statement of Financial Accounting Standards (“SFAS”) No. 133. (Fair value accounting is also referred to as mark-to-market accounting.) However, existing derivatives as of December 31, 2005 were reflected on the Company’s consolidated balance sheet as derivative assets and liabilities at an approximate fair value as follows:


	Assets		Liabilities
Contracts maturing during fiscal year 2006	$	277,384	$	277,742
Contracts maturing during fiscal years 2007 and 2008
Contracts maturing during fiscal years 2009 and beyond		59,480

Total	$	336,864	$	277,742

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 December 31, 2005, the Company’s regulated operations have no contracts meeting the mark-to-market accounting requirements.

NOTE 2 — INCOME TAX EXPENSES (BENEFITS)

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


	Three Months Ended						Six Months Ended
	December 31,						December 31,
	2005			2004			2005			2004
Tax expense (benefit) at statutory rate of 35%	$	626,381		$	336,103		$	267,977		$	(316,048	)
State income tax expense (benefit), net of federal tax benefit		51,768			39,074			12,615			(50,926	)
Amortization of deferred investment tax credits		(5,265	)		(5,265	)		(10,531	)		(10,531	)
Other		(321	)		18,711			62			19,275


Total income tax expense (benefit)	$	672,563		$	388,623		$	270,123		$	(358,230	)

NOTE 3 — 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 by establishing a $23.0 million revolving credit facility with LaSalle Bank National Association, as Agent for certain banks (collectively, the “Lender”), replacing a previous short-term line of credit. The Montana Public Service Commission (“MPSC”) order granting approval of the $23.0 million credit facility imposes restrictions on 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 November 28, 2005, the Company entered into a restated credit agreement with the Lender. Pursuant to the restated credit agreement, the previous $23.0 million revolving credit facility was replaced with a $15.0 to $20.0 million revolving credit facility and a $6.0 million term loan maturing on March 31, 2009. The revolving line of credit is $20 million during the three month period November 28, 2005 through February 28, 2006 and continues at $15 million during the nine month period March 1, 2006 to November 26, 2006.

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 collateralized on an equal and ratable basis with the Lender in the collateral granted to secure the borrowings under the LaSalle Facility with the exception of the first $1.0 million which is secured to LaSalle.

Under the LaSalle Facility the Company may elect to pay interest on portions of the amounts outstanding under the revolving line of credit at the London interbank offered rate (LIBOR), plus 200 basis points or at the Prime Rate, for interest periods selected by the Company. 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 300 basis points or at the Prime Rate. The Company also pays a commitment fee of 25 basis points for the daily unutilized portion of the 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 on 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, maintaining a total debt to total capital ratio of not more than .70 to 1.00 and an interest coverage ratio of no less than 2.00 to 1.00. The LaSalle 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. During the three months and six months ended December 31, 2005, the Company was in compliance with the financial covenants under the LaSalle Facility.

At December 31, 2005, the Company had approximately $1,077,000 of cash on hand. In addition, at December 31, 2005, the Company had borrowed $11.0 million under the revolving line of credit. The Company’s short-term borrowings under its lines of credit during the six months ended December 31, 2005 had a daily weighted average interest rate of 7.29% per annum. The Company’s net availability at December 31, 2005 was $9.0 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 which is secured to LaSalle.

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, asset sales, and from incurring additional long-term indebtedness if it does not meet certain debt to interest and debt to capital ratios. Dividends and distributions during the period are limited to the cumulated net income for the prior sixty months. 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.

The total amount outstanding under all of the Company’s long-term debt obligations was approximately $19.4 million and $22.4 million at December 31, 2005 and December 31, 2004, respectively. The portion of such obligations due within one year was approximately $1,057,000 and $2,978,000 at December 31, 2005, and December 31, 2004, respectively.

NOTE 4 — 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 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 repaid over a four year period, collateralized by the wholesale propane assets sold. This note was paid in full on July 19, 2005.

NOTE 5 — DEFERRED CHARGES

Deferred Charges consist of the following:


	December 31,				June 30,
	2005		2004		2005
Regulatory asset for property taxes	$	2,419,169	$	2,690,505	$	2,561,265
Regulatory asset for income taxes		458,753		458,753		458,753
Regulatory asset for deferred environmental remediation costs		385,978		472,119		413,218
Other regulatory assets		40,249		75,152		52,198
Unamortized debt issue costs		1,115,821		1,365,502		1,240,490


Total	$	4,419,970	$	5,062,031	$	4,725,924

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

The property tax asset does not earn a return in the rate base; however the property tax is recovered in rates over a ten-year period starting January 1, 2004. The income taxes and environmental remediation costs earn a return equal to that of the Company’s rate base. No other assets earn a return or are recovered in the rate structure. Other regulatory assets are amortized over fiscal year 2006.

NOTE 6 — 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 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.

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

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

At December 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 December 31, 2005, the Company had recovered approximately $1,577,000 through such surcharges. As of December 31, 2005, the cost remaining to be recovered is $386,000.

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.

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

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 have been 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 should be assessed. The settlement amount is being paid in ten annual installments of $243,000 each beginning 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 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.

NOTE 7 — SEGMENTS OF OPERATIONS


	Three Months Ended					Six Months Ended
	December 31					December 31
	2005		2004			2005			2004
Gross margin (operating revenue less cost of gas purchased):
Natural gas operations	$	3,740,347	$	3,575,172		$	5,718,628		$	5,328,788
Propane operations		1,079,591		1,357,561			1,526,810			1,804,876
EWR		385,856		190,580			514,219			129,419
Pipeline operations		102,539		101,931			210,747			186,286

		5,308,333		5,225,244			7,970,404			7,449,369


Operating income (loss):
Natural gas operations		1,442,599		1,137,072			1,137,146			582,037
Propane operations		413,699		595,668			161,982			321,273
EWR		261,839		(260,935	)		115,693			(651,516	)
Pipeline operations		59,438		63,865			121,133			101,398

