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UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549
FORM 10-K
For the transition period from to
Commission File Number 0-8877
CREDO PETROLEUM CORPORATION (Exact name of registrant as specified in its charter)
1801 Broadway, Suite 900, Denver, Colorado 80202-3837 (Address of principal executive offices and zip code)
Registrant’s telephone number, including area code: (303) 297-2200
Securities registered pursuant to Section 12(b) of the Act: None
Securities registered pursuant to Section 12(g) of the Act:
Common Stock, $.10 Par Value (Title of class and shares outstanding)
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act: o Yes x No
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act: o Yes x No
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. x Yes o No
Indicate by 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.
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act) o Yes x No
The aggregate market value of the voting and non-voting common equity held by non-affiliates as of April 30, 2009, the end of the registrant’s most recently completed second quarter was $76,795,000.
As of January 4, 2010, the registrant had 10,204,000 shares of common stock outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Pursuant to instruction G (3) to Form 10-K, Items 10, 11, 12, 13 and 14 are omitted because the company will file a definitive proxy statement (the “Proxy Statement”) pursuant to Regulation 14A under the Securities Exchange Act of 1934 not later than 120 days after the end of the fiscal year. The information required by such items will be included in the Proxy Statement to be so filed for the company’s annual meeting of shareholders to be held on or about April 8, 2010 and is hereby incorporated by reference.
NON-GAAP FINANCIAL MEASURES
In this Annual Report on Form 10-K, the company uses the term “EBITDA (Earnings Before Interest, Taxes, Depreciation and Amortization including impairment losses)” which is considered a non-GAAP financial measure as defined in SEC Regulation S-K Item 10 and should not be considered in isolation or as a substitute for measures of performance prepared in accordance with GAAP. See Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for a definition of this measure as used in this Annual Report on Form 10-K.
Estimated Future Net Revenues Discounted at 10% is not a GAAP measure of operating performance. This pre-tax, non-GAAP measure is used by the company in connection with estimating funds expected to be available in the future for drilling and other operating activities. See Item 2 PROPERTIES, Significant Properties, Estimated Proved Oil and Gas Reserves, and Future Net Revenues for a reconciliation of Estimated Future Net Revenues Discounted at 10% to the Standardized Measure of Discounted Future Net Cash Flows as shown in Note 13 to the company’s Consolidated Financial Statements.
FORWARD-LOOKING STATEMENTS
This Annual Report on Form 10-K includes certain statements that may be deemed to be “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements included in this Annual Report on Form 10-K, other than statements of historical facts, address matters that the company reasonably expects, believes or anticipates will or may occur in the future. Forward-looking statements may include, among other things, statements relating to:
· the company’s future financial position, including working capital and anticipated cash flow; · amounts and nature of future capital expenditures; · projections of operating costs and other expenses; · wells to be drilled or reworked including new drilling expectations; · expectations regarding oil and natural gas prices and demand; · existing fields, wells and prospects; · diversification of exploration, capital exposure, risk and reserve potential of drilling activities; · estimates of proved oil and natural gas reserves; · expectations and projections regarding joint ventures; · reserve potential; · development and drilling potential; · expansion and other development trends in the oil and natural gas industry; · the company’s business strategy; · production and production potential of oil and natural gas; · matters related to the Calliope Gas Recovery System, including projections for future use of Calliope and the success of Calliope; · effects of federal, state and local regulation; · adequacy of insurance coverage; · employee relations; · effectiveness of the company’s hedging transactions; · investment strategy and risk; and · expansion and growth of the company’s business and operations.
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.
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.
Credo is engaged in the exploration for, acquisition of, and production of crude oil, natural gas and natural gas liquids. The company’s business strategy focuses on two core areas: drilling for oil and natural gas and recovering stranded gas from low-pressure reservoirs using the company’s patented Calliope Gas Recovery System (“Calliope”). Together, the company believes that drilling and Calliope provide a unique formula for success which distinguishes Credo from other oil and gas exploration and production companies.
Prior to 2006, the company’s core drilling region was the northern shelf of the Anadarko Basin in Oklahoma and North Texas where it explored primarily for natural gas. As a result, a significant majority of the company’s reserves have historically been comprised of natural gas.
In recent years, the company has made significant strategic changes with the objectives of expanding the volume and breadth of its drilling activities and focusing on drilling for and developing crude oil reserves. To accomplish these objectives, the company implemented new exploration projects in central Kansas, the Williston Basin of North Dakota and South Texas. This strategic change is intended to diversify the company’s drilling projects both technologically and geographically and to improve the balance between crude oil and natural gas in both its production and reserves.
