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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549

FORM 10-K/A

For the transition period from                          to

Commission File Number 0-8877

CREDO PETROLEUM CORPORATION

(Exact name of registrant as specified in its charter)

1801 Broadway, Suite 900, Denver, Colorado 80202-3837

(Address of principal executive offices and zip code)

Registrant’s telephone number, including area code:  (303) 297-2200

Securities registered pursuant to Section 12(b) of the Act:  None

Securities registered pursuant to Section 12(g) of the Act:

Common Stock, $.10 Par Value

(Title of class and shares outstanding)

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act:  o  Yes  x  No

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act:  o  Yes  x  No

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.  x  Yes  o  No

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this form 10-K or any amendment to this Form 10-K/A.  x

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

Large accelerated filer  o  Accelerated filer  x  Non-accelerated filer  o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act.  o  Yes  x  No

The aggregate market value of the voting and non-voting common equity held by non-affiliates as of April 30, 2007, the end of the registrant’s most recently completed second quarter was $110,276,000.

As of January 8, 2008, the registrant had 9,295,000 shares of common stock outstanding.

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EXPLANATORY NOTE

On September 2, 2008, in connection with preparing its quarterly report for third quarter 2008, management of CREDO Petroleum Corporation (the “company”) and the Audit Committee of its Board of Directors determined that the contemporaneous formal documentation it had historically prepared to support its initial hedge designations in connection with the company’s natural gas hedging program does not meet the technical requirements to qualify for cash flow hedge accounting treatment in accordance with SFAS 133.  The primary reason for this determination was that the formal hedge documentation lacks specificity of the hedged items and therefore, the cash flow designations failed to meet hedge documentation requirements for cash flow hedge accounting treatment.  Consequently, the unrealized gain or loss should have been recorded in the consolidated statements of operations as a component of income before income taxes.  Under the cash flow accounting treatment used by the company, the fair values of the hedge contracts was recognized in the consolidated balance sheets with the resulting unrealized gain or loss, net of income taxes, recorded initially in accumulated other comprehensive income and later reclassified through earnings when the hedged production affected earnings.

The company has restated its consolidated financial statements for fiscal years ended October 31, 2005, 2006, 2007 and the first and second quarters of fiscal year ending October 31, 2008.  There is no effect in any period on overall cash flows, EBITDA, total assets, total liabilities or total stockholders’ equity.  The restatement did not have any impact on any of the Company’s financial covenants under its line of credit.  Details of the effect of the restatement are indicated in Note 1 to the Consolidated Financial Statements.

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DOCUMENTS INCORPORATED BY REFERENCE

Pursuant to instruction G (3) to Form 10-K/A, Items 10, 11, 12, 13 and 14 are omitted because the company will file a definitive proxy statement (the “Proxy Statement”) pursuant to Regulation 14A under the Securities Exchange Act of 1934 not later than 120 days after the close of the fiscal year.  The information required by such items will be included in the Proxy Statement to be so filed for the company’s annual meeting of shareholders to be held on or about March 20, 2008 and is hereby incorporated by reference.

NON-GAAP FINANCIAL MEASURES

In this Annual Report on Form 10-K/A, the company uses the term “EBITDA (Earning Before Interest, Taxes, Depreciation and Amortization)” which is considered a non-GAAP financial measure as defined in SEC Regulation S-K Item 10 and should not be considered in isolation or as a substitute for measures of performance prepared in accordance with GAAP.  See Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations for a definition of this measure as used in this Annual Report on Form 10-K/A.

Estimated Future Net Revenues Discounted at 10% is not a GAAP measure of operating performance.  This pre-tax, non-GAAP measure is used by the company in connection with estimating funds expected to be available in the future for drilling and other operating activities.  See Item 2 PROPERTIES, Significant Properties, Estimated Proved Oil and Gas Reserves, and Future Net Revenues for a reconciliation of Estimated Future Net Revenues Discounted at 10% to the Standardized Measure of Discounted Future Net Cash Flows as shown in Note 9 to the company’s Consolidated Financial Statements.

FORWARD-LOOKING STATEMENTS

This Annual Report on Form 10-K/A 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 Annual Report on Form 10-K/A, 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.

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Although the company believes that the expectations reflected in such forward-looking statements are reasonable, it can give no assurance that such expectations will prove to be correct.  Disclosure of important factors that could cause actual results to differ materially from the company’s expectations, or cautionary statements, are included under “Risk Factors” and elsewhere in this Annual Report on Form 10-K/A, including, without limitation, in conjunction with the forward-looking statements.  The following factors, among others that could cause actual results to differ materially from the company’s expectations, include:

·                  unexpected changes in business or economic conditions;

·                  significant changes in natural gas and oil prices;

·                  timing and amount of production;

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

·                  changes in overhead costs;

·                  material events resulting in changes in estimates; and

·                  competitive factors.

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

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PART I

ITEM 1.                  BUSINESS

General

CREDO Petroleum Corporation (“CREDO”) was incorporated in Colorado in 1978.  CREDO and its wholly owned subsidiaries, SECO Energy Corporation and United Oil Corporation (“SECO”, “United” and collectively “the company”), are Denver, Colorado based independent oil and gas companies which engage primarily in oil and gas exploration, development and production activities in the Mid-Continent region of the United States.  The company has operating activities in ten states and has twelve full-time employees.  CREDO is an active operator in Kansas, Wyoming, Colorado, Louisiana and Texas.  United is an active operator doing business primarily in Oklahoma, and SECO primarily owns royalty interests in the Rocky Mountain region.  References to years as used in this report indicate fiscal years ended October 31.

The company effected a 20% stock dividend in fiscal 2003, and a three-for-two stock split in each of fiscal 2005 and 2004.  All share and per share amounts discussed and disclosed in this Annual Report on Form 10-K/A reflect the effect of the dividend and stock splits.

Business Activities

During 2007, the company continued implementation of new drilling projects in central Kansas and South Texas, which projects are designed to sustain the company’s growth rate by expanding and diversifying its business, both technically and geographically.  These projects will also diversify the capital exposure, risk and reserve potential of the company’s drilling activities.  This includes approximately equal commitments to conventional drilling and to the company’s patented Calliope Gas Recovery System (“Calliope”) operations.

The company’s goal is to create steady growth by adding production and long-lived reserves at reasonable costs and risks.  The strategy to achieve this goal involves conventional drilling and increasing the number of Calliope installations.  Third party industry participants are involved in most of the company’s operating activities.