		2,177,575		1,535,670			1,535,954			353,192


Net income (loss):
Natural gas operations		765,320		424,934			417,283			(213,319	)
Propane operations		189,962		307,355			(5,451	)		106,619
EWR		132,755		(198,972	)		23,236			(491,937	)
Pipeline operations		29,067		33,080			60,463			43,340

	$	1,117,104	$	566,397		$	495,531		$	(555,297	)

NOTE 8 — ACCRUED AND OTHER CURRENT LIABILITIES

Accrued and other current liabilities consists of the following:


	December 31,				June 30,
	2005		2004		2005
Property tax settlement—current portion	$	243,000	$	243,000	$	243,000
Payable to employee benefit plans		114,713		340,982		481,514
Accrued vacation		265,513		402,723		267,859
Customer deposits		479,985		429,987		418,148
Accrued incentives		164,670		616,865		12,246
Accrued interest		230,971		108,870		97,987
Accrued taxes other than income		639,165		648,373		507,288
Customer prepayments from levelized billing		909,561		1,045,682		399,760
Other short-term borrowing		—		3,500,000		459,814
Other		874,123		801,859		862,561

Total	$	3,921,701	$	8,138,341	$	3,750,177

NOTE 9 — OTHER LONG TERM LIABILITIES

Other long-term liabilities consist of the following:


	December 31,				June 30,
	2005		2004		2005
Asset retirement obligation	$	634,595	$	602,351	$	618,473
Contribution in aid of construction		1,469,429		1,255,321		1,447,448
Customer advances for construction		775,233		629,849		677,936
Accumulated postretirement obligation		377,145		299,656		342,900
Deferred gain — long-term *		446,341				569,102
Deferred gain on sale leaseback of assets		11,825		35,453		23,639
Regulatory liability for income taxes		83,161		83,161		83,161
Property tax settlement		1,458,008		1,701,008		1,701,008

Total	$	5,255,737	$	4,606,799	$	5,463,667


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

NOTE 10 — STOCK OPTIONS

As of July 1, 2005, SFAS No. 123(R) became effective for the Company. The Company had previously followed Accounting Principles Board Opinion (“APB”) No. 25 and related Interpretations in accounting for its employee stock options. Under APB No. 25, no compensation expense was recognized, since the exercise price of the Company’s employee stock options equals the market price of the underlying stock on the date of grant. Under SFAS No. 123(R), compensation expense is now recognized. Stock-based compensation cost is measured at the grant date, based on the fair value of the award and is recognized over the

employee’s requisite service period. Compensation expense is calculated using the Black-Scholes option pricing model. The Black-Scholes calculations performed for the second quarter ended December 31, 2005 stock-based compensation expense utilized the methodology and assumptions consistent with those previously used by the Company to report pro-forma net income or loss under SFAS No. 123(R). The general and administrative expense for the stock-based compensation in the second quarter of fiscal 2006 was approximately $20,000 which is less than $0.01 per share.

The Company uses the Black Scholes methodology, with a volatility assumption of 54%, an expected life of 7 years, 2% expected dividend rate, and a risk free interest rate of 3.9%. If the Company had recorded stock option expense in the quarter ended December 31, 2004, its pro forma net income would have been decreased by approximately $32,000 or approximately $.01 per share.

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

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, 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. (See “Risk Factors” in the Company’s Annual Report on Form 10-K for the fiscal year ended June 30, 2005 filed with the Securities and Exchange Commission.) Any such forward looking statement is qualified by reference to these risk factors. The Company cautions that these risk factors are not exclusive. 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.

Operating Results of Our Company

Executive Overview

We have seen significant benefits from controlling costs and the renewed focus on our core business. This has lead to a decrease in the amount we have had to borrow under our credit facility even though we are paying a higher price to buy natural gas and propane. This has resulted in an opportunity to restore dividends to our shareholders. However, we continue to address certain challenges.

We must remain vigilant about our increasing demand for cash due to high commodity prices and our heavy reliance on a few suppliers. The loss of key personnel in such areas as accounting, engineering, propane and pipeline operations can have a dramatic impact on the efficient operation of the Company. Our small size makes the Company vulnerable to large earnings variations if litigation or other one-time expenses occur.

The foregoing concerns are counterbalanced by what we believe are our strengths:

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

	•		We continue to experience high growth in and around our Arizona propane business.

	•		Our positive reputation with regulators and customers.

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

Three Months Ended December 31, 2005 Compared To Three Months Ended December 31, 2004

The following discussion of the Company’s financial condition and results of operations should be read in conjunction with the Condensed Consolidated Financial Statements and Notes thereto and other financial information included elsewhere in this report and the Company’s Annual Report on Form 10-K for the fiscal year ended June 30, 2005. The following gives effect to the unaudited Condensed Consolidated Financial Statements as of December 31, 2005 and for the three month period ended December 31, 2005. Results of operations for interim periods are not necessarily indicative of results to be attained for any future period.

Net Income— The Company’s net income for the second quarter ended December 31, 2005 was $1,117,000 compared to a net income of $566,000 in the second quarter ended December 31, 2004, an increase of $551,000. The increase in the Company’s net income from the second quarter ended December 31, 2004 to the second quarter ended December 31, 2005 was primarily due to higher gross margins in Natural Gas and EWR, lower operating expenses in all segments except Pipeline, higher other income and a decrease in interest expense. The increases in gross margin for Natural Gas and EWR and the reductions in expenses were partially offset by a decrease in gross margin in Propane and an increase in income tax expense due to higher pretax income.

Revenues— The Company’s revenues for the second quarter ended December 31, 2005 were $28,929,000 compared to $23,116,000 in the second quarter ended December 31, 2004, an increase of $5,813,000. The increase was primarily attributable to: (1) natural gas revenue increases of $5,959,000 due to higher prices for natural gas passed through to customers; (2) EWR revenue increases of $573,000 due to a $339,000 favorable change in the valuation of derivative contracts, and $6,000 from normal operations. When analyzing the change in revenues it should be noted that revenue in the second quarter ended December 31, 2004 was reduced by $199,000 to record mark-to-market unrealized losses on derivative contracts. There was no material mark-to-market adjustments in the second quarter ended December 31, 2005. However, the revenues for the second quarter were favorably impacted by $139,000 of amortization of a deferred gain. The deferred gain was recorded in January 2005 when certain derivative contracts were re-classified as “normal purchase or normal sales.” The deferred gain is being amortized ratably over the life of the contracts (for further discussion regarding this reclassification see the Company’s June 30, 2005 10-K). These increases in revenue were offset by propane revenue decreases of $492,000 due to warmer weather and fewer volumes sold, partially offset by higher propane prices.

