Forestar Petroleum Corp - FORM 10-Q

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EX-32.1 - EX-32.1 - Forestar Petroleum Corp	a11-13713_1ex32d1.htm
EX-31.1 - EX-31.1 - Forestar Petroleum Corp	a11-13713_1ex31d1.htm
EX-31.2 - EX-31.2 - Forestar Petroleum Corp	a11-13713_1ex31d2.htm

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

(Mark One)

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

For the quarterly period ended April 30, 2011

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)

Delaware		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 x No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate web site, if any, every interactive data file required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files.) Yes o No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. (See the definitions of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Act.)

Large accelerated filer o		Accelerated filer x

Non-accelerated filer o		Smaller Reporting Company o
(Do not check if a smaller reporting company)

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

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 9, 2011		Common stock, $.10 par value		10,041,000

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CREDO PETROLEUM CORPORATION AND SUBSIDIARIES

Quarterly Report on Form 10-Q For the Period Ended April 30, 2011

TABLE OF CONTENTS

		Page No.
	PART I - FINANCIAL INFORMATION

Item 1.	Financial Statements

Consolidated Balance Sheets As of April 30, 2011 (Unaudited) and October 31, 2010		3

Consolidated Statements of Operations For the Three and Six Months Ended April 30, 2011 and 2010 (Unaudited)		5

Consolidated Statements of Cash Flows For the Six Months Ended April 30, 2011 and 2010 (Unaudited)		6

Notes to Consolidated Financial Statements (Unaudited)		7

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	13

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	21

Item 4.	Controls and Procedures	21

	PART II - OTHER INFORMATION

Item 1.	Legal Proceedings	21

Item 1A.	Risk Factors	22

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	22

Item 3.	Defaults Upon Senior Securities	22

Item 5.	Other Information	22

Item 6.	Exhibits	22

Signatures		23

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

A S S E T S

	April 30,			October 31,
	2011			2010
	(Unaudited)

Current Assets:
Cash and cash equivalents	$	3,094,000		$	7,179,000
Short-term investments	2,000,000			1,990,000
Receivables:
Accrued oil and gas sales	2,761,000			1,574,000
Trade	904,000			479,000
Derivative assets	—			32,000
Other current assets	260,000			832,000
Total current assets	9,019,000			12,086,000

Long-term Assets:
Oil and gas properties, at cost, using full cost method:
Unevaluated oil and gas properties	10,416,000			8,801,000
Evaluated oil and gas properties	91,016,000			83,360,000
Less: accumulated depreciation, depletion and amortization of oil and gas properties	(58,240,000		)	(56,339,000		)
Net oil and gas properties, at cost, using full cost method	43,192,000			35,822,000

Intangible assets, net of accumulated amortization of $1,089,000 in 2011 and $872,000 in 2010	3,360,000			3,578,000

Compressor and tubular inventory to be used in development	1,574,000			1,855,000

Other, net	76,000			64,000

Total Assets	$	57,221,000		$	53,405,000

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

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L I A B I L I T I E S A N D S T O C K H O L D E R S ‘ E Q U I T Y

	April 30,			October 31,
	2011			2010
	(Unaudited)

Current Liabilities:
Accounts payable	$	2,918,000		$	1,200,000
Revenue distribution payable	787,000			565,000
Accrued compensation	350,000			466,000
Other accrued liabilities	224,000			177,000
Derivative liability	1,096,000			—
Income taxes payable	17,000			17,000
Total current liabilities	5,392,000			2,425,000

Long Term Liabilities:
Deferred income taxes, net	3,319,000			3,281,000
Non-current derivative liability	450,000			—
Asset retirement obligation	1,175,000			1,132,000
Total liabilities	10,336,000			6,838,000

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, 10,660,000 issued	1,066,000			1,066,000
Capital in excess of par value	31,525,000			31,486,000
Treasury stock at cost, 619,000 shares in 2011 and 601,000 in 2010	(4,654,000		)	(4,509,000		)
Retained earnings	18,948,000			18,524,000
Total stockholders’ equity	46,885,000			46,567,000

Total Liabilities and Stockholders’ Equity	$	57,221,000		$	53,405,000

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,
	2011			2010			2011			2010

Oil sales	$	5,320,000		$	3,530,000		$	3,085,000		$	1,806,000
Natural gas sales	1,998,000			2,557,000			983,000			1,139,000
	7,318,000			6,087,000			4,068,000			2,945,000

Costs and expenses:
Oil and natural gas production	1,834,000			1,658,000			967,000			802,000
Depreciation, depletion and amortization	2,141,000			1,723,000			1,147,000			858,000
General and administrative	1,196,000			1,119,000			711,000			577,000
	5,171,000			4,500,000			2,825,000			2,237,000

Income from operations	2,147,000			1,587,000			1,243,000			708,000

Other income and (expense)
Realized and unrealized gain (loss) from derivative contracts	(1,655,000		)	27,000			(950,000		)	41,000

Investment and other income	59,000			43,000			33,000			44,000
	(1,596,000		)	70,000			(917,000		)	85,000

Income before income taxes	551,000			1,657,000			326,000			793,000
Income taxes	(127,000		)	(415,000		)	(71,000		)	(190,000		)

