ITEM 1.
BUSINESS
Corporate Organization
We were incorporated under the laws of the State of Nevada on April 12, 2005 under the name “Carlin Gold Corporation”. On July 19, 2005, we changed our name to “Nevada Gold Corp.” On October 18, 2005, we changed our name to “Gulf States Energy, Inc.” and increased our authorized capital from 100,000,000 shares of common stock to 500,000,000 shares of common stock, par value $0.001 per share. On September 5, 2006, we changed our name to “Strategic American Oil Corporation”.
We own 100% of the issued and outstanding share capital of (i) Penasco Petroleum Inc., a Nevada corporation, (ii) Galveston Bay Energy, LLC, a Texas Corporation and (iii) SPE Navigation I, LLC, a Nevada limited liability corporation.
Our principal offices are located at 800 Gessner, Suite 200, Houston, Texas, 77024. Our telephone number is (281) 408-4880 and our fax number is (281) 408-4879.
General
We are a natural resource exploration and production company engaged in the exploration, acquisition, development, and production of oil and gas properties in the United States. As of July 31, 2011, we maintain developed acreage both onshore and offshore in Texas and Illinois. As of July 31, 2011, we were producing oil and gas from our working interest in three wells onshore in Texas and in three of our offshore fields in Galveston Bay. We also own overriding royalty interests in producing properties in Louisiana and carried working interests in one field in Illinois under development.
As part of our ongoing business strategy, we continue to review and evaluate acquisition opportunities in Texas, Illinois and other areas of the continental United States.
Exploration and Production Activities
Our oil and gas interests are as follows:
Galveston Bay
Through our subsidiary, Galveston Bay Energy, LLC (“GBE”), we hold majority interests (approximately 93% working interest) and operate four fields in the shallow waters of Galveston Bay which is Southeast of Houston, Texas. Currently, we are producing three of the four fields that were acquired with GBE. The fields were shut-in in September 2008 due to a direct hit from Hurricane Ike. The then-owner went into bankruptcy and the properties were purchased out of bankruptcy by a private seller who performed reconstruction work on the fields and later sold them to us. The fields are not yet producing at pre-storm levels. Our operational goals include infrastructure improvements and modifications to increase production as well a full development strategy which will include drilling, reworking wells, and recompletions. The entire bay is covered with 3D seismic data, which can be purchased relatively cheaply and on an as-needed basis. We intend to utilize this seismic data to complement our exploration and development plans.
The Welder Lease (Barge Canal), Texas
On November 16, 2006 we completed an assignment and purchase agreement with OPEX Energy, LLC with an effective date of August 1, 2006. Under the terms of the agreement, we acquired a 100% working interest (90% after payout) and a 72.5% net revenue interest (65.25% after payout) in approximately 81 acres of an oil and gas lease (the “Welder Lease”) located in Calhoun County, Texas. At the time of the acquisition, the two wells on the Welder lease were producing assets.
Effective January 1, 2010, we acquired the remaining 10% working in the Welder Leases from Treydan Corporation and own 100% of the working interest.
As of the date of this annual report, two wells are producing gas and oil from the property. The wells are operated using a gas lift system. A third well is utilized for salt water disposal. The wells have additional proven non-producing zones behind pipe. We intend to develop the proved developed non-producing (PDNP) zones as current producing horizons deplete. In October 2011, the Welder #5 well was recompleted into a productive zone up the hole and is currently in production.
Louisiana
We currently receive revenues from our 6% overriding royalty interests in 3 leases located in the South Delhi and Big Creek oil fields in Northeastern Louisiana. These interests carry no operational or financial responsibilities for expenses or liabilities.
Janssen Lease, Texas
In October 2005, we entered into an agreement to purchase a 25% working interest and an 18.75% net revenue interest in approximately 138 acres of an oil and gas lease (the “Janssen Lease”) located in Karnes County, Texas. This lease interest was acquired from Rockwell Energy. An unsuccessful attempt was made to re-enter and re-complete the Roeder gas sand at 10,300 feet using side track drilling techniques. As the original lease was set to expire, we negotiated a new oil and gas lease with the mineral owners and farmed out 97% of the working interest to ETG Energy Resources. We retained a 3% working interest on any producing zones and a 5% non-promoted option to participate in any offset drilling within the leased area. ETG successfully re-completed in the Roeder Sand and the Janssen A-1 well is currently producing between 250-300 mcf gas per day and approximately six (6) barrels per day of condensate.
