UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549

FORM 10-K/A

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

For The Fiscal Year Ended October 31, 2008

or

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

For the transition period from                          to                         

Commission File Number 0-8877

CREDO PETROLEUM CORPORATION

(Exact name of registrant as specified in its charter)

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:

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/A 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, 2008, the end of the registrant’s most recently completed second quarter was $78,774,000.

As of January 7, 2009, the registrant had 10,437,000 shares of common stock outstanding.

EXPLANATORY NOTE

Our February 17, 2009 CREDO Petroleum Corporation (the “Company”) received a letter from the Securities and Exchange Commission (the “SEC”) regarding the Company’s Annual Report on Form 10-K filed by the Company with the SEC on January 14, 2009 (the “Original Filing”) for the fiscal year ended October 31, 2008.  The Company has responded to the SEC’s comments to our Original Filing in this Amendment #1.

In connection with the review of the Original Filing, the SEC asked the Company to:

The amendment has no impact on the Company’s consolidated balance sheet, consolidated statements of operations, consolidated statements of changes in shareholders’ equity and consolidated statements of cash flows for the year ended October 31, 2008.  Accordingly, we have not refiled the financial statements for the fiscal year ended October 31, 2008.

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 end 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 19, 2009 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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TABLE OF CONTENTS

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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 thirteen 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.

Business Activities

During 2008, the company continued implementation of new exploration projects in central Kansas, South Texas, and North Dakota, which projects are designed to sustain the company’s growth 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.

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 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.  In South Texas, the initial test well on the Gemini Prospect resulted in a dry hole.  The 17,000-foot well confirmed the seismic interpretation and found porous sand.  However, the sand was water wet and the well was plugged and abandoned.  CREDO received approximately $1,300,000 of cash for the multiple prospect package and retained an 11.25% “carried interest” in the test well.

The prospect package consists of two additional Deep Wilcox prospects located to the north of Gemini Prospect.  These two prospects are structurally different and unique compared to the Gemini Prospect.  Those prospects are being further evaluated, and if drilled, CREDO will have the same 11.25% carried interest in the next well as it did in the Gemini Prospect test well.

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’s Kansas acreage is located in prolific oil producing areas where 3-D seismic has proven effective in identifying undrilled structures.  Drilling targets the Lansing-Kansas City and Arbuckle formations at about 4,000 feet, making the cost of drilling very inexpensive in relation to potential reserve value.  At October 31, 2008, 29 wells have been drilled on company acreage, of which 49% have been successful.

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During the fourth quarter of fiscal 2008, the company acquired approximately 4,100 net acres on the Fort Berthold Reservation in North Dakota.  The acreage is in the Bakken Shale Resource Play.  The company believes that these 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.

On November 6, 2008 the company purchased all of the patents underlying the Calliope gas recovery technology, all of the related third party interests in future installations of the technology and patents covering a new fluid lift technology for shallow wells known as Tractor Seal for $4,500,000.

The company owns the patents covering the Calliope Gas Recovery System (“Calliope”) and has been instrumental in developing, testing, refining, and patenting the Calliope Gas Recovery System.  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.  External sources of capital have not been required for the development, refinement or installation of Calliope.    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 2008 with two new agreements reached and others under negotiation at October 31, 2008. 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 130 wells pursuant to standard industry operating agreements.  The company owns working interests in 314 producing wells and overriding royalty interests in 1,167 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 2008, the posted price for West Texas intermediate in July reached more than $140.00 per barrel, then fell below $35.00 in December.

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.  The first leg of the Rocky Mountain Express pipeline was completed in early 2008 that transports gas from the Rocky Mountain region to northeast Missouri.  The eastern extension of the pipeline connects with other pipelines that transport natural gas to the eastern United States.  Until the eastern extension, extending to Ohio, is completed natural gas is being delivered into the mid-continent region which is creating excess supply and downward pricing pressure on mid-continent gas sales.