Compared to drilling in Oklahoma, the North Dakota and South Texas projects involve higher costs and greater risks but have significantly higher per well reserve potential. In contrast, drilling in central Kansas is less expensive than the company’s Oklahoma drilling projects while still yielding excellent economics. Depending on natural gas prices, the company will continue generating prospects and drilling on its Oklahoma and South Texas acreage concentrating on medium depth properties. Refer to Item 2 — “Properties — General” for further information about these drilling projects.
The company owns the patents covering Calliope and has been instrumental in developing, testing, refining, and patenting the technology. Calliope efficiently lifts fluids from wellbores using pressure differentials, thus allowing gas previously trapped by fluid build-up in the wellbore to flow to the surface. Calliope is distinguished from other fluid lift technologies because it does not rely on bottom-hole pressure and has only one down-hole moving part. Calliope is primarily applicable to mature natural gas wells in low pressure, natural gas expansion reservoirs at depths below 8,000 feet. External sources of capital have not been required for the development, refinement or installation of Calliope. The company has proven Calliope’s economic viability and flexibility over a wide range of applications.
The company currently has Calliope installed on wells located in Oklahoma, Texas and Louisiana which include both sandstones and limestones in the Chester, Cotton Valley, Edwards, Hart, Hunton, Morrow, Nodosaria, Red Fork and Springer reservoirs.
Calliope’s low per-unit finding and production costs have become increasingly attractive as the economics on many drilling projects have deteriorated due to lower product prices. The company
also believes that lower natural gas prices may stimulate divestitures of marginal properties by other companies, including properties that have Calliope potential.
The company acts as “operator” of approximately 135 wells pursuant to standard industry operating agreements. The company owns working interests in about 350 producing wells and overriding royalty interests in about 1,200 wells.
Refer to Item 2., “Properties”, for more information regarding the company’s properties and Calliope.
Marketing of the company’s oil and gas production is influenced by many factors which are beyond the company’s control, and the exact effect of which cannot be accurately predicted. These factors include changes in supply and demand, market prices, regulation, and actions of major foreign producers. Oil price fluctuations can be extremely volatile as was demonstrated when, during 2008, the posted price for West Texas intermediate in July reached more than $140 per barrel, then fell below $35 in December.
Natural gas price decontrol, the advent of an active spot market for natural gas, changes in supply and demand for natural gas, speculation, and weather patterns cause natural gas prices to be subject to significant fluctuations. The company presently sells virtually all of its natural gas under three to five year contracts with major pipeline companies. The sales price is typically based on monthly index prices for the applicable pipeline. Title to the natural gas normally passes to the pipeline at meters located near the wells. The index prices are reduced by certain pipeline charges.
Most of the company’s natural gas production is located in northwestern Oklahoma. There has been significant consolidation among natural gas pipelines in this area, thereby reducing the number of available purchasers. In many instances, there may be only one viable pipeline option, which enables the pipeline to charge higher rates.
Natural gas prices were strong through mid-2008 due to concern about possible domestic supply/demand imbalances and in sympathy with increasing oil prices. This, together with supply vulnerability to natural disasters, such as hurricanes, and active speculation in the natural gas futures market caused natural gas prices to become increasingly volatile. The economic downturn that commenced in the second half of 2008 resulted in a significant reduction in industrial demand for natural gas at the same time gas supplies were increasing due to drilling success in gas resource plays. Those events caused an over supply of natural gas with the result that prices crashed. For example, the Panhandle Eastern Pipeline natural gas index, the basis for most of the company’s gas sales, fell from $11.07 per Mcf in July 2008 to $2.81 in November 2008 and $3.50 in October, 2009. The company expects natural gas prices to return to more historical levels but cannot reasonably predict the extent or timing of natural gas price fluctuations.
As discussed elsewhere in this Annual Report on Form 10-K, the company periodically hedges the price of a portion of its estimated natural gas production in the form of forward short positions on the NYMEX futures market.
Oil production is sold to crude oil purchasing companies at competitive field prices. Crude oil and condensate production are readily marketable, and the company is generally not dependent on a single purchaser. Crude oil prices are subject to world-wide supply and demand, and are primarily dependent upon available supplies which can vary significantly depending on production and pricing policies of OPEC and other major producing countries and on significant events, such as wars, in major producing regions. Crude oil prices were strong through mid-2008 due to supply concerns in view of the demand growth expected from developing countries such as China and India. However, the economic crisis that commenced in the second half of 2008 resulted in reduced demand projections and oil prices crashed from about $140 per barrel (NYMEX basis) in July 2008 to about $35 per barrel in February, 2009. Prices have since recovered to the $70 to $80 per barrel range.
