Item 1. Business
We were incorporated in the State of Wyoming in August 1994 under the name GeoPetro Company as an oil and gas exploration, development drilling and production company. In June 1996, we merged with our wholly-owned subsidiary, GeoPetro Resources Subsidiary Company, a California corporation, and the resulting merged company is incorporated in the state of California under the California General Corporation Law under the name GeoPetro Resources Company.
Our principal and registered office is located at One Maritime Plaza, Suite 700, San Francisco, California, USA 94111. We maintain a website located at www.geopetro.com.
Intercorporate Relationships
We hold 100% of the shares of Redwood Energy Company, a Texas corporation, “Redwood.” Redwood is the general partner of, and holds a 5% interest in, Redwood Energy Production, L.P., “Redwood LP”, a Texas limited partnership. We are the sole limited partner of Redwood LP and own the remaining 95% partnership interest in Redwood LP.
In addition, we hold a 12% interest in Continental-GeoPetro (Bengara II) Ltd., “C-G Bengara” which is a British Virgin Islands company and a 50% interest in CG Xploration Inc., “CG Xploration”, which is a Delaware corporation.
We also hold 100% of the shares of GeoPetro Canada Ltd., “GeoPetro Canada”, an Alberta company, 100% of the shares of GeoPetro Alaska LLC “GeoPetro Alaska”, an Alaska limited liability company, and 100% of the shares of South Texas GeoPetro, LLC, “South Texas GeoPetro”, a Texas limited liability company.
GENERAL DEVELOPMENT OF THE BUSINESS
During the past five years, we have conducted leasehold acquisition, exploration and drilling activities on our North American, Australian and Indonesian prospects. These projects currently encompass approximately 372,317 gross (158,401 net) acres, consisting of mineral leases, production sharing contracts and exploration permits that give us the right to explore for, develop and produce oil and natural gas. Most of these properties are in the exploration, appraisal or development drilling phase and have not begun to produce revenue from the sale of oil and natural gas. Excluding minor interest and dividend income, our only cash inflows until 2003 were the recovery of capital invested in projects through sale or other divestiture of interests in oil and gas prospects to industry partners.
In December 2000, we acquired working interests in oil and natural gas leases in the Madisonville Field in Madison County, Texas, including interests in the Rodessa Formation. Also included in the acquisition was the Magness Well, an existing well that had been drilled, cased and production tested in the Rodessa Formation. In October 2001, we re-completed and tested the Magness Well over a 12-day period. In October 2002, we drilled, completed and successfully tested an injection well to dispose of waste products resulting from the treating process for gas produced from the Rodessa Formation. The Madisonville Field gas treatment plant and associated pipelines, which were built specifically for this project, were placed into service in May 2003, and the Magness Well began production in late May 2003. Since 2003, substantially all of our revenue has been generated from natural gas sales derived from the Madisonville Field. The Madisonville Project is expected to be our primary source of revenue in 2008. The first development well in the Madisonville Field, the Fannin Well, was drilled in 2004 and was tested at rates of up to 25.7 MMcf/d. In 2006, we drilled the Wilson and Mitchell wells. Presently, the Fannin, Mitchell and Magness wells are producing while the Wilson well is shut-in awaiting a fracture stimulation. We own a 100% working interest in the four wells. Historically, our wells have been production constrained by the gas treatment plant at the Madisonville Field, which had a treating capacity limit of approximately 18,000 Mcf per day. We entered into an agreement with the plant owner, Madisonville Gas Processing, LP (“MGP”), an unaffiliated third party, which required, among other things, that MGP expand the design treating capacity of the plant from 18,000 to 68,000 Mcf per day to treat additional volumes from our producing wells. In early October 2007, MGP completed the additional treating facilities and the additional treating capacity at such facilities, however operations at the additional treating facilities were suspended in December 2007 in order to make modifications to more effectively deal with the presence of diamondoids in the gas stream produced from the Rodessa Formation. See “Properties” - Description of the Properties - Texas - The Madisonville Gas Treatment Plant and Gathering Facilities.”
As of March 31, 2008 we have 31,950,970 shares of common stock outstanding as a result of raising approximately $54.9 million of equity, net of offering costs, by way of private placements and a public offering in Canada. These funds have been used primarily to acquire, explore and develop our oil and natural gas prospects.
Most recently, on August 13, 2007, we sold, pursuant to a private placement, 2,002,599 units of our securities at a price of $3.85 per unit, for total gross proceeds of $7,710,006. Each unit consists of one share of our common stock and a warrant to purchase three-tenths of a common share. Each one whole warrant shall entitle the holder to acquire one share of common stock at a price of $4.50 per share for a period of five years from the closing date. The units were purchased by a small number of accredited investors. We filed a re-sale registration statement covering the common shares and warrants exercisable for common shares sold in such placement, which registration statement was declared effective by the Securities and Exchange Commission in October 2007. The gross proceeds from the sale have been, and will be, used to fund the Company’s exploration and development program and for general working capital purposes.
Growth Strategy
Our strategy is to maximize shareholder value through the exploration and development drilling of oil and natural gas prospects. To carry out this philosophy we employ the following business strategies:
· identify and pursue potential projects which individually have the potential to be “company makers” which we define as projects which could generate a minimum unrisked net present value of $50 million net to our interest using a 10% discount factor;
· perform geological, engineering and geophysical evaluations;
· gain control of key acreage;
· generate high quality drillable exploration and development drilling prospects;
· retain a large working interest in those projects which involve low risk appraisal or development drilling, exploitation or appraisal of proven, probable and possible reserves; and
· minimize early investment and exploration risk in higher risk exploratory prospects through farmouts to other oil and natural gas companies and maintain meaningful interests with a “carry” through the exploration phase.
Risks Associated With Foreign Operations
Our business activities in Indonesia, Canada and the United States are subject to political and economic risks, including: loss of revenue, property and equipment as a result of unforeseen events like expropriation, nationalization, war, terrorist attacks and insurrection; risks of increases in import, export and transportation regulations and tariffs, taxes and governmental royalties; renegotiation of contracts with governmental entities; changes in laws and policies governing operations of foreign-based companies in Indonesia; exchange controls, and numerous other factors. While we expect these risks are greater in Indonesia, especially political risk, any one or more of such political or economic conditions could change in the United States or Canada to our detriment. For a related discussion of the risks attendant with foreign operations, see “Risk Factors.”
Financial Information About Geographic Areas
Please see the notes to the financial statements for information concerning oil and gas properties located in the United States and foreign countries.
Regulations
Domestic exploration for, and production and sale of, oil and gas are extensively regulated at both the federal and state levels. Our business is and will be directly or indirectly affected by numerous governmental laws and regulations applicable to the energy industry, including:
· Federal environmental laws and regulations
· State environmental laws and regulations
· Local environmental laws and regulations
· Conservation laws and regulations
· Tax and other laws and regulations pertaining to the energy industry
Legislation, rules and regulations affecting the oil and gas industry are under constant review for amendment or expansion, frequently increasing the regulatory burden. Any changes in the existing legislation, rules or regulations could adversely affect our business. The regulatory burdens are often costly to comply with and carry substantial penalties for failure to comply.
As of December 2007, we have re-completed an existing production well and drilled three additional production wells and an injection well in the Madisonville Project as operator. In addition, we may drill oil, gas and disposal wells in the future as the operator and will be required to obtain local government and other permits to drill such wells. There can be no assurance that such permits will be available on a timely basis or at all. Texas and other states have statutes or regulations pertaining to conservation matters which, among other matters, regulate the unitization or pooling of gas properties and the spacing, plugging and abandonment of such wells and set limits on the maximum rates of natural gas that can be produced from gas wells.
Our operations and activities are subject to numerous federal, state and local environmental laws and regulations. These laws and regulations:
· Require the acquisition of permits
· Restrict the type, quantities and concentration of various substances that can be discharged into the environment
· Limit or prohibit drilling and other activities on wetlands and other designated, protected areas
· Regulate the generation, handling, storage, transportation, disposal and treatment of waste materials
· Impose criminal or civil liabilities for pollution resulting from oil and natural gas operations
We expect that with the increase in our exploratory and development drilling activities, the impact of environmental laws and regulations on our business and operations will also increase. We may be required in the future to make substantial outlays of money to comply with environmental laws and regulations. Additional changes in operating procedures and expenditures to comply with future environmental laws cannot be predicted.
Other than our U.S. projects, we do not operate oil and gas properties in which we own an interest. In those instances, we are not in the position to exert direct control over compliance with most of the rules and regulations discussed above. We are substantially dependent on the operators of our non-operated oil and gas properties to monitor, administer and oversee such compliance. The failure of the operator to comply with such rules and regulations could result in substantial liabilities to us.
As the operator of the Madisonville Project, among other various environmental laws and regulations, we are subject to the U.S. Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”) and any comparable legislation adopted by Texas which imposes strict, joint and several liability on owners and operators of properties and on persons who dispose or arrange for the disposal of “hazardous substances” found on or under the sites of such properties.
Under CERCLA, one owner, lessee or other party, having responsibility for and an interest in a site requiring cleanup may, under certain circumstances, be required to bear a disproportionate share of liability for the cost of such cleanup if payments cannot be obtained from other responsible parties. The Resource Conservation and Recovery Act (“RCRA”) and comparable rules adopted by Texas and other states regulate the generation, management and disposal of hazardous oil and gas waste.
The Texas Railroad Commission has been delegated the responsibility and authority to regulate and prevent pollution from oil and gas operations, including the prevention of pollution of surface or subsurface water resulting from the drilling of oil and gas wells and the production of oil and gas. In addition to regulating the generation, management and disposal of hazardous oil and gas waste, the Texas Railroad Commission has been delegated authority to regulate underground hydrocarbon storage, saltwater disposal pits and injection wells.
The drilling of oil and gas wells in Texas requires operators to obtain drilling permits, file an organization report and a performance bond or other form of financial security, such as a letter of credit, and obtain a permit to maintain pits to store and dispose of drilling fluids, saltwater and waste as well as other types of pits for other purposes. The issuance of such permits is conditioned upon the Texas Railroad Commission’s determination that these pits will not result in waste or pollution of surface or subsurface water.
Other states in which we have an interest in oil and gas properties may impose similar or more stringent regulations than imposed under CERCLA or RCRA.
In re-completing the existing well on the Madisonville Project, we were required to drill a well for injection or disposal of produced waste gas from wells. Injection wells are subject to regulation under the Safe Drinking Water Act (“SDWA”) and the regulations and procedures which have been adopted by the Environmental Protection Agency (“EPA”) under that Act. Generally, enforcement procedures under the SDWA are administered by the EPA unless such authority has been delegated by the EPA to a state which has primary enforcement responsibility based on the EPA’s determination that the state has adopted drinking water regulations no less stringent than the national primary drinking water regulations and meets certain other criteria. Underground injection wells not used for the underground injection of natural gas for storage are generally unlawful and subject to penalties under the SWDA unless authorized by:
· permit issued by the EPA or a state having primary enforcement responsibility, or
· rule pursuant to an underground injection control program established by a state or the EPA.
The regulatory burden on the natural gas and oil industry increases our cost of doing business and affects our financial condition. Future developments, such as stricter requirements of environmental or health and safety laws and regulations affecting our business or more stringent interpretations of, or enforcement policies with respect to, such laws and regulations, could adversely affect us. To meet changing permitting and operational standards, we may be required, over time, to make site or operational modifications at our facilities, some of which might be significant and could involve substantial expenditures. There can be no assurance that material costs or liabilities will not arise from these or additional environmental matters that may be discovered or otherwise may arise from future requirements of law.
Overseas Regulations
We own a working interest in an oil and gas project located in Indonesia. We have farmed out our interest in this project to a third party who is the operator of this project. In exploring for, drilling and developing this property, this operator will be required to comply with the environmental, conservation, tax and other laws and regulations of Indonesia. We own non-operated working interests in oil and gas projects located in Canada. In exploring for, drilling and developing these properties, these operators will be required to comply with the environmental, conservation, tax and other laws and regulations in Canada.
Technology
We participate in projects utilizing economically feasible exploration technology in our exploration and development drilling activities to reduce risks, lower costs, and more efficiently produce oil and gas. We believe that the availability of
cost effective 2-D and 3-D seismic data makes its use in exploration and development drilling activities attractive from a risk management perspective in certain areas.
Briefly, through the use of a seismograph, a seismic survey sends pulses of sound from the surface down into the earth, and records the echoes reflected back to the surface. By calculating the speed at which sound travels through the various layers of rock, it is possible to estimate the depth to the reflecting surface. It then becomes possible to infer the structure of rock deep below the earth’s surface. We evaluate substantially all of our exploratory prospects using 2-D seismic data. In addition, we own approximately 12 square miles of 3-D seismic data covering our leasehold and adjacent lands in the Madisonville Project.
The use of seismic technology does not entirely remove the risk of exploration and development drilling of oil and natural gas deposits. It is important to consider the following:
· we may not recognize significant geological features due to errors in interpretation, processing limitations, the presence of certain geological environments that are out of our control or other factors; and
· seismic generally becomes less reliable with increasing depth of the geological horizon; and
· the use of this technology may increase our finding cost over that if it is not used.
Principal Products
Our principal products are the production of natural gas and crude oil from properties in which we own an interest. Since our inception, we have realized only limited production of natural gas and crude oil from the properties in which we own an interest. We have working interests in various undeveloped oil and gas properties. See “Properties” for a general description of these properties.
During the last three fiscal years, 100% of our revenues have been derived from the sale of natural gas. Substantially all of our natural gas sales, approximately 99%, have been generated by three producing wells, the Magness #1, Fannin #1and Mitchell #1 wells, located in the Madisonville Field in East Texas. Natural gas produced by the wells is sold at the wellhead where it is delivered to a gathering pipeline and transported to a nearby gas treatment plant where it is treated to remove impurities. The gas is then transported nine miles to one of two common carrier pipelines from which point it is delivered to the greater Dallas, Texas area. The price received for the natural gas is the Houston Ship Channel price index less certain adjustments for the quality of the gas delivered. The adjustments for the quality of gas delivered at the wellsite as well as the gathering and transportation costs presently amount to approximately $1.75 per Mcf of untreated gas delivered at the wellsite.
For financial information regarding our business activities by segment, please see our Financial Statements beginning on page of this annual report. Substantially all of our revenue is produced from natural gas sales in the Madisonville Field located in East Texas.
Reserves
The volume of production from oil and natural gas properties generally declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. Our proved reserves will decline as reserves are produced from our properties unless we are able to acquire or develop new reserves.
Acquisition of Producing Properties
We may supplement our exploration efforts with acquisitions of producing oil and gas properties. We may seek to acquire producing properties that are underperforming relative to their potential.
Patents, Trademarks, Licenses, Franchises and Concessions Held
Permits and licenses are important to our operations, since they allow the search for the extraction of any oil, gas and minerals discovered on the areas covered. See “Properties” for a general description of the permits and licenses under which we operate. Provided we establish a commercial discovery thereon, the Bengara PSC in Indonesia grants us the right to produce oil and gas from the PSC area until 2027.
Seasonality of Business
Our business is not seasonal.
Working Capital Items
The majority of our current assets are in the form of cash and deposits in trust received from the sale of natural gas from our Madisonville Project in Texas and from the sale of common stock in private placements. We are required to use this cash to pay for the cost of our operations and activities. See further, “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
Customers
Substantially all of our revenues to date have been derived from sales by MGP to two customers, Luminant Energy Company, and ETC Katy Pipeline, Ltd., of natural gas produced from our Madisonville Project in Texas. We have not committed any forward sales of our natural gas. We contract to sell the gas with spot-market based contracts that vary with market forces on a monthly basis. No other customer accounts for in excess of 10% of our revenues. The loss of either of these customers could result in the loss of our revenues, which would have a material adverse effect on our results of operations. See “Risk Factors”.
Competition
The natural gas and oil industry is intensely competitive and speculative in all of its phases. We encounter competition from other natural gas and oil companies in all areas of our operations. In seeking suitable natural gas and oil properties for acquisition, we compete with other companies operating in our areas of interest, including large natural gas and oil companies and other independent operators, which have greater financial resources and in many instances, have been engaged in the exploration and production business for a much longer time than we have. Many of our competitors also have substantially larger operating staffs than we do. Many of these competitors not only explore for and produce natural gas and oil but also market natural gas and oil and other products on a regional, national or worldwide basis. These competitors may be able to pay more for productive natural gas and oil properties and exploratory prospects and define, evaluate, bid for and purchase a greater number of properties and prospects than us. In addition, these competitors may have a greater ability to continue exploration activities during periods of low market prices. Our ability to acquire additional properties and to discover reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment.
The prices of our natural gas production are controlled by market forces. However, competition in the natural gas and oil exploration industry also exists in the form of competition to acquire leases and obtain favorable transportation prices. We are relatively small and may have difficulty acquiring additional acreage and/or projects and may have difficulty arranging for the transportation of our production. We also face competition in obtaining natural gas and oil drilling rigs and in sourcing the manpower to run them and provide related services.
Employees
Currently, we have 10 employees, all of whom are full time. We use the services of independent consultants and contractors to perform various professional services, including reservoir engineering, land, legal, environmental and tax services. On those properties where we are not the operator, we rely on outside operators to drill, produce and market our natural gas and oil.
Item 1A.
Item 1A. Risk Factors
In addition to risks and uncertainties in the ordinary course of business that are common to all businesses, important factors that are specific to our industry and our company could materially impact our future performance and results of operations. We have provided below a list of these risk factors that should be reviewed when considering our securities. These are not all the risks we face and other factors currently considered immaterial or unknown to us may impact our future operations.
Risks Related to Our Business
As of December 31, 2007 we have capitalized costs totaling $53.28 million as evaluated and unevaluated oil and gas properties whereas we have generated revenues of only $29.9 million since January 1, 2003 and revenues of only $6.9 million during the fiscal year ended December 31, 2007.
Since inception, our activities have been primarily related to acquiring and exploring leasehold interests in oil and natural gas properties in Texas, California, Alaska, Alberta, Indonesia and Australia. We incur substantial acquisition and exploration costs and overhead expenses in our operations, and until 2003, excluding minor interest and dividend income, our only significant cash inflows were the recovery of capital invested in projects through sale or other divestitures of interests in oil and gas prospects to industry partners. As a result, we have sustained an accumulated deficit through December 30, 2007 of $12,010,789. Our production activities commenced in May 2003. Since May 2003, over 90% of our revenue has been generated from natural gas sales derived from wells in the Madisonville Field in Texas. It is possible that in the future we will be unable to continue to generate revenues from our sales of natural gas from our Madisonville Field wells because our proved reserves decline as reserves are produced from the wells. The drilling of exploratory oil and natural gas wells is highly speculative and often unproductive. Our participation in future drilling activities to explore, develop and exploit the properties in which we have an interest, or in which we may acquire interests, may be unsuccessful, may fail to generate positive cash flow, and may not enable us to maintain profitability in the future.
Approximately 99% of our current revenues are generated by our interest in the Madisonville Project. Delays or interruptions of the Madisonville Project natural gas drilling and production operations including, but not limited to, events beyond our control or the failure of third parties on which we rely to provide key services, could negatively impact our revenues.
Approximately 99% of our oil and natural gas revenues for the years ended December 31, 2007 and 2006 were derived from the Madisonville Project. In connection with that project, we have contracted with third parties to provide key services, including:
(a) Madisonville Gas Processing, LP, or MGP, which owns and operates gathering pipelines and a dedicated natural gas treatment plant which we utilize to treat impurities in the Madisonville Project natural gas; and
(b) Gateway Processing Company, or Gateway which operates a sales pipeline for such natural gas.
The failure of MGP or Gateway to perform their contractual obligations to us could impose delays or interruptions in our production operations and prevent us from generating revenues. In addition, events which are beyond our control, or that of Gateway or MGP, could affect our production operations. Such events include, but are not limited to:
· events referred to as force majeure, such as an act of God, act of a public enemy, war, blockade, public riot, lightning, fire, storm, flood, explosion and any other causes whether of the kind enumerated or otherwise not reasonably within the control of MGP, Gateway or our company.
· subsurface conditions or formations encountered during the drilling of wells, whether natural or mechanical, including but not limited to blowout, igneous rock, salt, saltwater flow, loss of circulation, loss of hole, abnormal pressures, or any other impenetrable substance or adverse condition, which renders further drilling of a well impossible or impractical.
· the inability to secure raw materials or equipment,
· transportation accidents, and
· labor disputes and equipment failures.
In excess of 90% of our revenues to date have been derived from sales by MGP to two customers. The loss of one or both these customers could have a material adverse impact on our oil and gas revenues.
Approximately 99% of our oil and natural gas revenues for the years ended December 31, 2007 and 2006 were derived from the Madisonville Project. During 2007 and 2006, approximately 99% of our revenues have been derived from sales by MGP to two customers, Luminant Energy Company, LLC, and ETC Katy Pipeline, Ltd. The loss of one of these customers could impact the price we receive for our gas sold due to lessened competition. The loss of both customers could result in a total loss of our revenue.
Unless we replace our oil and natural gas reserves, our reserves and production will decline.
The volume of production from oil and natural gas properties generally declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. Our proved reserves will decline as reserves are produced from our properties unless we are able to acquire or develop new reserves. The business of exploring for, developing or acquiring reserves is capital intensive. For example, as of December 30, 2007 we have capitalized costs totaling $53,276,945 as evaluated and unevaluated oil and gas properties. To the extent cash flow from operations is reduced and external sources of capital become limited or unavailable, our ability to make the necessary capital investment to maintain or expand our asset base of oil and natural gas reserves will be impaired. Even if we are able to raise capital to develop or acquire additional properties, no assurance can be given that our future exploitation and development drilling activities will result in the discovery of any reserves.
Our exploration and development drilling activities may not be commercially successful. The drilling of exploratory oil and natural gas wells is expensive, highly speculative and often unproductive.
Exploration for oil and natural gas on unproven prospects is expensive, highly speculative and involves a high degree of risk, including the risk that no commercially productive oil or natural gas reservoirs will be encountered. Reserves are dependent on our ability to successfully complete drilling activity on proven prospects.
The cost of drilling, completing and operating wells is often uncertain, and drilling operations may be curtailed, delayed or cancelled as a result of a variety of factors, including:
· unexpected drilling conditions, pressure or irregularities in formations;
· equipment failures or accidents, adverse weather conditions;
· compliance with governmental requirements; and
· shortages or delays in the availability of drilling rigs and the delivery of equipment.
Our evaluations of the oil and gas prospects of our properties may be wrong.
With the exception of the Madisonville Project, the properties in which we have an interest are prospects in which the presence of oil and natural gas reserves in commercial quantities has not been established. Any decision to engage in exploratory drilling or other activities on any of these properties will be dependent in part on the evaluation of data compiled by petroleum engineers and geologists and obtained through geophysical testing and geological analysis.
Reservoir engineering, geophysics and geology are not exact sciences and the results of studies and tests used to make such evaluations are sometimes inconclusive or subject to varying interpretations. As such, there is no certain way to know in advance whether any of our prospects will yield oil and natural gas in commercial quantities. Further, it is possible that we will participate in the drilling of more dry holes than productive wells or that all or substantially all of the wells drilled will
be dry holes. The drilling of dry holes on prospects in which we have an interest could adversely affect their values and our decision to undertake further exploration and development drilling of such prospects. It is not certain or predictable whether, and no assurance can be made that, the wells drilled on the properties in which we have an interest will be productive or, if productive, that we will recover all or any part of our investment in the properties. In sum, our participation in future drilling activities may not be successful and, if unsuccessful, such failure will negatively impact our revenues and have a material adverse effect on our results of operations and financial condition. Our oil and natural gas revenues were $6,890,777 and $6,716,360 for the years ended December 31, 2007 and 2006, respectively. Future revenues could decline from those levels if our future drilling efforts are not successful. Furthermore, as of December 30, 2007 we have capitalized costs totaling $53.28 million as evaluated and unevaluated oil and gas properties. Should our future drilling activities be unsuccessful, we may then be required to record an impairment charge equal to a portion of, or all, of the capitalized costs resulting in an immediate adverse impact on our results of operations and financial position.
Our business may be harmed by failures of third party operators on which we rely.
Our ability to manage and mitigate the various risks associated with certain of our exploration and operations in Alberta, Canada, and Indonesia is limited since we rely on third parties to operate our projects. We are a non-operating interest owner in our Canadian and Indonesian properties. With respect to our interests outside of the United States, we have entered into agreements with third party operators for the conduct and supervision of drilling, completion and production operations. In the event that commercial quantities of oil and natural gas are discovered on one of our properties, the success of the oil and natural gas operations on that property depends in large measure on whether the operator of the property properly performs its obligations. The failure of such operators and their contractors to perform their services in a proper manner could result in materially adverse consequences to the owners of interests in that particular property, including us.
Our percentage share of oil and gas revenues from our Indonesian property is diminished by the terms of our production sharing contract in the Bengara Block.
C-G Bengara owns 100% of the underlying rights to explore for and produce oil and natural gas within the Bengara Block. We have a 12% interest in C-G Bengara. C-G Bengara is subject to a production sharing contract, which means generally that C-G Bengara is entitled to receive, from production proceeds, 100% of expenditures in the block as “cost recovery.” Once these costs are recovered, C-G Bengara’s production share will be reduced to approximately 26.7% of oil produced and 62.5% of all natural gas produced. We are entitled to 12% of C-G Bengara’s reduced share of any such production. See the discussion under “Properties for more information concerning the production sharing contract.
Drilling and completion equipment, services, supplies and personnel are scarce and may not be available when needed, which could significantly disrupt or delay our operations.
From time to time, there has been a general shortage of drilling rigs, equipment, supplies and oilfield services in North America and Indonesia, which may intensify with current increased industry activity. In addition, the costs and delivery times of rigs, equipment and supplies have risen. There can be no assurance that sufficient drilling and completion equipment, services and supplies will be available when needed. Shortages could delay our proposed exploration, development drilling,
and sales activities, which could have a material adverse effect on our results of operations. Our oil and natural gas revenues were $6.9 million for the year ended December 31, 2007. Future revenues could decline from those levels if we experience delays in our proposed exploration, development drilling, and sales activities. The demand for, and wage rates of, qualified rig crews have risen in the drilling industry due to the increasing number of active rigs in service. If the demand for qualified rig crews continues to rise in the drilling industry, then the oil and gas industry may experience shortages of qualified personnel to operate drilling rigs. This could delay our drilling operations and adversely affect our financial condition and results of operations.
Our working interest in properties, and our ability to realize any profits from such properties, will be diminished to the extent that we enter into farmout arrangements with unaffiliated third parties.
We have previously entered into, and may in the future enter into, farmout arrangements with third parties willing to drill natural gas and oil wells on leaseholds in which we originally acquired working interests, in exchange for our assignment of part or all of our leasehold interests. As a consequence of these arrangements, our retained interests in properties which are subject to farmout arrangements have been or may be diminished. Our opportunity to realize revenues and profits from properties which are successfully developed under farmout arrangements will be diminished to the extent of our reduced interests.
Competition with other oil and natural gas exploration and development drilling companies for viable oil and natural gas properties may limit our success.