Koliba Lease, Texas
The Koliba Lease property is located near our Welder lease and has one shut-in oil/gas well. The well previously produced 30 Bbls oil per day plus water. The well is in close proximity to our Welder gas sales line and salt water disposal system. The Koliba No. 2 well was drilled June 2010 and found to be slightly down-dip from the No.1 well. We elected to plug the No. 2 and subsequently drilled the No. 3 well in anticipation of getting up-dip to the No. 1 well. The No. 3 lacked a sufficient increase in pay or gain in structure and therefore was plugged. No further exploration activity is contemplated on these leases.
Illinois
Through the date of this annual report, we have entered into numerous oil and gas leases in Jefferson and other counties in Illinois. Currently these leases total approximately 237 gross acres. In January 2011, we farmed out our interest in the Markham City prospect in Illinois to Core Minerals Management II, LLC (“Core”). Under the farmout agreement, we retained a 10% working interest and assigned the balance of our working interest in the Markham City prospect to Core. Core will be the operator of the property. Core will perform exploration activities on the prospect including drilling new wells. Our working interest is carried until Core meets the “Earnings Threshold”, $1,350,000. Once Core has recouped their initial investment we will gain an additional 15% working interest, bringing our total working interest in the project to 25%.
Recent Activities
We continue to review and evaluate submittals on properties in Texas, Illinois, Louisiana and other areas of the continental United States.
Productive Wells
The following table sets forth information regarding the total gross and net productive wells as of November 15, 2011, expressed separately for oil and gas. All of our productive oil and gas wells were located in Texas and Illinois. For the purposes of this subsection: (i) one or more completions in the same bore hole have been counted as one well, and (ii) a well with one or multiple completions at least one of which is an oil completion has been classified as an oil well. We do not have any wells with multiple completions.
A productive well is an exploratory well, development well, producing well or well capable of production, but does not include a dry well. A dry well, or a hole, is an exploratory or a development well found to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.
A gross well is a well in which a working interest is owned, and a net well is the result obtained when the sum of fractional ownership working interests in gross wells equals one. The number of gross wells is the total number of wells in which a working interest is owned, and the number of net wells is the sum of the fractional working interests owned in gross wells expressed as whole numbers and fractions thereof. The “completion” of a well means the installation of permanent equipment for the production of oil or gas, or, in the case of a dry hole, to the reporting of abandonment to the appropriate agency.
Production and Price History
The table below sets forth the net quantities of oil and gas production, net of royalties, attributable to us in the years ended July 31, 2011 and 2010. For the purposes of this table, the following terms have the following meanings: (i) “Bbl” means one stock tank barrel or 42 U.S. gallons liquid volume; (ii) “MBbls” means one thousand barrels of oil; (iii) “Mcf” means one thousand cubic feet; (iv) “Mcfe” means one thousand cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of oil; (v) “MMcfe/d” means one million cubic feet equivalent per day, determined by using the ratio of six Mcf of natural gas to one Bbl of oil; and (vi) “MMcf” means one million cubic feet.
(1)
Taxes, transportation and production-related administrative expenditures are included in lease operating expenses.
Net production includes only production that is owned by us, whether directly or beneficially, and produced to our interest, less royalties and production due to others. Production of natural gas includes only marketable production of gas on an “as sold” basis. Production of natural gas includes only dry, residue and wet gas, depending on whether liquids have been extracted before we passed title, and does not include flared gas, injected gas and gas consumed in operations. Recovered gas, lift gas and reproduced gas are not included until sold.
The following table illustrates our estimated net proved reserves, including changes, and proved developed reserves for the periods indicated, as estimated by third party reservoir engineers.
The SEC amended its definitions of oil and natural gas reserves effective December 31, 2009. Previous periods were not restated for the new rules. Key revisions include a change in pricing used to prepare reserve estimates to a 12-month un-weighted average of the first-day-of-the-month prices, the inclusion of non-traditional resources in reserves, definitional changes, and allowing the application of reliable technologies in determining proved reserves, and other new disclosures (Revised SEC rules). The Revised SEC rules did not affect the quantities of our proved reserves.