Gross Margin— Gross margin, which is defined as revenue less gas purchased and costs of gas and electricity (wholesale), increased $83,000, from $5,225,000 in the second quarter ended December 31, 2004 to $5,308,000 in the second quarter ended December 31, 2005.

EWR margin increased $195,000 due to the $339,000 favorable change in the valuation of the derivative contracts as discussed above, a $34,000 increase in production and electricity margins, offset by a decrease in gas margin of $178,000 due to higher gas cost.

Natural Gas Operations’ margin increased $165,000 primarily due to approved rate increases put into effect in November 2004. Propane Operations’ margin decreased $278,000 primarily due to warmer weather and less volumes sold.

Expenses Other Than Costs of Gas and Electricity and Costs of Goods Sold— Expenses other than gas purchased decreased by $559,000 in the second quarter ended December 31, 2005 as compared to the second quarter ended December 31, 2004. The primary reasons for this decrease were (1) decreases in the Company’s general and administrative costs of $431,000, (2) decreases in depreciation and amortization of $59,000, and (3) decreases in overhead and maintenance costs of $62,000 and $35,000 respectively, offset by (4) increases of $29,000 in taxes other than income.

Other Income— Other income increased by $67,000, from $141,000 in the second quarter ended December 31, 2004 to $208,000 in the second quarter ended December 31, 2005. Natural Gas other income increased $137,000 primarily due to income generated in fiscal year 2006 for services to customers over what had been provided in prior years, and other miscellaneous income. Propane other income decreased $21,000 due to the payoff on July 9^th, 2005 of the note receivable in RMF resulting in less interest income than in the second quarter ended December 31, 2004. EWR other income decreased $48,000 due to income from the settlement of a contract dispute in fiscal year 2005.

Interest Expense— Interest expense decreased by approximately $126,000 during the second quarter ended December 31, 2005 from the second quarter ended December 31, 2004 due to lower short-term borrowings and a decrease in the amortization of debt issuance costs related to securing the LaSalle short-term credit facility in fiscal year 2005.

Income Tax Expense— Income tax expense increased $284,000 in the second quarter ended December 31, 2005 as compared to the second quarter ended December 31, 2004 due to increased net income in the second quarter ended December 31, 2005.

Six Months Ended December 31, 2005 Compared To Six Months Ended December 31, 2004

The following discussion of the Company’s financial condition and results of operations should be read in conjunction with the Condensed Consolidated Financial Statements and Notes thereto and other financial information included elsewhere in this report and the Company’s Annual Report on Form 10-K for the fiscal year ended June 30, 2005. The following gives effect to the unaudited Condensed Consolidated Financial Statements as of December 31, 2005 and for the six month period ended December 31, 2005. Results of operations for interim periods are not necessarily indicative of results to be attained for any future period.

Net Income (Loss)— The Company’s net income for the six months ended December 31, 2005 was $495,000 compared to a net loss of $555,000 in the six months ended December 31, 2004, an increase of $1,051,000. The increase in the Company’s net income was primarily due to higher gross margins in Natural Gas, EWD and EWR, lower operating expenses in all segments except EWD, higher other income and a decrease in interest expense. The increases in gross margin and the reductions in expenses were partially offset by an increase in income tax expense due to higher pretax income.

Revenues— The Company’s revenues for the six months ended December 31, 2005 were $39,220,000 compared to $35,156,000 in the six months ended December 31, 2004, an increase of $4,065,000. The increase was primarily attributable to natural gas revenue increases of $7,067,000 due to higher prices for natural gas passed through to customers, as well as a rate increase put into effect in November of 2004 partially offset by decreases in EWR totaling $2,280,000 including trading revenue decreases of $2,277,000; reduction in retail gas revenues of $1,380,000 due to a decrease in volumes sold partially offset by higher prices; a $993,000 favorable change in the value of derivative contracts and increases of $16,000 in production and electric revenue. When analyzing the change in revenues it should be noted that revenue in the six months ended December 31, 2004 was reduced by $714,000 to record mark-to-market unrealized losses on derivative contracts. There were no material mark-to-market adjustments in the second quarter ended December 31, 2005. However, the second quarter ended December 31, 2005 quarter revenue was favorably impacted by $279,000 of amortization of a deferred gain. The deferred gain was recorded in January 2005 when certain derivative contracts were re-classified as “normal purchase or normal sales.” The deferred gain is being amortized ratably over the life of the contracts (for further discussion regarding this reclassification see the Company’s June 30, 2005 10-K). Revenues also reflect a decrease of $346,000 in the Propane segment due to warmer weather and lower volumes sold, as well as reduced sales to external

customers by Rocky Mountain Fuels. The increased revenues in Pipeline operations of $24,000 are due to an increase in gathering volumes on the Glacier line.

Gross Margin— Gross margin, which is defined as revenue less gas purchased and costs of gas and electricity (wholesale), increased $521,000, from $7,449,000 in the six months ended December 31, 2004 to $7,970,000 in the six months ended December 31, 2005. EWR margins increased $385,000 due to a $993,000 favorable change in the valuation of derivative contracts as discussed above, and a $31,000 increase in electricity and production margins, offset by a decrease in gas margin of $639,000 due to lower sales volumes and higher gas costs.

Pipeline Operations’ margin increased $24,000 due to the Glacier line being temporarily down from early June 2004 until the first week of November 2004. Natural Gas Operations’ margin increased $390,000 primarily due to approved rate increases put into effect in November 2004. Propane Operations’ margin decreased $278,000 primarily due to warmer weather and lower volumes, as well as reduced sales to external customers through Rocky Mountain Fuels.

