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 January 31, 2007

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

For the transition period from                      to                     

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)

(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 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 Act.)

Large accelerated filer o       Accelerated filer þ       Non-accelerated filer o

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
March 12, 2007		Common stock, $.10 par value		9,261,000

 

 

CREDO PETROLEUM CORPORATION AND SUBSIDIARIES

Quarterly Report on Form 10-Q For the Period Ended January 31, 2007

TABLE OF CONTENTS

		Page No.
PART I — FINANCIAL INFORMATION
Item 1. Financial Statements
Consolidated Balance Sheets As of January 31, 2007 (Unaudited) and October 31, 2006			3
Consolidated Statements of Operations For the Three Months Ended January 31, 2007 and 2006 (Unaudited)			4
Consolidated Statement of Stockholders’ Equity and Comprehensive Income For the Three Months Ended January 31, 2007 (Unaudited)			5
Consolidated Statements of Cash Flows For the Three Months Ended January 31, 2007 and 2006 (Unaudited)			6
Notes to Consolidated Financial Statements (Unaudited)			7
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			10
Item 3. Quantitative and Qualitative Disclosures About Market Risk			19
Item 4. Controls and Procedures			19
PART II — OTHER INFORMATION
Item 1. Legal Proceedings			19
Item 1A. Risk Factors			19
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			19
Item 3. Defaults Upon Senior Securities			19
Item 4. Submission of Matters to a Vote of Security Holders			20
Item 5. Other Information			20
Item 6. Exhibits			20
Signatures			21
Certification by Chief Executive Officer
Certification by Chief Financial Officer
Certification by CEO and 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

		January 31,				October 31,
		2007				2006
		(Unaudited)
ASSETS
Current Assets:
Cash and cash equivalents		$	3,055,000			$	4,577,000
Short-term investments			6,136,000				5,624,000
Receivables:
Accrued oil and gas sales			1,656,000				777,000
Trade			1,143,000				1,963,000
Derivative Assets			526,000				897,000
Other current assets			240,000				71,000
Total current assets			12,756,000				13,909,000
Long-term assets:
Oil and gas properties, at cost, using full cost method:
Unevaluated oil and gas properties			8,962,000				7,060,000
Evaluated oil and gas properties			44,691,000				43,588,000
Less: accumulated depreciation, depletion and amortization of oil and gas properties			(19,488,000	)			(18,556,000	)
Net oil and gas properties, at cost, using full cost method			34,165,000				32,092,000
Exclusive license agreement, net of amortization of $449,000 in 2007 and $431,000 in 2006			251,000				268,000
Compressor and tubular inventory to be used in development			1,308,000				1,293,000
Other (net)			229,000				197,000
Total assets		$	48,709,000			$	47,759,000
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Accounts payable		$	1,400,000			$	1,581,000
Revenue distribution payable			1,122,000				1,273,000
Other accrued liabilities			510,000				808,000
Income taxes payable			273,000				174,000
Total current liabilities			3,305,000				3,836,000
Long Term Liabilities:
Deferred income taxes, net			8,367,000				8,039,000
Exclusive license obligation, less current obligations of $70,000 in 2007 and 2006			163,000				163,000
Asset retirement obligation			957,000				954,000
Total liabilities			12,792,000				12,992,000
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, 9,510,000 shares issued in 2007 and 2006			951,000				951,000
Capital in excess of par value			14,851,000				14,794,000
Treasury stock at cost, 249,000 shares in 2007 and 2006			—				—
Accumulated other comprehensive income (loss)			379,000				650,000
Retained earnings			19,736,000				18,372,000
Total stockholders’ equity			35,917,000				34,767,000
Total liabilities and stockholders’ equity		$	48,709,000			$	47,759,000

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

CREDO PETROLEUM CORPORATION AND SUBSIDIARIES

		Three Months Ended
		January 31,
		2007				2006
REVENUES:
Oil and gas sales		$	3,808,000			$	4,120,000
Investment income and other			247,000				245,000
			4,055,000				4,365,000
COSTS AND EXPENSES:
Oil and gas production			913,000				1,004,000
Depreciation, depletion and amortization			958,000				738,000
General and administrative			278,000				260,000
Interest			6,000				9,000
			2,155,000				2,011,000
INCOME BEFORE INCOME TAXES			1,900,000				2.354,000
INCOME TAXES			(536,000	)			(659,000	)
NET INCOME		$	1,364,000			$	1,695,000
EARNINGS PER SHARE OF COMMON STOCK BASIC		$	.15			$	.19
EARNINGS PER SHARE OF COMMON STOCK DILUTED		$	.15			$	.18
Weighted average number of shares of Common Stock and dilutive securities:
Basic			9,261,000				9,137,000
Diluted			9,387,000				9,475,000