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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 some major producing regions, supply vulnerability to natural disasters, such as hurricanes, and active speculation in the natural gas futures market caused natural gas prices to become increasingly volatile.  The economic downturn that commenced in the 2nd half of 2008 appears to have resulted in demand reductions at a time when supply has been increasing.  The supply/demand imbalance pendulum has recently swung in the opposite direction, as evidenced by volatile price reductions experienced in the 2nd half of 2008.  The Panhandle Eastern Pipeline natural gas index, the basis for most of the company’s gas sales, has fallen from $11.07 per Mcf in July 2008 to $2.81 for November, 2008.  The company expects natural gas prices to return to more historical levels 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 the NYMEX futures market.

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 and pricing policies of OPEC and other major producing countries and on significant events in major producing regions.  Until recently, 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.  Recently the economic crisis that commenced in the 2nd half of 2008 has resulted in rapid global reductions in demand for oil.  The effects of oversupply are evidenced by volatile price reductions experienced in the 2nd half of 2008.  World wide prices for oil have declined approximately 70% since reaching peak levels in July 2008.

Information concerning the company’s major customers is included in Note (10) 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 2009.  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.

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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.

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.  In the event of sustained low oil and gas prices, 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 also make the company more vulnerable to competitive pressures and economic downturns.

8

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, 2008, approximately 33% 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 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.

Full cost pool ceiling subject to reserve values.

The company uses the full cost method of accounting for costs related to its oil and natural gas properties.  Capitalized costs included in the full cost pool are depleted on an aggregate basis using the units-of-production method.  A change in proved reserves without a corresponding change in capitalized costs will cause the depletion rate to increase or decrease.

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”.

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The capitalized costs in the full cost pool are subject to a quarterly ceiling test that limits such pooled costs to the aggregate of the present value of future net revenues attributable to proved oil and natural gas reserves discounted at 10 percent plus the lower of cost or market value of unproved properties less any associated tax effects.  If such capitalized costs exceed the ceiling, the company will record a write-down to the extent of such excess as a non-cash charge to earnings, unless the company considers price increases subsequent to the balance sheet date which may reduce or eliminate a write-down.  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 natural gas prices may subsequently increase the ceiling.

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 68 properties which represent 24% of the company’s total properties but a disproportionate 80% of the discounted value (at 10%) of the company’s reserves.  Individual wells on which Calliope is installed comprise 16% of these significant properties and 14% of the discounted reserve value of such properties.  Reserves added during 2008 comprise 25% of these significant properties and 26% 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.

During 2008, the company experienced delays in securing drilling rigs and delivery of production equipment, primarily compressors and coil tubing.  These delays extended the time it took 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.

Natural gas derivatives 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 derivative 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 derivatives.  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 derivative 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’s derivatives are generally based on NYMEX prices but the company’s hedged production is primarily sold on a regional pipeline index price.  The regional price is normally 15% to

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17% below NYMEX prices.  However, regional weather conditions and other economic factors, such as the current delay in completion of the eastern extension of the Rocky Mountain Express gas pipeline, resulting in excess natural gas supplies to the mid-continent region, can periodically result in substantially higher basis differentials.  At October 31, 2008, the Oklahoma basis differential was 56% of the NYMEX price.

The company has elected not to designate its commodity derivatives as cash flow hedges for accounting purposes.  Accordingly, such contracts are recorded at fair value on its Balance Sheet and changes in fair value are recorded in the Consolidated Statements of Operations as they occur.

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.  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.

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.  Compared to the company’s Oklahoma drilling, the South Texas project involves higher costs and greater risks.

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.

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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 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 Oklahoma 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.

The company’s Kansas drilling activities provide 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.  Generally 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 about 139,000 gross (65,000 net) 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 85%.

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.

On November 6, 2008 the company purchased all of the patents underlying the Calliope gas recovery technology, all of the related third party interests in future installations of the technology and patents covering a new fluid lift technology for shall wells known as Tractor Seal for $4,500,000.

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.  The company’s current compilation of Calliope’s track record shows Calliope installations 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 4.4 billion cubic feet of gas and they now have estimated ultimate (8/8ths) Calliope reserves totaling 11.2 billion cubic feet of gas.  Eleven of the Calliope wells are included in the company’s Significant Properties.

