UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

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  ý    No  o

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act).  Yes  o   No  ý

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.

CREDO PETROLEUM CORPORATION AND SUBSIDIARIES

Quarterly Report on Form 10-Q For the Period Ended April 30, 2005

TABLE OF CONTENTS

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

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

Statement of Stockholders’ Equity and Comprehensive Income

(Unaudited)

For the Six Months Ended April 30, 2005

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)

April 30, 2005

1.             BASIS OF PRESENTATION

Effective November 1, 2004, the company became subject to full SEC reporting requirements.  The company’s first filing subject to full reporting requirements was its quarterly report on Form 10-Q for the first fiscal quarter ended January 31, 2005.

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.  These consolidated financial statements should be read in conjunction with the company’s Form 10-KSB for the fiscal year ended October 31, 2004.

2.             SIGNIFICANT ACCOUNTING POLICIES

The preparation of financial statements in conformity with generally accepted accounting principles requires the company to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The company bases its estimates on historical experience and on various other assumptions it believes to be reasonable under the circumstances.  Although actual results may differ from these estimates under different assumptions or conditions, the company believes that its estimates are reasonable and that actual results will not vary significantly from the estimated amounts.  The company believes the following accounting policies and estimates are critical in the preparation of its consolidated financial statements: the carrying value of its oil and 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 gas properties.  Capitalized costs included in the full cost pool are depleted on an aggregate basis using the units-of-production method.  Depreciation, depletion and amortization is a significant component of oil and gas properties. A reduction in proved reserves without a corresponding reduction in capitalized costs will cause the depletion rate to increase.

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

The capitalized costs in the full cost pool are subject to a quarterly ceiling test that limits such pooled costs to the aggregate of the present value of future net revenues attributable to proved oil and 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.  Any such write-down will reduce earnings in the period of occurrence and result in lower depreciation and depletion in future periods.  A write-down may not be reversed in future periods, even though higher oil and gas prices may subsequently increase the ceiling.

The company has made only one ceiling write-down in its 27-year history.  That write down was made in 1986 after oil prices fell 51% and gas prices fell 45% between fiscal year end 1985 and 1986.

Changes in oil and gas prices have historically had the most significant impact on the company’s ceiling test. In

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

OIL AND GAS RESERVES.  The determination of depreciation and depletion expense as well as ceiling test write-downs, if any, related to the recorded value of the company’s oil and gas properties are highly dependent on the estimates of the proved oil and gas reserves.  Oil and 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 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 gas ultimately recovered and the corresponding lifting costs associated with the recovery of these reserves.

At October 31, 2004, the date of the company’s most recent reserve report, the company’s reserves, and reserve values, were concentrated in 43 properties (“Significant Properties”).  Some of the Significant Properties were individual wells and others were multi-well properties.  The Significant Properties represent 24% of the company’s total properties but a disproportionate 75% of the discounted value (at 10%) of the company’s reserves.  Individual wells on which the company’s patented liquid lift system is installed comprised 26% of the Significant Properties and represented 37% of the discounted reserve value of such properties.  At October 31, 2004, relatively new wells comprised 30% of the Significant Properties and represented 30% of the discounted value of such properties.

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

Price changes will affect the economic lives of oil and gas properties and, therefore, price changes may cause reserve revisions.  Price changes have not caused significant proved reserve revisions by the company except in 1986 when a 51% decline in oil prices and a 45% decline in gas prices resulted in an 8.7% reduction in estimated proved reserves.  Based upon this historical experience, the company does not believe its reserve estimates are particularly sensitive to prices changes within historical ranges.

One measure of the life of the company’s proved reserves can be calculated by dividing proved reserves at a fiscal year end by production for that fiscal year.  This measure yields an average reserve life of nine years.  Since this measure is an average, by definition, some of the company’s properties will have a life shorter than the average and some will have a life longer than the average.  The expected economic lives of the company’s properties may vary widely depending on, among other things, the size and quality, natural gas and oil prices, possible curtailments in consumption by purchasers, and changes in governmental regulations or taxation.  As a result, the company’s actual future net cash flows from proved reserves could be materially different from its estimates.

The company is not aware of any material adverse issues related to its reserves regarding regulatory approval, the availability of additional development capital, or the installation of additional infrastructure.

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ASSET RETIREMENT OBLIGATIONS.  SFAS No. 143, “Accounting for Asset Retirement Obligations” requires that the company estimate the future cost of asset retirement obligations, discount that cost to its present value, and record a corresponding asset and liability in its Consolidated Balance Sheets.  The values ultimately derived are based on many significant estimates, including future abandonment costs, inflation, 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.