It is likely that in seeking future property acquisitions, we will compete with companies which have substantially greater financial and management resources. Our competition comes primarily from three sources:
(a) those competitors that are seeking oil and gas fields for expansion, further drilling, or increased production through improved engineering techniques;
(b) income-seeking entities purchasing a predictable stream of earnings based upon historic production from fields being acquired; and
(c) junior companies seeking exploration opportunities in unknown, unproven territories.
Our competitors may be able to pay more for productive oil and natural gas properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than we can. Our ability to acquire additional properties in the future will depend upon our ability to conduct efficient operations, evaluate and select suitable properties, implement advanced technologies and consummate transactions in a highly competitive environment.
Estimates of oil and natural gas reserves are inherently imprecise. Any material inaccuracies in these reserve estimates or underlying assumptions will affect materially the quantities and present value of our reserves.
Estimates of proved oil and natural gas reserves and the future net cash flows attributable to those reserves are prepared by independent petroleum engineers and geologists. There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves and cash flows attributable to such reserves, including factors beyond our control and that of our engineers. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. Different reserve engineers may make different estimates of reserves and cash flows based on the same available data. The accuracy of an estimate of quantities of reserves, or of cash flows attributable to such reserves, is a function of the available data, assumptions regarding future oil and natural gas prices and expenditures for future development drilling and exploration activities, and of engineering and geological interpretation and judgment. Additionally, reserves and future cash flows may be subject to material downward or upward revisions, based upon production history, development drilling and exploration activities and prices of oil and natural gas. Actual future production, revenue, taxes, development drilling expenditures, operating expenses, underlying information, quantities of recoverable reserves and the value of cash flows from such reserves may vary significantly from the assumptions and underlying information set forth herein.
Competitive pressures may force us to implement new technologies at substantial cost and our limited financial resources may limit our ability to implement such technologies at the same rate as our competitors.
The oil and gas industry is characterized by rapid and significant technological advancements and introductions of new products and services utilizing new technologies. Other oil and gas companies may have greater financial, technical and personnel resources that allow them to enjoy technological advantages and may in the future allow them to implement new technologies before we do. There can be no assurance that we will be able to respond to such competitive pressures and implement such technologies on a timely basis or at all. One or more of the technologies currently utilized by us or implemented in the future may become obsolete.
We will require additional capital to fund our future activities. Our ability to pursue our business plan may be restricted by our access to additional financing.
Until such time as the properties in which we own interests are generating sufficient cash flow to fund planned capital expenditures, we will be required to raise additional capital through the issuance of additional securities or otherwise sell or farm out interests in our oil and natural gas properties to third parties. If and when the properties in which we own interests become productive and have adequate reserves, we may borrow funds to finance our future oil and natural gas operations and exploratory and development drilling activities. We may not be able to raise additional funds in the future from any source or, if such additional funds are made available to us, we may not be able to obtain such additional financing on terms acceptable to us. To the extent such funds are not available from any of those sources, our operations and activities will be limited to those operations and activities we can afford with the funds then available to us. We have committed to a three well drilling program in our Madisonville project to facilitate the expansion of the gas treatment plant. The commitment is not discretionary. While we have fulfilled the commitment to drill the first two wells of the three well commitment, we are further required to drill a third well sufficient to test the Smackover Formation (estimated to be encountered at approximately 18,000 feet) on or before September 30, 2008. This well is expected to cost approximately $12 million to drill and complete. We have granted MGP a security interest in the Madisonville Field properties to secure the three well commitment. Subject to events of force majeure, and the availability of suitable drilling rigs, well services, and equipment, our failure to drill this well could result in the loss of our interest in the Madisonville Project. Our larger competitors, by reason of their size and relative financial strength, may be more easily able to access capital markets than us.
The volatility in crude oil and natural gas prices could adversely affect our financial results and ability to raise additional capital.
Our revenues, cash flows and profitability are substantially dependent on prevailing prices for both oil and natural gas. Decreases in natural gas prices will decrease revenues and cash flows from the Madisonville Project and our other producing properties, if any, and decreases in oil and natural gas prices could deter potential investors from investing in our company and generally impede our ability to raise additional financing to fund our exploration and development drilling activities. Historically, oil and natural gas prices and markets have been volatile, and they are likely to continue to be volatile in the future. Prices for oil and natural gas are subject to wide fluctuations in response to relatively minor changes in the supply of, and demand for, oil and natural gas, market uncertainty and a variety of additional factors that are beyond our control. These factors include, but are not limited to, political conditions in the Middle East and other regions, internal and political decisions of OPEC and other oil and natural gas producing nations to decrease or increase production of crude oil, domestic and foreign supplies of oil and natural gas, consumer demand, weather conditions, domestic and foreign government regulations, transportation costs, the price and availability of alternative fuels and overall economic conditions.
Our current operations are particularly exposed to volatility in natural gas prices because a portion of the fees we pay to process natural gas at the Madisonville gas treatment plant is fixed. The sale price of natural gas must be above a minimum price of approximately $3.00 per Mcf at the present time before we earn any net revenues from the sale of natural gas.
We are subject to a number of operational risks beyond our control against which we may not have, or be able to obtain insurance.
Our operations are subject to the many risks and hazards incident to exploring and drilling for, and producing and transporting, oil and natural gas, including among other risks:
· blowouts, fires, craterings, pollution and equipment failures that may result in damage to or destruction of wells, producing formations, production facilities and equipment;
· personal injuries or death due to accidents, human error or acts of God;
· unavailability of materials and equipment to drill and complete or re-complete wells; unfavorable weather conditions; engineering and construction delays;
· fluctuations in product markets and prices; proximity and capacity of pipeline, and trucking or termination facilities to our oil and natural gas reserves; hazards resulting from unusual or unexpected geological or environmental conditions; environmental regulations and requirements;
· accidental leakage of toxic or hazardous materials, such as petroleum liquids or drilling fluids into the environment, remediation and clean-up costs; and
· political instability and civil unrest, insurrections or disruptions in foreign countries in which some of our interests are located.
If one or more of these events occurs, we could incur substantial liabilities to third parties or governmental entities, the payment of which could have a material adverse effect on our financial condition and results of operations, or we could lose properties in which we have invested significant sums (totaling $53.28 million) which are capitalized as evaluated and unevaluated oil and gas properties as of December 30, 2007.
A loss not covered by insurance could result in substantial expenses to us.
We do not insure fully against all business risks either because such insurance is not available or because premium costs are prohibitive. This is a common practice in the oil and gas industry. However, a loss not fully covered by insurance could result in expenses to us and could have a material adverse effect on our financial position and results of operations. Uninsured losses in excess of $1.0 million would be materially adverse.
We are subject to extensive government regulations that can change from time to time, compliance with which are costly and could negatively impact our production, operations and financial results.
The oil and gas industry is subject to extensive government regulations in the countries in which we operate. Matters subject to regulation include discharge permits for drilling operations, drilling bonds, reports concerning operations, unitization and pooling of properties and taxation. Historically, our costs of complying with these regulations have not exceeded $100,000 per year. From time to time, regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of oil and natural gas wells below actual production capacity in order to conserve supplies of oil and natural gas. We are also subject to changing and extensive tax laws, the effects of which cannot be predicted. Legal requirements are frequently changed and subject to interpretation, and we are unable to predict the ultimate cost of compliance with these requirements or their effects on our operations. Future laws, or existing laws or regulations, as currently interpreted or reinterpreted or changed in the future, could result in increased operating costs, fines and liabilities, in amounts which are unknown at this time, any of which could materially adversely affect our results of operations and financial condition.
Our industry is subject to extensive environmental regulation that may limit our operations and negatively impact our production.
Extensive national, state, provincial and local environmental laws and regulations in the United States and foreign jurisdictions affect nearly all of our operations. These laws and regulations set various standards regulating certain aspects of health and environmental quality, provide for penalties and other liabilities for the violation of such standards and establish in certain circumstances obligations to remediate current and former facilities and locations where operations are or were conducted. In addition, special provisions may be appropriate or required in environmentally sensitive areas of operation.
Environmental legislation may require that we, among other things:
· acquire permits before commencing drilling;
· restrict spills, releases or emissions of various substances produced in association with our operations;
· limit or prohibit drilling activities on protected areas such as wetlands or wilderness areas;
· take reclamation measures to prevent pollution from former operations;
· take remedial measures to mitigate pollution from former operations, such as plugging abandoned wells and remediating contaminated soil and groundwater;
· take remedial measures with respect to property designated as a contaminated site.
The cost of any of these actions is presently unknown but is likely to be significant.
Compliance with existing or future environmental legislation is unknown but could be substantial.
Compliance with such legislation can require significant expenditures and a breach may result in the imposition of fines and penalties. The discharge of oil, natural gas or other pollutants into the air, soil or water may give rise to liabilities to governments and third parties and may require us to incur substantial costs to remedy such discharge. Under these laws and regulations, we could be liable for personal injury, clean-up costs and other environmental and property damages, as well as administrative, civil and criminal penalties. We could be required to cease production on properties if environmental damage occurs. Environmental legislation is evolving in a manner expected to result in stricter standards and enforcement, larger fines and liability and potentially increased capital expenditures and operating costs. Changes in, or enforcement of, environmental laws may result in a curtailment of our production activities, or a material increase in the costs of production, development drilling or exploration, any of which could have a material adverse effect on our financial condition and results of operations or prospects. We are not presently aware of any environmental liabilities or able to predict the ultimate cost of liabilities not yet recognized. We have recorded an asset retirement obligation in connection with the estimated future costs to plug certain wells in our Madisonville Project in Texas upon abandonment totaling approximately $53,726 as of December 31, 2007.
Our natural gas deliveries to the Madisonville gas treatment plant may be affected by the demands of Crimson Exploration, Inc. (“Crimson”) and other third parties for access to the plant, and as a result, our access to the plant could be restricted.
We are dependent upon the Madisonville gas treatment plant to treat our natural gas. We have committed all natural gas production from our interest in the Madisonville Project to MGP, which has in turn committed to provide treatment capacity of up to 68 MMcf/d for our natural gas. Third parties may seek access to the gas treatment plant through regulatory proceedings, which could restrict our access to the plant, disrupt our production operations and negatively impact our revenues. An example of such a proceeding is the complaint filed by Crimson with the Texas Railroad Commission described under “Properties-Description of the Properties-Texas-The Madisonville Gas Treatment Plant and Gathering Facilities.” On August 9, 2006, the Texas Railroad Commission issued an order requiring MGP to ratably process, take, transport or purchase natural gas produced by Crimson into the Madisonville gas treatment plant. MGP completed additional treating facilities to increase the design capacity from 18 MMcf/d to 68 MMcf/d in November of 2007, but operations in these additional facilities were suspended in December 2007 in order to more effectively deal with the presence of diamondoids in the gas stream produced from the Rodessa Formation. There is no guarantee that we will be able to obtain full access to treatment capacity of up to 68 MMcf/d once the phase-in is completed because, for example, Crimson now has the right to have its natural gas treated at the plant, which may reduce the plant’s ability to treat all of our natural gas, unless the plant’s capacity is further expanded.
Political and/or economic conditions in Indonesia, Canada or the United States could change in manners that negatively affect our operations and prospects in those countries.
Our business activities in Indonesia, Canada and the United States are subject to political and economic risks, including: loss of revenue, property and equipment as a result of unforeseen events like expropriation, nationalization, war, terrorist attacks and insurrection; increases in import, export and transportation regulations and tariffs, taxes and governmental royalties; renegotiation of contracts with governmental entities; changes in laws and policies governing operations of foreign-based companies; exchange controls, currency fluctuations and other uncertainties arising out of foreign government sovereignty over international operations; laws and policies affecting foreign trade, taxation and investment; and the possibility of being subject to the exclusive jurisdiction of foreign courts in connection with legal disputes and the possible inability to subject foreign persons to the jurisdiction of courts in the United States.
Terrorist attacks could have an adverse effect on our oil and natural gas operations, especially overseas.
To date, our operations have not been disrupted by terrorist activity. It is uncertain how terrorist activity will affect us in the future, or what steps, if any, the Indonesian, Canadian or American government may take in response to terrorist activities. The attack on the New York World Trade Center in 2001 and the subsequent wars in Afghanistan and Iraq have increased the likelihood that U.S. citizens and U.S. owned interests may be targeted by terrorist groups operating both in the United States and in foreign countries, especially in Indonesia.
We could lose our entire Production Sharing Contract (“PSC”), if BP Migas ascertains we have not discovered commercially producible hydrocarbons.
It is possible that BP Migas could terminate our entire Production Sharing Contract (“PSC”) if it is determined that the hydrocarbons we have discovered are not in commercially producible quantities. Our Indonesian PSC requires us and our partners to submit to and receive approval from BP Migas for a “Plan of Development” by specified dates in order to maintain our oil and natural gas rights. See “Properties-Description of the Properties-Indonesia.” If we do not establish commerciality and receive an approved Plan of Development for the PSC, or successfully renegotiate the terms, all or part of our contract may be terminated. If this contract is terminated, we would also lose all of our investment in that overseas prospect. If we forfeit our interest in the contract area, it will be necessary to record an impairment write-down equal to the net capitalized costs recorded for the area forfeited. This could have a material adverse impact on our financial condition and results of future operations in future periods. If approval of a Plan of Development is not obtained and if further deferrals of such obligations are not secured, we will need to record an impairment charge equal to the amount of costs capitalized which were approximately $582,946 as of December 31, 2007, and we may lose all of our rights in the Bengara Block.
We may not be able to sell our natural gas production in Indonesia, limiting our ability to obtain a return on our investment there.
Our Indonesian operations lack a local market for natural gas, and if we produce natural gas in Indonesia, it will most likely have to be transported to an area where there is a demand. If no market for natural gas develops locally, we may incur costs for transportation. If we are not able to sell our natural gas production at a commercially acceptable price or at all, we may not be able to obtain a return on our investment in our Indonesian property.
We could lose our ownership interests in our properties due to a title defect of which we are not presently aware.
As is customary in the oil and gas industry, only a perfunctory title examination, if any, is conducted at the time properties believed to be suitable for drilling operations are first acquired. Before starting drilling operations, a more thorough title examination is usually conducted and curative work is performed on known significant title defects. We typically depend upon title opinions prepared at the request of the operator of the property to be drilled. The existence of a title defect on one or more of the properties in which we have an interest could render it worthless and could result in a large expense to our business. Industry standard forms of operating agreements usually provide that the operator of an oil and natural gas property is not to be monetarily liable for loss or impairment of title. The operating agreements to which we are a party provide that, in the event of a monetary loss arising from title failure, the loss shall be borne by all parties in proportion to their interest owned.
Our acquisition activities are subject to uncertainties, may not be successful and provide a return to us on our investments.
We have grown primarily through acquisitions and intend to continue acquiring undeveloped oil and gas properties. Although we perform a review of the properties proposed to be acquired, such reviews are subject to uncertainties. It generally is not feasible to review in detail every individual property involved in an acquisition. Ordinarily, management review efforts are focused on the higher-valued properties; however, even a detailed review of all properties and records may not reveal existing or potential problems; nor will it permit us to become sufficiently familiar with the properties to assess fully their deficiencies and capabilities. Inspections are not always performed on every well, and potential problems, such as mechanical integrity of equipment and environmental conditions that may require significant remedial expenditures, are not necessarily observable even when an inspection is undertaken.
We are dependent upon our key officers and employees and our inability to retain and attract key personnel could significantly hinder our growth strategy and cause our business to fail.
While no assurances can be given that our current management resources will enable us to succeed as planned, a loss of one or more of our current directors, officers or key employees could severely and negatively impact our operations and delay or preclude us from achieving our business objectives. Stuart Doshi, David Creel and Chris Steinhauser, the three members of our senior management team, have a combined experience of approximately 100 years in the oil and gas industry. Although we have entered into employment agreements with Messrs. Doshi, Creel and Steinhauser, we could suffer the loss of key individuals for one reason or another at any time in the future. There is no guarantee that we could attract or locate other individuals with similar skills or experience to carry out our business objectives. We maintain “key man” insurance with respect to our Chief Executive Officer, Stuart Doshi.
Some of our directors may become subject to conflicts of interest which could impair their abilities to act in our best interest.
Nick DeMare, one of our directors, is a director, officer and/or significant shareholder of other natural resource companies and David Anderson, another one of our directors, is a director and officer of Dundee Securities Corporation, an investment banking firm that was the lead underwriter of our public offering of common stock in Canada and concurrent previous private placement of common shares with qualified institutional buyers in the U.S. Their association with these other companies in the oil and gas business may give rise to conflicts of interest from time to time. For example, they could be presented with business opportunities in their capacities as our directors, which they could, in turn, offer to the other companies for whom they also serve as directors, rather than to us, whose interests might be competitive with ours. Our directors are required by law to act honestly and in good faith with a view to our best interests and to disclose any interest which they may have in any project or opportunity to us; however, their interests in the other companies may affect their judgment and cause such directors to act in a manner that is not necessarily in our best interests.
Our directors and officers hold significant positions in our shares and their interests may not always be aligned with those of our other shareholders.
As of December 31, 2007 our directors and officers beneficially own approximately 20% of our outstanding common stock. This shareholding level will allow the directors, officers and certain beneficial owners to have a significant degree of influence on matters that are required to be approved by shareholders, including the election of directors and the approval of significant transactions. The short-term interests of our directors, officers and certain beneficial owners may not always be aligned with the long-term interests of our public shareholders, and vice versa. Because our directors, officers and certain beneficial owners have a significant degree of influence on matters that are required to be approved by our shareholders, they could influence the approval of transactions.
Our failure to manage internal or acquisition-based growth may cause operational difficulties and negatively affect our financial performance.
We expect to experience internal and/or acquisition-based growth, which may bring many challenges. Growth in the number of employees, sales and operations will place additional pressure on already limited resources and infrastructure. No assurances can be given that we will be able to effectively manage this or future growth. Our growth may place a significant strain on our managerial, operational, financial and other resources. Our success will depend upon our ability to manage our growth effectively which will require that we continue to implement and improve our operational, administrative and financial and accounting systems and controls and continue to expand, train and manage our employee base. Our systems, procedures and controls may not be adequate to support our operations and our management may not be able to achieve the rapid execution necessary to exploit the market for our business model. If we are unable to manage internal and/or acquisition-based growth effectively, our business, results of operations and financial condition will be materially adversely affected.
Risks Related to Our Common Stock
The shareholding position of holders of our common stock could be diluted by future issuances and conversions of other securities.
If our options and warrants are exercised for common shares, holders of our common stock will experience immediate and, depending on the magnitude of the exercises, substantial dilution. As of the date of this report, 2,441,688 shares of our common stock are issuable upon exercise of warrants and 2,670,000 shares of our common stock are issuable upon exercise of options.
Investors may be subject to further dilution if we sell additional common shares or issue additional common shares in connection with future financings. If a significant number of our common shares are sold in the public market, the market price of our common shares could be depressed. This could hamper our ability to raise capital by issuing additional equity securities.
Our results may be affected by fluctuations in currency exchange rates.
Our financial statements are reported in U.S. dollars and all of our revenue, and most of our operating costs, are currently denominated in U.S. dollars; however, we have operations outside the United States and we plan to expend money in Indonesia and Canada, where our operating costs will be denominated in local currencies. Fluctuations in exchange rates may increase our relative cost of operating in these countries, and may therefore have a negative effect on our financial results.
Non- U.S. holders of our common shares may be subject to U.S. federal income tax on the sale of our common shares and purchasers may have IRS withholding requirements
Since we believe that we are a United States real property holding corporation, gain recognized by a non U.S. holder on the sale of our common shares will be subject to U.S. federal income tax at normal graduated rates, and a purchaser will be required to withhold for the benefit of the IRS 10% of the purchase price, unless certain trading requirements are met. There is an exemption from U.S. federal income tax for non-U.S. holders of 5% or less of our common shares (and therefore no tax withholding requirements) if our common shares are “regularly traded on an established securities market.” In the event that 100 or fewer persons own 50% or more of our common shares (which had been, may now be and may continue to be, the case), temporary Treasury Regulations provide that our common shares will be “regularly traded on an established securities market” for a calendar quarter if the established securities market is located in the United States and our common shares are regularly quoted by more than one broker or dealer making a market in our common shares; our common shares are currently listed on the American Stock Exchange (which constitutes an established United States securities market for this purpose) and are being regularly quoted. There can be no assurance, however, that our common shares will continue to be regularly traded on an established securities market for this purpose in any particular calendar quarter so as to avoid U.S. federal income tax on the sale of our common shares by non-U.S. holders of 5% or less of our common shares and the withholding requirement on the purchaser.
At such time that it is no longer the case that 100 or fewer persons own 50% or more of our common shares, under temporary Treasury Regulations, our common shares would also be “regularly traded” on an established securities market for a calendar quarter if: (a) our common shares trade, other than in de minimis quantities, on at least 15 days during the calendar quarter; (b) the aggregate number of our common shares traded during the calendar quarter is at least 7.5% of the average number of our common shares outstanding during such calendar quarter (reduced to 2.5% if there are 2,500 or more record shareholders); and (c) in the event that our common shares are traded on an established securities market located outside the United States, the common shares are registered under Sec. 12 of the Securities Exchange Act of 1934 (which is presently the case). See “Material Income Tax Consequences - Dispositions of Common Shares” for a more detailed discussion.
There is a limited public market for our common shares, and the ability of our shareholders to dispose of their common shares may be limited.
Our common shares have been listed on The Toronto Stock Exchange since March 2006, and have been trading on the American Stock Exchange since February 15, 2007. We cannot foresee the degree of liquidity that will be associated with our common shares. A holder of our common shares may not be able to liquidate his, her or its investment in a short time period or at the market prices that currently exist at the time the holder decides to sell. The purchase and sale of relatively small common share positions may result in disproportionately large increases or decreases in the price of our common shares. A trade involving a large number of common shares could have an exaggerated effect on the reported market price of our common shares.
Our stock price may fluctuate significantly.
The stock market in general and the market for natural gas and oil exploration companies have experienced price and volume fluctuations that are often unrelated or disproportionate to the operating results or asset values of companies. These broad market and industry factors may seriously impact the market price and trading volume of our common shares regardless of our actual operating performance. The market price of our common stock could also fluctuate significantly as a result of:
· actual or anticipated quarterly variations in our operating results and our reserve estimates;
· changes in expectations as to our future financial performance or changes in financial estimates, if any, of public market analysts;
· announcements relating to our business or the business of our competitors;
· conditions generally affecting the oil and natural gas industry, including changes in oil and natural gas prices;
· speculation in the press or investment community;
· general market and economic conditions;
· the success of our operating strategy; and
· the operating and stock price performance of other comparable companies.
The sale of large numbers of our common stock may depress the market price of our common stock.
The sale of a substantial number of shares of our common stock in the public market, or the perception that substantial sales may occur, could cause the market price of our common stock to decrease. Substantially all of the shares of our common stock are freely transferable or will be transferable in compliance with restrictions under the Securities Act of 1933, as amended.
We will continue to incur significant expenses as a result of being a public company, which may negatively impact our financial performance.
We have incurred and will continue to incur significant legal, accounting, insurance and other expenses as a result of being a public company. The Sarbanes-Oxley Act of 2002, as well as related rules implemented by the Securities and Exchange Commission, or SEC, and the American Stock Exchange, have required changes in corporate governance practices of public companies. Compliance with these laws, rules and regulations has increased our expenses, including our legal and accounting costs, and made some activities more time-consuming and costly. We also believe these laws, rules and regulations have made it more expensive for us to obtain director and officer liability insurance, and in the future we may be required to accept reduced policy limits and coverage or incur substantially higher costs to obtain the same or similar coverage. As a result, it may be more difficult for us to attract and retain qualified persons to serve on our board of directors or as officers. Furthermore, any additional increases in legal, accounting, insurance and certain other expenses that we may experience in the future could negatively impact our financial performance and have a material adverse effect on our results of operations and financial condition.
Item 1B.
Item 1B. Unresolved Staff Comments
None.
Item 2.
Item 2. Properties
Our principal executive office consists of 2,956 square feet and is located at One Maritime Plaza, Suite 700, San Francisco, CA 94111.
Description of the Properties
Our current oil and natural gas exploration, appraisal and development drilling activities are focused in three distinct project areas as follows:
· United States-Texas (onshore South and East Texas regions), Alaska (onshore Cook Inlet area) and California (onshore San Joaquin basin);
· Canada-Alberta (central Alberta basin); and
· Indonesia-onshore East Kalimantan Province;
We do not fully insure against all business risks either because such insurance is not available or because premium costs are prohibitive. This is a common practice in the oil and gas industry. We believe our property is adequately insured in view of the nature of our operations and industry practices in this regard.
Texas
Madisonville Project, Madison County, East Texas
We own and operate the interest in the Madisonville Project in Madison County, Texas. We own working interests in approximately 4,941 gross and net acres of leases in the Rodessa Formation interval, as well as approximately 4,348 gross and net acres of leases as to depths below the Rodessa Formation interval. We also own a license as to 12.5 square miles of 3-D seismic data over the Madisonville Field.
The Madisonville Field, located approximately 100 miles north of Houston, has produced oil and natural gas from four different horizons above the Rodessa Formation for over 50 years. The field was discovered in 1945 with the Boring No. 1 well, which was drilled to the Rodessa Formation. The well blew out at an uncontrolled rate for three days during a test; however, due to hydrogen sulphide, carbon dioxide and nitrogen in the Rodessa Formation natural gas, the gas reserves were never developed. Over 125 wells were drilled in the Madisonville Field to shallower intervals above the Rodessa Formation. In 1994, nearly 50 years after the initial discovery, United Meridian Corporation (“UMC”) drilled the Magness Well as the first follow-up well into the Rodessa Formation to the Boring No. 1 well. The Magness Well had 139 feet of net pay but the natural gas was found to contain 28% impurities.
UMC previously production tested the Magness Well in 1994 through perforations in the lower most ten feet of the indicated Rodessa Formation pay interval. The well tested at a rate of 12 MMcf/d from this limited interval on a 22/64ths inch choke with flowing wellhead pressures increasing from 3,915 to 3,919 pounds per square inch. In 2001, we re-entered and recompleted the Magness Well. A total of 139 feet of interval has been perforated in the Rodessa Formation at approximately 12,000 feet of depth for this well. The well was production tested over a 12-day period in 2001 on various choke sizes with flowing rates ranging up to approximately 20.8 MMcf/d. We own a 100% working interest (75.1333% net revenue interest) in the Magness Well located in the surrounding production unit consisting of 629 gross and net acres. The Magness Well commenced production in May of 2003.
The first development well, the Fannin Well, was drilled and completed in 2004. We own a 100% working interest (69.2483% net revenue interest) in the Fannin Well located in the surrounding production unit consisting of 704 gross (704 net) acres. A total of 146 feet of indicated pay was perforated in the well and a flow test of the well was completed in December 2004 from the Rodessa Formation at rates of up to 25.7 MMcf/d. We commenced production from the Fannin Well in early 2006.
In 2006, we drilled the Wilson and Mitchell wells. We own a 100% working interest (70% net revenue interest) in the Wilson and Mitchell wells. Presently, the Fannin and Magness wells are producing at a combined restricted rate of approximately 13.5 MMcf/d while the Wilson and Mitchell wells are shut-in. The production rate is presently restricted while awaiting a planned expansion of the Madisonville Field gas treatment plant to 68 MMcf/d treating capacity.
