UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

(Mark One)

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

For the quarterly period ended July 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: 0-8877

CREDO PETROLEUM CORPORATION

(Exact name of registrant as specified in its charter)

Colorado		84-0772991
(State or other jurisdiction of incorporation or organization)		(IRS Employer Identification No.)
1801 Broadway, Suite 900
Denver, Colorado		80202
(Address of principal executive offices)		(Zip Code)

303-297-2200

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

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

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, net of treasury stock, as of the latest practicable date.

Date		Class		Outstanding
September 9, 2005		Common stock, $.10 par value		6,076,696

 

 

CREDO PETROLEUM CORPORATION AND SUBSIDIARIES

Quarterly Report on Form 10-Q For the Period Ended July 31, 2005

TABLE OF CONTENTS

		Page No.
PART I — FINANCIAL INFORMATION
Item 1. Financial Statements
Consolidated Balance Sheets As of July 31, 2005 (Unaudited) and October 31, 2004			3
Consolidated Statements of Operations For the Three and Nine Months Ended July 31, 2005 and 2004 (Unaudited)			4
Consolidated Statement of Stockholders’ Equity and Comprehensive Loss For the Nine Months Ended July 31, 2005 (Unaudited)			5
Consolidated Statements of Cash Flows For the Nine Months Ended July 31, 2005 and 2004 (Unaudited)			6
Notes to Consolidated Financial Statements (Unaudited)			7
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			12
Item 3. Quantitative and Qualitative Disclosures About Market Risk			17
Item 4. Controls and Procedures			17
PART II — OTHER INFORMATION
Item 1. Legal Proceedings			18
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			18
Item 3. Defaults Upon Senior Securities			18
Item 4. Submission of Matters to a Vote of Security Holders			18
Item 5. Other Information			18
Item 6. Exhibits			18
Signatures			19
Certification by CEO Pursuant to Section 302
Certification by CFO Pursuant to Section 302
Certification by CEO & CFO Pursuant to Section 906

The terms “CREDO”, “Company”, “we”, “our”, and “us” refer to CREDO Petroleum Corporation and its subsidiaries unless the context suggests otherwise.

PART I — FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

CREDO PETROLEUM CORPORATION AND SUBSIDIARIES

Consolidated Balance Sheets

		July 31,				October 31,
		2005				2004
		(Unaudited)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents		$	892,000			$	518,000
Short term investments			5,512,000				6,371,000
Receivables:
Accrued oil and gas sales			2,810,000				2,051,000
Trade			356,000				1,019,000
Other current assets			1,260,000				58,000
Total current assets			10,830,000				10,017,000
Oil and gas properties, at cost, using full cost method:
Evaluated oil and gas properties			34,004,000				30,072,000
Unevaluated oil and gas properties			3,731,000				2,174,000
Less: accumulated depreciation, depletion and amortization of oil and gas properties			(14,232,000	)			(12,737,000	)
Net oil and gas properties, at cost, using full cost method			23,503,000				19,509,000
Exclusive license agreement, net of amortization of $344,000 in 2005 and $291,000 in 2004			355,000				408,000
Other, net			745,000				1,042,000
		$	35,433,000			$	30,976,000
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable and accrued liabilities		$	2,996,000			$	4,394,000
Income taxes payable			144,000				12,000
Total current liabilities			3,140,000				4,406,000
LONG-TERM LIABILITIES:
Deferred income taxes, net			6,021,000				4,605,000
Exclusive license obligation, less current obligations of $58,000			297,000				297,000
Asset retirement obligation			862,000				748,000
Total liabilities			10,320,000				10,056,000
COMMITMENTS
STOCKHOLDERS’ EQUITY:
Preferred stock, no par value, 5,000,000 shares authorized, none issued			—				—
Common stock, $.10 par value, 20,000,000 shares authorized, 6,340,000 shares issued in 2005 and 2004			634,000				634,000
Capital in excess of par value			12,577,000				12,463,000
Treasury stock, at cost, 279,000 shares in 2005 and 303,000 in 2004			(275,000	)			(452,000	)
Accumulated other comprehensive loss			(36,000	)			(437,000	)
Retained earnings, net of $6,272,000 related to 20% stock dividend in 2003			12,213,000				8,712,000
Total stockholders’ equity			25,113,000				20,920,000
		$	35,433,000			$	30,976,000

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

CREDO PETROLEUM CORPORATION AND SUBSIDIARIES

Consolidated Statements of Operations

(Unaudited)