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 separate 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.

The company’s operating revenue is comprised of contractually based payments made to the company, as operator, to drill and supervise oil and gas wells.  The company reports these revenues gross for the amounts received before taking into account related costs which are recorded as separate expenses.  Revenue is recorded in the month it is earned.  The company views providing these services as a way to control the operations on wells in which it owns an interest.

3.             STOCK-BASED COMPENSATION

In December 2002, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No. 148, “Accounting for Stock-Based Compensation – Transition and Disclosure, an amendment of SFAS No. 123.”  Among other provisions, the statement amends the disclosure requirements of SFAS No. 123, “Accounting for Stock-Based Compensation.” Under current accounting rules the company elected to account for its stock-based employee compensation under the intrinsic value method established by Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees.”

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If compensation expense had been determined in accordance with the provisions of SFAS No. 123, the company’s net income and net income per share of common stock would have been reported as follows:

4.             NATURAL GAS PRICE HEDGING

The company periodically hedges 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 and collars in the NYMEX futures market, and are closed by purchasing offsetting positions.  Such hedges, which are accounted for as cash flow hedges, do not exceed estimated production volumes, are expected to have reasonable correlation between price movements in the futures market and the cash markets where the company’s production is located, and are authorized by the company’s Board of Directors.  Hedges 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 recognizes all derivatives on the balance sheet at fair value at the end of each period.  Changes in the fair value of a cash flow hedge are recorded in Stockholders’ Equity as Accumulated Other Comprehensive Income on the Consolidated Balance Sheets and then are reclassified into the Consolidated Statement of Earnings as the underlying hedged item affects earnings.  Amounts reclassified into earnings related to natural gas hedges are included in oil and gas sales.

Hedging gains and losses are recognized as adjustments to gas sales as the hedged product is produced.  The company had after tax hedging losses of $202,000 in the first six months of 2005 and $41,000 for the same period in 2004.  Any hedge ineffectiveness is immediately recognized in gas sales.  Subsequent to the end of the second fiscal quarter, the company closed its May and June contracts for 220 MMbtu with an after tax loss of $37,000.  The company’s current open hedge position is 420 MMbtu covering the months of July through September 2005 and December 2005 and January 2006.  These hedging contracts represent approximately 50% to 55% of the company’s estimated gas equivalent production for the months of July through September 2005 and 25% to 30% of the company’s estimated gas equivalent production for December 2005 and January 2006.  July through September hedges are collars with a weighted average floor price of $6.02 and a weighted average ceiling price of $7.15 totaling 100 MMbtu in each month.  December 2005 and January 2006 hedges are collars with a weighted average floor price of $7.00 and a weighted average ceiling price of $8.68 totaling 60 MMbtu in each month.

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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 is $2,000,000 with interest calculated at the prime rate.  The facility is unsecured and requires the company to maintain $3,000,000 in cash or short term investments and prohibits unfunded debt in excess of $500,000.  It expires on October 31, 2006.

5.             COMPREHENSIVE INCOME

Comprehensive income includes all changes in equity during a period except those resulting from investments by owners and distributions to owners.  The components of comprehensive income for the three and six months ended April 30, 2005 and 2004 are as follows:

6.             EARNINGS PER SHARE

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

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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 extremely 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.

8.             COMMITMENTS

Effective January 1, 2005, the company entered into an exploration agreement to generate and market gas drilling prospects in South Texas.  The agreement commits the company to spend a maximum of $1,500,000 over two years primarily for seismic, leases and administrative costs.  Through April 30, 2005 the company has made payments of $370,000 towards this commitment.  The company owns 75% of the venture before payout and will own 37.5% after payout.  Drilling of generated prospects is not covered by the agreement.  The company’s drilling cost, if any, will depend upon its election to participate with, or sell, all or a portion of its interest in any prospect generated.

In April 2005, the company committed approximately $1,000,000 over an expected two-year period to purchase a 25% interest in 15,000 gross acres along the Central Kansas Uplift, in Graham and Sheridan counties, Kansas, participate in a 3-D seismic survey, and drill five exploratory wells.  Subsequent drilling will be determined by results from the initial wells.  Approximately 25 square miles of proprietary 3-D seismic will be shot to define Lansing-Kansas City oil prospects at about 4,000 feet.

