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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

(Mark One)

For the quarterly period ended January 31, 2009

For the transition period from                 to                 

Commission File Number:   0-8877

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 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 Exchange 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, 2009

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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 STATEMENT OF STOCKHOLDERS’ EQUITY

For the Three Months Ended January 31, 2009

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, 2009

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.  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, 2008.  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, 2009 and 2008 were $1,192,000 and $826,000 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.

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

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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.

Due to lower oil and natural gas prices at January 31, 2009, capitalized costs of oil and natural gas properties exceeded the estimated present value of future net revenues from proved reserves, net of related income tax considerations, resulting in a non-cash write-down of $15,697,000.  The spot prices used in the ceiling test calculation at January 31, 2008 for oil and natural gas were $38.25 per barrel and $3.33 per Mcf.  Given the volatility of oil and natural gas prices, additional write downs may be required in fiscal 2009.

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 the three months ended January 31, 2009 and 2008, the company recognized stock based compensation expense of $8,000 and $15,000 respectively.  The estimated unrecognized compensation cost from unvested stock options as of January 31, 2009 was approximately $56,000 which is expected to be recognized over an average of 2.8 years.

No options were granted during the three months ended January 31, 2009 or 2008.

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Plan activity for the three months ended January 31, 2009 is set forth below:

5.             NATURAL GAS DERIVATIVES

The company periodically uses 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 and collars 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.

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.

For the quarters ended January 31, 2009 and 2008, the company had realized gains on derivatives of $925,000 and $847,000 respectively, and unrealized gains of $541,000 and unrealized losses of $316,000 respectively.  At January 31, 2009 open derivative contracts covered 550,000 MMBtus at NYMEX basis prices ranging from $8.00 to $10.60, and cover the production months of February 2009 through October 2009.  Average prices in the company’s primary market are expected to be 15% to 17% below NYMEX prices due to basis differentials and transportation costs.

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

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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.

6.             EARNINGS PER SHARE

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

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, 2009 the company’s 2007 Federal tax return was under audit by the IRS.  Subsequent to January 31 2009, the IRS issued its final report.  Approximately $24,000 in additional tax is due related to the company’s 2007 tax return.  The company remains subject to examination of Federal and state tax returns, except Colorado, for the tax years 2005 and 2006, and for the tax years 2004 through 2007 for Colorado tax returns.

8.             INTANGIBLE ASSETS

On November 6, 2008 the company purchased all of the patents underlying the Calliope Gas Recovery Technology, all of the related third party interests in future installations of the technology and patents covering a new fluid lift technology for shallow wells known as Tractor Seal for $4,400,000.  The patents are being amortized on a straight line basis over the remaining lives ranging from 8.6 to 17.6 years.

On September 1, 2000, the company acquired an unrestricted, exclusive license for patented Calliope Gas Recovery System technology.  In July 2008, the company acquired the third party rights resulting from

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certain future Calliope installations for $975,000.  Those third party rights would have resulted principally from Calliope installations of joint ventures between the company and other natural gas producing companies.

As a result of the current natural gas market, the company believes it is more likely than not that the formation of joint ventures for the installation of Calliope technology that would have been subject to these third party rights will not occur within the foreseeable future.  Based on this assumption, and in accordance with FASB Statement No. 144 Accounting for the Impairment or Disposal of Long-Lived Assets (FAS 144), the company has determined that, currently, the sum of the undiscounted value of cash flows to be derived from future installations of Calliope technology resulting from joint ventures is minimal.  Accordingly, the company has recorded an impairment loss of $926,000.

The company reviews the value of its intangible assets in accordance with SFAS 144, Accounting for the Impairment or Disposal of Long Lived Assets, which requires that it evaluate these 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.

9.                                      FAIR VALUE MEASUREMENTS

On November 1, 2008, the company adopted FASB Statement No. 157 Fair Value Measurements, which defines fair value, establishes a framework for measuring fair value, and expands disclosures about fair value measurements.  SFAS No. 157 applies to other accounting pronouncements that require or permit fair value measurements; however, it does not require any new 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.  SFAS No. 157 establishes 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.

A financial asset’s or liability’s classification 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 SFAS No. 157, 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

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carried at fair value measured on a recurring basis as of January 31, 2009:

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, 2009:

(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.