Historically, the company’s primary drilling focus has been in the Anadarko Basin of Oklahoma where the company owns interests in approximately 70,000 gross acres.  The company will continue generating prospects and drilling on this acreage concentrating on medium depth properties generally ranging from 7,000 to 11,000 feet.  Refer to “Management’s Discussion and Analysis of Financial Condition and Results of Operations-Oil and Gas Activities-Drilling Activities-Northern Anadarko Basin” for additional information.

In recent years, the company has significantly expanded both the volume and breadth of its exploration program with new projects in South Texas and north-central Kansas.  Compared to drilling in Oklahoma, the South Texas project involves higher costs and greater risks but significantly higher per well reserve potential.  The South Texas project is 3-D seismic driven with well depths ranging from 10,000 to 17,000 feet.  The north-central Kansas project is geared to oil exploration and has excellent potential to add significant reserves at moderate costs and risks.  This project is also 3-D seismic driven with well depths of approximately 4,000 feet.  Exploration teams for both projects specialize in their respective geographic areas and have been highly successful finding new reserves using 3-D seismic.  The company believes that both projects have the potential to generate significant future production and reserve growth.  Refer to “Management’s Discussion and Analysis of Financial Condition and Results of Operations–Oil and Gas Activities–Drilling Activities-Drilling Program Expansion and Diversification, South Texas, and North-Central Kansas” for additional information.

The company has participated in developing, testing, refining, and patenting Calliope.  Calliope efficiently lifts fluids from wellbores using pressure differentials, thus allowing gas previously trapped by fluid build-up in the wellbore to flow to the surface.  Calliope is distinguished from all other fluid lift technologies because it does not rely on bottom-hole pressure and has only one down-hole moving part.  Calliope is primarily applicable to mature natural gas wells in low pressure, natural gas expansion reservoirs at depths below 8,000 feet.  The company has a 10 year

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unrestricted exclusive license for the Calliope technology that expires in 2010, but that can be extended, at the company’s option, to cover the term of the latest patent.  External sources of capital have not been required for the development, refinement or installation of Calliope.  At October 31, 2007, Calliope has been installed on 25 wells ranging in depth from 6,500 feet to 18,400 feet.  The company has proven Calliope’s economic viability and flexibility over a wide range of applications.

The company currently has Calliope installed on wells located in Oklahoma, Texas and Louisiana which include both sandstones and limestones in Chester, Cotton Valley, Edwards, Hart, Hunton, Morrow, Nodosaria, Red Fork and Springer reservoirs.  Joint venture discussions were accelerated in fiscal year 2007 with two new agreements reached and others under negotiation at October 31, 2007.  Refer to “Management’s Discussion and Analysis of Financial Condition and Results of Operations-Oil and Gas Activities-Calliope Gas Recovery Technology” for additional information.

The company acts as “operator” of approximately 115 wells pursuant to standard industry operating agreements.  The company owns working interests in 282 producing wells and overriding royalty interests in 1,163 wells.

Markets and Customers

Marketing of the company’s oil and gas production is influenced by many factors which are beyond the company’s control, and the exact effect of which cannot be accurately predicted. These factors include changes in supply and demand, market prices, regulation, and actions of major foreign producers.  Oil price fluctuations can be extremely volatile as was demonstrated when, during 2003, the posted price for West Texas intermediate fell below $25.00 per barrel and then rose to over $90.00 per barrel during 2007.

Natural gas price decontrol, the advent of an active spot market for natural gas, changes in supply and demand for natural gas, and weather patterns cause natural gas prices to be subject to significant fluctuations.  The company presently sells virtually all of its natural gas under one to five year contracts with major pipeline companies.  The sales price is typically based on monthly index prices for the applicable pipeline.  Title to the natural gas normally passes to the pipeline at meters located near the wells.  The index prices are reduced by certain pipeline charges.

Most of the company’s natural gas production is located in northwestern Oklahoma.  There has been significant consolidation among natural gas pipelines in this area, thereby reducing the number of available purchasers.  In many instances, there may be only one viable pipeline option, which enables the pipeline to charge higher rates.  A new pipeline is scheduled to be completed in early 2008 that will transport gas from the Rocky Mountain region to northeast Missouri.  The pipeline will connect with other pipelines that transport natural gas to the eastern United States.  Depending on supply and demand factors, gas delivered from the Rocky Mountain region may compete with the company’s Oklahoma gas resulting in the possibility of downward pressure on gas prices received by the company in Oklahoma.

Over the past few years there has been increasing concern that a supply/demand imbalance has developed in domestic natural gas based on increasing demand and lower deliverability.  This, together with rising oil prices, political unrest and uncertainty in certain major producing regions, supply vulnerability to natural disasters, such as hurricanes, and active speculation in the natural gas futures market has caused natural gas prices to become increasingly volatile.  The company expects natural gas prices to remain strong but cannot reasonably predict the extent or timing of natural gas price fluctuations.

As discussed elsewhere in this Annual Report on Form 10-K/A, the company periodically hedges the price of a portion of its estimated natural gas production in the form of forward short positions and collars on both the NYMEX futures market and regional markets.

Oil production is sold to crude oil purchasing companies at competitive spot field prices. Crude oil and condensate production are readily marketable, and the company is generally not dependent on a single purchaser.  Crude oil prices are subject to world-wide supply and demand, and are primarily dependent upon available supplies which can vary significantly depending on production

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and pricing policies of OPEC and other major producing countries and on significant events in major producing regions.  Political unrest and market uncertainty in the Middle East, Africa, South America and former Soviet Union, OPEC’s renewed cooperation in managing the price of its produced oil, and increased demand from countries with developing economies, such as China and India, have resulted in higher world-wide oil prices during the past several years.

Information concerning the company’s major customers is included in Note (9) to the Consolidated Financial Statements.

Competition and Regulation

The oil and gas industry is highly competitive.  As a small independent, the company must compete against companies with substantially larger financial, human and other resources in all aspects of its business.

Oil and gas drilling and production operations are regulated by various federal, state and local agencies.  These agencies issue binding rules and regulations which carry penalties, often substantial, for failure to comply.  The company anticipates its aggregate burden of federal, state and local regulation will continue to increase particularly in the area of rapidly changing environmental laws and regulations.  The company also believes that its present operations substantially comply with applicable regulations.  To date, such regulations have not had a material effect on the company’s operations, or the costs thereof.  There are no known environmental or other regulatory matters related to the company’s operations which are reasonably expected to result in material liability to the company.  The company believes that capital expenditures related to environmental control facilities or other regulatory matters will not be material in 2008.  The company cannot predict what subsequent legislation or regulations may be enacted or what effect they might have on the company’s business.