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

CREDO PETROLEUM CORPORATION AND SUBSIDIARIES

(Unaudited)
For the Three Months Ended January 31, 2007

																		Accumulated
										Capital In								Other												Total
		Common Stock								Excess Of				Treasury				Comprehensive				Comprehensive				Retained				Stockholders’
		Shares				Amount				Par Value				Stock				Income				Income				Earnings				Equity
Balance, October 31, 2006			9,510,000			$	951,000			$	14,794,000			$	—			$	650,000							$	18,372,000			$	34,767,000
Comprehensive income:
Net income			—				—				—				—				—			$	1,364,000				1,364,000				1,364,000
Other comprehensive income:
Change in fair value of derivatives, net of tax			—				—				—				—				(271,000	)			(271,000	)			—				(271,000	)
Total comprehensive income			—				—				—				—				—			$	1,093,000				—				—
Compensation expense associated with unvested portion of previously granted stock options			—				—				57,000				—				—								—				57,000
Balance, January 31, 2007			9,510,000			$	951,000			$	14,851,000			$	—			$	379,000							$	19,736,000			$	35,917,000

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

CREDO PETROLEUM CORPORATION AND SUBSIDIARIES

		Three Months Ended
		January 31,
		2007				2006
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income		$	1,364,000			$	1,695,000
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization			958,000				738,000
Deferred income taxes			328,000				417,000
Compensation expense related to stock options granted			57,000				60,000
Other			3,000				—
Changes in operating assets and liabilities:
Proceeds from short-term investments			719,000				193,000
Purchase of short-term investments			(1,231,000	)			(404,000	)
Accrued oil and gas sales			307,000				422,000
Trade receivables			(367,000	)			(702,000	)
Other current assets			(69,000	)			318,000
Accounts payable and accrued liabilities			(629,000	)			1,343,000
Income taxes payable			99,000				89,000
NET CASH PROVIDED BY OPERATING ACTIVITIES			1,539,000				4,169,000
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas properties			(3,005,000	)			(3,539,000	)
Proceeds from sale of oil and gas properties			—				146,000
Changes in other long-term assets			(56,000	)			172,000
NET CASH USED IN INVESTING ACTIVITIES			(3,061,000	)			(3,221,000	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from exercise of stock options			—				272,000
NET CASH PROVIDED BY FINANCING ACTIVITIES			—				272,000
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS			(1,522,000	)			1,220,000
CASH AND CASH EQUIVALENTS:
Beginning of period			4,577,000				1,935,000
End of period		$	3,055,000			$	3,155,000
Supplemental cash flow information:
Cash paid during the period for income taxes		$	—			$	240,000
Cash paid during the period for interest		$	—			$	—

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

CREDO PETROLEUM CORPORATION AND SUBSIDIARIES

1. BASIS OF PRESENTATION

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 Annual Report on Form 10-K for the fiscal year ended October 31, 2006.

Certain financial statement amounts have been reclassified to conform to the presentation used for the 2007 periods. Effective with the second quarter of 2006, the company has reclassified reimbursed overhead from operating revenue to general and administrative expense. For the three months ended January 31, 2007 and 2006, the reclassified amounts were $186,000 and $173,000, respectively.

2. SIGNIFICANT ACCOUNTING POLICIES

The preparation of financial statements in conformity with generally accepted accounting principles requires management 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 has changed its estimate with respect to estimated salvage value of lease and well equipment. This change in estimate resulted in a decrease in depreciation, depletion and amortization of approximately $65,000 for the quarter ended January 31, 2007.

3. STOCK-BASED COMPENSATION

The company currently has one stock-based employee compensation plan, the CREDO Petroleum Corporation 1997 Stock Option Plan (the 1997 Plan) which is described in the Notes to Consolidated Financial Statements in the company’s Annual Report on Form 10-K for the year ended October 31, 2006. This Plan will expire on July 29, 2007. The CREDO Petroleum Corporation 2007 Stock Option Plan (the 2007 Plan), which is similar in all respects to the 1997 Plan has been proposed to the shareholders for approval at the Annual Meeting of Shareholders on March 22, 2007. If the 2007 Plan is approved, no additional options will be granted under the 1997 Plan. However, all outstanding options granted under the 1997 Plan will continue to be governed by the rules of the 1997 Plan. Effective November 1, 2005, the company adopted the fair value recognition provisions of SFAS No. 123 (R), Share Based Payment, using the modified-retrospective-transition method. Under this transition method, the company restated the results of all prior periods back to the beginning of fiscal 1997 (the fiscal year of inception for this stock-based compensation plan) in accordance with the original provisions of SFAS No. 123. For the three months ended January 31, 2007 and 2006, the company recognized compensation expense of $57,000 and $60,000, respectively.

