Credo Petroleum (CRED) 10-Q 2007 Q2 Quarterly report

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 endedApril 30, 2007

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 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
June 11, 2007	Common stock, $.10 par value	9,262,000

CREDO PETROLEUM CORPORATION AND SUBSIDIARIES

Quarterly Report on Form 10-Q For the Period Ended April 30, 2007

TABLE OF CONTENTS

		Page No.
	PART I — FINANCIAL INFORMATION
Item 1.	Financial Statements
	Consolidated Balance Sheets As of April 30, 2007 (Unaudited) and October 31, 2006		3
	Consolidated Statements of Operations For the Three and Six Months Ended April 30, 2007 and 2006 (Unaudited)		4
	Consolidated Statement of Stockholders’ Equity and Comprehensive Income (Loss) For the Six Months Ended April 30, 2007 (Unaudited)		5
	Consolidated Statements of Cash Flows For the Six Months Ended April 30, 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		11
Item 3.	Quantitative and Qualitative Disclosures About Market Risk		19
Item 4.	Controls and Procedures		19
	PART II — OTHER INFORMATION
Item 1.	Legal Proceedings		20
Item 1A.	Risk Factors		20
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		20
Item 3.	Defaults Upon Senior Securities		20
Item 4.	Submission of Matters to a Vote of Security Holders		20
Item 5.	Other Information		21
Item 6.	Exhibits		21
Signatures			22
Certification of CEO Pursuant to Section 302
Certification of CFO Pursuant to Section 302
Certification of 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.

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PART I — FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

CREDO PETROLEUM CORPORATION AND SUBSIDIARIES
Consolidated Balance Sheets

	April 30,			October 31,
	2007			2006
	(Unaudited)
ASSETS
Current Assets:
Cash and cash equivalents	$	5,274,000		$	4,577,000
Short-term investments		6,017,000			5,624,000
Receivables:
Accrued oil and gas sales		2,148,000			1,963,000
Trade		585,000			777,000
Derivative Assets		—			897,000
Other current assets		255,000			71,000
Total current assets		14,279,000			13,909,000
Long-term assets:
Oil and gas properties, at cost, using full cost method:
Unevaluated oil and gas properties		8,025,000			7,060,000
Evaluated oil and gas properties		46,856,000			43,588,000
Less: accumulated depreciation, depletion and amortization of oil and gas properties		(20,401,000	)		(18,556,000	)
Net oil and gas properties, at cost, using full cost method		34,480,000			32,092,000
Exclusive license agreement, net of amortization of $466,000 in 2007 and $431,000 in 2006		233,000			268,000
Compressor and tubular inventory to be used in development		1,346,000			1,293,000
Other (net)		259,000			197,000
Total assets	$	50,597,000		$	47,759,000
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Accounts payable	$	1,059,000		$	1,581,000
Revenue distribution payable		1,094,000			1,273,000
Other accrued liabilities		664,000			808,000
Income taxes payable		287,000			174,000
Total current liabilities		3,104,000			3,836,000
Long Term Liabilities:
Deferred income taxes, net		8,873,000			8,039,000
Exclusive license obligation, less current obligations of $70,000 in 2007 and 2006		163,000			163,000
Asset retirement obligation		984,000			954,000
Total liabilities		13,124,000			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 in 2006		951,000			951,000
Capital in excess of par value		14,909,000			14,794,000
Treasury stock at cost, 248,000 shares in 2007 and 249,000 in 2006		—			—
Accumulated other comprehensive income (loss)		(105,000	)		650,000
Retained earnings		21,718,000			18,372,000
Total stockholders’ equity		37,473,000			34,767,000
Total liabilities and stockholders’ equity	$	50,597,000		$	47,759,000

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

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CREDO PETROLEUM CORPORATION AND SUBSIDIARIES
Consolidated Statements of Operations
(Unaudited)