		Nine Months Ended								Three Months Ended
		July 31,								July 31,
		2005				2004				2005				2004
REVENUES:
Oil and gas sales		$	8,785,000			$	6,932,000			$	3,396,000			$	2,226,000
Operating			487,000				444,000				164,000				152,000
Investment and other income			201,000				186,000				105,000				61,000
			9,473,000				7,562,000				3,665,000				2,439,000
COSTS AND EXPENSES:
Oil and gas production			1,920,000				1,464,000				790,000				532,000
Depreciation, depletion and amortization			1,610,000				1,227,000				568,000				436,000
General and administrative			1,052,000				1,011,000				337,000				344,000
Interest			28,000				30,000				9,000				7,000
			4,610,000				3,732,000				1,704,000				1,319,000
INCOME BEFORE INCOME TAXES			4,863,000				3,830,000				1,961,000				1,120,000
INCOME TAXES			(1,362,000	)			(1,073,000	)			(549,000	)			(314,000	)
NET INCOME		$	3,501,000			$	2,757,000			$	1,412,000			$	806,000
EARNINGS PER SHARE OF COMMON STOCK — BASIC		$	.58			$	.46			$	.23			$	.14
EARNINGS PER SHARE OF COMMON STOCK — DILUTED		$	.56			$	.45			$	.22			$	.13
Weighted average number of shares of Common Stock and dilutive securities:
Basic			6,046,000				6,020,000				6,058,000				6,038,000
Diluted			6,221,000				6,186,000				6,226,000				6,222,000

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

CREDO PETROLEUM CORPORATION AND SUBSIDIARIES

Statement of Stockholders’ Equity and Comprehensive Income

(Unaudited)

For the Nine Months Ended July 31, 2005

																		Accumulated
										Capital In								Other												Total
		Common Stock								Excess Of				Treasury				Comprehensive				Comprehensive				Retained				Stockholders’
		Shares				Amount				Par Value				Stock				Loss				Income				Earnings				Equity
Balance, October 31, 2004			6,340,000			$	634,000			$	12,463,000			$	(452,000	)		$	(437,000	)						$	8,712,000			$	20,920,000
Comprehensive income:
Net income			—				—				—				—				—			$	3,501,000				3,501,000				3,501,000
Other comprehensive income:
Change in fair value of derivatives, net of tax			—				—				—				—				401,000				401,000				—				401,000
Total comprehensive income																						$	3,902,000
Purchase of treasury stock			—				—				—				(8,000	)			—								—				(8,000	)
Exercise of common stock options			—				—				—				185,000				—								—				185,000
Tax benefit from the exercise of common stock options			—				—				114,000				—				—								—				114,000
Balance, July 31, 2005			6,340,000			$	634,000			$	12,577,000			$	(275,000	)		$	(36,000	)						$	12,213,000			$	25,113,000

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

CREDO PETROLEUM CORPORATION AND SUBSIDIARIES

Consolidated Statements of Cash Flows

(Unaudited)

		Nine Months Ended
		July 31,
		2005				2004
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income		$	3,501,000			$	2,757,000
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization			1,610,000				1,227,000
Deferred income taxes			1,250,000				931,000
Other			76,000				—
Changes in operating assets and liabilities:
Proceeds from short term investments			2,500,000				509,000
Purchase of short term investments			(1,641,000	)			(1,849,000	)
Accrued oil and gas sales			(759,000	)			(319,000	)
Trade receivables			663,000				(339,000	)
Other current assets			(1,138,000	)			(59,000	)
Accounts payable and accrued liabilities			(853,000	)			682,000
Income taxes payable			132,000				(10,000	)
NET CASH PROVIDED BY OPERATING ACTIVITIES			5,341,000				3,530,000
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas properties			(5,064,000	)			(3,980,000	)
Proceeds from sale of oil and gas properties			118,000				—
Changes in other long-term assets			(198,000	)			(388,000	)
NET CASH USED IN INVESTING ACTIVITIES			(5,144,000	)			(4,368,000	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from exercise of stock options (24,000 options in 2005 and 78,000 options in 2004)			185,000				291,000
Purchase of treasury stock (500 shares in 2005 and 2,000 shares in 2004)			(8,000	)			(39,000	)
NET CASH PROVIDED BY FINANCING ACTIVITIES			177,000				252,000
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS			374,000				(586,000	)
CASH AND CASH EQUIVALENTS:
Beginning of period			518,000				1,885,000
End of period		$	892,000			$	1,299,000
Supplemental cash flow information:
Cash paid during the period for income taxes		$	—			$	157,000
Cash paid during the period for interest		$	—			$	—

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

CREDO PETROLEUM CORPORATION AND SUBSIDIARIES

Notes To Consolidated Financial Statements (Unaudited)

July 31, 2005

1. BASIS OF PRESENTATION

Effective November 1, 2004, the company became subject to full SEC reporting requirements. The company’s first filing subject to full reporting requirements was its quarterly report on Form 10-Q for the first fiscal quarter ended January 31, 2005.

The accompanying unaudited consolidated financial statements have been prepared in accordance with U. S. generally accepted accounting principles for interim financial information and with the instructions for Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by U. S. generally accepted accounting principles for complete financial statements. In the opinion of management, the consolidated financial statements contain all adjustments (consisting of normal recurring adjustments) considered necessary for a fair presentation of the company’s results for the periods presented. These consolidated financial statements should be read in conjunction with the company’s Form 10-KSB for the fiscal year ended October 31, 2004.