No options were granted during fiscal year 2006 and the fair value of the 40,000 options granted during the three months ended January 31, 2007 was estimated as of the grant date using the Black-Scholes option pricing model with the following assumptions: volatility, 50.84%; expected option term, 2 and 3 years; risk-free interest rate, 4.58% and; expected dividend yield, 0%. If option grants are made in the future, compensation expense for all such share-based payments granted, based upon the grant-date fair value estimated in accordance with the provisions of SFAS No. 123(R) will also be included in compensation expense.

Plan activity for the three months ended January 31, 2007 is set forth below.

		Three Months Ended January 31, 2007
						Weighted
						Average
		Number of				Exercise
		Options				Price
Outstanding at October 31, 2006			315,002			$	5.52
Granted			40,000				12.78
Exercised			—				—
Cancelled or forfeited			—				—
Outstanding at January 31, 2007			355,002			$	6.34
Exercisable at January 31, 2007			274,543			$	5.70
Weighted average contractual life at January 31, 2007							6.70

The following table summarizes information about stock options currently outstanding and exercisable at January 31, 2007:

		Outstanding												Exercisable
		Number				Weighted Average				Weighted				Number
Range of		Outstanding				Remaining				Average				Exercisable at				Weighted
Exercise		at January 31,				Contractual				Exercise				January 31,				Average
Prices		2007				Life in Years				Price				2007				Exercise Price
$3.09-$3.72			54,750				5.87			$	3.56				44,625			$	3.52
$5.93-$5.93			260,252				5.54			$	5.93				223,251			$	5.93
$12.78-$12.78			40,000				9.82			$	12.78				6,667			$	12.78
$3.09-$12.78			355,002				6.70			$	6.34				274,543			$	5.70

Total estimated unrecognized compensation cost from unvested stock options as of January 31, 2007 was approximately $219,000, which is expected to be recognized over an average period of approximately 1.44 years.

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 (consisting solely of cash flow hedges) on its 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 Income on the Consolidated Balance Sheets and then are transferred into the Consolidated Statement of Operations as the underlying hedged item affects earnings. Amounts reclassified into earnings related to natural gas hedges are included in oil and gas sales.

Hedges include contracts indexed to the NYMEX and to Panhandle Eastern Pipeline Company for Texas, Oklahoma mainline. For comparative purposes, hedges indexed to Panhandle Eastern Pipeline Company are expressed on a NYMEX basis. For hedges indexed to Panhandle Eastern Pipeline Company, the individual month price (basis) differentials between the NYMEX and Panhandle Eastern Pipeline Company range from minus $1.45 in the winter months to minus $0.90 in the spring months.

Hedging gains and losses are recognized as adjustments to gas sales as the hedged product is produced. The company had hedging gains of $396,000 in first quarter of fiscal 2007, and hedging losses of $265,000 for the same period in 2006. Any hedge ineffectiveness, which was not material for any period is immediately recognized in gas sales.

Realized (February 2007) and unrealized (March 2007 through October 2007) gains on hedge contracts at January 31, 2007 totaled $526,000 and were included in “Accumulated Other Comprehensive Income”. These contracts covered 930 MMBtus at NYMEX basis prices ranging from $7.56 to $8.95.

Subsequent to January 31, 2007, the company entered into additional hedge contracts covering 1,070 MMBtus at NYMEX basis prices ranging from $7.76 to $9.47 and including production months from March 2007 through March 2008.

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 $4,500,000 with interest calculated at the prime rate. The facility is unsecured and has covenants that require the company to maintain $3,000,000 in cash or short term investments, none of which are required to be maintained at the company’s bank, and prohibits unfunded debt in excess of $500,000. It expires on October 31, 2007.