The reserves in this report have been estimated using deterministic methods. For wells classified as proved developed producing where sufficient production history existed, reserves were based on individual well performance evaluation and production decline curve extrapolation techniques.
Acreage
The following table sets forth information regarding our gross and net developed and undeveloped oil and natural gas acreage under lease as of November 15, 2011:
(1)
The gross acreage cited includes leasehold acreage to be earned under the farm-out agreements.
A developed acre is an acre spaced or assignable to productive wells, a gross acre is an acre in which a working interest is owned, and a net acre is the result that is obtained when the sum of fractional ownership working interests in gross acres equals one. The number of net acres is the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.
Undeveloped acreage is considered to be those lease acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or natural gas, regardless of whether or not such acreage contains proved reserves, but does not include undrilled acreage held by production under the terms of a lease. As is customary in the oil and gas industry, we can retain our interest in undeveloped acreage by drilling activity that establishes commercial production sufficient to maintain the lease or by payment of delay rentals during the remaining primary term of the lease. The oil and natural gas leases in which we have an interest are for varying primary terms; however, most of our developed lease acreage is beyond the primary term and is held so long as oil or natural gas is produced.
Plan of Operations
In Texas, we plan to continue producing oil and gas from our Welder (Barge Canal) lease. We will continue to maintain our 3.0% non-operated working interest in the Janssen No. A-1 well (gas and minor condensate) in Karnes County, Texas. In Galveston Bay, Texas we plan to continue enhancing the production from our four productive fields. Our plans include drilling, reworking, recompletions, as well as infrastructure improvements to exploit the known reserves as well as explore for additional reserves.
Government Regulation
General
The availability of a ready market for oil and gas production depends upon numerous factors beyond our control. These factors include local, state, federal and international regulation of oil and gas production and transportation, as well as regulations governing environmental quality and pollution control, state limits on allowable rates of production by a well or proration unit, the amount of oil and gas available for sale, the availability of adequate pipeline and other transportation and processing facilities, and the marketing of competitive fuels. State and federal regulations are generally intended to prevent waste of oil and gas, protect rights to produce oil and gas between owners in a common reservoir, and control contamination of the environment.
Applicable legislation is under constant review for amendment or expansion. These efforts frequently result in an increase in the regulatory burden on companies in our industry and a consequent increase in the cost of doing business and decrease in profitability. Numerous federal and state departments and agencies issue rules and regulations imposing additional burdens on the oil and gas industry that are often costly to comply with and carry substantial penalties for non-compliance. Our production operations may be affected by changing tax and other laws relating to the petroleum industry, constantly changing administrative regulations and possible interruptions or termination by government authorities.
The transportation and certain sales of natural gas in interstate commerce are heavily regulated by agencies of the federal government and are affected by the availability, terms and cost of transportation. The price and terms of access to pipeline transportation are subject to extensive federal and state regulation. The Federal Energy Regulatory Commission (FERC) is continually proposing and implementing new rules and regulations affecting the natural gas industry, most notably interstate natural gas transmission companies that remain subject to the FERC’s jurisdiction. The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the natural gas industry. Some recent FERC proposals may, however, adversely affect the availability and reliability of interruptible transportation service on interstate pipelines.
State regulatory authorities have established rules and regulations requiring permits for drilling operations, drilling bonds and reports concerning operations. Many states have statutes and regulations governing various environmental and conservation matters, including the establishment of maximum rates of production from oil and gas wells, and restricting production to the market demand for oil and gas. Such statutes and regulations may limit the rate at which oil and gas could otherwise be produced. Most states impose a production or severance tax with respect to the production and sale of crude oil, natural gas and natural gas liquids within their respective jurisdictions. State production taxes are generally applied as a percentage of production or sales.
Oil and gas rights may be held by individuals and corporations, and, in certain circumstances, by governments having jurisdiction over the area in which such rights are located. As a general rule, parties holding such rights grant licenses or leases to third parties, such as us, to facilitate the exploration and development of these rights. The terms of the licenses and leases are generally established to require timely development. Notwithstanding the ownership of oil and gas rights, the government of the jurisdiction in which the rights are located generally retains authority over the manner of development of those rights.