2. SIGNIFICANT ACCOUNTING POLICIES

The preparation of financial statements in conformity with generally accepted accounting principles requires the company to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The company bases its estimates on historical experience and on various other assumptions it believes to be reasonable under the circumstances. Although actual results may differ from these estimates under different assumptions or conditions, the company believes that its estimates are reasonable and that actual results will not vary significantly from the estimated amounts. The company believes the following accounting policies and estimates are critical in the preparation of its consolidated financial statements: the carrying value of its oil and gas properties, the accounting for oil and gas reserves, and the estimate of its asset retirement obligations.

OIL AND GAS PROPERTIES. The company uses the full cost method of accounting for costs related to its oil and gas properties. Capitalized costs included in the full cost pool are depleted on an aggregate basis using the units-of-production method. Depreciation, depletion and amortization is a significant component of oil and gas properties. A reduction in proved reserves without a corresponding reduction in capitalized costs will cause the depletion rate to increase.

Both the volume of proved reserves and any estimated future expenditures used for the depletion calculation are based on estimates such as those described under “Oil and Gas Reserves” below.

The capitalized costs in the full cost pool are subject to a quarterly ceiling test that limits such pooled costs to the aggregate of the present value of future net revenues attributable to proved oil and gas reserves discounted at 10 percent plus the lower of cost or market value of unproved properties less any associated tax effects. If such capitalized costs exceed the ceiling, the company will record a write-down to the extent of such excess as a non-cash charge to earnings. Any such write-down will reduce earnings in the period of occurrence and result in lower depreciation and depletion in future periods. A write-down may not be reversed in future periods, even though higher oil and gas prices may subsequently increase the ceiling.

The company has made only one ceiling write-down in its 27-year history. That write down was made in 1986 after oil prices fell 51% and gas prices fell 45% between fiscal year end 1985 and 1986.

Changes in oil and gas prices have historically had the most significant impact on the company’s ceiling test. In general, the ceiling is lower when prices are lower. Even though oil and gas prices can be highly volatile over weeks and even days, the ceiling calculation dictates that prices in effect as of the last day of the test period be used and held constant. The resulting valuation is a snapshot as of that day and, thus, is generally not indicative of a true fair value that would be placed on the company’s reserves by the company or by an independent third party. Therefore, the future net revenues associated with the estimated proved reserves are not based on the company’s assessment of future prices or costs, but rather are based on prices and costs in effect as of the end of the test period.

OIL AND GAS RESERVES. The determination of depreciation and depletion expense as well as ceiling test write-downs, if any, related to the recorded value of the company’s oil and gas properties are highly dependent on the estimates of the proved oil and gas reserves. Oil and gas reserves include proved reserves that represent estimated quantities of crude oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. There are numerous uncertainties inherent in estimating oil and gas reserves and their values, including many factors beyond the company’s control. Accordingly, reserve estimates are often different from the quantities of oil and gas ultimately recovered and the corresponding lifting costs associated with the recovery of these reserves.

At October 31, 2004, the date of the company’s most recent reserve report, the company’s reserves, and reserve values, were concentrated in 43 properties (“Significant Properties”). Some of the Significant Properties were individual wells and others were multi-well properties. The Significant Properties represent 24% of the company’s total properties but a disproportionate 75% of the discounted value (at 10%) of the company’s reserves. Individual wells on which the company’s patented liquid lift system is installed comprised 26% of the Significant Properties and represented 37% of the discounted reserve value of such properties. At October 31, 2004, relatively new wells comprised 30% of the Significant Properties and represented 30% of the discounted value of such properties.

Estimates of reserve quantities and values for certain Significant Properties must be viewed as being subject to significant change as more data about the properties becomes available. Such properties include wells with limited production histories and properties with proved undeveloped or proved non-producing reserves. In addition, the company’s patented liquid lift system is generally installed on mature wells. As such, they contain older down-hole equipment that is more subject to failure than new equipment. The failure of such equipment, particularly casing, can result in complete loss of a well. Historically, performance of the company’s wells has not caused significant revisions in its proved reserves.

Price changes will affect the economic lives of oil and gas properties and, therefore, price changes may cause reserve revisions. Price changes have not caused significant proved reserve revisions by the company except in 1986 when a 51% decline in oil prices and a 45% decline in gas prices resulted in an 8.7% reduction in estimated proved reserves. Based upon this historical experience, the company does not believe its reserve estimates are particularly sensitive to prices changes within historical ranges.

One measure of the life of the company’s proved reserves can be calculated by dividing proved reserves at a fiscal year end by production for that fiscal year. This measure yields an average reserve life of nine years. Since this measure is an average, by definition, some of the company’s properties will have a life shorter than the average and some will have a life longer than the average. The expected economic lives of the company’s properties may vary widely depending on, among other things, the size and quality, natural gas and oil prices, possible curtailments in consumption by purchasers, and changes in governmental regulations or taxation. As a result, the company’s actual future net cash flows from proved reserves could be materially different from its estimates.

The company is not aware of any material adverse issues related to its reserves regarding regulatory approval, the availability of additional development capital, or the installation of additional infrastructure.