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 months ended January 31, 2007 and 2006 are as follows:

		Three Months Ended
		January 31,
		2007				2006
Net income		$	1,364,000			$	1,695,000
Other comprehensive income:
Change in fair value of derivatives			(371,000	)			425,000
Income tax expense			100,000				(119,000	)
Total comprehensive income		$	1.093,000			$	2,001,000

6. EARNINGS PER SHARE

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

		Three Months Ended January 31,
		2007																2006
										Net																Net
		Net								Income								Net								Income
		Income				Shares				Per Share								Income				Shares				Per Share
Basic earnings per share		$	1,364,000				9,261,000			$	.15							$	1,695,000				9,137,000			$	.19
Effect of dilutive shares of common stock from stock options			—				126,000				(.00	)							—				338,000				(.01	)
Diluted earnings per share		$	1,364,000				9,387,000			$	.15							$	1,695,000				9,475,000			$	.18

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

The company has no material outstanding commitments at January 31, 2007.

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

FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q includes certain statements that may be deemed to be “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. All statements included in this Quarterly Report on Form 10-Q, other than statements of historical facts, address matters that the company reasonably expects, believes or anticipates will or may occur in the future. Forward-looking statements may relate to, among other things:

	•		the company’s future financial position, including working capital and anticipated cash flow;
	•		amounts and nature of future capital expenditures;
	•		operating costs and other expenses;
	•		wells to be drilled or reworked;
	•		oil and natural gas prices and demand;

	•		existing fields, wells and prospects;
	•		diversification of exploration;
	•		estimates of proved oil and natural gas reserves;
	•		reserve potential;
	•		development and drilling potential;
	•		expansion and other development trends in the oil and natural gas industry;
	•		the company’s business strategy;
	•		production of oil and natural gas;
	•		matters related to the Calliope Gas Recovery System;
	•		effects of federal, state and local regulation;
	•		insurance coverage;
	•		employee relations;
	•		investment strategy and risk; and
	•		expansion and growth of the company’s business and operations.

LIQUIDITY AND CAPITAL RESOURCES

At January 31, 2007, working capital increased $1,487,000 or 19% to $9,451,000 compared to $7,964,000 at January 31, 2006. For the three months ended January 31, 2007, net cash provided by operating activities decreased $2,639,000 to $1,530,000 compared to net cash provided by operating activities of $4,169,000 for the same period in 2006. Net income decreased $331,000 primarily due to a decrease in revenues of $310,000, and an increase in depreciation, depletion and amortization (DD&A) of $220,000, net of a $65,000 decrease in DD&A due to an increase in estimated salvage values.

For the three months ended January 31, 2007 and 2006, net cash used in investing activities was $3,061,000 and $3,221,000, respectively. During the first quarter of fiscal 2007 and 2006 investing activities primarily included oil and gas exploration and development expenditures, including Calliope, totaling $3,005,000 and $3,539,000 respectively.

The average return on the company’s investments for the three months ended January 31, 2007 and 2006 was 4.5% and 3.2%, respectively. At January 31, 2007, approximately 57% 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.

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. At January 31, 2007, 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.

The company’s earnings before interest, taxes, depreciation, depletion and amortization, (“EBITDA”) decreased to $2,864,000 for the three months ended January 31, 2007 from $3,101,000 for the three months ended January 31, 2006. EBITDA is not a GAAP measure of operating performance. The company uses this non-GAAP performance measure primarily to compare its performance with other companies in the industry that make a similar disclosure. The company believes that this performance measure may also be useful to investors for the same purpose. Investors should not consider this measure in isolation or as a substitute for operating income, or any other measure for determining the company’s operating performance that is calculated in accordance with GAAP. In addition, because EBITDA is not a GAAP measure, it may not necessarily be comparable to similarly titled measures employed by other companies. A reconciliation between EBITDA and net income is provided in the table below:

		Three Months Ended January,
		2007				2006
RECONCILIATION OF EBITDA:
Net Income		$	1,364,000			$	1,695,000
Add Back:
Interest Expense			6,000				9,000
Income Tax Expense			536,000				659,000
Depreciation, Depletion and Amortization Expense			958,000				738,000
EBITDA		$	2,864,000			$	3,101,000

OFF-BALANCE SHEET FINANCING

The company has no off-balance sheet financing arrangements at January 31, 2007.

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 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, swaps and collars which are executed on the NYMEX futures market or by indexing to regional index prices associated with pipelines in proximity to the company’s production. A portion of the company’s current hedges are indexed to Panhandle Eastern Pipeline Company for Texas, Oklahoma (mainline) (“PEPL”) which serves the regions where the company produces the majority of its gas. Refer to Note 4 of the Consolidated Financial Statements for a complete discussion on the company’s hedging activities.

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.

