Table of Contents

 

 

 

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, 2010

 

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, 2010, the end of the registrant’s most recently completed second quarter was $70,031,000.

 

As of January 4, 2011, the registrant had 10,043,000 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 7, 2011 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 12 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;

·      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

15

 

Productive Wells and Developed Acreage

15

 

Undeveloped Acreage

16

 

Drilling

16

 

Insurance

17

 

Facilities and Employees

17

 

Company Website

17

Item 3.

Legal Proceedings

17

Item 4.

Submission of Matters to a Vote of Security Holders

17

 

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

21

Item 7.

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

22

Item 7A.

Quantitative and Qualitative Disclosures about Market Risk

29

Item 8.

Financial Statements and Supplementary Data

30

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

54

Item 11.

Executive Compensation

54

Item 12.

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

54

Item 13.

Certain Relationships and Related Transactions and Director Independence

54

Item 14.

Principal Accounting Fees and Services

54

 

 

 

PART IV

 

 

 

Item 15.

Exhibits and Financial Statement Schedules

54

 

 

 

Signatures

 

56

 

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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.

 

Historically, the company’s core drilling region was the northern shelf of the Anadarko Basin in Oklahoma where it explored primarily for natural gas.  As a result, the company’s reserves have historically been comprised mostly 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 conventional exploration projects in central and western Kansas and Nebraska, and new horizontal exploration prospects in the North Dakota Bakken and the Texas Panhandle.  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. Depending on natural gas prices, the company will continue generating prospects and drilling on its core natural gas-prone acreage in Oklahoma, concentrating on medium depth properties.

 

Compared to conventional drilling, the horizontal drilling projects in the North Dakota Bakken and the Texas Panhandle involve higher costs but have significantly higher per well reserve potential.

 

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

 

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The company acts as “operator” of approximately 102 wells pursuant to standard industry operating agreements. The company owns working interests in about 305 producing wells and overriding royalty interests in about 1,200 wells.

 

Refer to Item 2., “Properties” and to “Drilling” in MD&A, for more information regarding the company’s properties, its drilling projects, 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, speculation, 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. Oil prices have since recovered to the $85 to $90 per barrel range.  Oil production is generally sold to crude oil purchasing companies under one year contracts 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.

 

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 significantly increasing due to horizontal 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, $3.50 in October 2009, and $3.55 in October 2010.  The company 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 and hedges a portion of its estimated oil production generally in the form of costless collars.

 

Information concerning the company’s major customers is included in Note (12) 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 2011.  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 25 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 its current production rates, the company must add new oil and natural gas reserves to replace those being depleted by production. Competition within the oil and natural gas industry is intense and many of the company’s competitors have financial and other resources substantially greater than those available to the company. This could place the company at a disadvantage with respect to accessing opportunities to maintain, or increase, its oil and natural gas reserve base.

 

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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.

 

In the event the company does not meet its plan for future Calliope installations, it may be required to record an impairment of the asset.

 

The patents underlying the Calliope Gas Recovery System are carried as a non-current asset on the company’s balance sheet and are being amortized over the average remaining life of the patents. The company periodically evaluates this asset for realizability.

 

The company believes that the number of future installations will be sufficient to demonstrate recoverability of the cost.  Due to various factors, there have been no recent Calliope installations.  If the Company is unable to achieve the expected level of installations, the company may in the future be required to record an impairment of the asset.  Should this event occur, it would be a non-cash charge to income and would have no effect on working capital.

 

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.

 

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As of October 31, 2010, approximately 29% 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.

 

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 is also required to base the PV-10 on average prices on the first day of each of the preceding twelve months and costs as of the date of the reserve estimate.  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.

 

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.  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 65 properties which represent 23% 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 15% of these significant properties and 15% of the discounted reserve value of such properties.  Reserves added during 2010 comprise 9% of these significant properties and 6% 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

 

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wells with limited production histories and properties with proved undeveloped or proved non-producing reserves. In addition, Calliope is generally installed on mature wells.  As such, they contain older down-hole equipment that is more subject to failure than new equipment.  The failure of such equipment, particularly casing, can result in complete loss of a well.

 

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

 

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

 

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 oil and natural gas, the company periodically enters into derivative hedging transactions for a portion of its estimated production.  These transactions may limit the company’s potential gains if product 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 product 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 natural gas derivatives are generally based on NYMEX prices but the company’s hedged natural gas production is primarily sold on a regional pipeline index price.  The regional price is currently 5% below NYMEX prices.  Regional weather conditions and other economic factors can frequently result in substantially higher basis differentials.  Oil derivatives generally are in the form of costless collars.

 

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

 

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the company’s results of operations and financial condition.  Also, the company may not be able to obtain the right to drill in areas where it believes there is significant potential for the company.

 

The company has recently expanded the volume and breadth of its exploration program with new drilling projects in North Dakota, Kansas, the Texas Panhandle and Nebraska.  Compared to the company’s conventional drilling, the Texas Panhandle and North Dakota horizontal drilling projects are substantially more expensive.

 

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 primarily located on the northern shelf of the Anadarko Basin of Oklahoma, 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 natural gas-prone area.  Future drilling on the Oklahoma 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 North Dakota’s Bakken, the Texas Panhandle, Kansas and Nebraska.  Compared to conventional drilling, the North Dakota and Texas Panhandle horizontal drilling projects involve higher costs but significantly higher per well reserve potential.  Conventional drilling in Kansas and Nebraska is less expensive than in Oklahoma.  The company believes that all of the projects have excellent economic potential.

 

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In Kansas and Nebraska, the company owns interests in approximately 147,000 gross acres (85,000 net) acres and it is continuing to expand its acreage position. At October 31, 2010, the company has participated in drilling 69 wells on its acreage, of which over 40% 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 with working interests ranging from 12.5% to 95%.  The company’s Kansas and Nebraska drilling activities provide scientific diversification to the company’s drilling program  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 other projects, is relatively low cost, low risk, and exclusively targets oil reserves.

 

In 2009, the Kansas project yielded a significant oil discovery, known as the Huslig Field, in which the company owns an 85% working interest.  Huslig Field production peaked at 365 barrels of oil per day, net to Credo, which drove the 108% increase in 2009 oil production compared to 2008.

 

In North Dakota’s Bakken oil resource play, the company has assembled approximately 8,000 gross (6,000 net) acres in the core of the play which are located primarily on the Fort Berthold Reservation, south and west of the Parshall Field.  The acreage consists of approximately 50 initial well 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 Sanish/Three Forks formations. 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. The company’s interests range from very small to 56% depending on the size of the spacing unit.

 

To date, five wells have been drilled on the company’s acreage.  Three of the wells are producing and two are awaiting completion for production.

