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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549

 

FORM 10-K

 

x

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

 

 

 

For The Fiscal Year Ended October 31, 2009

 

 

 

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)

 

Delaware

 

84-0772991

(State or other jurisdiction

 

(I.R.S. Employer Identification Number)

of incorporation or organization)

 

 

 

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 checkmark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  o Yes o No

 

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (S229.405 of this chapter) 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.   x

 

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

 

Large accelerated filer o

 

Accelerated filer x

 

 

 

Non-accelerated filer o

 

Smaller reporting company 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, 2009, the end of the registrant’s most recently completed second quarter was $76,795,000.

 

As of January 4, 2010, the registrant had 10,204,000 shares of common stock outstanding.

 

 

 



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DOCUMENTS INCORPORATED BY REFERENCE

 

Pursuant to instruction G (3) to Form 10-K, 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 April 8, 2010 and is hereby incorporated by reference.

 

NON-GAAP FINANCIAL MEASURES

 

In this Annual Report on Form 10-K, the company uses the term “EBITDA (Earnings Before Interest, Taxes, Depreciation and Amortization including impairment losses)” 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.

 

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 13 to the company’s Consolidated Financial Statements.

 

FORWARD-LOOKING STATEMENTS

 

This Annual Report on Form 10-K 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, 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, 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

 

ITEM

 

PAGE

 

 

 

PART I

 

 

 

Item 1.

Business

5

 

General

5

 

Business Activities

5

 

Markets and Customers

6

 

Competition and Regulation

7

Item 1A.

Risk Factors

7

Item 1B.

Unresolved Staff Comments

11

Item 2.

Properties

11

 

General

11

 

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

13

 

Production, Average Sales Prices and Average Production Costs

14

 

Productive Wells and Developed Acreage

15

 

Undeveloped Acreage

15

 

Drilling

15

 

Insurance

16

 

Facilities and Employees

16

 

Company Website

16

Item 3.

Legal Proceedings

16

Item 4.

Submission of Matters to a Vote of Security Holders

16

 

PART II

 

 

 

Item 5.

Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

17

Item 6.

Selected Financial Data

20

Item 7.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

21

Item 7A.

Quantitative and Qualitative Disclosures about Market Risk

29

Item 8.

Financial Statements and Supplementary Data

29

Item 9.

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

52

Item 9A.

Controls and Procedures

52

Item 9B.

Other Information

53

 

 

 

PART III

 

 

 

Item 10.

Directors, Executive Officers and Corporate Governance

53

Item 11.

Executive Compensation

53

Item 12.

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

53

Item 13.

Certain Relationships and Related Transactions and Director Independence

53

Item 14.

Principal Accounting Fees and Services

53

 

 

 

PART IV

 

 

 

Item 15.

Exhibits and Financial Statement Schedules

53

 

 

 

Signatures

 

55

 

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PART I

 

ITEM 1.                  BUSINESS

 

General

 

Credo Petroleum Corporation (“Credo”) was incorporated in Colorado in 1978 and reincorporated in Delaware in 2009.  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 and Rocky Mountain areas of the United States.  The company has operating activities in nine states and has thirteen full-time employees.  Credo is an active operator in Kansas, Wyoming, Colorado 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

 

Credo is engaged in the exploration for, acquisition of, and production of crude oil, natural gas and natural gas liquids.  The company’s business strategy focuses on two core areas:  drilling for oil and natural gas and recovering stranded gas from low-pressure reservoirs using the company’s patented Calliope Gas Recovery System (“Calliope”).  Together, the company believes that drilling and Calliope provide a unique formula for success which distinguishes Credo from other oil and gas exploration and production companies.

 

Prior to 2006, the company’s core drilling region was the northern shelf of the Anadarko Basin in Oklahoma and North Texas where it explored primarily for natural gas.  As a result, a significant majority of the company’s reserves have historically been comprised of natural gas.

 

In recent years, the company has made significant strategic changes with the objectives of expanding the volume and breadth of its drilling activities and focusing on drilling for and developing crude oil reserves. To accomplish these objectives, the company implemented new exploration projects in central Kansas, the Williston Basin of North Dakota and South Texas.  This strategic change is intended to diversify the company’s drilling projects both technologically and geographically and to improve the balance between crude oil and natural gas in both its production and reserves.

 

Compared to drilling in Oklahoma, the North Dakota and South Texas projects involve higher costs and greater risks but have significantly higher per well reserve potential.  In contrast, drilling in central Kansas is less expensive than the company’s Oklahoma drilling projects while still yielding excellent economics.  Depending on natural gas prices, the company will continue generating prospects and drilling on its Oklahoma and South Texas acreage concentrating on medium depth properties.  Refer to Item 2 — “Properties — General” for further information about these drilling projects.

 

The company owns the patents covering Calliope and has been instrumental in developing, testing, refining, and patenting the technology.  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 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 the Chester, Cotton Valley, Edwards, Hart, Hunton, Morrow, Nodosaria, Red Fork and Springer reservoirs.

 

Calliope’s low per-unit finding and production costs have become increasingly attractive as the economics on many drilling projects have deteriorated due to lower product prices.  The company

 

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also believes that lower natural gas prices may stimulate divestitures of marginal properties by other companies, including properties that have Calliope potential.

 

The company acts as “operator” of approximately 135 wells pursuant to standard industry operating agreements.  The company owns working interests in about 350 producing wells and overriding royalty interests in about 1,200 wells.

 

Refer to Item 2., “Properties”, for more information regarding the company’s properties and Calliope.

 

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 per barrel, then fell below $35 in December.

 

Natural gas price decontrol, the advent of an active spot market for natural gas, changes in supply and demand for natural gas, speculation, and weather patterns cause natural gas prices to be subject to significant fluctuations.  The company presently sells virtually all of its natural gas under three 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.

 

Natural gas prices were strong through mid-2008 due to concern about possible domestic supply/demand imbalances and in sympathy with increasing oil prices.  This, together with 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 second half of 2008 resulted in a significant reduction in industrial demand for natural gas at the same time gas supplies were increasing due to drilling success in gas resource plays.  Those events caused an over supply of natural gas with the result that prices crashed.  For example, the Panhandle Eastern Pipeline natural gas index, the basis for most of the company’s gas sales, fell from $11.07 per Mcf in July 2008 to $2.81 in November 2008 and $3.50 in October, 2009.  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, the company periodically hedges the price of a portion of its estimated natural gas production in the form of forward short positions on the NYMEX futures market.

 

Oil production is sold to crude oil purchasing companies at competitive 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, such as wars, in major producing regions.  Crude oil prices were strong through mid-2008 due to supply concerns in view of the demand growth expected from developing countries such as China and India.  However, the economic crisis that commenced in the second half of 2008 resulted in reduced demand projections and oil prices crashed from about $140 per barrel (NYMEX basis) in July 2008 to about $35 per barrel in February, 2009.  Prices have since recovered to the $70 to $80 per barrel range.

 

Information concerning the company’s major customers is included in Note (13) to the Consolidated Financial Statements.

 

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Competition and Regulation

 

The oil and gas industry is highly competitive.  As a small independent, the company must compete against companies with substantially greater 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.  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 2010.  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.  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 14 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

 

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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.

 

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

 

This Annual Report on Form 10-K 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, 2009, approximately 36% 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 from those estimates.

 

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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.

 

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”.

 

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.  See Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for more information related to ceiling test write-downs.