		Three Months Ended January 31,
		2007								2006								% Change
Product		Volume				Price				Volume				Price				Volume				Price
Gas (Mcf)			528,000			$	6.03	(1)			437,000			$	8.19	(2)			+21	%			-26	%
Oil (bbls)			11,900			$	52.06				9,500			$	56.94				+25	%			- 8	%

OPERATIONS

During the first quarter of fiscal 2007, the company’s operations were focused on its two core projects — natural gas drilling and application of its patented Calliope Gas Recovery System.

As discussed below, the company has expanded into South Texas through an exploration program using 3-D seismic to define the Vicksburg, Frio, Queen City and Wilcox prospects in Hidalgo and Jim Hogg counties. The company has also expanded into north-central Kansas through an exploration program using 3-D seismic to define Lansing-Kansas City oil prospects along the Central Kansas Uplift.

Also as discussed below, the company has expanded its Calliope operations into Texas and Louisiana. The company believes these are fertile areas for Calliope and will continue to expand as opportunities allow. During 2007, the company plans to commence drilling operations on a new project to drill wells into existing reservoirs for the specific purpose of using Calliope to recover stranded gas.

The company believes that, in combination, its drilling and Calliope projects provide an excellent (and possibly unique) balance for achieving its goal of adding long-lived natural gas reserves and production at reasonable costs and risks. However, it should be expected that successful results will occur unevenly for both the drilling and Calliope projects. Drilling results are dependent on both the timing of drilling and on the drilling success rate. Calliope results are primarily dependent on the timing, volume and quality of Calliope installations available to the company.

The company will continue to actively pursue adding reserves through its two core projects in fiscal 2007, and expects these activities to be a reliable source of 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 gas recovery system on low pressure gas wells. The prevailing price of oil and natural gas has a significant effect on demand and, thus, the related cost of such services and wells.

The company is currently experiencing delays in securing drilling rigs and delivery of production equipment, primarily compressors and coil tubing. These delays are extending the time it takes the company to conduct its field operations. As a result, the company could be at risk for price increases related to these types of services and equipment.

Drilling Activities.

Northern Anadarko Basin—The company drills primarily on its significant inventory of acreage (approximately 68,000 gross acres) located along the northern portion of the Anadarko Basin where it has drilled approximately 77 wells. The wells target the Morrow, Oswego and Chester formations between 7,000 and 11,000 feet. The company expects to drill a substantial number of additional wells on this acreage.

During the first quarter of fiscal 2007, the company drilled the ninth well on its 5,760 Glacier Prospect located in Harper and Woodward Counties, Oklahoma. The Carmella State well is an east extension from the high rate Garnet State and Scarlet State wells that were completed last year. The well encountered excellent quality Morrow sands. Initial production rates are in excess of 2.0 million cubic feet of gas per day. The well has been on production for only a few days and is still being lined-out. Accordingly, all well data is very preliminary. The company owns a 72% working interest and is the operator.

The initial test well on the 2,500 gross acre Humphries Prospect located in the Texas Panhandle was drilled in the first quarter of 2007. The 11,200-foot well encountered excellent quality, over-pressured Upper Morrow sands. The well commenced production in February and is currently producing about 330 thousand cubic of gas per day. Initial pressure information indicates that the reservoir is limited in size at the location of the well. However, the well established the presence of high quality Morrow sand on the prospect. The company intends to acquire and reprocess 3-D seismic over the prospect to assess whether the well is separated from a larger reservoir by faulting. Additional acreage is also being acquired in the area and further drilling is expected on the prospect. The company owns a 25% working interest.

The company has completed interpretation of the recent 3-D seismic program over its 3,840 gross acre Buffalo Creek Prospect. To date, six producing wells have been drilled on the prospect. Based on the seismic interpretation, the company has initially identified another four to six drilling locations for the Morrow, Chester and Oswego sands. The company owns varying interest in different portions of the prospect that generally range from 30% to 45%. Additional drilling is expected in the second quarter of fiscal 2007.

An excellent well has been drilled on the 640 gross acre Loosen Prospect located in Canadian County, Oklahoma. The 11,500-foot Hazel well encountered excellent sands in the Redfork and Skinner formations, and is producing approximately 2.5 million cubic of gas per day. The company owns a small overriding royalty interest in the Hazel well but has the right to participate for a 12.5% interest in any offset well.

Drilling Program Expansion and Diversification—During the past two years, 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 significantly 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.

South Texas—The company’s new exploration project in South Texas is 3-D seismic driven and focuses on the Vicksburg, Frio, Queen City and Wilcox sands in Hidalgo and Jim Hogg Counties ranging in depth from 7,500 to 17,000 feet. Both the cost and the potential of this project far exceed any of the company’s previous projects.