ASSET RETIREMENT OBLIGATIONS. Statement of Financial Accounting Standards (“SFAS”) No. 143, “Accounting for Asset Retirement Obligations” requires that the company estimate the future cost of asset retirement obligations, discount that cost to its present value, and record a corresponding asset and liability in its Consolidated Balance Sheets. The values ultimately derived are based on many significant estimates, including future abandonment costs, inflation, market risk premiums, useful life, and cost of capital. The nature of these estimates requires the company to make judgments based on historical experience and future expectations. Revisions to the estimates may be required based on such things as changes to cost estimates or the timing of future cash outlays. Any such changes that result in upward or downward revisions in the estimated obligation will result in an adjustment to the related capitalized asset and corresponding liability on a prospective basis.

		July 31,				October 31,
		2005				2004
Asset retirement obligation beginning of period		$	748,000			$	238,000
Accretion expense			25,000				(10,000	)
Obligations incurred			44,000				23,000
Obligations settled			(45,000	)			(6,000	)
Change in estimate			90,000				503,000
Asset retirement obligation end of period		$	862,000			$	748,000

REVENUE RECOGNITION. The company derives its revenue primarily from the sale of produced natural gas and crude oil. The company reports revenue gross for the amounts received before taking into account production taxes and transportation costs which are reported as separate expenses. Revenue is recorded in the month production is delivered to the purchaser at which time title changes hands. The company makes estimates of the amount of production delivered to purchasers and the prices it will receive. The company uses its knowledge of its properties; their historical performance; the anticipated effect of weather conditions during the month of production; NYMEX and local spot market prices; and other factors as the basis for these estimates. Variances between estimates and the actual amounts received are recorded when payment is received.

A majority of the company’s sales are made under contractual arrangements with terms that are considered to be usual and customary in the oil and gas industry. The contracts are for periods of up to five years with prices determined based upon a percentage of a pre-determined and published monthly index price. The terms of these contracts have not had an effect on how the company recognizes its revenue.

The company’s operating revenue is comprised of contractually based payments made to the company, as operator, to drill and supervise oil and gas wells. The company reports these revenues gross for the amounts received before taking into account related costs which are recorded as separate expenses. Revenue is recorded in the month it is earned. The company views providing these services as a way to control the operations on wells in which it owns an interest.

3. STOCK-BASED COMPENSATION

In December 2002, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 148, “Accounting for Stock-Based Compensation — Transition and Disclosure, an amendment of SFAS No. 123.” Among other provisions, the statement amends the disclosure requirements of SFAS No. 123, “Accounting for Stock-Based Compensation.” Under current accounting rules the company elected to account for its stock-based employee compensation under the intrinsic value method established by Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees.”

If compensation expense had been determined in accordance with the provisions of SFAS No. 123, the company’s net income and net income per share of common stock would have been reported as follows:

		Nine Months Ended								Three Months Ended
		July 31,								July 31,
		2005				2004				2005				2004
Net income as reported		$	3,501,000			$	2,757,000			$	1,412,000			$	806,000
Fair value of stock-based compensation, net of tax			(156,000	)			(212,000	)			(50,000	)			(71,000	)
Pro forma net income		$	3,345,000			$	2,545,000			$	1,362,000			$	735,000
Net income per share of common stock, basic:
As reported		$	0.58			$	0.46			$	0.23			$	0.14
Pro forma		$	0.55			$	0.42			$	0.22			$	0.12
Net income per share of common stock, diluted:
As reported		$	0.56			$	0.45			$	0.22			$	0.13
Pro forma		$	0.54			$	0.41			$	0.22			$	0.12

4. NATURAL GAS PRICE HEDGING

The company periodically hedges the price of a portion of its estimated natural gas production when the potential for significant downward price movement is anticipated. Hedging transactions typically take the form of forward short positions and collars on the NYMEX futures market, and are closed by purchasing offsetting positions. Such hedges, which are accounted for as cash flow hedges, do not exceed estimated production volumes, are expected to have reasonable correlation between price movements in the futures market and the cash markets where the company’s production is located, and are authorized by the company’s Board of Directors. Hedges are expected to be closed as related production occurs but may be closed earlier if the anticipated downward price movement occurs or if the company believes that the potential for such movement has abated.

The company recognizes all derivatives on the balance sheet at fair value at the end of each period. Changes in the fair value of a cash flow hedge are recorded in Stockholders’ Equity as Accumulated Other Comprehensive Loss on the Consolidated Balance Sheets and then are reclassified into the Consolidated Statement of Earnings as the underlying hedged item affects earnings. Amounts reclassified into earnings related to natural gas hedges are included in oil and gas sales.

Hedging gains and losses are recognized as adjustments to gas sales as the hedged product is produced. The company had after tax hedging losses of $207,000 in the first nine months of 2005 and after tax hedging losses of $350,000 for the same period in 2004. Any hedge ineffectiveness is immediately recognized in gas sales. Subsequent to the end of the third fiscal quarter, the company closed its August and September contracts for 200 MMbtu with an after tax hedging loss of $308,000. The company’s current open hedge position is 120 MMbtu covering the months of December 2005 and January 2006. These hedging contracts represent approximately 30% of the company’s estimated gas equivalent production for December 2005 and January 2006. December 2005 and January 2006 hedges are collars with a weighted average floor price of $7.00 and a weighted average ceiling price of $8.68 totaling 60 MMbtu in each month.