Net income	$	424,000		$	1,242,000		$	255,000		$	603,000

Earnings per share of Common Stock—Basic	$	.04		$	.12		$	.03		$	.06

Earnings per share of Common Stock—Diluted	$	.04		$	.12		$	.03		$	.06

Weighted average number of shares of Common Stock and dilutive securities:
Basic	10,042,000			10,140,000			10,041,000			10,187,000

Diluted	10,078,000			10,179,000			10,089,000			10,205,000

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,
	2011			2010

Cash Flows From Operating Activities:

Net income	$	424,000		$	1,242,000
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	2,141,000			1,723,000
ARO liability accretion	43,000			39,000
Unrealized (gain) loss on derivative instruments	1,577,000			(24,000		)
Deferred income taxes	38,000			365,000
Gain on short term investments	(53,000		)	(11,000		)
Compensation expense related to stock options granted	38,000			34,000
Changes in operating assets and liabilities:
Purchase of short term investments	(50,000		)	(1,500,000		)
Proceeds from short-term investments	93,000			96,000
Accrued oil and gas sales	(1,187,000		)	22,000
Trade receivables	(425,000		)	301,000
Other current assets	572,000			208,000
Accounts payable and accrued liabilities	489,000			(363,000		)
Income taxes payable	—			12,000

Net Cash Provided By Operating Activities	3,700,000			2,144,000

Cash Flows From Investing Activities:
Additions to oil and gas properties	(7,606,000		)	(3,565,000		)
Proceeds from sale of oil and gas properties	—			86,000
Changes in other long-term assets	(34,000		)	(117,000		)

Net Cash Used In Investing Activities	(7,640,000		)	(3,596,000		)

Cash Flows From Financing Activities:
Purchase of treasury stock	(145,000		)	(1,114,000		)
Proceeds from exercise of stock options	—			297,000

Net Cash Used In Financing Activities	(145,000		)	(817,000		)

Decrease In Cash And Cash Equivalents	(4,085,000		)	(2,269,000		)

Cash And Cash Equivalents:
Beginning of period	7,179,000			12,348,000

End of period	$	3,094,000		$	10,079,000

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, 2011

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. Management has evaluated events and transactions occurring after the balance sheet date through the date the financial statements were issued. For a more complete understanding of the Company’s financial condition and accounting policies, 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, 2010. The results for interim periods are not necessarily indicative of annual results.

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.

2. OIL AND NATURAL GAS PROPERTIES

Depreciation, depletion and amortization of oil and natural gas properties for the six months ended April 30, 2011 and 2010 were $1,901,000 and $1,485,000, respectively, and were $1,027,000 and $740,000 for the three months ended April 30, 2011 and 2010, respectively. 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. All costs incurred in the acquisition, exploration, and development of properties (including costs of surrendered and abandoned leaseholds, delay lease rentals, dry holes, and overhead related to exploration and development activities) and the fair value of estimated future costs of site restoration, dismantlement, and abandonment activities are capitalized. Costs for unevaluated properties, which typically include lease rentals, geology and seismic costs, are capitalized but are excluded from amortizable costs during the evaluation period. When determinations are made whether the property has proved recoverable reserves or not, or if there is an impairment, the costs are reclassified to amortizable costs.

The Company performs a ceiling test each quarter. The full cost ceiling test is a limitation on capitalized costs prescribed by SEC Regulation S-X Rule 4-10. The ceiling test is not a fair value based measurement. Rather, it is a standardized mathematical calculation. The ceiling test provides that capitalized costs less related accumulated depletion and deferred income taxes for each cost center may not exceed the sum of (1) the present value of future net revenue from estimated production of proved oil and gas reserves using current prices (as discussed below), excluding the future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, at a discount factor of 10%; plus (2) the cost of properties not being amortized, if any; plus (3) the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any; less (4) income tax effects related to differences in the book and tax basis of oil and gas properties. The April 30, 2011 ceiling test was based on the average of the first-day-of-the-month prices during the twelve-month period prior to April 30, 2011 pursuant to the SEC’s “Modernization of Oil and Gas Reporting” rule, which was effective for the Company beginning

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with October 31, 2010 reporting. If unamortized costs capitalized within a cost center, less related deferred income taxes, exceed the cost center ceiling, the excess shall be charged to expense and separately disclosed during the period in which the excess occurs. Amounts thus required to be written off shall not be reinstated for any subsequent increase in the cost center ceiling.

At April 30, 2011 and 2010, no ceiling test write-down was required.

3. STOCK-BASED COMPENSATION

For the six months ended April 30, 2011 and 2010, the Company recognized stock based compensation expense of $38,000 and $34,000 respectively. For three months ended April 30, 2011 and 2010, the Company recognized stock based compensation expense of $21,000 and $27,000, respectively. The estimated unrecognized compensation cost from unvested stock options as of April 30, 2011 was approximately $243,000 which is expected to be recognized over an average of 2.5 years.

The fair value of the 30,000 options granted during the three months ended April 30, 2011 was estimated as of the grant date using the Black-Scholes option pricing model with the following assumptions: volatility, 50.1%; expected option term, 4 years; risk-free interest rate, 2.28% 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 estimate will also be included in compensation expense.