ITEM 1A.               RISK FACTORS

In evaluating the company, careful consideration should be given to the following risk factors, in addition to the other information included or incorporated by reference in this Annual Report on Form 10-K/A.  Each of these risk factors could adversely affect the company’s business, operating results and financial condition, as well as adversely affect the value of an investment in the company’s common stock.

Volatility of oil and natural gas prices could adversely affect the company’s profitability and financial condition.

The company’s performance in terms of revenues, operating results, profitability, future rate of growth and the carrying value of its oil and natural gas properties is significantly impacted by prevailing market prices for oil and natural gas.  Any substantial or extended decline in the price of oil or natural gas could have a material adverse effect on the company.  It could reduce the company’s operating cash flow as well as the value and, to a lesser degree, the quantity of its oil and natural gas reserves.  See the table of oil and gas sales volumes and prices on page 13 for further information.

Historically, the markets for oil and natural gas have been volatile, and they are likely to continue to be volatile.  Relatively minor changes in supply or demand can have a significant effect on oil and natural gas prices.  Some of the factors affecting oil and natural gas prices which are beyond the company’s control include:

·                  worldwide and domestic supplies of oil and natural gas;

·                  worldwide and domestic demand for oil and natural gas;

·                  the ability of the members of OPEC to agree to and maintain oil price and production controls;

·                  political instability or armed conflict in oil or natural gas producing regions;

·                  worldwide and domestic economic conditions;

·                  the availability of transportation facilities;

·                  weather patterns; and

·                  actions of governmental authorities.

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Competition for opportunities to replace and increase production and reserves is intense and could adversely affect the company.

Properties produce at a declining rate over time.  In order to maintain current production rates the company must add new oil and natural gas reserves to replace those being depleted by production.  Competition within the oil and natural gas industry is intense and many of the company’s competitors have financial and other resources substantially greater than those available to the company.  This could place the company at a disadvantage with respect to accessing opportunities to maintain, or increase, its oil and natural gas reserve base.

In the event that the company does not have adequate cash flow to fund operations, it may be required to use debt or equity financing.

The company makes, and will continue to make, significant expenditures to find, acquire, develop and produce oil and natural gas reserves.  If oil and natural gas prices decrease, or if operating difficulties are encountered that result in cash flow from operations being less than expected, the company may have to reduce capital expenditures unless additional funds are raised through debt or equity financing.  Debt or equity financing or cash generated by operations may not be available to the company in sufficient amounts or on acceptable terms to meet these requirements.

Future cash flows and the availability of financing will be subject to a number of variables, such as:

·                  the company’s success in locating and producing new reserves;

·                  the level of production from existing wells; and

·                  prices of oil and natural gas;

Issuing equity securities to satisfy the company’s financing requirements could cause substantial dilution to existing stockholders.  Debt financing could make the company more vulnerable to competitive pressures and economic downturns.

Reserve quantities and values are subject to many variables and estimates and actual results may vary.

This Annual Report on Form 10-K/A contains estimates of the company’s proved oil and natural gas reserves and the estimated future net revenues from those reserves.  Any significant negative variance in these estimates could have a material adverse effect on the company’s future performance.

Reserve estimates are based on various assumptions, including assumptions required by the SEC relating to oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds.  The process of estimating reserves is complex.  This process requires significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data.

Reserve estimates are dependent on many variables, and therefore, as more information becomes available, it is reasonable to expect that there will be changes to the estimates.  Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves will most likely vary from those estimated.  Any significant variance could materially affect the estimated quantities and present value of reserves disclosed by the company.  In addition, estimates of proved reserves will be adjusted in the future to reflect production history, results of exploration and development, prevailing oil and natural gas prices and other factors, many of which are beyond the company’s control.

As of October 31, 2007, approximately 24% of the company’s estimated proved reserves are classified as proved undeveloped.  Estimation of proved undeveloped reserves and proved developed non-producing reserves is generally based on volumetric calculations rather than the performance data used to estimate reserves for producing properties.  Recovery of proved undeveloped reserves generally requires significant capital expenditures and successful drilling operations.  Revenues

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from proved developed non-producing and proved undeveloped reserves will not be realized until some time in the future.  The reserve estimate includes an estimate of the capital expenditures required to develop these reserves as well as the timing of such expenditures.  Although the company has prepared estimates of its proved undeveloped reserves and the associated development costs in accordance with industry standards, they are based on estimates, and actual results may vary.

You should not interpret the present value of estimated reserves, or PV-10, as the current market value of reserves attributable to the company’s properties.  The 10% discount factor, which we are required to use to calculate PV-10 for reporting purposes, is not necessarily the most appropriate discount factor given actual interest rates and risks to which the company’s business or the oil and natural gas industry in general are subject.  The company has based the PV-10 on prices and costs as of the date of the reserve estimate, in accordance with applicable regulations.  Actual future prices and costs may be materially higher or lower.  In addition to the price volatility factors discussed above, factors that will affect actual future net cash flows, include:

·                  the amount and timing of actual production;

·                  curtailments or increases in consumption by oil and natural gas purchasers; and

·                  changes in governmental regulations or taxation.

As a result, the company’s actual future net cash flows could be materially different from the estimates included in this Annual Report on Form 10-K/A.

The company’s reserve quantities and values are concentrated in a relative few properties and fields.

The company’s reserves, and reserve values, are concentrated in 61 properties which represent 26% of the company’s total properties but a disproportionate 77% of the discounted value (at 10%) of the company’s reserves.  Individual wells on which Calliope is installed comprise 20% of these significant properties and 22% of the discounted reserve value of such properties.  New wells comprise 16% of these significant properties and 15% of the discounted reserve value of such properties.

Estimates of reserve quantities and values for these 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, Calliope 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.

Competition for materials and services is intense and could adversely affect the company.

Major oil companies, independent producers, and institutional and individual investors are actively seeking oil and gas properties throughout the world, along with the equipment, labor and materials required to develop and operate properties.  Shortages of equipment, labor or materials may result in increased costs or the inability to obtain such resources as needed.  Many of the company’s competitors have financial and technological resources which exceed those available to the company.