10.          COMMON STOCK

On September 22, 2008, the company’s Board of Directors authorized a stock repurchase Program.  Under the program, the company may acquire up to $2,000,000 of its common stock.  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, 2009, the company acquired 74,486 shares of its common stock at an aggregate cost of $690,000.

Subsequent to January 31, 2009, and through March 2, 2009, the company has repurchased an additional 31,104 shares, bringing the total shares repurchased to 204,530 at an average price per share of $8.19 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 no material outstanding commitments at January 31, 2009.

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12.          RECENT ACCOUNTING PRONOUNCEMENTS

On December 29, 2008 the Securities and Exchange Commission announced final approval of new requirements for reporting oil and gas reserves to be effective in January 2010.  The new disclosure requirements provide for consideration of new technologies in evaluating reserves, allow companies to disclose their probable and possible reserves to investors, report oil and gas reserves using an average price based on the prior 12-month period rather than year-end prices, and revise the disclosure requirements for oil and gas operations.  The accounting for the limitation on capitalized costs for full cost companies will also be revised.  The new rule is expected to be effective for years ending on or after December 31, 2009.  Early adoption is not permitted.  The company has not yet evaluated the effects on its financial statements and disclosures.

In March 2008, the FASB issued Statement No. 161 (FAS 161), “Disclosures about Derivative Instruments and Hedging Activities, an amendment of FASB Statement No. 133,” which requires additional disclosures about the objectives of using derivative instruments, the method by which the derivative instruments and related hedged items are accounted for under FASB Statement No. 133 and its related interpretations, and the effect of derivative instruments and related hedged items on financial position, financial performance and cash flows.  FAS 161 also requires disclosure of the fair values of derivative instruments and their gains and losses in a tabular format.  FAS 161 is effective for fiscal years beginning after November 15, 2008 and interim periods within those fiscal years (fiscal 2010 for the company).  The company is in the process of determining the effects the adoption of FAS 161 will have on its financial statement disclosures.

In December 2007 the FASB issued Statement No. 159, The Fair Value Option for Financial Assets and Financial Liabilities – Including an amendment of FASB Statement No. 115 (FAS 159).  This Statement provides all entities with an option to report selected financial assets and liabilities at fair value.  The Statement is effective as of the beginning of an entity’s first fiscal year beginning after November 15, 2007, with early adoption available in certain circumstances.  The company does not expect to elect the options provided by FAS 159.

In November 2007, the FASB issued Statement No. 141 (revised 2007), Business Combination (FAS 141(R)) and Statement No. 160, Noncontrolling Interests in Consolidated Financial Statements, an amendment of ARB No. 51 (FAS 160).  FAS 141(R) will change how business acquisitions are accounted for and will impact financial statements both on the acquisition date and in subsequent periods.  FAS 160 will change the accounting and reporting for minority interests, which will be recharacterized as noncontrolling interests and classified as a component of equity.  FAS 141(R) and FAS 160 are effective for both public and private companies for fiscal years beginning on or after December 15, 2008 (fiscal 2010 for the company).  FAS 141(R) will be applied prospectively. FAS 160 requires retroactive adoption of the presentation and disclosure requirements for existing minority interests. All other requirements of FAS 160 will be applied prospectively.  Early adoption is prohibited for both standards.  Management is currently evaluating the requirements of FAS 141(R) and FAS 160 and has not yet determined the impact on its financial statements.

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

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reasonably expects, believes or anticipates will or may occur in the future.  Forward-looking statements may relate to, among other things:

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

·                  amounts and nature of future capital expenditures;

·                  operating costs and other expenses;

·                  wells to be drilled or reworked;

·                  oil and natural gas prices and demand;

·                  existing fields, wells and prospects;

·                  diversification of exploration;

·                  estimates of proved oil and natural gas reserves;

·                  reserve potential;

·                  development and drilling potential;

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

·                  the company’s business strategy;

·                  production of oil and natural gas;

·                  matters related to the Calliope Gas Recovery System;

·                  effects of federal, state and local regulation;

·                  insurance coverage;

·                  employee relations;

·                  investment strategy and risk; and

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

LIQUIDITY AND CAPITAL RESOURCES

At January 31, 2009, working capital decreased $8,985,000 to $15,175,000 compared to $24,160,000 at October 31, 2008.  For the three months ended January 31, 2009, net cash provided by operating activities was $1,281,000 compared to $1,626,000 for the same period in 2008.  Net income decreased $11,464,000 primarily due to impairment losses of $16,623,000, a decrease in revenue of $1,625,000 and increased other cost and expenses of $1,053,000.