Expenses Other Than Costs of Gas and Electricity and Costs of Goods Sold— Expenses other than gas purchased decreased by $662,000 in the six months ended December 31, 2005 as compared to the six months ended December 31, 2004. The primary reasons for this decrease were (1) decreases in the Company’s general and administrative costs of $549,000, (2) decreases in depreciation and amortization of $79,000, and (3) decreases in overhead and maintenance of $21,000 and $20,000 respectively, offset by (4) an increase of $8,000 in taxes other than income.

Other Income— Other income increased by $112,000, from $207,000 in the six months ended December 31, 2004 to $319,000 in the six months ended December 31, 2005. Natural Gas other income increased $188,000 primarily due to income generated in fiscal year 2006 for services to customers over what had been provided in prior years, and other miscellaneous income. Propane other income decreased $42,000 due to the payoff on July 9^th, 2005 of the note receivable in RMF resulting in less interest and consulting fee income than in the second quarter fiscal year 2005. EWR other income decreased $34,000 due to income generated from settlement of a contract dispute during the six months ended December 31, 2004.

Interest Expense— Interest expense decreased by approximately $385,000 during the six months ended December 31, 2005 from the six months ended December 31, 2004 due to lower short-term borrowings and the amortization of debt issuance costs related to securing the LaSalle short-term credit facility in fiscal year 2005.

Income Tax Expense— Income tax expense increased $628,000 in the six months ended December 31, 2005 as compared to the six months ended December 31, 2004 due to increased pretax income in the six months ended December 31, 2005.

Operating Results of our Natural Gas Operations


	Three Months Ended						Six Months Ended
	December 31,						December 31,
Natural Gas Operations	2005			2004			2005			2004
Operating revenues	$	20,187,548		$	14,228,550		$	26,502,915		$	19,436,226
Gas Purchased		16,447,201			10,653,378			20,784,287			14,107,438

Gross Margin		3,740,347			3,575,172			5,718,628			5,328,788
Operating expenses		2,297,748			2,438,100			4,581,482			4,746,751

Operating income		1,442,599			1,137,072			1,137,146			582,037
Other income		170,164			33,558			235,943			47,704


Income before interest and taxes		1,612,763			1,170,630			1,373,089			629,741

Interest expense		401,449			447,490			730,610			940,648

Income (loss) before income taxes		1,211,314			723,140			642,479			(310,907	)
Income tax benefit (expense)		(445,994	)		(298,206	)		(225,196	)		97,588


Net income (loss)	$	765,320		$	424,934		$	417,283		$	(213,319	)

Three Months Ended December 31, 2005 Compared To Three Months Ended December 31, 2004

Natural Gas Revenues and Gross Margins— The Natural Gas Operations’ operating revenues in the second quarter ended December 31, 2005 increased to $20,188,000 from $14,229,000 in the second quarter ended December 31, 2004. This $5,959,000 increase was primarily due to higher gas costs and an approved rate increase put into effect in November 2004.

Gas purchases in Natural Gas Operations increased by $5,794,000, from $10,653,000 in the second quarter ended December 31, 2004 to $16,447,000 in the second quarter ended December 31, 2005. The increase in gas cost reflects higher commodity prices during the current fiscal year.

Gross margin, which is defined as operating revenues less gas purchased, was approximately $3,740,000 for the second quarter ended December 31, 2005 compared to approximately $3,575,000 in the second quarter ended December 31, 2004. The increase of $165,000 is primarily due to approved rate increases put into effect in November 2004.

Natural Gas Operating Expenses— Natural Gas Segment’s operating expenses were approximately $2,298,000 for the second quarter ended December 31, 2005 as compared to $2,438,000 for second quarter ended December 31, 2004. The $140,000 reduction is due to $55,000 decrease in payroll and other general and administrative expenses resulting from the implementation of cost-saving measures, $40,000 in lower depreciation charges, $46,000 in lower overhead charges, and $36,000 in decreased maintenance charges. These savings were partially offset by $37,000 in higher taxes other than income taxes.

Natural Gas Other Income— Other income increased by $136,000, from $34,000 in the second quarter ended December 31, 2004 to $170,000 in the second quarter ended December 31, 2005. This was due primarily to additional service sales and other miscellaneous income.

Natural Gas Interest Expense— Interest expense is $46,000 lower in the current year second quarter compared to prior year second quarter primarily due to lower short-term borrowings and a decrease in the amortization of debt issuance costs.

Natural Gas Income Tax Expense— Tax expense is $148,000 higher in the current year second quarter compared to prior year second quarter due to higher pretax income.

Six Months Ended December 31, 2005 Compared to Six Months Ended December 31, 2004

Natural Gas Revenues and Gross Margins— The Natural Gas Operations’ operating revenues in the six months ended December 31, 2005 increased to $26,503,000 from $19,436,000 in the six months ended December 31, 2004. This $7,067,000 increase was primarily due to higher gas costs and an approved rate increase put into effect in November 2004.

Gas purchases in Natural Gas Operations increased by $6,677,000, from $14,107,000 in the six months ended December 31, 2004 to $20,784,000 in the six months ended December 31, 2005. The increase in gas cost reflects higher commodity prices during the current fiscal year.

Gross margin, which is defined as operating revenues less gas purchased, was approximately $5,719,000 for the six months ended December 31, 2005 compared to approximately $5,329,000 in the six months ended December 31, 2004. The increase of $390,000 is primarily due to approved rate increases put into effect in November 2004.

Natural Gas Operating Expenses— Natural Gas Segment’s operating expenses were approximately $4,581,000 for the six months ended December 31, 2005 as compared to $4,747,000 for the six months ended December 31, 2004. The $165,000 reduction is due to $78,000 decrease in payroll and other general and administrative expenses resulting from the implementation of cost-saving measures, $63,000 in lower depreciation charges, $21,000 in lower overhead charges, and $26,000 in lower maintenance costs. These savings were partially offset by $23,000 in higher taxes other than income taxes.