The company is currently experiencing delays in securing drilling rigs and delivery of production equipment, primarily compressors and coil tubing.  These delays are extending the time it takes the company to conduct its field operations.  As a result, the company could be at risk for price increases related to these types of services and equipment.

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The company’s hedging arrangements involve credit risk and may limit future revenues from price increases.

To manage the company’s exposure to price risks associated with the sale of natural gas, the company periodically enters into hedging transactions for a portion of its estimated natural gas production.  These transactions may limit the company’s potential gains if natural gas prices were to rise substantially over the price established by the hedge.  In addition, such transactions may expose the company to the risk of financial loss in certain circumstances, including instances in which:

·                  the company’s production is less than the amount hedged;

·                  the contractual counterparties fail to perform under the contracts; or

·                  a sudden, unexpected event, materially impacts natural gas prices.

The terms of the company’s hedging agreements may also require that it furnish cash collateral, letters of credit or other forms of performance assurance in the event that mark-to-market calculations result in settlement obligations by the company to the counterparties, which would encumber the company’s liquidity and capital resources.

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

A new pipeline is scheduled to be completed in early 2008 that will transport gas from the Rocky Mountain region to northeast Missouri.  The pipeline will connect with other pipelines that transport natural gas to the eastern United States.  Depending on supply and demand factors, gas delivered from the Rocky Mountain region may compete with the company’s Oklahoma gas resulting in the possibility of downward pressure on gas prices received by the company in Oklahoma.

The marketability of the company’s natural gas production is dependent upon infrastructure, such as gathering systems, pipelines and processing facilities, that the company does not own or control.

The marketability of the company’s natural gas production depends in part upon the availability, proximity and capacity of natural gas gathering systems, pipelines and processing facilities necessary to move the company’s natural gas production to market.  The company does not own this infrastructure and is dependent on other companies to provide it.

Oil and natural gas operations are inherently risky.

The oil and natural gas business involves a variety of risks, including the risks of operating hazards such as fires, explosions, cratering, blow-outs, and encountering formations with abnormal pressures.  The occurrence of any of these risks could result in losses.  The company maintains insurance against some, but not all, of these risks.  Management believes that the level of insurance against these risks is reasonable and is consistent with general industry practices.  The occurrence of a significant event that is not fully insured could have a material adverse effect on the company’s financial position and results of operations.

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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.

The company has recently expanded the volume and breadth of its exploration program with new drilling projects in South Texas.  These projects diversify the company’s exploration geographically, scientifically, and in terms of capital, risk and reserve potential.  Compared to the company’s Oklahoma drilling, the South Texas project involves higher costs and greater risks but offers significantly higher per well production and reserve potential.

The company’s operations are subject to a variety of regulatory constraints.

The production and sale of oil and natural gas are subject to a variety of federal, state and local government regulations.  These include:

·                  the prevention of waste;

·                  the discharge of materials into the environment;

·                  the conservation of oil and natural gas;

·                  pollution;

·                  permits for drilling operations;

·                  drilling bonds;

·                  reports concerning operations;

·                  the spacing of wells; and

·                  the unitization and pooling of properties.

Because current regulations covering the company’s operations are subject to change at any time, and despite its belief that it is in substantial compliance with applicable environmental and other government laws and regulations, the company could incur significant costs for future compliance.

Increases in taxes on energy sources may adversely affect the company’s operations.

Federal, state and local governments which have jurisdiction in areas where the company operates impose taxes on the oil and natural gas products sold.  Historically, there has been on-going consideration by federal, state and local officials concerning a variety of energy tax proposals.  Such matters are beyond the company’s ability to accurately predict or control.

The company is highly dependent on the services of one of its officers.

The company is highly dependent on the services of James T. Huffman, its President and Chief Executive Officer.  The loss of Mr. Huffman could have a material adverse effect on the company.

ITEM 1B.                                            UNRESOLVED STAFF COMMENTS

The company does not have any unresolved comments from the Commission.

ITEM 2.                                                     PROPERTIES

General

The company’s drilling activities are primarily located along the Northern Anadarko Basin of Oklahoma including the Oklahoma Panhandle where the company owns interests in approximately 70,000 gross developed and undeveloped acres.  Specifically, drilling expenditures have been focused on prospects located in Harper, Ellis and Beaver Counties, Oklahoma.  Wells target the Morrow and Chester formations between 7,000 and 11,000 feet.  Since 2002, the company has participated in drilling approximately 89 wells on such prospects with interests ranging up to 83%.  Of those wells, 64 were completed as producers and 25 were dry holes.  Several of the wells are exceptional for the area, and 22 of the wells are included in the company’s Significant Properties (see

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definition below).  The company has recently expanded its drilling activities into South Texas and Kansas.

The company owns the exclusive right to the Calliope Gas Recovery System.  The company has proven that Calliope will add 0.5 to 2.0 Bcf of proved gas reserves to many dead and uneconomic wells.  The company believes there are presently many (more than 1,000) wells that meet its general criteria for Calliope candidate wells and thousands more that will meet its general Calliope criteria in the future.

Calliope operations were historically focused in Oklahoma where the company has a significant field operations infrastructure.  Most Calliope wells are located in the Northern Anadarko Basin of Oklahoma.  To date, Calliope has been installed on 25 wells located in Oklahoma, Texas and Louisiana.  The Calliope wells include both sandstone and carbonate reservoirs including the Chester, Cotton Valley, Edwards, Hart, Hunton, Morrow, Nodosaria, Redfork and Springer formations.  The Calliope wells range in depth from 6,400 to 18,400 feet.  At the time Calliope was installed, 14 of the wells were dead, nine were uneconomic and two were marginal.  There are 14 non-experimental Calliope wells.  As a group, those wells were producing a total of 88 thousand cubic feet of gas per day at the time Calliope was installed.  Since Calliope was installed, those wells have produced 3.4 billion cubic feet of gas and they now have estimated ultimate (8/8ths) Calliope reserves totaling 13.6 billion cubic feet of gas.  Twelve of the Calliope wells are included in the company’s Significant Properties.

For additional information regarding current year activities, including oil and gas production, refer to “Management’s Discussion and Analysis of Financial Condition and Results of Operations”.