In return for a 75% interest before investment payout (calculated on a prospect by prospect basis) and 37.5% interest after investment payout, the company initially committed $1,500,000 for prospect generation and leasing costs. The commitment has been fully funded and all future project funding is at the company’s discretion. The company has the option to participate in drilling each prospect for all, or a portion, of its interest. If the company does not participate for its full interest, the remaining portion will be sold to industry participants on a promoted basis.

The exploration team has generated a significant number of high quality 3-D seismic drilling prospects, and will generate more prospects in the future. Seven prospects have been fully leased and two of those prospects have been drilled.

As previously reported, the company participated for its full 37.5% interest in the first project well which was drilled on the 1,700 gross acre Robertson Prospect in Hidalgo County. Production casing has been set on the 10,500-foot well, and Upper Frio sands have been tested at rates of approximately 1.0 MMcfe per day. However, pressure data indicates that the reservoir may be limited in size. An additional up-hole sand appears on logs to be productive and may be evaluated before a final commercial production decision is made. The well is currently being evaluated for pipeline connection.

A 6,850-foot well has recently been drilled on the 600 gross acre Vela Prospect located in Jim Hogg County, Texas. The well encountered Queen City sands that appear to be productive on electric logs and is currently awaiting completion for production. The company sold its interest in the prospect to third parties in return for cash and a carried interest in the drilling and completion of the well. The company will own an 18% working interest in production from the well before payout and a 9% interest after payout.

Fully leased prospects that are in the process of being sold to third parties include the 800 gross acre Esparza Prospect which targets Marks sands at approximately 12,500 feet, the 2,300 gross acre Sam Houston Prospect which targets Frio sands at approximately 10,500 feet, the 1,200 gross acre West Mestena Prospect which targets Queen City sands at approximately 10,500 feet, the 1,120 gross acre Millennium Prospect which targets Wilcox sands at approximately 15,000, and the 960 gross acre Gemini Prospect which targets Wilcox sands at approximately 17,000 feet. The company expects a number of these prospects to be drilled during 2007.

In response to drilling costs which have almost doubled since the project began, beginning with the Vela Prospect (discussed above), the company recently elected to reduce its exposure to drilling participation in the next four prospects by selling all, or a significant portion, of its 37.5% interest to industry drilling participants. The company expects to recover its investment in each prospect and retain a promoted interest in exploratory wells with the option to participate in development drilling. Because the project has significant potential to increase production and reserves, the company has reserved the option to participate for its full 37.5% interest in all other prospects. This strategy will reduce the company’s South Texas exploration risk and improve its staying power.

North-Central Kansas—The company’s new exploration project in Central Kansas includes interests in three different drilling projects encompassing about 30,000 gross acres located on the Central Kansas Uplift. The acreage is located in a prolific producing area of the Central Kansas Uplift where 3-D seismic has recently proven to be an effective exploration tool. The project provides diversification to the company’s drilling program, both geographically and scientifically, through the use of 3-D seismic. It also exclusively targets oil reserves which will help bring better product balance to the company’s reserve base.

The company owns interests in the projects ranging from 12.5% to 100%. Drilling targets the Lansing-Kansas City formation at 4,000 feet. Completed costs for individual wells are averaging approximately $300,000.

The largest of the three drilling projects is approximately 21,000 gross acres located in Graham and Sheridan Counties, Kansas. The company owns a 30% interest and committed to shoot seismic and participate in drilling five test wells. The commitment has been fully funded and all future project funding is at the company’s discretion. Approximately 28 square miles of 3-D seismic have been shot and evaluated, and six exploratory wells have been drilled, of which one well is an excellent producer and five wells are dry holes. The new producer is making 115 BO per day after four months of production. It is located on a prospect containing approximately 1,000 gross acres. Additional development drilling is scheduled for the prospect.

The project is in an early stage and the learning curve is steep. Seismic data is currently being reprocessed and re-evaluated to incorporate data obtained from drilling the initial wells. The company believes drilling results will improve as it gains additional experience in the area. Drilling is expected on approximately 30 prospects.

Calliope Drilling Project—See discussion under Calliope Gas Recovery Technology below.

All of the company’s oil and natural 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. There are currently three U.S. patents and one Canadian patent related to the technology. Two additional patents that mirror the U.S. patents have been applied for in Canada.

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 reservoirs, lower bottom-hole pressure can translate into recovery of substantial additional natural 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 is implementing strategies designed to expand the population of wells on which it can install Calliope.