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

FORWARD-LOOKING STATEMENTS

Certain information included in this quarterly report and other materials filed by the company with the Commission contain 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.  These statements relate to the company’s operations and the oil and gas industry, in general.  Such forward-looking statements are based on management’s current projections and estimates and are identified by words such as “expects,” “intends,” “plans,” “projects,” “anticipates,” “believes,” “estimates” and similar words.  These statements are

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not guarantees of future performance and involve certain risks, uncertainties and assumptions that are difficult to predict.  Therefore, actual results may differ materially from what is expressed or forecasted in such forward-looking statements.  Among many factors that could cause actual results to differ materially are:  (i) natural gas and crude oil price fluctuations, (ii) the company’s ability to acquire oil and gas properties that meet its objectives and to identify prospects for drilling, and (iii) potential delays or failure to achieve expected production from existing and future exploration and development projects.  In addition, such forward-looking statements may be affected by general domestic and international economic and political conditions.

LIQUIDITY AND CAPITAL RESOURCES

At April 30, 2005, working capital was $7,296,000, compared to $7,118,000 at April 30, 2004.  For the six months ended April 30, 2005, net cash provided by operating activities increased $2,749,000, or 217% to $4,017,000 when compared to net cash provided by operating activities of $1,268,000 for the same period in 2004.  This increase is primarily the result of increases in net income and other non-cash items of $631,000; a net decrease of $1,362,000 in short term investments in 2005 versus a net increase in short term investments of $1,698,000 in 2004 which resulted in a net change of $3,060,000 between the two periods; a net increase in accrued oil and gas sales, trade receivables and other current assets of $602,000; somewhat offset by a decrease in accounts payable and income taxes payable of $1,544,000.  For the six months ended April 30, 2005 and 2004, net cash used in investing activities was $3,621,000 and $2,439,000, respectively.  Investing activities primarily included oil and gas exploration and development expenditures, including Calliope, totaling $3,454,000 and $1,945,000, respectively.

The average return on CREDO’s investments for the six months ended April 30, 2005 and 2004 was 1.4% and 3.4%, respectively.  At April 30, 2005 approximately 48% of the investments were directly invested in mutual funds and were managed by professional money managers.  Remaining investments are in managed partnerships that use various strategies to minimize their correlation to stock market movements.  Most of the investments are highly liquid and the company believes they represent a responsible approach to cash management.  In the company’s opinion, the greatest investment risk is the potential for negative market impact from unexpected, major adverse news, such as the September 11th terrorist attacks.

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.  As discussed in note 8, at April 30, 2005 the company had remaining commitments of $2,130,000 related to projects in South Texas and along the Central Kansas uplift.  Such costs are expected to be funded over the next 18 to 20 months.  At April 30, 2005, the company had no lines of credit or other bank financing arrangements except for the hedging line of credit discussed in note 4.  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.

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 natural gas prices by forward selling a portion of its estimated production in the NYMEX futures market typically in the form of forward short positions and collars.  This is generally done when (i) the price relationship (the “basis”) between the futures markets and the cash markets where the company sells its gas is stable within historical ranges, and (ii) in the company’s opinion, the current price is adequate to insure reasonable returns at a time when downside price risks appear to be substantial. The company closes its hedges by purchasing offsetting positions in the futures market at then prevailing prices.  Accordingly, the gain or loss on the hedge position will depend on futures prices at the time offsetting positions are purchased.  Hedging gains and losses are included in revenues from oil and gas sales.  The company believes its most significant hedging risk is that expected correlations in price movements as discussed above do not occur, and thus, that gains or losses in one market are not fully offset by opposite moves in the other market.

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As more fully described in note 4 to the consolidated financial statements, the company currently has open hedge positions totaling 420 MMbtu covering the months of July through September 2005 and December 2005 and January 2006.  The hedges represent about 50% to 55% of the company’s estimated gas equivalent production for April through September and about 25% to 30% of the company’s estimated gas equivalent production for December 2005 and January 2006.  All prices are NYMEX basis.  Subsequent to the end of the second fiscal quarter, the company closed its May and June contracts for 220 MMbtu at a loss of $51,000.  Average gas prices in the company’s market areas are expected to be 15% to 17% below NYMEX prices due to basis differentials and transportation costs.

Gas and oil sales volume and price realization comparisons for the indicated periods are set forth below.  Price realizations include the sales price and hedging gains and losses.

(1) Includes $0.33 Mcf hedging loss.

(2) Includes $0.12 Mcf hedging loss.

(3) Includes $0.07 Mcf hedging loss.

(4) Includes $0.34 Mcf hedging loss.