 

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 64 properties which represent 22% 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 2009 comprise 8% of these significant properties and 14% 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.

 

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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.

 

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 currently 2% below NYMEX prices.  However, regional weather conditions and other economic factors can frequently result in substantially higher basis differentials.

 

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 Sheets and changes in fair value are recorded in the 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.

 

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The company has recently expanded the volume and breadth of its exploration program with new drilling projects in South Texas and North Dakota.  Compared to the company’s Oklahoma drilling, these projects involve 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 regulations relating to:

 

·                  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.

 

The company could incur liability for violations of these regulations.  In addition, because current regulations covering the company’s operations are subject to change at any time, 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.

 

ITEM 1B.               UNRESOLVED STAFF COMMENTS

 

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

 

ITEM 2.                  PROPERTIES

 

General

 

Refer to Item 1.—“Business Activities” for a general description of the company’s oil and gas drilling and Calliope projects.  Refer to Item 2. — “Significant Properties, Estimated Proved Oil and Gas Reserves, and Future Net Revenues” for information regarding the company’s significant oil and gas properties.

 

The company owns approximately 70,000 gross acres located on the northern shelf of the Anadarko Basin of Oklahoma and North Texas where it also owns interests in approximately 226 gross (71 net) wells, primarily natural gas wells.  Historically, the company’s drilling has been focused on this area.  However, in recent years the company has diversified its drilling activities into other regions and has deemphasized drilling for natural gas in favor of drilling for crude oil reserves. Continued drilling on the company’s Oklahoma and North Texas acreage is primarily dependent on natural gas prices, however, because much of the company’s acreage is held by production, the timing of drilling is not critical in terms of preserving most of the company’s acreage ownership.

 

In recent years, the company has significantly expanded both the volume and breadth of its drilling activities with new projects in central Kansas, North Dakota’s Williston Basin, and South Texas.  Compared to drilling in Oklahoma, the North Dakota and South Texas projects involve higher costs and greater risks but significantly higher per well reserve potential.  In contrast, drilling in central Kansas is less expensive than the company’s Oklahoma drilling projects while still yielding excellent economics.

 

In central Kansas, the company owns interests in approximately 140,000 gross acres and 77,000 net acres and it is continuing to expand its acreage position. At October 31, 2009, the company has

 

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participated in drilling 44 wells on its acreage, of which 43% have been successfully completed as producers.  The company is continuing to conduct an active drilling program expected to consist of two to three wells per month.  The company owns working interests in the existing prospects ranging from 12.5% to 85%. The company’s north-central 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 older technology.  Drilling targets the Lansing-Kansas City and Arbuckle formations at about 4,000 feet and, compared to the company’s Northern Anadarko Basin, North Dakota Bakken, and South Texas projects, is relatively low cost, low risk, and exclusively targets oil reserves.

 

In North Dakota’s Bakken oil shale play, the company has assembled approximately 7,600 gross and 5,675 net acres on the Fort Berthold Indian Reservation south and west of Parshall Field.  The acreage consists of approximately 33 drilling locations based on 640 acre spacing units and 13 locations based on 1,280 acre spacing units.  The company expects that more than one well will be drilled on many spacing units.  The project targets horizontal drilling for the Bakken and Three Forks shales.  Breakthroughs in precision horizontal drilling and multi-stage, high pressure fracture stimulations have made the Bakken shale a very active resource play which is being actively developed by a significant number of companies, including large independents and majors.  The U.S. Geological Survey recently estimated that the Bakken contains around 4.0 billion barrels of undiscovered oil.  Vertical well depths on the company’s acreage are approximately 10,000 feet and the horizontal legs are generally expected to range between 5,000 and 10,000 feet.  Drilling is complete on the first Bakken horizontal well in which the company owns an interest and the well is currently awaiting completion which has been delayed due to cold weather and is now expected to commence in February 2010.  The horizontal leg of the well is approximately 9,200 feet and will be completed in multiple stages.  Credo owns a 10% working interest.  Work is currently under way in preparation for drilling two to three additional wells on company acreage.

 

The South Texas project is 3-D seismic driven with well depths ranging from 10,000 to 17,000 feet. The most significant well drilled to date tested the Deep Wilcox formation on the Gemini Prospect and 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.  The company 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 sold 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, the company will have the same 11.25% carried interest in the next well as it did in the Gemini Prospect test well.  This project is highly dependent on natural gas prices and is currently on hold due to low natural gas prices.

 

The company owns the patents covering Calliope and the exclusive rights to the technology.  The company has been instrumental in developing, testing, refining, and patenting the technology.  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 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 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.  The company has proven Calliope’s economic viability and flexibility over a wide range of applications.

 

External sources of capital have not been required for the development, refinement or installation of Calliope.

 

The company currently has Calliope installed on wells located in Oklahoma and Texas which include both sandstones and limestones in the Chester, Cotton Valley, Edwards, Hart, Hunton, Morrow, Nodosaria, Red Fork and Springer reservoirs.  At the time Calliope was installed, 14 of the wells

 

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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 5.4 billion cubic feet of gas and they now have estimated ultimate (8/8ths) Calliope reserves totaling 7.0 billion cubic feet of gas.  Ten of the Calliope wells are included in the company’s Significant Properties.

 

Calliope’s low per-unit finding and production cost have become increasingly attractive as the economics on many drilling projects have deteriorated due to lower product prices.  The company also believes that lower natural gas prices may stimulate divestitures of marginal properties by other companies, including properties that have Calliope potential.

 

On November 6, 2008 the company purchased all of the patents underlying Calliope, 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 has three primary strategies to monetize its Calliope technology.  The preferred strategy is to purchase dead and uneconomic wells from outside parties.  A second strategy involves entering into joint ventures with outside parties that already own Calliope candidate wells.  The third strategy is to drill new wells into old depleted fields and then use Calliope to recover the stranded gas.  That strategy is highly dependent on natural gas prices and is generally not viable at current natural gas prices.  The company is actively pursuing acquiring wells and joint ventures with other companies.  During fiscal 2009, a joint venture agreement for a pilot project was completed with a large independent and joint venture discussions are underway with several companies, both large and small.

 

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

 

The company’s reserves, and reserve values, are concentrated in 64 properties (“Significant Properties”).  Some of the Significant Properties are individual wells and others are multi-well properties.  At year-end, Significant Properties represent 22% 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 2009 comprise 8% of the Significant Properties and represent 14% of the discounted value of such properties.

 

Estimates of reserve quantities and values for certain Significant Properties must be viewed as being subject to significant change as more data about the properties becomes available. Such properties include wells with limited production histories and properties with proved undeveloped or proved non-producing reserves. In addition, 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, 2009 and 2008, LaRoche Petroleum Consultants, Ltd., an independent petroleum engineering firm, estimated proved reserves for all of the company’s properties.  In 2007 McCartney Engineering, Inc., an independent petroleum engineering firm, estimated proved reserves for the company’s properties which represented 64% of the total estimated future value of estimated reserves.  In 2007, remaining reserves were estimated by the company.  At October 31, 2009, natural gas represented 74% and crude oil represented 26% 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 (11) to the Consolidated Financial Statements where additional reserve information is provided.  The average price used to calculate estimated future net revenues was $4.49, $3.50, and $5.89 per Mcf of gas and $69.24, $62.25, and $86.61 per barrel of oil as of October 31, 2009, 2008, and 2007, respectively.  Amounts do not include estimates of future Federal and state income taxes.