Plan activity for the six months ended April 30, 2011 is set forth below:

	Six Months Ended April 30, 2011
			Weighted
			Average			Aggregate
	Number of		Exercise			Intrinsic
	Options		Price			Value
Outstanding at October 31, 2010	179,063		$	8.40		$	184,000
Granted	30,000		12.45			—
Exercised	(10	)	5.93			—
Cancelled or forfeited	—		—			—
Outstanding at April 30, 2011	209,053		$	8.98		$	609,000

Exercisable at April 30, 2011	145,720		$	8.20		$	535,000

Weighted average contractual life at April 30, 2011			5.46		years

	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	2011	Life in Years	Price		2011	Exercise Price

$ 5.93	89,053	2.12	$	5.93	89,053	$	5.93
$ 9.30	50,000	8.67	$	9.30	16,667	$	9.30
$ 12.45	30,000	9.88	$	12.45	—	$	12.45
$ 12.78	40,000	5.60	$	12.78	40,000	$	12.78

$ 5.93 -$12.78	209,053		$	8.98	145,720	$	8.20

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4. OIL AND NATURAL GAS DERIVATIVES

The Company manages exposure to commodity price fluctuations by periodically hedging a portion of estimated production. These transactions typically take the form of costless collars for oil, and forward short positions for natural gas based upon the NYMEX futures market, which are closed by purchasing offsetting positions. Such contracts do not exceed estimated production volumes and are authorized by the Company’s Board of Directors. Contracts are expected to relate to the timing of actual production 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.

At April 30, 2011, the Company held costless collar derivative contracts for 5,000 barrels of oil for each production month of May through December 2011 with a floor price of $80.00 and an average ceiling price of $92.80 per barrel. The Company also held costless collar derivative contracts for 3,000 barrels of oil for each production month of January through December 2012 with a floor price of $80.00 and an average ceiling price of $95.67 per barrel. Based on second quarter 2011 production, the hedges cover about 45% of the Company’s remaining 2011 oil production and 27% of the Company’s 2012 production. However, the Company expects future oil production to increase and the actual percentages hedged to be lower.

For the six months ended April 30, 2011 and 2010, the Company had realized gains (losses) on derivatives of ($78,000) and $3,000, respectively, and unrealized gains (losses) of ($1,577,000) and $24,000, respectively. For the quarters ended April 30, 2011 and 2010, the Company had realized gains (losses) on derivatives of ($114,000) and $13,000, respectively, and unrealized gains (losses) of ($836,000) and $28,000, respectively.

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 available is $7,200,000 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 funded debt in excess of $500,000. The line expires May 1, 2013.

The Company has elected not to designate its commodity derivatives as cash flow hedges for accounting purposes. Accordingly, such contracts are recorded at fair value on the balance sheet and changes in fair value are recorded in the statement of operations as they occur. The location and amount of derivative fair values and related gain (loss) are indicated in the following tables:

Derivatives not designated as hedging instruments:

Amount of Gain or (Loss) Recognized in Income on Derivatives:

Derivatives not designated as hedging instruments:

	Location of Gain/(Loss)	Six Months
	Recognized in	Ended
	Income (Loss) on Derivatives	April 30, 2011
Natural Gas Forward Positions	Other Income and (Expense)	$	79,000
Natural Gas Basis Positions	Other Income and (Expense)	(20,000		)
Crude Oil Collars	Other Income and (Expense)	(1,714,000		)

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5. 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 effect of percentage depletion deductions is the primary cause of the variation of the effective tax rate from the statutory rate.

The total future deferred income tax liability is 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.

As of April 30, 2011 the Company’s 2008 Federal tax return was under audit by the IRS. The Company remains subject to examination of 2006 and 2009 Federal and 2006 through 2009 state tax returns, except Colorado, in which the 2005 tax year also remains open.

6. FAIR VALUE MEASUREMENTS

The Company utilizes derivative contracts to hedge against the variability in cash flows associated with the forecasted sale of its anticipated future natural gas production. These derivatives are carried at fair value on the consolidated balance sheets. Additionally, the Company’s short-term investments consist primarily of professionally managed limited partnerships which include investments that are not publicly traded and may have less readily determinable market values. Accounting standards established a valuation hierarchy for disclosure of the inputs to valuation used to measure fair value. This hierarchy prioritizes the inputs into three broad levels as follows:

· Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities.

· Level 2 inputs are quoted prices for similar assets and liabilities in active markets or inputs that are observable for the asset or liability, either directly or indirectly through market corroboration, for substantially the full term of the financial instrument.

· Level 3 inputs are measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources.

The classification of financial asset or liability within the hierarchy is determined based on the lowest level input that is significant to the fair value measurement. The determination of the fair values below incorporates various factors required under fair value accounting guidance, including the impact of the counterparty’s non-performance risk with respect to the Company’s financial assets and the Company’s non-performance risk with respect to the Company’s financial liabilities. The following table provides the assets and liabilities carried at fair value measured on a recurring basis as of April 30, 2011:

	As of April 30, 2011
	Level 1		Level 2		Level 3		Total
	(in thousands)
Asset:
Short-term investments	$	1,966	$	—	$	34	$	2,000
Derivative Liability-Current	$	—	$	1,096	$	—	$	1,106
Derivative Liability-Non Current	$	—	$	450	$	—	$	475

Level 3 instruments are comprised of the Company’s investments in professionally managed limited partnerships. The fair value represents the net asset value of the Company’s share in each partnership.