The Madisonville Field is a geologic feature encompassing approximately 5,800 acres at the Rodessa limestone at about 11,800 feet of depth. A 3-D seismic program shot in early 1998 confirmed the size of the structure and slightly increased its size over earlier interpretations.
Our working interest covers the Rodessa Formation at approximately 12,000 feet of depth. The Rodessa reserves are being developed through the recompletion of the Magness Well and the drilling of additional proved and probable undeveloped locations. Production began in May 2003 and stabilized at a rate of 18 MMcf/d of raw gas from the Magness Well. The Magness and Fannin wells are currently producing at a combined restricted rate of approximately 13.5 MMcf/d. Current net sales production is approximately 8 MMcf/d. In addition, we own a working interest in certain leases and farmout rights which cover depths below the Rodessa Formation.
The hydrogen sulphide, carbon dioxide and nitrogen combined comprise about 28% of the gas content. As described below, an unaffiliated third party purchases the untreated natural gas from us at the well site point of delivery for a net price equal to the weighted average price per MMBTU that the third party receives for the natural gas delivered to the sales pipeline less certain gathering, treatment and transportation charges. As a result of the charges, we receive a net price that is substantially lower than we would otherwise receive if the gas did not contain the 28% of impurities. In addition, the high concentrations of hydrogen sulphide and carbon dioxide result in higher capital and operating costs for our wells. For example, the hydrogen sulphide and carbon dioxide are corrosive to the wellbores. This means we have to utilize higher grade specification well tubing and casing which is more expensive than what we would utilize absent the impurities. In addition, we continuously treat the wellbores with chemicals designed to inhibit the corrosive effects of the impurities. We also maintain field personnel at or near the wellsites who monitor the wells on a twenty four hour basis and equip the wellsites with extensive safety equipment systems due to the toxic properties of the hydrogen sulphide and carbon dioxide. These factors and others result in higher capital and operating costs for our wells in the Madisonville Project.
The Madisonville Gas Treatment Plant and Gathering Facilities
In order to produce the proven gas reserves from the Rodessa Formation, we developed an onsite plan to treat and remove impurities from the Madisonville Project natural gas in order to meet pipeline-quality specifications. On June 15, 2001, we, through our subsidiary Redwood LP, entered into an agreement, which agreement was subsequently amended and restated, together with certain related agreements (collectively, the “Hanover Agreement”), with Hanover Compression Limited Partnership pursuant to which Hanover committed to fund, construct and operate a dedicated natural gas treatment plant to process our Rodessa Formation natural gas. The Hanover Agreement also provided for the installation by Gateway of field gathering pipelines and an approximately nine-mile sales pipeline with an estimated capacity of approximately 70 MMcf/d to transport the Madisonville Field natural gas to a major pipeline. By April of 2003, the construction and installation of Hanover’s natural gas treatment plant and Gateway’s associated pipeline and gathering facilities were completed. Gas production from the Magness Well commenced in May 2003. We received the first revenues from the sale of natural gas from the Madisonville Project in July 2003. The natural gas plant is currently capable of treating approximately up to 15 MMcf/d of inlet natural gas.
On July 25, 2005, MGP purchased the natural gas treatment plant from Hanover and purchased the gathering pipelines upstream of the gas treatment plant from Gateway. Concurrent with MGP’s purchase of the gas treatment plant and gathering pipelines, we, through our subsidiary Redwood LP, Gateway and MGP terminated the Hanover Agreement and entered into a new agreement, (the “MGP Agreement”), to treat and transport our gas production from the Madisonville Project. As a result of the MGP Agreement, MGP committed to install and make operational additional treating facilities capable of treating 50 MMcf/d, which combined with the capacity of the current in-service treating facilities will represent a total treating capacity of 68 MMcf/d for the Madisonville treatment plant. The MGP Agreement provides that the newly installed gas treatment facilities will be electrically driven. Currently, the existing in-service treatment plant utilizes some of the natural gas produced and delivered from our well(s). The conversion to electricity on the expanded portion of the treatment plant is expected to reduce shrinkage of our natural gas that occurs in the treating process.
Originally, the MGP Agreement required MGP to complete the additional treating facilities by March 1, 2006. However, due to events of force majeure, construction of the additional treating facilities were just completed in October 2007 and early phase operations at the additional treating facilities were recently suspended. In early November 2007, MGP began accepting 20 million cubic feet of gas per day MMcfd at the inlet of the additional treating facilities. Subsequently in December 2007, MGP temporarily suspended the operations of the additional treating facilities in order to make modifications to more effectively deal with the presence of diamondoids in the gas stream produced from the Rodessa Formation. A diamondoid is a rare, naturally occurring compound that can segregate out of the gas stream upon a decrease in temperature and pressure
and as such, could cause operational problems for the nitrogen rejection portion of the additional treating facilities. MGP has obtained a detailed laboratory composition analysis of the diamondoids and is currently finalizing plans for modifications to the operating system. MGP indicates that removal of the diamondoids will require flowing the natural gas stream through a diesel contactor after the gas stream has had the hydrogen sulfide and carbon dioxide removed. Through this contactor process, the diesel will absorb the diamondoids from the gas stream prior to entry into the nitrogen removal tower. MGP expects to complete installation of the system modifications required in the new plant by the second quarter of 2008. In the meantime, the existing, in service portion of the plant continues to treat approximately 15 million cubic feet per day of inlet gas.
We have proceeded to drill and complete our new development wells notwithstanding MGP’s delay in completing the expansion of the treatment plant and subsequent suspension of operations in December 2007. To the extent that production begins at the new wells before operations resume, as is the case with the Fannin Well which was placed on production in March 2006, production of the wells will be restricted as necessary. The term of the MGP Agreement commenced August 1, 2005 and continues so long as we own any oil and gas leases in the Madisonville Field, provided that it shall terminate on July 31, 2035 unless extended. Under the terms of the MGP Agreement, we have committed all natural gas production from our interest in the Madisonville Project to MGP. MGP purchases the untreated natural gas from us at the well site point of delivery for a net price equal to the weighted average price per MMBTU that MGP receives for the natural gas delivered to the sales pipeline less certain gathering, treatment and transportation charges. The gathering, treatment and transportation price adjustments are described below. All proceeds from MGP’s sale of Rodessa Formation gas are deposited in an escrow account and then disbursed in accordance with the joint direction of MGP and ourselves.
The MGP Agreement provides that certain gathering, treating and transportation fees shall be paid to MGP from the escrow account. The MGP Agreement provides that MGP will receive a gathering and marketing fee of $0.07 and $0.01 per Mcf, respectively, of gas measured and delivered to the natural gas treatment plant. In addition, for the first 18,000 Mcf/d of gas measured and delivered to the inlet flange of the gas treatment plant, MGP will receive a treating fee of $1.50 per Mcf. This treating fee will remain in effect until September 30, 2010. For any gas volumes in excess of 18,000 Mcf/d of gas delivered to the inlet flange of the gas treatment plant, MGP will receive a treating fee of $1.10 per Mcf. Beginning October 1, 2010, this fee of $1.10 per Mcf shall be charged for all gas measured and delivered to the plant. One-quarter (1/4) of the foregoing treating fees are adjusted using the Producer Price Index for Industrial Commodities (“PPI”) and one-quarter (1/4) using the Consumer Price Index (“CPI”). One-half (1/2) of the foregoing gathering and marketing fees are adjusted using the CPI. We have the right, upon giving 60 days notice, to terminate the marketing fee whereupon we shall assume the sole responsibility of marketing the natural gas sold. The PPI and the CPI are price indices published by the U.S. Department of Labor.
For the first 18,000 Mcf/d of gas measured and delivered to the inlet flange of the gas treatment plant, Gateway will receive a transportation fee of $0.10 per Mcf. This fee will remain in effect through July 31, 2008. Beginning August 1, 2008 and terminating on July 31, 2010, the fee shall be reduced to $0.08 per Mcf for the first 18,000 Mcf/d of gas measured and delivered to the inlet flange of the gas treatment plant. For any gas volumes in excess of 18,000 Mcf/d of gas measured and delivered to the inlet flange of the gas treatment plant, Gateway will receive a transportation fee of $0.12 per Mcf measured and delivered from the outlet flange of the plant. This fee will remain in effect through July 31, 2008 and shall be reduced to $0.10 per Mcf thereafter. After July 31, 2010, this transportation fee shall be $0.10 per Mcf for all volumes delivered from the outlet flange of the plant.
The foregoing gathering, treatment and transportation price adjustments are inclusive of all costs and expenses to gather, separate, treat, dehydrate and transport natural gas produced and delivered from our well(s).
Our natural gas deliveries to the Madisonville gas treatment plant may be affected by third party demands for access to the plant. On July 20, 2005 Crimson Exploration Inc. (“Crimson”) filed a complaint with the Texas Railroad Commission (“TRC”) against Gateway and Hanover. The complaint alleged discrimination by Hanover and Gateway, and requested that the TRC issue an order requiring Hanover and Gateway to ratably process, take, transport, or purchase natural gas produced by Crimson into the Madisonville Field gas treatment plant. The complaint did not allege any wrongdoing by Redwood or Redwood LP; however, the complaint referred to the contractual relationship between each of Redwood LP, Hanover, and Gateway which was terminated July 25, 2005 as the basis for its discrimination complaint. Redwood received a subsequent notice dated January 13, 2006 from the TRC informing Redwood that (i) Crimson had filed a request to docket its complaint against MGP for failure to ratably take gas pursuant to Texas regulations and (ii) a pre-hearing conference was held on January 25, 2006 relating to the complaint. Redwood withdrew from the proceeding.
On January 23, 2006, our counsel received a letter from counsel for MGP reaffirming that regardless of the outcome of the proceedings before the TRC, MGP nonetheless recognizes that it has a contractual obligation to treat 68 MMcf/d of natural gas produced by Redwood LP and delivered to the treatment plant. After consultation with legal counsel, we believe that our contract with MGP is fully enforceable.
On August 9, 2006, the Texas Railroad Commission issued an order requiring MGP to ratably process, take, transport or purchase natural gas produced by Crimson into the Madisonville gas treatment plant. The gas treatment plant is currently operating at capacity. There is no guarantee that we will be able to maintain full access to treatment capacity of up to 68 MMcf/d at the Madisonville Plant at all times because, for example, Crimson now has the right to have its natural gas treated at the plant, which may reduce the plant’s ability to treat all of our natural gas, unless the plant’s capacity is further expanded.
To date, Crimson has permitted four wells to be drilled to the Rodessa Formation. The drilling of two of these wells has been completed to a depth of approximately 12,635 feet. Crimson has also drilled an injection well for disposal of waste products resulting from the treatment of their natural gas. Crimson is presently delivering gas to the treatment plant.
We have committed to a three-well drilling program to facilitate the expansion of the gas treatment plant. We have drilled two of the three required wells to the Rodessa formation. The commitment requires us to drill the third well sufficient to test the Smackover Formation (estimated to be encountered at approximately 18,000 feet) on or before September 30, 2008. We estimate the 18,000 foot well will cost $12 million to drill and complete. We have granted MGP a security interest in the Madisonville Field properties to secure the three well commitment. The security interest shall be subordinated to any third party lender in the event we secure future debt against the property. MGP granted us a similar security interest in the gas treatment plant to secure its obligation to expand the treatment plant on a timely basis.
Other Interests in the Madisonville Project
Our working interest in the Madisonville Project is subject to a net profits interest in favor of the third party that sold us our working interests in the Madisonville Project. The net profits interest is 12.5% (proportionately reduced to our interest) of the net operating profits until payout is achieved. After payout, the net profits interest increases to 30% (proportionately reduced to our interest). “Payout”, for purposes of the net profits interest, is defined and achieved at such time as we have recouped from net operating cash flows our total net investment in the Madisonville Project plus a 33% cash on cash return.
South Dry Hollow Project, Lavaca County, South Texas
We own a 15% non-operated working interest in approximately 2,000 gross and 300 net acres of leases in Lavaca County, South Texas. A test well, the Willstar Eichhorn No. 1 well (the “Willstar well”), has commenced drilling and is expected to be drilled to a total depth of 17,000 feet. The primary objective of this well is to test the Rochelle sands in the Lower Wilcox formation. Secondary objectives include the “10,500”, Peck, Dagg, Lampley and Massive sandstone formations in the Wilcox formation. The Willstar well is a vertical well located approximately 800 feet south of the Eichhorn Gas Unit No. 1 well drilled by Newfield Exploration Company (the “Newfield well”) in 2002. The Newfield well was completed in 2002 in the Lampley member of the Wilcox formation at an initial rate of 3.8 MMcfd and has produced approximately 0.9 Bcf of natural gas. The Newstar well also encountered natural gas shows in the Rochelle, “10,500”, Peck, Dagg, and Massive members of the Wilcox formation which were not tested.
Alaska
The Cook Inlet Alaska CBM Project
We entered into an agreement with Pioneer Oil Company, Inc. (“Pioneer”) dated April 20, 2005, wherein we secured the Cook Inlet Option to acquire a 100% working interest, 81% net revenue interest, in approximately 116,806 acres onshore
in Cook Inlet, Alaska. We have since acquired 5,368 additional acres. We believe this acreage to be prospective for both coal bed methane and conventional gas production.
The 122,174 acre lease position consists of two separate target areas that have been selected for exploration. These areas are called the Point MacKenzie and Trading Bay Prospects, respectively.
The Point MacKenzie Prospect is located twelve miles northwest of Anchorage. The Trading Bay Prospect is located 50 miles west of Anchorage across the Cook Inlet. The Cook Inlet basin contains a thick section of terrestrial Tertiary rocks which includes shales, sandstones, and coals. The coals occur in seams which are commonly 20 feet thick and can be as thick as 70 feet. Accessible onshore areas have 200 to 300 feet of coal shallower than 5,000 feet. Gas content for these coals ranges from 80 to 250 standard cubic feet per ton, but testing is restricted to a very small number of bore holes and is almost completely unknown for most of the inlet.
Markets for natural gas in the Cook Inlet area include power generation, heating, fertilizer production and liquefied natural gas exports. An extensive pipeline system supplies these facilities and crosses the Point MacKenzie Prospect and Trading Bay Prospect lease blocks. These pipelines are only partially filled with gas and could accommodate additional production.
In addition to coal bed methane reserve potential, preliminary log analysis indicates the Point MacKenzie Prospect and Trading Bay Prospect lease blocks may also contain conventional accumulations of natural gas reserves in Tertiary sandstones.
The terms of the Cook Inlet Option provide for us to pay total consideration of $20 per acre, or approximately $2.3 million, for the leases. The Cook Inlet Option provides that we will pay the total lease consideration in two installments. We paid the first installment totaling $1,068,063 on August 17, 2005 and we have received assignment of the 100% working interest in the leases. Within three years from the date of receipt of assignment of the 100% working interest in the leases, we have the option to conduct a $2.5 million work program on the leases over a three-year period, and, after completion of the work program and an evaluation of the results, to remit the final additional acreage consideration of $10 per acre for the leases. The Cook Inlet Option provides that if we fail to pay the lease consideration when due, fail to perform the work program or otherwise default under the Cook Inlet Option, we shall forfeit our interest and reassign the leases to Pioneer, and we will have no further liability to Pioneer.
Approximately one to two miles of pipeline will be required to tie in any wells drilled at a currently preferred location at the Point MacKenzie Prospect, and approximately four to five miles of the pipeline will be required to tie in any wells drilled at a currently preferred location at the Trading Bay Prospect. We have not yet prepared an estimate of the cost to tie these wells in.
We are aware of two major pipelines which transverse the acreage blocks, the Enstar 20” line and the UnoCal-Marathon 16” line. We estimate the UnoCal-Marathon 16” line presently has available unused capacity of approximately 40 MMcf/d. In addition, we estimate the Enstar 20” line has available unused capacity of approximately 100 MMcf/d.
California
Lokern Project
We have a working interest in the Lokern Project, located in the southern San Joaquin basin, near Bakersfield, California. The primary exploration objective is the Miocene Stevens formation. The secondary objectives include the Miocene Reef Ridge and Pliocene Etchegoin sands. The Stevens formation is Upper Miocene age.
The Lokern Project is being developed in part as a result of positive results from the Machii-Ross Ackerman show well drilled in 1979 on acreage currently controlled by us. Based on log analysis, we believe that well had approximately 240 feet of potential net oil pay and an additional 150 feet of potential pay in the Stevens zone. The Machii-Ross Ackerman well was drilled to a depth of 15,078 feet by Machii-Ross Petroleum Company and was plugged and abandoned as a dry hole. We believe, based on our log analysis, that the well may have been a bypassed producer.
We expect that a well will be drilled, either by us or through a farmout arrangement with a third party, to a depth of 15,000 feet in 2009.
Based on our review of title information from public authorities and other publicly available sources, we believe that we have a 100% working interest in the Lokern Project. As is customary in the U.S. oil and gas industry, we will not conduct a thorough title review with respect to our interest in the Lokern Project until we have made a definitive decision to drill in a particular lease area.
Alberta
Swan Hills Project
The Swan Hills Project is located in the Central Alberta Basin, Alberta, Canada. The primary exploration objective is the Swan Hills Formation at approximately 9,000 feet. Secondary objectives will include the shallower Gilwood, Nordegg and Falher formations.
We, through our wholly-owned subsidiary, GeoPetro Canada, have reviewed 3-D seismic data over the prospect and plan to participate in the drilling of a test well. We have a 33% working interest in approximately 4,480 leased acres.
Indonesia
C-G Bengara owns 100% of the underlying rights to explore for and produce oil and natural gas within the contract area designated as the Bengara II Block, which rights have been granted under a production sharing contract dated December 4, 1997 (the “Bengara II PSC”) with Pertamina. Previously we owned 40% of CG Bengara and Continental Energy Corporation (“Continental”) owned the remaining 60% and, through it, the rights to the Bengara II PSC. On September 29, 2006, we executed a definitive agreement to sell 70% of our interest in C-G Bengara to CNPCHK (Indonesia) Limited (“CNPC”). We have retained a 12% stake in C-G Bengara and the Bengara II PSC. Continental has likewise sold its interest and retained an 18% interest in C-G Bengara and the Bengara II PSC.
The Bengara Block is located in the Tarakan Basin, mostly onshore but partially offshore astride the Bulungan River Delta in the Indonesian province of East Kalimantan. It originally covered a single contiguous area of approximately 1.2 million gross acres, of which 300,000 gross acres were relinquished in 2001 and an additional 300,000 gross acres were relinquished in 2007 by C-G Bengara in accordance with the terms of the Bengara II PSC. C-G Bengara has tendered an additional relinquishment such that the remaining acreage within the Bengara II PSC total approximately 240,000 acres, or 970 square kilometers. The remaining 240,000 acres is considered by C-G Bengara to be the most prospective portion of the original 1.2 million acre block and is pending approval from BP Migas.
The Makapan Gas Field
Since 1938, only two wells have been drilled in the Bengara Block prior to 2007, one of which resulted in the discovery of the Makapan Gas Field. The Muara Makapan No. 1 well was drilled in 1988 by P.T. Deminex Indonesia from a swamp barge positioned on one of the Bulungan River Delta mouth channel distributaries. The well was drilled to a total depth of 10,800 feet and tested 19.5 million cubic feet of gas per day together with 600 bbls of 54 degree API condensate per day from a 33 feet thick sandstone section near 6,000 feet. The well was plugged and abandoned as a natural gas discovery. Several other gas zones indicated on logs were not tested. The well was not produced nor were any confirmation wells drilled due to the lack of a local natural gas market at the time the well was drilled. The Makapan Gas Field gas is a “Wet’ gas with a high LPG fraction which may be commercial to extract at the wellhead for a third revenue source in addition to the gas and condensate. The Makapan Gas Field lies mostly offshore in very shallow water, less than 10 feet, amidst numerous islands of the Bulungan River Delta.
Exploration in the Bengara Block
We believe that the key to successful prospecting in the Bengara Block will be the identification of traps and understanding sand distribution.
Nearly 2,200 line kilometers of 2-D seismic data available within the Bengara Block appear to be adequate for both detailed and reconnaissance interpretation purposes. Some localized areas may benefit from reprocessing. New seismic data is required in places where insufficient data exists and for prospect confirmation in other locations.
Several separate and unique geologic plays within the Bengara Block as well as a number of prospects and leads have been identified. Some well-defined prospects present immediate drilling targets. Exploration within the Bengara Block is in its formative stages and it is premature to make meaningful resource or reserve estimates. However, the existing exploration work to date indicates that there may be potential petroleum accumulations in the Bengara Block. Analysis of source rocks indicates a propensity for both oil and natural gas.
Terms of Participation in the Bengara Block
The Bengara II PSC is a “standard terms” PSC employed by BP Migas for all oil and natural gas concessions in Indonesia. Generally, the joint venture participants are entitled to receive, from production proceeds, 100% of expenditures in the block as “cost recovery”. Once these costs are recovered, C-G Bengara is entitled to a production share of approximately 26.7% of oil produced and 62.5% of all natural gas produced. We will be entitled to 12% of C-G Bengara’s share of any such production. Sharing terms for certain categories of oil vary slightly as defined in the Bengara II PSC. The term of the contract is thirty years from December 1997 or a shorter period if C-G Bengara elects to terminate its obligations under the contract or if no commercial hydrocarbons are discovered within the contract area. At the end of six years, unless mutually extended by C-G Bengara and BP Migas, the contract expires if no commercially producible hydrocarbons have been discovered in the contract area. C-G Bengara and BP Migas have mutually extended the early termination provisions until December 3, 2008. C-G Bengara may terminate the contract at any time by relinquishing all of its rights and obligations under the contract area. C-G Bengara is required to relinquish 25% of the contract area within the first three years of the contract, a further 25% of the contract area within six years from the commencement of the contract and an additional area within the first ten years so that the area retained thereafter shall not be in excess of 970 square kilometers, or 20% of the original total contract area, whichever is less. C-G Bengara may designate which areas are to be relinquished subject to approval by BP Migas. C-G Bengara’s obligation to relinquish parts of the original contract area under these provisions does not apply to the surface area of any field in which petroleum has been discovered. To date, 600,000 gross acres have been relinquished by C-G Bengara in accordance with the terms of the Bengara II PSC. In 2007, C-G Bengara tendered an additional relinquishment such that the remaining acreage within the Bengara II PSC shall total approximately 240,000 acres, or 970 square kilometers. The remaining 240,000 acres is considered by C-G Bengara to be the most prospective portion of the original 1.2 million acre block and is pending approval from BP Migas.
C-G Bengara is required to pay to BP Migas specified amounts based on achieving certain cumulative production quantities of crude oil from the contract area when and if commercial production is established. These production bonuses are as follows:
In order to maintain the Bengara II PSC in effect, C-G Bengara is required to complete the following work programs and expenditures during the first ten years of the contract, unless the requirement is extended or waived by BP Migas:
C-G Bengara has fulfilled the minimum work and cash expenditure requirements described above. Upon establishing commercial production, if ever, C-G Bengara and BP Migas shall share ratably in the first 20% of oil and natural gas produced in the contract area within a given year according to the percentages specified below. After the first 20% of production, C-G Bengara is entitled to receive 100% of production until cost recovery has been achieved. Cost recovery generally includes 100% of the operating and drilling costs and depreciation of fixed assets applicable to oil and natural gas operations within the contract area. After C-G Bengara has received oil and natural gas production with a value sufficient to achieve cost recovery in a given year, C-G Bengara and BP Migas shall then share ratably in the production according to the percentages specified below:
Upon the completion of five years after commercial production commences, C-G Bengara is further subject to a domestic market obligation. This obligation requires C-G Bengara to sell and deliver to BP Migas, to meet Indonesia’s domestic crude oil needs, a specified quantity of crude oil at a price which is only 15% of the market price of the oil. However, for new fields, for a period of five years starting on the month of the first delivery of crude oil produced from a new field, the fee per barrel for such crude oil supplied to the Indonesian domestic market shall be the market price, with the condition that the excess over the 15% of market price shall preferably be used to assist financing of continued exploration efforts in the contract area.
Upon the first commercial discovery of oil or natural gas in the contract area, BP Migas has the right to demand that 10% of C-G Bengara’s undivided interest in the total rights and obligations under the Bengara II PSC be offered to itself or an entity owned by Indonesian nationals. The 10% interest shall be offered at a dollar amount equal to 10% of C-G Bengara’s cumulative costs incurred in the contract area.
Current and Planned Activities in the Bengara Block
In accordance with the terms of our agreement dated September 29, 2006 which sold 70% of our interest in C-G Bengara to CNPC, CNPC:
1. Purchased 14,000 and 21,000 shares of C-G Bengara from us and Continental, respectively, at a cost of $1 per share. As a result of the transaction, we and Continental own 6,000 and 9,000 C-G Bengara shares, respectively, retaining a 12% and 18% interest in C-G Bengara, respectively.
2. Paid the sum of $18.7 million (the “Earning Obligation”) into a special joint venture account at a Hong Kong international bank. The funds are under joint signature control of CNPC, ourselves and Continental, and are being expended exclusively to pay for 2006 and 2007 exploration and/or appraisal drilling in the Bengara II PSC area.
3. Agreed to provide development loans to pay 100%, and thereby “carry” our share and Continental’s share of all C-G Bengara’s exploitation, drilling, and development expenditures attributable to the Bengara II PSC, after the Earning Obligation funds are expended and a Plan of Development has been approved by BP Migas, until an additional amount of U.S. $41.3 million over and above the Earning Obligation funds has been expended.
4. Agreed to pay a cash bonus totaling $5,000,000, in the proportions of $2,000,000 to us and $3,000,000 to Continental, respectively, contingent upon and within fourteen business days of the receipt by C-G Bengara of the written approval from governmental authorities approving the development of the first commercial oil or gas discovery within the Bengara II PSC contract area.
During 2007, C-G Bengara drilled a total of four wells on the Bengara II PSC. The results are as follows:
A. The Seberaba-1 was originally planned to reach a total depth of 4,000 meters (13,120 feet). Drilling of the Seberaba-1 terminated at a depth of 2,914 meters (9,558 feet) in the third of three sidetracks made from the original wellbore. Testing activity of the Seberaba-1 has been suspended. Approximately 150 barrels of crude oil has been recovered by swabbing. Flow test and pressure build up tests to date have proved inconclusive due to apparent formation damage. Any future re-entry is expected to be conducted with a different drilling mud and testing fluid program to avoid damage to the target reservoir intervals.
B. Drilling of the Seberaba-3 has been completed to a total depth of 2,594 meters (8,508 feet). An open hole drill stem test successfully flowed oil and minor gas at surface from one zone. The open hole test confirms lateral continuity of the Seberaba reservoir with at least one of the three zones from which oil was recovered during testing of the Seberaba-1 discovery well. The Seberaba-3 has been logged and casing has been set.
C. Drilling activity on the Seberaba-4 has been terminated. Seberaba-4 failed to encounter an expected reservoir sand anticipated at 2,450 meters (8,036 feet) probably because the wellbore penetrated a normal fault and the expected reservoir interval was faulted out. The Seberaba-4 wellbore has been suspended and preserved for possible re-entry.
D. Drilling of the Punga-1 has been completed at a total depth of 2,500 meters (8,200 feet). The well has been logged and casing has been set. A testing program may be conducted in the future by CG-B2 to evaluate zones with oil and gas shows.