Significant Properties, Estimated Proved Oil and Gas Reserves, and Future Net Revenues

The company’s reserves, and reserve values, are concentrated in 61 properties (“Significant Properties”).  Some of the Significant Properties are individual wells and others are multi-well properties.  At year-end, Significant Properties represent 26% of the company’s total properties but a disproportionate 77% of the discounted value (at 10%) of the company’s reserves.  Individual Calliope wells comprise 20% of the Significant Properties and represent 22% of the discounted reserve value of such properties.  New wells comprise 16% of the Significant Properties and represent 15% 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 (including post Calliope installation wells) and properties with proved undeveloped or proved non-producing reserves. In addition, Calliope wells are generally 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.

McCartney Engineering, Inc., an independent petroleum engineering firm, estimated proved reserves for the company’s properties which represented 64% in 2007, 63% in 2006 and 63% in 2005 of the total estimated future value of estimated reserves.  Remaining reserves were estimated by the company in all years.  At October 31, 2007, natural gas represented 83% and crude oil represented 17% of total reserves denominated in equivalent Mcf’s using a six Mcf of gas to one barrel of oil conversion ratio.

The following table sets forth, as of October 31 of the indicated year, information regarding the company’s proved reserves which is based on the assumptions set forth in Note (9) to the Consolidated Financial Statements where additional reserve information is provided.  The average price used to calculate estimated future net revenues was $5.89, $6.32, and $10.26 per Mcf of gas and $86.61, $53.69, and $55.59 per barrel of oil as of October 31, 2007, 2006, and 2005, respectively.  Amounts do not include estimates of future Federal and state income taxes.

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*     The percentage of total reserves classified as proved developed was approximately 76% in 2007, 87% in 2006, and 89% in 2005.

Estimated Future Net Revenues Discounted at 10% is not a GAAP measure of operating performance. Because the company drills new wells on an ongoing basis, and plans to continue to do so in the future, it expects to continue to generate deferred income taxes which are not reasonably expected to be paid in the near term.  This pre-tax, non-GAAP measure is used by the company in connection with estimating funds expected to be available in the future for drilling and other operating activities.  The company believes that this performance measure may also be useful to investors for the same purpose.  The difference between this measure and the Standardized Measure of Discounted Future Net Cash Flows From Reserves is that this measure excludes future income tax expense and the effect of the 10% discount factor on future income tax expense.  The following table provides a reconciliation of Estimated Future Net Revenues Discounted at 10% to the Standardized Measure of Discounted Future Net Cash Flows as shown in Note 9 to the company’s Consolidated Financial Statements.

*       The average price used to calculate estimated future net revenues was $5.89, $6.32, and $10.26 per Mcf of gas and $86.61, $53.69, and $55.59 per barrel of oil as of October 31, 2007, 2006, and 2005, respectively.

Production, Average Sales Prices and Average Production Costs

The company’s net production quantities and average price realizations per unit for the indicated years are set forth below.  Price realizations are net of any realized hedging gains or losses.

(1)          Includes $0.99 Mcf realized hedging gain.

(2)          Includes $0.12 Mcf realized hedging loss.

(3)          Includes $0.39 Mcf realized hedging loss.

Average production costs, including production taxes, per equivalent Mcf of production (using a six Mcf of gas to one barrel of oil conversion ratio) were $1.51, $1.40, and $1.35 per Mcfe in 2007, 2006, and 2005, respectively.

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Productive Wells and Developed Acreage

Developed acreage at October 31, 2007 totaled 27,000 net and 80,000 gross acres.  At October 31, 2007, the company owned working interests in 82.13 net (282 gross) wells consisting of 65.52 net (236 gross) natural gas wells and 16.61 net (46 gross) oil wells.  In addition, the company owned royalty and production payment interests in approximately 1,163 wells, primarily coal bed methane, located in Wyoming.  In 2007, the company sold 0.28 net (one gross) well and abandoned 0.37 net (one gross) well.  In the same period, the company drilled and acquired interests in 5.54 net (17 gross) productive wells in which it did not previously own an interest.

Undeveloped Acreage

The following table sets forth the number of undeveloped acres leased by the company (primarily located in the Mid-Continent and Rocky Mountain Regions) which will expire during the next five years (and thereafter) unless production is established in the interim.  Undeveloped acres “held-by-production” represent the undeveloped portions of producing leases which will not expire until commercial production ceases.

In general, “royalty” interests are non-operated interests which are not burdened by costs of exploration or lease operations, while “working interests” have operating rights and participate in such costs.

Drilling

The following tables set forth the number of gross and net oil and gas wells in which the company has participated and the results thereof for the periods indicated.

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Insurance

The company believes that its existing insurance coverage is adequate to protect it from the risks associated with the ongoing operation of its business.  This coverage includes commercial property, liability and auto, workers compensation, inland marine and excess liability.

Facilities and Employees

The company’s corporate headquarters are located at 1801 Broadway, Suite 900, Denver, Colorado, in approximately 4,000 square feet occupied under a lease.  The company believes that this space is adequate for its current needs.  The company’s current lease expires in April 2011.

As of October 31, 2007, the company had 12 employees.  None of the company’s employees is subject to a collective bargaining agreement, and the company considers relations with its employees to be good.

Company Website

Information related to the following items, among other information, can be found on the company’s website at www.credopetroleum.com:  (a) company filings with the Securities and Exchange Commission, (b) company press releases, (c) officers, directors and ten percent shareholders filings on Forms 3, 4 and 5, and (d) the company’s Code of Ethics and Audit Committee Charter.  The company’s website is not a part of, or incorporated by reference in, this Annual Report on Form 10-K/A.

ITEM 3.                                                     LEGAL PROCEEDINGS

From time to time, the company may be involved in litigation relating to claims arising out of the company’s operations in the normal course of business.  As of the date of this Annual Report on Form 10-K/A, the company is not a party to any pending legal proceedings.  No such proceedings have been threatened and none are contemplated by the company.

ITEM 4.                                                     SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

No matters were submitted to a vote of security holders during the fourth quarter of 2007.

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PART II

ITEM 5.              MARKET FOR THE REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES

The company’s common stock is traded on the NASDAQ Global Market^SM under the symbol “CRED”.  Market quotations shown below were reported by the Financial Industry Regulatory Authority (FINRA) and represent prices between dealers excluding retail mark-up or commissions and may not necessarily represent actual transactions.

At January 4, 2008, the company had 2,621 shareholders of record.  The company has never paid a cash dividend and does not expect to pay any cash dividends in the foreseeable future.  Earnings are reinvested in business activities.

Issuer Purchases of Equity Securities.