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The Company identified the investments as Level 3 instruments due to the fact that quoted prices for the underlying investments in the partnerships cannot be obtained and there is not an active market for the underlying investments or the partnerships shares. The Company utilizes the periodic fund statements along with current fund redemption activity and communication with investment advisors to determine the valuation of its investment. All of the Level 3 investments are in the process of liquidation, and redemption.

The following table sets forth a reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy for the three and six months ended April 30, 2011:

	Three Months Ended			Six Months Ended
	April 30, 2011			April 30, 2011

Balance as of January 31, 2010, and October 31, 2010(1), respectively	$	120,000		$	125,000
Total gains or losses (realized or unrealized):
Included in earnings(2)	0			2,000
Redemptions	(86,000		)	(93,000		)
Balance as of April 30, 2011(1)	$	34,000		$	34,000

(1) This amount is included in short term investments on the balance sheet.

(2) This amount is included in investment and other income (expense) on the statement of operations.

7. INTANGIBLE ASSETS

The patents underlying the Calliope Gas Recovery System are carried as a non-current asset on the Company’s balance sheet and are being amortized over the average remaining life of the patents. The Company periodically evaluates this asset for realizability.

The Company recently completed a Calliope installation on a dead well and revived production as expected.

The Company believes that the number of anticipated future installations will be sufficient to demonstrate recoverability of the cost. If the Company is unable to achieve the expected level of installations, the Company may in the future be required to record an impairment of the asset. Should this event occur, it would be a non-cash charge to income and would have no effect on working capital.

	April 30, 2011
	Gross Carrying		Accumulated
	Amount		Amortization
Amortized intangible assets:
Calliope intangible assets	$	4,449,000	$	1,089,000

Aggregate amortization expense:
For the six months ended April 30, 2011			$	217,000

8. COMMON STOCK

On September 22, 2008, the Company’s Board of Directors authorized a Stock Repurchase Program and approved repurchase of the Company’s common stock up to $2,000,000. On April 9, 2009, the Board expanded the program to $4,000,000 and on July 29, 2010 the program was expanded to $5,000,000. The repurchases may be made on the open market, in block trades or otherwise. The stock repurchase program may be expanded, suspended or discontinued at any time. At April 30, 2011, the Company has acquired

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545,429 shares under the program, at an aggregate cost of $4,755,000, or $8.72 per share.

Subsequent to April 30, 2011 and through June 10, 2011, no additional shares have been repurchased.

9. EARNINGS PER SHARE

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

	Six Months Ended April 30,
	2011					2010
	Net			Earnings		Net			Earnings
	Income		Shares	Per Share		Income		Shares	Per Share
Basic earnings per share	$	424,000	10,042,000	$	.04	$	1,242,000	10,140,000	$	.12

Effect of dilutive shares of common stock from stock options	—		36,000	—		—		39,000	—

Diluted earnings per share	$	424,000	10,078,000	$	.04	$	1,242,000	10,179,000	$	.12

	Three Months Ended April 30,
	2011					2010
	Net			Earnings		Net			Earnings
	Income		Shares	Per Share		Income		Shares	Per Share
Basic earnings per share	$	255,000	10,041,000	$	.03	$	603,000	10,187,000	$	.06
Effect of dilutive shares of common stock from stock options	—		47,000	—		—		18,000	—

Diluted earnings per share	$	255,000	10,089,000	$	.03	$	603,000	10,205,000	$	.06

10. CONCENTRATION OF CREDIT RISK

CREDO’s accounts receivable are primarily from purchasers of the Company’s oil and natural gas production and from other exploration and production companies which own joint working interests in the properties that the Company operates. This industry concentration could adversely impact the Company’s overall credit risk, because the Company’s customers and working interest owners may be similarly affected by changes in economic and financial market conditions, commodity prices, and other conditions. CREDO’s oil and gas production is sold to various purchasers in accordance with the Company’s credit policies and procedures. These policies and procedures take into account, among other things, the creditworthiness of potential purchasers and concentrations of credit risk. For most joint working interest partners, the Company may have the right of offset against related oil and natural gas revenues.

11. COMMITMENTS AND CONTINGENCIES

The Company has been named as a defendant in a lawsuit brought by a former employee. The suit alleges breach of contract and other employment issues together with material damages. Although the Company believes plaintiff’s claims are without merit and that the Company will prevail, the ultimate outcome of

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this lawsuit cannot be determined at this time. A trial date has been scheduled for August, 2011.

The Company has no material outstanding commitments at April 30, 2011.

ITEM 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

OPERATIONS

Summary

During the first half of fiscal 2011, the Company’s operations continued to focus on its two core projects — oil and 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 2011, 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 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.

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.

RESULTS OF OPERATIONS

Six Months Ended April 30, 2011 Compared to Six Months Ended April 30, 2010

For the six months ended April 30, 2011, oil and gas revenues increased 20% to $7,318,000 compared to $6,087,000 during the same period last year. As the oil and gas price/volume table on page 15 shows, oil sales prices increased 20% to $86.97 per barrel and natural gas sales prices decreased 10% to $4.39 per Mcf. The net effect of these price changes was to increase oil and gas sales by $426,000. For the six months ended April 30, 2011, the Company’s oil production increased 26% to 61,200 barrels while natural gas production declined 13% to 455,000 Mcf. Total production, at a 6 to 1 gas to oil energy equivalent conversion ratio, increased slightly to 137,100 barrels of oil equivalent (BOE). The increased total production volume resulted in a revenue increase of $805,000. For the six month period, the Company had realized derivative losses of $78,000 at April 30, 2011 compared to gains of $3,000 April 30, 2010. The Company had unrealized derivative losses of $1,577,000 at April 30, 2011, compared to unrealized derivative gains of $24,000 at April 30, 2010. At April 30, 2011, unrealized derivative losses are related to costless collar derivative contracts for oil.