Realizing Calliope’s value continues to be one of the company’s top priorities. The company is focused on three fronts to increase the number of Calliope installations: expanding the geographic region for purchasing Calliope candidate wells from third parties, joint ventures with larger companies, and drilling wells into low-pressure gas reservoirs for the purpose of using Calliope to recover stranded natural gas reserves.

Calliope Drilling Project—During 2006, the company entered into a 50/50 joint venture with Redman Energy Holdings II, L.P. to drill wells for the purpose of using its patented Calliope Gas Recovery System to recover stranded gas reserves. Redman Energy Holdings is an affiliate of Redman Energy Corporation, a privately-held, Houston-based exploration and production company. Redman is affiliated with Natural Gas Partners, a highly

respected industry funding source, and brings a wealth of knowledge and a solid operating foundation in the project area. Drilling will concentrate on previously mature, prolific fields containing significant stranded gas.

In its initial phases, the joint venture plans to invest up to $35,000,000 to acquire leases, drill new wells, and install Calliope principally in South and East Texas. Drilling will target large gas fields that were abandoned when natural gas prices were considerably lower than today, and when technologies to remove fluids from wellbores were much less effective than Calliope. The company presently expects to fund its 50% share of the joint venture from existing cash and future cash flow.

Access to fields and drilling locations are generally available through leasing or acquiring interests in old fields. The company believes this project is a target-rich opportunity for the company to take control of expanding its Calliope operations. Wells are expected to range in depth from 8,000 to 13,000 feet. Reserves are projected to range from 1.0 to 3.0 Bcfe (billion cubic feet of gas equivalent) per well, with beginning production rates ranging from 500 to 1,500 Mcf per day. Average drilling economics are expected to include payouts of approximately two years.

Several prospects are located in old fields currently owned by Redman, and several prospects are in various stages of leasing. The old fields currently owned by Redman contain very significant stranded gas reserves due to their large reservoir volume and high remaining pressure. The company believes that Calliope will recover billions of cubic feet of gas from these fields by pulling-down reservoir pressure to previously unachievable levels.

The first well to be proposed under the joint venture is an 11,500-foot well located in a field that has produced 110 billion cubic of gas from the Smackover formation. Drilling is expected to commence during the second quarter of fiscal 2007.

In addition to the Redman joint venture, the company is developing other Calliope drilling prospects. The Redman joint venture applies largely to South and East Texas. There are many other areas, including Oklahoma, Louisiana, Mississippi and North Texas, that are highly prospective for Calliope drilling.

The Calliope drilling project will be the company’s first opportunity to use Calliope to recover stranded reserves from an entire field. The company believes that drilling new wells for Calliope will provide a repeatable opportunity to lease large areas for systematic re-development. In addition, the company intends to install optimum casing and tubular sizes to substantially improve reserves and production compared to installing Calliope on existing wells where undersized tubulars often impede Calliope’s performance.

Although there are always risks associated with drilling, the company considers this to be low risk, development type drilling because it involves areas known to be productive. The company believes that drilling wells into under-pressured reservoirs without damaging the reservoir with drilling fluids is key to the success of the project. If that can be done successfully, the company believes that Calliope can be used to recover stranded gas reserves that can estimated with a high degree of confidence.

Purchasing Calliope Candidate Wells—Calliope systems are currently installed on 18 wells owned and operated by the company. The wells are located in Oklahoma, Texas and Louisiana, and range in depth from 6,500 to 18,400 feet. They represent the most rigorous applications for Calliope because the wells were either totally dead or uneconomic at the time Calliope was installed. In addition, prior to the time Calliope was installed, many of the reservoirs were damaged by the “parting shots” of previous operators. Initial Calliope production rates range up to 650 Mcfd (thousand cubic feet of gas per day) and average per well Calliope reserves for non-prototype wells are estimated to be 1.10 Bcf. One of the company’s early Calliope installations, the J.C. Carroll well, has now produced almost a billion cubic feet of gas using Calliope.

Calliope operations have recently been expanded into Texas and Louisiana with two installations in southwest Texas and one in Louisiana. The company considers Texas and Louisiana to be very fertile areas for Calliope and has retained personnel and opened a Houston office to focus exclusively on Calliope.

In general, higher gas prices have made it increasingly difficult for the company to purchase wells for its Calliope system. In addition, higher gas prices have provided the incentive for other companies to perform high risk procedures (“parting shots”) in an attempt to revive wells prior to abandoning or selling the wells. These parting shots often result in severe reservoir damage that renders wells unsuitable for Calliope.