 

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Table of Contents

 

 

 

 

 

 

 

 

 

Estimated Future

 

 

 

Gas

 

Oil

 

Estimated Future

 

Net Revenues

 

Year

 

(Mcf) *

 

(bbls) *

 

Net Revenues

 

Discounted at 10%

 

 

 

 

 

 

 

 

 

 

 

2009

 

14,940,000

 

876,000

 

$

71,863,000

 

$

40,434,000

 

2008

 

15,525,000

 

710,000

 

$

53,655,000

 

$

32,330,000

 

2007

 

16,973,000

 

591,000

 

$

101,501,000

 

$

62,071,000

 

 


*     The percentage of total reserves classified as proved developed was approximately 61% in 2009, 67% in 2008, and 76% in 2007.

 

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 13 to the company’s Consolidated Financial Statements.

 

 

 

Year Ended October 31,

 

 

 

2009

 

2008

 

2007

 

Estimated future net revenues discounted at 10%

 

$

40,434,000

*

$

32,330,000

*

$

62,071,000

*

 

 

 

 

 

 

 

 

Future income tax expense

 

(15,119,000

)

(9,119,000

)

(24,967,000

)

 

 

 

 

 

 

 

 

Effect of the 10% discount factor on future income tax expense

 

7,285,000

 

4,408,000

 

9,697,000

 

 

 

 

 

 

 

 

 

Standardized measure of discounted future net cash flows

 

$

32,600,000

 

$

27,619,000

 

$

46,801,000

 

 


*     The average price used to calculate estimated future net revenues was $69.24, $62.25 and $86.61 per barrel of oil and $4.49, $3.50 and $5.89 per Mcf of gas as of October 31, 2009, 2008, and 2007, 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.

 

 

 

2009

 

2008

 

2007

 

Product

 

Volume

 

Price

 

Volume

 

Price

 

Volume

 

Price

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil (bbls)

 

116,000

 

$

51.46

 

56,000

 

$

99.28

 

51,000

 

$

60.95

 

Gas (Mcf)

 

1,229,000

 

$

6.37

(1)

1,545,000

 

$

7.40

(2)

1,926,000

 

$

6.78

(3)

 


(1)   Included $3.02 Mcf realized natural gas hedging derivative gain.

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

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

 

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 $1.71, $2.05 and $1.51 per Mcfe in 2009, 2008, and 2007, respectively.

 

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Productive Wells and Developed Acreage

 

Developed acreage at October 31, 2009 totaled 28,000 net and 188,000 gross acres.  At October 31, 2009, the company owned working interests in 93 net (339 gross) wells consisting of 70.61 net (265 gross) natural gas wells and 22.21 net (74 gross) oil wells.  In addition, the company owned royalty and production payment interests in approximately 1,181 wells, primarily coal bed methane, located in Wyoming.  In 2009, no wells were sold or abandoned or acquired.

 

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.

 

Expiration

 

Royalty

 

Working

 

Year Ending

 

Interest Acreage

 

Interest Acreage

 

October 31,

 

Gross

 

Net

 

Gross

 

Net

 

 

 

 

 

 

 

 

 

 

 

2010

 

3,300

 

100

 

49,100

 

16,800

 

2011

 

 

 

86,600

 

52,500

 

2012

 

 

 

11,400

 

7,600

 

2013

 

 

 

7,800

 

6,100

 

2014

 

 

 

1,600

 

500

 

Thereafter

 

3,700

 

500

 

3,000

 

1,900

 

Held-By-Production

 

148,100

 

7,900

 

16,300

 

3,500

 

 

 

 

 

 

 

 

 

 

 

Total

 

155,100

 

8,500

 

175,400

 

88,900

 

 

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.

 

Gross Wells

 

Year Ended

 

Total Gross

 

Exploratory

 

Development

 

October 31,

 

Wells

 

Oil

 

Gas

 

Dry

 

Oil

 

Gas

 

Dry

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2009(1)

 

25

 

7

 

2

 

12

 

1

 

2

 

1

 

2008

 

32

 

12

 

9

 

11

 

 

 

 

2007

 

24

 

5

 

11

 

7

 

 

1

 

 

 


(1)                Of the gross wells drilled in 2009, 3 of the oil wells, 2 of the gas wells and 8 of the dry holes were operated by the company.  The remaining wells represent company participations in wells operated by others.

 

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Net Wells

 

Year Ended

 

Total Net

 

Exploratory

 

Development

 

October 31,

 

Wells

 

Oil

 

Gas

 

Dry

 

Oil

 

Gas

 

Dry

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2009(1)

 

12.089

 

3.007

 

0.131

 

7.109

 

0.168

 

1.230

 

0.444

 

2008

 

6.581

 

1.874

 

1.886

 

2.821

 

 

 

 

2007

 

8.591

 

1.166

 

4.143

 

2.700

 

 

0.582

 

 

 


(1)                Of the net wells drilled in 2009, 2.550 of the oil wells, 1.230 net gas wells and 6.043 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, directors and officers and excess liability.

 

Facilities and Employees

 

The company’s corporate headquarters are located at 1801 Broadway, Suite 900, Denver, Colorado, in approximately 5,000 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, 2009, 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, 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.

 

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, 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.

 

The company has also been named as a defendant in a lawsuit brought by a former employee.  The suit, Pownell v. Credo Petroleum Corp. et al., U.S.D.C. for the District of Colorado, alleges breach of contract and other employment issues.  Although the company believes the allegations are without merit and that the company will ultimately prevail, the ultimate outcome of this lawsuit cannot be determined at this time.

 

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 2009.

 

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Table of Contents

 

PART II

 

ITEM 5.

MARKET FOR THE REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

 

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.

 

 

 

2009

 

2008

 

Quarter Ended

 

High

 

Low

 

High

 

Low

 

January 31

 

$

10.21

 

$

7.86

 

$

10.37

 

$

7.95

 

April 30

 

$

9.53

 

$

6.73

 

$

11.36

 

$

8.57

 

July 31

 

$

12.87

 

$

8.08

 

$

18.04

 

$

9.93

 

October 31

 

$

12.90

 

$

9.72

 

$

11.06

 

$

6.03

 

 

At January 4, 2010, the company had 2,321 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 fiscal year, the company repurchased 196,494 shares of its common stock on the open market at a weighted average price of $9.27.  The purchases were made pursuant to a stock repurchase plan announced on September 24, 2008.  The plan authorized repurchases up to $2,000,000, and was subsequently expanded to authorize purchases up to $4,000,000.  Subsequent to October 31, 2009, and through January 7, 2010, the company has repurchased an additional 36,937 shares, bringing the total shares repurchased to 332,371 at an average price per share of $8.79.