Information concerning the company’s major customers is included in Note (13) to the Consolidated Financial Statements.
The oil and gas industry is highly competitive. As a small independent, the company must compete against companies with substantially greater financial, human and other resources in all aspects of its business.
Oil and gas drilling and production operations are regulated by various federal, state and local agencies. These agencies issue binding rules and regulations which carry penalties, often substantial, for failure to comply. The company anticipates its aggregate burden of federal, state and local regulation will continue to increase, particularly in the area of rapidly changing environmental laws and regulations. The company also believes that its present operations substantially comply with applicable regulations. There are no known environmental or other regulatory matters related to the company’s operations which are reasonably expected to result in material liability to the company. The company believes that capital expenditures related to environmental control facilities or other regulatory matters will not be material in 2010. The company cannot predict what subsequent legislation or regulations may be enacted or what effect they might have on the company’s business.
In evaluating the company, careful consideration should be given to the following risk factors, in addition to the other information included or incorporated by reference in this Annual Report on Form 10-K. Each of these risk factors could adversely affect the company’s business, operating results and financial condition, as well as adversely affect the value of an investment in the company’s common stock.
Volatility of oil and natural gas prices could adversely affect the company’s profitability and financial condition.
The company’s performance in terms of revenues, operating results, profitability, future rate of growth and the carrying value of its oil and natural gas properties is significantly impacted by prevailing market prices for oil and natural gas. Any substantial or extended decline in the price of oil or natural gas could have a material adverse effect on the company. It could reduce the company’s operating cash flow as well as the value and, to a lesser degree, the quantity of its oil and natural gas reserves. See the table of oil and gas sales volumes and prices on page 14 for further information.
Historically, the markets for oil and natural gas have been volatile, and they are likely to continue to be volatile. Relatively minor changes in supply or demand can have a significant effect on oil and natural gas prices. Some of the factors affecting oil and natural gas prices which are beyond the company’s control include:
· worldwide and domestic supplies of oil and natural gas; · worldwide and domestic demand for oil and natural gas; · the ability of the members of OPEC to agree to and maintain oil price and production controls; · political instability or armed conflict in oil or natural gas producing regions; · worldwide and domestic economic conditions; · the availability of transportation facilities; · weather patterns; and · actions of governmental authorities.
Competition for opportunities to replace and increase production and reserves is intense and could adversely affect the company.
Properties produce at a declining rate over time. In order to maintain current production rates the company must add new oil and natural gas reserves to replace those being depleted by production. Competition within the oil and natural gas industry is intense and many of the company’s competitors have financial and other resources substantially greater than those available
to the company. This could place the company at a disadvantage with respect to accessing opportunities to maintain, or increase, its oil and natural gas reserve base.
In the event that the company does not have adequate cash flow to fund operations, it may be required to use debt or equity financing.
The company makes, and will continue to make, significant expenditures to find, acquire, develop and produce oil and natural gas reserves. In the event of sustained low oil and gas prices, or if operating difficulties are encountered that result in cash flow from operations being less than expected, the company may have to reduce capital expenditures unless additional funds are raised through debt or equity financing. Debt or equity financing or cash generated by operations may not be available to the company in sufficient amounts or on acceptable terms to meet these requirements.
Future cash flows and the availability of financing will be subject to a number of variables, such as:
· the company’s success in locating and producing new reserves; · the level of production from existing wells; and · prices of oil and natural gas.
Issuing equity securities to satisfy the company’s financing requirements could cause substantial dilution to existing stockholders. Debt financing could also make the company more vulnerable to competitive pressures and economic downturns.
Reserve quantities and values are subject to many variables and estimates and actual results may vary.
This Annual Report on Form 10-K contains estimates of the company’s proved oil and natural gas reserves and the estimated future net revenues from those reserves. Any significant negative variance in these estimates could have a material adverse effect on the company’s future performance.
Reserve estimates are based on various assumptions, including assumptions required by the SEC relating to oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The process of estimating reserves is complex. This process requires significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data.