 

Several years ago, the U.S. Geological Survey estimated that the Bakken contains around 4.0 billion barrels of undiscovered oil.  Since that time, reserve estimates for the play have been increasing steadily as technology improves.  The North Dakota Department of Mineral Resources recently indicated that the North Dakota portion of the Bakken and Sanish/Three Forks plays could reasonably contain 11 billion barrels of recoverable oil.

 

The company anticipates drilling at least nine wells on its Bakken acreage during 2011.

 

In the Texas Panhandle, the company owns an average 33% working interest in about 3,000 gross acres located in Lipscomb and Hemphill counties.  The company operates twelve vertical wells within the area and has recently drilled its first horizontal well which was completed in the Tonkawa formation.  The 7,600-foot vertical well has an approximate 5,000-foot lateral and is expected to primarily produce oil.  The area contains producing wells completed in the Morrow, Tonkawa and Cleveland formations.

 

The company owns the patents covering Calliope, together with 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 many wells that meet its general criteria for Calliope candidate wells and thousands more that will meet the 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.

 

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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 on 14 non-experimental wells, they were collectively at their economic limit and had no significant remaining reserves.  Since Calliope was installed, the wells have produced 5.7 billion cubic feet of gas and they now have estimated ultimate (8/8ths) Calliope reserves totaling 12.1 billion cubic feet of gas.  Nine 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.

 

In November 2008, the company purchased all of the patents underlying Calliope, all related third party interests in future installations, and the 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.

 

For additional information on the company’s North Dakota Bakken and other drilling activities, see Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations—Drilling Activities, on Page 27.

 

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

 

The company’s reserves, and reserve values, are concentrated in 65 properties (“Significant Properties”). Some of the Significant Properties are individual wells and others are multi-well properties.  At year-end, Significant Properties represent 23% 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 15% of the Significant Properties and represent 15% of the discounted reserve value of such properties.  Reserves added in 2010 comprise 9% of the Significant Properties and represent 6% of the discounted value of such properties.

 

The Securities and Exchange Commission (“SEC”) adopted amendments designed to modernize the SEC oil and gas company reserves reporting requirements, effective for our company as of the quarter ended October 31, 2010. The most significant amendments to the requirements included the following:

 

·                  Commodity Prices-Economic producibility of reserves and discounted cash flows are now based on the average of the commodity spot price on the first day of each of the twelve preceding months unless contractual arrangements designate the price to be used.

 

·                  Disclosure of Unproved ReservesCProbable and possible reserves may be disclosed separately on a voluntary basis.

 

·                  Proved Undeveloped Reserve GuidelinesCReserves may be classified as proved undeveloped if there is a high degree of confidence that the quantities will be recovered and the well from which the reserves are to be recovered is scheduled to be drilled within the next five years, unless the specific circumstances justify a longer time.

 

·                  Reserves Estimation Using New TechnologiesCReserves may be estimated through the use of reliable technology in addition to flow tests and production history.

 

·                  Reserves Personnel and Estimation ProcessCAdditional disclosure is required regarding the qualifications of the chief technical person who oversees the reserves estimation process. We are also required to provide a general discussion of our internal controls used to assure the

 

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Table of Contents

 

objectivity of the reserves estimate.

 

·                  Non-Traditional ResourcesCThe definition of oil and gas producing activities has expanded and focuses on the marketable product rather than the method of extraction.

 

We adopted the rules effective for our quarter and year ended October 31, 2010, as required by the SEC.

 

All of Credo’s reserves are located within the continental United States. LaRoche Petroleum Engineers, LLC (LaRoche), our independent petroleum engineering consulting firm, prepared the company’s estimated reserves as of October 31, 2010, 2009 and 2008. The company did not place any limitations on LaRoche in the conduct of determining their estimates of the company’s reserves.  We are not aware of any assumptions provided by management that were relied upon by LaRoche without testing.

 

Our year-end reserve report is prepared by LaRoche based upon a review of property interests being appraised, production from such properties, current costs of operation and development, current prices for production, agreements relating to current and future operations and sale of production, geosciences and engineering data, and other information we provide to them.  This information is reviewed by knowledgeable members of our company to ensure accuracy and completeness of the data prior to submission to LaRoche. Upon analysis and evaluation of data provided, LaRoche issues a preliminary appraisal report of our reserves.  The preliminary appraisal report and changes in our reserves are reviewed by our Engineering Manager and our President for completeness of the data presented and reasonableness of the results obtained.  Once any questions have been addressed, LaRoche issues the final appraisal report, reflecting their conclusions.

 

Engineering Manager, Kenneth J. DeFehr, is a Registered Professional Engineer with 36 years of experience in the oil and gas industry.  Mr. DeFehr received a Masters Degree in Civil Engineering from Texas A&M University in 1973, and began his petroleum engineering career with Phillips Petroleum from 1974 to 1982, where he worked in the Mid-Continent, Rockies, North Sea, and R&D.  Mr. DeFehr served as Senior Petroleum Engineer for Axem Resources in Denver from 1982 to 1990, and has served as Engineering Manager for Credo Petroleum since 1990.  During his career, Mr. DeFehr has been involved in exploration, property acquisitions, waterflooding, operations, and reserve evaluations.

 

A letter which identifies the professional qualifications of the individual at LaRoche who was responsible for overseeing the preparation of our reserve estimates as of October 31, 2010 has been filed as an addendum to Exhibit 99.1 to this report.

 

A variety of methodologies are used to determine our proved reserve estimates.  The principal methodologies employed are reservoir simulation, decline curve analysis, volumetric, material balance, advance production type curve matching, petro-physics/log analysis and analogy.  Some combination of these methods is used to determine reserve estimates in substantially all of our fields.

 

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 (12) to the Consolidated Financial Statements where additional reserve information is provided.  The average price used to calculate estimated future net revenues was $68.30, $69.24, and $62.25 per barrel of oil and $4.49, $4.49, and $3.50 per Mcf of gas as of October 31, 2010, 2009, and 2008, respectively.  Amounts do not include estimates of future Federal and state income taxes.

 

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Table of Contents

 

 

 

 

 

 

 

 

 

Estimated Future

 

 

 

Oil

 

Gas

 

Estimated Future

 

Net Revenues

 

Year

 

(bbls)*

 

(Mcf)*

 

Net Revenues

 

Discounted at 10%

 

 

 

 

 

 

 

 

 

 

 

2010

 

954,000

 

13,938,000

 

$

69,865,000

 

$

38,730,000

 

2009

 

876,000

 

14,940,000

 

$

71,863,000

 

$

40,434,000

 

2008

 

710,000

 

15,525,000

 

$

53,655,000

 

$

32,330,000

 

 


*     The percentage of total reserves classified as proved developed was approximately 71% in 2010, 61% in 2009, and 67% in 2008.