OPERATIONS

The company’s business focuses on two core projects—natural gas drilling and application of its patented Calliope Gas Recovery System.  The company has recently expanded into South Texas through an exploration program using 3-D seismic to define the Vicksburg and Frio prospects in Hidalgo, Jim Hogg and Star counties and into north-central Kansas through an exploration program using 3-D seismic to define Lansing-Kansas City oil prospects in Graham and Sheridan counties.  In combination, its drilling and Calliope projects provide an excellent (and possibly unique) balance for achieving its goal of adding long-lived gas reserves and production at reasonable costs and risks.

The company will continue to actively pursue adding reserves through its two core projects in fiscal 2005 and expects these activities to continue to be the primary source of its 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 availability of oil field services such as drilling rigs, production equipment and related services and access to wells for application of the company’s patented liquid lift system on low pressure gas wells.  The prevailing price of oil and gas has a significant affect on demand and, thus, the related cost of such services and wells.

Drilling Activities.  During the first six months of 2005, the company drilled seven wells in Oklahoma with working interests ranging up to 69%.  Five of these wells were completed as producers and two were dry holes. Drilling expenditures were concentrated on the company’s inventory located along the northern shelf of the Anadarko Basin of Oklahoma.  The wells targeted the Morrow and Chester formations between 7,000 and

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9,000 feet.  A substantial number of additional wells are anticipated for the area, including approximately six wells scheduled for the remainder of this fiscal year.

Drilling is not restricted to the company’s inventory located along the northern shelf of the Anadarko Basin.  The company is generating prospects elsewhere in the Northern Anadarko Basin, in the Oklahoma Panhandle, north-central Oklahoma, north-central Kansas and South Texas. In addition, 16 coal bed methane wells were drilled on acreage in Wyoming where the company owns working interests of approximately 10%, and 99 coal bed methane wells were drilled on Wyoming acreage where the company owns small royalty interests.

A promising well was drilled on the Dunlap portion of the company’s 14,000 gross acre Sand Creek Prospect, located in Harper County, Oklahoma.  The company owns a 24% working interest in this well which commenced production in late May 2005.  Two additional promising wells were drilled on the company’s 1,280 gross acre Gage Prospect located in Ellis County, Oklahoma.  The first well commenced production in late April and the second well commenced production in late May.  The company owns a 50% working interest in the first well and 30% in the second well.

This year, the company significantly expanded its exploration activity with new projects located in South Texas and north-central Kansas.  Both projects are in areas where 3-D seismic is a proven exploration tool and where continuing refinements are providing excellent exploration success.  Equally as important, both exploration teams specialize in their respective geographic areas and have been highly successful finding new reserves using 3-D seismic.  See note 8 for additional information on these two exploration projects.

All of the company’s oil and 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.

Calliope Gas Recovery Technology.  The company owns the exclusive right to a patented technology known as the Calliope Gas Recovery System.  Calliope can achieve substantially lower flowing bottom hole pressure than conventional production methods because it does not rely on reservoir pressure to lift liquids.  In many gas wells, lower bottom hole pressure translates into recovery of substantial additional gas reserves.

Calliope has proven to be reliable and flexible over a wide range of applications on wells the company owns and operates.  It has also proven to be consistently successful.  Accordingly, the company has recently begun implementing strategies designed to widen the envelope of wells on which Calliope should be installed.

The Calliope segment of the company’s business is currently focused on two areas:  increasing the number of Calliope installations through joint ventures with larger companies that own Calliope candidate wells, and expanding the company’s effort to directly purchase Calliope candidate wells from third parties.

In the joint venture area, Calliope has been presented to several major companies and several independents.  With only one exception, the companies have expressed a keen interest in the technology and further discussions are currently ongoing.  Joint well identification and initial commercial negotiations are underway with several companies.

In addition to joint ventures, the company has expanded its effort to acquire Calliope candidate wells into Texas.  This effort is being spearheaded on a full-time basis by a highly qualified petroleum engineer based in Houston.

As part of its Calliope effort in Texas, the company recently acquired a 79% working interest in the 9,800-foot Adolfo Trevino well as part of a South Texas production package.  This well has produced 23.7 Bcf (billion

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cubic feet of gas) from the Wilcox formation and is dead.  The company is completing a wellbore and formation evaluation in order to make a decision whether to install Calliope.

The company also has an agreement to purchase two additional Calliope candidate wells.  These wells will be jointly acquired by the company and a third party “finder”.  The company will own a 59% working interest and will be the operator.

The company’s initial success acquiring wells in Texas has established momentum that it believes will result in more success.