Reserve estimates are dependent on many variables, and therefore, as more information becomes available, it is reasonable to expect that there will be changes to the estimates. Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves will most likely vary from those estimated. Any significant variance could materially affect the estimated quantities and present value of reserves disclosed by the company. In addition, estimates of proved reserves will be adjusted in the future to reflect production history, results of exploration and development, prevailing oil and natural gas prices and other factors, many of which are beyond the company’s control.
As of October 31, 2009, approximately 36% of the company’s estimated proved reserves are classified as proved undeveloped. Estimation of proved undeveloped reserves and proved developed non-producing reserves is generally based on volumetric calculations rather than the performance data used to estimate reserves for producing properties. Recovery of proved undeveloped reserves generally requires significant capital expenditures and successful drilling operations. Revenues from proved developed non-producing and proved undeveloped reserves will not be realized until some time in the future. The reserve estimate includes an estimate of the capital expenditures required to develop these reserves as well as the timing of such expenditures. Although the company has prepared estimates of its proved undeveloped reserves and the associated development costs in accordance with industry standards, they are based on estimates, and actual results may vary from those estimates.
You should not interpret the present value of estimated reserves, or PV-10, as the current market value of reserves attributable to the company’s properties. The 10% discount factor, which we are required to use to calculate PV-10 for reporting purposes, is not necessarily the most appropriate discount factor given actual interest rates and risks to which the company’s business or the oil and natural gas industry in general are subject. The company has based the PV-10 on prices and costs as of the date of the reserve estimate, in accordance with applicable regulations. Actual future prices and costs may be materially higher or lower. In addition to the price volatility factors discussed above, factors that will affect actual future net cash flows, include:
· the amount and timing of actual production; · curtailments or increases in consumption by oil and natural gas purchasers; and · changes in governmental regulations or taxation.
As a result, the company’s actual future net cash flows could be materially different from the estimates included in this Annual Report on Form 10-K.
Full cost pool ceiling subject to reserve values.
The company uses the full cost method of accounting for costs related to its oil and natural gas properties. Capitalized costs included in the full cost pool are depleted on an aggregate basis using the units-of-production method. A change in proved reserves without a corresponding change in capitalized costs will cause the depletion rate to increase or decrease.
Both the volume of proved reserves and any estimated future expenditures used for the depletion calculation are based on estimates such as those described under “Oil and Gas Reserves”.
The capitalized costs in the full cost pool are subject to a quarterly ceiling test that limits such pooled costs to the aggregate of the present value of future net revenues attributable to proved oil and natural gas reserves discounted at 10 percent plus the lower of cost or market value of unproved properties less any associated tax effects. If such capitalized costs exceed the ceiling, the company will record a write-down to the extent of such excess as a non-cash charge to earnings, unless the company considers price increases subsequent to the balance sheet date which may reduce or eliminate a write-down. Any such write-down will reduce earnings in the period of occurrence and result in lower depreciation and depletion in future periods. A write-down may not be reversed in future periods, even though higher oil and natural gas prices may subsequently increase the ceiling. See Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for more information related to ceiling test write-downs.
The company’s reserve quantities and values are concentrated in a relative few properties and fields.
The company’s reserves, and reserve values, are concentrated in 64 properties which represent 22% of the company’s total properties but a disproportionate 80% of the discounted value (at 10%) of the company’s reserves. Individual wells on which Calliope is installed comprise 16% of these significant properties and 14% of the discounted reserve value of such properties. Reserves added during 2009 comprise 8% of these significant properties and 14% of the discounted reserve value of such properties.
Estimates of reserve quantities and values for these properties must be viewed as being subject to significant change as more data about the properties becomes available. Such properties include wells with limited production histories and properties with proved undeveloped or proved non-producing reserves. In addition, Calliope is generally installed on mature wells. As such, they contain older down-hole equipment that is more subject to failure than new equipment. The failure of such equipment, particularly casing, can result in complete loss of a well.
Competition for materials and services is intense and could adversely affect the company.
Major oil companies, independent producers, and institutional and individual investors are actively seeking oil and gas properties throughout the world, along with the equipment, labor and materials required to develop and operate properties. Shortages of equipment, labor or materials may result in increased costs or the inability to obtain such resources as needed. Many of the company’s competitors have financial and technological resources which exceed those available to the company.
Natural gas derivatives involve credit risk and may limit future revenues from price increases.
To manage the company’s exposure to price risks associated with the sale of natural gas, the company periodically enters into derivative transactions for a portion of its estimated natural gas production. These transactions may limit the company’s potential gains if natural gas prices were to rise substantially over the price established by the derivatives. In addition, such transactions may expose the company to the risk of financial loss in certain circumstances, including instances in which:
· the company’s production is less than the amount hedged; · the contractual counterparties fail to perform under the contracts; or · a sudden, unexpected event materially impacts natural gas prices.