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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 68 properties (“Significant Properties”).  Some of the Significant Properties are individual wells and others are multi-well properties.  At year-end, Significant Properties represent 24% of the company’s total properties but a disproportionate 80% of the discounted value (at 10%) of the company’s reserves.  Individual Calliope wells comprise 16% of the Significant Properties and represent 14% of the discounted reserve value of such properties.  Reserves added in 2008 comprise 25% of the Significant Properties and represent 26% 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.

At October 31, 2008, LaRoche Petroleum Consultants, Ltd., an independent petroleum engineering firm, estimated proved reserves for all of the company’s properties.  In 2007 and 2006 McCartney Engineering, Inc., an independent petroleum engineering firm, estimated proved reserves for the company’s properties which represented 64% in 2007 and 63% in 2006 of the total estimated future value of estimated reserves.  In 2007 and 2006, remaining reserves were estimated by the company.  At October 31, 2008, natural gas represented 78% and crude oil represented 22% 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 (10) to the Consolidated Financial Statements where additional reserve information is provided.  The average price used to calculate estimated future net revenues was $3.50, $5.89, and $6.32 per Mcf of gas and $62.25, $86.61, and $53.69 per barrel of oil as of October 31, 2008, 2007, and 2006, respectively.  Amounts do not include estimates of future Federal and state income taxes.

*     The percentage of total reserves classified as proved developed was approximately 67% in 2008, 76% in 2007, and 87% in 2006.

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.

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* The average price used to calculate estimated future net revenues was $3.50, $5.89 and $6.32 per Mcf of gas and $62.25, $86.61, and $53.69 per barrel of oil as of October 31, 2008, 2007, and 2006, 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 include realized derivative gains or losses.

(1)   Includes $0.25 Mcf realized natural gas hedging derivative loss.

(2)   Includes $0.99 Mcf realized natural gas hedging derivative gain.

(3)   Includes $0.12 Mcf realized natural gas hedging derivative 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 $2.05, $1.51 and $1.40 per Mcfe in 2008, 2007, and 2006, respectively.

Productive Wells and Developed Acreage

Developed acreage at October 31, 2008 totaled 27,000 net and 82,000 gross acres.  At October 31, 2008, the company owned working interests in 88.26 net (334 gross) wells consisting of 69.16 net (266 gross) natural gas wells and 19.1 net (68 gross) oil wells.  In addition, the company owned royalty and production payment interests in approximately 1,169 wells, primarily coal bed methane, located in Wyoming.  In 2008, the company sold 0.29 net (2 gross) wells.  No wells were abandoned.  In the same period, the company acquired interests in 6.14 net (23 gross) productive wells.

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.

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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.

(1)                Of the gross wells drilled in 2008, four of the gas wells and three of the dry holes were operated by the company.  The remaining wells represent company participations in wells operated by others.

(1)                Of the net wells drilled in 2008, 1.380 net gas wells and 0.925 net dry holes were operated by the company.  The remaining wells represent company participations in wells operated by others.

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.

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As of October 31, 2008, the company had 13 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 including our annual report on Form 10-K/A, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) of 15(d) of the Exchange Act as soon as reasonably practicable after filing, (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.

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 has been named as a defendant in a lawsuit alleging breach of contract, and other issues, arising in the normal course of its oil and gas activities.  The company believes that a contractual agreement requires that disputes be resolved by arbitration.  Although the company believes the allegations are without merit and that the company will ultimately prevail, the ultimate outcome of this lawsuit, or arbitration, cannot be determined at this time.

No matters were submitted to a vote of security holders during the fourth quarter of 2008.

PART II

The company’s common stock is traded on the NASDAQ Global MarketSM 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 7, 2009, the company had 2,451 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 98,940 shares of its common stock on the open market at a weighted average price of $7.30.  The purchases were made pursuant to a stock repurchase plan announced on September 24, 2008.  The plan authorized repurchases up to $2,000,000, but could be expanded, suspended or discontinued at any time.  Subsequent to October 31, 2008, and through January 5, 2009, the company has repurchased an additional 64,112 shares, bringing the total shares repurchased to 163,052 at an average price per share of $8.60.