 

Issuer Purchases of Equity Securities

 

 

 

 

 

 

 

Total number

 

 

 

 

 

 

 

 

 

of shares

 

Maximum dollar

 

 

 

 

 

 

 

purchased

 

value of shares

 

 

 

 

 

 

 

as part of

 

that may yet

 

 

 

Total number of

 

Average price

 

publicly

 

be purchased

 

Period

 

shares purchased

 

paid per share

 

announced plan

 

under the plan

 

 

 

 

 

 

 

 

 

 

 

September 22, 2008 - October 31, 2008

 

98,940

 

$

7.31

 

98,940

 

$

1,277,000

 

November 1 - 30 2008

 

45,954

 

$

9.45

 

45,954

 

$

843,000

 

December 1 - 31 2008

 

22,350

 

$

8.88

 

22,350

 

$

645,000

 

January 1 - 31 2009

 

6,182

 

$

9.16

 

6,182

 

$

588,000

 

February 1 - 28, 2009

 

29,104

 

$

8.56

 

29,104

 

$

338,000

 

March 1 - 31, 2009

 

15,110

 

$

7.49

 

15,110

 

$

225,000

 

April 1 - 30, 2009

 

12,800

 

$

7.76

 

12,800

 

$

2,126,000

 

June 1 - 30, 2009

 

1,031

 

$

9.58

 

1,031

 

$

2,116,000

 

July 1 - 31, 2009

 

6,451

 

$

10.90

 

6,451

 

$

2,045,000

 

August 1-31, 2009

 

 

$

 

 

$

2,045,000

 

September 1-30, 2009

 

25,412

 

$

10.32

 

25,412

 

$

1,783,000

 

October 1-31, 2009

 

32,100

 

$

10.19

 

32,100

 

$

1,456,000

 

 

 

 

 

 

 

 

 

 

 

Total

 

295,434

 

$

8.61

 

295,434

 

 

 

 

Subsequent to October 31, 2009, and through January 7, 2010, the company has repurchased an additional 36,937 shares, bringing the total shares repurchased to 332,371 at an average price per share of $8.79.

 

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Performance Graph

 

The following performance graph compares the cumulative total stockholder return on the company’s common stock for the five-year period ended October 31, 2009 with the cumulative total return of Standard and Poor’s SmallCap 600 Oil and Gas Exploration and Production 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, 2009 were derived from the audited financial statements and the accompanying notes to those financial statements.

 

 

 

Years Ended October 31,

 

 

 

2009

 

2008

 

2007

 

2006

 

2005

 

Audited Financial Information

 

 

 

 

 

 

 

 

 

 

 

Statement of Operations Data:

 

 

 

 

 

 

 

 

 

 

 

Oil and gas sales

 

$

10,067,000

 

$

17,345,000

 

$

14,265,000

 

$

16,103,000

 

$

13,862,000

 

Oil and gas production expense

 

3,260,000

 

3,861,000

 

3,375,000

 

3,407,000

 

2,759,000

 

Depreciation, depletion and amortization

 

4,439,000

 

3,583,000

 

3,666,000

 

3,642,000

 

2,402,000

 

Non-cash writedown of oil & gas properties and impairment of long lived assets

 

24,653,000

 

 

 

 

 

General and administrative

 

3,250,000

 

1,637,000

 

1,397,000

 

1,291,000

 

1,117,000

 

Income(loss) from operations

 

(25,535,000

)

8,264,000

 

5,827,000

 

7,763,000

 

7,584,000

 

Realized and Unrealized gains(losses) from derivative contracts

 

2,079,000

 

188,000

 

1,455,000

 

1,061,000

 

(537,000

)

Income(loss) before income taxes

 

(23,515,000

)

8,153,000

 

8,075,000

 

9,436,000

 

7,156,000

 

Net income(loss)

 

(14,454,000

)

5,993,000

 

5,760,000

 

6,836,000

 

5,153,000

 

Earnings(loss) per share:

 

 

 

 

 

 

 

 

 

 

 

Basic

 

$

(1.40

)

$

0.62

 

$

0.62

 

$

0.74

 

$

0.57

 

Diluted

 

$

(1.40

)

$

0.61

 

$

0.61

 

$

0.72

 

$

0.55

 

Weighted-average shares outstanding(1):

 

 

 

 

 

 

 

 

 

 

 

Basic

 

10,326,000

 

9,697,000

 

9,280,000

 

9,207,000

 

9,080,000

 

Diluted

 

10,326,000

 

9,758,000

 

9,395,000

 

9,482,000

 

9,367,000

 

 

 

 

 

 

 

 

 

 

 

 

 

Balance Sheet Data:

 

 

 

 

 

 

 

 

 

 

 

Working capital

 

13,542,000

 

24,160,000

 

12,511,000

 

10,073,000

 

7,697,000

 

Total assets

 

52,552,000

 

80,650,000

 

55,349,000

 

47,759,000

 

37,844,000

 

Long-term obligations:

 

 

 

 

 

 

 

 

 

 

 

Deferred income taxes-net

 

2,537,000

 

11,117,000

 

9,204,000

 

8,039,000

 

5,978,000

 

Asset retirement obligation

 

1,502,000

 

1,338,000

 

1,016,000

 

954,000

 

929,000

 

Exclusive license agreement obligation

 

 

 

85,000

 

163,000

 

233,000

 

Stockholders’ equity

 

46,056,000

 

62,211,000

 

41,140,000

 

34,767,000

 

26,947,000

 

 

 

 

 

 

 

 

 

 

 

 

 

Unaudited Operating Data

 

 

 

 

 

 

 

 

 

 

 

Production Volumes:

 

 

 

 

 

 

 

 

 

 

 

Oil (Bbls)

 

116,000

 

56,000

 

51,000

 

41,000

 

37,000

 

Gas (Mcf)

 

1,229,000

 

1,545,000

 

1,926,000

 

2,176,000

 

1,830,000

 

Mcfe

 

1,923,000

 

1,880,000

 

2,234,000

 

2,422,000

 

2,050,000

 

Avg. sales price before realized derivative gains & losses:

 

 

 

 

 

 

 

 

 

 

 

Per Bbls

 

$

51.46

 

$

99.28

 

$

60.95

 

$

61.14

 

$

50.90

 

Per Mcf

 

$

3.35

 

$

7.65

 

$

5.79

 

$

6.24

 

$

6.55

 

Avg. sales price after realized derivative gains & losses:

 

 

 

 

 

 

 

 

 

 

 

Per Bbls

 

$

51.46

 

$

99.28

 

$

60.95

 

$

61.14

 

$

50.90

 

Per Mcf

 

$

6.37

 

$

7.40

 

$

6.78

 

$

6.11

 

$

6.16

 

Reserves((1)

 

 

 

 

 

 

 

 

 

 

 

Oil (Bbls)

 

876,000

 

710,000

 

591,000

 

422,000

 

386,000

 

Gas (Mcf)

 

14,940,000

 

15,525,000

 

16,973,000

 

16,005,000

 

15,516,000

 

Mcfe

 

20,197,000

 

19,788,000

 

20,517,000

 

18,537,000

 

17,835,000

 

Estimated future net revenues

 

$

71,863,000

 

$

53,655,000

 

$

101,501,000

 

$

84,861,000

 

$

136,878,000

 

Estimated future net revenues discounted at 10%

 

$

40,434,000

 

$

32,330,000

 

$

62,071,000

 

$

52,328,000

 

$

81,209,000

 

 


(1) See Footnote 13 to the Consolidated Financial Statements.

 

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Table of Contents

 

ITEM 7.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

 

Operations

 

Summary — During 2008 and 2009, the company’s operations were focused on its two core projects — drilling in the Mid-Continent and Rocky Mountain areas 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 2010, 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.

 

Results of Operations

 

In 2009, oil and gas revenues decreased 42% to $10,067,000 compared to $17,345,000 in 2008.  The decrease was due to a 48% decrease in oil prices and a 56% decrease in natural gas prices (excluding realized derivative gains and losses).  As the oil and gas price/volume table on page 22 shows, total gas price realizations, which reflect realized derivative transactions, decreased 14% to $6.37 per Mcf and oil price realizations decreased to $51.46 per barrel.  The net effect of these price realization changes was to decrease total oil and gas sales realizations by $5,200,000 ($9,305,000 decrease without derivative gains and losses).  Realized derivative gains were $3,720,000 in 2009 compared to losses of $1,113,000 in 2008.  During the same period, the company’s oil production increased 108% to 116,000 barrels, which offset a 21% reduction in gas production to 1,229,000 Mcf resulting in an increase in oil and gas sales of $2,028,000.  Unrealized derivative losses were $1,641,000 in 2009 compared to unrealized gains of $1,301,000 in 2008.  Investment and other income decreased primarily due to the impact of market place declines on the company’s investments coupled with a liquidation of investments during 2009.

 

In 2009, total costs and expenses, excluding oil and gas property and intangible asset impairment charges, increased 21% to $10,949,000 compared to $9,081,000 in 2008.  Oil and gas production expenses decreased 16% due primarily to decreased field level service costs.  General and administrative expenses increased $1,613,000 to $3,250,000 primarily due to increases in salaries and benefits, Board of Director fees and expenses, legal fees and a one-time $414,000 retirement payment to the Chief Executive Officer in lieu of a $2,500 per month retirement annuity.

 

Due primarily to low natural gas prices during the first half of 2009, for the fiscal year ended October 31, 2009, the company recorded non-cash ceiling test write-downs at the end of the first and second quarters, in the aggregate of $23,726,000.  The company also recorded intangible asset impairment charges of $927,000 in the first quarter of 2009.

 

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Table of Contents

 

The effective tax rate was 38.5% and 26.5% for the 2009 and 2008 periods, respectively.  The variation from the statutory rate in 2008 is primarily due to percentage depletion.

 

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 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 2008 and 2007, respectively.  The variation from statutory rate is primarily due to percentage depletion.

 

Liquidity and Capital Resources

 

At October 31, 2009, working capital decreased to $13,542,000, compared to $24,160,000 at October 31, 2008, primarily due to the use of cash for additions to oil and gas properties, other long-term assets and intangible assets.  For the year ended October 31, 2009, net cash provided by operating activities was $9,932,000 compared to $12,293,000 for the same period in 2008.  The difference is primarily due to decrease in net income of $5,285,000 excluding the non-cash effect of oil and gas property and intangible asset impairment charges, offset by differences in non-cash unrealized gains/losses from derivatives of $2,942,000, differences in non cash gains/losses from short term investments of $438,000, a change in net proceeds from short term investment liquidations of $492,000 and a decrease in other operating assets and liabilities of $1,132,000.  Investing activities primarily included oil and gas exploration and development expenditures, including Calliope, totaling $11,480,000 and $12,528,000 in 2009 and 2008, respectively.  Financing activities primarily included the purchase of treasury stock of $1,821,000 and $722,000 in 2009 and 2008, the sale of common stock of $15,095,000 net of transaction costs in 2008, and proceeds and tax benefits from exercise of stock options of $89,000 and $637,000 in 2009 and 2008, respectively.

 

The company’s earnings before interest, taxes, depreciation, depletion and amortization and write-downs of oil and gas properties and impairment losses (“EBITDA”) was $5,580,000 for the year ended October 31, 2009 and $11,744,000 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:

 

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Table of Contents

 

 

 

For The Year Ended October 31,

 

 

 

2009

 

2008

 

2007

 

 

 

 

 

 

 

 

 

RECONCILIATION OF EBITDA:

 

 

 

 

 

 

 

Net Income (Loss)

 

$

(14,454,000

)

$

5,993,000

 

$

5,760,000

 

Add Back(Deduct):

 

 

 

 

 

 

 

Interest Expense

 

3,000

 

8,000

 

26,000

 

Income Tax Expense (Benefit)

 

(9,061,000

)

2,160,000

 

2,315,000

 

Depreciation, Depletion and Amortization Expense

 

4,439,000

 

3,583,000

 

3,666,000

 

 

 

 

 

 

 

 

 

Write-Down of oil and natural gas properties and impairment of intangible assets

 

24,653,000

 

 

 

EBITDA

 

$

5,580,000

 

$

11,744,000

 

$

11,767,000

 

 

During 2009 the company liquidated the majority of its short term investments in professionally managed limited partnerships which were not publicly traded and had less readily determinable market values.  Only $342,000 of these investments remain at October 31, 2009.  These investments are anticipated to be entirely liquidated during early fiscal 2010.  Other short term investments are directly invested in certificates of deposit and mutual funds.

 

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, 2009, the company had no lines of credit or other bank financing arrangements except for the derivative line of credit discussed in Note 5 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, 2009, the company had the following known contractual obligations:

 

 

 

Payments Due by Period

 

 

 

 

 

Less Than

 

1-3

 

3-5

 

More Than

 

 

 

Total

 

1 Year

 

Years

 

Years

 

5 Years

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating lease obligations

 

61,000

 

41,000

 

20,000

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total

 

$

61,000

 

$

41,000

 

$

20,000

 

$

 

$

 

 

Impact of Current Credit Markets

 

As the company exited the fourth quarter of fiscal 2009, oil and natural gas prices remained sharply below their 2008 record levels.  In addition, problems in the credit markets, steep stock market declines, financial institution failures and government bail-outs provide evidence of a weakened 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 events.  The company has no debt and is in a financially strong position due in large part to its historical policy of conservative balance sheet management. 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, however, the company is not opposed to taking on reasonable debt to finance opportunities which it believes are in the company’s best long term interest.

 

Off-Balance Sheet Arrangements

 

The company has no off-balance sheet arrangements at October 31, 2009.

 

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Table of Contents

 

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.

 

 

 

2009

 

2008

 

2007

 

Price Realization

 

 

 

 

 

 

 

Oil

 

 

 

 

 

 

 

Net wellhead price received (per Bbl)

 

$

51.46

 

$

99.28

 

$

60.95

 

Effects of derivative gains (losses) (per Bbl)

 

 

 

 

Net price realization (per Bbl)

 

$

51.46

 

$

99.28

 

$

60.95

 

% Change

 

(48

)%

63

%

0

%

 

 

 

 

 

 

 

 

Natural Gas

 

 

 

 

 

 

 

Net wellhead price received (per Mcf)

 

$

3.35

 

$

7.65

 

$

5.79

 

Effects of derivative gains (losses) (per Mcf) (1)

 

3.02

 

(0.25

)

0.99

 

Net price realization (per Mcf)

 

$

6.37

 

$

7.40

 

$

6.78

 

% Change

 

(14

)%

9

%

11

%

 

 

 

 

 

 

 

 

 

 

2009

 

2008

 

2007

 

Total Sales Volumes

 

 

 

 

 

 

 

Oil (Bbl)

 

116,000

 

56,000

 

51,000

 

% Change

 

108

%

9

%

24

%

 

 

 

 

 

 

 

 

Natural Gas (Mcf)

 

1,229,000

 

1,545,000

 

1,926,000

 

% Change

 

(21

)%

(20

)%

(11

)%

 

 

 

 

 

 

 

 

Total equivalent production (Mcfe)

 

1,923,000

 

1,880,000

 

2,234,000

 

% Change

 

2

%

(16

)%

(8

)%

 


(1)  Effects of realized gains (losses) on natural gas 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 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, 2009 are indexed to the NYMEX and are represented by short positions and offsetting long positions.  The company also held basis differential hedges for NYMEX vs. Panhandle Eastern Pipeline basis differentials.  Actual price realizations in the company’s principal areas of operations (primarily Oklahoma) are currently 2% below NYMEX prices primarily due to basis differentials.  However, regional weather conditions and other economic factors frequently result in substantially higher basis differentials which have historically averaged in the 15% range.

