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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

(Mark One)

CREDO PETROLEUM CORPORATION

(Exact name of registrant as specified in its charter)

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-Y 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.)

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.

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CREDO PETROLEUM CORPORATION AND SUBSIDIARIES

Quarterly Report on Form 10-Q For the Period Ended January 31, 2010

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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)

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)

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)

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)

January 31, 2010

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, 2009.  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.             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.

3.             OIL AND NATURAL GAS PROPERTIES

Depreciation, depletion and amortization of oil and natural gas properties for the three months ended January 31, 2010 and 2009 were $745,000 and $1,192,000 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 bonus, geology and seismic costs, are capitalized but are excluded from the amortizable pool 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 the full cost pool.

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The capitalized costs in the full cost pool are subject to a quarterly ceiling test that limits such pooled costs to the aggregate of the present value of future net revenues attributable to proved oil and natural gas reserves discounted at 10 percent plus the lower of cost or market value of unproved properties less any associated tax effects.  The ceiling test is calculated using oil and natural gas prices in effect as of the balance sheet date.  If such capitalized costs exceed the ceiling, the company will record a write-down to the extent of such excess as a non-cash charge to earnings, unless the company considers price increases subsequent to the balance sheet date which may reduce or eliminate a write-down.  A write-down may not be reversed in future periods, even though higher oil and natural gas prices may subsequently increase the ceiling.

At January 31, 2010 the estimated present value of future net revenues from proved reserves, net of related income tax considerations, exceeded the capitalized costs of the company’s oil and natural gas properties.  Therefore, a ceiling test write-down was not required.  For the three months ended January 31, 2009, the company recorded a non-cash ceiling test write-down of $15,697,000.

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

4.             STOCK-BASED COMPENSATION

For each of the three month periods ended January 31, 2010 and 2009, the company recognized stock based compensation expense of $8,000.  The estimated unrecognized compensation cost from unvested stock options as of January 31, 2010 was approximately $25,000 which is expected to be recognized over 10 months.

No options were granted during the three months ended January 31, 2010 or 2009.

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Plan activity for the three months ended January 31, 2010 is set forth below:

5.             NATURAL GAS DERIVATIVES

The company is exposed to certain commodity price risks relating to its ongoing operations.  The company periodically uses natural gas derivatives as economic hedges of the price of a portion of its estimated natural gas production when the potential for significant downward price movement is anticipated.  These transactions typically take the form of forward short positions based upon the NYMEX futures market, 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 the quarters ended January 31,  2010 and 2009 the company had realized gains (losses) on derivatives of ($10,000) and $925,000 respectively, and unrealized gains (losses) of ($4,000) and $541,000, respectively.  At January 31, 2010 the company held open derivative contracts representing short sales positions for 640,000 MMBtus at NYMEX basis prices ranging from $5.22 to $7.27 and covering the production months of February 2010 through December 2010.  The company also held open derivative contracts with the same counterparty representing long positions for 390,000 MMBtus at NYMEX basis prices ranging from $5.15 to $5.83 and covering the production months of February 2010 through December 2010.  These positions are presented net due to the contractual netting provisions with the counterparty.  The open derivative contracts net to 250,000 MMBtus with a net unrealized gain of $214,210 at January 31, 2010.  Average prices in the company’s primary market are currently 2% below NYMEX prices due to basis differentials and transportation costs.

At January 31, 2010 the company also held basis differential hedges on 440,000 MMBtus with NYMEX vs. Panhandle Eastern Pipeline basis differentials of $0.47 and covering the production months of

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February 2010 through December 2010.  These open basis differential contracts represent unrealized losses of $114,000 at January 31, 2010.

Subsequent to January 31, the February and March derivative contracts closed, resulting in realized derivative losses of $2,000.

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 $5,900,000 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 November 15, 2010.