For the three months ended January 31, 2009 and 2008, net cash used in investing activities was $11,534,000 and $3,203,000, respectively.  Investing activities primarily included oil and gas exploration and development expenditures, including Calliope, totaling $6,157,000 and $2,844,000 respectively.  For the period ended January 31, 2009, the company also purchased the patents underlying the Calliope Technology for $4,400,000.

The average return on the company’s investments was a loss of 5.5% for the three months ended January 31, 2009 compared to a loss of 1.2% for the same period last year.  At January 31, 2009, 89% of the short term investments were being liquidated.

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, 2009, 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 $1,678,000 for the three months ended January 31, 2009 compared to $3,075,000 for the three months ended January 31, 2008.  EBITDA is not a GAAP measure of operating performance.  The company uses this non-GAAP performance measure primarily to compare its

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performance with other companies in the industry that make a similar disclosure.  The company believes that this performance measure may also be useful to investors for the same purpose.  Investors should not consider this measure in isolation or as a substitute for operating income, or any other measure for determining the company’s operating performance that is calculated in accordance with GAAP.  In addition, because EBITDA is not a GAAP measure, it may not necessarily be comparable to similarly titled measures employed by other companies.  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, 2009.

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.  Refer to Note 5 of the Consolidated Financial Statements for a complete discussion on the company’s hedging activities.

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

(1) Includes $2.55 per Mcf realized hedging gain.

(2) Includes $2.16 per Mcf realized hedging gain.

See comments at “Results of Operations”

OPERATIONS

During the first quarter of fiscal 2009, 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.

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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 2009, 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.

The cost of field services, particularly the cost of drilling wells, has increased dramatically during the past several years, driven by higher energy prices.  Concurrently, the quality of field services has diminished markedly due to manpower shortages.  The combination of much higher field service costs and degradation in the quality of the services had a material negative impact on drilling economics.  Accordingly, the company has delayed additional drilling scheduled for second quarter 2009 for a period of at least two months in anticipation of significant improvement in both the cost and quality of drilling services and materials.

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.

Proprietary Drilling Results — The company recently announced that it has participated in drilling a wildcat discovery well that flowed oil at impressive initial rates during completion testing.  For competitive reasons, we have not disclosed any detailed ownership, location or technical information about the well.  Due to low oil prices, production is being curtailed to between 100 and 200 barrels of oil per day.  Confirmation drilling has yielded positive results.

Northern Anadarko Basin — Oklahoma drilling has historically been the primary driver for CREDO’s production growth.  CREDO owns approximately 75,000 gross acres and has interests in almost 200 wells.  During the first quarter of fiscal 2009, CREDO completed two wells on its Pool\Proffitt Prospect to test multiple carbonate reservoirs using new fracture stimulation technology.  Both appear to be commercial wells, and there are up to 12 additional locations on CREDO’s acreage.

One of the wells is a new pool discovery in the Hunton formation.  During the final 24-hour test, the well flowed 535 barrels of oil and an estimated 1.0 to 2.0 MMcfg (million cubic feet of gas) with virgin pressure.  Due to low oil prices and the reservoir character, we are curtailing production to 100 barrels of oil per day.  The well also found over 150 feet of potential pay in the Mississippian formation and 31 feet of excellent Chester pay.  CREDO owns a 50% working interest.  The second well encountered over 150 feet of indicated pay in the Mississippian formation and 35 feet of Chester formation.  The well is currently being tested.  CREDO owns a 73% working interest.

In Hemphill County, Texas, the company purchased an additional 3,800 gross acres and assumed operatorship of 11 wells.  The new acreage complements the company’s Humphreys Prospect and brings our total acreage in the area to approximately 8,300 gross acres.  We have drilled two successful wells on the acreage, and intend to drill more wells in 2009.  CREDO owns interests ranging up to 25%.

South Texas  — CREDO entered the South Texas joint venture to use 3-D seismic to explore for deep, highly faulted prospects.  The high potential, 17,000-foot wildcat well drilled to test the Deep Wilcox sand on the Gemini Prospect confirmed the seismic interpretation and found porous sand.  However, the sand was water wet and the well was plugged and abandoned.  CREDO received approximately $1,300,000 of

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cash for the prospect package and retained an 11.25% “carried interest” in the test well.  The prospect package consists of two additional Deep Wilcox prospects which are geologically different from Gemini Prospect.  They are being further evaluated, and if drilled, CREDO will have an 11.25% carried interest in the next well.