 

The company has a derivative 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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Table of Contents

 

Oil and Gas Activities

 

Capital Spending.  Capital spending in 2009 totaled $18,184,000, consisting primarily of additions to oil and gas properties.  In November, 2008, 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 stage 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

 

The company owns approximately 70,000 gross acres located on the northern shelf of the Anadarko Basin of Oklahoma and North Texas where it also owns interests in approximately 226 gross (71 net) wells, primarily natural gas wells.  Historically, the company’s drilling has been focused on this area.  However, in recent years the company has diversified its drilling activities into other regions and has deemphasized drilling for natural gas in favor of drilling for crude oil reserves.  Continued drilling on the company’s Oklahoma and North Texas acreage is primarily dependent on natural gas prices, however, because much of the company’s acreage is held by production, the timing of drilling is not critical in terms of preserving most of the company’s acreage ownership.

 

In recent years, the company has significantly expanded both the volume and breadth of its drilling activities with new projects in central Kansas, North Dakota’s Williston Basin, and South Texas.  Compared to drilling in Oklahoma, the North Dakota and South Texas projects involve higher costs and greater risks but significantly higher per well reserve potential.  In contrast, drilling in central Kansas is less expensive than the company’s Oklahoma drilling projects while still yielding excellent economics.

 

In central Kansas, the company owns interests in approximately 140,000 gross acres and 77,000 net acres and it is continuing to expand its acreage position. At October 31, 2009, the company has participated in drilling 44 wells on its acreage, of which 43% have been successfully completed as producers.  The company is continuing to conduct an active drilling program expected to consist of two to three wells per month.  The company owns working interests in the existing prospects ranging from 12.5% to 85%. The company’s north-central 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, North Dakota Bakken, and South Texas projects, is relatively low cost, low risk, and exclusively targets oil reserves.

 

In North Dakota’s Bakken oil shale play, the company has assembled approximately 7,600 gross 5,675 net acres on the Fort Berthold Indian Reservation south and west of Parshall Field.  The acreage consist of approximately 33 drilling locations based on 640 acre spacing units and 13 locations based on 1,280 acre spacing units.  The company expects that more than one well will be drilled on many spacing units.  The project targets horizontal drilling for the Bakken and Three Forks shales.  Breakthroughs in precision horizontal drilling and multi-stage, high pressure fracture stimulations have made the Bakken shale a very active resource play which is being actively developed by a significant number of companies, including large independents and majors.  The U.S. Geological Survey recently estimated that the Bakken contains around 4.0 billion barrels of undiscovered oil.  Vertical well depths on the company’s acreage are approximately 10,000 feet and the horizontal legs are generally expected to range between 5,000 and 10,000 feet.  Drilling is complete on the first Bakken horizontal well in which the company owns an interest and the well is currently awaiting completion which has been delayed due to cold weather and is now expected to commence in February 2010.  The horizontal leg of the well is approximately 9,200 feet and will be completed in multiple stages.  Credo owns a 10% working interest.  Work is currently under way in preparation for drilling two to three additional wells on company acreage.

 

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Table of Contents

 

The South Texas project is 3-D seismic driven with well depths ranging from 10,000 to 17,000 feet. The most significant well drilled to date tested the Deep Wilcox formation on the Gemini Prospect and 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.  The company 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 sold 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, the company will have the same 11.25% carried interest in the next well as it did in the Gemini Prospect test well.  This project is highly dependent on natural gas prices and is currently on hold due to low natural gas prices.

 

The company owns the patents covering Calliope and the exclusive rights to the technology.  The company has been instrumental in developing, testing, refining, and patenting the technology.  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 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 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.  The company has proven Calliope’s economic viability and flexibility over a wide range of applications.

 

External sources of capital have not been required for the development, refinement or installation of Calliope.

 

The company currently has Calliope installed on wells located in Oklahoma and Texas which include both sandstones and limestones in Chester, Cotton Valley, Edwards, Hart, Hunton, Morrow, Nodosaria, Red Fork and Springer reservoirs.  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 5.4 billion cubic feet of gas and they now have estimated ultimate (8/8ths) Calliope reserves totaling 7.0 billion cubic feet of gas.  Ten of the Calliope wells are included in the company’s Significant Properties.

 

Calliope’s low per-unit finding and production cost have become increasingly attractive as the economics on many drilling projects have deteriorated due to lower product prices.  The company also believes that lower natural gas prices may stimulate divestitures of marginal properties by other companies, including properties that have Calliope potential.

 

On November 6, 2008 the company purchased all of the patents underlying Calliope, 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 has three primary strategies to monetize its Calliope technology.  The preferred strategy is to purchase dead and uneconomic wells from outside parties.  A second strategy involves entering into joint ventures with outside parties that already own Calliope candidate wells.  The third strategy is to drill new wells into old depleted fields and then use Calliope to recover the stranded gas.  That strategy is highly dependent on natural gas prices and is generally not viable at current natural gas prices.  The company is actively pursuing acquiring wells and joint ventures with other companies.  During fiscal 2009, a joint venture agreement for a pilot project was completed with a large independent and joint venture discussions are underway with several companies, both large and small.

 

Reserves.  Refer to Item 2, “Properties, Significant Properties, Estimated Proved Oil and Gas Reserves and Future Net Revenues”, for information regarding oil and gas reserves.

 

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Table of Contents

 

Critical Accounting Policies and Estimates

 

The preparation of financial statements in conformity with generally accepted accounting principles requires the company to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.  The company bases its estimates on historical experience and on various other assumptions it believes to be reasonable under the circumstances.  Although actual results may differ from these estimates under different assumptions or conditions, the company believes that its estimates are reasonable and that actual results will not vary significantly from the estimated amounts.  The company believes the following accounting policies and estimates are critical in the preparation of its consolidated financial statements: the carrying value of its oil and natural gas properties, the accounting for oil and natural gas reserves, and the estimate of its asset retirement obligations.

 

Derivatives.  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.

 

Oil and Gas Properties.  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.  Depreciation, depletion and amortization is a significant component of oil and natural gas properties.  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” below.

 

The capitalized costs in the full cost pool are subject to a quarterly ceiling test that limits such pooled costs to the aggregate of the present value of future net revenues attributable to proved oil and 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 considered price increases subsequent to the quarterly 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.

 

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

 

Oil and Gas Reserves.  The determination of depreciation and depletion expense as well as ceiling test write-downs related to the recorded value of the company’s oil and natural gas properties are highly dependent on the estimates of the proved oil and natural gas reserves. Oil and natural gas reserves include proved reserves that represent estimated quantities of crude oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.  There are numerous uncertainties inherent in estimating oil and natural gas reserves and their values, including many factors beyond the company’s control. Accordingly, reserve estimates are often different from the quantities of oil and natural gas ultimately recovered and the corresponding lifting costs associated with the recovery of these reserves are often different than the estimated costs.

 

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

 

One measure of the life of the company’s proved reserves can be calculated by dividing proved reserves at fiscal year end 2009 by production for fiscal year 2009.  This measure yields an average reserve life of 10.5 years.  Since this measure is an average, by definition, some of the company’s properties will have a life shorter than the average and some will have a life longer than the average.  The expected economic lives of the company’s properties may vary widely depending on, among other things, the size and quality, natural gas and oil prices, possible curtailments in consumption by purchasers, and changes in governmental regulations or taxation.  As a result, the company’s actual future net cash flows from proved reserves could be materially different from its estimates.