The terms of the company’s derivative agreements may also require that it furnish cash collateral, letters of credit or other forms of performance assurance in the event that mark-to-market calculations result in settlement obligations by the company to the counterparties, which would encumber the company’s liquidity and capital resources.
The company’s derivatives are generally based on NYMEX prices but the company’s hedged production is primarily sold on a regional pipeline index price. The regional price is currently 2% below NYMEX prices. However, regional weather conditions and other economic factors can frequently result in substantially higher basis differentials.
The company has elected not to designate its commodity derivatives as cash flow hedges for accounting purposes. Accordingly, such contracts are recorded at fair value on its Balance Sheets and changes in fair value are recorded in the Statements of Operations as they occur.
The marketability of the company’s natural gas production is dependent upon infrastructure, such as gathering systems, pipelines and processing facilities, that the company does not own or control.
The marketability of the company’s natural gas production depends in part upon the availability, proximity and capacity of natural gas gathering systems, pipelines and processing facilities necessary to move the company’s natural gas production to market. The company does not own this infrastructure and is dependent on other companies to provide it.
Oil and natural gas operations are inherently risky.
The oil and natural gas business involves a variety of risks, including the risks of operating hazards such as fires, explosions, cratering, blow-outs, and encountering formations with abnormal pressures. The occurrence of any of these risks could result in losses. The company maintains insurance against some, but not all, of these risks. The occurrence of a significant event that is not fully insured could have a material adverse effect on the company’s financial position and results of operations.
All of the company’s oil and natural gas properties are located on-shore in the continental United States. The company’s future drilling activities may not be successful, and its overall drilling success rate may change. Unsuccessful drilling activities could have a material adverse effect on the company’s results of operations and financial condition. Also, the company may not be able to obtain the right to drill in areas where it believes there is significant potential for the company.
The company has recently expanded the volume and breadth of its exploration program with new drilling projects in South Texas and North Dakota. Compared to the company’s Oklahoma drilling, these projects involve higher costs and greater risks.
The company’s operations are subject to a variety of regulatory constraints.
The production and sale of oil and natural gas are subject to a variety of federal, state and local government regulations. These include regulations relating to:
· the prevention of waste; · the discharge of materials into the environment; · the conservation of oil and natural gas; · pollution; · permits for drilling operations; · drilling bonds; · reports concerning operations; · the spacing of wells; and · the unitization and pooling of properties.
The company could incur liability for violations of these regulations. In addition, because current regulations covering the company’s operations are subject to change at any time, the company could incur significant costs for future compliance.
Increases in taxes on energy sources may adversely affect the company’s operations.
Federal, state and local governments which have jurisdiction in areas where the company operates impose taxes on the oil and natural gas products sold. Historically, there has been on-going consideration by federal, state and local officials concerning a variety of energy tax proposals. Such matters are beyond the company’s ability to accurately predict or control.
ITEM 1B. UNRESOLVED STAFF COMMENTS
The company does not have any unresolved comments from the Commission.
Refer to Item 1.—“Business Activities” for a general description of the company’s oil and gas drilling and Calliope projects. Refer to Item 2. — “Significant Properties, Estimated Proved Oil and Gas Reserves, and Future Net Revenues” for information regarding the company’s significant oil and gas properties.
The company owns approximately 70,000 gross acres located on the northern shelf of the Anadarko Basin of Oklahoma and North Texas where it also owns interests in approximately 226 gross (71 net) wells, primarily natural gas wells. Historically, the company’s drilling has been focused on this area. However, in recent years the company has diversified its drilling activities into other regions and has deemphasized drilling for natural gas in favor of drilling for crude oil reserves. Continued drilling on the company’s Oklahoma and North Texas acreage is primarily dependent on natural gas prices, however, because much of the company’s acreage is held by production, the timing of drilling is not critical in terms of preserving most of the company’s acreage ownership.
In recent years, the company has significantly expanded both the volume and breadth of its drilling activities with new projects in central Kansas, North Dakota’s Williston Basin, and South Texas. Compared to drilling in Oklahoma, the North Dakota and South Texas projects involve higher costs and greater risks but significantly higher per well reserve potential. In contrast, drilling in central Kansas is less expensive than the company’s Oklahoma drilling projects while still yielding excellent economics.