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Issuer Purchases of Equity Securities

Subsequent to October 31, 2008, and through January 5, 2008, the company has repurchased an additional 64,112 shares, bringing the total shares repurchased to 163,052 at an average price per share of $8.60.

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, 2008 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.

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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, 2008 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 are reflected in all historical share and per share data.

(2) See Footnote 10 to the Consolidated Financial Statements.

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Operations

Summary — During 2008, 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.

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 oil and natural gas reserves and production at reasonable costs and risks.  However, it should be expected that successful results will occur unevenly for both the drilling and Calliope projects.  Drilling results are dependent on both the timing of drilling and on the drilling success rate.  Calliope results are primarily dependent on the timing, volume and quality of Calliope installations available to the company.

The company will continue to actively pursue adding reserves through its two core projects in fiscal 2009, and expects these activities to be a reliable source of reserve additions.  However, the timing and extent of such activities can be dependent on many factors which are beyond the company’s control, including but not limited to, the 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.

During the year, the company experienced delays in securing delivery of production equipment, primarily compressors and coil tubing.  These delays extended the time to conduct field operations in general, and in particular related to installations of Calliope systems.

Results of Operations

In 2008, oil and gas revenues increased 22% to $17,345,000 compared to $14,265,000 in 2007.  The increase was due to a 63% increase in oil prices and a 32% increase in gas prices (excluding realized derivative gains and losses) partially offset by a 16% decrease in gas equivalent production.  As the oil and gas price/volume table on page 22 shows, total gas price realizations, which reflect realized derivative transactions, increased 9% to $7.40 per Mcf and oil price realizations increased to $99.28 per barrel.  The net effect of these price realization changes was to increase oil and gas sales by $3,252,000 (vs. $5,547,000 increase without derivative gains and losses).  Realized derivative losses were $1,113,000 in 2008 compared to gains of $1,909,000 in 2007.  During the same period, the company’s gas equivalent production fell 16% resulting in a decrease in oil and gas sales of $2,467,000.  Unrealized derivative gains were $1,301,000 in FY 2008 compared to unrealized losses of $454,000 in 2007.  Investment and other income decreased primarily due to market place declines impact on the company’s investments.

In 2008, total costs and expenses rose 7.6% to $9,081,000 compared to $8,438,000 in 2007.  Oil and gas production expenses increased 14% due primarily to the addition of new wells and escalating field service costs.  General and administrative expenses increased 17% primarily due to increases in salaries and benefits, accounting and professional fees.  The effective tax rate was 26.5% and 28.7% for the 2008 and 2007 periods, respectively.  The variation from statutory rate is primarily due to percentage depletion.

In 2007, oil and gas revenues decreased 11% to $14,265,000 compared to $16,103,000 in 2006.  The decrease was due to a 7% decline in gas prices (excluding realized derivative gains and losses) and an 8% decrease in gas equivalent production.  As the oil and gas price/volume table on page 22

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shows, total gas price realizations, which reflect realized hedging transactions, increased 11% to $6.78 per Mcf and oil price realizations fell to $60.95 per barrel.  The net effect of these price realization changes was to increase oil and gas sales by $1,187,000 (vs. $988,000 decrease without derivatives).  Realized derivative gains were $1,909,000 in 2007 compared to losses of $266,000 in 2006.  During the same period, the company’s gas equivalent production fell 8% resulting in a decrease in oil and gas sales of $849,000.  Unrealized derivative losses were $454,000 in FY 2007 compared to unrealized gains of $1,327,000 in 2006.  Investment and other income increased primarily due to improved performance from the company’s investments.

In 2007, total costs and expenses rose 1% to $8,438,000 compared to $8,340,000 for 2006.  Oil and gas production expenses fell 1% due primarily to reduced taxes associated with lower production.  General and administrative expenses increased 8% primarily due to increases in professional fees related to compliance with Sarbanes-Oxley regulations.  Interest expense relates to the Calliope exclusive license agreement note payment.  The effective tax rate was 28.7% and 27.6% for the 2007 and 2006 periods, respectively.