The technical information provided by drilling and testing results to date confirm the presence of an oil accumulation. However the data is not yet adequate to conclusively demonstrate the extent of the oil accumulation or that it has sufficient size of oil reserves to economically justify a full commercial development. Further technical information is required prior to commencing development. C-G Bengara has prepared a preliminary plan of development for the Seberaba discovery based upon drilling and testing results from the Seberaba-1 and 3 wells. Further testing of the Punga-1 well and Seberaba-3 well is expected to be conducted in 2008. In addition to these well test results, C-G Bengara feels additional technical information is needed prior to finalizing the formal plan of development and submitting it for approval to Indonesian oil and gas authorities. Approval of the formal plan of development will automatically invoke the final 20-year production period of the Bengara-II PSC through December 3, 2027. C-G Bengara has submitted the preliminary plan to the Indonesian authorities together with a request for additional time of three years to implement the plan and thereby obtain the additional data needed to further appraise and prove up the Seberaba discovery prior to completing and submitting the formal plan of development. Approval is expected but not assured.
CG Xploration
In November 2005, we and Continental formed CG Xploration to pursue new venture oil and gas exploration and production projects and obtain new exploration concessions in Indonesia. CG Xploration Inc. is incorporated in Delaware and is owned 50% by us and 50% by Continental. CG Xploration Inc. will actively pursue and may acquire new venture opportunities on behalf of ourselves and Continental. To date, CG Xploration has made no acquisitions.
Natural Gas Reserves
Our estimated total net proved reserves of natural gas and oil as of December 31, 2007, 2006 and 2005, and the present values of estimated future net revenues attributable to those reserves as of those dates, are presented in the following tables.
“Proved developed oil and gas reserves” means reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.
“Proved developed nonproducing reserves” means reserves expected to be recovered from zones behind casing in existing wells.
“Proved oil and gas reserves” means estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.
(i) Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes (A) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and (B) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.
(ii) Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the “proved” classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.
(iii) Estimates of proved reserves do not include the following:
(A) oil that may become available from known reservoirs but is classified separately as “indicated additional reserves”;
(B) crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors;
(C) crude oil, natural gas, and natural gas liquids, that may occur in undrilled prospects; and
(D) crude oil, natural gas, and natural gas liquids, that may be recovered from oil shales, coal, gilsonite and other such sources.
“Proved undeveloped reserves” means reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimate for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.
The 2007 and 2006 estimates were prepared by MHA Petroleum Consultants, independent reservoir engineers, and are part of their reserve reports on our natural gas and oil properties. The 2005 estimates were prepared by Sproule Associates Inc., independent reservoir engineers, and are part of their reserve reports on our natural gas and oil properties. MHA Petroleum Consultants’ and Sproule Associates Inc.’s estimates were based on a review of geologic, economic, ownership and engineering data that we provided. In estimating the reserve quantities that are economically recoverable, MHA Petroleum Consultants and Sproule Associates Inc. used end-of-period natural gas and oil prices. In accordance with U.S. Securities and Exchange Commission regulations, no price or cost escalation or reduction was considered. All of our proved reserves are attributable to our Madisonville Project in Madison County, Texas.
In accordance with Securities and Exchange Commission regulations, estimates of our proved reserves and future net revenues are made using sales prices estimated to be in effect as of the date of such reserve estimates and are held constant throughout the life of the properties, except to the extent a contract specifically provides for escalation. Estimated quantities of proved reserves and future net revenues therefrom are affected by natural gas and oil prices, which have fluctuated significantly in recent years. We filed reports with the U.S. Department of Energy in June 2007 and the Alberta Securities Commission in March 2007 that included total proved reserves inclusive of royalties and net profits interests as of December 31, 2006 totaling 43,517 MMcf. The total net proved reserves, excluding royalties and net profits interests, as of December 31, 2006 was 24,600 MMcf. The difference between the two numbers represents proved reserves attributable to royalties and net profits interests.
Standardized Measure of Discounted Future Net Cash Flows
For purposes of the following disclosures, estimates were made of quantities of proved reserves and the periods during which they are expected to be produced. Future cash flows were computed by applying year-end prices to estimated annual future production from proved gas reserves. The average year-end prices for gas were as indicated below. Future development drilling and production costs were computed by applying year-end costs to be incurred in producing and further developing the proved reserves. Future income tax expenses were computed by applying, generally, year-end statutory tax rates (adjusted for permanent differences, tax credits and allowances) to the estimated net future pre-tax cash flows. The discount was computed by application of a 10% discount factor. The calculations assume the continuation of existing economic, operating and contractual conditions. However, such arbitrary assumptions have not proven to be the case in the past. Other assumptions of equal validity could give rise to substantially different results.
Pricing Assumptions
SEC regulations require that the gas and oil prices used in the MHA Petroleum Consultants and Sproule Associates Inc. reserve reports included herewith are the period-end prices for natural gas at December 31, 2007, 2006 and 2005, respectively. These prices are projected without inflation for the life of the wells included in the reserve reports. The pricing assumptions are listed below:
Drilling Activities
The following indicates the number of natural gas and oil wells drilled during the periods indicated.
Acreage and Productive Wells
The following table sets forth our ownership interest in undeveloped acreage, developed acreage and productive wells in the areas indicated where we own a working interest as of December 31, 2007. Gross represents the total number of acres or wells in which we own a working interest. Net represents our proportionate working interest resulting from our ownership in gross acres or wells. Productive wells are wells in which we have a working interest and that are capable of producing natural gas or oil. Wells that are completed in more than one producing horizon are counted as one well.
The following table sets forth as of December 31, 2007, the expiration periods of the gross and net undeveloped acreage:
Volumes, Prices and Production Costs
Substantially all of our production is derived from our Madisonville Project in Madison County, Texas. The following table sets forth information with respect to our production volumes, average prices received and average production costs for the periods indicated:
(1) Represents sales price realized net of treatment costs.
Business Risks and Other Special Considerations
Refer to “Risk Factors” in this report for a discussion of business risks and other special considerations.
Item 3.
Item 3. Legal Proceedings
From time to time, we are party to litigation or other legal and administrative proceedings that we consider to be a part of the ordinary course of our business. Currently, we are not involved in any legal proceedings nor are we party to any pending or threatened claims that could, individually or in the aggregate, reasonably be expected to have a material adverse effect on our financial condition, cash flow or results of operations.
Item 4.
Item 4. Submission of Matters to a Vote of Security Holders
Not applicable.
PART II
Item 5.
Item 5. Market for the Registrant’s Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities
Our common stock trades on the American Stock Exchange under the symbol “GPR”. Our common stock is also listed on the Toronto Stock Exchange under the symbol “GEP.s”. On March 28, 2008, the last reported sale prices for our common stock on the American Stock Exchange and Toronto Stock Exchange were $2.65 and $2.60, respectively. The following table sets forth the high and low sale prices of our common shares as reported on the American Stock Exchange and the Toronto Stock Exchange and bid prices as quoted in the United States in the “pink sheets” over-the-counter market for the periods presented. Prior to the first quarter of 2006, there was no trading market for our common shares.
(1) Our common stock commenced trading on the American Stock Exchange on February 15, 2007.
(2) Our common stock is quoted in U.S. dollars on the Toronto Stock Exchange. Our common stock commenced trading on the Toronto Stock Exchange on March 30, 2006.
As of March 28, 2008, there were 369 holders of record of our common shares.
Over-the-counter market quotations reflect inter-dealer prices, without retail mark-up, mark-down or commission, and may not necessarily represent actual transactions.
Dividends
On March 28, 2007, all outstanding shares of Series AA 8% Convertible Preferred Stock converted to common shares. Dividends on Series AA preferred stock are no longer payable. The holders of Series AA preferred stock were entitled to receive ratably such cash dividends, as were declared from time to time by the board of directors out of funds legally available therefore and, when declared, dividends were paid at the rate of $0.28 per share per annum, paid on a calendar quarter basis. Prior to the conversion, we had declared and paid dividends on a quarterly basis with respect to all outstanding shares of Series AA preferred stock at the rate of $0.28 per share per year from the time the Series AA stock was issued.
The holders of our common stock shall be entitled to receive ratably such lawful dividends as may be declared by the Board of Directors. We have never paid any dividends, whether cash or property, on our common stock. For the foreseeable future it is anticipated that any earnings which may be generated from our operations will be used to finance our growth and that dividends will not be paid to common stockholders.
Use of Proceeds
On our registration statement on Form S-1 (Reg. No. 333-135485) we registered up to 16,499,991 shares of our common stock, no par value per share, including 5,943,105 shares of common stock issuable upon exercise of warrants and options, for resale by selling shareholders. The registration statement was declared effective by the Securities and Exchange Commission in February 2007. The offering commenced on in February 2007 and has not terminated. On our registration statement on Form S-1 (Reg. No. 333-146557) we registered up to 2,002,599 shares of outstanding common stock and the resale of up to 780,857 shares of common stock issuable upon exercise of warrants, for resale by selling shareholders. The registration statement was declared effective by the Securities and Exchange Commission in October 2007. The offering commenced in October 2007 and has not terminated. We will not receive any proceeds from the sale of our common stock by the selling shareholders under the registration statements; however if all warrants and options to acquire our common stock being registered thereunder are exercised, we will realize cash proceeds of approximately $13,787,973, which we expect to use for general working capital purposes and the drilling of wells in our Texas, Alaska, California and Indonesian prospects.
If less than the $13,787,973 proceeds are realized from the exercise of such warrants and options, the proceeds will be spent in the following order of priority:
1. Alaska Cook Inlet Project, up to approximately $3.0 million will be expended for the drilling of pilot program wells.
2. Madisonville Project, Madison County, Texas. Up to approximately $12 million will be expended in the Madisonville Field area towards the drilling and completion of one deep exploratory well location to an estimated depth of 18,000 feet.
3. General working capital.
We do not know if, or how many, of the warrants or options will be exercised. This is our best estimate of our use of proceeds generated from the possible exercise of warrants or options based on the current state of our business operations, our current plans and current economic and industry conditions. Any changes in the projected use of proceeds will be made at the sole discretion of our board of directors.
Unregistered Sales of Securities
On November 1, 2007, we issued 50,000 shares of common stock to an officer and director, an accredited investor, pursuant to an exercise of stock options at $2.00 per share for proceeds of $100,000. On November 29, 2007 we issued 50,000 shares of common stock to a former officer and director, pursuant to an exercise of stock options at $2.00 per share for proceeds of $100,000. These shares were issued pursuant to Rule 701 promulgated under the Securities Act, in that they were offered and sold pursuant to a written contract relating to compensation, as provided by Rule 701.
On November 9, 2007, we issued 18,000 shares of common stock pursuant to an exercise of stock warrants at $3.50 per share for proceeds of $63,000. These shares were issued to one investor. The private placement was exempt from the registration requirements of the Securities Act pursuant to Section 4(2) of the Securities Act and Rule 506 of Regulation D. The investor in the private placement was either an accredited investor, as defined in Rule 501(a), or one we reasonably believed to be. The purchase agreement signed by the investor contained customary and appropriate representations and warranties regarding the investor’s status as an accredited investor, and that the investor was acquiring the securities for his or her own account and not with a view to resale or distribution. It also contained questions further attesting to his or her status as an accredited investor. In addition, we did not accomplish the offer or sale of the securities sold in the private placement through any manner of general solicitation or general advertising. Moreover, it was disclosed to the investor prior to sale that, except as otherwise may be provided in any registration rights granted to him or her, the securities purchased would not be registered under the Securities Act and could therefore not be resold unless first registered under the Securities Act or an exemption from registration was available. We placed a legend on each certificate representing the securities sold stating that the securities have not been registered under the Securities Act and further setting forth customary and appropriate restrictions on the transferability of the securities. Finally, we made available to the investor, prior to purchase, the opportunity to ask questions and receive answers concerning the terms and conditions of the private placement.
During December 2007, we issued 121,662 shares of common stock to one individual who is both an officer and a director, two individuals who are directors, and one individual who is an employee, all pursuant to a net exercise of stock options. All of the options were exercisable at $2.00 per share. A net exercise is the security holder’s election to receive that
number of shares of our common stock that is equal to the quotient of: i) the fair market value of such shares, less the exercise price then in effect, multiplied by the number of shares that the security holder would otherwise have been entitled to purchase; over ii) the fair market value of the common stock. In the case of those individuals who were employees at the time of exercise, the number of common shares issued to these individuals is further reduced by the quotient of: the employee’s shares of payroll taxes attributable to the option exercise over the fair market value of the common stock. The common shares issued pursuant to the net exercise were as follows:
These shares were issued pursuant to Rule 701 promulgated under the Securities Act, in that they were offered and sold pursuant to a written contract relating to compensation, as provided by Rule 701.
In December 2007, we issued 128,301 shares of common stock to an individual who is both an officer and director pursuant to a net exercise of stock options at $2.00 per share. Because the individual was an employee at the time of exercise, the number of common shares issued to this individual was further reduced by the quotient of: the employee’s share of payroll taxes attributable to the option exercise over the fair market value of the common stock. The private placement was exempt from the registration requirements of the Securities Act pursuant to Section 4(2) of the Securities Act and Rule 506 of Regulation D. The investor in the private placement was an accredited investor, as defined in Rule 501(a). The option exercise agreement signed by the investor contained customary and appropriate representations and warranties regarding the investor’s status as an accredited investor, and that the investor was acquiring the securities for his or her own account and not with a view to resale or distribution. It also contained questions further attesting to his or her status as an accredited investor. In addition, we did not accomplish the offer or sale of the securities sold in the private placement through any manner of general solicitation or general advertising. Moreover, it was disclosed to the investor prior to sale that, except as otherwise may be provided in any registration rights granted to him or her, the securities purchased would not be registered under the Securities Act and could therefore not be resold unless first registered under the Securities Act or an exemption from registration was available. We placed a legend on each certificate representing the securities sold stating that the securities have not been registered under the Securities Act and further setting forth customary and appropriate restrictions on the transferability of the securities. Finally, we made available to the investor, prior to purchase, the opportunity to ask questions and receive answers concerning the terms and conditions of the private placement.
Performance Graph
The following graph shows a comparison from February 15, 2007 (the date our common stock began trading on the American Stock Exchange) through December 31, 2007 of cumulative stockholders total return for our common stock, companies we deem to be in our industry peer group and the Russell Microcap Index (IWC). The comparable companies are Kodiak Oil and Gas Corporation (KOG), Petro Resources Corporation (PRC), and American Oil & Gas Incorporated (AEZ).
All of these cumulative returns are computed assuming the value of the investment in GeoPetro common stock and each stock as $100.00 on February 15, 2007, and the reinvestment of dividends at the frequency with which dividends were paid during the applicable months. The months compared are February through December of 2007. Since our common stock began trading on the American Stock Exchange, we have not declared any dividends to be paid to our common stockholders and do not have any present plans to declare dividends.
COMPARISON OF CUMULATIVE RETURN AMONG GEOPETRO RESOURCES COMPANY,
RUSSELL MICROCAP INDEX (“IWC”) AND SELECTED PEER GROUP ISSUERS
Item 6.
Item 6. Selected Consolidated Financial Data
The following selected consolidated financial data should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our consolidated financial statements and the related notes to those statements included elsewhere in this report. The consolidated statements of operations data for the years ended December 31, 2005, 2006 and 2007 and the balance sheet data as of December 31, 2006 and 2007 are derived from our audited consolidated financial statements included elsewhere in this report. The consolidated statements of operations data for the years ended December 31, 2003 and 2004 and the balance sheet data as of December 31, 2003, 2004 and 2005 are derived from our audited consolidated financial statements not included in this report. Historical results are not necessarily indicative of the results to be expected in the future, and the results for the years presented should not be considered indicative of our future results of operations.
Item 7.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis should be read in conjunction with accompanying financial statements and related notes included elsewhere in this report. It contains forward looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward looking statements.
Factors that could cause or contribute to such differences include, but are not limited to, market prices for natural gas and oil, economic and competitive conditions, regulatory changes, estimates of proved reserves, potential failure to achieve production from development drilling projects, capital expenditures and other uncertainties, as well as those factors discussed below and elsewhere in this report, particularly in “Risk Factors” and “Cautionary Notes Regarding Forward Looking Statements”, all of which are difficult to predict and which expressly qualify all subsequent oral and written forward-looking statements attributable to us or persons acting on our behalf. In light of these risks, uncertainties and assumptions, the forward looking events discussed may not occur. We do not have any intention or obligation to update forward-looking statements included in this report after the date of this report, except as required by law.
Overview
We are an oil and gas company in the business of exploring and developing oil and natural gas reserves on a worldwide basis. Since inception, we have conducted leasehold acquisition, exploration and drilling activities on our North American, Australian and Indonesian prospects. These projects currently encompass approximately 372,317 gross (158,401 net) acres, consisting of mineral leases, production sharing contracts and exploration permits that give us the right to explore for, develop and produce oil and natural gas. Most of these properties are in the exploration, appraisal or development drilling phase and have not begun to produce revenue from the sale of oil and natural gas. Excluding minor interest and dividend income, our only significant cash inflows until 2003 were the recovery of capital invested in projects through sale or other divestiture of interests in oil and gas prospects to industry partners.
Since 2003, substantially all of our revenue has been generated from natural gas sales derived from the Magness #1, the Fannin #1, and the Mitchell #1 wells in the Madisonville Field in East Texas under spot gas purchase contracts at market prices. Natural gas sales from the Madisonville Field are expected to account for substantially all of our revenues for 2008. We expect the majority of our capital expenditures in 2008 to be the costs of drilling and completing wells in the Madisonville Field.
Revenue and Operating Trends in
As discussed in the “Properties - Texas - Madisonville Project” section in this prospectus, in order to produce the gas reserves from the Rodessa Formation, we developed an onsite plan to treat and remove impurities from the Madisonville Project natural gas in order to meet pipeline-quality specifications. In 2003, the construction and installation of a natural gas treatment plant with a designed capacity of 18 million cubic feet of gas per day (“MMcf/d”) and associated pipeline and gathering facilities were completed. The treatment plant and associated pipeline and gathering facilities are owned by an unaffiliated third party.
In 2005 we secured a commitment from MGP to install and make operational additional treating facilities capable of treating 50 MMcf/d, which combined with the capacity of the current in-service treating facilities will represent a total designed treating capacity of 68 MMcf/d for the Madisonville treatment plant. In early October 2007, MGP completed the additional treating facilities and the additional treating capacity at such facilities was being phased in. In December 2007, the phase-in of operations at the additional treating facilities were suspended in order to make modifications to deal with the
presence of diamondoids in the gas stream produced from the Rodessa Formation, which modifications are expected to be completed by the second quarter of 2008.
Upon completion of the phase-in, we expect to produce our wells at a higher rate as the well rates have previously been restricted due to capacity limitations in the gas treatment plant. In addition, we expect to fracture stimulate the Wilson Well in the second or third quarter of 2007, and provided such stimulation is successful, we will place the Wilson Well on production.
In addition, our contract with MGP provides that for the first 18,000 Mcf/d of gas measured and delivered to the inlet flange of the gas treatment plant, MGP will receive a treating fee of $1.50 per thousand cubic feet (“Mcf”) (this fee is presently $1.55 per Mcf adjusted for inflation). For any gas volumes in excess of 18,000 Mcf/d of gas delivered to the inlet flange of the gas treatment plant, the treating fee received by MGP is reduced from $1.50 to $1.10 per Mcf ($1.14 per Mcf adjusted for inflation). We record our revenues net of these treating fees. Thus, if we are able to increase our inlet production volumes over 18 MMcf/d on a sustained basis, we expect to experience a disproportionately higher increase in revenue due to lower average treating fees per Mcf.
While there can be no assurance, the higher production rates from our wells combined with the lower average treating fees per Mcf, may result in higher net production and increased revenue during 2008 as compared to 2007 and prior periods.
Industry Overview for the year ended December 31, 2007
The twelve months ended December 31, 2007 saw strengthening natural gas prices. The Houston Ship Channel price, the index price prevailing in the locale of our Madisonville Project in Madison County, Texas, as quoted in Gas Daily as of December 28, 2007, was $6.81 per Mcf versus $5.40 per Mcf as of December 29, 2006. Natural gas prices improved during the year due to higher demand induced by cold temperatures experienced in many parts of the United States, among other factors.
Company Overview in 2007
Our net loss after taxes for the year ended December 31, 2007 was $1,616,804. From our inception, through mid-2003, we only received nominal revenues from our oil and natural gas activities, while incurring substantial acquisition and exploration costs and overhead expenses which have resulted in an accumulated deficit through December 31, 2007 of $12,010,789. Commencing in May 2003, we placed our Madisonville Project into production. Substantially all of our oil and natural gas sales for the year ended December 31, 2007 were derived from our Madisonville Project, from three producing wells, the UMC Ruby Magness #1 well (the “Magness Well”), the Angela Farris Fannin #1 well (the “Fannin Well”), and the Mitchell #1 well (the “Mitchell Well”).
Comparison of Results of Operations for the year ended December 31, 2007 and 2006
During the twelve months ended December 31, 2007, we had oil and natural gas revenues of $6,890,777. Our net production was 2,005,359 Mcf of natural gas at an average price of $3.44 per Mcf. During the twelve months ended December 31, 2006, we had oil and natural gas revenues of $6,716,360. Our net production for the twelve months ended December 31, 2006 was 2,229,059 Mcf at an average price of $3.01 per Mcf. Revenues increased in the twelve months ended December 31, 2007 as compared to the prior year period due to higher gas prices but 10% lower production volumes. Prices were approximately 14% higher for the twelve months ended December 31, 2007 versus the same period in 2006.
During the twelve months ended December 31, 2007, we incurred lease operating expense of $1,558,900. Our average lifting cost for the 2007 period was $0.78 per Mcf. During the twelve months ended December 31, 2006, we incurred lease operating expense of $1,602,932. Our average lifting cost for the 2006 period was $0.72 per Mcf. The average lifting cost per Mcf in 2006 was lower due to higher production volume in 2006.
During the twelve months ended December 31, 2007, we incurred net profits interest expense of $679,337 associated with the Magness, the Fannin, and the Mitchell wells as compared to $632,708 during the twelve months ended December 31, 2006. The 7% increase resulted from higher gas prices in the twelve months ended December 31, 2007 versus 2006. The net profit interest is 12.5% of the net operating profit from our Magness, Fannin, and Mitchell wells.
General and administrative (“G&A”) expenses for the twelve months ended December 31, 2007 were $2,807,091 compared to $2,347,447 for the twelve months ended December 31, 2006. This represents a $459,644 increase over the prior
year period due primarily to U.S. and Canada public company filing fees, costs associated with our SEC registration statement, and ongoing filing requirements. The $459,644 increase over the prior year period due to primarily to:
1. $128,232 in filing fees related to our SEC registration,
2. $331,412 public company filing fees in U.S. and Canada, ongoing filing requirements and costs associated with SEC compliance.
For the year ended December 31, 2007, impairment expense was incurred in amount of $1,111,151 as compared to $38,849 in the same period of 2006. The 2007 and 2006 impairment write-downs were due to dry holes drilled associated with the Canadian oil and gas properties, which resulted in ceiling test write downs.
Depreciation, depletion and amortization expense (“DD&A”) for the twelve months ended December 31, 2007 was $2,269,995 as compared to $2,406,612 in the same period of 2006, which amounts primarily represent amortization of the oil and gas properties for the twelve months ended December 31, 2007 and 2006, respectively. The decrease was due to lower net production in the twelve months period of 2007 and an increase in the amount of capitalized cost in the U.S. oil and gas properties.
Loss from operations totaled $1,535,697 for the twelve months ended December 31, 2007 as compared to $312,188 for the twelve months ended December 31, 2006. The increase in the loss from operations was due primarily to higher G&A cost and impairment expense associated with the Canadian oil and gas properties in the twelve months ended December 31, 2007 versus 2006.
Other income for the twelve months ended December 31, 2007 and 2006 consisted of interest income in the amount of $174,560 and $198,050, respectively. The reason for the decreased interest income was lower average cash and cash equivalent balances during the 2007 period as compared to 2006 period.
During the twelve months ended December 31, 2007 and 2006, we incurred interest expense of $306,340 and $306,682, respectively. The interest expense comparisons between the year ended 2007 and 2006 were relatively consistent.
Net loss before taxes for the twelve months ended December 31, 2007 was $1,667,477 as compared to $420,820 for the twelve months ended December 31, 2006. The increase in net loss during the twelve months ended December 31, 2007 was primarily due to higher G&A cost and Canadian impairment write-off in the twelve months ended December 31, 2007 versus 2006.
Income tax refund for the twelve months ended December 31, 2007 was $50,673 compared to income tax expense of $61,586 in the same period of 2006. Income tax benefit in 2007 was due to a refund of prior year alternative minimum tax paid offset by a current year state tax payable.
Industry Overview for the Year Ended December 31, 2006
The year 2006 saw softening natural gas prices. The Houston Ship Channel price, the index price prevailing in the locale of our Madisonville Project in Madison County, Texas, as quoted in Gas Daily as of December 29, 2006, was $5.40 versus $7.80 as of December 31, 2005. In the year of 2005, the natural gas prices were strong as a result of hurricane related supply disruptions and generally tight supplies of natural gas in the United States. Availability of capital, particularly equity capital for junior oil and natural gas companies, continued to show improvement in 2006. As a result of the initial public offering in Canada in March 2006, we were able to drill two wells in our Madisonville Project during 2006.
Company Overview in 2006
Our net loss after taxes for the year ended December 31, 2006 was $1,011,806. From our inception, through mid-2003, we only received nominal revenues from our oil and natural gas activities, while incurring substantial acquisition and exploration costs and overhead expenses which have resulted in an accumulated deficit through December 31, 2006 of $10,393,985. Commencing in May 2003, we placed our Madisonville Project into production. Substantially all of our oil and natural gas sales for the year ended December 31, 2006 were derived from our Madisonville Project, from two producing wells, the UMC Ruby Magness #1 well (the “Magness Well”) and the Angela Farris Fannin #1 well (the “Fannin Well”).
Comparison of Results of Operations for the twelve months ended December 31, 2006 and
During the twelve months ended December 31, 2006, we had oil and natural gas revenues of $6,716,360. Our net production was 2,229,059 thousand cubic feet (Mcf) of natural gas at an average price of $3.01 per Mcf. During the twelve months ended December 31, 2005, we had oil and natural gas revenues of $7,975,990. Our net production for the twelve months ended December 31, 2005 was 1,991,105 Mcf at an average price of $4.01 per Mcf. Revenues decreased in the twelve months ended December 31, 2006 as compared to the prior year period due to lower gas prices in spite of 12% higher production volumes. Prices were approximately 25% lower for the twelve months ended December 31, 2006 versus the same period in 2005.