During the fourth quarter of the fiscal year, the company repurchased 50,000 shares of its common stock on the open market at a weighted average price of $10.13.  The purchase was made pursuant to a stock repurchase plan announced on October 4, 2007.  The plan authorized repurchases up to $1,000,000, but could be expanded, suspended or discontinued at any time. No additional shares have been repurchased subsequent to October 31, 2007.

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Performance Graph

The following performance graph compares the cumulative total stockholder return on the company’s common stock for the six-year period ended October 31, 2007 with the cumulative total return of the AMEX Natural Gas Index, and the Standard & Poor’s 500 Stock Index.  The identities of the companies included in the index will be provided upon request.

Comparison of 6 Year Cumulative Total Return

October 2007

(Assumes Initial Investment of $100)

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ITEM 6.                  SELECTED FINANCIAL DATA

The following table sets forth certain financial information with respect to the company and is qualified in its entirety by reference to the historical financial statements and notes thereto of the company included in Item 8, “Financial Statements and Supplementary Data.”  The statement of operations and balance sheet data included in this table for each of the five years in the period ended October 31, 2007 were derived from the audited financial statements and the accompanying notes to those financial statements.

(1) The effect of the three for two stock splits in 2005 and 2004, and 20% stock dividend in 2003, are reflected in all historical share and per share data.

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Liquidity and Capital Resources

At October 31, 2007, working capital increased 24% to $12,511,000, compared to $10,073,000 at October 31, 2006.  For the year ended October 31, 2007, net cash provided by operating activities was $11,674,000 compared to $12,973,000 for the same period in 2006.  The difference is primarily due to a decrease in non-cash items (DD&A, deferred income taxes and other items) of $226,000, an increase in short term investments of $759,000 in 2007 compared to $129,000 in 2006 and net changes in other operating assets.  For the year ended October 31, 2007 and 2006, net cash used in investing activities was $8,750,000 and $11,096,000, respectively.  Investing activities primarily included oil and gas exploration and development expenditures, including Calliope, totaling $9,144,000 and $11,746,000, respectively.  Financing activities primarily included the purchase of treasury stock of $506,000 and proceeds from exercise of stock options of $368,000 and $835,000 in 2007 and 2006, respectively.

The company’s adjusted earnings before unrealized gains/losses on derivative contracts, interest, taxes, depreciation, depletion and amortization, (“EBITDA”) increased 4% to $12,221,000 for the year ended October 31, 2007 from $11,793,000 for the prior year.  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 EBITDA is not a GAAP measure, it may not necessarily be comparable to similarly titled measures employed by other companies.  A reconciliation between EBITDA and net income is provided in the table below:

The average return on the company’s investments for the year ended October 31, 2007 and 2006 was 11.0% and 8.4%, respectively.  At October 31, 2007, approximately 46% 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.

Existing working capital and anticipated cash flow are expected to be sufficient to fund operations and capital requirements for at least the next 12 months.  At October 31, 2007, the company had no lines of credit or other bank financing arrangements except for the hedging line of credit discussed in Note 1 to the Consolidated Financial Statements.  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.

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As of October 31, 2007, the company had the following known contractual obligations:

Off-Balance Sheet Financing

The company has no off-balance sheet financing arrangements at October 31, 2007.

Product Prices and Production

Refer to Item 1., “Markets and Customers”, for discussion of oil and gas prices and marketing.

Oil and natural gas sales volume and price realization comparisons for the indicated years ended October 31 are set forth below.  Price realizations include realized hedging gains and losses.

(1)   Includes $0.99 Mcf hedging gain.

(2)   Includes $0.l2 Mcf hedging loss.

(3)   Includes $0.39 Mcf hedging loss.

Significant Properties (see definition on page 12) contributed 62% of 2007 production on a gas-equivalent basis.  Increases in oil volumes resulted primarily from successful drilling in Kansas.

Although product prices are key to the company’s ability to operate profitably and to budget capital expenditures, they are beyond the company’s control and are difficult to predict.  Since 1991, the company has periodically hedged the price of a portion of its estimated natural gas production when the potential for significant downward price movement is anticipated.  Hedging transactions typically take the form of forward short positions and collars on the NYMEX futures market, and are closed by purchasing offsetting positions.

On September 2, 2008, in connection with preparing its quarterly report for third quarter 2008, management of CREDO Petroleum Corporation (the “company”) and the Audit Committee of its Board of Directors determined that the contemporaneous formal documentation it had historically prepared to support its initial hedge designations in connection with the company’s natural gas hedging program does not meet the technical requirements to qualify for cash flow hedge accounting treatment in accordance with SFAS 133.  The primary reason for this determination was that the formal hedge documentation lacks specificity of the hedged items and therefore, the cash flow designations failed to meet hedge documentation requirements for cash flow hedge accounting treatment.  Consequently, the unrealized gain or loss should have been recorded in the consolidated statements of operations as a component of income before income taxes.  Under the cash flow accounting treatment used by the company, the fair values of the hedge contracts was recognized in the consolidated balance sheets with the resulting unrealized gain or loss, net of income taxes, recorded initially in accumulated other comprehensive income and later reclassified through earnings when the hedged production affected earnings.

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

The company had realized hedging gains of $1,909,000 in fiscal 2007 and losses of $266,000 in fiscal 2006 and $719,000 in fiscal 2005.  In fiscal 2007 the company had unrealized hedging losses of $454,000 and gains of $1,327,000 in fiscal 2006 and $182,000 in fiscal 2005.

Open hedge contracts at October 31, 2007 are indexed to the NYMEX and are represented by short positions.  Actual price realizations in the company’s principal areas of operations (primarily Oklahoma) are expected to be 10% to 12% below NYMEX prices primarily due to basis differentials.

As of December 31, 2007, hedges covering the contract months of November 2007 through January of 2008 had been closed at expiration resulting in a gain of $847,000.  Such hedges covered 430 MMBtus at NYMEX basis prices ranging from $8.70 to $9.92.  Open hedge positions as of December 31, 2007, are set forth below.

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 $5,900,000 with interest calculated at the prime rate.  The facility is unsecured and has covenants that require the company to maintain $3,000,000 in cash or short term investments, none of which are required to be maintained at the company’s bank, and prohibits funded debt in excess of $500,000.  The line expires November 15, 2010.

Oil and Gas Activities

Capital Spending.  Capital spending, net of sales, in 2007 totaled $8,808,000, consisting primarily of additions to oil and gas properties, excluding the change in the company’s asset retirement related asset.

