Table of Contents

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

(Mark One)

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

For the quarterly period ended January 31, 2011

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

For the transition period from                to               

Commission File Number:  0-8877

CREDO PETROLEUM CORPORATION

(Exact name of registrant as specified in its charter)

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.

Table of Contents

CREDO PETROLEUM CORPORATION AND SUBSIDIARIES

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

TABLE OF CONTENTS

The terms “CREDO”, “Company”, “we”, “our”, and “us” refer to CREDO Petroleum Corporation and its subsidiaries unless the context suggests otherwise.

2

Table of Contents

PART I - FINANCIAL INFORMATION

ITEM 1.  FINANCIAL STATEMENTS

CREDO PETROLEUM CORPORATION AND SUBSIDIARIES

Consolidated Balance Sheets

(Unaudited)

A S S E T S

3

Table of Contents

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

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

4

Table of Contents

CREDO PETROLEUM CORPORATION AND SUBSIDIARIES

Consolidated Statements of Operations

(Unaudited)

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

5

Table of Contents

CREDO PETROLEUM CORPORATION AND SUBSIDIARIES

Consolidated Statements of Cash Flows

(Unaudited)

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

6

Table of Contents

CREDO PETROLEUM CORPORATION AND SUBSIDIARIES

Notes To Consolidated Financial Statements (Unaudited)

January 31, 2011

1.             BASIS OF PRESENTATION

The accompanying unaudited consolidated financial statements have been prepared in accordance with U. S. generally accepted accounting principles for interim financial information and with the instructions for Form 10-Q and Article 10 of Regulation S-X.  Accordingly, they do not include all of the information and footnotes required by U. S. generally accepted accounting principles for complete financial statements. In the opinion of management, the consolidated financial statements contain all adjustments (consisting of normal recurring adjustments) considered necessary for a fair presentation of the company’s results for the periods presented.  Management has evaluated events and transactions occurring after the balance sheet date through the date the financial statements were issued.  For a more complete understanding of the company’s financial condition and accounting policies, these consolidated financial statements should be read in conjunction with the company’s Annual Report on Form 10-K for the fiscal year ended October 31, 2010.  The results for interim periods are not necessarily indicative of annual results.

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.  The company bases its estimates on historical experience and on various other assumptions it believes to be reasonable under the circumstances.  Although actual results may differ from these estimates under different assumptions or conditions, the company believes that its estimates are reasonable and that actual results will not vary significantly from the estimated amounts.

2.             OIL AND NATURAL GAS PROPERTIES

Depreciation, depletion and amortization of oil and natural gas properties for the three months ended January 31, 2011 and 2010 were $874,000 and $745,000 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 rentals, 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.

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 January 31, 2011 ceiling test was based on the average of the first-day-of-the-month prices during the twelve-month period prior to January 31, 2011 pursuant to the SEC’s “Modernization of Oil and Gas Reporting” rule, which was effective for the company beginning with October 31, 2010 reporting.  If 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.  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, 2011 and 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

7

Table of Contents

properties.  Therefore, a ceiling test write-down was not required.

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.  The ceiling test is not a fair value based measurement.  Rather it is a standardized mathematical calculation and 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.

3.             STOCK-BASED COMPENSATION

For the three months ended January 31, 2011 and 2010, the company recognized stock based compensation expense of $17,000 and $8,000 respectively.  The estimated unrecognized compensation cost from unvested stock options as of January 31, 2011 was approximately $110,000 which is expected to be recognized over an average of 1.9 years.

No options were granted during fiscal year 2011.  The fair value of the 50,000 options granted during the three months ended January 31, 2010 was estimated as of the grant date using the Black-Scholes option pricing model with the following assumptions:  volatility, 51.6%; expected option term, 3 years; risk-free interest rate, 2.69% and; expected dividend yield, 0%.  If option grants are made in the future, compensation expense for all such share-based payments granted, based upon the grant-date fair value estimate will also be included in compensation expense.

Plan activity for the three months ended January 31, 2011 is set forth below:

8

Table of Contents

4.             OIL AND NATURAL GAS DERIVATIVES

The company manages exposure to commodity price fluctuations by periodically hedging a portion of estimated production when the potential for significant downward price movement is anticipated.  These transactions typically take the form of costless collars for oil. For natural gas the company uses forward short positions based upon the NYMEX futures market for which are closed by purchasing offsetting positions.  Such contracts do not exceed estimated production volumes and are authorized by the company’s Board of Directors.  Contracts are expected to relate to the timing of actual production but may be closed earlier if the anticipated downward price movement occurs or if the company believes that the potential for such movement has abated.

At January 31, 2011 the company held costless collar derivative contracts for 5,000 barrels of oil for each production month of February through December 2011 with a floor of $80.00 and a ceiling ranging from $90.50 to $97.50 per barrel.  The company also held costless collar derivative contracts for 3,000 barrels of oil for each production month of January through December 2012 with a floor of $80.00 and a ceiling ranging from $94.00 to $99.00 per barrel.

At January 31, 2011 the company held open derivative contracts representing natural gas short sales positions for 60,000 MMBtus at NYMEX basis prices ranging from $4.35 to $4.51 and covering the production months of February and March 2010.  Average prices in the company’s primary market are currently 2% below NYMEX prices due to basis differentials and transportation costs.

For the quarters ended January 31, 2011 and 2010 the company had realized gains (losses) on derivatives of $36,000 and ($10,000) respectively, and unrealized (losses) of ($741,000) and ($4,000), respectively.  Current quarter unrealized losses are attributable only to oil collar derivatives.

The company has a hedging line of credit with its bank which is available, at the discretion of the company, to meet margin calls.  To date, the company has not used this facility and maintains it only as a precaution related to possible margin calls.  The maximum credit line available is $7,200,000 with interest calculated at the prime rate.  The facility is unsecured and has covenants that require the company to maintain $3,000,000 in cash or short term investments, none of which are required to be maintained at the company’s bank, and prohibits funded debt in excess of $500,000.  The line expires May 1, 2013.

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

Derivatives not designated as hedging instruments:

9

Table of Contents

5.             INCOME TAXES

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

The 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, 2011 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.  Subsequent to January 31, 2011, the company was notified that its 2008 federal tax return had been selected for audit by the Internal Revenue Service.

6.             FAIR VALUE MEASUREMENTS

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

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

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

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

The classification of financial asset or liability within the hierarchy is determined based on the lowest level input that is significant to the fair value measurement.  The determination of the fair values below incorporates various factors required under fair value accounting guidance, including the impact of the counterparty’s non-performance risk with respect to the company’s financial assets and the company’s non-performance risk with respect to the company’s financial liabilities.  The following table provides the assets and liabilities carried at fair value measured on a recurring basis as of January 31, 2011:

10

Table of Contents

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, 2011:

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

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

7.             INTANGIBLE ASSETS

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

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

8.             COMMON STOCK

On September 22, 2008, the company’s Board of Directors authorized a Stock Repurchase Program and

11

Table of Contents

approved repurchase of the company’s common stock up to $2,000,000.  On April 9, 2009, the Board expanded the program to $4,000,000 and on July 29, 2010 the program was expanded to $5,000,000.  The repurchases may be made on the open market, in block trades or otherwise.  The stock repurchase program may be expanded, suspended or discontinued at any time.  At January 31, 2011, the company has acquired 545,429 shares under the program, at an aggregate cost of $4,755,000, or $8.72 per share.

Subsequent to January 31, 2011 and through March 10, 2011, no additional shares have been repurchased.

9.             EARNINGS PER SHARE

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

10.          CONCENTRATION OF CREDIT RISK

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

11.          COMMITMENTS AND CONTINGENCIES

The company has been named as a defendant in a lawsuit brought by a former employee.  The suit alleges breach of contract and other employment issues.  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, 2011.

12

Table of Contents

OPERATIONS

Summary

During the first quarter of fiscal 2011, the company’s operations continued to focus on its two core projects — oil and natural gas drilling and application of its patented Calliope Gas Recovery System.

The company believes that, in combination, its drilling and Calliope projects provide an excellent (and possibly unique) balance for achieving its goal of adding long-lived natural gas reserves and production at reasonable costs and risks.  However, it should be expected that successful results will occur unevenly for both the drilling and Calliope projects.  Drilling results are dependent on both the timing of drilling and on the drilling success rate.  Calliope results are primarily dependent on the timing, volume and quality of Calliope installations available to the company.

The company will continue to actively pursue adding reserves through its two core projects in fiscal 2011, and expects these activities to be a reliable source of reserve additions.  However, the timing and extent of such activities can be dependent on many factors which are beyond the company’s control, including but not limited to, the cost and quality of oil field services such as drilling rigs, production equipment and related services, and access to wells for application of the company’s patented gas recovery system on low pressure gas wells.  The prevailing price of oil and natural gas has a significant effect on demand and, thus, the related cost of such services and wells.

In recent years, the company has significantly expanded both the volume and breadth of its drilling activities with new projects in North Dakota’s Bakken, the Texas Panhandle, Kansas and Nebraska.  Compared to conventional drilling, the North Dakota and Texas Panhandle horizontal drilling projects involve higher costs but significantly higher per well reserve potential.  Conventional drilling in Kansas and Nebraska is less expensive than in Oklahoma.  The company believes that all of the projects have excellent economic potential.

All of the company’s oil and natural gas properties are located on-shore in the continental United States.  The company’s future drilling activities may not be successful, and its overall drilling success rate may change.  Unsuccessful drilling activities could have a material adverse effect on the company’s results of operations and financial condition.  Also, the company may not be able to obtain the right to drill in areas where it believes there is significant potential for the company.

RESULTS OF OPERATIONS

Three Months Ended January 31, 2011 Compared to Three Months Ended January 31, 2010

For the three months ended January 31, 2011, oil and gas revenues increased to $3,250,000 compared to $3,142,000 during the same period last year.  As the oil and gas price/volume table on page 15 shows, oil sales prices increased 9% to $79.75 per barrel and natural gas sales prices decreased 16% to $4.34 per Mcf.  The net effect of these price changes was to decrease oil and gas sales by $70,000.  For the three months ended January 31, 2011, the company’s oil production increased 19% to 28,000 barrels while natural gas production declined 15% to 234,000 Mcf.  Total production, at a 6 to 1 oil to gas conversion ratio, fell 3% to 67,000 BOE.  The increased oil production volume, combined with oil to gas conversion ratios, more than offset the decline in natural gas production, resulting in a revenue increase of $178,000.  The company had realized gains of $36,000 from natural gas derivatives for the quarter ended January 31, 2011 compared to a loss of $10,000 in the prior year.  Unrealized derivative losses of $741,000 at January 31, 2011 are primarily due to oil collar derivatives.

13

Table of Contents

For the three months ended January 31, 2011, total costs and expenses increased 4% to $2,346,000 compared to $2,263,000 for the comparable period in 2010.  Oil and gas production expenses were virtually unchanged as reduced field level expenses were offset by an increased number of operating wells. DD&A increased primarily due to an increase 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 25% and 26% for the 2011 and 2010 periods, respectively.  The effect of percentage depletion deductions is the primary cause of the variation of the effective tax rate from the statutory rate.

LIQUIDITY AND CAPITAL RESOURCES

At January 31, 2011, working capital was $5,823,000 compared to $9,661,000 at October 31, 2010 primarily due to capital expenditures for oil and gas activities.  For the three months ended January 31, 2011, net cash provided by operating activities was $2,318,000 compared to $1,312,000 for the same period in 2010.

For the three months ended January 31, 2011 and 2010, net cash used in investing activities was $2,539,000 and $864,000, respectively.  Investing activities primarily included oil and gas lease acquisition, exploration and development expenditures.

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, 2011, 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, and unrealized derivative gains and losses, (“Adjusted EBITDA”) was $1,960,000 for the three months ended January 31, 2011 compared to $1,733,000 for the three months ended January 31, 2010.  Adjusted EBITDA is not a GAAP measure of operating performance.  The company uses this non-GAAP performance measure primarily to compare its performance with other companies in the industry that make a similar disclosure.  The company believes that this performance measure may also be useful to investors for the same purpose.  Investors should not consider this measure in isolation or as a substitute for operating income, or any other measure for determining the company’s operating performance that is calculated in accordance with GAAP.  In addition, because Adjusted EBITDA is not a GAAP measure, it may not necessarily be comparable to similarly titled measures employed by other companies.  Reconciliation between Adjusted EBITDA and net income is provided in the table below:

OFF-BALANCE SHEET FINANCING

The company has no off-balance sheet arrangements at January 31, 2011.

14

Table of Contents

PRODUCT PRICES AND PRODUCTION

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

The oil and natural gas average sales prices reflected in the table below exclude the effects of commodity derivative instruments since the company has elected not to designate derivative instruments as cash flow hedges. See Note 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.

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

Recent Drilling Activities.

Bakken Shale — Credo has leased approximately 8,000 gross (6,000 net) acres on the Ft. Berthold 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.  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 continues to escalate rapidly.

At January 31,2011, the company’s first Bakken horizontal well, the Petro Hunt 148-94-17D-08-1H (“17-D”), located on the Fort Berthold Reservation, has been on production for approximately fourteen months and is on pump.  Through the first fourteen months the well has produced about 92,000 BOE.  Credo owns a 10% working interest.

The company’s second Bakken well (Brigham Weisz 11-14) tested at an initial rate of 2,278 BOEPD on a 48/64” choke, and has produced approximately 60,000 BOE in six months.  The well is located about 50 miles northwest of the Petro-Hunt 17-D in Williams County.  Credo owns a 6.25% working interest in the well.  Brigham’s development plans for the spacing unit could potentially include three additional

15

Table of Contents

Bakken wells and up to four Sanish/Three Forks wells.

The company’s third high rate Bakken producer was recently completed.  The Petro-Hunt 3-A well was drilled on a 1,280-acre spacing unit with an approximate 10,000-foot lateral, and was fracture stimulated in 25 stages.  The well flowed at a restricted rate of 1,367 barrels of oil equivalent during a 24-hour test on a small (18/64”) choke with flowing casing pressure of 3,050 psi and has produced more than 25,000 barrels of oil in less than three months.  While the well was drilled in fiscal 2010, the completion phase was delayed until January, 2011 due to shortages of fracture stimulation equipment.  The well is located in Dunn County on the Fort Berthold Reservation about four miles southeast of the company’s Petro-Hunt 17-D well.  Credo owns an 18.75% working interest in the new well.  The company expects to drill at least nine wells on its Bakken acreage during 2011.

Central Kansas Uplift — In Kansas and Nebraska, the company owns interests in approximately 147,000 gross acres and 85,000 net acres and it is continuing to expand its acreage position.  At January 31, 2010, the company has participated in drilling 77 wells on its acreage, of which approximately 40% have been successfully completed as producers.  The company’s Kansas and Nebraska drilling activities provide scientific diversification to the company’s drilling program through the use of 3-D seismic to identify shallow oil prospects.  The company is continuing to conduct an active drilling program expected to consist of two to three wells per month for the next few years with working interests ranging from 12.5% to 95%.