During the twelve months ended December 31, 2006, we incurred lease operating expenses of $1,602,932. Our average lifting cost for the 2006 period was $0.72 per Mcf. During the twelve months ended December 31, 2005, we incurred lease operating expenses of $878,176. Our average lifting cost for the 2005 period was $0.44 per Mcf. The higher average lifting cost in 2006 was due to higher lease operating costs and production taxes attributable to the Fannin #1 well. The primary reason for the increase in average lifting cost per Mcf were increases in production costs related to the Fannin #1 well which was placed in production in March 2006. The production for the Magness and the Fannin wells is at present limited to the current treatment plant’s capacity of up to 18,000 Mcf/d. Therefore, the production from the Fannin #1 and the Magness #1 wells is limited to a rate that is below the combined productive flow capability of the wells. A majority of the lease operating costs are fixed costs such as chemical treatments for the wells, insurance, ad valorem tax, and salaries paid to the field personnel. During the twelve months ended December 31, 2006, the total lease operating costs for the Magness #1 well were $752,924 versus $878,176 in the same period of 2005. The net production of the Magness #1 well was 1,155,840 Mcf for the twelve months ended December 31, 2006 compared to 1,991,105 Mcf in same period of 2005. Some of the production decrease is attributable to natural declines and some of the decrease is attributable to the fact that the Magness #1 well shared the treating capacity of the treatment plant with the Fannin #1 well in 2006 whereas in the comparable 2005 period it did not. As a result, the average lifting cost for Magness #1 well was $0.65 per Mcf for the twelve months ended December 31, 2006 versus $0.44 per Mcf in the same period of 2005. The Fannin #1 well’s average lifting cost was higher than the Magness #1 well due mainly to the severance tax of $230,600 which was incurred on the Fannin #1 well for the twelve months ended December 31, 2006. The Magness #1 well is exempt from the severance tax. The average lifting cost for the Fannin #1 well was $0.79 per Mcf for the twelve months ended December 31, 2006.
During the twelve months ended December 31, 2006, we incurred net profits interest expense of $632,708 associated with the Magness and Fannin wells as compared to $856,837 during the twelve months ended December 31, 2005. The 26% decrease resulted from lower net revenues from the wells in the twelve months ended December 31, 2006 versus 2005. The net profits interest is 12.5% of the net operating profits from our Magness and Fannin wells.
General and administrative expenses for the twelve months ended December 31, 2006 were $2,347,447 compared to $1,551,747 for the twelve months ended December 31, 2005. This represents a $795,700 increase over the prior year period due to primarily to:
1. $198,000 of stock based compensation,
2. a $265,000 increase in directors and officers liability insurance,
3. $48,000 in filing fees related to our public listing on the Toronto Stock Exchange; and
4. $285,000 in legal, audit, printing and filing fees associated with the S-1 registration statement which was prepared for the resale of some of our common stock.
For the year ended December 31, 2006, impairment expense was incurred in amount of $38,849 as compared to $0 in the same period of 2005. The 2006 impairment write-downs were associated with the Canadian cost pool. The remaining costs of drilling a dry hole in Canada of $38,849 were expensed in 2006.
Depreciation, depletion and amortization expense, also known as DD&A, for the twelve months ended December 31, 2006 was $2,406,612 as compared to $1,832,693 in the same period of 2005, which amounts represent amortization of the U.S. full cost pool for the twelve months ended December 31, 2006 and 2005, respectively. The increase was due to higher
net production in the twelve months period of 2006 and an increase in the amount of capitalized cost in the U.S. full cost pool.
Loss from operations totaled $312,188 for the twelve months ended December 31, 2006 as compared to income from operations of $2,856,537 for the twelve months ended December 31, 2005. The decrease in the income from operations was due primarily to lower gas prices, higher lease operating expenses, and higher G&A expenses.
Other income for the twelve months ended December 31, 2006 and 2005 consisted of interest income in the amount of $198,050 and $18,969, respectively. The reason for the increased interest income was higher average cash and cash equivalent balances during 2006 period as compared to 2005 period resulting from net proceeds received from common stock offerings completed by us in 2006.
During the twelve months ended December 31, 2006 and 2005, we incurred interest expense of $306,682 and $217,768, respectively. The higher interest expense in the current year period was due to $194,691 in expense related to the amortization of debt issuance costs in connection with a debt financing in January 2006 consisting of: (i) the fair market value assigned to common stock warrants issued, and (ii) a loan origination fee paid.
Net loss before taxes for the twelve months ended December 31, 2006 was $420,820 as compared to net income before taxes of $2,657,738 for the twelve months ended December 31, 2005. The loss incurred during 2006 was primarily due to lower gas income, higher lease operating expenses as well as higher general and administrative costs.
Income tax expense for the twelve months ended December 31, 2006 was $61,586 compared to $17,267 in the same period of 2005. The increased income tax expense was due to 2005 alternative minimum tax paid in 2006.
Industry Overview for the Year Ended December 31, 2005
The year 2005 saw continued strong natural gas prices as a result of hurricane related supply disruptions and generally tight supplies of natural gas in the United States. The Houston Ship Channel price, the index price prevailing in the locale of our Madisonville Project in Madison County, Texas, as quoted in Gas Daily as of December 31, 2005, was $7.80 versus $5.82 as of December 31, 2004. Availability of capital, particularly equity capital for junior oil and natural gas companies, continued to show improvement in 2005, and in 2005, we raised $4,727,824 net of issuance costs through equity financing transactions. As a result, and through the sale of one of our Indonesian property interests, we were able to repay our indebtedness of $1.7 million to various creditors and improve our capital position during 2005.
During 2005, we received a weighted average net price of $4.01 per mcf of gas sold. As further discussed under “Properties-Texas-Madisonville Project”, we receive revenue for our gas sales net of certain costs to treat and transport the gas. The weighted average gross price during 2005, prior to the deduction of the treating and transportation costs, was $6.81. This compares to $7.80 which was the price prevailing on the last day of 2005.
Company Overview in 2005
Our net income for the year ended December 31, 2005 was $2,640,471. From our inception to 2003, we only received nominal revenues from our oil and natural gas activities, while incurring substantial acquisition and exploration costs and overhead expenses which resulted in our sustaining an accumulated deficit through December 31, 2005 of $9,382,179. We placed our Madisonville Project into production in May 2003. Substantially all of our oil and natural gas sales for the year ended December 31, 2005 were derived from our Madisonville Project, from one producing well, the Magness #1 well.
Comparison of Results of Operations for the twelve months ended December 31, 2005 and 2004
During the year ended December 31, 2005, we had oil and natural gas revenues of $7,975,990. Our net production was 1,991,105 thousand cubic feet (Mcf) of natural gas at an average price of $4.01 per Mcf. During the year ended December 31, 2004, we had oil and natural gas revenues of $5,825,072. Our net production for the year ended December 31, 2004 was 2,316,895 Mcf at an average price of $2.51 per Mcf. Revenues increased in the year ended December 31, 2005 as compared to the prior period due to higher gas prices. Average prices in 2005 were 60% higher than 2004, more than offsetting the 14% drop in production from 2004 to 2005. Production was lower due to normal declines associated with the production of reserves from the Magness #1 well.
During the year ended December 31, 2005, we incurred lease operating expenses of $878,176. Our average lifting cost for this period was $0.44 per Mcf. During the year ended December 31, 2004, we incurred lease operating expenses of $780,237. Our average lifting cost for this period was $0.34 per Mcf. The primary reasons for the increase in average lifting cost per Mcf were increases in costs and lower net production. The increase in lease operating costs was due primarily to higher insurance premiums, approximately $40,000, and higher costs of chemical treatments, approximately $60,000 associated with the Magness #1 well.
During the year ended December 31, 2005, we incurred net profits interest expense of $856,837 associated with the Magness Well compared to $579,590 during the year ended December 31, 2004. The increase resulted from higher revenues associated with the Magness Well in 2005 versus 2004.
General and administrative expenses for the year ended December 31, 2005 were $1,551,747 compared to $1,963,649 for the year ended December 31, 2004. This represents a $411,902 decrease over the prior year period due to stock based compensation incurred in 2004. During 2004 we issued 500,000 shares of our common stock for cash proceeds of $500,000 in connection with the exercise of stock options by an officer and director. Concurrent with the exercise of stock options, the officer sold 117,647 shares of common stock to us at the estimated fair market value price prevailing at that time of $4.25 per share. We recorded compensation expense of $500,000 in connection with the purchase of stock.
Depreciation, depletion and amortization expense for the year ended December 31, 2005 was $1,832,693 compared to $2,077,004 in the year ended December 31, 2004, which amounts represent amortization of the U.S. full cost pool for the year ended December 31, 2005 and 2004, respectively. The decrease was due to lower net production in 2005 as well as an upward revision in net proved reserve estimates during the year.
For the year ended December 31, 2005, no impairment expense was incurred as compared to $2,038,422 for the year ended December 31, 2004. The 2004 impairment write-downs were associated with the Canadian and Australian cost pools. We expensed the costs of drilling dry holes in those areas during 2004 while no such costs associated with unsuccessful wells were incurred in 2005.
Earnings from operations totaled $2,856,537 for the year ended December 31, 2005 compared to a loss of $1,613,830 for the year ended December 31, 2004. The increase in the earnings from operations was due primarily to higher revenues associated with the Magness Well.
Other income for the year ended December 31, 2005 and 2004 consisted of interest income in the amount of $18,969 and $6,548, respectively. The reason for the increase was higher average cash and cash equivalents balances for the 2005 period as compared to 2004.
During the year ended December 31, 2005 and 2004, we incurred interest expense of $217,768 and $402,958, respectively. The lower interest expense in the current year period was due to lower average debt levels. In March 2004, we incurred a cash finders fee of $67,375 to a director associated with the negotiation of a reduction in debt through the conversion of $1,347,500 of long-term debt to equity.
Net income after taxes for the year ended December 31, 2005 was $2,640,471 compared to net loss of $2,077,615 for the year ended December 31, 2004. The increase in net income was primarily due to higher revenues associated with the Magness Well and the impairments expense recorded in the previous period.
Recent Developments
In December 2007, officers, directors, and an employee exercised cashless options to purchase 249,963 shares of our common stock. A cashless exercise is the security holder’s election to receive that number of shares of our common stock that is equal to the quotient of (i) the fair market value of such shares, less the exercise price then in effect, multiplied by the number of shares that the security holder would otherwise have been entitled to purchase (or such lesser number of shares as the security holder may designate in the case of a partial exercise; over (ii) the Fair Market Value. The requisite tax withholdings for those persons employed by us at the time of exercise were taken in shares of common stock and the Company paid to the taxing authorities the amounts required to be withheld in cash equal to the value of the withheld shares.
On August 13, 2007, we sold, pursuant to a private placement, 2,002,599 units of our securities at a price of $3.85 per unit for gross proceeds of $7,710,006. The Placement Agent also received a warrant to purchase 60,078 shares expiring August 13, 2010 for additional gross proceeds of $231,300.30. Each unit consists of one share of common stock and a warrant to purchase three-tenths of a common share. Each one whole warrant shall entitle the holder to acquire one share of common stock at a price of $4.50 per share for a period of five years from the closing date. The units were purchased by a small number of accredited investors. We agreed to file a resale registration statement covering the common shares sold in the placement. The gross proceeds of the sale of common shares used to fund the Company’s exploration and development program and for general working capital purposes.
In October 2007, a resale registration statement covering the common shares sold in the placement was declared effective by the SEC. Under the terms of a registration rights agreement in connection with the private placement, we must pay the holders of the registrable securities issued in the private placement liquidated damages if the registration statement does not remain in effect until all such shares cease to be restricted securities (subject to certain exceptions). We must pay as liquidated damages a number of shares of common stock equal to 1.0%, up to a maximum of 10%, of the number of shares of our common stock that were issued to the holder for each 30 day period (pro-rated on a daily pro-rata basis for periods shorter than 30 days) that the above condition is not met.
In February 2007, we borrowed $900,000 pursuant to three promissory notes bearing interest at 8% per annum. The notes matured on October 31, 2007. In connection with these notes, we paid loan origination fees totaling $27,000 and issued warrants to the noteholders to purchase 45,000 shares of our common stock at $3.50 per share through February 2009. On October 31, 2007, the notes plus accrued interest were paid in full.
In February 2007, we received an extension of the maturity date of our promissory note for $1,000,000 payable to Pine Hill Capital, LLC to October 31, 2007. In connection with the extension, we paid a loan extension fee of $30,000 and issued a warrant to purchase 50,000 shares of our common stock at $3.50 per share which expires in February 2009. If we did not repay the note by October 31, 2007, we would have been required to dedicate 5% of our net cash flow from the Madisonville Project located in Madison County, Texas, toward the unpaid principal and all accrued and unpaid interest on the note, until all such amounts were paid in full. Net cash flow for this purpose meant gross revenues, less royalties, production taxes and net profits interest expense. On October 31, 2007, the principal balance of the note plus accrued interest were paid in full.
In February 2007, Stuart J. Doshi, President and CEO, loaned $100,000 to us pursuant to a promissory note bearing interest at 8% per annum, payable upon demand. We repaid the note plus accrued interest on March 28, 2007.
On June 7, 2006, we loaned $1,000,000 to G. Carter Sednaoui, a 5% shareholder at the time of the loan, evidenced by a full-recourse short-term promissory note with a maturity date of March 31, 2007. On March 30, 2007, we extended the maturity date of the note to June 30, 2007. On June 29, 2007, we received full payment of the note plus accrued interest.
On March 28, 2007, all 1,890,710 of our outstanding shares of our Series AA Stock automatically converted into 1,890,710 shares of our common stock. Under our Amended and Restated Articles of Incorporation, the Series AA stock automatically converts into common shares on a one-for-one share basis effective the first trading day after the reported high selling price for our common shares is at least $5.25 per share for any consecutive ten trading days, which condition was met on March 27, 2007. As a result of the conversion of our Series AA stock to common stock on March 28, 2007, dividends on the Series AA Stock ceased accruing on December 31, 2006. In 2006, dividends paid on the Series AA Stock totaled $529,400.
On April 25, 2007, May 9, 2007, June 13, 2007, and November 1, 2007, an officer and director exercised warrants and options to purchase 80,000, 70,000, 33,333, and 50,000 shares of common stock at an exercise price of $2.00, $2.00,$4.00 and $2.00 per share, respectively. The warrants were granted on June 18, 2000 and had expiration dates of between June 18 and June 30, 2007 and the options were granted on December 29, 2000 and had an expiration date of December 29, 2007.
During 2007, we issued 150,607 shares of common stock to persons other than directors, officers and employees, at exercise prices ranging from $1.50 to $3.50 per share in connection with exercises of outstanding warrants and options.
On June 20, 2007, we agreed to sell and transfer all of our remaining property interests in Australia to an unrelated party for cash consideration and a Petroleum Sales Royalty Payment equal to 25% of the future annual earnings before interest, taxes, depreciation and amortization from the property interests.
Specifically, the agreement provides that we will be paid consideration for the sale and transfer of our property interests as follows:
1. initial cash consideration of $175,000 subject to certain closing conditions;
2. a second cash payment of $175,000 upon a successful flow test of petroleum from a well located on the property interests. A successful flow test is defined for purposes of this agreement to be a test of at least 7 million standard cubic feet of natural gas for a continuous and uninterrupted 24 hour period (or an equivalent oil/condensate rate based on a conversion ratio of 6000 cubic feet of gas to a barrel of oil or condensate); and,
3. a Petroleum Sales Royalty Payment equal to 25% of the future annual earnings before interest, taxes, depreciation and amortization from the property interests up to a total amount of $2,200,000.
The first cash payment of $175,000 was received on November 19, 2007.
During 2007, we participated, for a 50% non-operated working interest, in the drilling of three wells in Alberta, two of which were determined to be non-commercial and one of which is currently under evaluation.
On October 17, 2007, we acquired a 33 1/3% non-operated working interest in the Swan Hills Prospect, Central Alberta, Canada. We paid $273,581 to purchase 4,480 gross (1,493 net) acres in this prospect.
.
Liquidity and Capital Resources
We had a working capital surplus of $3,361,853 versus a working capital deficit of $1,238,261 at December 31, 2007 and December 31, 2006, respectively. Our working capital increased during year ended December 31, 2007 due primarily to a private placement which is discussed below.
We have historically financed our business activities through December 31, 2007 principally through issuances of common shares, promissory notes and common share purchase warrants in private placements and an initial public offering. These financings are summarized as follows:
The net proceeds of our equity financings have been primarily invested in oil and natural gas properties totaling $5,214,421, $16,721,944, and $5,602,741 for the years ended December 31, 2007, 2006 and 2005, respectively.
On October 31, 2007, we repaid $1.9 million plus accrued but unpaid interest of $12,910 on the short-term notes we borrowed during 2007 and 2006.
In October 2005, we sold our 40% interest in C-G Yapen for cash proceeds of $2.4 million. Our cost basis in C-G Yapen was $698,000. The sale of the interest was recorded as a reduction of the capitalized cost pool for the Indonesian properties. We utilized the cash proceeds to repay indebtedness during the fourth quarter of 2005. On October 27, 2005, we repaid the remaining principal balance of $1,260,292 plus accrued but unpaid interest of $8,287 on the Rolling Hill Promissory Note dated October 18, 2002, as well as the unsecured promissory note dated September 30, 2004 with a remaining principal balance of $475,000 and accrued but unpaid interest of $9,058 to Patricia S. Cayce. See “Certain Relationships and Related Party Transactions.”
On May 31, 2005, we paid the remaining balance of $962,780 plus accrued but unpaid interest of $4,431 on a note to G. Carter Sednaoui dated July 19, 2004. See “Certain Relationships and Related Party Transactions.”
Our cash balance at December 31, 2007 was $4,294,565 compared to a cash balance of $734,561 at December 31, 2006. The change in our cash balance is summarized as follows:
During January and February 2006, we conducted a private placement of common shares to accredited investors. We issued 927,314 common shares at $3.50 per share for gross cash proceeds of $3,245,600 (net of $3,123,408).
On January 31, 2006, we borrowed $1,000,000 from Pinehill Capital Inc. pursuant to an 8% promissory note with a maturity date of January 31, 2007. We issued 150,000 shares at $3.50 per share of no par voting common stock warrants, immediately exercisable with an expiration date on January 31, 2009 to Pinehill Capital Inc., as well as a $30,000 loan origination fee. The fair market value of the warrants on the date of issuance, $182,390, as well as the $30,000 loan origination fee, was recorded as a debt discount and is being amortized over the life of the promissory note. On February 1, 2007, the maturity date was extended to October 31, 2007. We paid $80,000 accrued interest thru January 31, 2007. In connection with the extension, we paid a loan extension fee of $30,000 and granted a three-year warrant exercisable to purchase 50,000 Common Shares at $3.50 per share. The fair value of the warrants on the date of issuance, $57,242, together with the $30,000 loan extension fee, were recorded as a debt discount and are being amortized over the life of the promissory note. As of June 30, 2007, the unamortized debt discount was $38,774. In the event this note is not repaid by the maturity date, and unless an extension thereof is mutually agreed to, then we have agreed that we shall dedicate 5% of our net cash flow from the Madisonville Field toward the unpaid principal amount and all accrued and unpaid interest thereon, until such amounts are paid in full. Net cash flow for purposes of this provision means gross revenues received by us less royalties, production taxes and net profits interest expense. The note plus the accrued interest were paid in full on October 31, 2007.
On March 30, 2006, we completed an initial public offering pursuant to a final prospectus under the securities laws of each of the provinces of Canada, which consisted of 3,730,021 common shares from our treasury at an issue price of $3.50 per common share and 519,500 common shares issued on a “flow-through” basis under the Income Tax Act of Canada at an issue price of $3.85 per common share for aggregate gross proceeds of $15,055,149. We used the net proceeds of the offering
to fund development drilling of proven and probable natural gas reserves associated with the Madisonville Project and to conduct exploration and appraisal activities on our other projects in the United States, Canada and Indonesia.
It was required that we expend $2,000,075 of the proceeds realized from the Canadian offering from the issuance of 519,500 “flow-through” shares toward Canadian exploration expense pursuant to Canadian tax law. Canadian exploration expense generally means, but is not limited to, the drilling of exploratory wells in Canada. Pursuant to the terms of our agreement with the subscribers of the “flow-through” shares, we must renounce the tax deductions which would result from these expenditures and pass the deductions through to the holders of these shares. We incurred these expenditures by the end of our fiscal year ended December 31, 2007.
On August 13, 2007 we completed a private placement consisting of 2,002,599 units of the Company at a subscription price of $3.85 per Unit for total proceeds of $7,710,006. Each unit consisted of one share of common stock of the Company and three-tenths common share purchase warrant of the Company. Each one whole warrant entitles the holder to acquire one share of common stock at a price of $4.50 per share for a period of five years from the closing date. The units were purchased by a group of private investors. The proceeds of the sale of common shares will be used to fund the Company’s exploration and development program and for general working capital purposes.
Our current cash and cash equivalents and anticipated cash flow from operations may not be sufficient to meet our working capital, capital expenditures and growth strategy requirements for the foreseeable future. See “Outlook for 2008” for a description of our expected capital expenditures for 2008. If we are unable to generate revenues necessary to finance our operations over the long-term, we may have to seek additional capital through the sale of our equity or borrowing. As noted in “Recent Developments,” we periodically borrow funds pursuant to short term promissory notes to finance our activities.
As discussed in the “Outlook for 2008”, we are forecasting capital expenditures of $26.2 million during 2008. We will need to obtain adequate sources of cash to fund our anticipated capital expenditures through the end of 2008 and to follow through with plans for continued investments in oil and gas properties. Our success, in part, depends on our ability to generate additional financing and farm-out certain of our projects.
Since our inception, we have participated as a working interest owner in the acquisition of undeveloped leases, seismic options, lease options and foreign concessions and have participated in seismic surveys and the drilling of test wells on our undeveloped properties. Further leasehold acquisitions, drilling and seismic operations are planned for 2008 and future periods. In addition, exploratory and development drilling is scheduled during 2008 and future periods on our undeveloped properties. It is anticipated that these exploration activities together with others that may be entered into will impose financial requirements which will exceed our existing working capital. We may raise additional equity and/or debt capital, and we may farm-out certain of our projects to finance our continued participation in planned activities. However, if additional financing is not available, we may be compelled to reduce the scope of our business activities. If we are unable to fund planned expenditures, it may be necessary to:
1. forfeit our interest in wells that are proposed to be drilled;
2. farm-out our interest in proposed wells;
3. sell a portion of our interest in prospects and use the sale proceeds to fund our participation for a lesser interest; and
4. reduce general and administrative expenses.
Contractual Obligations
A summary of our contractual obligations as of December 31, 2007 is provided in the following table:
(1) Effective March 1, 2004, GeoPetro is committed under an office sublease which provides for a sixty month term. The sublease is cancelable by either party after thirty-six months. Minimum annual rentals due under this agreement are $78,334 in 2008 and $13,056 in 2009.
(2) In order to facilitate the expansion of the gas treatment plant in our Madisonville Project, we are subject to a drilling commitment. The commitment, subject to events of force majeure, including, but not limited to rig availability, requires us to drill a well sufficient to test the Smackover Formation (estimated to be encountered at approximately 18,000 feet) on or before September 30, 2008. The commitment is not discretionary. We have granted MGP a security interest in the Madisonville Field properties to secure the commitment. The security interest shall be subordinated to any third party lender in the event we secure future debt against the property. MGP granted us a security interest in the Madisonville Field Gas Treatment Plant to secure their obligation to expand the capacity of the facilities.
(3) On or before November 1, 2008, we have the option to conduct a $2.5 million work program on the leases over a three-year period, and, after completion of the work program and an evaluation of the results, to remit the final additional acreage consideration of $10 per acre for the leases estimated at approximately $1,068,000. The Cook Inlet Option provides that if we fail to pay the lease consideration when due, fail to perform the work program or otherwise default under the Cook Inlet Option, we shall forfeit our interest and reassign the leases to Pioneer with no further liability to us.
(4) This table does not include the liability for dismantlement, abandonment and restoration costs of oil and gas properties. Effective with the adoption of SFAS No. 143, “Accounting for Asset Retirement Obligations,” we recorded a separate liability for the fair value of this asset retirement obligation. See Note 2 of the Notes to Consolidated Financial Statements for further discussion.
Other than the above commitments, the timing of most of our capital expenditures is discretionary. We have no other material long-term commitments associated with our capital expenditure plans or operating agreements. Consequently, we have a significant degree of flexibility to adjust the level of such expenditures as circumstances warrant. The level of capital expenditures will vary in future periods depending on the success we experience on planned exploratory and appraisal drilling activities, natural gas and oil price conditions and other related economic and political factors. Accordingly, we have not yet prepared an estimate of capital expenditures for periods beyond 2008.
Income Taxes
As of December 31, 2007, GeoPetro had net operating loss (NOL) carryforwards of approximately $24,771,000 for federal income tax purposes which begin to expire in 2010. However, in accordance with SFAS 123(R), a deferred tax asset has not been recognized for the portion of the net operating loss carryforwards that is attributable to excess tax deductions associated with the exercise of stock options in 2007 which do not reduce income taxes payable. Accordingly, $2,128,000 of the GeoPetro’s federal NOL has not been benefited for financial statement purposes as it relates to excess tax deductions that have not reduced income taxes payable. The benefit of these excess tax deductions will not be recognized for financial statement purposes until the related deductions reduce income taxes payable.
The Company also has $11,112,000 of California and Alaska net operating losses which begin to expire in 2008. In accordance with SFAS 123(R), a portion of the state NOLs has similarly not been benefited for financial statement purposes as it relates to excess tax deductions which have not resulted in the reduction of income taxes payable. The benefit of such excess tax deductions will not be recognized for financial statement purposes until the related deductions reduce state income taxes payable.
In addition, the Company has $341,000 of carryforward credits in Texas, a portion of which may be utilized each year against Texas Margin Tax liability through 2027.
A significant change in our ownership may limit our ability to use these NOL carryforwards. Statement of Financial Accounting Standards No. 109, Accounting for Income Taxes, requires that the tax benefit of such net operating loss be recorded as an asset. At December 31, 2007, we had net deferred tax assets of approximately $4.4 million related to the NOL and other temporary differences. We have recorded a full valuation allowance of $4.4 million at December 31, 2007 due to uncertainties surrounding the realizability of the deferred tax asset.
Effective January 1, 2007, we adopted the provisions of FASB interpretation No. 48, Accounting for Uncertainty in Income Taxes, the detail of which is included in Note 5 to the Financial Statements.
Off Balance Sheet Arrangements
As of March 31, 2008, we have no off balance sheet arrangements.
Financial Instruments
We currently have no natural gas price financial instruments or hedges in place. Similarly, we have no financial derivatives. Our natural gas marketing contracts use “spot” market prices. Given the uncertainty of the timing and volumes of our natural gas production this year, we do not currently plan to enter into any long term fixed-price natural gas contracts, swap or hedge positions, other gas financial instruments or financial derivatives in 2008.
Outlook for 2008
Depending on capital availability, we are forecasting capital spending of up to approximately $26.2 million during the year 2008, allocated as follows:
1. Madisonville Project, Madison County, Texas. Approximately $13.5 million may be expended in the Madisonville Field area as follows: $1.5 million toward the fracture stimulation and hook up costs of the Wilson Well and $12.0 million toward the drilling of a deep well.
2. Central Alberta Project. Up to approximately $2.7 million may be expended to drill an exploratory well in the Swan Hills Prospect.
3. Cook Inlet, Alaska. Up to $5.0 million may be expended toward the drilling and completion of one exploratory well and an additional $2.0 million to be utilized for land acquisition and geologic and geophysical costs.
