Credo Petroleum (CRED) 10-Q 2011 Q3 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

(Mark One)

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

For the quarterly period ended July 31, 2011

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

CREDO PETROLEUM CORPORATION AND SUBSIDIARIES

Quarterly Report on Form 10-Q For the Period Ended July 31, 2011

TABLE OF CONTENTS

		Page No.
PART I - FINANCIAL INFORMATION
Item 1.	Financial Statements
Consolidated Balance Sheets
As of July 31, 2011 (Unaudited) and October 31, 2010		3
Consolidated Statements of Operations
For the Three and Nine Months Ended July 31, 2011 and 2010 (Unaudited)		5
Consolidated Statements of Cash Flows
For the Nine Months Ended July 31, 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	19
Item 4.	Controls and Procedures	20
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	21
Item 5.	Other Information	21
Item 6.	Exhibits	22
Signatures		22

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 (Unaudited)

A S S E T S

	July 31,			October 31,
	2011			2010
Current Assets:
Cash and cash equivalents	$	3,615,000		$	7,179,000
Short-term investments	1,985,000			1,990,000
Receivables:
Accrued oil and gas sales	2,676,000			1,574,000
Trade	383,000			479,000
Derivative assets	—			32,000
Other current assets	835,000			832,000
Total current assets	9,494,000			12,086,000
Long-term Assets:
Oil and gas properties, at cost, using full cost method:
Unevaluated oil and gas properties	9,856,000			8,801,000
Evaluated oil and gas properties	93,569,000			83,360,000
Less: accumulated depreciation, depletion and amortization of oil and gas properties	(59,381,000		)	(56,339,000		)
Net oil and gas properties, at cost, using full cost method	44,044,000			35,822,000
Intangible assets, net of accumulated amortization of $1,198,000 in 2011 and $872,000 in 2010	3,251,000			3,578,000
Compressor and tubular inventory to be used in development	1,661,000			1,855,000
Other, net	70,000			64,000
Total Assets	$	58,520,000		$	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

	July 31,			October 31,
	2011			2010
Current Liabilities:
Accounts payable	$	1,437,000		$	1,200,000
Revenue distribution payable	1,312,000			565,000
Accrued compensation	284,000			466,000
Other accrued liabilities	1,253,000			177,000
Derivative liability	310,000			—
Income taxes payable	17,000			17,000
Total current liabilities	4,613,000			2,425,000
Long Term Liabilities:
Deferred income taxes, net	3,942,000			3,281,000
Non-current derivative liability	155,000			—
Asset retirement obligation	1,210,000			1,132,000
Total liabilities	9,920,000			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	31,533,000			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	20,655,000			18,524,000
Total stockholders’ equity	48,600,000			46,567,000
Total Liabilities and Stockholders’ Equity	$	58,520,000		$	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)

	Nine Months Ended						Three Months Ended
	July 31,						July 31,
	2011			2010			2011			2010
Oil sales	$	8,678,000		$	5,252,000		$	3,358,000		$	1,722,000
Natural gas sales	3,128,000			3,752,000			1,130,000			1,195,000
	11,806,000			9,004,000			4,488,000			2,917,000
Costs and expenses:
Oil and natural gas production	2,893,000			2,480,000			1,059,000			822,000
Depreciation, depletion and amortization	3,401,000			2,648,000			1,260,000			925,000
General and administrative	2,016,000			1,629,000			820,000			510,000
	8,310,000			6,757,000			3,139,000			2,257,000
Income from operations	3,496,000			2,247,000			1,349,000			660,000
Other income and (expense)
Realized and unrealized gain (loss) from derivative contracts	(671,000		)	66,000			984,000			39,000
Investment and other income (loss)	55,000			52,000			(4,000		)	9,000
	(616,000		)	118,000			980,000			48,000
Income before income taxes	2,880,000			2,365,000			2,329,000			708,000
Income taxes	(749,000		)	(568,000		)	(622,000		)	(153,000		)
Net income	$	2,131,000		$	1,797,000		$	1,707,000		$	555,000
Earnings per share of Common Stock—Basic	$	.21		$	.18		$	.17		$	.06
Earnings per share of Common Stock—Diluted	$	.21		$	.18		$	.17		$	.06
Weighted average number of shares of Common Stock and dilutive securities:
Basic	10,042,000			10,179,000			10,041,000			10,146,000
Diluted	10,078,000			10,200,000			10,072,000			10,151,000

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)

	Nine Months Ended
	July 31,
	2011			2010
Cash Flows From Operating Activities:
Net income	$	2,131,000		$	1,797,000
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	3,401,000			2,648,000
ARO liability accretion	78,000			59,000
Unrealized (gain) loss on derivative instruments	497,000			(13,000		)
Deferred income taxes	661,000			568,000
Gain on short term investments	(47,000		)	(14,000		)
Compensation expense related to stock options granted	47,000			56,000
Changes in operating assets and liabilities:
Purchase of short term investments	(50,000		)	(1,500,000		)
Proceeds from short-term investments	102,000			194,000
Accrued oil and gas sales	(1,102,000		)	(74,000		)
Trade receivables	96,000			191,000
Other current assets	(3,000		)	273,000
Accounts payable and accrued liabilities	2,243,000			(690,000		)
Income taxes payable	—			(39,000		)
Net Cash Provided By Operating Activities	8,054,000			3,456,000
Cash Flows From Investing Activities:
Additions to oil and gas properties	(11,468,000		)	(6,100,000		)
Proceeds from sale of oil and gas properties	—			86,000
Changes in other long-term assets	(5,000		)	107,000
Net Cash Used In Investing Activities	(11,473,000		)	(5,907,000		)
Cash Flows From Financing Activities:
Purchase of treasury stock	(145,000		)	(1,638,000		)
Proceeds from exercise of stock options	—			297,000
Net Cash Used In Financing Activities	(145,000		)	(1,341,000		)
Decrease In Cash And Cash Equivalents	(3,564,000		)	(3,792,000		)
Cash And Cash Equivalents:
Beginning of period	7,179,000			12,348,000
End of period	$	3,615,000		$	8,556,000

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)

July 31, 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 nine months ended July 31, 2011 and 2010 were $3,042,000 and $2,292,000, respectively, and were $1,141,000 and $807,000 for the three months ended July 31, 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 July 31, 2011 ceiling test was based on the average of the first-day-of-the-month prices during the twelve-month period prior to July 31, 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 July 31, 2011 and 2010, no ceiling test write-down was required.

3.STOCK-BASED COMPENSATION

For the nine months ended July 31, 2011 and 2010, the Company recognized stock based compensation expense of $47,000 and $56,000 respectively.  For each of the three month periods ended July 31, 2011 and 2010, the Company recognized stock based compensation expense of $8,000.  The estimated unrecognized compensation cost from unvested stock options as of July 31, 2011 was approximately $82,000 which is expected to be recognized over an average of 1.4 years.

The fair value of the 30,000 options granted during the nine months ended July 31, 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%.  These options have been cancelled.  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 nine months ended July 31, 2011 is set forth below:

	Nine Months Ended July 31, 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	(30,000	)	12.45			—
Outstanding at July 31, 2011	179,053		$	8.40		$	370,000
Exercisable at July 31, 2011	145,720		$	8.20		$	353,000
Weighted average contractual life at July 31, 2011			4.48		years

	Outstanding				Exercisable
	Number	Weighted Average	Weighted		Number
Range of	Outstanding	Remaining	Average		Exercisable at	Weighted
Exercise	at July 31,	Contractual	Exercise		July 31,	Average
Prices	2011	Life in Years	Price		2011	Exercise Price
$ 5.93	89,053	1.87	$	5.93	89,053	$	5.93
$ 9.30	50,000	8.42	$	9.30	16,667	$	9.30
$12.78	40,000	5.35	$	12.78	40,000	$	12.78
$ 5.93 -$12.78	179,053		$	8.40	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 July 31, 2011, the Company held costless collar derivative contracts for 4,000 barrels of oil for each production month of August through December 2011 with a floor price of $80.00 and an average ceiling price of $91.62 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.  Subsequent to July 31, 2011 the company closed all of its oil derivative contracts for 2011 and 2012.  These transactions resulted in a realized gain of approximately $15,000, and reversal of $465,000 unrealized loss for the nine months ended July 31, 2011.

For the nine months ended July 31, 2011 and 2010, the Company had realized gains (losses) on derivatives of $174,000 and $53,000, respectively, and unrealized gains (losses) of ($497,000) and $13,000, respectively.  For the quarters ended July 31, 2011 and 2010, the Company had realized gains (losses) on derivatives of ($96,000) and $50,000, respectively, and unrealized gains (losses) of $1,080,000 and ($11,000), 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:

	As of July 31, 2011
	Balance Sheet Location	Fair Value
Crude Oil Collars	Derivative Liability-Current	$	310,000
Crude Oil Collars	Derivative Liability-Non Current	155,000

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

Derivatives not designated as hedging instruments:

	Location of Gain/(Loss)	Nine Months
	Recognized in	Ended
	Income (Loss) on Derivatives	July 31, 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)	(730,000		)

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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 July 31, 2011 the Company’s 2008 and 2009 Federal tax returns were under audit by the IRS.  The Company remains subject to examination of 2006 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 July 31, 2011:

	As of July 31, 2011
	Level 1		Level 2		Level 3		Total
	(in thousands)
Asset:
Short-term investments	$	1,960	$	—	$	25	$	1,985
Derivative Liability-Current	$	—	$	310	$	—	$	310
Derivative Liability-Non Current	$	—	$	155	$	—	$	155

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.  The Company identified the investments as Level 3 instruments due to the fact that quoted prices for the

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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 nine months ended July 31, 2011:

	Three Months Ended			Nine Months Ended
	July 31, 2011			July 31, 2011
Balance as of April 30, 2011, and October 31, 2010(1), respectively	$	34,000		$	125,000
Total gains or losses (realized or unrealized):
Included in earnings(2)	1,000			3,000
Redemptions	(10,000		)	(103,000		)
Balance as of July 31, 2011(1)	$	25,000		$	25,000

(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.

	July 31, 2011
	Gross Carrying		Accumulated
	Amount		Amortization
Amortized intangible assets:
Calliope intangible assets	$	4,449,000	$	1,198,000
Aggregate amortization expense:
For the nine months ended July 31, 2011			$	326,000

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 July 31, 2011, the Company has acquired 545,429 shares under the program, at an aggregate cost of $4,755,000, or $8.72 per share.

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Subsequent to July 31, 2011 and through September 9, 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:

	Nine Months Ended July 31,
	2011					2010
	Net			Earnings		Net			Earnings
	Income		Shares	Per Share		Income		Shares	Per Share
Basic earnings per share	$	2,131,000	10,042,000	$	.21	$	1,797,000	10,179,000	$	.18
Effect of dilutive shares of common stock from stock options	—		36,000	—		—		21,000	—
Diluted earnings per share	$	2,131,000	10,078,000	$	.21	$	1,797,000	10,200,000	$	.18

	Three Months Ended July 31
	2011					2010
	Net			Earnings		Net			Earnings
	Income		Shares	Per Share		Income		Shares	Per Share
Basic earnings per share	$	1,707,000	10,041,000	$	.17	$	555,000	10,146,000	$	.06
Effect of dilutive shares of common stock from stock options	—		31,000	—		—		5,000	—
Diluted earnings per share	$	1,707,000	10,072,000	$	.17	$	555,000	10,151,000	$	.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

Prior to the trial date of a lawsuit brought by a former employee, a preliminary settlement agreement was entered into by the parties.  The incremental settlement cost to the Company, net of insurance proceeds, is approximately $183,000, which is included in general and administrative expenses for the three months ended July 31, 2011.  Insurance recoveries are included in other current assets.  The Company does not

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believe it will be responsible for any further material costs associated with this suit, but cannot be certain that additional legal fees will not be incurred.

The Company has no material outstanding commitments at July 31, 2011.

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

OPERATIONS

Summary

During the first nine months 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

Nine Months Ended July 31, 2011 Compared to Nine Months Ended July 31, 2010

For the nine months ended July 31, 2011, oil and gas revenues increased 31% to $11,806,000 compared to $9,004,000 during the same period last year.  As the oil and gas price/volume table on page 15 shows, oil sales prices increased 23% to $87.49 per barrel and natural gas sales prices decreased 5% to $4.53 per Mcf.  The net effect of these price changes was to increase oil and gas sales by $982,000.  For the nine months ended July 31, 2011, the Company’s oil production increased 35% to 99,200 barrels while natural gas production declined 12% to 690,000 Mcf.  Total production, at a 6 to 1 gas to oil energy equivalent conversion ratio, increased 5% to 214,300 barrels of oil equivalent (BOE).  The increased total production volume resulted in a revenue increase of $1,820,000.  For the nine month period, the Company had realized derivative losses of $174,000 at July 31, 2011 compared to gains of $53,000 at July 31, 2010. Unrealized derivative losses for the nine months ended July 31, 2011 were $497,000, compared to gains of $13,000 for the prior year.  At July 31, 2011, unrealized derivative losses are related to costless collar derivative contracts for oil.

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For the nine months ended July 31, 2011, total costs and expenses increased 23% to $8,310,000 compared to $6,757,000 for the comparable period in 2010.  Oil and gas production expenses increased 17% 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 due to legal and professional fees and the settlement of a lawsuit.  The effective tax rate was 26% and 24% for the nine months ended July 31, 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 July 31, 2011 Compared to Three Months Ended July 31, 2010

For the three months ended July 31, 2011, oil and gas revenues increased 54% to $4,488,000 compared to $2,917,000 during the same period last year.  As the oil and gas price/volume table on page 15 shows, oil sales prices increased 29% to $88.32 per barrel and natural gas sales prices increased 5% to $4.81 per Mcf. The net effect of these price changes was to increase oil and gas sales by $549,000.  For the three months ended July 31, 2011, the Company’s oil production increased 51% to 38,000 barrels while natural gas production declined 10% to 235,000 Mcf.  Total production, at a 6 to 1 gas to oil energy equivalent conversion ratio, increased 13% to 77,200 BOE, resulting in a revenue increase of $1,022,000.  For the three months ended July 31, 2011 and 2010, the Company had realized gains (losses) on derivatives of ($96,000) and $50,000, respectively, and unrealized gains (losses) of $1,080,000 and ($11,000), respectively.  Unrealized derivative gains at July 31, 2011 are due to costless collar derivatives.

For the three months ended July 31, 2011, total costs and expenses increased 39% to $3,139,000 compared to $2,257,000 for the comparable period in 2010.  Oil and gas production expenses increased 29% 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 due to legal and professional fees and the settlement of a lawsuit.  The effective tax rate was 27% and 22% 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 nine months ended July 31, 2011, net cash provided by operating activities was $8,054,000 compared to $3,456,000 for the same period in 2010.  For the nine months ended July 31, 2011 and 2010, net cash used in investing activities was $11,473,000 and $5,907,000, 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.  Working capital has declined from $9,661,000 at October 31, 2010 (fiscal year end) to $4,881,000 at July 31, 2011 (third 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 entered into preliminary discussions with its primary bank to establish a credit line.  At July 31, 2011, the Company had no lines of credit or other bank financing arrangements except for the hedging line of credit discussed in Note 4 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.

The Company’s adjusted earnings before interest, taxes, depreciation, depletion and amortization, and unrealized derivative gains and losses, (“Adjusted EBITDA”) was $6,778,000 for the nine months ended July 31, 2011 compared to $4,999,000 for the nine months ended July 31, 2010.  Adjusted EBITDA is not

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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:

	Nine Months Ended July 31,
	2011		2010
RECONCILIATION OF ADJUSTED EBITDA:
Net Income	$	2,131,000	$	1,797,000
Add Back):
Income Tax Expense	749,000		567,000
Depreciation, Depletion and Amortization Expense	3,401,000		2,648,000
Unrealized Derivative Losses (Gains)	497,000		(13,000		)
ADJUSTED EBITDA	$	6,778,000	$	4,999,000

OFF-BALANCE SHEET FINANCING

The Company has no off-balance sheet arrangements at July 31, 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.

	Nine Months Ended July 31,
	2011			2010			% Change
Product	Volume	Price		Volume	Price		Volume		Price
Oil (bbls)	99,200	$	87.49	73,600	$	71.35	+35	%	+23	%
Gas (Mcf)	690,000	$	4.53	783,000	$	4.79	-12	%	-5	%
BOE (Barrels of Oil Equivalent)	214,300			204,100			+5	%

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	Three Months Ended July 31,
	2011			2010			% Change
Product	Volume	Price		Volume	Price		Volume		Price
Oil (bbls)	38,000	$	88.32	25,100	$	68.66	+51	%	+29	%
Gas (Mcf)	235,000	$	4.81	260,000	$	4.60	-10	%	+5	%
BOE (Barrels of Oil Equivalent)	77,200			68,400			+13	%

OIL 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 July 31, 2011, the Company held costless collar derivative contracts for 4,000 barrels of oil for each production month of August through December 2011 with a floor price of $80.00 and an average ceiling price of $91.62 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.

Subsequent to July 31, 2011, the Company closed all of its derivative contracts for 2011 and 2012.  These transactions resulted in a realized gain of approximately $15,000, and reversal of $465,000 unrealized loss for the nine months ended July 31, 2011.

For the nine months ended July 31, 2011, hedge contracts which have expired resulted in losses of $174,000 in 2011 and gains of $53,000 for the same period last year.  Hedge contracts which are outstanding at July 31, 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 $497,000 for the period ended July 31, 2011 compared to an unrealized gain of $13,000 for the period ended July 31, 2010.

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.

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.

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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 July 31, 2011 ceiling test was based on the average of the first-day-of-the-month prices during the twelve-month period prior to July 31, 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.

RECENT DRILLING ACTIVITIES

Overview—During 2011, the Company is conducting the most aggressive drilling program in its history.  The 2011 drilling budget was increased by about 50% to $15,000,000, compared to $10,000,000 last year.  A total of 59 gross (26.3 net) wells are planned, representing a 149% increase in net wells over last year.  The Company’s average well ownership will be about 45% in 2011, up 43% over last year.  Vertical oil wells in Kansas and Nebraska comprise approximately two-thirds of the exploration budget, with the other one-third allocated to horizontal oil drilling in the North Dakota Bakken and Texas Panhandle.  Thirty one (31) of the 59 wells will be Company operated, a six-fold increase over last year.  The Company expects to fully fund its drilling from operating cash flow and cash on hand.

At July 31, 2011, a total of 36 gross wells had been drilled, of which approximately 70% were completed as producers.  Capital expenditures for the nine months totaled approximately $10,000,000.

The Company’s focus is almost exclusively on oil drilling because crude oil currently enjoys a nearly four to one energy equivalent price advantage over natural gas.  Natural gas production has declined since the Company has not drilled gas wells in about three years.

During 2011, the Company has also ramped-up activity on its Calliope Gas Recovery System through the purchase of wells, an installation on a Company-owned well, and discussions with other companies regarding installing Calliope on their wells.

Set forth below is certain information regarding the Company’s most significant drilling plays and its Calliope Gas Recovery System.

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 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.  Following weather related delays experienced earlier in the year, drilling activity on the Reservation is again rapidly escalating.

As of July 31, 2011, the Company has drilled and completed a total of eight Bakken wells on its acreage.  All of the wells are high rate producers.  Credo expects to drill at least five additional Bakken wells during 2011.  The Company’s interest in three of the five additional wells will range from 12% to 20%.

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

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July 31, 2011, the Company has participated in drilling 85 wells on its acreage, of which 40% 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.

During the quarter ended July 31, 2011, the Company drilled nine wells in Kansas and Nebraska, of which four, or 44%, are either producing or being completed for production.  The Company owns working interests ranging from 46%-80% in the four new producers, making the new production meaningful in terms of the Company’s interest in the wells.

Texas Panhandle — In the Texas Panhandle, the Company owns an average 33% working interest in about 3,000 gross acres.  The Texas Panhandle is a multi-pay environment with excellent Upper and Lower Cleveland potential in addition to the Tonkawa.  At July 31, 2011, the Company has drilled two horizontal Tonkawa wells and anticipates exploiting this potential in coming months with additional horizontal drilling.

Calliope Gas Recovery Technology

Credo remains committed to monetizing its patented Calliope Gas Recovery System.  During 2011, Credo has installed Calliope on two wells, one Company-owned and one purchased.  An installation is scheduled for a third well which was recently purchased by the company.  In March 2011, Calliope was successfully installed on the Carmella State well located in Harper County, Oklahoma.  The 7,500-foot well was loaded up with fluid and was only producing intermittently.  Calliope has eliminated downtime due to liquid loading, and increased production to a steady rate of 155 Mcfd.  Credo is the operator of the well and owns an 85% working interest.  A second installation was recently completed on the Ezell well located in Woodward County, Oklahoma.  The 8,000-foot well was producing about 55 Mcf of gas per day due to liquid loading, and Calliope is expected to return production to 150 to 200 Mcf of gas per day.  The system is currently in the start-up phase.  Credo is the operator of the well and owns a 100% working interest.  A Calliope installation is currently being designed for a third well located in Canadian County, Oklahoma.  The well is not producing due to liquid loading problems.  The system is expected to be installed in the next two months.  Credo is the operator of the well and owns a 100% working interest.

Credo is continuing to seek opportunities to purchase wells for its Calliope system.  Calliope also continues to generate interest from new players with fresh ideas as rapidly growing international companies and companies with horizontal shale gas wells seek innovative solutions to solve liquid loading problems and capture energy reserves.

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;

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·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.

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

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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 July 31, 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 July 31, 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.
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 nine months 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 July 31, 2011, the Company has repurchased 545,429 shares of common stock at an average price per share of $8.72.

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

Issuer Purchases of Equity Securities

				Total number
				of shares	Maximum dollar
				purchased	value of shares
				as part of	that may yet
	Total number of	Average price		publicly	be purchased
Period	shares purchased	paid per share		announced plan	under the plan
September 22, 2008 – October 31, 2008	98,940	$	7.31	98,940	$	1,277,000
November 1 – 30 2008	45,954	$	9.45	45,954	$	843,000
December 1 – 31 2008	22,350	$	8.88	22,350	$	645,000
January 1 – 31 2009	6,182	$	9.16	6,182	$	588,000
February 1 – 28, 2009	29,104	$	8.56	29,104	$	338,000
March 1 – 31, 2009	15,110	$	7.49	15,110	$	225,000
April 1 – 30, 2009	12,800	$	7.76	12,800	$	2,126,000
June 1 – 30, 2009	1,031	$	9.58	1,031	$	2,116,000
July 1 – 31, 2009	6,451	$	10.90	6,451	$	2,045,000
August 1 – 31, 2009	—	$	—	—	$	2,045,000
September 1 – 30, 2009	25,412	$	10.32	25,412	$	1,783,000
October 1 – 31, 2009	32,100	$	10.19	32,100	$	1,456,000
November 1 – 30, 2009	40,937	$	10.19	40,937	$	1,039,000
December 1 – 31, 2009	—	$	—	—	$	1,039,000
January 1 – 31, 2010	26,520	$	9.38	26,520	$	790,000
February 1 – 28, 2010	23,800	$	8.87	23,800	$	579,000
March 1 – 31, 2010	7,800	$	9.73	7,800	$	503,000
April 1 – 30, 2010	16,378	$	9.84	16,378	$	342,000
May 1 – 30, 2010	18,600	$	9.24	18,600	$	170,000
June 1 – 30, 2010	21,167	$	8.02	21,167	$	—
July 1 – 31, 2010	24,000	$	7.59	24,000	$	818,000
August 1 – 31, 2010	13,827	$	7.87	13,827	$	709,000
September 1 – 30, 2010	26,566	$	8.25	26,566	$	490,000
October 1 – 31, 2010	12,400	$	8.07	12,400	$	390,000
November 1 – 30, 2010	18,000	$	8.04	18,000	$	245,000
December 1 – 31, 2010	—	—		—	$	245,000
January 1 – 31, 2011	—	—		—	$	245,000
February 1 – 28, 2011	—	—		—	$	245,000
March 1 – 31, 2011	—	—		—	$	245,000
April 1 – 30, 2011	—	—		—	$	245,000
May 1 – 31, 2011	—	—		—	$	245,000
June 1 – 30, 2011	—	—		—	$	245,000
July 1 – 31, 2011	—	—		—	$	245,000
Total	545,429	$	8.72	545,429	$	245,000

ITEM 3.	DEFAULTS UPON SENIOR SECURITIES
	None.
ITEM 5.	OTHER INFORMATION
	None.

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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)

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: September 9, 2011

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