Natural Gas Other Income— Other income increased by $188,000, from $48,000 in the six months ended December 31, 2004 to $236,000 in the six months ended December 31, 2005. This was due primarily to service sales in Great Falls and other miscellaneous income.

Natural Gas Interest Expense— Interest expense is $210,000 lower in the six months ended December 31, 2005 compared to the six months ended December 31, 2004 primarily due to lower short-term borrowings and a decrease in the amortization of debt issuance costs.

Natural Gas Income Tax Expense— Tax expense increased $323,000 in the six months ended December 31, 2005 compared to the six months ended December 31, 2004 due to higher pretax income.

Operating Results of our Propane Operations


	Three Months Ended						Six Months Ended
	December 31,						December 31,
Propane Gas Operations	2005			2004			2005			2004
Operating revenues	$	2,530,948		$	3,022,491		$	3,528,930		$	3,875,102
Gas Purchased		1,451,357			1,664,930			2,002,120			2,070,226

Gross Margin		1,079,591			1,357,561			1,526,810			1,804,876
Operating expenses		665,892			761,893			1,364,828			1,483,603

Operating income		413,699			595,668			161,982			321,273
Other income		29,719			51,202			60,813			103,231


Income before interest and taxes		443,418			646,870			222,795			424,504

Interest expense		128,547			141,468			235,153			299,927

Income (loss) before income taxes		314,871			505,402			(12,358	)		124,577
Income tax benefit (expense)		(124,909	)		(198,047	)		6,907			(17,958	)

Net income (loss)	$	189,962		$	307,355		$	(5,451	)	$	106,619

Three Months Ended December 31, 2005 Compared To Three Months Ended December 31, 2004

Propane Revenue and Gross Margins— Propane Operations’ revenues decreased $491,000, from $3,022,000 for the second quarter ended December 31, 2004 to $2,531,000 for the second quarter ended December 31, 2005 as a result of warmer weather and lower volumes in the Arizona regulated and unregulated operations, coupled with lower sales to external customers in the wholesale Rocky Mountain Fuels operation. Gas purchases decreased $214,000, from $1,665,000 in the second quarter ended December 31, 2004 to $1,451,000 in the second quarter ended December 31, 2005. This decrease was due primarily to warmer weather and less volumes sold in the propane segment. Gross margin decreased $278,000, from $1,358,000 in the second quarter ended December 31, 2004 to $1,080,000 in the second quarter ended December 31, 2005. This was again attributable to warmer weather and lower volumes. Although propane prices were higher in fiscal year 2006, the warmer weather and volume decrease had a greater impact on revenues and margin.

Propane Operating Expenses— Operating expenses were $666,000 in the second quarter ended December 31, 2005 compared to $762,000 in the second quarter ended December 31, 2004. This decrease of $96,000 is due to decreases in general and administrative costs of $77,000, lower overhead costs of $13,000, lower taxes other than income of $4,000, and lower depreciation of $3,000. These savings were offset by an increase in maintenance of $1,000.

Propane Other Income— Other income decreased by $21,000, from $51,000 for the second quarter ended December 31, 2004 to $31,000 for the second quarter ended December 31, 2005. In the second quarter ended December 31, 2004, RMF had interest income from a note

receivable generated with the sale of assets in August 2003. This note was paid in full on July 9^th, 2005, resulting in lower interest income.

Propane Interest Expense— Interest expense decreased by $13,000, from $141,000 in the second quarter ended December 31, 2004 to $128,000 for the second quarter ended December 31, 2005, primarily due to lower short-term borrowings and a decrease in the amortization of debt issuance costs.

Propane Income Tax Expense— Income tax expense decreased by $73,000, from $198,000 in the second quarter ended December 31, 2004 to $125,000 in the second quarter ended December 31, 2005 due to lower pretax income.

Six Months Ended December 31, 2005 Compared to Six Months Ended December 31, 2004

Propane Revenue and Gross Margins— Propane Operations’ revenues decreased $346,000, from $3,875,000 for the six months ended December 31, 2004 to $3,529,000 for the six months ended December 31, 2005 as a result of warmer weather and lower volumes, coupled with less sales to external customers in the wholesale Rocky Mountain Fuels operation. These lower volumes were partially offset by higher prices in the propane market. Gas purchased decreased from $2,070,000 to $2,020,000 for the same period due also to warmer weather and less volumes sold. The volume decrease was partially offset by higher prices in the cost of propane for both the regulated utility and the wholesale propane operations. Gross margin decreased $278,000, from $1,805,000 in the six months ended December 31, 2004 to $1,527,000 for the six months ended December 31, 2005. This margin decrease was primarily due to warmer weather and lower volumes, coupled with less sales to external customers in the wholesale operation.

Propane Operating Expenses— Operating expenses were $1,484,000 in the six months ended December 31, 2004 compared to $1,365,000 in the six months ended December 31, 2005. This decrease of $119,000 is due to decreases in overhead, general and administrative costs of $119,000, and taxes other than income of $8,000. These savings were offset by increases in maintenance and depreciation of $9,000.

Propane Other Income— Other income decreased by $42,000, from $103,000 for the six months ended December 31, 2004 to $61,000 for the six months ended December 31, 2005. In the six months ended December 31, 2004, RMF had interest income from a note receivable generated with the sale of assets in August 2003. This note was paid in full on July 9^th, 2005, resulting in lower interest income in fiscal year 2006.

Propane Interest Expense— Interest expense decreased by $65,000, from $300,000 in the six months ended December 31, 2004 to $235,000 for the six months ended December 31, 2005, primarily due to lower short-term borrowings and a decrease in the amortization of debt issuance costs.

Propane Income Tax Benefit (Expense)— Income tax expense was $18,000 in the six months ended December 31, 2004, compared to an income tax benefit of $7,000 in the six months ended December 31, 2005 due to lower pretax income in fiscal year 2006.