 

Oil reserves increased 9% and currently account for 29% of the company’s total proved reserves.  No gas wells were drilled in 2010 resulting in a 7% decline in gas reserves.  The decline in gas reserves more than offset the 9% increase in oil reserves and resulted in a 3% decrease in total reserves, based on the industry standard six Mcf of gas to one barrel of oil conversion rate.  Had the company not experienced completion timing delays on new wells in the North Dakota Bakken and Texas Panhandle, additional reserves would have been booked from those projects.  Total reserves at October 31, 2010 were 3,277,000 barrels of oil equivalent, compared to 3,366,000 last year.

 

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 12 to the company’s Consolidated Financial Statements.

 

 

 

Year Ended October 31,

 

 

 

2010

 

2009

 

2008

 

Estimated future net revenues discounted at 10%

 

$

38,730,000

 

$

40,434,000

*

$

32,330,000

*

 

 

 

 

 

 

 

 

Future income tax expense

 

(14,898,000

)

(15,119,000

)

(9,119,000

)

 

 

 

 

 

 

 

 

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

 

7,098,000

 

7,285,000

 

4,408,000

 

 

 

 

 

 

 

 

 

Standardized measure of discounted future net cash flows

 

$

30,930,000

 

$

32,600,000

 

$

27,619,000

 

 

Production, Average Sales Prices and Average Production Costs

 

See Item 7 “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS” “Product Prices and Production”

 

Productive Wells and Developed Acreage

 

Developed acreage at October 31, 2010 totaled 22,000 net and 81,000 gross acres.  At October 31, 2010, the company owned working interests in 74 net (305 gross) wells consisting of 52 net (224 gross) natural gas wells and 22 net (81 gross) oil wells.  In addition, the company owned royalty and production payment interests in approximately 1,200 wells, primarily coal bed methane, located in Wyoming.  In 2010, no wells were acquired, and 38 were sold or abandoned.

 

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Table of Contents

 

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

 

Working

 

Royalty

 

Year Ending

 

Interest Acreage

 

Interest Acreage

 

October 31,

 

Gross

 

Net

 

Gross

 

Net

 

2011

 

91,600

 

53,700

 

 

 

2012

 

23,000

 

14,300

 

 

 

2013

 

18,100

 

15,800

 

 

 

2014

 

6,300

 

4,600

 

 

 

2015

 

12,300

 

11,300

 

 

 

Thereafter

 

3,300

 

1,400

 

3,700

 

500

 

Held-By-Production

 

19,400

 

4,500

 

148,100

 

7,900

 

 

 

 

 

 

 

 

 

 

 

Total

 

174,000

 

105,600

 

151,800

 

8,400

 

 

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2010*

 

34

 

15

 

4

 

15

 

 

 

 

2009

 

25

 

7

 

2

 

12

 

1

 

2

 

1

 

2008

 

32

 

12

 

9

 

11

 

 

 

 

 


*     Of the gross wells drilled in 2010, 1 of the oil wells, 1 of the gas wells and 3 of the dry holes were operated by the company.  The remaining wells represent company participations in wells operated by others.

 

Net Wells

 

Year Ended

 

Total Net

 

Exploratory

 

Development

 

October 31,

 

Wells

 

Oil

 

Gas

 

Dry

 

Oil

 

Gas

 

Dry

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2010*

 

10.572

 

3.097

 

1.009

 

6.466

 

 

 

 

2009

 

12.089

 

3.007

 

0.131

 

7.109

 

0.168

 

1.230

 

0.444

 

2008

 

6.581

 

1.874

 

1.886

 

2.821

 

 

 

 

 


*     Of the net wells drilled in 2010, 0.500 of the oil wells, 0.840 gas wells and 2.342 dry holes were operated by the company.  The remaining wells represent company participations in wells operated by others.

 

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Table of Contents

 

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, limited equipment 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 that expires in April 2011. Subsequent to October 31, 2010, the company extended its office space lease until April 2016.

 

As of October 31, 2010, the company had 14 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.  The company was named in a defendant in a lawsuit alleging breach of contract and other issues.  The suit was settled on August 11, 2010 at a cost of $25,000 to Credo.

 

The company has 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.                REMOVED AND RESERVED.

 

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.

 

 

 

2010

 

2009

 

Quarter Ended

 

High

 

Low

 

High

 

Low

 

January 31

 

$

10.52

 

$

8.70

 

$

10.21

 

$

7.86

 

April 30

 

$

10.47

 

$

8.40

 

$

9.53

 

$

6.73

 

July 31

 

$

9.91

 

$

7.13

 

$

12.87

 

$

8.08

 

October 31

 

$

8.63

 

$

7.67

 

$

12.90

 

$

9.72

 

 

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At January 4, 2011, the company had 2,239 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 fiscal year 2010, the company repurchased 231,995 shares of its common stock on the open market at a weighted average price of $8.91.  The purchases were made pursuant to a stock repurchase plan announced on September 24, 2008 and extended by the Board of Directors on April 9, 2009 and July 29, 2010.  The extended plan authorized repurchases up to $5,000,000, but could be expanded, suspended or discontinued at any time.  At October 31, 2010, the company has repurchased 527,429 shares of common stock at an average price per share of $8.74.  Subsequent to October 31, 2010, and through January 13, 2011, the company has repurchased 18,000 shares, bringing the total shares repurchased to 545,429 at an average price per share of $8.72.

 

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

 

November 1 – 30, 2009

 

40,937

 

$

10.19

 

40,937

 

$

1,039,000

 

December 1 – 31, 2009

 

 

$

 

 

$

1,039,000

 

January 1 – 31, 2010

 

26,520

 

$

9.38

 

26,520

 

$

790,000

 

February 1 – 28, 2010

 

23,800

 

$

8.87

 

23,800

 

$

579,000

 

March 1-31, 2010

 

7,800

 

$

9.73

 

7,800

 

$

503,000

 

April 1 – 30, 2010

 

16,378

 

$

9.84

 

16,378

 

$

342,000

 

May 1 – 30, 2010

 

18,600

 

$

9.24

 

18,600

 

$

170,000

 

June 1 – 30, 2010

 

21,167

 

$

8.02

 

21,167

 

$

 

July 1 – 31, 2010

 

24,000

 

$

7.59

 

24,000

 

$

818,000

 

August 1 - 31, 2010

 

13,827

 

$

7.87

 

13,827

 

$

709,000

 

September 1 - 30, 2010

 

26,566

 

$

8.25

 

26,566

 

$

490,000

 

October 1 - 31, 2010

 

12,400

 

$

8.07

 

12,400

 

$

390,000

 

 

 

 

 

 

 

 

 

 

 

Total

 

527,429

 

$

8.72

 

527,429

 

$

390,000

 

 

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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, 2010 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.