	Six Months Ended						Three Months Ended
	April 30,						April 30,
	2007			2006			2007			2006
REVENUES:
Oil and gas sales	$	8,493,000		$	7,843,000		$	4,685,000		$	3,723,000
Investment income and other		453,000			443,000			206,000			198,000
		8,946,000			8,286,000			4,891,000			3,921,000
COSTS AND EXPENSES:
Oil and gas production		1,709,000			1,743,000			796,000			739,000
Depreciation, depletion and amortization		1,900,000			1,629,000			942,000			891,000
General and administrative		644,000			579,000			366,000			319,000
Interest		13,000			18,000			7,000			9,000
		4,266,000			3,969,000			2,111,000			1,958,000
INCOME BEFORE INCOME TAXES		4,680,000			4,317,000			2,780,000			1,963,000
INCOME TAXES		(1,334,000	)		(1,230,000	)		(798,000	)		(571,000	)
NET INCOME	$	3,346,000		$	3,087,000		$	1,982,000		$	1,392,000
EARNINGS PER SHARE OF COMMON STOCK BASIC	$	.36		$	.34		$	.21		$	.15
EARNINGS PER SHARE OF COMMON STOCK DILUTED	$	.36		$	.33		$	.21		$	.15
Weighted average number of shares of Common Stock and dilutive securities:
Basic		9,261,000			9,171,000			9,261,000			9,207,000
Diluted		9,395,000			9,498,000			9,395,000			9,506,000

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

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CREDO PETROLEUM CORPORATION AND SUBSIDIARIES
Statement of Stockholders’ Equity and Accumulated Other Comprehensive Income
(Unaudited)
For the Six Months Ended April 30, 2007

							Accumulated
					Capital In		Other					Total
	Common Stock				Excess Of		Comprehensive			Retained		Stockholders’
	Shares		Amount		Par Value		Income(Loss)			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		—		—		—		—			3,346,000		3,346,000
Other comprehensive income:
Change in fair value of derivatives, net of tax		—		—		—		(755,000	)		—		(755,000	)
Total comprehensive income		—		—		—		—			—		—
Exercise of common stock options		—		—		5,000		—			—		5,000
Compensation expense associated with unvested portion of previously granted stock options		—		—		110,000		—			—		110,000
Balance, April 30, 2007		9,510,000	$	951,000	$	14,909,000	$	(105,000	)	$	21,718,000	$	37,473,000

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

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CREDO PETROLEUM CORPORATION AND SUBSIDIARIES
Consolidated Statements of Cash Flows
(Unaudited)

	Six Months Ended
	April 30,
	2007			2006
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	3,346,000		$	3,087,000
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		1,900,000			1,629,000
Deferred income taxes		834,000			803,000
Compensation expense related to stock options granted		110,000			119,000
Other		30,000			—
Changes in operating assets and liabilities:
Proceeds from short-term investments		1,492,000			193,000
Purchase of short-term investments		(1,885,000	)		(591,000	)
Accrued oil and gas sales		(185,000	)		(153,000	)
Trade receivables		192,000			187,000
Other current assets		(43,000	)		294,000
Accounts payable and accrued liabilities		(845,000	)		(639,000	)
Income taxes payable		113,000			28,000
NET CASH PROVIDED BY OPERATING ACTIVITIES		5,059,000			4,957,000
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas properties		(4,404,000	)		(5,536,000	)
Proceeds from sale of oil and gas properties		171,000			174,000
Changes in other long-term assets		(134,000	)		1,000
NET CASH USED IN INVESTING ACTIVITIES		(4,367,000	)		(5,361,000	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from exercise of stock options		5,000			553,000
NET CASH PROVIDED BY FINANCING ACTIVITIES		5,000			553,000
INCREASE IN CASH AND CASH EQUIVALENTS		697,000			149,000
CASH AND CASH EQUIVALENTS:
Beginning of period		4,577,000			1,935,000
End of period	$	5,274,000		$	2,084,000
Supplemental cash flow information:
Cash paid during the period for income taxes	$	90,000		$	486,000

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

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CREDO PETROLEUM CORPORATION AND SUBSIDIARIES
Notes To Consolidated Financial Statements (Unaudited)
April 30, 2007

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.

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 and $130,000 for the three and six month periods ended April 30, 2007.