Operating Results of our EWR Operations


	Three Months Ended						Six Months Ended
	December 31,						December 31,
Energy West Resources (“EWR”)	2005			2004			2005			2004
Operating revenues	$	6,108,052		$	5,763,054		$	8,977,884		$	11,657,898
Gas Purchased		5,722,196			5,572,474			8,463,665			11,528,479

Gross Margin		385,856			190,580			514,219			129,419
Operating expenses		124,017			451,515			398,526			780,935

Operating income (loss)		261,839			(260,935	)		115,693			(651,516	)
Other income		8,250			56,535			22,399			56,535

Income (loss) before interest and taxes		270,089			(204,400	)		138,092			(594,981	)
Interest expense		53,557			119,522			100,833			204,306

Income (loss) before income taxes		216,532			(323,922	)		37,259			(799,287	)
Income tax benefit (expense)		(83,777	)		124,950			(14,023	)		307,350

Net income (loss)	$	132,755		$	(198,972	)	$	23,236		$	(491,937	)

Three Months Ended December 31, 2005 Compared To Three Months Ended December 31, 2004

EWR Revenues and Gross Margins— Revenues increased $345,000 from $5,763,000 in the second quarter ended December 31, 2004 to $6,108,000 in the second quarter ended December 31, 2005. Increased revenues were primarily due to an increase of $339,000 from a favorable change in the valuation of derivative contracts and $6,000 from normal operations. When analyzing the change in revenues it should be noted that revenue in the second quarter ended December 31, 2004 was reduced by $199,000 to record mark-to-market unrealized losses on derivative contracts. There were no material mark-to-market adjustments in the second quarter ended December 31, 2005. However, the second quarter ended December 31, 2005 revenue was favorably impacted by $139,000 of amortization of a deferred gain. The deferred gain was recorded in January 2005 when certain derivative contracts were re-classified as “normal purchase or normal sales.” The deferred gain is being amortized ratably over the life of the contracts (for further discussion regarding this reclassification see the Company June 30, 2005 10-K).

Second quarter fiscal year 2006 gross margin of $386,000 represents an increase of $195,000 over the gross margin earned in the second quarter fiscal year 2005. This is primarily due to a $339,000 increase in the valuation of derivative contracts, a $30,000 increase in production margin and a $4,000 increase in electric margin, offset by a $178,000 increase in gas cost.

EWR Operating Expenses— Operating expenses decreased approximately $327,000, from $452,000 for second quarter ended December 31, 2004 to $124,000 for the second quarter ended December 31, 2005. This decrease is due primarily to a reduction in outside services of

$232,000, $72,000 in salary and benefits and $23,000 in various other general and administrative charges.

EWR Other Income— Other income decreased by $48,000 due to income from the settlement of a contract dispute in the second quarter ended December 31, 2004.

EWR Interest Expense— Interest expense decreased by $66,000 primarily due to lower short-term borrowings and a decrease in the amortization of debt issuance costs.

EWR Income Tax Benefit (Expense)— Tax expense increased due to increased pretax income in the second quarter ended December 31, 2005.

Six Months Ended December 31, 2005 Compared to Six Months Ended December 31, 2004

EWR Revenues and Gross Margins— Revenues decreased $2,680,000 from $11,658,000 in the six months ended December 31, 2004 to $8,978,000 in the six months ended December 31, 2005. The decreased revenues were due to $2,277,000 lower trading revenue and $1,380,000 lower retail gas revenues due to a 62% decrease in volumes sold offset by higher sales prices. These decreases were offset by a $993,000 favorable change in the value of derivative contracts and a $16,000 decrease in production and electric revenue. When analyzing the change in revenues it should be noted that revenue in the six months ended December 31, 2004 was reduced by $714,000 to record mark-to-market unrealized losses on derivative contracts. There was no material mark-to-market adjustments in the second quarter ended December 31, 2005. However, the six months ended December 31, 2005 revenue was favorably impacted by $279,000 of amortization of a deferred gain. The deferred gain was recorded in January 2005 when certain derivative contracts were re-classified as “normal purchase or normal sales.” The deferred gain is being amortized ratably over the life of the contracts (for further discussion regarding this reclassification see the Company’s June 30, 2005 10-K).

Second quarter fiscal year 2006 gross margin increased $385,000 from gross margin earned in the first six months fiscal year 2005. This is primarily due to a $993,000 increase in the valuation of derivative contracts and $31,000 increase in production and electricity margin, offset by a $639,000 decrease due to lower sales volumes and higher gas cost.

EWR Operating Expenses— Operating expenses decreased approximately $382,000 during the six months ended December 31, 2005. This decrease is due primarily to a reduction in outside services of $270,000 and a decrease of $58,000 in salaries and benefits, a $29,000 decrease in depletion and depreciation expense, and $25,000 savings in various other general and administrative charges.

EWR Other Income— Other income decreased by $34,000 due the settlement of a contract dispute in the six months ended December 31, 2004.

EWR Interest Expense— Interest expense decreased by $103,000 due to a decrease in short-term borrowings and debt issue costs.

EWR Income Tax Benefit (Expense)— Tax expense increased due to increased pretax income.

Operating Results of our Pipeline Operations


	Three Months Ended						Six Months Ended
	December 31,						December 31,
Pipeline Operations	2005			2004			2005			2004
Operating revenues	$	102,539		$	101,931		$	210,747		$	186,286
Gas Purchased		—			—			—			—

Gross Margin		102,539			101,931			210,747			186,286
Operating expenses		43,101			38,066			89,614			84,888

Operating income		59,438			63,865			121,133			101,398
Other income		—			—			—			—

Income before interest and taxes		59,438			63,865			121,133			101,398
Interest expense		12,488			13,465			22,859			29,308

Income before income taxes		46,950			50,400			98,274			72,090
Income tax (expense)		(17,883	)		(17,320	)		(37,811	)		(28,750	)

Net income	$	29,067		$	33,080		$	60,463		$	43,340

Three Months Ended December 31, 2005 Compared To Three Months Ended December 31, 2004

Pipeline Revenues and Gross Margins— Pipeline revenue consists of gathering revenue from the Glacier line and capacity charge revenue on the Shoshone line. Both pipelines are located in Montana and Wyoming.