4. Indonesia. Up to $3.0 million may be expended toward the drilling, completion and testing of wells as well as the acquisition of seismic data in the Bengara II PSC as well as acquisition costs associated with new ventures.
We may, in our discretion, decide to allocate resources towards other projects in addition to or in lieu of, those listed above should other opportunities arise and as circumstances warrant. We currently do not have sufficient working capital to fund all of the capital expenditure listed above. See “Liquidity and Capital Resources.”
We expect commodity prices to be volatile, reflecting the current tight supply and demand fundamentals for North American natural gas and world crude oil. Political events around the world, which are difficult to predict, will continue to influence both oil and gas prices. Higher prices for oil and gas often lead to higher levels of drilling activity which in turn lead to higher costs to explore, develop and acquire oil and gas reserves due to greater competition for resources and supplies. These higher costs could affect the returns on our capital expenditures. Higher crude prices could also help keep natural gas prices high by keeping alternative fuels, such as heating oil and residual fuel, expensive.
Impact of Inflation & Changing Prices
As the following table illustrates, average sales prices of natural gas have changed in the past three years. This has led to changes in revenues and earnings from operations:
(1) Includes $1,111,151 impairment expense
(2) Includes $38,849 impairment expense
We are highly dependent upon natural gas pricing. A material decrease in current and projected natural gas prices could impair our ability to raise additional capital on acceptable terms. Likewise, a material decrease in current and projected natural gas prices could also impact our revenues and cash flows. This could impact our ability to fund future activities.
GeoPetro anticipates an increase in gas price in 2008 from 2007. This would have a materially positive impact on our cash flow and revenues.
Changing prices have had a significant impact on costs of drilling and completing wells, particularly in the Madisonville Field area where we are currently the most active. The estimated cost of drilling and completing a Rodessa formation well at approximately 12,300 feet of depth has increased from $3.0 million in 2001 to $7.5 million in 2007 due to higher costs associated with tubular goods, well equipment, and day rates for drilling contracts, among other factors. These higher costs have impacted and will continue to impact our income from operations in the form of higher depletion expense.
Critical Accounting Estimates
Our consolidated financial statements have been prepared by management in accordance with U.S. GAAP.
The preparation of consolidated financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates.
Management believes the most critical accounting policies that may have an impact on our financial results relate to the accounting for oil and gas properties. Amortization, abandonment costs and full cost ceiling limitation write-downs are all
based on numerous estimates, many of which are beyond management’s control. Reserves valuation is central to much of the accounting for an oil and gas company as described below.
Significant accounting policies are contained in Note 2 to the consolidated financial statements. A summary of unaudited supplementary oil and gas reserve information is contained in Note 12 to the consolidated financial statements.
The following discusses the accounting estimates that are critical in determining the reported financial results:
Oil and Gas Properties-We follow the full cost method of accounting for oil and gas producing activities as prescribed by U.S. GAAP and, accordingly, capitalize all costs incurred in the acquisition, exploration, and development drilling of proved oil and gas properties, including the costs of abandoned properties, dry holes, geophysical costs, and lease rentals. All general corporate costs are expensed as incurred. In general, sales or other dispositions of oil and gas properties are accounted for as adjustments to capitalized costs, with no gain or loss recorded. Amortization of evaluated oil and gas properties is computed on the units of production method based on all proved reserves on a country by country basis. Unevaluated oil and gas properties are assessed for impairment either individually or on an aggregate basis. The net capitalized costs of evaluated oil and gas properties (full cost ceiling limitation) are not to exceed their related estimated future net revenues discounted at 10%, and the lower of cost or estimated fair value of unproved properties, net of tax considerations.
Reserves-We engage independent petroleum engineering consultants to evaluate our reserves. Reserves, future production profiles, and net revenues are estimated by independent professional reservoir engineering firms. While we engage qualified reservoir engineering firms, their estimates are inherently uncertain, involve numerous assumptions that may not be realized, and predict asset values that may not be indicative of the true market value of the assets evaluated. As a result of the inherent uncertainties and changing technical and economic assumptions, reserve estimates are subject to revisions that can materially impact our results.
Asset Retirement Obligation-We provide for the estimated site restoration and abandonment costs of tangible long-lived assets using a fair value method, which approximates the cost a third party would incur in performing the tasks necessary to retire such assets. The reported liability is a discounted amount. The amount of the liability is affected by factors such as the number of wells, the timing of the expected expenditures and the discount factor. These estimates will change and the revisions could impact the amortization rates.
Stock Based Compensation-The Company has a stock- based compensation plan that allows employees to purchase common shares of the Company. Option exercise prices approximate the market price for the common shares on the date the options were issued. Options granted under the plan are generally fully exercisable after five years and expire five to ten years after the grant date. Under U.S. GAAP, prior to 2006, the Company elected not to expense compensation cost for stock-based employee compensation at fair value but did disclose the impact of the fair value accounting of employee stock options in Note 2 to the annual audited consolidated financial statements. GeoPetro adopted Statement of Financial Accounting Standards No. 123(R) (“Statement 123R”) on January 1, 2006, which is the beginning of its first interim period following the effective date of Statement 123R. GeoPetro has applied the modified prospective method of adoption, and accordingly, the financial statements for GeoPetro’s prior interim periods and fiscal years will not reflect any restated amounts. GeoPetro has recorded $121,421 and $201,335 of stock-based employee compensation for the twelve months ended December 31, 2007 and 2006, respectively, in connection with the portion of previously granted employee stock options that vest on or after January 1, 2006. The impact of the fair value accounting of employee stock options is estimated on the date of grant using the Black-Scholes option pricing model with assumptions for: risk free interest rates, expected dividend yields, expected life of the options from the date of grant, and expected volatility.
Recently Issued Accounting Pronouncements
In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements,” which is effective for the Company beginning January 1, 2008 and provides a definition of fair value, establishes a framework for measuring fair value, and expands disclosures about fair value measurements for future transactions. We do not expect the adoption of this pronouncement to have a material impact on our financial position or results of operations.
In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities,” which permits an entity to measure certain financial assets and financial liabilities at fair value. The objective of SFAS No. 159 is to improve financial reporting by allowing entities to mitigate volatility in reported earnings caused by the measurement of related assets and liabilities using different attributes, without having to apply complex hedge accounting
provisions. Under SFAS No. 159, entities that elect the fair value option (by instrument) will report unrealized gains and losses in earnings at each subsequent reporting date. The fair value option election is irrevocable, unless a new election date occurs. SFAS No. 159 establishes presentation and disclosure requirements to help financial statement users understand the effect of the entity’s election on its earnings, but does not eliminate disclosure requirements of other accounting standards. Assets and liabilities that are measured at fair value must be displayed on the face of the balance sheet. We do not expect the adoption of this pronouncement to have a material impact on our financial position or results of operations.
Risks and Uncertainties
There are a number of risks that face participants in the U.S., Canadian and international oil and natural gas industry, including a number of risks that face us in particular. Accordingly, there are risks involved in an ownership of our securities. See “Risk Factors” for a description of the principal risks faced by us.
Item 7A.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
We are exposed to market risks arising from fluctuating prices of crude oil, natural gas and interest rates as discussed below.
Commodity Risk. Our major commodity price risk exposure is to the prices received for our natural gas production. Realized commodity prices received for our production are the spot prices applicable to natural gas in the East Texas region. Prices received for natural gas are volatile and unpredictable and are beyond our control. For the year ended December 31, 2007, a 10% change in the prices received for natural gas production would have had an approximate $700,000 impact on our revenues.
Currency Translation Risk. Because our revenues and expenses are primarily in U.S. dollars, we have little exposure to currency translation risk, and, therefore, we have no plans in the foreseeable future to implement hedges or financial instruments to manage international currency changes.
Hedging. We did not enter into any hedging transactions during the years ended December 31 2007, 2006 and 2005.
Item 8.
Item 8. Financial Statements and Supplementary Data
The reports of our independent registered public accounting firms and our consolidated financial statements and supplemental information required to be filed under Item 8 of Form 10-K are presented beginning on Page of this Form 10-K.
Item 9.
Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
None.
Item 9A.
Item 9A. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
Based on their evaluation as of the end of the fiscal year ended December 31, 2007, our Chief Executive Officer and Chief Financial Officer have concluded that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) are effective to ensure that information required to be disclosed in reports that we file or submit under the Exchange Act are recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and in providing reasonable assurance that information required to be disclosed by the Company in such reports is accumulated and communicated to the Company’s management, including its Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosures.
During the most recent fiscal quarter, there have been no changes in our internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Management’s Report on Internal Control Over Financial Reporting
As management, we are responsible for establishing and maintaining adequate internal control over our financial reporting. In order to evaluate the effectiveness of internal control over financial reporting, as required by Section 404 of the Sarbanes-Oxley Act of 2002, we have conducted an assessment, including testing using the criteria in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). GeoPetro’s system of internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.
Based on our assessment, we have concluded that we maintained effective internal control over financial reporting as of December 31, 2007, based on criteria in Internal Control-Integrated Framework issued by the COSO. This annual report does not include an attestation report of the company’s registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by the Company’s registered public accounting firm pursuant to temporary rules of the Securities and Exchange Commission that permit the company to provide only management’s report in this annual report. Management’s report shall not be deemed to be filed for purposes of Section 18 of the Exchange Act or otherwise subject to the liabilities of that section.
Item 9B.
Item 9B. Other Information
None.
PART III
Item 10.
Item 10. Directors, Executive Officers and Corporate Governance
The information required by this item is incorporated by reference from our definitive proxy statement relating to our 2008 Annual Meeting of Shareholders, to be filed pursuant to Regulation A, on or before April 29, 2008, or the 2008 proxy statement.
Item 11.
Item 11. Executive Compensation
The information required by this item is incorporated by reference from our 2008 proxy statement.
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters
The information required by this item is incorporated by reference from our 2008 proxy statement.
Item 13.
Item 13. Certain Relationships and Related Transactions and Director Independence
The information required by this item is incorporated by reference from our 2008 proxy statement.
Item 14.
Item 14. Principal Accountant Fees and Services
The information required by this item is incorporated by reference from 2008 proxy statement.
PART IV
Item 15.
Item 15. Exhibits and Financial Statement Schedules
(a) The following documents are filed as part of this report
1. Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets as of December 31, 2007 and 2006
Consolidated Statements of Operations for the years ended December 31, 2007, 2006 and 2005
Consolidated Statements of Shareholders’ Equity for the years ended December 31, 2007, 2006 and 2005
Consolidated Statements of Cash Flows for the years ended December 31, 2007, 2006 and 2005
Notes to Consolidated Financial Statements
2. All other schedules are omitted because they are not applicable, not required or the required information is included in the consolidated financial statements or related notes.
3. A list of exhibits filed or furnished with this report on Form 10-K (or-incorporated by reference to exhibits previously filed or furnished by GeoPetro) is provided in the Exhibit Index immediately following the financial statements in this report.
GLOSSARY OF OIL AND NATURAL GAS TERMS
In this report, unless the context otherwise requires, the following terms shall have the indicated meanings. A reference to an agreement means the agreement as it may be amended, supplemented or restated from time to time.
“1933 Act” means the United States Securities Act of 1933, as amended.
“Bengara II PSC” means the PSC dated December 4, 1997 between C-G Bengara and Pertamina.
“Bengara Block” means the contract area in the Indonesian province of East Kalimantan designated as the Bengara (II) PSC Block.
“BP Migas” means Badan Pelaksana Minyak Dan Gas Muni, a new executive board established by the government of Indonesia in 2002 for oil and gas upstream operations and an implementing body created to assume the role of Pertamina’s regulatory functions and responsibilities in managing oil and gas contractors.
“CBM” means coal bed methane, which is methane found in coal seams. It is produced by non-traditional means, and therefore, while it is sold and used the same as traditional natural gas, its production is different. CBM is generated either from a biological process as a result of microbial action or from a thermal process as a result of increasing heat with depth of the coal. Often a coal seam is saturated with water, with methane held in the coal by water pressure.
“C-G Bengara” means Continental-GeoPetro (Bengara II) Ltd., a British Virgin Islands corporation owned 12% by GeoPetro.
“CG Xploration” means CG Xploration Inc., a Delaware corporation owned 50% by GeoPetro.
“C-G Yapen” means Continental-GeoPetro (Yapen) Ltd., a British Virgin Islands corporation formerly owned 40% by GeoPetro.
“CNPC” means CNPCHK (Indonesia) Limited. CNPC is a wholly owned subsidiary of CNPC (Hong Kong) Limited, a publicly held company based in Hong Kong where its shares trade on the Hong Kong Stock Exchange under the listing number 0135.HK.
“Company” or “GeoPetro” means GeoPetro Resources Company, a corporation incorporated under the laws of the State of California and its wholly-owned subsidiaries.
“Condensate” means a low-density, high-API gravity liquid hydrocarbon product that is generally produced in association with natural gas. Condensate is mainly composed of propane, butane, pentane and heavier hydrocarbon fractions.
“Continental” means Continental Energy Corporation.
“Cook Inlet Option” means the option granted to GeoPetro by Pioneer to acquire a 100% working interest (81% net revenue interest) in approximately 122,000 acres in Cook Inlet, near Anchorage, Alaska.
“CRA” means the Canada Revenue Agency.
“Earning Obligation” means $18.7 million paid by CNPC into a special joint venture account at a Hong Kong international bank, which funds are under joint signature control of CNPC ourselves and Continental, and has been expended to pay for 2007 exploration drilling in the Bengara II PSC area.
“EIA” means the United States Energy Information Administration.
“EP 408” means the approximately 201,000 gross (52,675 net) acre permit area including the Whicher Range gas field in the South Perth basin of Western Australia designated as Exploration Permit 408 which we transferred to an unrelated party in June 2007.
“Evaluated Properties” means those properties that are producing oil or gas or on which, based on known geological and engineering data, oil and gas reserves are reasonably certain to exist.
“Fannin Well” means the Angela Farris Fannin No. 1 well located at the Madisonville Field.
“Farmout” means an agreement whereby a third party agrees to pay for the drilling of a well on one or more of GeoPetro’s properties in order to earn an interest therein with GeoPetro retaining a residual interest in such properties.
“Flow-Through Share” means a share of common stock issued as a “flow-through share” within the meaning of Canadian tax law.
“Gateway” means Gateway Processing Company, a Texas corporation that has constructed pipeline facilities at the Madisonville Field.
“GeoPetro Alaska” means GeoPetro Alaska LLC, an Alaska limited liability company, which is a wholly-owned subsidiary of GeoPetro.
“GeoPetro Canada” means GeoPetro Canada Ltd., an Alberta corporation, which is a wholly-owned subsidiary of GeoPetro.
“Hanover” means Hanover Compression Limited Partnership, a Delaware limited partnership that has constructed and previously operated treatment facilities at the Madisonville Field.
“Hanover Agreement” means, collectively, the First Amended and Restated Master Agreement, dated as of September 12, 2002 among Redwood, Hanover and Gateway, as amended, providing for the processing of natural gas from the Madisonville Field, and the agreements related thereto, which agreements were in effect prior to August 2005.
“LPG” means liquefied petroleum gas.
“Madisonville Field” means the Madisonville (Rodessa) field in Madison County, Texas.
“Madisonville Project” means the oil and natural gas exploration, development and production project at the Madisonville Field.
“Magness Well” means the UMC Ruby Magness No. 1 well located at the Madisonville Field.
“Makapan Gas Field” means the Makapan gas field in East Kalimantan, Indonesia.
“MGP” means Madisonville Gas Processing, LP, a Colorado Limited Partnership that has purchased from Hanover and currently operates the treatment facilities at the Madisonville Field, and is jointly owned by JPMorgan Partners and Bear Cub Investments LLC.
“MGP Agreement” means, collectively, the Termination and Release Agreement, Madisonville Field Development Agreement, Gas Purchase Contract between Redwood LP as Seller, and MGP as Buyer, Escrow Agreement and Dedication Agreement, all effective as of August 1, 2005 among Redwood LP, MGP, Gateway and Gateway Pipeline Company, providing for the termination of the Hanover Agreement, the expansion of the treatment facilities and the provision of the gathering, processing, transportation and sale of natural gas from the Madisonville Field.
“Mitchell Well” means the Mitchell No. 1 well located at the Madisonville Field.
“Pertamina” means Perusahaan Pertambangan Minyak Dan Gas Bumi Negara, the previous Indonesian state-owned oil and natural gas company established in 1971 which had exclusive authority to explore, drill for, and produce oil and natural gas minerals in Indonesia. In accordance with the new Indonesian Oil and Gas Law, its corporate form has been changed to become a state-owned limited liability company established under Indonesian Company Law, and all rights and obligations of Pertamina under existing PSCs shall pass to BP Migas.
“Pioneer” means Pioneer Oil Company, Inc.
“Proved developed oil and gas reserves” means reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.
“Proved developed nonproducing reserves” means reserves expected to be recovered from zones behind casing in existing wells.
“Proved oil and gas reserves” means estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.
(i) Reservoirs are considered proved if economic producibility is supported by either actual production or a conclusive formation test. The area of a reservoir considered proved includes (A) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and (B) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.
(ii) Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the “proved” classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.
(iii) Estimates of proved reserves do not include the following:
(A) oil that may become available from known reservoirs but is classified separately as “indicated additional reserves”;
(B) crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors;
(C) crude oil, natural gas, and natural gas liquids, that may occur in undrilled prospects; and
(D) crude oil, natural gas, and natural gas liquids, that may be recovered from oil shales, coal, gilsonite and other such sources.
“Proved undeveloped reserves” means reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates, for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.
“PSC” means a production sharing contract, being a contract with Pertamina whereby Pertamina contracts with a petroleum company to explore for, develop and extract petroleum substances from a particular license area, on Pertamina’s behalf, at the risk and expense of the petroleum company, in exchange for a share of the production.
“Redwood” means Redwood Energy Company, a Texas corporation, which is a wholly-owned subsidiary of GeoPetro and which is the general partner of, and holds a 5% interest in, Redwood LP.
“Redwood LP” means Redwood Energy Production, L.P., a Texas limited partnership, the sole limited partner of which is GeoPetro and which is 100% owned, directly or indirectly, by GeoPetro.
“Rodessa Formation” means the geological formation at the Madisonville Field existing at a depth of approximately 12,000 feet.
“Seismic” means data collected that uses reflected seismic waves to produce images of the Earth’s subsurface. The method requires a controlled seismic source of energy, such as dynamite or a specialized air gun. By noting the time it takes for a reflection to arrive at a receiver, it is possible to estimate the depth of the feature that generated the reflection.
“Series A Stock” means the preferred stock of GeoPetro designated as Series A preferred stock, all of which converted to GeoPetro’s common stock on March 30, 2006.
“Series AA Stock” means the preferred stock of GeoPetro designated as Series AA preferred stock, as described under “Description of Share Capital”.
“South Texas GeoPetro” means South Texas GeoPetro, LLC., a Texas limited liability company, the sole limited partner of which is GeoPetro and which is 100% owned, directly or indirectly, by GeoPetro.
“Tertiary Sandstones” means sandstones which were deposited during a geologic time period ranging from 2 to 63 million years ago.
“TSX” means the Toronto Stock Exchange.
“Unevaluated Properties” means properties not yet evaluated through exploration and drilling as to whether or not they have proved reserves.
“U.S. GAAP” means the accounting principles generally accepted in the United States.
“Wilson Well” means the Wilson No. 1 well located at the Madisonville Field.
“Working interest” means the percentage of undivided interest held by a party in the oil and/or natural gas or mineral lease granted by the mineral owner, which interest gives the holder the right to “work” the property (lease) to explore for, develop, produce and market the leased substances.
ABBREVIATIONS AND CONVERSIONS
In this report, the following abbreviations have the meanings set forth below:
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on March 31, 2008.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on March 31, 2008.
Signature
Title
Date
/s/ Stuart J. Doshi
Chairman of the Board, President
March 31, 2008
Stuart J. Doshi
and Chief Executive Officer
/s/ David V. Creel
Vice President of Exploration and
March 31, 2008
David V. Creel
Director
/s/ J. Chris Steinhauser
Vice President of Finance and
March 31, 2008
J. Chris Steinhauser
Chief Financial Officer, Principal
Accounting Officer and Director
/s/ Kevin M. Delehanty
Director
March 31, 2008
Kevin M. Delehanty
/s/ Thomas D. Cunningham
Director
March 31, 2008
Thomas D. Cunningham
/s/ David G. Anderson
Director
March 31, 2008
David G. Anderson
/s/ Nick DeMare
Director
March 31, 2008
Nick DeMare
GEOPETRO RESOURCES COMPANY
CONSOLIDATED FINANCIAL STATEMENTS FOR THE FISCAL YEARS ENDED DECEMBER 31, 2007, 2006 AND 2005
Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets as of December 31, 2007 and 2006
Consolidated Statements of Operations for the years ended December 31, 2007, 2006 and
Consolidated Statements of Shareholders’ Equity for the years ended December 31, 2007, 2006 and 2005
Consolidated Statements of Cash Flows for the years ended December 31, 2007, 2006 and
Notes to Consolidated Financial Statements
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
March 26, 2008,
To the Shareholders and Board of Directors
GeoPetro Resources Company
San Francisco, California
We have audited the accompanying consolidated balance sheets of GeoPetro Resources Company and subsidiaries as of December 31, 2007 and 2006, and the related consolidated statements of operations, shareholders’ equity, and cash flows for each of the three years in the period ended December 31, 2007. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of GeoPetro Resources Company and subsidiaries as of December 31, 2007 and 2006, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2007, in conformity with accounting principles generally accepted in the United States of America.
We were not engaged to examine management’s assertion about the effectiveness of GeoPetro Resources Company’s internal control over financial reporting as of December 31, 2007 included in the accompanying Form 10K and, accordingly, we do not express an opinion thereon.
As discussed in Note 5 to the accompanying financial statements, effective January 1, 2007, the Company adopted FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes.
(signed) HEIN & ASSOCIATES
Irvine, California
GEOPETRO RESOURCES COMPANY
CONSOLIDATED BALANCE SHEETS
See accompanying notes to these consolidated financial statements.
GEOPETRO RESOURCES COMPANY
CONSOLIDATED BALANCE SHEETS
(Continued)
See accompanying notes to these consolidated financial statements.
GEOPETRO RESOURCES COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
See accompanying notes to these consolidated financial statements.
GEOPETRO RESOURCES COMPANY
CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY
FOR THE YEARS ENDED DECEMBER 31, 2007, 2006 AND 2005
See accompanying notes to these consolidated financial statements.
GEOPETRO RESOURCES COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
GEOPETRO RESOURCES COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
Continued
The accompanying notes are an integral part of these consolidated financial statements.
GEOPETRO RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Information subsequent to December 31, 2007 is unaudited)
1. ORGANIZATION AND NATURE OF OPERATIONS:
GeoPetro-GeoPetro Resources Company (“GeoPetro” or the “Company”) was originally incorporated as GeoPetro Company under the laws of the State of Wyoming in 1994 to participate in the oil and gas acquisition, exploration, development and production business in the United States and internationally. GeoPetro Company was subsequently merged into GeoPetro Resources Subsidiary Company, a California corporation, on June 28, 1996. GeoPetro’s name was then changed to GeoPetro Resources Company. GeoPetro’s corporate offices are in San Francisco, California. The accompanying consolidated financial statements include the accounts of GeoPetro and its wholly-owned subsidiaries. All significant intercompany accounts and transactions have been eliminated in consolidation.
Operations-Although GeoPetro is not a development stage enterprise, the company has a limited operating history upon which an evaluation of its business prospects can be based. The risks, expense, and difficulties encountered by early stage companies must be considered when evaluating GeoPetro’s business prospects. GeoPetro recorded net income of $2,111,074 in 2005 but incurred net losses of $1,616,804, and $1,011,806 in 2007 and 2006 respectively, and had an accumulated deficit at December 31, 2007 of $12,010,789. GeoPetro expects to make significant capital expenditures in the foreseeable future. Management believes that GeoPetro will be successful in obtaining adequate sources of cash to fund its anticipated capital expenditures through the end of 2008 and to follow through with plans for continued investments in oil and gas properties. GeoPetro’s success, in part, depends on its ability to generate additional financing, farm-out certain of its projects and manage its relations with the companies that provide exploration and development services. GeoPetro’s success also depends on its ability to effectively manage growth and develop proven reserves. Additionally, GeoPetro’s operations are subject to all of the environmental and operational risks normally associated with the oil and gas industry. GeoPetro maintains insurance that is customary in the industry.
Since its inception, GeoPetro has participated as a working interest owner in the acquisition of undeveloped leases, seismic options, lease options and foreign concessions and has participated in seismic surveys and the drilling of test wells on its undeveloped properties. Further leasehold acquisitions and seismic operations are planned for 2008 and future periods. In addition, exploratory and development drilling is scheduled during 2008 and future periods on GeoPetro’s undeveloped properties. It is anticipated that these exploration activities together with others that may be entered into may impose financial requirements which may exceed the existing working capital of GeoPetro. Management may raise additional equity and/or debt capital, and has farmed-out certain of its projects to finance its continued participation in planned activities. However, if additional financing is not available, GeoPetro may be compelled to reduce the scope of its business activities. If GeoPetro is unable to fund planned expenditures, it may be necessary to:
1. forfeit its interest in wells that are proposed to be drilled;
2. farm-out its interest in proposed wells;
3. sell a portion of its interest in prospects and use the sale proceeds to fund its participation for a lesser interest; and
4. reduce general and administrative expenses.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
U.S. GAAP-The Company’s financial statements have been prepared in accordance with accounting principles generally accepted within the United States of America (“U.S. GAAP”).
Use of Estimates and Significant Estimates-Certain amounts in GeoPetro’s financial statements are based upon significant estimates, including oil and gas reserve quantities which form the basis for the calculation of depreciation, depletion, amortization and impairment of oil and gas properties. Actual results could materially differ from those estimates.
Oil and Gas Properties-GeoPetro follows the full cost method of accounting for oil and gas producing activities and, accordingly, capitalizes all costs incurred in the acquisition, exploration, and development of proved oil and gas properties, including the costs of abandoned properties, dry holes, geophysical costs, and annual lease rentals. All general corporate costs are expensed as incurred. In general, sales or other dispositions of oil and gas properties are accounted for as adjustments to capitalized costs, with no gain or loss recorded. Amortization of evaluated oil and gas properties is computed on the units of production method based on all proved reserves on a country by country basis. Unevaluated oil and gas properties are assessed for impairment either individually or on an aggregate basis. The net capitalized costs of evaluated oil and gas properties (full cost ceiling limitation) are not to
exceed their related estimated future net revenues discounted at 10%, and the lower of cost or estimated fair value of unproved properties, net of tax considerations.
Asset Impairment-Under full cost accounting, a ceiling test is performed to ensure that unamortized capitalized costs in each cost center (country) do not exceed their fair value. Impairment is recognized when the carrying value is greater than the undiscounted future cash flows. In the event of impairment, the amount by which the carrying value exceeds the estimated fair value of the long-lived asset is charged to earnings. The present value of estimated future net revenues is computed by applying current oil and gas prices to estimated future production of proved oil and gas reserves as of period-end, less estimated future expenditures to be incurred in developing and producing the proved reserves assuming the continuation of existing economic conditions. As of twelve months ended December 31, 2007, the impairment test was met for the United States.