In Beckham County, Oklahoma, the company is testing and re-evaluating an 18,700-foot well for a Calliope installation.  This well has produced 24.1 Bcf and is currently dead.  The company owns an 87.5% working interest.

Results of Operations

Six Months Ended April 30, 2005 Compared to Six Months Ended April 30, 2004

For the six months ended April 30, 2005, total revenues increased 13% to $5,808,000 compared to $5,123,000 last year.  As the oil and gas price/volume table on page 14 shows, total gas price realizations, which reflect hedging transactions, increased 15% to $5.39 per Mcf and oil price realizations increased 38% to $43.66 per barrel.  The net effect of these price changes was to increase oil and gas sales by $860,000.  For the six months ended April 30, 2005, the company’s gas equivalent production decreased 3% resulting in an oil and gas sales decrease of $177,000.  Operating income increased 11% due to an increase in drilling and production supervision income related to operated wells.  Investment income and other decreased 23% primarily due to changes in market conditions.

For the six months ended April 30, 2005, total costs and expenses rose 20% to $2,906,000 compared to $2,413,000 for last year.  Oil and gas production expenses increased 21% due primarily to new wells.  Depreciation, depletion and amortization (“DD&A”) increased 32% primarily due to an increase in the amortizable full cost pool base.  General and administrative expenses increased 7% primarily due to increases in professional fees and salaries and benefit costs related primarily to increased administration resulting from rapid growth, transition from small business SEC reporting status to full reporting status, compliance with Sarbanes-Oxley regulations and preparation for accelerated filing requirements related to the company’s quarterly and annual SEC reports.  Interest expense relates to the exclusive license agreement note payment.  The effective tax rate was 28% for the 2005 and 2004 periods.

Three Months Ended April 30, 2005 Compared to Three Months Ended April 30, 2004

For the three months ended April 30, 2005, total revenues increased 41% to $3,202,000 compared to $2,273,000 for last year.  As the oil and gas price/volume table on page 14 shows, total gas price realizations, which reflect hedging transactions, increased 28% to $5.51 per Mcf and oil price realizations increased 36% to $44.49 per barrel.  The net effect of these price changes was to increase oil and gas sales by $620,000.  For the three months ended April 30, 2005, the company’s gas equivalent production increased 11% resulting in an oil and gas sales increase of $283,000.  Operating income rose 6% due to drilling and production supervision income related to operated wells.  Investment income and other increased 100% primarily due to an increase in other income.

For the three months ended April 30, 2005, total costs and expenses rose 32% to $1,563,000 compared to $1,181,000 for the comparable period in 2004.  Oil and gas production expenses increased 36% due primarily to new wells.  DD&A rose 56% primarily due to an increase in the amortizable full cost pool base and increased production.  General and administrative expenses increased 3% primarily due to increases in professional fees and salaries and benefit costs related primarily to increased administration resulting from

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rapid growth, transition from small business SEC reporting status to full reporting status, compliance with Sarbanes-Oxley regulations and preparation for accelerated filing requirements related to the company’s quarterly and annual SEC reports.  Interest expense relates to the exclusive license agreement note payment.  The effective tax rate was 28% for the 2005 and 2004 periods.

ITEM 3.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The company manages exposure to commodity price fluctuations by periodically hedging a portion of expected production through the use of derivatives, typically collars and forward short positions in the NYMEX futures market.  See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Product Prices and Production” for more information on the company’s hedging activities.  The following table summarizes current open hedge positions:

ITEM 4.  CONTROLS AND PROCEDURES

The effectiveness of our or any system of disclosure controls and procedures is subject to certain limitations, including the exercise of judgment in designing, implementing and evaluating the controls and procedures, the assumptions used in identifying the likelihood of future events, and the inability to eliminate misconduct completely.  As a result, there can be no assurance that our disclosure controls and procedures will detect all errors or fraud.  By their nature, our or any system of disclosure controls and procedures can provide only reasonable assurance regarding management’s control objectives.

Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we evaluated the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, or the “Exchange Act”) as of April 30, 2005.  On the basis of this review, our management, including our Chief Executive Officer and Chief Financial Officer, concluded that our disclosure controls and procedures are designed, and are effective, to give reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC and to ensure that information required to be disclosed in the reports filed or submitted under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, in a manner that allows timely decisions regarding required disclosure.  There were no changes in the company’s internal controls over financial reporting that occurred in the second fiscal quarter of 2005 that materially affected or were reasonably likely to materially affect, its internal control over financial reporting.

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