COMPARISON OF 5 YEAR CUMULATIVE TOTAL RETURN*

Among CREDO Petroleum Corporation, the S&P 500 Index

and the S&P SmallCap 600 Oil & Gas Exploration & Production Index

 

 

*$100 invested on 10/31/05 in stock or index, including reinvestment of dividends.

Fiscal year ending October 31.

 

Copyright©2010 S&P, a division of The McGraw-Hill Companies Inc. All rights reserved.

 

 

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Table of Contents

 

COMPARISON OF 10 YEAR CUMULATIVE TOTAL RETURN*

Among CREDO Petroleum Corporation, the S&P 500 Index

and the S&P SmallCap 600 Oil & Gas Exploration & Production Index

 

 

*$100 invested on 10/31/00 in stock or index, including reinvestment of dividends.

Fiscal year ending October 31.

 

Copyright©2010 S&P, a division of The McGraw-Hill Companies Inc. All rights reserved.

 

 

The information in this Annual Report on Form 10-K appearing under the heading “Stock Performance Graph” is being furnished pursuant to Item 201(e) of Regulation S-K and shall not be deemed to be “soliciting material” or “filed” with the SEC or subject to Regulation 14A or 14C, other than as provided in Item 201(e) of Regulation S-K, or to the liabilities of Section 18 of the Securities Exchange Act of 1934, as amended.

 

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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, 2010 were derived from the audited financial statements and the accompanying notes to those financial statements.

 

 

 

Years Ended October 31,

 

 

 

2010

 

2009

 

2008

 

2007

 

2006

 

Audited Financial Information

 

 

 

 

 

 

 

 

 

 

 

Statement of Operations Data:

 

 

 

 

 

 

 

 

 

 

 

Oil and gas sales

 

$

11,566,000

 

$

10,067,000

 

$

17,345,000

 

$

14,265,000

 

$

16,103,000

 

Oil and gas production expense

 

3,192,000

 

3,260,000

 

3,861,000

 

3,375,000

 

3,407,000

 

Depreciation, depletion and amortization

 

3,602,000

 

4,439,000

 

3,583,000

 

3,666,000

 

3,642,000

 

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

 

 

24,653,000

 

 

 

 

General and administrative

 

2,107,000

 

3,250,000

 

1,637,000

 

1,397,000

 

1,291,000

 

Income(loss) from operations

 

2,665,000

 

(25,535,000

)

8,264,000

 

5,827,000

 

7,763,000

 

Realized and Unrealized gains(losses) from derivative contracts

 

42,000

 

2,079,000

 

188,000

 

1,455,000

 

1,061,000

 

Income(loss) before income taxes

 

2,815,000

 

(23,515,000

)

8,153,000

 

8,075,000

 

9,436,000

 

Net income(loss)

 

2,203,000

 

(14,454,000

)

5,993,000

 

5,760,000

 

6,836,000

 

Earnings(loss) per share:

 

 

 

 

 

 

 

 

 

 

 

Basic

 

$

0.22

 

$

(1.40

)

$

0.62

 

$

0.62

 

$

0.74

 

Diluted

 

$

0.22

 

$

(1.40

)

$

0.61

 

$

0.61

 

$

0.72

 

Weighted-average shares outstanding(1):

 

 

 

 

 

 

 

 

 

 

 

Basic

 

10,183,000

 

10,326,000

 

9,697,000

 

9,280,000

 

9,207,000

 

Diluted

 

10,202,000

 

10,326,000

 

9,758,000

 

9,395,000

 

9,482,000

 

 

 

 

 

 

 

 

 

 

 

 

 

Balance Sheet Data:

 

 

 

 

 

 

 

 

 

 

 

Working capital

 

9,661,000

 

13,542,000

 

24,160,000

 

12,511,000

 

10,073,000

 

Total assets

 

53,405,000

 

52,552,000

 

80,650,000

 

55,349,000

 

47,759,000

 

Long-term obligations:

 

 

 

 

 

 

 

 

 

 

 

Deferred income taxes-net

 

3,281,000

 

2,537,000

 

11,117,000

 

9,204,000

 

8,039,000

 

Asset retirement obligation

 

1,132,000

 

1,502,000

 

1,338,000

 

1,016,000

 

954,000

 

Exclusive license agreement obligation

 

 

 

 

85,000

 

163,000

 

Stockholders’ equity

 

46,567,000

 

46,056,000

 

62,211,000

 

41,140,000

 

34,767,000

 

 

 

 

 

 

 

 

 

 

 

 

 

Unaudited Operating Data

 

 

 

 

 

 

 

 

 

 

 

Production Volumes:

 

 

 

 

 

 

 

 

 

 

 

Oil (Bbls)

 

97,000

 

116,000

 

56,000

 

51,000

 

41,000

 

Gas (Mcf)

 

1,038,000

 

1,229,000

 

1,545,000

 

1,926,000

 

2,176,000

 

BOE

 

270,000

 

321,000

 

314,000

 

372,000

 

404,000

 

Avg. sales price before realized derivative gains & losses:

 

 

 

 

 

 

 

 

 

 

 

Per Bbls

 

$

70.88

 

$

51.46

 

$

99.28

 

$

60.95

 

$

61.14

 

Per Mcf

 

$

4.54

 

$

3.35

 

$

7.65

 

$

5.79

 

$

6.24

 

Reserves((1)

 

 

 

 

 

 

 

 

 

 

 

Oil (Bbls)

 

954,000

 

876,000

 

710,000

 

591,000

 

422,000

 

Gas (Mcf)

 

13,938,000

 

14,940,000

 

15,525,000

 

16,973,000

 

16,005,000

 

BOE

 

3,277,000

 

3,366,000

 

3,297,000

 

3,420,000

 

3,090,000

 

Estimated future net revenues

 

$

69,865,000

 

$

71,863,000

 

$

53,655,000

 

$

101,501,000

 

$

84,861,000

 

Estimated future net revenues discounted at 10%

 

$

38,730,000

 

$

40,434,000

 

$

32,330,000

 

$

62,071,000

 

$

52,328,000

 

 


(1) See Footnote 12 to the Consolidated Financial Statements.

 

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ITEM 7.                                                MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

 

Operations

 

Summary — During 2009 and 2010 the company’s operations focused on oil drilling in central and western Kansas and in the North Dakota Bakken oil resource play. In 2011 the company will expand its drilling operations into southwestern Nebraska and into oil-rich zones in the Texas Panhandle such as the Tonkawa and Cleveland.  These zones have become prime horizontal drilling targets.

 

These activities are discussed in greater detail below.

 

The company believes that its geographically diverse drilling projects provide an excellent 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 each of the drilling projects.  Drilling economics are dependent on both the timing of drilling and on the drilling success rate.