In central Kansas, the company owns interests in approximately 140,000 gross acres and 77,000 net acres and it is continuing to expand its acreage position. At October 31, 2009, the company has
participated in drilling 44 wells on its acreage, of which 43% have been successfully completed as producers. The company is continuing to conduct an active drilling program expected to consist of two to three wells per month. The company owns working interests in the existing prospects ranging from 12.5% to 85%. The company’s north-central Kansas drilling activities provide diversification to the company’s drilling program geographically and scientifically through the use of 3-D seismic to identify shallow oil prospects. The acreage is located in prolific oil producing areas where 3-D seismic has proven effective in identifying satellite structures near mature producing fields. Generally higher oil prices have justified using 3-D seismic technology to locate undrilled structures that are very difficult to find with older technology. Drilling targets the Lansing-Kansas City and Arbuckle formations at about 4,000 feet and, compared to the company’s Northern Anadarko Basin, North Dakota Bakken, and South Texas projects, is relatively low cost, low risk, and exclusively targets oil reserves.
In North Dakota’s Bakken oil shale play, the company has assembled approximately 7,600 gross and 5,675 net acres on the Fort Berthold Indian Reservation south and west of Parshall Field. The acreage consists of approximately 33 drilling locations based on 640 acre spacing units and 13 locations based on 1,280 acre spacing units. The company expects that more than one well will be drilled on many spacing units. The project targets horizontal drilling for the Bakken and Three Forks shales. Breakthroughs in precision horizontal drilling and multi-stage, high pressure fracture stimulations have made the Bakken shale a very active resource play which is being actively developed by a significant number of companies, including large independents and majors. The U.S. Geological Survey recently estimated that the Bakken contains around 4.0 billion barrels of undiscovered oil. Vertical well depths on the company’s acreage are approximately 10,000 feet and the horizontal legs are generally expected to range between 5,000 and 10,000 feet. Drilling is complete on the first Bakken horizontal well in which the company owns an interest and the well is currently awaiting completion which has been delayed due to cold weather and is now expected to commence in February 2010. The horizontal leg of the well is approximately 9,200 feet and will be completed in multiple stages. Credo owns a 10% working interest. Work is currently under way in preparation for drilling two to three additional wells on company acreage.
The South Texas project is 3-D seismic driven with well depths ranging from 10,000 to 17,000 feet. The most significant well drilled to date tested the Deep Wilcox formation on the Gemini Prospect and resulted in a dry hole. The 17,000-foot well confirmed the seismic interpretation and found porous sand. However, the sand was water wet and the well was plugged and abandoned. The company received approximately $1,300,000 of cash for the multiple prospect package and retained an 11.25% “carried interest” in the test well. The prospect package sold consists of two additional Deep Wilcox prospects located to the north of Gemini Prospect. These two prospects are structurally different and unique compared to the Gemini Prospect. Those prospects are being further evaluated, and if drilled, the company will have the same 11.25% carried interest in the next well as it did in the Gemini Prospect test well. This project is highly dependent on natural gas prices and is currently on hold due to low natural gas prices.
The company owns the patents covering Calliope and the exclusive rights to the technology. The company has been instrumental in developing, testing, refining, and patenting the technology. Calliope efficiently lifts fluids from wellbores using pressure differentials, thus allowing gas previously trapped by fluid build-up in the wellbore to flow to the surface. Calliope is distinguished from all other fluid lift technologies because it does not rely on bottom-hole pressure and has only one down-hole moving part. Calliope is primarily applicable to mature natural gas wells in low pressure, natural gas expansion reservoirs at depths below 8,000 feet. The company has proven that Calliope will add 0.5 to 2.0 Bcf of proved gas reserves to many dead and uneconomic wells. The company believes there are presently more than 1,000 wells that meet its general criteria for Calliope candidate wells and thousands more that will meet its general Calliope criteria in the future. The company has proven Calliope’s economic viability and flexibility over a wide range of applications.
External sources of capital have not been required for the development, refinement or installation of Calliope.
The company currently has Calliope installed on wells located in Oklahoma and Texas which include both sandstones and limestones in the Chester, Cotton Valley, Edwards, Hart, Hunton, Morrow, Nodosaria, Red Fork and Springer reservoirs. At the time Calliope was installed, 14 of the wells
were dead, nine were uneconomic and two were marginal. There are 14 non-experimental Calliope wells. As a group, those wells were producing a total of 88 thousand cubic feet of gas per day at the time Calliope was installed. Since Calliope was installed, those wells have produced 5.4 billion cubic feet of gas and they now have estimated ultimate (8/8ths) Calliope reserves totaling 7.0 billion cubic feet of gas. Ten of the Calliope wells are included in the company’s Significant Properties.