Liquidity and Capital Resources

At October 31, 2008, working capital increased 93% to $24,160,000, compared to $12,511,000 at October 31, 2007, primarily due to the sale of 1,150,000 shares of newly issued common stock.  For the year ended October 31, 2008, net cash provided by operating activities was $12,293,000 compared to $11,674,000 for the same period in 2007.  The difference is primarily due to differences in non-cash unrealized gains/losses from derivatives of $1,755,000 between 2007 and 2008, a change in net proceeds from short-term investments from 2007 to 2008 of $3,480,000 and a decrease in accounts payable and accrued liabilities from 2007 to 2008 of $285,000 and an increase in trade receivables from 2007 to 2008 of $759,000.  Investing activities primarily included oil and gas exploration and development expenditures, including Calliope, totaling $12,528,000 and $9,144,000, in 2008 and 2007.  Financing activities primarily included the sale of common stock of $15,095,000 net of transaction costs in 2008, the purchase of treasury stock of $722,000 and $506,000 and proceeds from exercise of stock options of $637,000 and $368,000 in 2008 and 2007, respectively.

The company’s earnings before interest, taxes, depreciation, depletion and amortization, (“EBITDA”) was $11,744,000 for the year ended October 31, 2008 and $11,767,000 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, loss, on the company’s investments for the year ended October 31, 2008 and 2007 was a loss of 2.0% and a gain of 11.0%, respectively.  At October 31, 2008, approximately 92% of the investments consist primarily of professionally managed limited partnerships which include investments that are not publicly traded and may have less readily determinable market values.  The company is in the process of liquidating these investments.  Remaining investments are directly invested in mutual funds and were managed by professional money managers.  Most of the investments are liquid and the company believes they represent a responsible approach to cash management.  In

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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, 2008, 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.

As of October 31, 2008, the company had the following known contractual obligations:

(1)          Subsequent to October 31, 2008, the company purchased the patents underlying the license agreement and eliminated this commitment.

Impact of Current Credit Markets

As the company exited the fourth quarter of fiscal 2008, oil and natural gas prices had declined sharply from their recent record levels.  In addition, recent problems in the credit markets, steep stock market declines, financial institution failures and government bail-outs provide evidence of a weakening United States and global economy.  As a result of the market turmoil and price decreases, oil and gas companies with high debt levels and lack of liquidity have been and will continue to be negatively impacted.  However, the company does not expect to be significantly impacted by these recent events.  The company has no debt and is in a financially-strong position due to its past strategies.  The company anticipates its cash on hand and operating cash flow will adequately fund planned capital expenditures and other capital uses over the near-term.

Off-Balance Sheet Arrangements

The company has no off-balance sheet arrangements at October 31, 2008.

Product Prices and Production

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

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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)  Effects of realized gains (losses) on natural gas hedging derivative contracts.

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.  Derivative transactions typically take the form of forward short positions and collars on the NYMEX futures market, and are closed by purchasing offsetting positions.

The company has elected not to designate its commodity derivatives as cash flow hedges for accounting purposes.  Accordingly, such contracts are recorded at fair value on its Balance Sheet and changes in fair value are recorded in the Consolidated Statements of Operations as they occur.

Open derivative contracts at October 31, 2008 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 15% to 17% below NYMEX prices primarily due to basis differentials.  However, regional weather conditions and other economic factors, such as the current delay in completion of the eastern extension of the Rocky Mountain Express gas pipeline, resulting in excess natural gas supplies to the mid-continent region, can periodically result in substantially higher basis differentials.  At October 31, 2008, the Oklahoma basis differential was 56% of the NYMEX price.

The company has a hedging line of credit with its bank which is available, at the discretion of the company, to meet margin calls.  To date, the company has not used this facility and maintains it only as a precaution related to possible margin calls.  The maximum credit line available is $5,900,000 with interest calculated at the prime rate.  The facility is unsecured and has covenants that require the company to 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.

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Oil and Gas Activities

Capital Spending.  Capital spending in 2008 totaled $14,948,000, consisting primarily of additions to oil and gas properties.  Subsequent to fiscal year end, the company purchased all of the Calliope Gas Recovery System patents and all of the remaining third party right, title and interest in the Calliope technology.  In addition, the company purchased all of the patents for its new Tractor Seal fluid lift technology together with all third party right, title and interest in the technology The Tractor Seal technology is currently in the development state and, except for the patents, the company has not yet provided public disclosure regarding the technology.  The total purchase price was $4,500,000.