For the unproved properties, the Company evaluates the possibility of potential impairment on a quarterly basis. During the twelve months ended December 31, 2007, approximately $1,111,151 of unproved property costs related to Goodwin and Wildwood projects were reclassified to proved property and a ceiling test impairment was recorded in the Canadian full cost pool due to dry holes drilled.
Joint Ventures-Some exploration and production activities are conducted jointly with others and, accordingly, the accounts reflect only GeoPetro’s proportionate interest in such activities.
Revenue Recognition-Revenue is recognized upon delivery of oil and gas production and is shown net of applicable royalty payments, processing and transportation fees. In addition, the Company recognizes revenue from the Madisonville Field net of applicable fees to gather, treat and transport the Company’s natural gas production. The applicable fees are paid to unrelated third parties. Revenue from the Madisonville Field is recognized when the price for gas delivered becomes fixed and determinable. The price for gas delivered to the purchaser, Madisonville Gas Processing LP (“MGP”), becomes fixed and determinable after the gas has been gathered, treated, and transported to a common carrier pipeline where it is then resold by MGP to the common carrier pipeline on a spot market basis. The proceeds from the sale of the gas are deposited directly into an escrow account under the joint signature control of the Company and MGP. The fees to gather, treat and transport the gas are distributed to MGP in accordance with agreements between them and the Company. The remaining net proceeds are distributed to the Company. See Note 10 for a more detailed discussion of the fees under the “MGP Agreement.”
Asset Retirement Obligation-In accordance with Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations (“SFAS 143”), the fair value of an asset retirement cost, and corresponding liability, should be recorded as part of the cost of the related long-lived asset and subsequently allocated to expense using a systematic and rational method. GeoPetro recorded an asset retirement obligation to reflect GeoPetro’s legal obligations related to future plugging and abandonment of its oil and gas wells. GeoPetro estimated the expected cash flow associated with the obligation and discounted the amount using a credit-adjusted, risk-free interest rate. At least annually, GeoPetro reassesses the obligation to determine whether a change in the estimated obligation is necessary. GeoPetro evaluates whether there are indicators that suggest the estimated cash flows underlying the obligation have materially changed. Should those indicators suggest the estimated obligation has materially changed, GeoPetro will accordingly update its assessment.
Furniture, Fixtures and Equipment-Furniture, fixtures and equipment are stated at cost. Depreciation is provided on furniture, fixtures and equipment using the straight-line method over an estimated service life of three to seven years.
Income Taxes-GeoPetro accounts for income taxes using the asset and liability method wherein deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which the temporary differences are expected to be recovered or settled. Because management has determined that realization of deferred tax assets is not more likely than not, the net deferred tax assets are fully reserved.
Concentrations of Credit Risk-Credit risk represents the accounting loss that would be recognized at the reporting date if counterparties failed completely to perform as contracted. Concentrations of credit risk (whether on or off balance sheet) that arise from financial instruments exist for groups of customers or counterparties when they have similar economic characteristics that would cause their ability to meet contractual obligations to be similarly affected by changes in economic or other conditions described below. The credit risk amounts for cash and accounts receivable do not take into account the value of any collateral or security.
GeoPetro maintains several cash accounts with three financial institutions. Accounts at each institution are insured by the Federal Deposit Insurance Corporation up to $100,000. As of December 31, 2007, the uninsured bank balance was $4,494,138. GeoPetro has not experienced any losses in such accounts and believes it is not exposed to any significant credit risk.
During the years ended December 31, 2007, 2006 and 2005, the Company had sales to customers exceeding 10% of total sales as follows:
At December 31, 2007, 2006 and 2005, the Company had accounts receivable balances from Luminant Energy Company, LLC of $965,188 or 74%, $394,337 or 77% $691,564, or 100%, and $449,947, or 99.5% of total accounts receivable respectively.
Allowance for Doubtful Accounts-Trade accounts receivable are recorded at net realizable value. If the financial condition of GeoPetro’s customers were to deteriorate, resulting in an impairment of their ability to make payments, additional allowances may be required. Delinquent trade accounts receivable are charged against the allowance for doubtful accounts once uncollectibility has been determined. The allowance is determined through an analysis of
the past-due status of accounts receivable and assessments of risk that are based on historical trends and an evaluation of the impact of current and projected economic conditions. There was no activity in the allowance for doubtful accounts as of December 31, 2007, December 31, 2006 and 2005.
Fair Value of Financial Instruments-The estimated fair values for financial instruments are determined at discrete points in time based on relevant market information. These estimates involve uncertainties and cannot be determined with precision. For certain of GeoPetro’s financial instruments, including cash, accounts receivable, accounts payable and current portion of notes payable, the carrying amounts approximate fair value due to their maturities.
Stock-Based Compensation-Statement of Financial Accounting Standards No. 123, Accounting for Stock-Based Compensation (“SFAS 123”), encourages, but does not require, companies to record compensation cost for stock-based employee compensation at fair value. Prior to January 1, 2006, GeoPetro elected to account for stock-based compensation using the intrinsic value method prescribed in Accounting Principles Board Opinion No. 25 (“APB 25”), Accounting for Stock Issued to Employees, and related interpretations.
In accordance with SFAS 123, GeoPetro discloses the impact of the fair value accounting of employee stock options. Transactions in equity instruments with non-employees for goods or services have been accounted for using the fair value method as prescribed by SFAS 123.
The following table illustrates the effect on GeoPetro’s net loss and loss per share as if GeoPetro had applied the fair value recognition provisions of SFAS 123 to its stock-based employee compensation awards granted in 2005, and recognized expense over the applicable award vesting period.
The assumptions made for purposes of estimating the fair value of the stock options are included in Note 8.
Effective January 1, 2006, the Company adopted the fair value recognition provisions of Statement of Financial Accounting Standard 123(R) “Share-Based Payment” (“SFAS 123(R)”) using the modified prospective transition method. In addition, the Securities and Exchange Commission issued Staff Accounting Bulletin No. 107 “Share-Based Payment” (“SAB 107”) in March, 2005, which provides supplemental SFAS 123(R) application guidance based on the views of the SEC. Under the modified prospective transition method, compensation cost recognized in the twelve month period ended December 31, 2007 includes: (a) compensation cost for all share-based payments granted prior to, but not yet vested as of January 1, 2006, based on the grant date fair value estimated in accordance with the original provisions of SFAS No. 123, and (b) compensation cost for all share-based payments granted beginning January 1, 2006, based on the grant date fair value estimated in accordance with the provisions of SFAS 123(R). In accordance with the modified prospective transition method, results for prior periods have not been restated.
The adoption of SFAS 123(R) resulted in stock compensation expense for the twelve months period ended December 31, 2007 and 2006 of $121,421 and $201,335, respectively, to income from continuing operations and income before income taxes, of which the entire amount was recorded to general and administrative expenses. The Company did not recognize a tax benefit from the stock compensation expense because the Company considers it is more likely than not that the related deferred tax assets, which have been reduced by a full valuation allowance, will not be realized.
The fair value of each option grant was estimated on the date of grant using the Black-Scholes option pricing model with the following weighted-average assumptions used for grants in 2003 and 2005 for all periods presented: risk-free, weighted-average interest rates ranging from 2.52 to 3.75% based on the U.S. Treasury yield curve in effect at the time of grant, expected dividend yield of 0%, expected life of 5 years from the date of grant, and expected volatility of 10 and 25%. After the initial public offering on March 30, 2006, an expected volatility factor of 58% was used for the newly issued common stock options and the extension of common stock warrants and options. A newly issued stock option is an option that was granted on or after March 30, 2006 or a previously granted stock option that is modified on or after March 30, 2006. The fair value of all newly issued stock options grants is estimated using the Black-Scholes option pricing model with the following weighted average assumptions used for grants and modifications of prior grants made on or after March 30, 2006 for the six months ended June 30, 2007: risk-free, weighted average interest rate of 4.9% based on the U.S. Treasury yield curve in effect at the time of grant, expected dividend yield of 0%, expected life of 5 years from the date of grant (the remaining term of the option in the case of option extensions), and expected volatility of 58%. GeoPetro has selected 10 publicly traded “small cap” companies whose primary business is oil and gas exploration and production. Small cap, for purposes of this analysis, is defined as companies with a market capitalization under $1 billion. From this peer group of similar companies, GeoPetro randomly selected 10 companies and derived expected volatility factors for the most recent completed fiscal years for each entity as reported in their recently filed 10K or 10KSB Annual Reports with the Securities and Exchange Commission. Where the expected volatilities were expressed as a range, a simple average of the range is used as an expected volatility for that entity.
The options outstanding as of December 31, 2007 have the following contractual lives:
The total intrinsic value of options outstanding was approximately $4,725,000 and $3,285,088 at December 31, 2007 and 2006, respectively. The intrinsic value for exercisable options was $4,717,950 and $2,935,088 at December 31, 2007 and 2006, respectively. The total intrinsic value for stock options exercised was approximately $1,448,388 and $0 for the years ended December 31, 2007 and 2006, respectively.
As of December 31, 2007, there are 2,188,000 options which are exercisable. The remaining 482,000 options will become exercisable ratably over the next four years. The stock compensation expense related to the unvested awards is $291,910.
Earnings (Loss) Per Common Share-Basic earnings per share excludes dilution and is calculated by dividing net income or loss by the weighted average number of common shares outstanding for the period. Diluted earnings per share reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock or resulted in the issuance of common stock that then shared from the earnings of the entity. 1,684,817 and 3,231,542 Potential common shares for the periods ended December 31, 2007 and
December 31, 2006, respectively, were excluded from the earnings per share computation because the Company incurred a net loss and were anti-dilutive. There were 1,506,064 outstanding common stock warrants at December 31, 2005 as well as 20,000 outstanding common stock options on December 31, 2005, that were not included in the diluted EPS calculation because the warrants’ and options’ exercise prices were greater than the average market price of the common shares. 1,890,710 shares of Series AA Stock were not included in the diluted EPS calculation at December 31, 2005 because they were anti-dilutive.
Segment Reporting-GeoPetro has oil and gas exploration, development and production operations in the United States, Canada, Australia and Indonesia. All revenues and related costs are associated with operations in the United States. A summary of assets and capital expenditures by geographical segment is included in Note 3.
Cash and Cash Equivalents-Cash and cash equivalents include cash on hand, amounts held in banks and highly liquid investments purchased with an original maturity of three months or less.
Recently Issued Accounting Pronouncements-In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements,” which is effective for the Company beginning January 1, 2008 and provides a definition of fair value, establishes a framework for measuring fair value, and expands disclosures about fair value measurements for future transactions. The Company does not expect the adoption of this pronouncement to have a material impact on its financial position or results of operations.
On January 1, 2007, the Company adopted Financial Accounting Standards Board (“FASB”) Financial Interpretation No. (“FIN”) 48, Accounting for Uncertainty in Income Taxes - an interpretation of FASB Statement No. 109. FIN 48 clarifies the accounting for the uncertainty in recognizing income taxes in an organization in accordance with FASB Statement No. 109 by providing detailed guidance for financial statement recognition, measurement and disclosure involving uncertain tax positions. FIN 48 requires an uncertain tax position to meet a more-likely-than-not recognition threshold at the effective date to be recognized both upon the adoption of FIN 48 and in subsequent periods. The implementation of FIN 48 did not have a material effect on the Company’s financial statements. See Note 5.
In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities,” which permits an entity to measure certain financial assets and financial liabilities at fair value. The objective of SFAS No. 159 is to improve financial reporting by allowing entities to mitigate volatility in reported earnings caused by the measurement of related assets and liabilities using different attributes, without having to apply complex hedge accounting provisions. Under SFAS No. 159, entities that elect the fair value option (by instrument) will report unrealized gains and losses in earnings at each subsequent
reporting date. The fair value option election is irrevocable, unless a new election date occurs. SFAS No. 159 establishes presentation and disclosure requirements to help financial statement users understand the effect of the entity’s election on its earnings, but does not eliminate disclosure requirements of other accounting standards. Assets and liabilities that are measured at fair value must be displayed on the face of the balance sheet. The Company does not expect the adoption of this pronouncement to have a material impact on its financial position or results of operations.
3. SUMMARY OF OIL AND GAS OPERATIONS:
Capitalized costs at year end and costs incurred relating to GeoPetro’s oil and gas activities are summarized as follows:
Capitalized costs as of December 31, 2007 are as follows:
Costs incurred for the year ended December 31, 2007 are as follows:
Capitalized costs as of December 31, 2006 are as follows:
Costs incurred for the year ended December 31, 2006 are as follows:
Capitalized costs as of December 31, 2005 are as follows:
Costs incurred for the year ended December 31, 2005 are as follows:
Generally, sales or dispositions of oil and gas properties, including sales of partial interests in prospects, are treated as adjustments to capitalized costs, with no gain or loss recorded.
Evaluated Oil and Gas Properties-In periods prior to 2005 it was determined that the total net costs in the U.S. and Australian evaluated cost pool exceeded their net realizable value. Accordingly, impairment write-downs of $4,464,948 were recorded in the prior periods. During 2007 and 2006, impairment write-downs associated with the Canadian evaluated cost pool due to dry holes of $1,111,151, and $38,849 were recorded.
Unevaluated Oil and Gas Properties-United States-As GeoPetro’s properties are evaluated through exploration, they will be included in the amortization base. Costs of unevaluated properties in the United States at December 31, 2007, 2006 and 2005 represent exploration costs in connection with GeoPetro’s California and Alaska prospects. The prospects and their related costs in unevaluated properties have been assessed individually and no impairment charges were considered necessary for the United States properties for any of the periods presented. The current status of these prospects is that seismic data is being interpreted on an on-going basis on the subject lands within the prospects.
Drilling in the California and Alaska prospects is expected to commence as early as 2008 and will continue in future periods. As the prospects are evaluated through drilling in future periods, the property acquisition and exploration costs associated with the wells drilled will be transferred to evaluated properties where they will be subject to amortization.
Unevaluated Oil and Gas Properties-Australia-Unevaluated costs incurred in Australia represent costs in connection with the exploration of two exploration permit areas in Australia. The prospects and their related costs in unevaluated properties have been assessed individually and no impairment charges were considered necessary for the Australian properties for any of the periods presented. On June 20, 2007, the Company entered into a contract to sell its Australian Properties to an unaffiliated third party, See Note 10.
Unevaluated Oil and Gas Properties-Indonesia-Unevaluated costs incurred in Indonesia represent costs in connection with one production sharing contract area and additional exploration efforts in Indonesia. The prospect and its related costs in unevaluated properties have been assessed individually and no impairment charges were considered necessary for the Indonesian property for any of the periods presented. The current status of this prospect is that seismic data is being interpreted on an on-going basis to identify drilling locations on the subject lands within the prospect. In October 2005, the Company sold its interest in another Indonesian production sharing contract for cash consideration of $2,400,000. The proceeds realized were credited to the Indonesian unevaluated cost pool.
Drilling was commenced on the prospect early 2007 and is expected to continue in future periods. As the prospect is evaluated through drilling in future periods, the property acquisition and exploration costs associated with the wells drilled will be transferred to evaluated properties where they will be subject to amortization.
The Company retains a carried 12% stake in the Bengara (II) Block PSC through its subsidiary, Continental-GeoPetro (Bengara-II) Ltd. (“CGB2”), the operator company of the project with offices in Jakarta, Indonesia. GeoPetro’s partner, Continental Energy Corporation likewise retains an 18% interest in the Bengara (II) Block. CNPCHK (Indonesia) Limited owns the remaining 70% in the Bengara (II) Block and has paid 100% of the cost of drilling certain exploratory and appraisal wells.
In the event that the Company does not establish commerciality and provided that no extensions are granted for establishing commerciality, the Company must forfeit its interest in the production sharing contract. If the Company forfeits its interest, it will be necessary to record an impairment write-down equal to the capitalized costs recorded for the area forfeited.
Breakdown of Unevaluated Oil and Gas Properties-The following table sets forth a summary of oil and gas property costs not being amortized at December 31, 2007, by the period in which the costs were incurred:
Management expects that planned activities for the year 2008 will enable the evaluation of approximately 5% of the costs as of December 31, 2007. Evaluation of 30% of the remaining costs is expected to occur in 2008 with the remaining 65% in 2009 and beyond.
4. SHORT - TERM DEBT:
Short -term non-convertible debt at December 31, 2007 and December 31, 2006 consisted of the following:
(a) The Company issued a $1,000,000 short term promissory note on January 31, 2006 with a maturity date of January 31, 2007. The note may be repaid at any time without penalty. In the event the note is not repaid by the maturity date, the Company has agreed to dedicate 5% of the net cash flow from the Madisonville Project in Texas toward the repayment of the note and any accrued interest thereon. In connection with the note, the Company paid a loan origination fee of $30,000 and granted a three-year warrant exercisable to purchase 150,000 Common Shares at $3.50 per share. The fair value of the warrants on the date of issuance, $182,390, as well as the $30,000 loan origination fee, was recorded as a debt discount and is being amortized over the life of the promissory note. On February 1, 2007, the maturity date was extended to October 31, 2007. The Company has paid $80,000 accrued interest thru January 31, 2007. In connection with the extension, the Company paid a loan extension fee of $30,000 and granted a three-year warrant exercisable to purchase 50,000 Common Shares at $3.50 per share. The fair value of the warrants on the date of issuance, $57,242, together with the $30,000 loan extension fee, were recorded as a debt discount and are being amortized over the life of the promissory note. As of December 31, 2007, the unamortized debt discount was $0. The note plus accrued interest were paid in full on October 31, 2007.
(b) The Company issued a $500,000 short term promissory note payable on February 1, 2007 with a maturity date of October 31, 2007. The note may be repaid at any time without penalty. The principal plus accrued interest on the note are due on the maturity date. In connection with the note, the Company paid a loan origination fee of $15,000 and granted a three-year exercisable warrant to purchase 25,000 Common Shares at $3.50 per share. The fair value of the warrants on the date of issuance, $27,072, as well as the $15,000 loan origination fee, was recorded as a debt discount and is being amortized over the life of the promissory note. As of December 31, 2007, the unamortized debt discount was $0. The note plus accrued interest were paid in full on October 31, 2007.
(c) The Company issued a $300,000 short term promissory note payable on February 6, 2007 with a maturity date of October 31, 2007. The note may be repaid at any time without penalty. The principal plus accrued interest on the note are due on the maturity date. In connection with the note, the Company paid a loan origination fee of $9,000 and granted a three-year exercisable warrant to purchase 15,000 Common Shares at $3.50 per share. The fair value of the warrants on the date of issuance, $16,214, as well as the $9,000 loan origination fee, was recorded as a debt discount and is being amortized over the life of the promissory note. As of December 31, 2007, the unamortized debt discount was $0. The note plus accrued interest were paid in full on October 31, 2007.
(d) The Company issued a $100,000 short term promissory note payable on February 1, 2007 with a maturity date of October 31, 2007. The note may be repaid at any time without penalty. The principal plus accrued interest on the note are due on the maturity date. In connection with the note, the Company paid a loan origination fee of $3,000 and granted a three-year exercisable warrant to purchase 5,000 Common Shares at $3.50 per share. The fair value of the warrants on the date of issuance, $5,414, as well as the $3,000 loan origination fee, was recorded as a debt discount and is being amortized over the life of the promissory note. As of December 31, 2007, the unamortized debt discount was $0. The note plus accrued interest were paid in full on October 31, 2007.
5. INCOME TAXES:
The Company files income tax returns in the U.S. federal jurisdiction and various states. The Internal Revenue Service recently completed an examination of the Company’s U.S. income tax return for 2004. As a result of this examination, the Company’s federal net operating loss was adjusted downward by $401,235. There are currently no federal or state income tax examinations underway. Furthermore, the Company is no longer subject to U.S. federal income tax examinations by the Internal Revenue Service for tax years before 2005 and for state and local tax authorities for tax years before 2002. The Company does, however, have net operating losses generated in tax years 1997 and after, which remain open for examination.
The Company adopted the provisions of FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes, on January 1, 2007. As a result of the adoption of FIN 48, the Company had unrecognized tax benefits of $86,000 as of the date of adoption. This unrecognized tax benefit has been reduced to zero as of December 31, 2007 because the uncertain tax position was ultimately not deducted in the 2006 tax returns. There have been no other changes during the year with respect to unrecognized tax benefits. The Company does not foresee the total amounts of unrecognized tax benefits significantly increasing within the next 12 months. Furthermore, no corresponding interest and penalties have been accrued as the Company is in a net operating loss position.
The Company provides for income taxes in accordance with Statement of Financial Accounting Standards No. 109, Accounting for Income Taxes (“SFAS 109”). SFAS 109 requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of temporary differences between the financial statement carrying amounts and the tax basis of the assets and liabilities. Where it is more likely than not that a tax benefit will not be realized, a valuation allowance is recorded to reduce the deferred tax asset to its realizable value.
A valuation allowance has been provided against the Company’s net deferred tax assets as the Company believes that it is more likely than not that the net deferred tax assets will not be realized.
The effective tax rate for the year ended December 31, 2007 is 3.1 percent (benefit) and is due largely to a refund of prior year alternative minimum tax (“AMT”) which is partially offset by a liability for Texas Margin Tax.
The provision for income taxes consist of the following:
The actual income tax (benefit) expense differs from the expected tax (benefit) expense as computed by applying the U.S. Federal corporate income tax rate of 35% for each period as follows:
Deferred income taxes reflect the net tax effects of temporary differences between carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. Significant components of the Company’s deferred tax assets (liabilities) are as follows:
As of December 31, 2007, GeoPetro had net operating loss (NOL) carryforwards of approximately $24,771,000 for federal income tax purposes which begin to expire in 2010. However, in accordance with SFAS 123(R), a deferred tax asset has not been recognized for the portion of the net operating loss carryforwards that is attributable to excess tax deductions associated with the exercise of stock options in 2007 which do not reduce income taxes payable. Accordingly, $2,128,000 of GeoPetro’s federal NOL has not been benefited for financial statement purposes as it relates to excess tax deductions that have not reduced income taxes payable. The benefit of these excess tax deductions will not be recognized for financial statement purposes until the related deductions reduce income taxes payable.
The Company also has $11,112,000 of California and Alaska net operating losses which begin to expire in 2008. In accordance with SFAS 123(R), a portion of the state NOLs has similarly not been benefited for financial statement purposes as it relates to excess tax deductions which have not resulted in the reduction of income taxes payable. The benefit of such excess tax deductions will not be recognized for financials statement purposes until the related deductions reduce state income taxes payable.
In addition, the Company has $341,000 of carryforward credits in Texas, a portion of which may be utilized each year against Texas Margin Tax liability through 2027.
6. RELATED PARTY TRANSACTIONS:
During December 2007, the Board of Directors approved the cashless exercise provision of options for officers, directors and employee such that “Fair Market Value” shall equal the lesser of “Market Price” or $2.92., Cashless exercise is the security holder’s election to receive that number of shares of the Corporation’s Common Stock that is equal to the quotient of: i) the Fair Market Value of such Shares, less the Exercise Price then in effect, multiplied by the number of Shares that the security holder would otherwise have been entitled to purchase; over ii) the Fair Market Value
of $2.92. The total common stock issued upon cashless exercise was 249,963 shares. The Company paid totaled $386,600 in taxes in connection with the cashless options exercise.
On April 25, 2007, May 9, 2007, and June 13, 2007, an officer and director, exercised warrants to purchase 80,000, 70,000 and 33,333 shares of common stock at an exercise price of $2.00, $2.00 and $4.00 per share, respectively. The warrants were granted on June 18, 2000 and had expiration dates of between June 18 and June 30, 2007. On November 1, 2007, the same officer and director, exercised options to purchase 50,000 shares of common stock at an exercise price of $2.00 per share. The options were granted on December 29, 2000 and had expiration date of December 29, 2007.
On February 12, 2007, Stuart J. Doshi, President and CEO, loaned $100,000 to the Company. The note bore interest at 8% annually and was payable on demand. The note plus accrued interest was repaid on March 28, 2007.
On June 7, 2006, the Company loaned $1,000,000 to G. Carter Sedanoui (“Borrower”), a shareholder, evidenced by a short term promissory note payable to the Company with a maturity date on March 31, 2007. On March 30, 2007, the Company extended the maturity date of the note to June 30, 2007. The note plus the accrued interest was paid in full on June 29, 2007.
The Company appointed David G. Anderson as a Director on March 30, 2006. Mr. Anderson is the Senior Vice President and a director of Dundee Securities Corporation, the lead underwriter in connection with a sale of common shares the Company completed on March 30, 2006. The decision to distribute the common shares and the determination of the terms of the distribution were made through arm’s length negotiations primarily between the Company and Dundee Securities Corporation as lead underwriter. Mr. Anderson had some involvement in such negotiations solely in his capacity as a director and officer of Dundee Securities Corporation. Dundee Securities Corporation received an underwriters’ fee totaling $632,000 in connection with the offering.
7. SHAREHOLDERS’ EQUITY:
GeoPetro’s articles of incorporation allow for the issuance of 100,000,000 shares of common stock, 1,000,000 shares of Series A preferred stock (“Series A Stock”), 5,000,000 shares of
Series AA preferred stock (“Series AA Stock”), and an additional 44,000,000 shares of preferred stock which may be issued from time to time in one or more series.
Common Stock-The holders of common stock are entitled to one vote per share. Subject to preferences on outstanding preferred stock, the holders of common stock are entitled to receive ratably such dividends as may be declared by the board of directors. In the event of a liquidation, the holders of common stock and Series A preferred stock are entitled to share ratably in all assets remaining after payment of liabilities, subject to prior distribution rights of preferred stock.
Conversion of Series A Stock-Upon completion of the Company’s initial public offering on March 30, 2006, all of the 1,000,000 shares of Series A Stock automatically converted into a like number of common shares.
Conversion of Series AA Preferred Stock-On March 28, 2007, all 1,890,710 of the Company’s outstanding shares of Series AA Stock automatically converted into 1,890,710 shares of our common stock, no par value per share. Under the Company’s Amended and Restated Articles of Incorporation, the Series AA stock automatically converts into common shares on a one-for-one share basis effective the first trading day after the reported high selling price for our common shares is at least $5.25 per share for any consecutive ten trading days, which condition was met on March 27, 2007. Dividends accrued on the Series AA Stock at a rate of $0.28 per annum, per share, while the Series AA Stock was outstanding. In 2006, dividends paid on the Series AA Stock totaled $529,400. Pursuant to the terms of the Series AA Stock, no dividends are payable for the first quarter of 2007.
8. COMMON STOCK OPTIONS:
Effective as of September 10, 2001, the board of directors approved an incentive stock plan, providing for awards under the terms and provisions of such plan of incentive stock options, stock appreciation rights and restricted stock awards to officers, directors and employees of GeoPetro and its consultants (the “Stock Incentive Plan”). The plan provides, among other provisions, the following:
The maximum number of Common Shares which may be awarded, optioned and sold under the plan is 5,000,000 (subject to adjustment for stock splits, stock dividends and certain other adjustments to GeoPetro’s common stock); and the per share exercise price for Common Shares to be issued pursuant to the exercise of an option shall be no less than the fair market value of GeoPetro’s Common Shares as of the date of grant.