Pipeline Operations’ margin has remained constant in the second quarter ended December 31, 2005 as compared to the second quarter ended December 31, 2004.

Pipeline Operating Expenses— Operating expenses increased by $5,000 due to an increase in maintenance charges and depreciation, offset by savings in various general and administrative charges.

Pipeline Interest Expense— Interest expense decreased due to a decrease in short-term borrowings and debt issue costs.

Pipeline Income Tax Expense— Tax expense remained consistent.

Six Months Ended December 31, 2005 Compared to Six Months Ended December 31, 2004

Pipeline Revenues and Gross Margins—Pipeline Operations’ margin increased $24,000 due an increase in gathering volumes on the Glacier gathering line.

Pipeline Operating Expenses— Operating expenses increased by $5,000 due to an increase in maintenance charges and depreciation, offset by savings in various general and administrative charges.

Pipeline Interest Expense— Interest expense decreased due to a decrease in short-term borrowings and debt issue costs.

Pipeline Income Tax Expense— Tax expense increased due to a higher pretax income in the six months ended December 31, 2005.

Consolidated Cash Flow Analysis

Sources and Uses of Cash

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

Our ability to maintain liquidity depends upon our credit facility at LaSalle Bank, shown as line of credit on the accompanying balance sheet. Our use of the LaSalle credit facility decreased to $11,000,000 at December 31, 2005, compared with $14,629,304 at December 31, 2004. This $3,629,304 improvement reflects the fact that we generated net income of $496,000 in the six months ended December 31, 2005 as compared to a net loss of $555,000 in the six months ended December 31, 2004, a $900,000 refund of income taxes collected from a carry back of net operating losses in prior years, a $2,838,000 increase in accounts receivable and a $4,426,000 increase in accounts payable. We finance our capital expenditures on an interim basis through this LaSalle credit facility. We periodically repay our short-term borrowings under our LaSalle credit facility by using the net proceeds from the sale of long-term debt and equity securities.

Long-term debt decreased to $18,370,000 at December 31, 2005, compared with $19,401,000 at December 31, 2004. This $1,031,000 decrease resulted primarily from the scheduled principal payments of $480,000 on the Series 1993 notes, $95,000 on the Series 1992B notes and $400,000 on the term loan as provided for in the debt agreements.

Cash increased by $983,000 at December 31, 2005, from June 30, 2005, compared with the $3,657,000 increase in cash for the six months ended December 31, 2004, as shown in the following table:


	December 31,
	2005			2004
Provided by (used in) operating activities	$	(4,895,067	)		($5,999,800	)
Used in investing activities		(843,863	)		(1,451,070	)
Provided by financing activities		6,722,408			11,107,934


Increase in cash	$	983,478		$	3,657,064

For the six months ended December 31, 2005, cash used by operating activities decreased $1,105,000 as compared to the six months ended December 31, 2004. This was due to an increase in net income of $1,151,000, decrease in depreciation expense of $156,000, increase in deferred income taxes of $744,000, increase in accounts receivable of $1,343,000, a decrease in the value of derivative assets of $293,000, a decrease in gas inventories of $2,189,000, an increase in accounts payable of $4,245,000 a decrease in derivative liabilities of $456,000, a decrease in deferred gain of $523,000, an increase in recoverable gas costs of $70,000, a decrease in prepaid items of $62,000, and an increase in cash used for other assets and liabilities of $16,000.

For the six months ended December 31, 2005, cash used in investing activities decreased $607,000 as compared to the six months ended December 31, 2004 due to a decrease in construction expense of $369,000, an increase in cash received from long term notes receivable of $175,000, and an increase in customer advances and aid in construction of $63,000.

For the six months ended December 31, 2005, cash provided by financing activities decreased by $4,386,000 as compared to the six months ended December 31, 2004, due to lower advances against the line of credit.

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, we have 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.

We maintain a revolving credit facility with LaSalle Bank National Association, as Agent for certain banks. The LaSalle credit facility is accompanied by a $6.0 million term loan maturing on March 31, 2009. The term loan at December 31, 2005 had an outstanding balance of $5.3 million. Borrowings under the LaSalle credit facility are secured by liens on substantially all of our assets. Our obligations under certain other notes and industrial development revenue obligations are secured on an equal and ratable basis with LaSalle in the collateral granted to secure the borrowings under the LaSalle credit facility with the exception of the first $1.0 million of debt under the LaSalle credit facility.

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


	First		Second		Third		Fourth
	Quarter		Quarter		Quarter		Quarter
Year Ended June 30, 2006
Minimum borrowing	$	3,100,000	$	5,200,000
Maximum borrowing	$	5,200,000	$	12,250,000
Average borrowing	$	4,167,000	$	9,489,000

Year Ended June 30, 2005
Minimum borrowing	$	7,729,000	$	12,688,000	$	3,500,000	$	2,700,000
Maximum borrowing	$	13,129,000	$	14,629,000	$	13,929,000	$	3,900,000
Average borrowing	$	10,196,000	$	13,982,000	$	8,110,000	$	3,167,000

Year Ended June 30, 2004
Minimum borrowing	$	6,105,000	$	12,102,000	$	9,229,000	$	4,729,000
Maximum borrowing	$	8,602,000	$	12,629,000	$	13,229,000	$	6,729,000
Average borrowing	$	7,482,000	$	12,277,000	$	10,563,000	$	5,563,000

At December 31, 2005, the Company had approximately $1,077,000 of cash on hand. In addition, at December 31, 2005, the Company had borrowed $11.0 million under the revolving line of credit. The Company’s short-term borrowings under its lines of credit during the six months ended December 31, 2005 had a daily weighted average interest rate of 7.29% per annum. The Company’s net availability at December 31, 2005, was $9.0 million under the LaSalle Facility revolving line of credit.

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.

The total amount outstanding under all of the Company’s long-term debt obligations was approximately $19.4 million and $22.4 million, at December 31, 2005 and December 31, 2004, respectively. The portion of such obligations due within one year was approximately $1,057,000 and $2,978,000 at December 31, 2005, and December 31, 2004, respectively.