Central Kansas Uplift — The company has achieved excellent drilling results on the Central Kansas Uplift.  To date, CREDO has participated in 33 wells on the Uplift, of which 48% have been successfully completed as oil producers.  That outstanding success prompted us to increase CREDO’s leasehold position to almost 150,000 gross and 75,000 net acres.  This acreage provides a good inventory of future drilling opportunities where CREDO owns interests ranging up to 85 percent.

Drilling on the Uplift is relatively shallow and costs are moderate, yielding good economics even in the current product price environment.  In addition, the project is oil targeted, thereby improving the balance between oil and natural gas in CREDO’s reserve base.  We expect Kansas to make a major contribution to our reserve and production growth in 2009.

Bakken Shale — CREDO entered the horizontal Bakken oil play in 2008 by leasing about 4,700 acres in North Dakota.  The new leases have five or ten year terms and they are located in the vicinity of the recently discovered and prolific Parshall Field.  Based on 640 acre spacing units, CREDO has interests in up to 27 well locations.  Breakthroughs in precision horizontal drilling and multi-stage, high pressure fracture stimulations have made the Bakken shale a very active resource play.  The U.S. Geological Survey recently estimated that the Bakken contains around 4.0 billion barrels of undiscovered oil.

Calliope Gas Recovery Technology

Calliope Gas Recovery System — We are continuing to actively discuss commercial Calliope terms with several companies.  We have proven beyond any doubt 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.

At year-end, Credo owned an exclusive license to the Calliope patents and the related technology.  However, in order to establish absolute control over the technology and to eliminate future costs for individual well licenses, we recently purchased all of the underlying patents for $4,500,000.  This acquisition also covers an exciting series of new patents, known as Tractor Seal, that is specifically designed to remove liquids from shallow wells more efficiently than existing technologies.  If perfected, this new technology will be an excellent complement to Calliope’s focus on deeper wells

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Results of Operations

Three Months Ended January 31, 2009 Compared to Three Months Ended January 31, 2008

For the three months ended January 31, 2009, oil and gas revenues decreased 44% to $2,108,000 compared to $3,733,000 during the same period last year.  As the oil and gas price/volume table on page 15 shows, total gas price realizations, which reflect realized hedging transactions, decreased 19% to $6.65 per Mcf and oil price realizations decreased 57% to $36.87 per barrel.  The net effect of these price changes was to decrease oil and gas sales by $1,468,000 ($1,546,000 without realized hedges).  For the three months ended January 31, 2009, the company’s gas equivalent production fell 5% resulting in an oil and gas sales decrease of $79,000. The company elected to postpone certain scheduled drilling due to the historically high costs of equipment and field services.  That decision came with the consequence that less drilling would cause production declines.  Investment and other income decreased $136,000, primarily due to performance of the company’s investments, compared to last year.

For the three months ended January 31, 2009, total costs and expenses, excluding the impairment loss of $16,623 ,000, increased 52% to $3,090,000 compared to $2,037,000 for the comparable period in 2008.  Oil and gas production expenses increased due primarily to an increased number of operating wells.  DD&A increased primarily due to an increase in the amortizable cost base before the impairment adjustment.  General and administrative expenses increased primarily due to accounting and professional fees and increased salaries and benefits.  The effective tax rate was 39.25% and 29.18% for the 2009 and 2008 periods, respectively.

SIGNIFICANT ACCOUNTING POLICIES

The company believes the following accounting policies and estimates are critical in the preparation of its consolidated financial statements: the carrying value of its oil and natural gas properties, the accounting for oil and gas reserves, and the estimate of its asset retirement obligations.

OIL AND GAS PROPERTIES

The company uses the full cost method of accounting for costs related to its oil and natural gas properties.  Capitalized costs included in the full cost pool are depleted on an aggregate basis using the units-of-production method.  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.

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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.  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.

At January 31, 2009, capitalized costs of natural gas and oil properties exceeded the estimated present value of future net revenues from proved reserves, net of related income tax considerations, resulting in a non-cash write down of $15,697,000.  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 of the test period.