The company has a hedging line of credit with its bank which is available, at the discretion of the company, to meet margin calls. To date, the company has not used this facility and maintains it only as a precaution related to possible margin calls. The maximum credit line is $2,000,000 with interest calculated at the prime

rate. The facility is unsecured and requires the company to maintain $3,000,000 in cash or short term investments and prohibits unfunded debt in excess of $500,000. It expires on October 31, 2006.

5. COMPREHENSIVE INCOME

Comprehensive income includes all changes in equity during a period except those resulting from investments by owners and distributions to owners. The components of comprehensive income for the three and nine months ended July 31, 2005 and 2004 are as follows:

		Nine Months Ended								Three Months Ended
		July 31,								July 31,
		2005				2004				2005				2004
Net income		$	3,501,000			$	2,757,000			$	1,412,000			$	806,000
Other comprehensive income:
Change in fair value of derivatives			567,000				(617,000	)			7,000				275,000
Income tax (expense) benefit			(166,000	)			173,000				(2,000	)			(77,000	)
Total comprehensive income		$	3,902,000			$	2,313,000			$	1,417,000			$	1,004,000

6. EARNINGS PER SHARE

The company’s calculation of earnings per share of common stock is as follows:

		Nine Months Ended July 31,
		2005												2004
										Net												Net
		Net								Income				Net								Income
		Income				Shares				Per Share				Income				Shares				Per Share
Basic earnings per share		$	3,501,000				6,046,000			$	.58			$	2,757,000				6,020,000			$	.46
Effect of dilutive shares of common stock from stock options			—				175,000				(.02	)			—				166,000				(.01	)
Diluted earnings per share		$	3,501,000				6,221,000			$	.56			$	2,757,000				6,186,000			$	.45

		Three Months Ended July 31,
		2005												2004
										Net												Net
		Net								Income				Net								Income
		Income				Shares				Per Share				Income				Shares				Per Share
Basic earnings per share		$	1,412,000				6,058,000			$	.23			$	806,000				6,038,000			$	.14
Effect of dilutive shares of common stock from stock options			—				168,000				(.01	)			—				184,000				(.01	)
Diluted earnings per share		$	1,412,000				6,226,000			$	.22			$	806,000				6,222,000			$	.13

7. INCOME TAXES

The company uses the asset and liability method of accounting for deferred income taxes. Deferred tax assets and liabilities are determined based on the temporary differences between the financial statement and tax basis of assets and liabilities. Deferred tax assets or liabilities at the end of each period are determined using the tax rate in effect at that time.

The total future deferred income tax liability is extremely complicated for any energy company to estimate due in part to the long-lived nature of depleting oil and gas reserves and variables such as product prices. Accordingly, the liability is subject to continual recalculation, revision of the numerous estimates required, and may change significantly in the event of such things as major acquisitions, divestitures, product price changes, changes in reserve estimates, changes in reserve lives, and changes in tax rates or tax laws.

8. COMMITMENTS

Effective January 1, 2005, the company entered into an exploration agreement to generate and market gas drilling prospects in South Texas. The agreement commits the company to spend a maximum of $1,500,000 over two years primarily for seismic, leases and administrative costs. Through July 31, 2005, the company has made payments of $525,000 towards this commitment. Until the entire venture pays out, the company owns 75% of each generated prospect before payout and will own 37.5% after payout. Upon payout of the venture, the company will own 37.5% of the venture and all generated prospects. Drilling of generated prospects is not covered by the agreement. The company’s drilling cost, if any, will depend upon its election to participate with, or sell, all or a portion of its interest in any prospect generated.

In April 2005, the company committed approximately $1,000,000 over an expected two-year period to purchase a 25% interest in 15,000 gross acres along the Central Kansas Uplift, in Graham and Sheridan counties, Kansas, participate in a 3-D seismic survey, and drill five exploratory wells. Through July 31, 2005, the company has made payments of $502,000 towards this commitment. Subsequent drilling will be determined by results from the initial wells. Approximately 25 square miles of proprietary 3-D seismic will be shot to define Lansing-Kansas City oil prospects at about 4,000 feet.

9. SUBSEQUENT EVENTS

On September 13, 2005, the company announced that its Board of Directors approved a three-for-two split of the company’s common stock. Shareholders of record as of the close of business on September 26, 2005 will be issued a certificate representing one additional share of the company’s common stock for each two shares of common stock held as of that date. The stock split will increase the number of shares of common stock outstanding to approximately 9.1 million shares.