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For the six months ended April 30, 2011, total costs and expenses increased 15% to $5,171,000 compared to $4,500,000 for the comparable period in 2010. Oil and gas production expenses increased 11% primarily due to production taxes on increased revenue together with the increased number of operating wells. DD&A increased primarily due to an increase in the amortizable base. General and administrative expenses increased primarily due to legal and professional fees and salaries and benefits. The effective tax rate was 23% and 25% for the six months ended April 30, 2011 and 2010, respectively. The effect of percentage depletion deductions is the primary cause of the variation of the effective tax rate from the statutory rate.

Three Months Ended April 30, 2011 Compared to Three Months Ended April 30, 2010

For the three months ended April 30, 2011, oil and gas revenues increased 38% to $4,068,000 compared to $2,945,000 during the same period last year. As the oil and gas price/volume table on page 15 shows, oil sales prices increased 29% to $93.07 per barrel and natural gas sales prices decreased 4% to $4.44 per Mcf. The net effect of these price changes was to increase oil and gas sales by $478,000. For the three months ended April 30, 2011, the Company’s oil production increased 33% to 33,200 barrels while natural gas production declined 10% to 221,000 Mcf. Total production, at a 6 to 1 gas to oil energy equivalent conversion ratio, increased 6% to 70,100 BOE, resulting in a revenue increase of $646,000. For the three months ended April 30, 2011 and 2010, the Company had realized gains (losses) on derivatives of ($114,000) and $13,000, respectively, and unrealized gains (losses) of ($836,000) and $28,000, respectively. Unrealized derivative losses at April 30, 2011 are related to costless collar derivative contracts for oil.

For the three months ended April 30, 2011, total costs and expenses increased 26% to $2,825,000 compared to $2,237,000 for the comparable period in 2010. Oil and gas production expenses increased 20% primarily due to production taxes on increased revenue together with an increased number of operating wells. DD&A increased primarily due to an increase in the amortizable base. General and administrative expenses increased primarily due to legal and professional fees and salaries and benefits. The effective tax rate was 22% and 24% for the 2011 and 2010 periods, respectively. The effect of percentage depletion deductions is the primary cause of the variation of the effective tax rate from the statutory rate.

LIQUIDITY AND CAPITAL RESOURCES

For the six months ended April 30, 2011, net cash provided by operating activities was $3,700,000 compared to $2,144,000 for the same period in 2010. For the six months ended April 30, 2011 and 2010, net cash used in investing activities was $7,640,000 and $3,596,000, respectively. Investing activities primarily included oil and gas lease acquisition, exploration and development expenditures.

The Company is executing the most aggressive drilling program in its history. As a result, cash and short term investments are being rapidly utilized as expected and budgeted. As a result, working capital has declined from $9,661,000 at October 31, 2010 (fiscal year end) to $3,627,000 at April 30, 2011 (second quarter end). 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. However, in the event that unexpected drilling or other costs are incurred which deplete the Company’s cash on hand to the point of prudent borrowing being advisable to ensure uninterrupted future operations, the Company has ample borrowing capacity and has entered into preliminary discussions with its primary bank to establish a credit line. At April 30, 2011, the Company had no lines of credit or other bank financing arrangements except for the hedging line of credit discussed in Note 5 to the Financial Statements. 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.

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The Company’s adjusted earnings before interest, taxes, depreciation, depletion and amortization, and unrealized derivative gains and losses, (“Adjusted EBITDA”) was $4,269,000 for the six months ended April 30, 2011 compared to $3,356,000 for the six months ended April 30, 2010. Adjusted 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 Adjusted EBITDA is not a GAAP measure, it may not necessarily be comparable to similarly titled measures employed by other companies. Reconciliation between Adjusted EBITDA and net income is provided in the table below:

	Six Months Ended April 30,
	2011		2010

RECONCILIATION OF ADJUSTED EBITDA:
Net Income	$	424,000	$	1,242,000
Add Back):
Income Tax Expense	127,000		415,000
Depreciation, Depletion and Amortization Expense	2,141,000		1,723,000
Unrealized Derivative Losses (Gains)	1,577,000		(24,000		)

ADJUSTED EBITDA	$	4,269,000	$	3,356,000

OFF-BALANCE SHEET FINANCING

The Company has no off-balance sheet arrangements at April 30, 2011.

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 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.

The oil and natural gas average sales prices reflected in the table below exclude the effects of commodity derivative instruments since the Company has elected not to designate derivative instruments as cash flow hedges. See Note 4 of the Notes to Consolidated Financial Statements and comments at “Results of Operations” for more information on gains and losses relating to commodity derivative instruments.