Calliope’s low per-unit finding and production cost have become increasingly attractive as the economics on many drilling projects have deteriorated due to lower product prices. The company also believes that lower natural gas prices may stimulate divestitures of marginal properties by other companies, including properties that have Calliope potential.
On November 6, 2008 the company purchased all of the patents underlying Calliope, all of the related third party interests in future installations of the technology and patents covering a new fluid lift technology for shallow wells known as Tractor Seal for $4,500,000.
The company has three primary strategies to monetize its Calliope technology. The preferred strategy is to purchase dead and uneconomic wells from outside parties. A second strategy involves entering into joint ventures with outside parties that already own Calliope candidate wells. The third strategy is to drill new wells into old depleted fields and then use Calliope to recover the stranded gas. That strategy is highly dependent on natural gas prices and is generally not viable at current natural gas prices. The company is actively pursuing acquiring wells and joint ventures with other companies. During fiscal 2009, a joint venture agreement for a pilot project was completed with a large independent and joint venture discussions are underway with several companies, both large and small.
Significant Properties, Estimated Proved Oil and Gas Reserves, and Future Net Revenues
The company’s reserves, and reserve values, are concentrated in 64 properties (“Significant Properties”). Some of the Significant Properties are individual wells and others are multi-well properties. At year-end, Significant Properties represent 22% of the company’s total properties but a disproportionate 80% of the discounted value (at 10%) of the company’s reserves. Individual Calliope wells comprise 16% of the Significant Properties and represent 14% of the discounted reserve value of such properties. Reserves added in 2009 comprise 8% of the Significant Properties and represent 14% of the discounted value of such properties.
Estimates of reserve quantities and values for certain Significant Properties must be viewed as being subject to significant change as more data about the properties becomes available. Such properties include wells with limited production histories and properties with proved undeveloped or proved non-producing reserves. In addition, Calliope wells are generally mature wells. As such, they contain older down-hole equipment that is more subject to failure than new equipment. The failure of such equipment, particularly casing, can result in complete loss of a well.
At October 31, 2009 and 2008, LaRoche Petroleum Consultants, Ltd., an independent petroleum engineering firm, estimated proved reserves for all of the company’s properties. In 2007 McCartney Engineering, Inc., an independent petroleum engineering firm, estimated proved reserves for the company’s properties which represented 64% of the total estimated future value of estimated reserves. In 2007, remaining reserves were estimated by the company. At October 31, 2009, natural gas represented 74% and crude oil represented 26% of total reserves denominated in equivalent Mcf’s using a six Mcf of gas to one barrel of oil conversion ratio.
The following table sets forth, as of October 31 of the indicated year, information regarding the company’s proved reserves which is based on the assumptions set forth in Note (11) to the Consolidated Financial Statements where additional reserve information is provided. The average price used to calculate estimated future net revenues was $4.49, $3.50, and $5.89 per Mcf of gas and $69.24, $62.25, and $86.61 per barrel of oil as of October 31, 2009, 2008, and 2007, respectively. Amounts do not include estimates of future Federal and state income taxes.
* The percentage of total reserves classified as proved developed was approximately 61% in 2009, 67% in 2008, and 76% in 2007.
Estimated Future Net Revenues Discounted at 10% is not a GAAP measure of operating performance. Because the company drills new wells on an ongoing basis, and plans to continue to do so in the future, it expects to continue to generate deferred income taxes which are not reasonably expected to be paid in the near term. This pre-tax, non-GAAP measure is used by the company in connection with estimating funds expected to be available in the future for drilling and other operating activities. The company believes that this performance measure may also be useful to investors for the same purpose. The difference between this measure and the Standardized Measure of Discounted Future Net Cash Flows From Reserves is that this measure excludes future income tax expense and the effect of the 10% discount factor on future income tax expense. The following table provides a reconciliation of Estimated Future Net Revenues Discounted at 10% to the Standardized Measure of Discounted Future Net Cash Flows as shown in Note 13 to the company’s Consolidated Financial Statements.
* The average price used to calculate estimated future net revenues was $69.24, $62.25 and $86.61 per barrel of oil and $4.49, $3.50 and $5.89 per Mcf of gas as of October 31, 2009, 2008, and 2007, respectively.