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

FORWARD-LOOKING STATEMENTS

Certain information included in this quarterly report and other materials filed by the company with the Commission contain 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. These statements relate to the company’s operations and the oil and gas industry, in general. Such forward-looking statements are based on management’s current projections and estimates and are identified by words such as “expects,” “intends,” “plans,” “projects,” “anticipates,” “believes,” “estimates” and similar words. These statements are not guarantees of future performance and involve certain risks, uncertainties and assumptions that are difficult to predict. Therefore, actual results may differ materially from what is expressed or forecasted in such forward-looking statements. Among many factors that could cause actual results to differ materially are:

(i) natural gas and crude oil price fluctuations, (ii) the company’s ability to acquire oil and gas properties that meet its objectives and to identify prospects for drilling, and (iii) potential delays or failure to achieve expected production from existing and future exploration and development projects. In addition, such forward-looking statements may be affected by general domestic and international economic and political conditions.

LIQUIDITY AND CAPITAL RESOURCES

At July 31, 2005, working capital was $7,690,000, compared to $6,942,000 at July 31, 2004. For the nine months ended July 31, 2005, net cash provided by operating activities increased $1,811,000, or 51% to $5,341,000 when compared to net cash provided by operating activities of $3,530,000 for the same period in 2004. This increase is primarily the result of increases in net income and other non-cash items of $1,522,000; a net decrease of $859,000 in short term investments in 2005 versus a net increase in short term investments of $1,340,000 in 2004 which resulted in a net increase of $2,199,000 between the two periods; a net decrease in cash as a result of changes in accrued oil and gas sales, trade receivables and other current assets of $517,000; and a net decrease in cash as a result of changes in accounts payable and income taxes payable of $1,393,000. For the nine months ended July 31, 2005 and 2004, net cash used in investing activities was $5,144,000 and $4,368,000, respectively. Investing activities primarily included oil and gas exploration and development expenditures, including Calliope, totaling $5,064,000 and $3,980,000, respectively.

The average return on the company’s investments for the nine months ended July 31, 2005 and 2004 was 3.1% and 5.0%, respectively. At July 31, 2005, approximately 52% of the investments were directly invested in mutual funds and were managed by professional money managers. Remaining investments are in managed partnerships that use various strategies to minimize their correlation to stock market movements. Most of the investments are highly liquid and the company believes they represent a responsible approach to cash management. In the company’s opinion, the greatest investment risk is the potential for negative market impact from unexpected, major adverse news, such as the September 11th terrorist attacks.

Existing working capital and anticipated cash flow are expected to be sufficient to fund operations and capital commitments for at least the next 12 months. As discussed in Note 8 to the consolidated financial statements, at July 31, 2005 the company had remaining commitments of $1,473,000 related to projects in South Texas and along the Central Kansas uplift. Such costs are expected to be funded over the next 15 to 17 months. At July 31, 2005, the company had no lines of credit or other bank financing arrangements except for the hedging line of credit discussed in Note 4. Because earnings are anticipated to be reinvested in operations, cash dividends are not expected to be paid. The company has no defined benefit plans and no obligations for post retirement employee benefits.

PRODUCT PRICES AND PRODUCTION

Although product prices are key to the company’s ability to operate profitably and to budget capital expenditures, they are beyond the company’s control and are difficult to predict. Since 1991, the company has periodically hedged natural gas prices by forward selling a portion of its estimated production in the NYMEX futures market typically in the form of forward short positions and collars. This is generally done when (i) the price relationship (the “basis”) between the futures markets and the cash markets where the company sells its gas is stable within historical ranges, and (ii) in the company’s opinion, the current price is adequate to insure reasonable returns at a time when downside price risks appear to be substantial. The company closes its hedges by purchasing offsetting positions in the futures market at then prevailing prices. Accordingly, the gain or loss on the hedge position will depend on futures prices at the time offsetting positions are purchased. Hedging gains and losses are included in revenues from oil and gas sales. The company believes its most significant hedging risk is that expected correlations in price movements as discussed above do not occur, and thus, that gains or losses in one market are not fully offset by opposite moves in the other market.

As more fully described in Note 4, the company currently has open hedge positions in the months of December 2005 and January 2006. The positions consist of “collars” totaling 120 MMbtu with a weighted

average floor price of $7.00 and a ceiling price of $8.68. The hedge covers approximately 30% of the company’s estimated gas equivalent production for these months. All prices are NYMEX basis. Subsequent to the end of the third fiscal quarter, the company closed its August and September contracts for 200 MMbtu at an after tax loss of $308,000. Average gas prices in the company’s market areas are expected to be 15% to 17% below NYMEX prices due to basis differentials and transportation costs.

Gas and oil sales volume and price realization comparisons for the indicated periods are set forth below. Price realizations include the sales price and hedging gains and losses.