	Six Months Ended April 30,
	2011			2010			% Change
Product	Volume	Price		Volume	Price		Volume		Price

Oil (bbls)	61,200	$	86.97	48,500	$	72.74	+26	%	+20	%
Gas (Mcf)	455,000	$	4.39	523,000	$	4.89	-13	%	-10	%
BOE (Barrels of Oil Equivalent)	137,100			135,700			+1	%

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	Three Months Ended April 30,
	2011			2010			% Change
Product	Volume	Price		Volume	Price		Volume		Price

Oil (bbls)	33,200	$	93.07	25,000	$	72.31	+33	%	+29	%
Gas (Mcf)	221,000	$	4.44	248,000	$	4.60	-11	%	-3	%
BOE (Barrels of Oil Equivalent)	70,100			66,200			+6	%

OIL AND NATURAL GAS PRICE HEDGING

The Company enters into derivative contracts, primarily costless collars, to hedge future crude oil production. The collars consist of options (puts and calls) that convert into the underlying monthly futures contract on the day before the futures contract expires. The primary objective of the company’s oil hedging activities is to ensure a portion of its cash flow to fund its drilling program, which is the most aggressive in the Company’s history. At April 30, 2011, the Company held costless collar derivative contracts for 5,000 barrels of oil for each production month of May through December 2011 with a floor price of $80.00 and an average ceiling price of $92.80 per barrel. The Company also held costless collar derivative contracts for 3,000 barrels of oil for each production month of January through December 2012 with a floor price of $80.00 and an average ceiling price of $95.67 per barrel. Based on second quarter 2011 production, the hedges cover about 45% of the Company’s remaining 2011 oil production and 27% of the Company’s 2012 production. However, the Company expects future oil production to increase and the actual percentages hedged to be lower.

For the six months ended April 30, 2011, hedge contracts which have expired resulted in losses of $78,000 in 2011 and gains of $3,000 for the same period last year. Hedge contracts which are outstanding at April 30, 2011 must be priced for financial reporting purposes based on the open option contracts (offsetting puts and calls) which sometimes include a significant speculative premium. Such pricing resulted in an unrealized loss of $1,577,000 at April 30, 2011 compared to an unrealized gain of $24,000 at April 30, 2010. The company cannot reasonably estimate what the underlying futures contract prices will be when the options actually expire for each month of production that is hedged.

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. All costs incurred in the acquisition, exploration, and development of properties (including costs of surrendered and abandoned leaseholds, delay lease rentals, dry holes, and overhead related to exploration and development activities) and the fair value of estimated future costs of site restoration, dismantlement, and abandonment activities are capitalized. Costs for unevaluated properties, which typically include lease rentals, geology and seismic costs, are capitalized but are excluded from amortizable costs during the evaluation period. When determinations are made whether the property has proved recoverable reserves or not, or if there is an impairment, the costs are reclassified to amortizable costs..

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current prices (as discussed below), excluding the future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, at a discount factor of 10%; plus (2) the cost of properties not being amortized, if any; plus (3) the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any; less (4) income tax effects related to differences in the book and tax basis of oil and gas properties. The April 30, 2011 ceiling test was based on the average of the first-day-of-the-month prices during the twelve-month period prior to April 30, 2011 pursuant to the SEC’s “Modernization of Oil and Gas Reporting” rule, which was effective for the Company beginning with October 31, 2010 reporting. If unamortized costs capitalized within a cost center, less related deferred income taxes, exceed the cost center ceiling, the excess shall be charged to expense and separately disclosed during the period in which the excess occurs. Amounts thus required to be written off shall not be reinstated for any subsequent increase in the cost center ceiling.

SUPPLEMENTAL INFORMATION

PROVED RESERVES

The following information related to the Company’s proved oil and natural gas reserves as of October 31, 2010 is presented to provide details of the proved developed and proved undeveloped reserve quantities in accordance with Item 1202(a)(2) of Regulation S-K.

		Natural
Proved Reserves	Oil (Bbls)	Gas (Mcf)	Total (BOE)(1)

Developed	501,000	8,791,000	1,996,000
Undeveloped	453,000	4,967,000	1,281,000
Total	954,000	13,938,000	3,277,000

(1) Natural gas is converted to barrels of oil equivalent using a conversion of six Mcf “equivalent” per barrel of oil. This conversion is based on energy equivalence and not price equivalence. For fiscal year 2010, the average of the first-day-of-the-month oil price was $68.30 per barrel, and the average of the first-day-of-the-month gas price was $4.49 per Mcf.

Oil reserves increased 9% and currently account for 29% of the Company’s total proved reserves. No gas wells were drilled in 2010 resulting in a 7% decline in gas reserves. The decline in gas reserves more than offset the 9% increase in oil reserves and resulted in a 3% decrease in total reserves, based on the industry standard six Mcf of gas to one barrel of oil conversion rate.

As of October 31, 2010, proved undeveloped reserves (“PUDs”) were estimated to be 1,281,000 BOE, or 39% of estimated proved reserves, compared to 1,307,000 BOE, or 39% of estimated proved reserves as of October 31, 2009. No significant proved undeveloped reserves were converted to proved developed reserves during fiscal year 2010. The net decrease of 26,000 BOE was primarily due to a decision not to develop certain natural gas reserves. The Company is scheduled to convert the PUDs disclosed as of October 31, 2010 to proved developed reserves within five years of the date they were initially disclosed as PUDs.