Operations

Summary – During 2007, the company’s operations were focused on its two core projects – drilling in the Mid-Continent area of the U.S. and application of its Calliope Gas Recovery System.  During the past several years, the company has significantly expanded the volume and breadth of its drilling activities by diversifying geographically, scientifically, and in terms of capital, risk and reserve potential.  The company has also implemented a program to increase the volume of its Calliope applications by joint venturing with other companies.

Production casing has been set on three wells that were drilling over fiscal year end, and the wells are in the process of being tested and completed.  Subsequent to year end, 13 wells commenced drilling, of which three are currently drilling, two are producing, five are being tested or completed for production, and three are dry holes.  Four of the wells were drilled in northwest Oklahoma, all of which have been, or are in the process of being, completed for production.  One well is currently drilling in Oklahoma.  Five of the wells were drilled in central Kansas of which one is producing, one is awaiting completion for production, and three were dry holes.  One well is currently drilling in central Kansas.  One well was drilled in South Texas and is awaiting pipeline

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connection, and one well is drilling in North Texas.  In addition to follow-up drilling that will be generated by the new wells, 14 additional wells are currently scheduled on prospects in Oklahoma, central Kansas and South Texas.  The scheduled wells include a high potential well in South Texas to test the Wilcox formation at 17,500 feet.  A high potential well in North Texas is currently drilling toward 11,200 feet.

Also subsequent to fiscal year end, the company has continued to discuss possible joint ventures with other companies for its Calliope Gas Recovery System.  One joint venture agreement has been executed and another is in the drafting stage.  Several are in the discussion stage.

These activities are discussed in greater detail below.

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 2008, 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 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 gas recovery system on low pressure gas wells.  The prevailing price of oil and natural gas has a significant effect on demand and, thus, the related cost of such services and wells.

The company is currently experiencing delays in securing delivery of production equipment, primarily compressors and coil tubing.  These delays are extending the time it takes the company to conduct its field operations in general, and in particular related to installations of its Calliope system.  As a result, the company could be at risk for price increases related to these types of services and equipment.

Drilling Activities

Northern Anadarko Basin – The company owns a significant inventory of acreage (approximately 70,000 gross acres) located along the northern portion of the Anadarko Basin where it conducts an active drilling program.  Wells generally target the Morrow, Oswego and Chester formations between 7,000 and 11,000 feet.  The company expects to drill a substantial number of additional wells on this acreage.

In Hemphill County, Texas, the 11,200-foot wildcat well drilled in fiscal 2007 to test the 3,780 gross acre Humphreys Prospect encountered excellent quality Morrow sands, and tested at the rate of 3.0 MMcf per day.  However, production declined rapidly but stabilized at 150 Mcf per day.  The stabilized production rate suggests that the first well is indirectly connected to a larger Morrow reservoir.  The company subsequently purchased and reprocessed 3-D seismic over the prospect, and believes that it has identified the primary Morrow channel.  A second well has commenced to test the seismic interpretation.  The company owns a 25% working interest.  This is an expensive but high potential well that, if successful, could have a material positive effect on the company’s production in 2008.

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In Canadian County, Oklahoma, the 640 gross acre Loosen Prospect continues to yield excellent drilling results from the Redfork and Skinner formations.  The 11,500-foot Marcia #1-14 is currently drilling and is the fifth well drilled on the prospect.  The Marcia well is a north extension to the recently completed Chappell well which encountered pay zones in five separate formations.  The well is currently completed in three of the five zones and is producing 1.9 MMcf and 30 barrels of oil per day.  The remaining zones will be opened for production at a later date.  The Chappell well was a north extension to the Hazel well, drilled in December 2006, which is still producing 2.0 MMcf (million cubic feet of gas) and about 20 barrels of oil per day.  The company owns working interests in the new wells as follows:  Hazel — 6.25%; Chappell — 16.3%, Marcia — 14.5%.

In Harper County, Oklahoma, the 3,840 gross acre Buffalo Creek Prospect continues to be a very active drilling area for the company based on a recently completed 3-D seismic program. Nine wells have now been completed on the prospect with production from the Chester, Morrow and Oswego formations.  The most recent well encountered 14 feet of excellent Morrow sand porosity that electric logs indicate is productive.  The well is currently being completed. The company owns working interests in the prospect ranging from 31% to 37%.  Three to five new drilling locations are currently planned for 2008, and more are expected based on the results of future wells.

In Ellis County, Oklahoma, the first well has been drilled on the company’s 2,560 gross acre North Boxer Prospect.  The 8,500-foot well is currently classified as a “tight hole”, meaning information is not being released for proprietary business reasons.  A second wildcat well has been drilled about one mile to the south and is currently being completed. The company owns working interests in the prospect ranging from 30% to 40%.

In Kingfisher County, Oklahoma, the first two wells have been drilled on the 1,280 gross acre Okarche Prospect to test the Hunton, Meramec, Chester and Redfork formations.  Both wells are currently awaiting completion.  The company owns working interests ranging from 9.5% to 11%.

In Carter County, Oklahoma, the Southeast Hewitt Waterflood Unit has produced over 600,000 incremental barrels of oil, significantly outperforming initial expectations.  As a result of development drilling, production from the unit has recently increased about 40% to 270 barrels of oil per day.  Further development is under consideration.  The company owns a 17% working interest.

In Love County, Oklahoma, a new waterflood project is currently in the initial stages of operations.  The company owns a 10% to 12% working interest in various phases of the project.

South Texas – The company has recently expanded the volume and breadth of its exploration program with new drilling projects in South Texas.  These projects diversify the company’s exploration geographically, scientifically, and in terms of capital, risk and reserve potential.  Compared to the company’s Oklahoma drilling, the South Texas project involves higher costs and greater risks but offers significantly higher per well production and reserve potential.

The most significant of the two South Texas projects is 3-D seismic driven and focuses on the Vicksburg, Frio and Queen City sands in Hidalgo County and the Wilcox sands in Jim Hogg County at depths ranging from 7,200 feet to 17,500 feet.  To date, the company has invested approximately $1,872,000 (net) in the project, exclusive of drilling.  Prior to sale or farmout of the prospects, the company owns a 75% interest before recovery of its investment, exclusive of drilling, and 37.5% thereafter.  The company has the option to participate in drilling any of the prospects for its full interest or to reduce its costs and risks by selling or farming-out its interest to third parties in return for cash consideration and a “carried interest” on the initial wildcat well(s).