		Nine Months Ended July 31,
		2005								2004								% Change
Product		Volume				Price				Volume				Price				Volume				Price
Gas (Mcf)			1,311,000			$	5.70	(1)			1,278,000			$	4.58	(3)			+3	%			+24	%
Oil (bbls)			27,700			$	47.37				32,900			$	32.66				-16	%			+45	%

		Three Months Ended July 31,
		2005								2004								% Change
Product		Volume				Price				Volume				Price				Volume				Price
Gas (Mcf)			469,000			$	6.25	(2)			417,000			$	4.37	(4)			+13	%			+43	%
Oil (bbls)			8,200			$	56.21				11,700			$	34.63				-30	%			+62	%

OPERATIONS

The company’s business focuses on two core projects—natural gas drilling and application of its patented Calliope Gas Recovery System. The company has recently expanded into South Texas through an exploration program using 3-D seismic to define the Vicksburg and Frio prospects in Hidalgo, Jim Hogg and Star counties and into north-central Kansas through an exploration program using 3-D seismic to define Lansing-Kansas City oil prospects in Graham and Sheridan counties. In combination, its drilling and Calliope projects provide an excellent (and possibly unique) balance for achieving its goal of adding long-lived gas reserves and production at reasonable costs and risks.

The company will continue to actively pursue adding reserves through its two core projects in fiscal 2005 and expects these activities to be the primary source of its reserve additions. However, the timing and extent of such activities can be dependent on many factors which are beyond the company’s control, including but not limited to, the availability of oil field services such as drilling rigs, production equipment and related services and access to wells for application of the company’s patented liquid lift system on low pressure gas wells. The prevailing price of oil and gas has a significant affect on demand and, thus, the related cost of such services and wells.

Drilling Activities . The company currently drills primarily on its 40,000 gross acre inventory located along the shelf of the Northern Anadarko Basin in Oklahoma. The company has completed eight consecutive wells as producers. The wells, which ranged from development to rank wildcat, are located on five different prospects.

During the first nine months of 2005, the company drilled 10 wells in Oklahoma with working interests ranging up to 69%. Eight of these wells have been completed as producers and two were dry holes. Drilling expenditures were concentrated on the company’s acreage inventory located along the northern shelf of the

Anadarko Basin of Oklahoma. The wells targeted the Morrow, Oswego and Chester formations between 7,000 and 9,200 feet. A substantial number of additional wells are anticipated for the area, including approximately three wells scheduled for the remainder of this fiscal year.

Drilling is not restricted to the company’s inventory located along the northern Anadarko shelf acreage. The company is generating prospects elsewhere in the Northern Anadarko Basin, in the Oklahoma Panhandle, north-central Oklahoma, north-central Kansas and South Texas. In addition, 16 coal bed methane wells were drilled on acreage in Wyoming where the company owns working interests of approximately 10%, and 134 coal bed methane wells were drilled on Wyoming acreage where the company owns small royalty interests.

A series of three wells were recently drilled in Harper and Ellis Counties, Oklahoma, all of which have been completed for production. These wells are located on the company’s 5,120 gross acre Glacier Prospect, the 2,560 gross acre Buffalo Creek prospect and the 14,000 gross acre Sand Creek Prospect. The company is the operator of these wells with working interests ranging from 25% to 57%. Production is expected to begin on all three wells during September 2005.

Three to four additional wells are expected to be drilled before calendar year-end on the Glacier, Buffalo Creek and Sand Creek Prospects.

This year the company significantly expanded both the volume and breadth of its exploration program with new projects in South Texas and north-central Kansas. It is the company’s intention to diversify its exploration geographically, scientifically, and in terms of capital, risk and reserve potential. Compared to drilling in Oklahoma, the South Texas project involves higher costs and greater risks but significantly higher per well reserve potential. The north-central Kansas project is geared to oil exploration and has excellent potential to add significant reserves at moderate costs and risks. Both projects are in areas where 3-D seismic is a proven exploration tool and where continuing refinements are providing excellent exploration success. Equally as important, both exploration teams specialize in their respective geographic areas and have been highly successful finding new reserves using 3-D seismic.

As previously discussed, drilling of generated South Texas prospects is not covered by the exploration agreement and, therefore, is not a commitment under the exploration agreement. Drilling is expected to commence late in 2005. The initial three well drilling program will be located in Hidalgo County and wells will range in depth from 10,200 to 15,500 feet with an estimated total cost (8\8ths basis) of $10,000,000 to $12,000,000. The company is currently evaluating what portion of its 37.5% after payout interest to retain for direct participation.

The north-central Kansas project agreement provides for five exploratory wells to be drilled as part of the initial commitment. Drilling will commence after new 3-D seismic shooting and interpretation is completed, which is expected in mid-2006. See Note 8 for additional information regarding the company’s commitments to these two exploration projects.

All of the company’s oil and gas properties are located on-shore in the continental United States. The company’s future drilling activities may not be successful, and its overall drilling success rate may change. Unsuccessful drilling activities could have a material adverse effect on the company’s results of operations and financial condition. Also, the company may not be able to obtain the right to drill in areas where it believes there is significant potential for the company.

Calliope Gas Recovery Technology. The company owns the exclusive right to a patented technology known as the Calliope Gas Recovery System. Calliope can achieve substantially lower flowing bottom hole pressure than conventional production methods because it does not rely on reservoir pressure to lift liquids. In many gas wells, lower bottom hole pressure translates into recovery of substantial additional gas reserves.