3. STOCK-BASED COMPENSATION

The company previously had 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, was approved by the shareholders at the Annual Meeting of Shareholders on March 22, 2007. 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.

The company recognized compensation expense related to its stock option plan of $110,000 and $119,000 for the six months ended April 30, 2007 and 2006 respectively. For the three months ended April 30, 2007 and 2006, the company recognized compensation expense of $53,000 and $59,000, respectively.

No options were granted during fiscal year 2006 and the fair value of the 40,000 options granted during the six months ended April 30, 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 to 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.

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Plan activity for the six months ended April 30, 2007 is set forth below:

	Six Months Ended April 30, 2007
				Weighted
				Average
	Number of			Exercise
	Options			Price
Outstanding at October 31, 2006		315,002		$	5.52
Granted		40,000			12.78
Exercised		(937	)		5.93
Cancelled or forfeited		(564	)		5.93
Outstanding at April 30, 2007		353,501		$	6.34
Exercisable at April 30, 2007		273,606		$	5.70
Weighted average contractual life at April 30, 2007				6.15		years

The following table summarizes information about stock options currently outstanding and exercisable at April 30, 2007:

	Outstanding						Exercisable
	Number		Weighted Average		Weighted		Number
Range of	Outstanding		Remaining		Average		Exercisable at		Weighted
Exercise	at April 30,		Contractual		Exercise		April 30,		Average
Prices	2007		Life in Years		Price		2007		Exercise Price
$3.09-$3.72		54,750		5.62	$	3.56		44,625	$	3.52
$5.93		258,751		4.97	$	5.93		222,314	$	5.93
$12.78		40,000		9.60	$	12.78		6,667	$	12.78
$3.09-$12.78		353,501		6.15	$	6.34		273,606	$	5.70

Total estimated unrecognized compensation cost from unvested stock options as of April 30, 2007 was approximately $166,000, which is expected to be recognized over an average period of approximately 3.0 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

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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 $986,000 in the six months ended April 30, 2007, and hedging losses of $190,000 for the same period in 2006. Hedging gains were $590,000 for the quarter ended April 30, 2007. There was no hedging activity in the same period in 2006. Any hedge ineffectiveness, which was not material for any period, is immediately recognized in gas sales.

Hedging positions for production months after second quarter end totaled 1.50 Bcf covering the production months of May 2007 through March 2008. These hedges are intended to cover between 75% and 88% of the company’s current production base without taking into consideration estimates of new production from future operations. The average monthly hedge price (NYMEX basis) ranges from $7.80 in the summer to $9.53 in the winter. Deferred hedging gains and losses at April 30, 2007 related to such hedging positions were a net loss of $146,000 ($105,000 net of income tax). These amounts have been included in Accumulated Other Comprehensive Income ($105,000) and Accrued Liabilities ($146,000).

Subsequent to April 30, 2007, the company entered into additional hedge contracts covering 60 MMBtus at NYMEX basis prices ranging from $9.57 to $9.92 for the production months of December 2007 through February 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 and six months ended April 30, 2007 and 2006 are as follows:

	Six Months Ended						Three Months Ended
	April 30,						April 30,
	2007			2006			2007			2006
Net income	$	3,346,000		$	3,078,000		$	1,982,000		$	1,392,000
Other comprehensive income:
Change in fair value of derivatives		(1,043,000	)		425,000			(672,000	)		—
Income tax expense		288,000			(119,000	)		188,000			—
Total comprehensive income	$	2,591,000		$	3,393,000		$	1,498,000		$	1,392,000

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6. EARNINGS PER SHARE

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

	Six Months Ended April 30,
	2007						2006
					Net						Net
	Net				Income		Net				Income
	Income		Shares		Per Share		Income		Shares		Per Share
Basic earnings per share	$	3,346,000		9,261,000	$	.36	$	3,087,000		9,171,000	$	.34
Effect of dilutive shares of common stock from stock options		—		134,000		—		—		327,000		(.01	)
Diluted earnings per share	$	3,346,000		9,395,000	$	.36	$	3,087,000		9,498,000	$	.33

	Three Months Ended April 30,
	2007						2006
					Net						Net
	Net				Income		Net				Income
	Income		Shares		Per Share		Income		Shares		Per Share
Basic earnings per share	$	1,982,000		9,261,000	$	.21	$	1,392,000		9,207,000	$	.15
Effect of dilutive shares of common stock from stock options		—		134,000		—		—		299,000		—
Diluted earnings per share	$	1,982,000		9,395,000	$	.21	$	1,392,000		9,506,000	$	.15

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 April 30, 2007.