 

The company will continue to actively pursue adding reserves through its drilling projects in fiscal 2011, 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, fracture stimulation equipment and related services, as well as access to wells for application of the company’s Calliope Gas Recovery System.  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 2010, oil and gas revenues increased 15% to $11,566,000 compared to $10,067,000 in 2009.  The increase was due to a 38% increase in oil prices and a 37% increase in natural gas prices.  As the oil and gas price/volume table on page 25 shows, oil prices increased to $70.88 per barrel and natural gas sales prices increased to $4.54 per Mcf.  The net effect of these price changes was to increase total oil and gas sales by $3,710,000. Realized derivative gains were $115,000 in 2010 compared to $3,720,000 in 2009.  Unrealized derivative losses were $73,000 in 2010 compared to unrealized losses of $1,641,000 in 2009.  During the same period, the company’s total production decreased 16% to 270,000 BOE, resulting in a decrease in oil and gas sales of $2,211,000.  The decline in 2010 oil production resulted because of delays caused by shortages of fracture stimulation equipment for horizontal wells in the North Dakota Bakken and the Texas Panhandle.  The situation was exacerbated by the expected flush production decline on the Huslig Field discovery which peaked last year at about 365 barrels of oil per day, net to Credo.  In addition, the company did not drill any gas wells during 2010 due to low natural gas prices.  Investment and other income increased primarily due to the impact of market place improvements on the company’s investments.

 

In 2010, total costs and expenses, excluding the impairment loss of $24,653,000 in 2009, decreased 19% to $8,901,000 compared to $10,949,000 in 2009.  Oil and gas production expenses decreased 2% due primarily to decreased field level service costs.  General and administrative expenses decreased $1,143,000 to $2,107,000 primarily due to decreased salaries and benefits and lower legal and professional fees.

 

The effective income tax rate was 22% and 38.5% for the 2010 and 2009 periods, respectively.  The variation from the statutory rate in 2010 is primarily due to percentage depletion.

 

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.  As the oil and gas price/volume table on page 24 shows, oil prices decreased to $51.46 per barrel and total natural gas prices decreased to $3.35 per Mcf.  The net effect of these price realization changes was to decrease total oil and gas sales by $9,305,000.  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

 

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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.

 

Liquidity and Capital Resources

 

At October 31, 2010, working capital decreased to $9,661,000, compared to $13,542,000 at October 31, 2009, primarily due to capital expenditures for oil and gas activities.  For the year-ended October 31, 2010, net cash provided by operating activities was $4,533,000 compared to $9,932,000 for the same period in 2009.  The difference is primarily due to the sale of $2,229,000 of short term investments in 2009 and the purchase of $1,500,000 in short term investments in 2010.  During 2009 and 2010, the company liquidated the majority of its short term investments in professionally managed limited partnerships.  Other short term investments are directly invested in certificates of deposit and mutual funds.  Investing activities primarily included oil and gas exploration and development expenditures, including Calliope, totaling $8,671,000 and $11,480,000 in 2010 and 2009, respectively.  Financing activities primarily included the purchase of treasury stock of $2,066,000 and $1,821,000 in 2010 and 2009

 

The company’s earnings before interest, taxes, depreciation, depletion and amortization and write-downs of oil and gas properties and impairment losses (“EBITDA”) was $6,417,000 for the year ended October 31, 2010 and $5,580,000 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:

 

 

 

For The Year Ended October 31,

 

 

 

2010

 

2009

 

2008

 

RECONCILIATION OF EBITDA:

 

 

 

 

 

 

 

Net Income (Loss)

 

$

2,203,000

 

$

(14,454,000

)

$

5,993,000

 

Add Back(Deduct):

 

 

 

 

 

 

 

Interest Expense

 

 

3,000

 

8,000

 

Income Tax Expense (Benefit)

 

612,000

 

(9,061,000

)

2,160,000

 

Depreciation, Depletion and Amortization Expense

 

3,602,000

 

4,439,000

 

3,583,000

 

 

 

 

 

 

 

 

 

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

 

 

24,653,000

 

 

EBITDA

 

$

6,417,000

 

$

5,580,000

 

$

11,744,000

 

 

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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, 2010, 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, 2010, 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

 

20,000

 

20,000

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total

 

$

20,000

 

$

20,000

 

$

 

$

 

$

 

 

Off-Balance Sheet Arrangements

 

The company has no off-balance sheet arrangements at October 31, 2010.

 

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 years ended October 31, 2010, 2009 and 2008 are set forth below.  Prices shown are market price and do not include realized hedging gains and losses.

 

 

 

Twelve Months Ended October 31,

 

 

 

2010 Wellhead

 

2009 Wellhead

 

2008 Wellhead

 

Product

 

Volume

 

Price

 

Volume

 

Price

 

Volume

 

Price

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil (bbls)

 

96,700

 

$

70.88

 

115,700

 

$

51.46

 

56,000

 

$

99.28

 

Gas (Mcf)

 

1,038,000

 

$

4.54

 

1,229,000

 

$

3.35

 

1,545,000

 

$

7.65

 

BOE (Barrels of Oil Equivalent)

 

269,700

 

$

42.89

 

320,500

 

$

31.41

 

313,500

 

$

55.33

 

 

The decline in 2010 oil production resulted because of delays caused by shortages of fracture stimulation equipment for horizontal wells in the North Dakota Bakken and the Texas Panhandle.  The situation was exacerbated by the expected flush production decline on the Huslig Field discovery which peaked last year at about 365 barrels of oil per day, net to Credo.  The flush production from the Huslig field drove a 108% increase in 2009 oil production over 2008 levels.  The expected decline in flush production from the Huslig Field contributed to a 7% decrease in oil production this year.  The company did not drill any gas wells in 2010 due to low natural gas prices, resulting in lower gas production in 2010.

 

The effect of realized derivative gains and losses and market prices on total price realizations are reflected in the following table:

 

 

 

Twelve Months Ended October 31,

 

 

 

2010

 

2009

 

2008

 

 

 

Net

 

Realized

 

Effective

 

Net

 

Realized

 

Effective

 

Net

 

Realized

 

Effective

 

 

 

Wellhead

 

Derivative

 

Price

 

Wellhead

 

Derivative

 

Price

 

Wellhead

 

Derivative

 

Price

 

Product

 

Price

 

Gain

 

Realization

 

Price

 

Gain

 

Realization

 

Price

 

Gain

 

Realization

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil

 

$

70.88

 

$

 

$

70.88

 

$

51.46

 

$

 

$

51.46

 

$

99.28

 

$

 

$

99.28

 

Gas

 

$

4.54

 

$

0.11

 

$

4.65

 

$

3.35

 

$

3.02

 

$

6.37

 

$

7.65

 

$

(0.25

)

$

7.40

 

 

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Average production costs, including production taxes, per equivalent BOE of production (using the industry standard of six Mcf of gas to one barrel of oil conversion ration) were $11.84, $10.17 and $12.32 per BOE in 2010, 2009 and 2008 respectively. Depreciation, depletion and amortization per equivalent BOE for the same periods were $11.60, $12.27 and $10.99.