Calliope has proven to be reliable and flexible over a wide range of applications on wells the company owns and operates. It has also proven to be consistently successful. Accordingly, the company has recently begun implementing strategies designed to widen the envelope of wells on which Calliope should be installed.

The Calliope segment of the company’s business is currently focused on two areas: increasing the number of Calliope installations through joint ventures with larger companies that own Calliope candidate wells, and expanding the company’s effort to directly purchase Calliope candidate wells from third parties.

In the joint venture area, Calliope has been presented to a range of companies, including majors and large independents. All of the companies have expressed a keen interest in the technology and further discussions are currently ongoing. Joint venture discussions are in various stages with several of these companies, including evaluation of candidate wells and discussion of commercial terms.

In addition to joint ventures, the company has expanded its effort to acquire Calliope candidate wells into Texas and Louisiana. This effort is being spearheaded on a full-time basis by a highly qualified petroleum engineer based in Houston.

As part of its Calliope effort in Texas, the company has recently acquired wells that are in various stages of evaluation for Calliope installations. Testing has been completed on the previously reported Adolfo Trevino well and the company has determined that this well is not a Calliope candidate.

In southwest Texas, the company recently purchased two Calliope candidate wells. These 11,700-foot wells have produced 3.0 Bcf and 65,000 barrels of oil and 5.4 Bcf and 158,000 barrels of oil, and are currently uneconomic. Initial testing indicates they are good Calliope candidates, with installations expected in October. The company owns a 59% working interest and is the operator.

In western Oklahoma, the company has fracture stimulated and completed evaluation of the 18,700-foot Wallace well for a Calliope installation. A casing leak had previously been repaired. The well has produced 25 Bcf and is currently dead. A Calliope installation is scheduled for September. The company owns an 87.5% working interest and is the operator.

Results of Operations

Nine Months Ended July 31, 2005 Compared to Nine Months Ended July 31, 2004

For the nine months ended July 31, 2005, total revenues increased 25% to $9,473,000 compared to $7,562,000 last year. As the oil and gas price/volume table on page 14 shows, total gas price realizations, which reflect hedging transactions, increased 24% to $5.70 per Mcf and oil price realizations increased 45% to $47.37 per barrel. The net effect of these price changes was to increase oil and gas sales by $1,853,000. For the nine months ended July 31, 2005, the company’s gas equivalent production increased slightly. Operating income increased 10% due to an increase in drilling and production supervision income related to operated wells. Investment and other income increased 8% primarily due to an increase in other income.

For the nine months ended July 31, 2005, total costs and expenses rose 24% to $4,610,000 compared to $3,732,000 for last year. Oil and gas production expenses increased 31% due primarily to new wells. Depreciation, depletion and amortization (“DD&A”) increased 31% primarily due to an increase in the amortizable full cost pool. General and administrative expenses increased 4% primarily due to increases in professional fees and salaries and benefit costs related primarily to increased administration resulting from rapid growth, transition from small business SEC reporting status to full reporting status, compliance with Sarbanes-Oxley regulations and preparation for accelerated filing requirements related to the company’s quarterly and annual SEC reports. Interest expense relates to the exclusive license agreement note payment. The effective tax rate was 28% for the 2005 and 2004 periods.

Three Months Ended July 31, 2005 Compared to Three Months Ended July 31, 2004

For the three months ended July 31, 2005, total revenues increased 50% to $3,665,000 compared to $2,439,000 for last year. As the oil and gas price/volume table on page 14 shows, total gas price realizations, which reflect hedging transactions, increased 43% to $6.25 per Mcf and oil price realizations increased 62% to $56.21 per barrel. The net effect of these price changes was to increase oil and gas sales by $1,038,000. For the three months ended July 31, 2005, the company’s gas equivalent production increased 6% resulting in an oil and gas sales increase of $132,000. Operating income rose 8% due to drilling and production supervision income related to operated wells. Investment and other income increased 72% primarily due to changes in market conditions and an increase in other income.

For the three months ended July 31, 2005, total costs and expenses rose 29% to $1,704,000 compared to $1,319,000 for the comparable period in 2004. Oil and gas production expenses increased 48% due primarily to new wells. DD&A rose 30% primarily due to an increase in the amortizable full cost pool and increased production. General and administrative expenses decreased 2% primarily due to an increase in allocable overhead. Interest expense relates to the exclusive license agreement note payment. The effective tax rate was 28% for the 2005 and 2004 periods.

the third fiscal quarter of 2005 that materially affected or were reasonably likely to materially affect, its internal control over financial reporting.

Exhibit Index

Exhibits are as follow:

	31.1		Certification by Chief Executive Officer under Section 302 of the Sarbanes-Oxley Act of 2002
	31.2		Certification by Chief Financial Officer under Section 302 of the Sarbanes-Oxley Act of 2002
	32.1		Certification by Chief Executive Officer and Chief Financial Officer under Section 906 of the Sarbanes-Oxley Act (18 U.S.C. Section 1350)