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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 April 30, 2007, working capital increased $2,342,000 or 27% to $11,175,000 compared to $8,833,000 at April 30, 2006. For the six months ended April 30, 2007, net cash provided by operating activities increased $102,000 to $5,059,000 compared to net cash provided by operating activities of $4,957,000 for the same period in 2006. Net income increased $259,000 primarily due to an increase in revenues of $660,000, partially offset by an increase in depreciation, depletion and amortization (DD&A) of $271,000, net of a $130,000 decrease in DD&A due to an increase in estimated salvage values.

For the six months ended April 30, 2007 and 2006, net cash used in investing activities was $4,367,000 and $5,361,000, respectively. Investing activities primarily included oil and gas exploration and development expenditures, including Calliope, totaling $4,404,000 and $5,536,000 respectively.

The average return on the company’s investments for the six months ended April 30, 2007 and 2006 was 7.3% and 6.5%, respectively. At April 30, 2007, approximately 45% of the investments were directly invested in mutual funds and were managed by professional money managers. Remaining investments are in managed partnerships (generally known as hedge funds) 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

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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 April 30, 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”) increased 11% to $6,594,000 for the six months ended April 30, 2007 from $5,964,000 for the six months ended April 30, 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:

	Six Months Ended April 30,
	2007		2006
RECONCILIATION OF EBITDA:
Net Income	$	3,346,000	$	3,087,000
Add Back:
Interest Expense		14,000		18,000
Income Tax Expense		1,334,000		1,230,000
Depreciation, Depletion and Amortization Expense		1,900,000		1,629,000
EBITDA	$	6,594,000	$	5,964,000

OFF-BALANCE SHEET FINANCING

The company has no off-balance sheet financing arrangements at April 30, 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 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 to the Consolidated Financial Statements for a complete discussion on the company’s hedging activities.

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

	Six Months Ended April 30,
	2007					2006					% Change
Product	Volume		Price			Volume		Price			Volume			Price
Gas (Mcf)		1,024,000	$	6.99	(1)		965,000	$	6.91	(2)	+	6	%	+	1	%
Oil (bbls)		25,100	$	53.73			19,800	$	59.37		+	27	%	-	9	%

	Three Months Ended April 30,
	2007					2006				% Change
Product	Volume		Price			Volume		Price		Volume			Price
Gas (Mcf)		495,000	$	7.99	(3)		528,000	$	5.85	-	6	%	+	37	%
Oil (bbls)		13,200	$	55.24			10,300	$	61.63	+	28	%	-	10	%

(1)	Includes $0.96 Mcf hedging gain.
(2)	Includes $0.27 Mcf hedging loss.
(3)	Includes $1.19 Mcf hedging gain.

OPERATIONS

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

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, cost and quality 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 cost of field services, particularly the cost of drilling wells, has increased dramatically during the past several years, driven by higher energy prices. Concurrently, the quality of field services has diminished markedly due to manpower shortages. The combination of much higher field service costs and degradation in the quality of the services is having a materially negative impact on drilling economics. Accordingly, the company continues to high-grade its drilling prospects, and in some cases postpone less robust projects pending improvement in the field services sector. In the short term, this will reduce the number of drilling prospects which may, in turn, impede the growth of the company’s production and reserves

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.

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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.

Drilling Activities.

Oklahoma and Texas Panhandle—The company drills primarily on its significant Northern Anadarko Basin acreage inventory (totaling over 75,000 gross acres) where it has drilled about 80 wells. Wells target the Morrow, Oswego and Chester formations between 7,000 and 11,000 feet. Four wells have been completed as producers in fiscal year 2007, one well was a dry hole, and four new wells are expected to be drilled on the acreage in the next 90 days.