 

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 production when the potential for significant downward price movement is anticipated.  These transactions typically take the form of costless collars for oil and forward short positions based upon the NYMEX futures market for natural gas, and are closed by purchasing offsetting positions. Such contracts do not exceed estimated production volumes and are authorized by the company’s Board of Directors.  Contracts are expected to be closed as related production occurs but may be closed earlier if the anticipated downward price movement occurs or if the company believes that the potential for such movement has abated.

 

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.

 

At October 31, 2010 the company held open derivative contracts representing natural gas short sales positions for 40,000 MMBtus at NYMEX basis prices ranging from $6.91 to $7.27 and covering the production months of November and December 2010.  The company closed the hedge transaction by purchasing offsetting contracts at NYMEX basis prices of $5.83.  These positions are presented net and represent an unrealized gain of $50,000 at October 31, 2010 which was realized as income subsequent to year-end. Average natural gas prices received in the company’s primary market have historically been 15%-17% below NYMEX prices due to basis differentials compared to the current differentials of about 5%.

 

At October 31, 2010 the company also held natural gas basis differential hedges on 80,000 MMBtus with NYMEX vs. Panhandle Eastern Pipeline basis differentials of $0.47 and covering the production months of November and December 2010.  These open basis differential contracts represent unrealized losses of $19,000 at October 31, 2010.

 

Subsequent to October 31, 2010, the company entered into natural gas derivative contracts for 30,000 MBTU’s for each of production months of January, February and March 2011.  These contracts are at NYMEX Basis prices of $4.35-4.52 per Mcf.

 

The company entered into costless collar derivative contracts subsequent to year-end for 5,000 barrels of oil for each production month of calendar year 2011 with a floor of $80.00 and a ceiling ranging from $90.50 to 95.00 per barrel and for 3,000 barrels of oil for each production month of calendar year 2012 with a floor of $80.00 and a ceiling ranging from $94.00 to $99.00 per barrel.

 

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 $7,200,000 with interest calculated at the prime rate.  The facility is unsecured and has covenants that require the company to maintain $3,000,000 in cash or short term investments, none of which are required to be maintained at the company’s bank, and prohibits funded debt in excess of $500,000.  The line expires May 1, 2013.

 

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Table of Contents

 

Oil and Gas Activities

 

Capital Spending. Capital spending in 2010 totaled $8,703,000, consisting of additions to oil and gas properties.  In November, 2008, the company purchased the Calliope patents and the remaining third party rights in the Calliope technology.  In addition, the company purchased the patents for its new Tractor Seal fluid lift technology together with all third party rights 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 primarily located on the northern shelf of the Anadarko Basin of Oklahoma 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 natural gas-prone area.  However, no gas wells were drilled in Oklahoma during 2010 due to low gas prices.  Future drilling on the Oklahoma 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 Kansas, Nebraska, North Dakota’s Bakken Play, and the Texas Panhandle.  Compared to drilling in Oklahoma, the North Dakota and Texas Panhandle horizontal drilling projects involve higher costs but significantly higher per well reserve potential.  Conventional drilling in Kansas and Nebraska is less expensive than in Oklahoma.

 

In Kansas and Nebraska, the company owns interests in approximately 147,000 gross acres and 85,000 net acres and it is continuing to expand its acreage position. At October 31, 2010, the company has participated in drilling 69 wells on its acreage, of which over 40% 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 with working interests ranging from 12.5% to 95%.  The company’s Kansas and Nebraska drilling activities provide scientific diversification to the company’s drilling program through the use of 3-D seismic to identify shallow oil prospects.

 

In 2009, the Kansas project yielded a significant oil discovery, known as the Huslig Field, in which the company owns an 85% working interest.  Huslig Field production peaked at 365 barrels of oil per day, net to Credo, which drove the 108% increase in 2009 oil production compared to 2008.

 

In North Dakota’s Bakken oil resource play, the company has assembled approximately 8,000 gross (6,000 net) acres in the core of the play which are located primarily on the Fort Berthold Reservation, south and west of the Parshall Field.  The acreage consists of approximately 50 initial well 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 Sanish/Three Forks formations. 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. The company’s interests range from very small to 56% depending on the size of the spacing unit.

 

To date, five wells have been drilled on the company’s acreage.  Three of the wells are producing and two are awaiting completion for production.

 

The company’s third high rate Bakken producer was recently completed.  The Petro-Hunt 3-A well was drilled on a 1,280-acre spacing unit with an approximate 10,000-foot lateral, and was fracture stimulated in 25 stages. The well flowed at a restricted rate of 1,367 barrels of oil equivalent during a 24-hour test on a small (18/64”) choke with flowing casing pressure of 3,050 psi.  While the well was drilled in fiscal 2010, the completion phase was delayed until recently due to shortages of fracture stimulation equipment. The well is located in Dunn County on the Fort Berthold Reservation about four miles southeast of the company’s Petro-Hunt 17-D well.  Credo owns an 18.75% working interest in the new well.

 

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The company’s first Bakken well (Petro-Hunt 17-D) tested at an initial rate of 1,474 barrels of oil equivalent per day (“BOEPD”) on a 20/64” choke, and has produced about 87,000 BOE in 11 months.  The well is also located in Dunn County on the southwest portion of the Fort Berthold Reservation, and appears to be one of the best wells in the area.  Credo owns a 10% working interest in the well.

 

The company’s second Bakken well (Brigham Weisz 11-14) tested at an initial rate of 2,278 BOEPD on a 48/64” choke, and has produced approximately 52,000 BOE in four months.  The well is located about 50 miles northwest of the Petro-Hunt 17-D in Williams County.  Credo owns a 6.25% working interest in the well.  Brigham’s development plans for the spacing unit could potentially include two additional Bakken wells and up to three Sanish/Three Forks wells.

 

Drilling is complete on two additional wells located on the Fort Berthold Reservation where Credo owns small interests — the Zenergy 14-23 well and the Questar MHA 1-32 well.  Both wells are currently awaiting completion for production.  Credo owns 1.56% and 3.57% in the wells, respectively.

 

The company anticipates drilling at least nine wells on its Bakken acreage during 2011.