 

Asset Retirement Obligations.  The FASB authoritative guidance requires that the company estimate the future cost of asset retirement obligations, discount that cost to its present value, and record a corresponding asset and liability in its Consolidated Balance Sheets.  The values ultimately derived are based on many significant estimates, including future abandonment costs, inflation, useful life, and cost of capital.  The nature of these estimates requires the company to make judgments based on historical experience and future expectations.  Revisions to the estimates may be required based on such things as changes to cost estimates or the timing of future cash outlays. Any such changes that result in upward or downward revisions in the estimated obligation will result in an adjustment to the related capitalized asset and corresponding liability on a prospective basis.

 

Recent Accounting Pronouncements

 

In May 2009, the FASB issued authoritative guidance that provides general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. This topic was previously addressed only in auditing literature. This guidance is similar to the existing auditing guidance with some exceptions that are not intended to result in significant changes to practice. Entities are now required to disclose the date through which subsequent events have been evaluated, with such date being the date the financial statements were issued or available to be issued. This guidance was effective on a prospective basis for interim or annual reporting periods ending after June 15, 2009. Accordingly, the company adopted this guidance for the quarter ended July 31, 2009.  There was no impact on the company’s financial position or results of operations as a result of the adoption.

 

In April 2009, the FASB issued authoritative guidance that requires the disclosure of the fair value, together with the carrying amount, of financial instruments, regardless of whether they are recognized at fair value in the statement of financial position, for interim reporting periods of publicly traded companies as well as in annual financial statements. This guidance was effective for interim reporting periods ending after June 15, 2009, with earlier adoption permitted for periods ending after March 15, 2009. The company adopted this guidance for the quarter ended July 31, 2009. As this guidance requires only additional disclosures, there was no impact on the company’s financial position or results of operations as a result of the adoption.

 

In December 2008, the Securities and Exchange Commission (“SEC”) adopted revisions to its oil and gas disclosure requirements that are intended to align them with current practices and changes in technology. Among other things, the amendments will: replace the single-day year-end pricing assumption with a twelve-month average pricing assumption; permit the disclosure of probable and possible reserves; allow the use of certain technologies to establish reserves; require the disclosure of the qualifications of the technical person primarily responsible for preparing the reserves estimates or conducting a reserves audit; require the filing of the independent reserve

 

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engineers’ summary report; and permit the disclosure of a reserves sensitivity analysis table to illustrate the impact of different price and/or cost assumptions on reserves. These amendments are effective for registration statements filed on or after January 1, 2010, and for annual reports on Form 10-K for fiscal years ending on or after December 31, 2009 (fiscal year 2010 for the company) with early adoption prohibited. The company is currently evaluating the impact that the adoption of these amendments will have on the company’s financial position, results of operations, and disclosures.  In September 2009, the FASB issued proposed authoritative guidance to align oil and gas reserve estimation and disclosures required for accounting and reporting with the new SEC reserve disclosure requirements discussed above. The proposed guidance would be effective for December 31, 2009 reporting on a prospective basis. Comments on this exposure draft were due in October 2009, with final guidance expected to be issued soon.

 

ITEM 7A.               QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

 

The company manages exposure to commodity price fluctuations by periodically hedging a portion of estimated natural gas production through the use of derivatives, typically forward short positions in the NYMEX futures market.  At October 31, 2009 the company held open derivative contracts representing short sales positions for 420,000 MMBtus at NYMEX basis prices ranging from $4.60 to $7.27 and covering the production months of November 2009 through December 2010.  The company also held open derivative contracts representing long positions that offset the short sales.  The long position contracts are at NYMEX basis prices ranging from $4.38 to $5.83.  The open derivative contracts net to zero volume but will result in hedging gains of $179,000 as the contracts expire.

 

At October 31, 2009 the company also held basis differential hedges on 540,000 MMBtus with NYMEX vs. Panhandle Eastern Pipeline basis differentials ranging from $0.16 to $0.47 and covering the production months of November 2009 through December 2010.

 

See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Product Prices and Production” for more information on the company’s hedging activities.

 

ITEM 8.                  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

 

Index to Consolidated Financial Statements

 

Page

 

 

 

Consolidated Balance Sheets, October 31, 2009 and 2008

 

30

 

 

 

Consolidated Statements of Operations for the Three Years Ended October 31, 2009

 

31

 

 

 

Consolidated Statements of Stockholders’ Equity for the Three Years Ended October 31, 2009

 

32

 

 

 

Consolidated Statements of Cash Flows for the Three Years Ended October 31, 2009

 

33

 

 

 

Notes to Consolidated Financial Statements

 

34

 

 

 

Reports of Independent Registered Public Accounting Firms

 

50

 

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Table of Contents

 

CONSOLIDATED BALANCE SHEETS

October 31, 2009 and 2008

 

CREDO PETROLEUM CORPORATION AND SUBSIDIARIES

 

 

 

2009

 

2008

 

ASSETS

 

 

 

 

 

 

 

 

 

 

 

Current assets:

 

 

 

 

 

Cash and cash equivalents

 

$

12,348,000

 

$

22,332,000

 

Short-term investments

 

635,000

 

3,044,000

 

Receivables:

 

 

 

 

 

Trade

 

487,000

 

995,000

 

Accrued oil and gas sales

 

1,566,000

 

1,733,000

 

Derivative assets

 

104,000

 

1,745,000

 

Other current assets

 

859,000

 

205,000

 

Total current assets

 

15,999,000

 

30,054,000

 

 

 

 

 

 

 

Long-term assets:

 

 

 

 

 

Oil and gas properties, at cost, using full cost method:

 

 

 

 

 

Unevaluated oil and gas properties

 

7,363,000

 

12,280,000

 

Evaluated oil and gas properties

 

76,127,000

 

59,730,000

 

Less: accumulated depreciation, depletion and amortization of oil and gas properties

 

(53,211,000

)

(25,554,000

)

Net oil and gas properties

 

30,279,000

 

46,456,000

 

Intangible assets, net of accumulated amortization of $436,000 in 2009 and $595,000 in 2008

 

4,013,000

 

1,079,000

 

Compressor and tubular inventory to be used in development of oil and gas properties

 

1,865,000

 

2,592,000

 

Other, net

 

396,000

 

379,000

 

Total assets

 

$

52,552,000

 

$

80,560,000

 

 

 

 

 

 

 

LIABILITIES AND STOCKHOLDERS’ EQUITY

 

 

 

 

 

 

 

 

 

 

 

Current liabilities:

 

 

 

 

 

Accounts payable

 

$

407,000

 

$

3,857,000

 

Revenue distribution payable

 

653,000

 

982,000

 

Accrued compensation

 

948,000

 

198,000

 

Other accrued liabilities

 

394,000

 

733,000

 

Income taxes payable

 

55,000

 

124,000

 

Total current liabilities

 

2,457,000

 

5,894,000

 

 

 

 

 

 

 

Long-term liabilities:

 

 

 

 

 

Deferred income taxes, net

 

2,537,000

 

11,117,000

 

Asset retirement obligation

 

1,502,000

 

1,338,000

 

Total liabilities

 

6,496,000

 

18,349,000

 

 

 

 

 

 

 

Commitments:

 

 

 

 

 

 

 

 

 

Stockholders’ equity:

 

 

 

 

 

Preferred stock, no par value, 5,000,000 shares authorized, none issued

 

 

 

Common stock, $.10 par value, 20,000,000 shares authorized, 10,660,000 shares issued

 

1,066,000

 

1,066,000

 

Capital in excess of par value

 

31,472,000

 

31,352,000

 

Treasury stock, at cost, 419,000 shares in 2009, and 223,000 shares in 2008

 

(2,803,000

)

(982,000

)

Retained earnings

 

16,321,000

 

30,775,000

 

Total stockholders’ equity

 

46,056,000

 

62,211,000

 

 

 

 

 

 

 

Total liabilities and stockholders’ equity

 

$

52,552,000

 

$

80,560,000

 

 

See accompanying notes to consolidated financial statements.

 

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Table of Contents

 

CONSOLIDATED STATEMENTS OF OPERATIONS

For the Three Years Ended October 31, 2009

 

CREDO PETROLEUM CORPORATION AND SUBSIDIARIES

 

 

 

2009

 

2008

 

2007

 

 

 

 

 

 

 

 

 

Oil sales

 

$

5,953,000

 

$

5,530,000

 

$

3,121,000

 

Gas sales

 

4,114,000

 

11,815,000

 

11,144,000

 

 

 

10,067,000

 

17,345,000

 

14,265,000

 

 

 

 

 

 

 

 

 

Costs and expenses:

 

 

 

 

 

 

 

Oil and gas production

 

3,260,000

 

3,861,000

 

3,375,000

 

Depreciation, depletion and amortization

 

4,439,000

 

3,583,000

 

3,666,000

 

Write-down of oil and natural gas properties (Note 3) and impairment of long lived assets (Note 8)

 

24,653,000

 

 

 

General and administrative

 

3,250,000

 

1,637,000

 

1,397,000

 

 

 

 

 

 

 

 

 

 

 

35,602,000

 

9,081,000

 

8,438,000

 

 

 

 

 

 

 

 

 

Income(loss) from operations

 

(25,535,000

)

8,264,000

 

5,827,000

 

 

 

 

 

 

 

 

 

Other income and (expense)

 

 

 

 

 

 

 

Realized and Unrealized gains (losses) from derivative contracts

 

2,079,000

 

188,000

 

1,455,000

 

 

 

 

 

 

 

 

 

Investment and other income (loss)

 

(59,000

)

(299,000

)

793,000

 

 

 

2,020,000

 

(111,000

)

2,248,000

 

 

 

 

 

 

 

 

 

Income(loss) before income taxes

 

(23,515,000

)

8,153,000

 

8,076,000

 

Income taxes

 

9,061,000

 

(2,160,000

)

(2,315,000

)

 

 

 

 

 

 

 

 

Net income(loss)

 

$

(14,454,000

)

$

5,993,000

 

$

5,760,000

 

 

 

 

 

 

 

 

 

Earnings(loss) per share of Common Stock-Basic

 

$

(1.40

)

$

.62

 

$

.62

 

 

 

 

 

 

 

 

 

Earnings(loss) per share of Common Stock-Diluted

 

$

(1.40

)

$

.61

 

$

.61

 

 

 

 

 

 

 

 

 

Weighted average number of shares of common stock and dilutive securities:

 

 

 

 

 

 

 

 Basic

 

10,326,000

 

9,697,000

 

9,280,000

 

 

 

 

 

 

 

 

 

 Diluted

 

10,326,000

 

9,758,000

 

9,395,000

 

 

See accompanying notes to consolidated financial statements.

 

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CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

For the Three Years Ended October 31, 2009

 

CREDO PETROLEUM CORPORATION AND SUBSIDIARIES

 

 

 

 

 

 

 

Capital In

 

 

 

 

 

Total

 

 

 

Common Stock

 

Excess Of

 

Treasury

 

Retained

 

Stockholders’

 

 

 

Shares

 

Amount

 

Par Value

 

Stock

 

Earnings

 

Equity

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Balance, October 31, 2006

 

9,510,000

 

$

951,000

 

$

14,794,000

 

$

 

$

19,022,000

 

$

34,767,000

 

Comprehensive income (loss):

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income

 

 

 

 

 

5,760,000

 

5,760,000

 

Purchase of treasury stock

 

 

 

 

(506,000

)

 

(506,000

)

Exercise of common stock options

 

 

 

368,000

 

 

 

368,000

 

Compensation expense related to stock options

 

 

 

153,000

 

 

 

153,000

 

Tax benefit from exercise of stock options

 

 

 

598,000

 

 

 

598,000

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Balance, October 31, 2007

 

9,510,000

 

951,000

 

15,913,000

 

(506,000

)

24,782,000

 

41,140,000

 

Comprehensive income (loss):

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income

 

 

 

 

 

5,993,000

 

5,993,000

 

Sale of common stock

 

1,150,000

 

115,000

 

16,560,000

 

 

 

16,675,000

 

Payment of transactions costs

 

 

 

(1,580,000

)

 

 

(1,580,000

)

Purchase of treasury stock

 

 

 

 

(722,000

)

 

(722,000

)

Exercise of common stock options

 

 

 

294,000

 

246,000

 

 

540,000

 

Compensation expense related to stock options

 

 

 

68,000

 

 

 

68,000

 

Tax benefit from exercise of stock options

 

 

 

97,000

 

 

 

97,000

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Balance, October 31, 2008

 

10,660,000

 

1,066,000

 

31,352,000

 

(982,000

)

30,775,000

 

62,211,000

 

Comprehensive income(loss):

 

 

 

 

 

 

 

 

 

 

 

 

 

Net (loss)

 

 

 

 

 

(14,454,000

)

(14,454,000

)

Purchase of treasury stock

 

 

 

 

 

(1,821,000

)

 

(1,821,000

)

Compensation expense related to stock options

 

 

 

31,000

 

 

 

31,000

 

Tax benefit from exercise of stock options

 

 

 

89,000

 

 

 

89,000

 

Balance, October 31, 2009

 

10,660,000

 

$

1,066,000

 

$

31,472,000

 

$

(2,803,000

)

$

16,321,000

 

$

46,056,000

 

 

See accompanying notes to consolidated financial statements.

 

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CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Three Years Ended October 31, 2009

 

CREDO PETROLEUM CORPORATION AND SUBSIDIARIES

 

 

 

2009

 

2008

 

2007

 

 

 

 

 

 

 

 

 

Cash flows from operating activities:

 

 

 

 

 

 

 

Net income(loss)

 

$

(14,454,000

)

$

5,993,000

 

$

5,760,000

 

Adjustments to reconcile net income (loss) to net cash provided by operating activities:

 

 

 

 

 

 

 

Non-cash write-down of oil and natural gas properties and impairment of long lived assets

 

24,653,000

 

 

 

Depreciation, depletion and amortization

 

4,439,000

 

3,583,000

 

3,666,000

 

ARO liability accretion

 

77,000

 

51,000

 

36,000

 

Unrealized (gains) losses from derivatives

 

1,641,000

 

(1,301,000

)

454,000

 

Deferred income taxes

 

(8,580,000

)

1,913,000

 

1,763,000

 

(Gain)loss on short-term investments

 

180,000

 

618,000

 

(603,000

)

Compensation expense related to stock options granted

 

31,000

 

68,000

 

153,000