Joint Ventures With Third Parties—In an effort to increase the number of Calliope installations, the company is seeking joint ventures with larger companies. Presentations have been made to a select group of companies, including majors and large independents. All of the companies have expressed a keen interest in Calliope, and joint venture discussions are continuing with a number of the companies, including evaluation of candidate wells.

The joint venture negotiation process has taken longer than expected because there are many decision points within large companies that cause delays. Nevertheless, the company continues to dedicate resources and make efforts as it believes that the company will eventually be successful in the joint venture area.

Results of Operations

Three Months Ended January 31, 2007 Compared to Three Months Ended January 31, 2006

For the three months ended January 31, 2007, total revenues decreased 7% to $4,055,000 compared to $4,365,000 during the same period last year. As the oil and gas price/volume table on page 13 shows, total gas price realizations, which reflect hedging transactions, decreased 26% to $6.03 per Mcf and oil price realizations decreased 8% to $52.06 per barrel. The net effect of these price changes was to decrease oil and gas sales by $989,000. For the three months ended January 31, 2007, the company’s gas equivalent production increased 21% resulting in an oil and gas sales increase of $678,000. Investment and other income was $247,000 for the first quarter of 2007 and $245,000 for 2006.

For the three months ended January 31, 2007, total costs and expenses rose 7% to $2,155,000 compared to $2,011,000 for the comparable period in 2006. Oil and gas production expenses decreased 9% due to a decrease in production taxes and lease operating expense. The decrease in production taxes is due to lower oil and gas revenue and hedging gains of $396,000 on which there is no production tax. Depreciation, depletion and amortization (DD&A) rose 30% primarily due to an increase in the amortizable full cost pool and increased production. A change in estimated salvage values resulted in a decrease in DD&A of approximately $65,000. General and administrative expenses increased 7%. Interest expense relates to the exclusive license agreement note payment. The effective tax rate was 28.2% and 28% for the 2007 and 2006 periods, respectively.

SIGNIFICANT ACCOUNTING POLICIES

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 natural 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 natural 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 natural gas properties. A change in proved reserves without a corresponding change in capitalized costs will cause the depletion rate to increase or decrease.

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 natural 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 natural gas prices may subsequently increase the ceiling.

The company has made only one ceiling write-down in its 28-year history. That write down was made in 1986 after oil prices fell 51% and natural gas prices fell 45% between fiscal year end 1985 and 1986.

Changes in oil and natural 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 natural 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 the test period.

OIL AND GAS RESERVES. The determination of depreciation and depletion expense as well as ceiling test write-downs related to the recorded value of the company’s oil and natural gas properties are highly dependent on the estimates of the proved oil and natural gas reserves. Oil and natural 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 natural 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 natural gas ultimately recovered and the corresponding lifting costs associated with the recovery of these reserves.

ASSET RETIREMENT OBLIGATIONS. 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.

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.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The company manages exposure to commodity price fluctuations by periodically hedging a portion of expected production through the use of derivatives, typically collars and forward short positions in the NYMEX or other regional indexes futures market. See Note 4 for more information on the company’s hedging activities.

ITEM 4. CONTROLS AND PROCEDURES

In accordance with the Securities Exchange Act of 1934 Rules 13a-15 and 15d-15, the Company carried out an evaluation, under the supervision and with the participation of management, including the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the Company’s disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation the Chief Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of January 31, 2007 to provide reasonable assurance that information required to be disclosed in the Company’s reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms. The Company’s disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed in reports filed or submitted under the Exchange Act is accumulated and communicated to the Company’s management, including the Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

There has been no change in the Company’s internal control over financial reporting that occurred during the three months ended January 31, 2007 that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

PART II — OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

None.

ITEM 1A. RISK FACTORS

There have been no material changes from the risk factors previously disclosed in the company’s Annual Report on Form 10-K for the fiscal year ended October 31, 2006.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

None.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

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

None.

ITEM 5. OTHER INFORMATION

None.

ITEM 6. EXHIBITS

Exhibits are as follow:

	31.1		Certification by Chief Executive Officer pursuant to Rule 13a-14(a) of the Securities Exchange Act, as amended
	31.2		Certification by Chief Financial Officer pursuant to Rule 13a-14(a) of the Securities Exchange Act, as amended
	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)

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

Date: March 12, 2007

Exhibit Index

	31.1		Certification by Chief Executive Officer pursuant to Rule 13a-14(a) of the Securities Exchange Act, as amended
	31.2		Certification by Chief Financial Officer pursuant to Rule 13a-14(a) of the Securities Exchange Act, as amended
	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)