The Carmella State #1-23, drilled in 2007, is the ninth well drilled on the 5,760 gross acre Glacier Prospect in Harper and Woodward Counties, Oklahoma. The 7,500-foot well tested the Morrow formation and encountered 16 feet of productive Morrow sand in two zones. Both zones were opened for production but were not fracture stimulated. The well is currently producing about 700 Mcfd (thousand cubic feet of gas per day). The lower zone contains excellent quality sand and is producing most of the gas. The upper zone will require a fracture stimulation at a later date. The company owns a 72% working interest and is the operator.

The Humphreys #1D well is the first well drilled on the Humphreys Prospect in the Texas Panhandle. The wildcat well encountered excellent quality Morrow sands at 11,200 feet, and initially tested at rates of about 3.0 MMcfd. However, a rapid decline in production indicates that the reservoir is limited in size at the well location. The well is currently making about 100 Mcfd (thousand cubic feet of gas per day). Three-dimensional seismic will be used to assess whether the well is separated from a larger reservoir by faulting. The company is encouraged by the presence of a Morrow channel system containing high quality sands, and has recently acquired additional acreage to expand the prospect from 2,500 to 3,780 gross acres. Three dimensional seismic (3-D) has been acquired and is being processed. Further drilling is expected. The company owns a 25% working interest.

An excellent well has been drilled on the 640 gross acre Loosen Prospect in Canadian County, Oklahoma. The 11,500-foot Hazel well encountered high quality sands in the Redfork and Skinner formations, and is producing approximately 2.0 MMcf and 72 barrels of oil per day. The company owns an overriding royalty interest in the Hazel well that is convertible to a 6.25% working interest at payout. An offset well is scheduled in which the company will own a 16% working interest.

A fifth well has been drilled on the company’s 1,260 gross acre Gage Prospect in Ellis County, Oklahoma. Four producers have previously been completed. The new 9,500-foot well encountered 26 feet of Morrow sands that appear on electric logs to be productive. The well is currently awaiting completion for pipeline production. The company owns a 31% working interest.

The company is currently drilling a seventh well on its 3,840 gross acre Buffalo Creek Prospect in Harper County, Oklahoma. The 6,900-foot well will test the Oswego and Chester formations. Six producing wells have previously been drilled on the prospect. A 3-D seismic survey was recently completed to better define faulting on the prospect. The 3-D survey has identified another four to six drilling locations. Other operators have recently scheduled two additional wells on the prospect which will commence shortly. CREDO owns varying interests in different portions of the prospect ranging from 30% to 45%.

In Carter County, Oklahoma, the company is continuing to develop its Southeast Hewitt Waterflood Unit. To date, the unit has produced 550,000 barrels of oil from the waterflood, and it continues to significantly outperform initial expectations. A 6,250-foot development well has been scheduled that is

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expected to significantly increase production over the current rate of 264 barrels of oil per day. CREDO owns a 17% interest.

A third well was drilled in May 2007 on the 1,260 gross acre Saddle Prospect in Harper County, Oklahoma. The 6,700-foot well tested the Morrow formation and resulted in a dry hole. The company owned a 61% working interest and is the operator.

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.

Two prospects have been drilled in the South Texas program and both resulted in producers. Drilling will commence shortly on a third prospect, and four prospects are currently being marketed to drilling participants.

A 10,500-foot wildcat well has been completed on the Robertson Prospect in Hidalgo County. The well encountered two Upper Frio sands that appear to be productive. The well is completed in the lower sand and has recently been placed on production at the rate of 450 Mcfd. The production rate is temporarily curtailed on a 4/64ths-choke pending resolution of pipeline issues. Pressure data indicates that the reservoir may be limited in size. The remaining up-hole sand will be evaluated at a later date. The company owns a 37.5% working interest.

In Jim Hogg County, a 7,200-foot wildcat well targeting the Queen City sand has recently been completed on the Vela Prospect. Although the Queen City formation was not productive, the well encountered productive gas sands at about 2,650 feet which tested at the rate of about 220 Mcfd. In addition to cash consideration, the company retained a carried interest in the drilling and completion of the well and owns a 15% working interest before payout and 7.5% after payout. The company has preserved its right to participate in additional drilling on the prospect based on the retained interest.

Drilling is expected to commence shortly on the West Mestena Prospect in Jim Hogg County. The wildcat well will target Queen City sands at about 8,500 feet. Due to the high cost and to reduce risks associated with the wildcat test well, the company farmed-out its interest in the initial test well in return for a carried interest to casing point and cash consideration. The company will own 9.375% of the initial test well after casing point and 9.375% of all additional wells, if any, drilled on the prospect.

Four prospects are in the process of being marketed to drilling participants, one of which is a wildcat prospect in Hidalgo County that will test Upper Frio sands at 12,500 feet. A nearby development prospect will also test Upper Frio sands at 10,500 feet. Two wildcat prospects in Jim Hogg County will test Wilcox sands at 15,000 and 17,000 feet, respectively. The company is marketing its interest in the prospects for cash consideration and a carried interest on the initial test well to be drilled on each prospect. The company will preserve its option to participate in future drilling for a portion of its interest.

The South Texas drilling program has potential that could substantially increase the company’s reserves and production. The deep Wilcox prospects are in an area where fields have made several hundred billion cubic feet of gas. The company will reduce its risk in these expensive ($10,000,000) wells by retaining a 9% to 18% carried interest in the test wells. The company will also preserve its option to participate in future drilling if the wildcat wells are successful.

North-Central Kansas—The company owns interests ranging from 12.5% to 100% in three different drilling projects encompassing about 30,000 gross acres on the Central Kansas uplift. The acreage is located in a prolific oil producing area where 3-D seismic has recently proven to be an effective exploration tool. Drilling targets the Lansing-Kansas City formation at 3,500 to 4,000 feet. Well costs are moderate at about $300,000.

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To date, six wells have been drilled on the largest of the three projects comprising 21,000 gross acres located in Graham and Sheridan Counties, Kansas. One well is a producer and five are dry holes. The new producer is an outstanding well, still making 105 barrels of oil per day after six months on production. At least two development wells are expected to be drilled offsetting the new discovery. CREDO owns a 30% working interest.

Seismic data is currently being reprocessed and re-evaluated to incorporate information obtained from drilling the initial wells. The company believes drilling results will improve as it gains additional experience in the area. The two other projects are being readied for evaluation using 3-D seismic. If seismic results are favorable, initial drilling should commence later this year.

Three dimensional seismic (3-D) has recently been completed on the second of the three projects and exploratory drilling has been identified on two separate prospects. Drilling is expected to commence in the third quarter.

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. The agreement committed Redman and CREDO, exclusively, to an extensive project area that covered much of South and East Texas. Effective May 1, 2007, the company terminated the Redman agreement.

The terms of the agreement provided that either party could terminate the agreement at the end of the first year if a minimum of three wells had not been drilled by that date. As of the first anniversary of the agreement on May 1, 2007, no wells had been drilled. There are no cancellation penalties.

Concurrently, CREDO entered into a joint venture with a private company based in Texas. This joint venture will install Calliope on a recently drilled well that has not produced due to low formation pressure. The well is located in a prolific, old natural gas field. Calliope will be installed on the 11,000-foot well to establish commercial production. CREDO owns 60% of the joint venture.

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

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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 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. The company has recently entered into a joint venture agreement with an independent oil and gas operator covering a pilot Calliope installation. The two companies are in the process of selecting a pilot location. 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

Six Months Ended April 30, 2007 Compared to Six Months Ended April 30, 2006

For the six months ended April 30, 2007, total revenues increased 8% to $8,946,000 compared to $8,286,000 last year. As the oil and gas price/volume table on page 13 shows, total gas price realizations, which reflect hedging transactions, increased 1% to $6.99 per Mcf and oil price realizations fell 9% to $53.73 per barrel. The net effect of these price changes was to decrease oil and gas sales by $47,000. For the six months ended April 30, 2007, the company’s gas equivalent production increased 8% resulting in an oil and gas sales increase of $697,000. Investment income and other increased $10,000 primarily due to the performance of the company’s investments.

For the six months ended April 30, 2007, total costs and expenses rose 7% to $4,266,000 compared to $3,969,000 for the comparable period in 2006. Depreciation, depletion and amortization (DD&A) rose 17% primarily due to increased production and an increase in the amortizable full cost pool. A change in estimated salvage values resulted in a decrease in DD&A of approximately $130,000. General and administrative expenses increased 11% primarily due to increased accounting and professional fees. Interest expense relates to the exclusive license agreement note payment. The effective tax rate was 28.5% for the 2007 and 2006 periods, respectively.

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Three Months Ended April 30, 2007 Compared to Three Months Ended April 30, 2006

For the three months ended April 30, 2007, total revenues increased 25% to $4,891,000 compared to $3,921,000 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, increased 37% to $7.99 per Mcf and oil price realizations fell 10% to $55.24 per barrel. The net effect of these price changes was to increase oil and gas sales by $1,062,000. For the three months ended April 30, 2007, the company’s gas equivalent production fell 3% resulting in an oil and gas sales decrease of $100,000. Investment and other income was $206,000 for the first quarter of 2007 and $198,000 for 2006.

For the three months ended April 30, 2007, total costs and expenses rose 8% to $2,111,000 compared to $1,958,000 for the comparable period in 2006. Oil and gas production expenses increased 8% due to an increase in production taxes and lease operating expense. The increase in production taxes is due to increased oil and gas revenue, net of hedging gains of $590,000 on which there is no production tax. Depreciation, depletion and amortization (DD&A) rose 6% primarily due to an increase in the amortizable full cost pool. A change in estimated salvage values resulted in a decrease in DD&A of approximately $65,000. General and administrative expenses increased 15% primarily due to increased accounting and professional fees. Interest expense relates to the exclusive license agreement note payment. The effective tax rate was 28.7% and 29.1% 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

18

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.The company estimates the future cost of asset retirement obligations, discounts that cost to its present value, and records 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 oil and gas production 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.

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

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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 six months ended April 30, 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

The company’s annual meeting of stockholders was held on March 22, 2007, for the purpose of electing two Class I directors, ratifying the appointment of Hein & Associates LLP as the company’s independent registered public accounting firm, and to approve the CREDO Petroleum Corporation 2007 Stock Option Plan. Proxies for the meeting were solicited pursuant to Section 14(a) of the Securities Exchange Act of 1934 and there was no solicitation in opposition to management’s solicitation. Each of management’s nominees for Class I directors, as listed in the proxy statement, was elected with the number of votes set forth below.

Name	For		Withheld
Oakley Hall		8,053,466		203,637
William F. Skewes		8,052,189		204,914

Continuing Directors:

After the company’s annual meeting on March 23, 2006, the following director continues to serve his three year term as Class III director, which term will expire at the company’s 2008 annual meeting:

Richard B. Stevens

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After the company’s annual meeting on March 23, 2006, the following directors continue to serve their three year terms as Class II directors, which terms will expire at the company’s 2009 annual meeting:

James T. Huffman
Clarence H. Brown

The results of the other matters voted upon at the company’ annual meeting are as follows:

The appointment of Hein & Associates LLP as the company’s independent registered public accounting firm:

For	Against		Abstain
8,189,753		51,400		15,950

The approval of the CREDO Petroleum Corporation 2007 Stock Option Plan.

For	Against		Abstain
4,061,845		823,913		39,842

The matters mentioned above are described in detail in the company’s definitive proxy statement dated February 20, 2007 for the annual meeting of shareholders held on March 22, 2007.

ITEM 5. OTHER INFORMATION

None.

ITEM 6. EXHIBITS

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)

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SIGNATURES

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

CREDO Petroleum Corporation (Registrant)
By:	/s/ James T. Huffman
	James T. Huffman
	President and Chief Executive Officer (Principal Executive Officer)
By:	/s/ David E. Dennis
	David E. Dennis
	Chief Financial Officer (Principal Financial and Accounting Officer)

Date: June 11, 2007

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EXHIBIT INDEX

Exhibit No.	Description
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)