The primary objective of this project has been identification of, leasing and sale of three “deep Wilcox” prospects located in Jim Hogg County.  The prospects cover 3,600 gross acres, range in depth from 16,500 to 17,500 feet, and are located in an area where several nearby fields have produced hundreds of billions of cubic feet of gas from the Wilcox formation.  The company’s 3-D seismic interpretation indicates that the prospects are large enough in size to have very substantial production and reserve potential in relation to the company’s existing production and reserves.  However, the prospects are high risk, rank wildcat prospects and per well drilling costs far exceed those normally incurred by the company.  Therefore, the company has elected to sell a

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portion of its interest for cash consideration and a “carried interest” on two initial wildcat wells.  Third parties have committed to purchase the three prospects and to drill a wildcat well on one prospect.  The second wildcat well is optional based on the outcome of the first well.  Paperwork is in the process of being completed.  The operator has indicated the intent to commence drilling early in 2008.  In addition to recovering a significant portion its cash investment in the project and being “carried” for an interest in the initial test well(s), the company has preserved its option to participate in other wells drilled on the prospects with interests ranging from 18% before recovery of its investment to 9% after recovery.  If drilling is successful, the company expects that its retained interest in the prospects will have a very significant impact on its production and reserve growth.

Elsewhere in South Texas, the first well has been drilled on the 2,500 gross acre Briggs Ranch Prospect located in Victoria County.  The prospect is fault separated from the Heyser Field which has produced 738,000 barrels of oil and 17 Bcf from the Frio sands.  The 8,600-foot Briggs Ranch #1 encountered 11 feet of Frio sands that electric logs indicate are productive.  The well has been completed and is awaiting pipeline connection.  The company owns a 9% working interest.

North-Central Kansas – The company further expanded the volume and breadth of its exploration program with a new drilling project in central Kansas.  The Kansas project provides diversification to the company’s drilling program geographically and scientifically through the use of 3-D seismic to identify shallow oil prospects.  The acreage is located in prolific oil producing areas where 3-D seismic has proven effective in identifying satellite structures near mature producing fields.  Higher oil prices have justified using 3-D seismic technology to locate undrilled structures that are very difficult to find with old technology.  Drilling targets the Lansing-Kansas City and Arbuckle formations at about 4,000 feet and, compared to the company’s Northern Anadarko Basin and South Texas projects, is relatively low cost, low risk, and exclusively targets oil reserves in an effort to bring better product balance to the company’s reserve base.  The company has assembled four separate drilling projects which encompass about 41,000 gross acres and is continuing to seek opportunities to increase its exposure to the play.  The company owns working interests in the existing prospects ranging from 12.5% to 75%.

The company’s recent drilling results have improved dramatically as it continues to find the keys to successful seismic and geologic interpretation.  Four of the last seven wells have been completed as producers, and three of those appear to be outstanding wells.

In Graham County, a wildcat well has been completed on the 3,280 gross acre White Anticline prospect.  The well encountered excellent porosity in the Lansing-Kansas City limestone and is producing 100 barrels of oil per day.  A second well on the prospect resulted in a dry hole.  In the same area, the first well on the 4,900 gross acre Mount Vernon prospect encountered Lansing-Kansas City limestone that appears from tests and electric logs to be productive.  The well is currently being completed and has swab tested at rates in excess of 150 barrels of oil per day.  The company owns a 12.5% working interest in both prospects.

In Sheridan County, a wildcat well has been successfully completed on the company’s 20,000 gross acre Lucerne Prospect.  The new well is located in the same general area as the previously reported Ficken #1-23 which has been an excellent well, having produced about 35,000 barrels of oil in 12 months.  The new well encountered productive Lansing-Kansas City limestone and is producing about 40 barrels of oil per day.  Also in Sheridan County, a new well has been drilled on the St. Peter North prospect and is awaiting completion after an excellent recovery on drillstem test.  The company owns a 30% working interest in both wells.

Calliope Gas Recovery Technology

The company owns the exclusive right to a patented technology known as the Calliope Gas Recovery System.  There are currently three U.S. patents and two Canadian patents related to the technology.  One additional patent that mirrors the U.S. patents has been applied for in Canada.  Calliope systems are installed on wells located in Oklahoma, Texas and Louisiana.

Calliope can achieve substantially lower flowing bottom-hole pressure than other production methods because it does not rely on reservoir pressure to lift liquids.  In many reservoirs, lower bottom-hole pressure can translate into recovery of substantial additional natural gas reserves.

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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 is implementing strategies designed to expand the population of wells on which it can install Calliope.

Calliope’s Track Record – At fiscal year end, Calliope had been installed on 25 wells located in Oklahoma, Texas and Louisiana.  The Calliope wells produce from both sandstone and carbonate reservoirs including the Chester, Cotton Valley, Edwards, Hart, Hunton, Morrow, Nodosaria, Redfork and Springer formations.  The Calliope wells range in depth from 6,400 to 18,400 feet.  These wells represent rigorous applications for Calliope because at the time Calliope was installed, 14 of the wells were dead (an average of two to three years), nine were uneconomic and two were marginal.  In addition, prior to the time Calliope was installed, many of the reservoirs were damaged by the “parting shots” of previous operators. Twenty-three of the wells were acquired from other operators after the operators had given-up on these wells.  The previous operators were mostly medium to large independent oil and gas companies.

Initial Calliope production rates range up to 650 Mcfd and average per well Calliope reserves for non-experimental wells are estimated to be 1.0 Bcf.  One of the company’s early Calliope installations, the J.C. Carroll well, has now produced over a billion cubic feet of gas using Calliope.

The 25 Calliope applications are grouped into two categories – experimental wells and non-experimental wells, also referred to as “go-forward” applications. Eleven of the 25 wells are experimental applications and 14 are go-forward applications.  Experimental wells generally represent the first experimental application of a Calliope configuration in a wellbore.  For example, the first installation of Calliope inside a particular tubing size is classified as an experimental application.

Calliope has achieved compelling results on these less than ideal wells as is shown in the table below.  For example, the entire group of 14 non-experimental wells were producing a total of only 88 Mcfd when Calliope was installed.  Without Calliope, the wells represented a substantial plugging liability.  However, with Calliope, those same 14 wells have now produced an incremental 3.4 Bcfe to date, and they are still producing about 2.0 MMcfed.  With Calliope, the 14 wells were projected to have estimated ultimate incremental Calliope reserves totaling 13.6 Bcfe.