Dividends

In October 2005 the Company declared a dividend of $.04 per share. Dividends totaling $114,432 were paid in the quarter ending December 31, 2005.

Contractual Obligations

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

The table below presents contractual balances of our consolidated long-term and short-term debt at the expected maturity dates as well as the fair value of those instruments on December 31, 2005. The interest rates presented below represent the weighted-average interest rates for the year ended December 31, 2005. The fair value of the interest rate swap was $59,480 and is recorded as a derivative asset on the accompanying financial statements.

Payments Due by Period


			1 year						After
Contractual Obligations	Total		or less		2-3 years		4-5 years		5 years
Interest payments (a)	$	6,635,241	$	1,056,735	$	1,980,790	$	1,825,516	$	1,772,200

Long Term Debt (b)		19,427,126		1,056,633		2,166,509		4,360,000		11,843,984

Operating Lease Obligations		252,548		116,612		135,936		—		—

Funding of retiree health plan (c)		116,000		21,000		42,000		42,000		11,000

Transportation and Storage Obligation (d)		17,827,014		2,183,858		8,544,997		7,098,160		—


Total Obligations	$	44,257,929	$	4,434,838	$	12,870,232	$	13,325,676	$	13,627,184


(a)		Our long-term debt, notes payable and customers’ deposits all require interest payments. Interest payments are projected based on actual interest payments incurred in fiscal 2005 until the underlying debts mature.

(b)		See Note 3 of the Notes to Consolidated Financial Statements for a description of this debt. The cash obligations represent the maximum annual amount of redemptions to be made to certain holders or their beneficiaries through the debt maturity date.


(c)		For the purpose of this calculation, we have assumed that our obligation is limited to a maximum of $125 per month for each of our 14 retired persons for the remainder of their expected life.

(d)		Transportation and Storage Obligations represent annual commitments with suppliers for periods extending up to four years. These costs are recoverable in customer rates.

CONTRACTS ACCOUNTED FOR AT FAIR VALUE

Management of Risks Related to Derivatives — 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 (RMC), 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.

The Company accounts for certain of such purchases or sale agreements in accordance with SFAS No. 133. Under SFAS 133, such contracts are reflected in the Company’s 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 the Company’s 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.”

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


	Assets		Liabilities
Contracts maturing during fiscal year 2006	$	277,384	$	277,742
Contracts maturing during fiscal years 2007 and 2008
Contracts maturing during fiscal years 2009 and beyond		59,480		—

Total	$	336,864	$	277,742

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

Off Balance Sheet Arrangements

The Company had no off balance sheet arrangements at December 31, 2005.

ITEM 3 — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

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

Commodity Price Risk

The Company seeks to protect itself against natural gas price fluctuations by limiting the aggregate level of net open positions that are exposed to market price changes. 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 the Company will consider to those related to physical natural gas deliveries. Therefore, management believes that our results of operations are not significantly exposed to changes in natural gas prices.

Interest Rate Risk

Our results of operations are affected by fluctuations in interest rates (e.g. interest expense on debt). The Company mitigates this risk by entering into long-term debt agreements with fixed interest rates. Some of our notes payable, however, are subject to variable interest rates which we may mitigate by entering into interest rate swaps. A hypothetical 100 basis point change in market rates applied to the balance of the notes payable would change interest expense by approximately $90,000 annually.

Credit Risk

Credit risk relates to the risk of loss that the Company 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 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. The Company seeks to mitigate credit risk by evaluating the financial strength of potential counterparties. However, despite mitigation efforts, defaults by counterparties may occur from time to time. To date, no such default has occurred.

ITEM 4. CONTROLS AND PROCEDURES

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

The evaluation of our disclosure controls by our principal executive officer and principal financial officer included a review of the controls’ objectives and design, the operation of the controls, and the effect of the controls on the information presented in this Quarterly Report. Our management, including our 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 Quarterly Report on Form 10-Q, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under

the Securities Exchange Act of 1934) were effective at the reasonable assurance level. They are not aware of any significant changes in our disclosure controls or in other factors that could significantly affect these controls subsequent to the date of their evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. During the most recent fiscal period, there have not been any changes in our internal control over financial reporting that have materially affected, or that are reasonably likely to materially affect, our internal control over financial reporting.

PART II — OTHER INFORMATION

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

We held our 2005 Annual Meeting of Shareholders on November 16, 2005. The following nominees were elected to the Company’s Board of Directors to serve for a one year term unless they resign.


Name	For		Withhold
W. E. Argo		2,389,658		68,370
David A. Cerotzke		2,419,454		38,380
Mark D. Grossi		2,414,699		43,055
Richard M. Osborne		2,373,099		84,995
Terry M. Palmer		2,437,320		27,049
Richard J. Schulte		2,502,837		30,426
Thomas J. Smith		2,350,804		106,726

Additionally, the Company’s shareholders voted upon a proposal to ratify the appointment of Hein & Associates LLP as our independent auditors for the fiscal year ending June 30, 2006.


For		Withhold

	2,447,877		22,039

ITEM 6. EXHIBITS


Exhibit
Number		Description

10.1		Amended and Restated Credit Agreement, dated December 14, 2005, by and among Registrant, its subsidiaries and LaSalle Bank National Association.

31		Certifications pursuant to SEC Release No. 33-8238, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

32		Certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

SIGNATURES

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


ENERGY WEST, INCORPORATED

/s/ Wade F. Brooksby

Wade F. Brooksby				February 13, 2006
Chief Financial Officer
(principal financial officer
and principal accounting officer)

EXHIBIT INDEX


Exhibit
Number		Description

10.1		Amended and Restated Credit Agreement, dated December 14, 2005, by and among Registrant, its subsidiaries and LaSalle Bank National Association.

31		Certifications pursuant to SEC Release No. 33-8238, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

32		Certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

Positive
Negative
Uncertain
Constraining
Legalese
Litigous
Readability	H.S. sophomore Avg

Gas Natural Inactive 10-Q2005 Q4 Quarterly report

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