 

In the Texas Panhandle, the company owns an average 33% working interest in about 3,000 gross acres.  The company has recently drilled its first horizontal well.  The 7,600-foot vertical depth well has an approximate 5,000-foot horizontal lateral and is expected to primarily produce oil.  Credo owns a 22% working interest in the well with Chesapeake Energy Corporation, the nation’s most active driller, as the Operator.  Drilling and high pressure fracturing have been completed, a pumping unit has been installed, and fracture fluids are currently being recovered.

 

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.

 

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.  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

 

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ceiling, the company will record a write-down to the extent of such excess as a non-cash charge to earnings. Any such write-down will reduce earnings in the period of occurrence and result in lower depreciation and depletion in future periods.  A write-down may not be reversed in future periods, even though higher oil and 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 the average prices in effect as of the first day of each month 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 average prices and costs in effect during the preceding year.

 

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.

 

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 System is generally installed on mature wells.  As such, they contain older down-hole equipment, such as casing, that is more subject to failure than new equipment.  The failure of such equipment 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 2010 by production for fiscal year 2010.  This measure yields an average reserve life of 12.1 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.

 

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: replace the single-day fiscal period-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 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 adopted the revisions and amendments effective with this report on Form 10-K.  Adoption of the New Rules did not have a significant impact on the Company’s reserve quantities.

 

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Intangible Assets.  The patents underlying the Calliope Gas Recovery System are carried as a non-current asset on the company’s balance sheet and are being amortized over the average remaining life of the patents.  The company periodically evaluates this asset to assure that the remaining value is recoverable.

 

The company believes that the number of future installations will be sufficient to demonstrate recoverability of the cost.  Due to various factors, there have been no recent Calliope installations.  If the Company is unable to achieve the expected level of installations, the company may in the future be required to record an impairment of the asset. Should this event occur, it would be a non-cash charge to income and would have no effect on working capital.

 

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.

 

ITEM 7A.                                            QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

 

The company manages exposure to commodity price fluctuations by periodically hedging a portion of estimated production when the potential for significant downward price movement is anticipated .  These transactions typically take the form of costless collars for oil and forward short positions based upon the NYMEX futures market for natural gas, and are closed by purchasing offsetting positions.  Such contracts do not exceed estimated production volumes and are authorized by the company’s Board of Directors.  Contracts are expected to be closed as related production occurs but may be closed earlier if the anticipated downward price movement occurs or if the company believes that the potential for such movement has abated.

 

At October 31, 2010 the company held open derivative contracts representing natural gas short sales positions for 40,000 MMBtus at NYMEX basis prices ranging from $6.91 to $7.27 and covering the production months of November 2010 through December 2010.  The company also held open offsetting derivative contracts with the same counterparty for 40,000 MMBtus at NYMEX basis prices of $5.83 and covering the production months of November 2010 through December 2010.  These positions are presented net due to the contractual netting provisions with the counterparty.  The open derivative contracts net to an unrealized gain of $50,000 at October 31, 2010.  Average natural gas prices received in the company’s primary market have historically been 15% - 17% below NYMEX prices due to basis differentials compared to the current differentials of about 5%.

 

At October 31, 2010 the company also held natural gas basis differential hedges on 80,000 MMBtus with NYMEX vs. Panhandle Eastern Pipeline basis differentials of $0.47 and covering the production months of November 2010 through December 2010. These open basis differential contracts represent unrealized losses of $19,000 at October 31, 2010.

 

Subsequent to October 31, the November and December natural gas related derivative contracts closed, resulting in net realized derivative gains of $30,000.  Subsequent to October 31, 2010, the company also entered into natural gas derivative contracts for 30,000 MBTU’s for each of production months of January, February and March 2011. These contracts are at NYMEX Basis prices of $4.35-4.52 per Mcf.

 

Also subsequent to October 31, 2010 the company entered into costless collar derivative contracts for 5,000 barrels of oil for each production month of calendar year 2011 with a floor of $80.00 and a ceiling ranging from $90.50 to $97.50 per barrel. The company also entered into costless collar derivative contracts for 3,000 barrels of oil for each production month of calendar year 2012 with a floor of $80.00 and a ceiling ranging from $94.00 to $99.00 per barrel.

 

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Table of Contents

 

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 $7,200,000 with interest calculated at the prime rate.  The facility is unsecured and has covenants that require the company to maintain $3,000,000 in cash or short term investments, none of which are required to be maintained at the company’s bank, and prohibits funded debt in excess of $500,000.  The line expires May 1, 2013.

 

ITEM 8.                                                     FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

 

 

 

Page

Index to Consolidated Financial Statements

 

 

Consolidated Balance Sheets, October 31, 2010 and 2009

 

31

Consolidated Statements of Operations for the Three Years Ended October 31, 2010

 

32

Consolidated Statements of Stockholders’ Equity for the Three Years Ended October 31, 2010

 

33

Consolidated Statements of Cash Flows for the Three Years Ended October 31, 2010

 

34

Notes to Consolidated Financial Statements

 

35

Reports of Independent Registered Public Accounting Firms

 

51

 

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Table of Contents

 

CONSOLIDATED BALANCE SHEETS

October 31, 2010 and 2009

 

CREDO PETROLEUM CORPORATION AND SUBSIDIARIES

 

 

 

2010

 

2009

 

 

 

 

 

 

 

ASSETS

 

 

 

 

 

Current assets:

 

 

 

 

 

Cash and cash equivalents

 

$

7,179,000

 

$

12,348,000

 

Short-term investments

 

1,990,000

 

635,000

 

Receivables:

 

 

 

 

 

Trade

 

479,000

 

487,000

 

Accrued oil and gas sales

 

1,574,000

 

1,566,000

 

Derivative assets

 

32,000

 

104,000

 

Other current assets

 

832,000

 

859,000

 

Total current assets

 

12,086,000

 

15,999,000

 

 

 

 

 

 

 

Long-term assets:

 

 

 

 

 

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

 

 

 

 

 

Unevaluated oil and gas properties

 

8,801,000

 

7,363,000

 

Evaluated oil and gas properties

 

83,360,000

 

76,127,000

 

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

 

(56,339,000

)

(53,211,000

)

Net oil and gas properties

 

35,822,000

 

30,279,000

 

Intangible assets, net of accumulated amortization of $872,000 in 2010 and $436,000 in 2009

 

3,578,000

 

4,013,000

 

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

 

1,855,000

 

1,865,000

 

Other, net

 

64,000

 

396,000

 

Total assets

 

$

53,405,000

 

$

52,552,000

 

 

 

 

 

 

 

LIABILITIES AND STOCKHOLDERS’ EQUITY

 

 

 

 

 

 

 

 

 

 

 

Current liabilities:

 

 

 

 

 

Accounts payable

 

$

1,200,000

 

$

407,000

 

Revenue distribution payable

 

565,000

 

653,000

 

Accrued compensation

 

466,000

 

948,000

 

Other accrued liabilities

 