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.

During the year, the company drilled thirteen wells on its Oklahoma properties.  Of those, eleven are producers and two were dry holes.  Subsequent to fiscal year end, the company drilled three wells in Oklahoma, all of which appear to be commercial producers.  During the final 24-hour test, a new deeper pool discover well on the company’s 1,280 gross acre Pool\Proffitt prospect produced oil and gas at high rates from the Hunton formation with virgin pressure.  Electric logs and drilling and completion data indicate that the Chester and Mississippian formations are also productive in the well.  However, completion of the up-hole zones will be delayed in order to more fully evaluate the Hunton zone potential.  The company owns a 47% working interest and is the operator.  About one mile to the north on the Pool\Proffitt prospect, another well is currently being completed in the Mississippian and Chester formations.  The company owns a 73% working interest and is the operator.  A third well is currently being completed for production in Carter County in which the company owns a 44% working interest.  The new well will develop two deeper Deese formation oil sands and the Woodford formation, both of which electric logs indicate are productive.

In Southern Oklahoma, the company is participating in three waterflood projects as part of its overall strategy to improve the oil ratio in its reserve base.  In Carter County, CREDO owns 17% of the Southeast Hewitt waterflood unit which has already produced 703,000 barrels of oil.  The company also owns about 22% in Phase 1, and 12.3% in Phase 2, of a Twin Forks Deese sand waterflood unit that has recently been formed.  In Love County, CREDO owns 13% in Phase 1, and 9.5% in Phase 2, of the Eastman Hills waterflood unit that is installed and operational.

In Hemphill County, Texas, the company has purchased interests in over 6,000 gross acres and has taken over as operator of 11 wells.  The new acreage complements the company’s existing prospect acreage and brings its total acreage in the area to approximately 9,000 gross acres.

South Texas — In South Texas, the initial test well on the Gemini Prospect resulted in a dry hole. The 17,000-foot well confirmed the seismic interpretation and found porous sand.  However, the sand was water wet and the well was plugged and abandoned.  CREDO received approximately $1,300,000 of cash for the multiple prospect package and retained an 11.25% “carried interest” in the test well.

The prospect package consists of two additional Deep Wilcox prospects located north of the Gemini Prospect.  These two prospects are structurally different and unique compared to the Gemini Prospect.  Those prospects are being further evaluated, and if drilled, CREDO will have an 11.25% carried interest in the first well.

Elsewhere in South Texas, the company has purchased a 15.5% working interest in the Escobas Field. A new 15,500-foot Wilcox well has been drilled in which the company has a small carried interest.  That well is currently producing 2.7 MMcfd (million cubic of gas per day) on a 12/64ths choke.

Central Kansas Uplift — The company further expanded the volume and breadth of its exploration program with a new drilling project in central Kansas and Nebraska.  The project provides

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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 about 141,000 gross (66,000 net) 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 85%.  The company’s recent drilling results have improved significantly as it continues to find the keys to successful seismic and geologic interpretation.  At October 31, 2008, the company has participated in drilling a total of 29 wells on the acreage, of which 48% have been successfully completed as oil producers.  Well depths range from 3,500 to 4,000 feet and drilling costs are moderate.

The company has recently drilled a wildcat well on a 2,150 gross acre seismically defined prospect. Production pipe has been set through the Lansing-Kansas City formation.  The well is classified as a “tight hole”, meaning that detailed information is not being released for proprietary business reasons.  CREDO owns an 85% working interest in the prospect and is the operator.  Development drilling is scheduled.

North Dakota — During 2008 the company expanded its exploration program into North Dakota and acquired approximately 4,200 gross acres (4,100 net) in the Fort Berthold Indian Reservation area of the Bakken shale play.

Calliope Gas Recovery Technology

Calliope’s Track Record — The company’s current compilation of Calliope’s track record shows Calliope installations 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 1.1 billion cubic feet of gas using Calliope.