The Stock Incentive Plan provides for the granting to employees of incentive stock options within the meaning of Section 422 of the United States Internal Revenue Code of 1986, as amended, and for the granting of non-statutory stock options to directors who are not employees and consultants. In the case of employees who receive incentive stock options which are first exercisable in a particular calendar year and the aggregate fair market value of which exceeds $100,000, the excess of the $100,000 limitation shall be treated as a nonstatutory stock option under the Stock Incentive Plan.
The Stock Incentive Plan is being administered by the Board of Directors. The Board of Directors determines the terms of the options granted, including the number of Common Shares subject to each option, the exercisability and vesting requirements of each option,
and the form of consideration payable upon the exercise of such option (i.e., whether cash or exchange of existing Common Shares in a cashless transaction or a combination thereof).
The Stock Incentive Plan will continue in effect for 10 years from September 10, 2001 (i.e., the date first adopted by the Board), unless sooner terminated by the board of directors. The Company has implemented a new 2004 Stock Option and Appreciation Rights Plan (the “Stock Option Plan”) for the issuance of options to purchase Common Shares and/or stock appreciation rights in 2004 or thereafter to directors, officers, employees and consultants of the Company and its subsidiaries. The Stock Option Plan has replaced the Stock Incentive Plan. Outstanding options issued under the Stock Incentive Plan will continue to be outstanding in accordance with their terms and the terms of the Stock Incentive Plan, but will count toward the limits in the amount of Common Shares available to be issued under the Stock Option Plan.
During 2007, no options were issued to employees or directors. No stock-based compensation was recognized for the year ended December 31, 2005. Effective January 1, 2006, the Company adopted SFAS 123 (R) resulting in stock compensation expense for the twelve months period ended December 31, 2006 of $201,335. During 2006, 150,000 stock options were issued to directors and during 2005, 20,000 stock options were issued to employees pursuant to the Stock Option Plan.
A summary of the status of GeoPetro’s stock option plan is as follows:
The weighted average fair value of options granted during the year ended December 31, 2005, as calculated under the Black-Scholes pricing model is $0.70 and for the weighted average fair value of options granted in 2006, as calculated under the same method was $1.83 per share.
The fair value of each option grant is estimated on the date of grant using the Black-Scholes option pricing model with the following weighted-average assumptions used for grants in 2005 and 2006: risk-free, weighted-average interest rates ranging from 3.75 to 4.9 percent based on the U.S. Treasury yield curve in effect at the time of grant, expected dividend yield of
0 percent, expected life of 5 years from the date of grant, and expected volatility of 10 and 58 percent.
The options outstanding as of December 31, 2007 have the following contractual lives:
The total intrinsic value of options outstanding was approximately $4,725,000 and $3,285,088 at December 31, 2007 and 2006, respectively. The intrinsic value for exercisable options was $4,717,950 and $2,935,088 at December 31, 2007 and 2006, respectively. The total intrinsic value for stock options exercised was approximately $1,448,388 and $0 for the years ended December 31, 2007 and 2006, respectively.
As of December 31, 2007, there are 2,188,000 options which are exercisable. The remaining 482,000 options will become exercisable over the next four years. The stock compensation expense related to the unvested awards is $291,910.
9. COMMON STOCK WARRANTS:
During 2007, the Company issued a two-year exercisable common stock warrant to purchase 25,000 Common Shares at $3.50 and $4.51 per share to an unaffiliated third party for geophysical services. The purchase right under the warrant has an expiration date of February 12, 2009 and February 28, 2009 unless terminated earlier in accordance with the stock warrant purchase agreement. The fair value of the warrants totaled $32,533 and was capitalized in oil and gas properties as part of the U.S. cost pool.
In conjunction with the issuance of a short term note payable during 2007, GeoPetro issued warrants to purchase 95,000 shares of GeoPetro’s common stock at exercise prices of $3.50 per share. The purchase rights under the warrants have expiration date of January 31, 2010 unless terminated earlier in accordance with the stock warrant purchase agreement. The fair value of the warrants issued on the date of the grant, $105,945 and origination fees of $57,000 were recorded as discount to notes payable and were being amortized as interest expense over the term of the note. As of December 31, 2007, the unamortized amount was $0.
In conjunction with the private placement on August 13, 2007, the Company issued warrants to purchase 660,857 shares of GeoPetro’s common stock at exercise price of $4.50 and $3.50 per share. These warrant issuances are discussed in Note 4.
The following table summarizes the number of shares reserved for the exercise of common stock purchase warrants as of December 31, 2007:
In conjunction with the issuance of a short term note payable during 2006, GeoPetro issued warrants to purchase 150,000 shares of GeoPetro’s common stock at exercise prices of $3.50 per share. The purchase rights under the warrants have expiration date of January 31, 2009 unless terminated earlier in accordance with the stock warrant purchase agreement. The fair value of the warrants issued on the date of the grant, $182,390, was recorded as a discount to notes payable and is being amortized as interest expense over the term of the note. As of December 31, 2006, the unamortized amount is $17,966.
The following table summarizes the number of shares reserved for the exercise of common stock purchase warrants as of December 31, 2006:
In conjunction with the issuance of units of equity securities during 2005, GeoPetro issued warrants to purchase 37,000 shares of GeoPetro’s common stock at exercise prices of $5.00 per share. The purchase rights under the warrants have expiration dates from June 30, 2006 to February 28, 2008 unless terminated earlier in accordance with the stock warrant purchase agreement. The Company agreed to extend the warrants by a period of one year for a total of 143,334 shares. The fair value of the warrants on the date of extension, $32,404, was disclosed and combined with compensation expense, FAS 123 in Note 2 and $2,927 was recorded as consulting expense.
The following table summarizes the number of shares reserved for the exercise of common stock purchase warrants as of December 31, 2005:
10. COMMITMENTS AND CONTINGENCIES:
Employment Agreements-The Company entered into a contract of employment with Stuart J. Doshi, Founder, President, Chief Executive Officer and Chairman of the Board of Directors, dated July 28, 1997 (effective July 1, 1997) and amended on January 11, 2001, July 1, 2003, April 20, 2004, May 9, 2005, July 28, 2005 and January 30, 2006. The contract as amended provides for a five-year term commencing May 1, 2005 which term is automatically extended for successive two-year renewal terms unless: (a) the board of directors elects not to renew the contract and the Company provides notice to Mr. Doshi of such non-renewal at least six months prior to the expiry of his employment term or any renewal term, or (b) Mr. Doshi attains age 75, in which case the term ends upon the completion of the calendar year in which he becomes 75 years old unless the Company and Mr. Doshi mutually agree to one-year extensions. The contract of employment currently provides for an annual base salary of $300,000 and further provides that in the event of a change of control of the Company or if Mr. Doshi is terminated without cause, he is entitled to receive (a) in exchange for all of his vested stock options and vested restricted shares, such number of Common Shares having a market value equal to the difference between (x) the aggregate total market value of all vested restricted shares and Common Shares he would receive upon exercise of all vested stock options less (y) the aggregate total exercise price for all of his vested stock options; provided, however, that if the Common Shares to be delivered to Mr. Doshi upon such change of control or termination have not been registered so as to permit immediate public resale, Mr. Doshi shall instead receive a cash payment equal to the market value on the date of termination of all vested stock options and restricted shares without any discount for liquidity or minority position against cancellation of such options and restricted shares, (b) a cash payment equal to the greater of (i) his compensation for the remainder of his term, including salary and the aggregate amount of his bonuses in respect of the last four fiscal years and (ii) four times his compensation in the current year, including his then-current salary and the average amount of his bonuses for the last four fiscal years, and (c) an additional cash payment representing his employment benefits equal to 20% of the amount of salary he is entitled to receive under (b)(i) or (b)(ii) above, as applicable. In addition, in the event of a change of control or termination without cause, all unvested options issued by the Company to Mr. Doshi will vest.
GeoPetro has executed an employment contract dated April 28, 1998 and amended on June 15, 2000, May 12, 2003 and January 1, 2005 with its Vice President of Exploration, David V. Creel. The contract provides an annual salary of $150,000 and may be terminated by GeoPetro without cause upon the payment to Mr. Creel of cash payments equal to the lesser of three months’ base salary or base salary during the remainder of the employment term, and, in the event of termination without cause, all unvested options issued by GeoPetro to Mr. Creel will vest. On December18, 2006, the independent members of the board of directors, acting on the recommendations of Stuart J. Doshi, the President and CEO, voted to increase the salary of Mr. Creel, to $163,200 annually effective January 1, 2007.
GeoPetro has executed an employment contract dated June 19, 2000 and amended on December 12, 2002, January 1, 2005, and December 18, 2007 with its Vice President of Finance and Chief Financial Officer, J. Chris Steinhauser. The contract provides for an annual salary of $163,200 and may be terminated by GeoPetro without cause upon the making of cash payments equal to the lesser of three months’ base salary or base salary during the remainder
of the employment term, and, in the event of termination without cause, all unvested warrants issued by GeoPetro to Mr. Steinhauser will vest.
Office Lease-Effective March 1, 2004, GeoPetro is committed under an office sublease which provides for a sixty month term. The sublease is cancelable by either party after thirty-six months. The sublease provides for minimum monthly lease payments of $5,788 during the first thirty-six months of the lease term and $6,527 per month from the thirty-seventh month to the sixtieth month. Minimum annual rentals due under this agreement are as follows:
Rent expense for the years ended December 31, 2007, 2006, and 2005, was approximately $76,856, $69,466, and $69,466 respectively, and is included in general and administrative expenses in the accompanying statements of operations.
Madisonville MGP Agreement-GeoPetro owns a 100% working interest in leases located in Madisonville (Rodessa) Field in Madison County, Texas. GeoPetro’s working interest covers the Rodessa formation interval at approximately 11,800 feet of depth. The Rodessa reserves are being developed through the re-entry and recompletion of the Ruby Magness No. 1 well (originally drilled in 1994) and the drilling of additional well locations. The natural gas in the Rodessa formation contains 28% impurities which must be removed in order to meet pipeline quality specifications.
In this connection, GeoPetro entered into agreements with a subsidiary of a NYSE listed company, Hanover Compressor Company (“Hanover”), that funded, constructed, installed and operated a dedicated gas treatment plant to process the Rodessa gas. The gas treatment plant is presently capable of treating and bringing up to pipeline specifications approximately 18 million cubic feet of inlet gas per day. Gateway Processing Company (“Gateway”) has installed field gathering pipelines and a sales pipeline with an estimated capacity of at least 70 million cubic feet of gas per day to transport the treated natural gas to a major pipeline in the area.
Effective July 25, 2005, Madisonville Gas Processing, LP (“MGP”) purchased the natural gas treatment plant from Hanover. Concurrent with MGP’s purchase of the gas treatment plant, the Company, Gateway and MGP terminated the Hanover/Gateway agreements and entered into a new agreement, (the “MGP Agreement”), to treat and transport the Company’s gas production from the Madisonville Project. As a result of the MGP Agreement, MGP has committed to install and make operational additional treating facilities capable of treating 50 MMcf/d, which combined with the capacity of the current in-service treating facilities will represent a total treating capacity of 68 MMcf/d for the Madisonville treatment plant.
The term of the MGP Agreement commenced August 1, 2005 and continues so long as the Company owns any oil and gas leases in the Madisonville Field, provided that it shall terminate 30 years from the effective date unless extended. Under the terms of the MGP Agreement, the Company has committed all natural gas production from its interest in the Madisonville Project to MGP. MGP purchases the untreated natural gas from the Company at the well site point of delivery for a net price equal to the weighted average price per MMBTU that MGP receives for the natural gas delivered to the sales pipeline less certain gathering, treatment and transportation charges. The gathering, treatment and transportation price adjustments are described below. All proceeds from MGP’s sale of Rodessa Formation gas are deposited in an escrow account and then disbursed in accordance with the joint direction of the Company and MGP.
The MGP Agreement provides that certain gathering, treating and transportation fees shall be paid to MGP from the escrow account. The MGP Agreement provides that MGP will receive a gathering and marketing fee of $0.07 and $0.01 per Mcf, respectively, of gas measured and delivered to the natural gas treatment plant. In addition, for the first 18,000 Mcf/d of gas measured and delivered to the inlet flange of the gas treatment plant, MGP will receive a treating fee of $1.50 per Mcf. This treating fee will remain in effect until September 30, 2010. For any gas volumes in excess of 18,000 Mcf/d of gas delivered to the inlet flange of the gas treatment plant, MGP will receive a treating fee of $1.10 per Mcf. Beginning October 1, 2010, this fee of $1.10 per Mcf shall be charged for all gas measured and delivered to the plant. One-quarter (¼) of the foregoing treating fees will be adjusted using the Producer Price Index for Industrial Commodities (“PPI”) and one-quarter (¼) using the Consumer Price Index (“CPI”) commencing January 1, 2006. One-half (½) of the foregoing gathering and marketing fees will be adjusted using the Consumer Price Index (“CPI”) commencing January 1, 2006. The Company has the right, upon giving 60 days’ notice, to terminate the marketing fee whereupon it shall assume the sole responsibility of marketing the natural gas sold.
For the first 18,000 Mcf/d of gas measured and delivered to the inlet flange of the gas treatment plant, Gateway will receive a transportation fee of $0.10 per Mcf. This fee will remain in effect for 36 months from the effective date of the MGP Agreement. Beginning in the 37th month and terminating at the end of the 60th month from the effective date of the MGP Agreement, the fee shall be reduced to $0.08 per Mcf for the first 18,000 Mcf/d of gas measured and delivered to the inlet flange of the gas treatment plant. For any gas volumes in excess of 18,000 Mcf/d of gas measured and delivered to the inlet flange of the gas treatment plant, Gateway will receive a transportation fee of $0.12 per Mcf measured and delivered from the outlet flange of the plant. This fee will remain in effect 36 months from the effective date of the MGP Agreement and shall be reduced to $0.10 per Mcf thereafter. After 60 months, this transportation fee shall be $0.10 per Mcf for all volumes delivered from the outlet flange of the plant.
The foregoing gathering, treatment and transportation price adjustments are inclusive of all costs and expenses to gather, separate, treat, dehydrate and transport natural gas produced and delivered from the Company’s well(s).
The Company has committed to a three-well drilling program to facilitate the expansion of the gas treatment plant. The Company has drilled two of the three required wells to the Rodessa formation. The commitment requires the Company to drill the third well sufficient to test the Smackover Formation (estimated to be encountered at approximately 18,000 feet) on or before September 30, 2008. It is estimated that the 18,000 foot well will cost $12 million to drill and complete. The Company has granted MGP a security interest in the Madisonville Field properties to secure the three well commitment. The security interest shall be subordinated to any third party lender in the event the Company secures future debt against the property. MGP has granted the Company a similar security interest in the gas treatment plant to secure its obligation to expand the treatment plant on a timely basis.
Madisonville Net Profits Interest-Redwood LP’s 100% working interest is subject to a net profits interest in favor of an unrelated third party. The net profits interest is 12.5% (proportionately reduced) of the net operating profits until payout is achieved. After payout, the net profits interest increases to 30% (proportionately reduced). Payout, for purposes of the net profits interest, is defined and achieved at such time as Redwood LP has recouped from net operating cash flows its total net investment in the project plus a 33% cash on cash return.
The Cook Inlet Alaska CBM Project-The Company entered into an agreement with Pioneer Oil Company, Inc. (“Pioneer”) dated April 20, 2005, wherein it acquired a 100% working interest (81% net revenue interest) in approximately 117,000 acres onshore in Cook Inlet, Alaska. The Company has subsequently acquired an additional 5,000 acres in this project. The terms provide for the Company to pay total consideration of $20 per acre, or approximately $2.3 million, for the leases. The Option provides that the Company will pay the total lease consideration in two installments. The Company paid the first installment totaling $1,068,063 on August 17, 2005 and has received assignment of the 100% working interest in the leases. Within three years from the date of receipt of legally sufficient assignment of the 100% working interest in the leases, the Company has the option to conduct a $2.5 million work program on the leases over a three-year period, and, after completion of the work program and an evaluation of the results, to remit the final additional acreage consideration of $10 per acre for the leases. The agreement provides that if the Company fails to pay the lease consideration when due, fails to perform the work program or otherwise defaults under the agreement, it shall forfeit its interest and reassign the leases to Pioneer with no further liability to GeoPetro.
Sale of Australian Interests, EP 381 & EP 408-On June 20, 2007, the Company agreed to sell and transfer all of its remaining property interests in Australia to an unrelated party for cash consideration and a Petroleum Sales Royalty Payment equal to 25% of the future annual earnings before interest, taxes, depreciation and amortization from the property interests. Specifically, the agreement provides that the Company will be paid consideration for the sale and transfer of its property interests as follows:
1. Initial cash consideration of $175,000 was received on November 19, 2007;
2. a second cash payment of $175,000 upon a successful flow test of petroleum from a well located on the property interests. A successful flow test is defined for purposes of this agreement to be a test of at least 7 million standard cubic feet of natural gas for a continuous and uninterrupted 24 hour period (or an equivalent oil/condensate rate based on a conversion ratio of 6000 cubic feet of gas to a barrel of oil or condensate); and,
3. a Petroleum Sales Royalty Payment equal to 25% of the future annual earnings before interest, taxes, depreciation and amortization from the property interests up to a total amount of $2,200,000.
Goodwin Prospect, Central Alberta, Canada-On June 21, 2007, the Company entered into a participation agreement wherein it acquired a 50% non-operated working interest in the Goodwin Prospect, which is located in the Central Alberta Basin, Canada. A total of 12,000 acres can be earned by the Company by the drilling of wells. During 2007, the Nexstar Goodwin 16-1958-12 Well was drilled. The Company has production tested this well and determined that it is non-commercial. The Company has plugged and abandoned this well. As a result, the Company recorded a ceiling test writedown of $543,042 in the year of 2007.
Swan Hills Project. Central Alberta, Canada-On October 17, 2007, The Company acquired a 33% non-operated working interest in 4,400 acres in the Central Alberta Basin, Alberta, Canada. The Company paid a total of $274,000 to acquire these leases.
Wildwood Prospect, Central Alberta, Canada-On October 1, 2007, the Company entered into a participation agreement wherein it acquired a 50% non-operated working interest in the Wildwood Prospect, which is located in the Wildwood Alberta Basin, Canada. On December 17, 2007, The Wildwood 11-22-55-09 well was spudded , with Ironhand Drilling Rig #1. The Company has production tested this well and determined that it is non-commercial. The Company has plugged and abandoned this well. As a result, the Company recorded a ceiling test writedown of $551,065 in the year of 2007.
11. SUBSEQUENT EVENTS:
South Dry Hollow Prospect, Lavaca County, Texas-On February 26, 2008, the Company’s subsidiary, South Texas GeoPetro LLC, entered into a participation agreement wherein it acquired a 15% non-operated working interest in the South Dry Hollow Prospect, which is located in Lavaca County, Texas. On February 25, 2008, the Company paid a $150,000 prospect fee and advanced $1.1 million to drill the Eichhorn #1 Well. The Eichorn #1 Well shall be drilled to a total depth sufficient to test the Rochelle Sand, the top of which is at a stratigraphic equivalent depth of approximately 16,000 feet.
12. UNAUDITED SUPPLEMENTARY OIL AND GAS RESERVE INFORMATION:
The following supplementary information is presented in compliance with United States Securities and Exchange Commission regulations and is not covered by the report of GeoPetro’s independent registered public accountants. The information required to be disclosed for the years ended 2007, 2006 and 2005 in accordance with FASB Statement No. 69, “Disclosures about Oil and Gas Producing Activities,” is discussed below and is further detailed in the following tables.
The reserve quantities and valuations for fiscal 2007 and 2006 are based upon estimates by MHA Petroleum Consultants. The reserve quantities and valuations for fiscal 2005 is based upon estimates by Sproule Associates Inc. The proved reserves presented herein are located entirely within the United States. Proved reserves are the estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e. prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions. Reservoirs are considered proved if economic productivity is supported by either actual production or a conclusive formation test. The area of a reservoir considered proved includes
(A) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any, and (B) the immediately adjoining portions not yet drilled, but which can reasonably be judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.
Proved developed reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas reserves expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.
The estimates included in the following tables are by their nature inexact and are subject to changing economic, operating and contractual conditions. At December 31, 2007, all of GeoPetro’s reserves are attributable to three producing wells, one shut-in wells and an undeveloped location. Other than the one producing well which has been on production since May 2003, one shut-in well which was placed on production in March 2006, and another shut-in well which was placed on production in June 2007. There is no other production history as of or subsequent to that date. Reserve estimates for these wells are subject to substantial upward or downward revisions after production commences and a production history is obtained. Accordingly, reserve estimates of future net revenues from production may be subject to substantial revision from year to year. Reserve information presented herein is based on reports prepared by independent petroleum engineers.
The assumptions used to compute the standardized measure are those prescribed by the Financial Accounting Standards Board and, as such, do not necessarily reflect GeoPetro’s expectations for actual revenues to be derived from those reserves nor their present worth. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations since these are the basis for the valuation process.
PROVED RESERVES PRESENTED HEREIN ARE LOCATED
ENTIRELY WITHIN THE UNITED STATES
For purposes of the following disclosures, estimates were made of quantities of proved reserves and the periods during which they are expected to be produced. Future cash flows were computed by applying year-end prices to estimated annual future production from proved gas reserves. The average year-end prices for gas were as indicated below. Future development and production costs were computed by applying year-end costs to be incurred in producing and further developing the proved reserves. Future income tax expenses were computed by applying, generally, year-end statutory tax rates (adjusted for permanent differences, tax credits and allowances) to the estimated net future pre-tax cash flows. The discount was computed by application of a 10% discount factor. The calculations assume the continuation of existing economic, operating and contractual conditions. However, such arbitrary assumptions have not proven to be the case in the past. Other assumptions of equal validity could give rise to substantially different results.
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
RELATING TO PROVED PETROLEUM AND NATURAL GAS RESERVES
(UNAUDITED)
AVERAGE YEAR-END PRICE
The following are the principal sources of changes in the standardized measure of discounted future net cash flows:
CHANGES IN THE STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH
FLOWS FROM PROVED PETROLEUM AND NATURAL GAS RESERVE
QUANTITIES (Unaudited)
PROVED RESERVES ARE LOCATED ENTIRELY WITHIN THE UNITED STATES
13. UNAUDITED SUPPLEMENTAL QUARTERLY FINANCIAL DATA:
The sum of the individual quarterly net income per common share amounts may not agree with year-to-date net income per common share because each period’s computation is based on the weighted average number of shares outstanding during that period.
EXHIBIT INDEX
Exhibit
Number­
Description
3.1 (2)
Amended and Restated Articles of Incorporation of GeoPetro Resources Company
3.2 (4)
Amended and Restated Bylaws of the GeoPetro Resources Company
4.1 (2)
Form of Warrant issued by GeoPetro Resources Company to various investors on various dates.
4.2 (3)
Specimen Common Stock Certificate
4.3
Form of common stock purchase warrant issued to various investors dated August 13, 2007 (filed as exhibit 4.1 to the Company’s Report on Form 8-K as filed with the Securities and Exchange Commission on August 16, 2007, and incorporated herein by reference)
4.4
Registration Rights Agreement between GeoPetro Resources Company and various investors dated August 13, 2007 (filed as Exhibit B to the Form of Unit Subscription Agreement dated August 13, 2007 filed as Exhibit 10.20 to the Company’s Report on Form 8-K as filed with the Securities and Exchange Commission on August 16, 2007 and incorporated herein by reference)
4.5 (6)
Placement Agent Warrant dated August 13, 2007
10.1 (2)
Joint Venture Agreement Bengara II, Dated January 1, 2000
10.2 (2)
Production Sharing Contract Bengara II, Dated December 4, 1997
10.4 (2)
Exploration Permit#408, Dated July 2, 1997
10.5 (2)
Madisonville Field Development Agreement Dated August 1, 2005
10.6 (2)
Alaska Cook Inlet Option dated April 20, 2005
10.7 (2)
The 2001 Stock Incentive Plan
10.8 (2)
The 2004 Stock Option and Appreciation Rights Plan
10.9 (2)
Stuart Doshi Employment Agreement, Dated July 28, 1997 (effective July 1, 1997) and amendments dated January 11, 2001, July 1, 2003, April 20, 2004, May 9, 2005, July 28, 2005 and January 30, 2006
10.10 (2)
David Creel Employment Agreement, Dated April 28, 1998 and amendments dated June 15, 2000, May 12, 2003 and January 1, 2005
10.11 (2)
J. Chris Steinhauser Employment Agreement, Dated June 19, 2000 and amendments dated December 12, 2002 and January 1, 2005
10.12 (2)
Office Lease Agreement, Dated effective March 1, 2004
10.13 (2)
Promissory Note to Pinehill Capital Inc., Dated January 31, 2006
10.14 (2)
Form of Subscription Agreement for GeoPetro Resources Company stock executed by various investors on various dates.
10.15 (2)
Promissory note between GeoPetro and G. Carter Sednaoui dated June 7, 2006
10.16 (2)
Flow-Through Share Agreement between GeoPetro Resources Company and GeoPetro Canada Ltd., Dated March 30, 2006
10.17 (2)
Form of Flow-Through Share Agreement between GeoPetro Resources Company and various investors, Dated March 30, 2006
10.19 (5)
Shares Sale & Purchase Agreement Dated September 29, 2006
10.20 (6)
Form of Unit Subscription Agreement Dated August 13, 2007
10.22 (6)
Promissory Note to Stuart Doshi dated February 12, 2007
10.23 (7)
Third Amendment to J. Chris Steinhauser Employment Agreement dated December 18, 2007
21.1 (1)
List of Subsidiaries of GeoPetro
23.3 (1)
Consent of MHA Petroleum Consultants
31.1 (1)
Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer.
31.2 (1)
Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer.
32.1 (1)
Certification of Chief Executive Officer and Chief Financial Officer of GeoPetro Resources Company pursuant to 18 U.S.C. § 1350.
(1) Filed herewith.
(2) Filed as the identically numbered exhibit to the Registration Statement on Form S-1, (No. 333-135485), as filed with the Securities and Exchange Commission on June 30, 2006, and incorporated herein by reference.
(3) Filed as the identically numbered exhibit to the Registration Statement on Form S-1, (No. 333-135485), as filed with the Securities and Exchange Commission on January 31, 2007, and incorporated herein by reference.
(4) Filed as the identically numbered exhibit to the Company’s Annual Report on Form 10-K as filed with the Securities and Exchange Commission on April 2, 2007, and incorporated herein by reference.
(5) Filed as the identically numbered exhibit to the Registration Statement on Form S-1 (No. 333-135485), as filed with the Securities and Exchange Commission on January 9, 2007, and incorporated herein by reference.
(6) Filed as the identically numbered exhibit to the Registration Statement on Form S-1 (No. 333-146557), as filed with the Securities and Exchange Commission on October 9, 2007, and incorporated herein by reference.
(7) Filed as Exhibit 10.1 to the Company’s Report on Form 8-K, as filed with the Securities and Exchange Commission on December 21, 2007. Securities and Exchange Commission on December 21, 2002, and incorporated herein by reference.
 Indicates a management or compensatory plan or arrangement.