CONTROLS AND PROCEDURES

“Our Annual Report on Form 10-K for the year ended October 31, 2010 included the following disclosure in the section entitled ‘Management’s Annual Report on Internal Control over Financial Reporting’:

Under the supervision and with the participation of our management, including our CEO and CFO, we assessed our internal control over financial reporting as of October 31, 2010, the end of our fiscal year. This assessment was based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our assessment, management has concluded that our internal control over financial reporting was effective as of October 31, 2009.

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The reference to 2009 in the second sentence of the foregoing is incorrect and the sentence should read ‘Based on our assessment, management has concluded that our internal control over financial reporting was effective as of October 31, 2010.’”

RECENT DRILLING ACTIVITIES

Bakken Shale — Credo has leased approximately 8,000 gross (6,000 net) acres on the Ft. Berthold Reservation containing about 50 initial drillable spacing units, however, it is expected that more than one well will be drilled on many spacing units. The Company’s interests range up to 51% depending on the size of the spacing unit. The Company’s acreage is generally located south and west of Parshall Field and is in the vicinity of considerable Bakken drilling and development activity. The Reservation is surrounded on three sides by horizontal Bakken production, and drilling activity on the Reservation continues to escalate rapidly.

As of April 30, 2011, the Company has drilled and completed a total of seven Bakken producers on its acreage. All of the wells are high rate producers. Credo expects to drill at least nine additional Bakken wells during 2011. The Company’s interest in six of the nine additional wells will range from 12% to 20%.

At April 30, 2011, the Company’s first Bakken horizontal well, the Petro Hunt 148-94-17D-08-1H (“17-D”) located on the Fort Berthold Reservation, has been on production for approximately fifteen months and has produced about 113,000 BOE. Petro Hunt has not yet indicated development plans for the 1,280 acre spacing unit. Credo owns a 10% working interest.

The Company’s second Bakken well (Brigham Weisz 11-14) has produced approximately 84,000 BOE in nine months. The well is located about 50 miles northwest of the Petro-Hunt 17-D in Williams County. Credo owns a 6.25% working interest in the well. Brigham’s development plans for the 1,280 acre spacing unit could potentially include three additional Bakken wells and up to four Sanish/Three Forks wells.

The Company’s third Bakken well located on the Fort Berthold Reservation (Petro-Hunt 3-A) has produced 67,000 BOE in five months. While the well was drilled in fiscal 2010, the completion phase was delayed until December, 2010 due to shortages of fracture stimulation equipment. Credo owns an 18.75% working interest in the well.

The Company has recently added four new horizontal Bakken wells on the Ft. Berthold Reservation. While Credo’s working interests in the new wells are small, ranging from 1% to 3%, the Company’s share of initial production from the four wells is approximately 140 barrels of oil equivalent per day (BOEPD). One of these wells, the Enerplus Ethan Hall, reported an initial production rate of 3,732 BOEPD, which is the highest initial rate of any Credo Bakken well drilled to date and ranks among the highest rates in the play.

Kansas and Nebraska — In Kansas and Nebraska, the Company owns interests in approximately 145,000 gross acres and 82,000 net acres and it is continuing to expand its acreage position. At April 30, 2011, the Company has participated in drilling 83 wells on its acreage, of which 41% have been successfully completed as producers. The Company’s Kansas and Nebraska drilling activities provide diversification to the Company’s drilling program through the use of detailed subsurface geology and 3-D seismic to identify shallow oil prospects. The Company is also re-entering previously abandoned wells to test potentially productive oil zones which it believes were bypassed.

Since first quarter-end, the Company has drilled nine wells in Kansas and Nebraska, of which six, or 67%, are either producing or being completed for production. The Company owns working interests ranging

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from 70% to 75% in four of the six new wells, making the new production meaningful in terms of the Company’s interest in the wells.

In Kansas, two of the new producing wells both initially tested at approximately 50 barrels of oil per day. Credo owns a 75% working interest in one of the wells and 12.5% in the other well. A third well located in Kansas is currently being completed for production. During drilling, the well tested significant amounts of oil with good pressures. Credo is the operator and owns a 46.5% working interest.

In southwestern Nebraska, the Company drilled and successfully completed three wells subsequent to April 30, 2011. After completion, the wells initially tested 50 BOPD, 100 BOPD and 200 BOPD, respectively. The Company is the operator of the three wells and owns a 70% working interest in each well.

The Company expects to continue conducting an active drilling program in Kansas and Nebraska, consisting of two to three wells per month for the next few years, with average working interests of approximately 50% or more.

Texas Panhandle — In the Texas Panhandle, the Company owns an average 33% working interest in about 3,000 gross acres. The Company’s first horizontal well was drilled to a vertical depth of 7,600-feet and has an approximate 4,000-foot horizontal lateral. The well is producing oil from the Tonkawa formation, and Credo owns a 22% working interest in the well. Fracture stimulation fluids are continuing to be recovered. The well is currently producing approximately 180 barrels of oil equivalent per day and has produced approximately 22,500 BOE in six months.

The Company’s second horizontal Tonkawa well in the Texas Panhandle was also drilled to a vertical depth of 7,600 feet and encountered sloughing shale about 2,400 feet into the projected 4,000-foot lateral. Because the well had previously encountered good quality sand and very good shows, the decision was made to cease drilling operations at about 2,400 feet and set pipe. The well was hydraulically fractured and, at April 30, 2011, was recovering frac fluid with a steadily increasing oil cut. Currently the well is producing approximately 100 BOE per day and has produced approximately 4,500 BOE in two months. Credo is the operator and owns a 32% working interest.