177,000

 

394,000

 

Income taxes payable

 

17,000

 

55,000

 

Total current liabilities

 

2,425,000

 

2,457,000

 

 

 

 

 

 

 

Long-term liabilities:

 

 

 

 

 

Deferred income taxes, net

 

3,281,000

 

2,537,000

 

Asset retirement obligation

 

1,132,000

 

1,502,000

 

Total liabilities

 

6,838,000

 

6,496,000

 

 

 

 

 

 

 

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

 

31,486,000

 

31,472,000

 

Treasury stock, at cost, 601,000 shares in 2010, and 419,000 shares in 2009

 

(4,509,000

)

(2,803,000

)

Retained earnings

 

18,524,000

 

16,321,000

 

Total stockholders’ equity

 

46,567,000

 

46,056,000

 

 

 

 

 

 

 

Total liabilities and stockholders’ equity

 

$

53,405,000

 

$

52,552,000

 

 

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, 2010

 

CREDO PETROLEUM CORPORATION AND SUBSIDIARIES

 

 

 

2010

 

2009

 

2008

 

 

 

 

 

 

 

 

 

Oil sales

 

$

6,855,000

 

$

5,953,000

 

$

5,530,000

 

Gas sales

 

4,711,000

 

4,114,000

 

11,815,000

 

 

 

11,566,000

 

10,067,000

 

17,345,000

 

 

 

 

 

 

 

 

 

Costs and expenses:

 

 

 

 

 

 

 

Oil and gas production

 

3,192,000

 

3,260,000

 

3,861,000

 

Depreciation, depletion and amortization

 

3,602,000

 

4,439,000

 

3,583,000

 

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

 

 

24,653,000

 

 

General and administrative

 

2,107,000

 

3,250,000

 

1,637,000

 

 

 

 

 

 

 

 

 

 

 

8,901,000

 

35,602,000

 

9,081,000

 

 

 

 

 

 

 

 

 

Income(loss) from operations

 

2,665,000

 

(25,535,000

)

8,264,000

 

 

 

 

 

 

 

 

 

Other income and (expense)

 

 

 

 

 

 

 

Realized and Unrealized gains (losses) from derivative contracts

 

42,000

 

2,079,000

 

188,000

 

 

 

 

 

 

 

 

 

Investment and other income (loss)

 

108,000

 

(59,000

)

(299,000

)

 

 

150,000

 

2,020,000

 

(111,000

)

 

 

 

 

 

 

 

 

Income(loss) before income taxes

 

2,815,000

)

(23,515,000

)

8,153,000

 

Income taxes

 

(612,000

)

9,061,000

 

(2,160,000

)

 

 

 

 

 

 

 

 

Net income(loss)

 

$

2,203,000

 

$

(14,454,000

)

$

5,993,000

 

 

 

 

 

 

 

 

 

Earnings(loss) per share of Common Stock-Basic

 

$

0.22

 

$

(1.40

)

$

.62

 

 

 

 

 

 

 

 

 

Earnings(loss) per share of Common Stock-Diluted

 

$

0.22

 

$

(1.40

)

$

.61

 

 

 

 

 

 

 

 

 

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

 

 

 

 

 

 

 

Basic

 

10,183,000

 

10,326,000

 

9,697,000

 

 

 

 

 

 

 

 

 

Diluted

 

10,202,000

 

10,326,000

 

9,758,000

 

 

See accompanying notes to consolidated financial statements.

 

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Table of Contents

 

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

For the Three Years Ended October 31, 2010

 

CREDO PETROLEUM CORPORATION AND SUBSIDIARIES

 

 

 

Common Stock

 

Capital In
Excess Of

 

Treasury

 

Retained

 

Total
Stockholders’

 

 

 

Shares

 

Amount

 

Par Value

 

Stock

 

Earnings

 

Equity

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

Comprehensive income(loss):

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income

 

 

 

 

 

2,203,000

 

2,203,000

 

Purchase of treasury stock

 

 

 

 

 

(2,066,000

)

 

(2,066,000

)

Compensation expense related to stock options

 

 

 

78,000

 

 

 

78,000

 

Exercise of stock options

 

 

 

(64,000

)

360,000

 

 

296,000

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Balance, October 31, 2010

 

10,660,000

 

$

1,066,000

 

$

31,486,000

 

$

(4,509,000

)

$

18,524,000

 

$

46,567,000

 

 

See accompanying notes to consolidated financial statements.

 

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CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Three Years Ended October 31, 2010

 

CREDO PETROLEUM CORPORATION AND SUBSIDIARIES

 

<

 

 

2010

 

2009

 

2008

 

 

 

 

 

 

 

 

 

Cash flows from operating activities:

 

 

 

 

 

 

 

Net income(loss)

 

$

2,203,000

 

$

(14,454,000

)

$

5,993,000

 

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

 

3,602,000

 

4,439,000

 

3,583,000

 

ARO liability accretion

 

75,000

 

77,000

 

51,000

 

Unrealized (gains) losses from derivatives

 

72,000

 

1,641,000

 

(1,301,000

)

Deferred income taxes

 

744,000

 

(8,580,000

)

1,913,000

 

(Gain)loss on short-term investments

 

(65,000

)

180,000

 

618,000

 

Compensation expense related to stock options granted

 

78,000

 

31,000

 

68,000

 

Other

 

(1,000

)

 

63,000

 

Changes in operating assets and liabilities:

 

 

 

 

 

 

 

Proceeds from short-term investments

 

210,000

 

2,229,000

 

2,721,000

 

Purchase of short-term investments

 

(1,500,000

)

 

 

Trade receivables

 

8,000

 

508,000

 

(393,000

)

Accrued oil and gas sales

 

(8,000

)

167,000

 

(86,000

)

Other current assets

 

27,000

 

(654,000

)

(150,000

)

Accounts payable and accrued liabilities

 

(874,000

)

(236,000

)

(477,000

)

Income taxes payable

 

(38,000

)

(69,000

)

(310,000

)

 

 

 

 

 

 

 

 

Net cash provided by operating activities

 

4,533,000

 

9,932,000

 

12,293,000

 

 

 

 

 

 

 

 

 

Cash flows from investing activities:

 

 

 

 

 

 

 

Additions to oil and gas properties

 

(8,525,000

)

(13,719,000

)

(9,544,000

)

Proceeds from sale of oil and gas properties

 

299,000

 

 

 

Changes in other long-term assets

 

294,000

 

(65,000

)

(1,652,000

)

Purchase of intangible assets

 

 

(4,400,000

)

(975,000

)

 

 

 

 

 

 

 

 

Net cash used in investing activities

 

(7,932,000

)

(18,184,000

)

(12,171,000

)

 

 

 

 

 

 

 

 

Cash flows from financing activities: