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, 2012

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  x  No  o

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

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, 2012

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

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

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, 2012

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, 2011.  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, 2012 and 2011 were $1,715,000 and $874,000, 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 amortized 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 amortizable costs.

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

7

Table of Contents

be written off shall not be reinstated for any subsequent increase in the cost center ceiling.

At January 31, 2012 and 2011, no ceiling test write-down was required.

3.             STOCK-BASED COMPENSATION

For the three months ended January 31, 2012 and 2011, the Company recognized stock based compensation expense of $15,000 and $17,000, respectively.  At January 31, 2012 the balance of unrecognized compensation cost from unvested stock options was zero.

No options were granted during fiscal year 2012.  The fair value of the 30,000 options granted during fiscal year 2011 was estimated as of the grant date using the Black-Scholes option pricing model with the following assumptions:  volatility, 50.1%; expected option term, 4 years; risk-free interest rate, 2.28% and; expected dividend yield, 0%.  If option grants are made in the future, compensation expense for all such share-based payments granted, based upon the grant-date fair value estimate will also be included in compensation expense.

Plan activity for the three months ended January 31, 2012 is set forth below:

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 or to assure availability of cash flow for anticipated debt service.  These transactions typically take the form of costless collars or forward short positions which are generally based upon the NYMEX futures prices. Hedge contracts are closed by purchasing offsetting positions.  Such hedges are authorized by the

8

Table of Contents

Company’s Board of Directors and do not exceed estimated production volumes for the months hedged.  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.

At January 31, 2012, the Company held short sales open derivative contracts for 6,000 barrels of oil for each production month of February 2012 through December 2012 with prices ranging from $91.95 to $93.00.  This hedge will be approximately 15% to 25% of estimated oil production for the hedged period.  The Company held no open derivative contracts for natural gas at January 31, 2012.

For the quarter ended January 31, 2012, the Company had a realized derivative loss of $44,000 and an unrealized loss of $481,000, compared to a $36,000 realized gain and a $741,000 unrealized loss for the same quarter last year.

At January 31, 2012, the Company had a hedging line of credit with its bank which is available, at the discretion of the Company, to meet margin calls.  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.

On February 16, 2012, the Company replaced the hedging line of credit with a Revolving Credit Agreement that includes a hedging line of credit.  See Note 5 to the Consolidated Financial Statements for further discussion of the new revolving line of credit.  During the first quarter of fiscal 2012, the covenants in the hedging line of credit were suspended in anticipation of completion of the revolving credit line.

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 on the Consolidated Balance Sheet and amount of derivative fair values is shown in the tables below:

The amount of derivative gain or (loss) included in “Other Income and Expense” is set forth in the table below:

5.             REVOLVING CREDIT LINE

At first quarter end the Company had no debt.  However, during fiscal 2012, the Company expects to borrow between $7 million and $12 million to partially finance its drilling activities.  On February 16, 2012, the Company entered into a Revolving Credit Agreement (the Agreement) with its principal bank, Bank of Oklahoma, NA.  The Agreement provides for a $25,000,000 credit facility.  The Agreement will mature in December 2016.  The credit availability under the Agreement is governed by a Borrowing Base, the determination of which is made semi-annually by the lender based on review of the Company’s reserves at April 30 and October 31.  The borrowing base under the Agreement could increase or decrease based on such redetermination.  In addition to the semi-annual redeterminations, the Company and the lender each have discretion at any time, but not more often than once during a calendar year, to have the Borrowing Base redetermined.  The initial borrowing base is $7 million and will be increased as

9

Table of Contents

the Company pledges additional collateral.  The Company has drawn down $2 million subsequent to January 31, 2012.

The Company must elect between one of two interest rates as follows:

(i)                         a rate that is based on interest rates applicable to dollar deposits in the London interbank market (“LIBOR Rate”) plus 175 to 275 basis points, depending on Borrowing Base utilization; or

(ii)                      a rate based on the greatest of (a) the prime rate announced by the Bank of Oklahoma; or (b) the federal funds rate plus 1/2 of 1%.

The Agreement includes terms and covenants that place limitations on certain types of activities, including restrictions or requirements with respect to additional debt, liens, asset sales, hedging activities, investments, dividends, mergers, and acquisitions, and also includes financial covenants.  If the Company were to fail to perform its obligations under these covenants or other covenants and obligations, it could cause an event of default and the Agreement could be terminated and amounts outstanding could be declared immediately due and payable by the lender, subject to notice and cure periods in certain cases.  Such events of default include non-payment, breach of warranty, non-performance of financial covenants, certain adverse judgments, change of control, or a failure of the liens securing the Borrowing Base.

6.             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.

The Company’s Federal Income Tax Returns for fiscal years 2010, 2009 and 2008 have been audited by the IRS and the IRS Agent’s Report has been received.  The Agent’s Report asserts multiple complex tax issues and potential additional tax due.  The Company has appealed the assertions.  Should the Company not prevail on the appeal, no additional tax would be due as NOL carry forwards would be applied to those years.  However, a non-cash charge to earnings of approximately $215,000 could result on loss of all or part of the appeal.  The Company believes the position of the IRS is without merit.

7.             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 oil and natural gas production.  These derivatives are carried at fair value on the consolidated balance sheets.  Additionally, the Company’s short-term investments consist partially 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

10

Table of Contents

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, 2012:

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, 2012:

(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.

8.                                      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.

11

Table of Contents

9.                                      COMMON STOCK

On September 22, 2008, the Company’s Board of Directors authorized a Stock Repurchase Program and approved repurchase of the Company’s common stock up to $2,000,000.  On April 9, 2009, the Board expanded the program to $4,000,000 and on July 29, 2010 the program was expanded to $5,000,000.  The repurchases may be made on the open market, in block trades or otherwise.  The stock repurchase program may be expanded, suspended or discontinued at any time.  At January 31, 2012, 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, 2012 and through March 12, 2012, no additional shares have been repurchased.

10.                               EARNINGS PER SHARE

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

11.                               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.

12.                               COMMITMENTS AND CONTINGENCIES

The Company has no material outstanding commitments or contingencies at January 31, 2012.

12

Table of Contents

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

OPERATIONS

Summary

During the first quarter of fiscal 2012, the Company’s operations focused primarily on its oil drilling projects in the North Dakota Bakken and Three Forks shale-oil play and in Kansas, Nebraska and the Texas Panhandle.  The Company expects these activities to be a reliable source of oil production and reserve additions.  However, the timing and extent of such activities can be dependent on many factors which are beyond the Company’s control, including for non-operated properties, the timing decisions of the well “operators” related to drilling, the availability of oil field services such as drilling rigs, fracture stimulation equipment and related services, and particularly in North Dakota, the weather. The price of oil and natural gas has a significant effect on the demand for, and cost of, drilling and oil field services.

The Company believes that its geographically and technically diverse oil drilling projects provide an excellent balance for achieving its goal of adding oil reserves and production at reasonable costs and risks. Horizontal drilling results are expected to occur relatively evenly due to the more developmental nature of the drilling.  Vertical drilling results will occur less evenly due to the more exploratory nature of the projects.

RESULTS OF OPERATIONS

Three Months Ended January 31, 2012 Compared to Three Months Ended January 31, 2011

Oil and gas revenues increased to $5,821,000 compared to $3,250,000 during the same period last year.  As the oil and gas price/volume table on page 15 shows, oil production increased 99% to 55,700 barrels while natural gas production declined 9% to 212,000 Mcf.  Total production, at a 6 to 1 oil to gas conversion ratio, increased 36% to 91,000 BOE.  The increased oil production more than offset the decline in natural gas production, resulting in a revenue increase of $2,416,000.  Oil sales prices increased 13% to $90.33 per barrel and natural gas sales prices decreased 14% to $3.73 per Mcf. The net effect of these price changes was to increase oil and gas sales by $155,000.  Realized oil-derivative losses were $44,000 compared to a gain of $36,000 in the prior year.  Unrealized oil derivative losses declined 35% to $481,000 compared to $741,000 last year.

Total costs and expenses increased 61% to $3,769,000 compared to $2,346,000 for the comparable period in 2011.  Oil and gas production expenses increased 37% due primarily to increased ad valorum taxes due to increased property values and increased production taxes resulting from increased revenue.  Production expenses also increased due to the increasing number of wells owned by the Company.  DD&A increased primarily due to an increase in costs being amortized which include future development costs related to proved undeveloped oil reserves in the Bakken.  Refer to the MD&A section (Item 7) of the Company’s Form 10-K for the fiscal year ended October 31, 2011 for additional information regarding “Certain Significant Effects of the Company’s Strategic Transition to Oil from Natural Gas”.  General and administrative expenses increased primarily due to salaries, employment costs and professional fees.  The effective tax rate increased to 32% compared to 25% for the same period last year.  The increase, required to be calculated on an annualized basis, is primarily due to the 1,000 barrel per day limitation on percentage depletion.  As the Company’s fiscal 2012 production grows beyond the 1,000 barrel per day tax limitation, percentage depletion will have proportionately less impact on reducing the effective tax rate.

13

Table of Contents

LIQUIDITY AND CAPITAL RESOURCES

At January 31, 2012, working capital was $1,708,000 compared to $2,940,000 at October 31, 2011 primarily due to capital expenditures for oil and gas properties exceeding cash flow from operating activities.  For the three months ended January 31, 2012, net cash provided by operating activities was $3,741,000 while expenditures on oil and gas properties was $4,369,000.

Drilling expenditures are expected to more than double in fiscal 2012 to $35,000,000 and, for the first time in the Company’s history, financing will be required to fund a portion of future drilling expenditures.  To provide financing, the Company has established a revolving credit line with its principal bank which provides for a $25,000,000 credit facility.  The initial borrowing base is $7 million but will be increased as the Company pledges additional collateral.  Borrowing in 2012 is expected to range from $7 million to $12 million.  The credit availability under the Agreement is governed by a Borrowing Base, the determination of which is made semi-annually by the lender based on review of the Company’s reserves at April 30 and October 31.  To date, the Company has drawn $2 million on the line of credit at an effective interest rate of 3.5%.

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”) increased 96% to $3,842,000 for the three months ended January 31, 2012 compared to $1,960,000 last year.  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, 2012

PRODUCT PRICES AND PRODUCTION

The table below shows the Company’s oil and gas production volumes and average wellhead prices for the reported periods.  For the first quarter of fiscal 2012, oil represents 61% of total production (on an energy equivalent basis) compared to 42% for the prior year.  Wellhead prices do not include oil derivative gains and losses since the Company has elected not to designate derivative instruments as cash flow hedges.

14

Table of Contents

Three Months Ended January 31,

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.  The Company periodically hedges the price of a portion of its estimated production when the potential for significant downward price movement is anticipated, or to assure availability of a portion of the cash flow for anticipated debt service.  Such hedges are authorized by the Company’s Board of Directors and they do not exceed estimated production volumes for the periods hedged.  Hedging transactions may take the form of costless collars or forward short positions and are generally based on the NYMEX futures prices at the time the transactions are initiated.  The positions are normally closed by purchasing offsetting positions.  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 quarter ended January 31, 2012, realized hedging losses were $44,000 compared to a $36,000 gain last year.  The effect of realized derivative gains and losses on average well head price realizations are shown in the following table:

Three Months Ended January 31,

See Note 4 of the Notes to Consolidated Financial Statements and comments under MD&A, “Results of Operation”, for more information regarding hedging gains and losses relating to oil derivative instruments.

Recent Drilling Activities.

Capital expenditures for fiscal 2012 are estimated to be a record $35,000,000, a 126% increase over last year.  Eighty five (85) gross (37 net) oil wells are currently scheduled to be drilled in fiscal 2012, representing an 85% increase in net wells over last year.  During the first quarter of 2012, 15 gross (8.6 net) wells were drilled and completed or were in various stages of drilling and completion at quarter end.  Weather conditions in the winter and spring are generally anticipated to curtail drilling in some of the company’s operating areas such as North Dakota.  Accordingly, drilling does not occur ratably over the year and the Company’s 2012 drilling programs are currently on schedule.  The regional allocation of the Company’s drilling budget is shown below (in millions).

15

Table of Contents

Bakken and Three Forks Play — In North Dakota’s Bakken and Three Forks shale-oil play, the Company has assembled approximately 6,300 net acres (73,000 gross acres based on interests in approximately 57 spacing units consisting of 1,280 acres).  Virtually all of the acreage is located in the core of the play on the Fort Berthold Reservation, south and west of the Parshall Field.  Fifty (50) of the spacing units are classified as prime.  While the Company’s interest differs in individual spacing units, its average working interest is approximately 9%.  The Company believes that a minimum of two Bakken and two Three Forks wells are likely to be drilled on most of the prime spacing units representing about 200 wells.  However, many of the larger Bakken operators predict that up to eight wells may be drilled in many spacing units, which could double potential Company wells.

Drilling on the Company’s acreage is in its infancy, but is rapidly increasing.  To date, the Company has completed 12 Bakken and Three Forks wells, all high rate producers.  The Company currently projects at least 20 new wells in fiscal 2012, for a total of 32 wells by year end 2012.  The Company’s average working interest in the wells is approximately 9.0%.  Seven of the 20 wells projected for 2012 are currently in various stages of being drilled or completed.  Three of the wells target the Three Forks formation and four target the Bakken formation.

The Company is participating as a non-operator with highly experienced Bakken operators.  In all cases, where a well has been drilled on a spacing unit, the Company expects additional development wells to be drilled on those spacing units.

The Company’s Bakken and Three Forks acreage position is subject to agreements with a third party which grant the third party an option to purchase between 5% and 10% of the Company’s interest in individual leases under certain specified circumstances.  To date, the Company believes that the third party has properly exercised its option on only one lease.

Kansas and Nebraska — The Company is continuing to lease aggressively in Kansas and Nebraska, and currently owns approximately 147,000 gross (85,000 net) acres.  The Company is conducting primarily a wildcat oil drilling project using subsurface geology which is generally confirmed by 3-D seismic.  For 2012, the Company estimates that it will participate in 52 gross (29 net) wells in Kansas and Nebraska with an average working interest of approximately 56%.  During the first quarter of 2012, the Company participated in 9 gross (5.7 net) wells with an average 63% working interest.  To date, the Company has participated in 114 gross (50 net) wells with an average 44% working interest.  The Company’s overall drilling success rate is about 42%, which it believes is approximately the same success rate as other knowledgeable companies involved in the area.  Wells are drilled to a vertical depth of 4,000 to 5,000 feet. The Company will be the operator of approximately 65% of the wells expected to be drilled in 2012.

Texas Panhandle — In the Texas Panhandle, the Company’s acreage consists of 8,500 gross (2,400 net) acres with the potential for multi-pay, horizontal and vertical drilling.  The Company currently owns interests in two gross (0.5 net) producing horizontal Tonkawa wells with an average working interest of 23%.  It also owns interests in 12 gross (.9 net) producing vertical wells with an average working interest of 7%.

The Company is conducting horizontal drilling projects in the Tonkawa and Cleveland formations and vertical drilling in the Morrow formation.  Horizontal wells are drilled on 320 or 640 acre spacing.  The Company owns interests in six 640 acre spacing units that are prospective for Tonkawa and Cleveland

16

Table of Contents

horizontal drilling and believes that each spacing unit could ultimately contain two Tonkawa and two Cleveland wells.  The Company’s two horizontal Tonkawa wells continue to be strong producers, and its first horizontal Cleveland well is scheduled to spud this spring.  The Company believes there is potential for up to 24 horizontal wells on its acreage, and estimates its average working interest to range between 25% and 30%.

Natural gas drilling in Oklahoma has been suspended pending a recovery in natural gas prices.  Accordingly, no gas wells are projected for Oklahoma during 2012. Most of the Company’s Oklahoma acreage is held by production and, thus, the timing of drilling is not critical to maintaining the Company’s leasehold ownership.

Calliope Gas Recovery Technology

The Company is taking advantage of opportunities created by low natural gas prices to buy wells for application of its patented Calliope Gas Recovery System.  A team is dedicated to Calliope with the objective of acquiring Calliope candidates, as companies de-emphasize natural gas and “offload” gas properties while shifting to oil development.

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.

17

Table of Contents

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

·                  unexpected changes in business or economic conditions;

·                  significant changes in natural gas and oil prices;

·                  timing and amount of production;

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

·                  changes in overhead costs;

·                  material events resulting in changes in estimates; and

·                  competitive factors.

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

ITEM 3.                        QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The Company manages exposure to commodity price fluctuations by periodically hedging a portion of estimated production when the potential for significant downward price movement is anticipated or to assure availability of cash flow for anticipated debt service. These transactions typically take the form of costless collars or forward short positions which are generally based upon the NYMEX futures prices. Hedge contracts are closed by purchasing offsetting positions.  Such hedges are authorized by the Company’s Board of Directors and do not exceed estimated production volumes for the months hedged.  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 Michael D. Davis, our Chief Executive Officer (Interim), and Alford B. Neely, our Chief Financial Officer, evaluated the effectiveness of our disclosure controls and procedures as of January 31, 2012.  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.

18

Table of Contents

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, 2012 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

The Company has filed a lawsuit for declaratory judgment regarding its contract rights under agreements with a third party related to its allotted lands Bakken and Three Forks leases.  The third party has asserted certain counterclaims.  The Company believes that the counter claims are without merit.

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, 2011.

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

Issuer Purchases of Equity Securities.

On September 22, 2008, the company’s Board of Directors authorized a Stock Repurchase Program and approved repurchase of the company’s common stock up to $2,000,000.  On April 9, 2009, the Board expanded the program to $4,000,000 and on July 29, 2010 the program was expanded to $5,000,000.  The repurchases may be made on the open market, in block trades or otherwise.  The stock repurchase program may be expanded, suspended or discontinued at any time.  As the following table shows, January 31, 2012, the company has acquired 545,429 shares under the program, at an average price of $8.72 per share.

19

Table of Contents

Issuer Purchases of Equity Securities