Calliope Gas Recovery Technology

Credo remains committed to monetizing its patented Calliope Gas Recovery System. During March 2011, Calliope was successfully installed on the Carmella State well located in Harper County, Oklahoma. Calliope has eliminated downtime due to liquid loading, and increased production to a steady rate of 150 Mcfd. Credo is the operator of the well and owns an 85% working interest. Final paperwork is currently in progress to purchase another well for Calliope, and the Company is actively pursuing other acquisition opportunities. Calliope also continues to generate interest from new players with fresh ideas as rapidly growing international companies seek innovative solutions to capture energy reserves.

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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 include, among other things, statements relating to:

· the Company’s future financial position, including working capital and anticipated cash flow;

· amounts and nature of future capital expenditures;

· projections of operating costs and other expenses;

· wells to be drilled or reworked including new drilling expectations;

· expectations regarding oil and natural gas prices and demand;

· existing fields, wells and prospects;

· diversification of exploration, capital exposure, risk and reserve potential of drilling activities;

· estimates of proved oil and natural gas reserves;

· expectations and projections regarding joint ventures;

· reserve potential;

· development and drilling potential;

· expansion and other development trends in the oil and natural gas industry;

· the Company’s business strategy;

· production and production potential of oil and natural gas;

· matters related to the Calliope Gas Recovery System, including projections for future use of Calliope and the success of Calliope;

· effects of federal, state and local regulation;

· the outcome of judicial or regulatory proceedings

· adequacy of insurance coverage;

· employee relations;

· effectiveness of the Company’s hedging transactions;

· investment strategy and risk; and

· expansion and growth of the Company’s business and operations.

Although the Company believes that the expectations reflected in such forward-looking statements are reasonable, it can give no assurance that such expectations will prove to be correct. Disclosure of important factors that could cause actual results to differ materially from the Company’s expectations, or cautionary statements, are included under “Risk Factors” in our Annual Report on Form 10-K. The following factors, among others, could cause actual results to differ materially from the Company’s expectations:

· unexpected changes in business or economic conditions;

· significant changes in natural gas and oil prices;

· timing and amount of production;

· unanticipated down-hole mechanical problems in wells or problems related to producing reservoirs or infrastructure;

· changes in overhead costs;

· material events resulting in changes in estimates; and

· competitive factors.

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All forward-looking statements speak only as of the date made. All subsequent written and oral forward-looking statements attributable to the Company, or persons acting on the Company’s behalf, are expressly qualified in their entirety by the cautionary statements. Except as required by law, the Company undertakes no obligation to update any forward-looking statement to reflect events or circumstances after the date on which it is made or to reflect the occurrence of anticipated or unanticipated events or circumstances.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The Company manages exposure to commodity price fluctuations by periodically hedging a portion of estimated production when the potential for significant downward price movement is anticipated. These transactions typically take the form of costless collars for oil and forward short positions based upon the NYMEX futures market for natural gas, and are closed by purchasing offsetting positions. Such contracts do not exceed estimated production volumes and are authorized by the Company’s Board of Directors. Contracts 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.

For further discussion, see Note 4 to the Consolidated Financial Statements.

ITEM 4. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

Our management, with the participation of Marlis E. Smith, Jr., our Chief Executive Officer, and Alford B. Neely, our Chief Financial Officer, evaluated the effectiveness of our disclosure controls and procedures as of April 30, 2011. Based on the evaluation, these officers have concluded that:

Our disclosure controls and procedures are effective to ensure that information required to be disclosed by us in the reports we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms; and

Our disclosure controls and procedures were effective to ensure that information required to be disclosed by us in the reports we file or submit under the Securities Exchange Act of 1934 was accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

Internal Control Over Financial Reporting

There has not been any change in our internal control over financial reporting that occurred during the quarter ended April 30, 2011 that has materially affected or is reasonably likely to materially affect, our internal control over financial reporting.

PART II - OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Reference is made to “Notes to Consolidated Financial Statements (Unaudited) — Note 11, Commitments and Contingencies”, in Part I, Item I of this Form 10-Q and incorporated by reference in this Part II, Item I.

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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, 2010.

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

Issuer Purchases of Equity Securities.

During the first quarter of fiscal year 2011, the Company repurchased 18,000 shares of its common stock on the open market at a weighted average price of $8.04. The purchases were made pursuant to a stock repurchase plan announced on September 24, 2008 and extended by the Board of Directors on April 9, 2009 and July 29, 2010. The extended plan authorized repurchases up to $5,000,000, but could be expanded, suspended or discontinued at any time. At April 30, 2011, the Company has repurchased 545,429 shares of common stock at an average price per share of $8.72.

No additional shares have been purchased subsequent to the first quarter, although the repurchase plan remains in effect.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

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/ Marlis E. Smith, Jr.
		Marlis E. Smith, Jr.
		Chief Executive Officer
		(Principal Executive Officer)

	By:	/s/ Alford B. Neely
		Alford B. Neely
		Chief Financial Officer
		(Principal Financial and Accounting Officer)


Date: June 9, 2011

As of April 30, 2011

Balance Sheet Location

Fair Value

Crude Oil Collars

Derivative Liability-Current

Crude Oil Collars

Derivative Liability-Non Current