Production, Average Sales Prices and Average Production Costs
The company’s net production quantities and average price realizations per unit for the indicated years are set forth below. Price realizations include realized derivative gains or losses.
(1) Included $3.02 Mcf realized natural gas hedging derivative gain. (2) Includes $0.25 Mcf realized natural gas hedging derivative loss. (3) Includes $0.99 Mcf realized natural gas hedging derivative gain.
Average production costs, including production taxes, per equivalent Mcf of production (using a six Mcf of gas to one barrel of oil conversion ratio) were $1.71, $2.05 and $1.51 per Mcfe in 2009, 2008, and 2007, respectively.
Productive Wells and Developed Acreage
Developed acreage at October 31, 2009 totaled 28,000 net and 188,000 gross acres. At October 31, 2009, the company owned working interests in 93 net (339 gross) wells consisting of 70.61 net (265 gross) natural gas wells and 22.21 net (74 gross) oil wells. In addition, the company owned royalty and production payment interests in approximately 1,181 wells, primarily coal bed methane, located in Wyoming. In 2009, no wells were sold or abandoned or acquired.
The following table sets forth the number of undeveloped acres leased by the company (primarily located in the Mid-Continent and Rocky Mountain Regions) which will expire during the next five years (and thereafter) unless production is established in the interim. Undeveloped acres “held-by-production” represent the undeveloped portions of producing leases which will not expire until commercial production ceases.
In general, “royalty” interests are non-operated interests which are not burdened by costs of exploration or lease operations, while “working interests” have operating rights and participate in such costs.
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
(1) Of the gross wells drilled in 2009, 3 of the oil wells, 2 of the gas wells and 8 of the dry holes were operated by the company. The remaining wells represent company participations in wells operated by others.
Net Wells
(1) Of the net wells drilled in 2009, 2.550 of the oil wells, 1.230 net gas wells and 6.043 net dry holes were operated by the company. The remaining wells represent company participations in wells operated by others.
The company believes that its existing insurance coverage is adequate to protect it from the risks associated with the ongoing operation of its business. This coverage includes commercial property, liability and auto, workers compensation, inland marine, directors and officers and excess liability.
The company’s corporate headquarters are located at 1801 Broadway, Suite 900, Denver, Colorado, in approximately 5,000 square feet occupied under a lease. The company believes that this space is adequate for its current needs. The company’s current lease expires in April 2011.
As of October 31, 2009, the company had 13 employees. None of the company’s employees is subject to a collective bargaining agreement, and the company considers relations with its employees to be good.
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.
From time to time, the company may be involved in litigation relating to claims arising out of the company’s operations in the normal course of business. As of the date of this Annual Report on Form 10-K, the company has been named as a defendant in a lawsuit alleging breach of contract, and other issues, arising in the normal course of its oil and gas activities. The company believes that a contractual agreement requires that disputes be resolved by arbitration. Although the company believes the allegations are without merit and that the company will ultimately prevail, the ultimate outcome of this lawsuit, or arbitration, cannot be determined at this time.
The company has also been named as a defendant in a lawsuit brought by a former employee. The suit, Pownell v. Credo Petroleum Corp. et al., U.S.D.C. for the District of Colorado, alleges breach of contract and other employment issues. Although the company believes the allegations are without merit and that the company will ultimately prevail, the ultimate outcome of this lawsuit cannot be determined at this time.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matters were submitted to a vote of security holders during the fourth quarter of 2009.
The company’s common stock is traded on the NASDAQ Global Market SM under the symbol “CRED”. Market quotations shown below were reported by the Financial Industry Regulatory Authority (FINRA) and represent prices between dealers excluding retail mark-up or commissions and may not necessarily represent actual transactions.
At January 4, 2010, the company had 2,321 shareholders of record. The company has never paid a cash dividend and does not expect to pay any cash dividends in the foreseeable future. Earnings are reinvested in business activities.
Issuer Purchases of Equity Securities.
During the fiscal year, the company repurchased 196,494 shares of its common stock on the open market at a weighted average price of $9.27. The purchases were made pursuant to a stock repurchase plan announced on September 24, 2008. The plan authorized repurchases up to $2,000,000, and was subsequently expanded to authorize purchases up to $4,000,000. Subsequent to October 31, 2009, and through January 7, 2010, the company has repurchased an additional 36,937 shares, bringing the total shares repurchased to 332,371 at an average price per share of $8.79.
Issuer Purchases of Equity Securities
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