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 (in thousands):

Derivatives not designated as hedging instruments:

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

Derivatives not designated as hedging instruments:

6.             EARNINGS PER SHARE

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

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The company’s outstanding options were not included in the calculation of diluted loss per share for the period ended January 31, 2009 as their inclusion would have an antidilutive effect.

7.             INCOME TAXES

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

The total future deferred income tax liability is 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 January 31, 2010 the company’s 2007 Federal tax return had been audited by the IRS.  The company remains subject to examination of 2006 and 2008 Federal and 2006 through 2008 state tax returns, except Colorado, in which the 2005 tax year also remains open.

8.             INTANGIBLE ASSETS

The company owns all of the patents underlying the Calliope Gas Recovery Technology and patents covering a new fluid lift technology for shallow wells known as Tractor Seal.  The patents are being amortized on a straight line basis over the remaining lives ranging from 7.4 to 16.4 years.

The company reviews the value of its intangible assets for impairment whenever events or changes in business circumstances indicate that the carrying amount of the assets may not be fully recoverable or that the useful lives of these assets are no longer appropriate.  For the period ended January 31, 2009, the company recorded a non-cash impairment expense of $926,000 related to other intangible assets.

9.             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

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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 January 31, 2010:

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 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 months ended January 31, 2010:

(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.

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10.          COMMON STOCK

On September 22, 2008, the company’s Board of Directors authorized a stock repurchase program.  Under the program, the company could acquire up to $2,000,000 of its common stock.  The Board subsequently authorized expanding the repurchase program to $4,000,000.  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.  During the quarter ended January 31, 2010, the company acquired 67,457 shares of its common stock at an aggregate cost of $667,000.

Subsequent to January 31, 2010, and through March 10, 2010, the company has repurchased an additional 23,800 shares, bringing the total shares repurchased to 386,691 at an average price per share of $8.85 under this program.

11.          COMMITMENTS AND CONTINGENCIES

The company has been named as a defendant in a lawsuit alleging breach of contract, and other issues, arising in the normal course of its oil and gas activities.  The company believes that a contractual agreement requires that disputes be resolved by arbitration.  Although the company believes the allegations are without merit and that the company will ultimately prevail, the ultimate outcome of this lawsuit, or arbitration, cannot be determined at this time.

The company has also been named as a defendant in a lawsuit brought by a former employee.  The suit alleges breach of contract and other employment issues.  Although the company believes the allegations are without merit and that the company will ultimately prevail, the ultimate outcome of this lawsuit cannot be determined at this time.

The company has no material outstanding commitments at January 31, 2010.

12.          RECENT ACCOUNTING PRONOUNCEMENTS

In February 2010, the FASB issued authoritative guidance that eliminated the requirement to disclose the date through which management evaluated subsequent events in the financial statements.  Such subsequent events must still be evaluated by management through the date that financial statements are issued.  The new guidance was effective immediately and the company adopted the guidance for financial statement issued subsequent to February 24, 2010.  There was no impact on the company’s financial position or results of operations as a result of the adoption.

In January 2010, the FASB issued authoritative guidance titled “Improving Disclosures about Fair Value Measurements.”  This guidance amends existing authoritative guidance to require additional disclosures regarding fair value measurements, including the amounts and reasons for significant transfers between Level 1 and Level 2 of the fair value hierarchy, the reasons for any transfers into or out of Level 3 of the fair value hierarchy, and presentation on a gross basis of information regarding purchases, sales, issuances, and settlements within the Level 3 rollforward.  This guidance also clarifies certain existing disclosure requirements.  The guidance is effective for interim and annual reporting periods beginning after December 15, 2009, except for the disclosures about purchases, sales, issuances, and settlements within the Level 3 rollforward, which are effective for interim and annual reporting periods beginning after December 15, 2010.  The adoption of this authoritative guidance will have no impact on our financial position or results of operations, but may require expanded disclosure about fair value measurements.

In December 2008, the Securities and Exchange Commission (“SEC”) adopted revisions to its oil and gas disclosure requirements that are intended to align them with current practices and changes in technology. Among other things, the amendments will: replace the single-day year-end pricing assumption with a twelve-month average pricing assumption; permit the disclosure of probable and possible reserves; allow

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the use of certain technologies to establish reserves; require the disclosure of the qualifications of the technical person primarily responsible for preparing the reserves estimates or conducting a reserves audit; require the filing of the independent reserve engineers’ summary report; and permit the disclosure of a reserves sensitivity analysis table to illustrate the impact of different price and/or cost assumptions on reserves. These amendments are effective for registration statements filed on or after January 1, 2010, and for annual reports on Form 10-K for fiscal years ending on or after December 31, 2009 (October 31, 2010 for the company) with early adoption prohibited. The company is currently evaluating the impact that the adoption of these amendments will have on the company’s financial position, results of operations, and disclosures.  In January 2010, the Financial Accounting Standards Board (“FASB”) issued oil and gas reserve estimation and disclosure authoritative accounting guidance effective for reporting periods ending on or after December 31, 2009.  This guidance was issued to align the accounting oil and gas reserve estimation and disclosure requirements with the requirements in the Securities and Exchange Commission’s (“SEC”) final rule.  The new FASB guidance includes changes to pricing used to estimate oil and gas reserves, broaden the types of technologies that a company may use to establish oil and gas reserves estimates, and broaden the definition of oil and gas producing activities to include the extraction of non-traditional resources.

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;

·                  adequacy of insurance coverage;

·                  employee relations;

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·                  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” and elsewhere in this Annual Report on Form 10-K, including, without limitation, in conjunction with the forward-looking statements.  The following factors, among others that could cause actual results to differ materially from the company’s expectations, include:

·                  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.

LIQUIDITY AND CAPITAL RESOURCES

At January 31, 2010, working capital was $13,667,000 compared to $13,542,000 at October 31, 2009.  For the three months ended January 31, 2010, net cash provided by operating activities was $1,312,000 compared to $1,281,000 for the same period in 2009.  Income before income taxes increased $17,145,000 primarily due to impairment losses of $16,623,000 in 2009, an increase in revenue of $1,034,000, decreased other cost and expenses of $827,000, and decreased other income of $1,339,000, which is mostly due to derivative transactions.

For the three months ended January 31, 2010 and 2009, net cash used in investing activities was $864,000 and $11,534,000, respectively.  Investing activities primarily included oil and gas lease acquisition, exploration and development expenditures, including Calliope, totaling $921,000 and $6,157,000 respectively.

Existing working capital and anticipated cash flow are expected to be sufficient to fund operations and capital commitments for at least the next 12 months.  At January 31, 2010, the company had no lines of credit or other bank financing arrangements except for the hedging line of credit discussed in Note 5.  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, including impairment losses, (“EBITDA”) was $1,729,000 for the three months ended January 31, 2010 compared to $1,678,000 for the three months ended January 31, 2009.  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

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consider this measure in isolation or as a substitute for operating income, or any other measure for determining the company’s operating performance that is calculated in accordance with GAAP.  In addition, because EBITDA is not a GAAP measure, it may not necessarily be comparable to similarly titled measures employed by other companies.  Reconciliation between EBITDA and net income is provided in the table below:

OFF-BALANCE SHEET FINANCING

The company has no off-balance sheet arrangements at January 31, 2010.

PRODUCT PRICES AND PRODUCTION

Although product prices are key to the company’s ability to operate profitably and to budget capital expenditures, they are beyond the company’s control and are difficult to predict.  Since 1991, the company has periodically hedged the price of a portion of its estimated natural gas production when the potential for significant downward price movement is anticipated.  Hedging transactions typically take the form of forward short positions, swaps and collars which are executed on the NYMEX futures market or by indexing to regional index prices associated with pipelines in proximity to the company’s production.  The company’s current hedges are indexed to NYMEX.

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 5 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.

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The effect of realized derivative gains and losses on total price realizations are reflected in the following table:

OPERATIONS

During the first quarter of fiscal 2010, 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 2010, 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.

In recent years, the company has significantly expanded both the volume and breadth of its drilling activities with new projects in central Kansas, North Dakota’s Williston Basin, and South Texas.  Compared to drilling in Oklahoma, the North Dakota and South Texas projects involve higher costs and greater risks but significantly higher per well reserve potential.  In contrast, drilling in central Kansas is less expensive than the company’s Oklahoma drilling projects while still yielding excellent economics.

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.

Recent Drilling Activities.

Bakken Shale — The company’s first Bakken horizontal well has been drilled and completed.  During testing the well flowed at 1,474 barrels of oil equivalent over a 24 hour period.  The well is located on the Fort Berthold Reservation in an area where there have been a significant number of successful Bakken completions.  The well was drilled on a 1,280 acre spacing unit with a horizontal lateral of approximately 9,200 feet.  Credo owns a 10% working interest.

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Credo has leased approximately 8,000 gross (6,000 net) acres on the Reservation containing about 50 drillable spacing units.  The company’s interests range up to 51% depending on the size of the spacing unit.  It is expected that more than one well will be drilled on many spacing units.

Horizontal drilling targets the Bakken and Three Forks formations.  The company’s acreage is generally located south and west of Parshall Field and is in the vicinity of several recently announced significant Bakken discoveries.  The Reservation is surrounded on three sides by horizontal Bakken production, and drilling activity on the Reservation is escalating rapidly.

Central Kansas Uplift — In Central Kansas, Credo currently owns 140,000 gross (77,000 net) acres where it is having excellent drilling results.  The acreage contains 31 blocks in which the company owns interests ranging from 12.5% to 100%.

To date, Credo has drilled 49 wells on its Central Kansas Uplift acreage, of which 48% have been successful.  The company is continuing an aggressive lease acquisition and drilling program with two to three wells per month scheduled.  Based on its historical experience in the play, the company plans to maintain that drilling pace for at least the next few years.

Four of the company’s last seven wells are successful discoveries.  One of those wells has been completed with an initial production rate of about 100 barrels per day and three are currently awaiting completion.  Each of these discoveries was the initial exploratory test on a seismically identified anomaly, and additional development drilling is expected.  The company owns working interests in the discoveries ranging from 12.5% to 28.8%.

Last year, Credo discovered a significant new field in Barton County, Kansas in which it owns an 85% working interest.  That field has produced 96,000 barrels of oil in about 14 months.

Calliope Gas Recovery Technology

Calliope Gas Recovery System — We are continuing to actively discuss commercial Calliope terms with several companies.  We have proven that Calliope will perform as advertised.  Credo has previously published statistics on its Calliope wells which show finding costs of about $0.50 per Mcf and total costs to deliver gas into the pipeline of about $1.00 per Mcf.  The statistics also show that Calliope is very low risk when installed on suitable wells.

Calliope’s low finding and production costs have become increasingly attractive as the economics on many industry drilling projects deteriorate due to lower product prices.  We also believe that lower natural gas prices may stimulate divestitures of marginal properties by other companies, including properties that have Calliope potential.

Results of Operations

Three Months Ended January 31, 2010 Compared to Three Months Ended January 31, 2009

For the three months ended January 31, 2010, oil and gas revenues increased 49% to $3,142,000 compared to $2,108,000 during the same period last year.  As the oil and gas price/volume table on page 15 shows, natural gas sales prices increased 26% to $5.15 per Mcf and oil sales prices increased 99% to $73.21 per barrel. The net effect of these price changes was to increase oil and gas sales by $984,000.  For the three months ended January 31, 2010, the company’s oil equivalent production (BOE) fell 10% but combined with the change in oil and gas production mix, and due to the diversity between the energy equivalency conversion rate of six to one compared to the price equivalency rate of over fourteen to one at January 31, 2010, revenue increased $50,000.

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For the three months ended January 31, 2010, total costs and expenses, excluding the 2009 impairment loss of $16,623,000, decreased 27% to $2,263,000 compared to $3,090,000 for the comparable period in 2009.  Oil and gas production expenses decreased 3% as reduced field level expenses were partially offset by an increased number of operating wells.  DD&A decreased primarily due to a decrease in the amortizable base.  General and administrative expenses decreased primarily due to legal and professional fees and decreased salaries and benefits.  The effective tax rate was 26.00% and 39.25% for the 2010 and 2009 periods, respectively.  The effect of percentage depletion deductions is the primary cause of the variation of the effective tax rate from the statutory rate.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

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

Derivatives.  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 its balance sheet and changes in fair value are recorded in the Consolidated Statements of Operations as they occur.

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

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

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

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

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Oil and Gas Reserves.  The determination of depreciation and depletion expense as well as ceiling test write-downs related to the recorded value of the company’s oil and natural gas properties are highly dependent on the estimates of the proved oil and natural gas reserves. Oil and natural gas reserves include proved reserves that represent estimated quantities of crude oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.  New rules for the calculation of recoverable reserves will not be adopted by the company until October 31, 2010.  The new rules may impact future calculations of ceiling tests and DD&A.  See Footnote #3 for additional discussion of DD&A and ceiling test calculations.  There are numerous uncertainties inherent in estimating oil and natural gas reserves and their values, including many factors beyond the company’s control. Accordingly, reserve estimates are often different from the quantities of oil and natural gas ultimately recovered and the corresponding lifting costs associated with the recovery of these reserves are often different than the estimated costs.

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

Asset Retirement Obligations.  The FASB authoritative guidance requires that the company estimate the future cost of asset retirement obligations, discount that cost to its present value, and record a corresponding asset and liability in its Consolidated Balance Sheets.  The values ultimately derived are based on many significant estimates, including future abandonment costs, inflation, useful life, and cost of capital.  The nature of these estimates requires the company to make judgments based on historical experience and future expectations.  Revisions to the estimates may be required based on such things as changes to cost estimates or the timing of future cash outlays. Any such changes that result in upward or downward revisions in the estimated obligation will result in an adjustment to the related capitalized asset and corresponding liability on a prospective basis.

ITEM 3.                      QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The company manages exposure to commodity price fluctuations by periodically hedging a portion of estimated natural gas production through the use of derivatives, typically forward short positions in the NYMEX futures market.  At January 31, 2010 the company held open derivative contracts representing short sales positions for 640,000 MMBtus at NYMEX basis prices ranging from $5.15 to $7.27 and covering the production months of February 2010 through December 2010.  The company also held open derivative contracts with the same counterparty representing long positions for 390,000 MMBtus at NYMEX basis prices ranging from $5.15 to $5.83 and covering the production months of February 2010 through December 2010.  These positions are presented net due to the contractual netting provisions with the counterparty.  The open derivative contracts net to 250,000 MMBtus with a net unrealized gain of $214,210 at January 31, 2010.  Average prices in the company’s primary market are currently 2% below NYMEX prices due to basis differentials and transportation costs.  However, regional weather conditions and other economic factors can periodically result in substantially higher basis differentials.

At January 31, 2010 the company also held basis differential hedges on 440,000 MMBtus with NYMEX vs. Panhandle Eastern Pipeline basis differentials of $0.47 and covering the production months of February 2010 through December 2010.  These open basis differential contracts represent an unrealized loss of $114,000 at January 31, 2010.

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See Note 5 to the Consolidated Financial Statements for more information regarding derivative transactions.

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 January 31, 2010.  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 January 31, 2010 that has materially affected or is reasonably likely to materially affect, our internal control over financial reporting.

PART II - OTHER INFORMATION

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Subsequent to January 31, 2010, and through March 10, 2010, the company has repurchased an additional 23,800 shares, bringing the total shares repurchased to 386,691 at an average price per share of $8.85.

Issuer Purchases of Equity Securities