OIL AND GAS RESERVES  The determination of depreciation and depletion expense as well as ceiling test write-downs related to the recorded value of the company’s oil and natural gas properties are highly dependent on the estimates of the proved oil and natural gas reserves.  Oil and natural gas reserves include proved reserves that represent estimated quantities of crude oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.  There are numerous uncertainties inherent in estimating oil and natural gas reserves and their values, including many factors beyond the company’s control.  Accordingly, reserve estimates are often different from the quantities of oil and natural gas ultimately recovered and the corresponding lifting costs associated with the recovery of these reserves.

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

INTANGIBLE ASSETS  The company reviews the value of its intangible assets in accordance with FASB Statement No. 144 which requires that it evaluate these 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.

On September 1, 2000, the company acquired an unrestricted, exclusive license for patented Calliope Gas Recovery System technology.  In July 2008, the company acquired the third party rights resulting from certain future Calliope installations for $975,000.  Those third party rights would have resulted principally from Calliope installations of joint ventures between the company and other natural gas producing companies.  As a result of the current natural gas market, the company believes it is more likely than not that the formation of joint ventures for the installation of Calliope technology that would have been subject to these third party rights will not occur within the foreseeable future.  Based on this assumption, and in

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accordance with FAS 144 Accounting for the Impairment or Disposal of Long-Lived Assets, the company has determined that, currently, the sum of the undiscounted value of cash flows to be derived from future installations of Calliope technology resulting from joint ventures is minimal.  Accordingly, the company has recorded an impairment loss of $926,000.

On November 6, 2008 the company purchased all of the patents underlying the Calliope Gas Recovery Technology, all of the related third party interests in future installations of the technology and patents covering a new fluid lift technology for shallow wells known as Tractor Seal for $4,400,000.  The patents are being amortized on a straight line basis over the remaining lives ranging from 8.6 to 17.6 years.

REVENUE RECOGNITION  The company derives its revenue primarily from the sale of produced natural gas and crude oil.  The company reports revenue gross for the amounts received before taking into account production taxes and transportation costs which are reported as oil and gas production expenses.  Revenue is recorded in the month production is delivered to the purchaser at which time title changes hands.  The company makes estimates of the amount of production delivered to purchasers and the prices it will receive.  The company uses its knowledge of its properties, their historical performance, the anticipated effect of weather conditions during the month of production, NYMEX and local spot market prices, and other factors as the basis for these estimates.  Variances between estimates and the actual amounts received are recorded when payment is received.

A majority of the company’s sales are made under contractual arrangements with terms that are considered to be usual and customary in the oil and gas industry.  The contracts are for periods of up to five years with prices determined based upon a percentage of a pre-determined and published monthly index price.  The terms of these contracts have not had an effect on how the company recognizes its revenue.

HEDGING  The company recognizes all derivatives as fair value hedges on its balance sheet at fair value at the end of each period.  Changes in the fair value of hedges are recorded in the Consolidated Statement of Operations.

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 collars and forward short positions in the NYMEX futures market.  At January 31, 2009 open derivative contracts covered 550,000 MMBtus, approximately 35% of the company’s anticipated 2009 natural gas production, at NYMEX prices ranging from $8.00 to $10.60 and covered the production months of February, 2009 through October, 2009.  Actual price realizations in the company’s principal areas of operations (primarily Oklahoma) are expected to be 15% to 17% below NYMEX prices primarily due to basis differentials and transportation costs.  However, regional weather conditions and other economic factors can periodically result in substantially higher basis differentials.  Relevant terms of the open derivative contracts at January 31, 2009 are as follows:

Natural Gas Forward Short Positions

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ITEM 4.                           CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

Our management, with the participation of James T. Huffman, 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, 2009.  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, 2009 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/A for the fiscal year ended October 31, 2008.

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

Issuer Purchases of Equity Securities.

During the first quarter of fiscal year 2009, the company repurchased 74,486 shares of its common stock on the open market at a weighted average price of $9.26.  The purchases were made pursuant to a stock repurchase plan announced on September 24, 2008.  The plan authorized repurchases up to $2,000,000, but could be expanded, suspended or discontinued at any time.  Subsequent to January 31, 2009, and through March 2, 2009, the company has repurchased an additional 31,104 shares, bringing the total shares repurchased to 204,530 at an average price per share of $8.19.

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Issuer Purchases of Equity Securities