Texas Panhandle — In the Texas Panhandle, the company owns an average 33% working interest in about 3,000 gross acres.  The company has recently drilled its first horizontal well.  The 7,600-foot vertical depth well has an approximate 5,000-foot horizontal lateral and is expected to primarily produce oil from the Tonkawa formation.  Credo owns a 22% working interest in the well with Chesapeake Energy Corporation, the nation’s most active driller, as the Operator.  Drilling and high pressure fracturing have been completed, a pumping unit has been installed, and fracture fluids are being recovered.  During the fluid recovery operation, the oil cut has continued to increase and the well has produced more than 7,500 BOE to date.  The company’s second horizontal Tonkawa well in the Texas Panhandle, the Credo-operated Bussard Cameron 74-1H, encountered sloughing shale about 2,000 feet into the projected 4,000-foot lateral.  Because the well had previously encountered good quality sand and very good shows, the decision was made to cease drilling operations at about 2,000 feet and set pipe.  The well is currently awaiting fracture stimulation and completion.

Calliope Gas Recovery Technology

Credo remains committed to the company’s patented Calliope Gas Recovery System.  An installation is now in process in Oklahoma and additional wells are being targeted for this proven technology.  In addition, Calliope is generating interest from new players with fresh ideas as rapidly growing international companies seek innovative solutions to capture energy reserves.  Monetizing Calliope’s value remains a top company priority.

16

Table of Contents

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;

·      effectiveness of the company’s hedging transactions;

·      investment strategy and risk; and

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

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

·      unexpected changes in business or economic conditions;

·      significant changes in natural gas and oil prices;

·      timing and amount of production;

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

·      changes in overhead costs;

·      material events resulting in changes in estimates; and

·      competitive factors.

All forward-looking statements speak only as of the date made.  All subsequent written and oral forward-looking statements attributable to the company, or persons acting on the company’s behalf, are expressly

17

Table of Contents

qualified in their entirety by the cautionary statements.  Except as required by law, the company undertakes no obligation to update any forward-looking statement to reflect events or circumstances after the date on which it is made or to reflect the occurrence of anticipated or unanticipated events or circumstances.

ITEM 3.          QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The company manages exposure to commodity price fluctuations by periodically hedging a portion of estimated production when the potential for significant downward price movement is anticipated.  These transactions typically take the form of costless collars for oil and forward short positions based upon the NYMEX futures market for natural gas, and are closed by purchasing offsetting positions.  Such contracts do not exceed estimated production volumes and are authorized by the company’s Board of Directors.  Contracts are expected to be closed as related production occurs but may be closed earlier if the anticipated downward price movement occurs or if the company believes that the potential for such movement has abated.

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

ITEM 4.          CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

Our management, with the participation of Marlis E. Smith, Jr., our Chief Executive Officer, and Alford B. Neely, our Chief Financial Officer, evaluated the effectiveness of our disclosure controls and procedures as of January 31, 2011.  Based on the evaluation, these officers have concluded that:

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

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

Internal Control Over Financial Reporting

There has not been any change in our internal control over financial reporting that occurred during the quarter ended January 31, 2011 that has materially affected or is reasonably likely to materially affect, our internal control over financial reporting.

PART II - OTHER INFORMATION

ITEM 1.         LEGAL PROCEEDINGS

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

ITEM 1A.      RISK FACTORS

There have been no material changes from the risk factors previously disclosed in the company’s Annual Report on Form 10-K for the fiscal year ended October 31, 2010.

18

Table of Contents

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

Issuer Purchases of Equity Securities.

During the first quarter of fiscal year 2011, the company repurchased 18,000 shares of its common stock on the open market at a weighted average price of $8.04.  The purchases were made pursuant to a stock repurchase plan announced on September 24, 2008 and extended by the Board of Directors on April 9, 2009 and July 29, 2010.  The extended plan authorized repurchases up to $5,000,000, but could be expanded, suspended or discontinued at any time.  At January 31, 2010, the company has repurchased 545,429 shares of common stock at an average price per share of $8.72.

Subsequent to January 31, 2010, and through March 10, 2010, no additional shares have been purchased.

Issuer Purchases of Equity Securities