Environmental
General. Our activities are subject to local, state and federal laws and regulations governing environmental quality and pollution control in the United States. The exploration, drilling and production from wells, natural gas facilities, including the operation and construction of pipelines, plants and other facilities for transporting, processing, treating or storing natural gas and other products, are subject to stringent environmental laws and regulations by state and federal authorities, including the Environmental Protection Agency (“EPA”). These laws and regulations may require the acquisition of a permit by operators before drilling commences, prohibit drilling activities on certain lands lying within wilderness areas, wetlands and other ecologically sensitive and protected areas, and impose substantial remedial liabilities for pollution resulting from drilling operations. Such regulation can increase our cost of planning, designing, installing and operating such facilities.
Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of significant investigatory or remedial obligations, and the imposition of injunctive relief that limits or prohibits our operations. Moreover, some environmental laws provide for joint and several strict liability for remediation of releases of hazardous substances, rendering a person liable for environmental damage without regard to negligence or fault on the part of such person. In addition, we may be subject to claims alleging personal injury or property damage as a result of alleged exposure to hazardous substances, such as oil and gas related products.
Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly waste handling, storage, transport, disposal or cleanup requirements could materially adversely affect our operations and financial position, as well as those of the oil and gas industry in general. While we believe that we are in substantial compliance with current environmental laws and regulations and have not experienced any material adverse effect from such compliance, there is no assurance that this trend will continue in the future.
Waste Disposal. We currently lease, and intend in the future to own or lease, additional properties that have been used for production of oil and gas for many years. Although we and our operators utilize operating and disposal practices that are standard in the industry, previous owners or lessees may have disposed of or released hydrocarbons or other wastes on or under the properties that we currently own or lease or properties that we may in the future own or lease. In addition, many of these properties have been operated in the past by third parties over whom we had no control as to such entities’ treatment of hydrocarbons or other wastes or the manner in which such substances may have been disposed of or released. State and federal laws applicable to oil and gas wastes and properties may require us to remediate property, including ground water, containing or impacted by previously disposed wastes (including wastes disposed of or released by prior owners or operators) or to perform remedial plugging operations to prevent future or mitigate existing contamination.
We may generate wastes, including hazardous wastes, that are subject to the federal Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes. The EPA has limited the disposal options for certain wastes that are designated as hazardous under RCRA. Furthermore, it is possible that certain wastes generated by our oil and gas projects that are currently exempt from treatment as hazardous wastes may in the future be designated as hazardous wastes, and therefore be subject to more rigorous and costly operating and disposal requirements.
CERCLA. The federal Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the “Superfund” law, generally imposes joint and several liability for costs of investigation and remediation and for natural resource damages, without regard to fault or the legality of the original conduct, on certain classes of persons with respect to the release into the environment of substances designated under CERCLA as hazardous substances. These classes of persons or so-called potentially responsible parties include the current and certain past owners and operators of a facility where there is or has been a release or threat of release of a hazardous substance and persons who disposed of or arranged for the disposal of the hazardous substances found at such a facility. CERCLA also authorizes the EPA and, in some cases, third parties to take action in response to threats to the public health or the environment and to seek to recover from the potentially responsible parties the costs of such action. Although CERCLA generally exempts petroleum from the definition of hazardous substances, we may have generated and may generate wastes that fall within CERCLA’s definition of hazardous substances. We may in the future be an owner of facilities on which hazardous substances have been released by previous owners or operators of our properties that are named as potentially responsible parties related to their ownership or operation of such property.
Air Emissions. Our projects are subject to local, state and federal regulations for the control of emissions of air pollution. Major sources of air pollutants are subject to more stringent, federally imposed permitting requirements, including additional permits. Producing wells, gas plants and electric generating facilities generate volatile organic compounds and nitrogen oxides. Some of our producing wells may be in counties that are designated as non-attainment for ozone and may be subject to restrictive emission limitations and permitting requirements. If the ozone problems in the applicable states are not resolved by the deadlines imposed by the federal Clean Air Act, or on schedule to meet the standards, even more restrictive requirements may be imposed, including financial penalties based upon the quantity of ozone producing emissions. If we fail to comply strictly with air pollution regulations or permits, we may be subject to monetary fines and be required to correct any identified deficiencies. Alternatively, regulatory agencies could require us to forego construction, modification or operation of certain air emission sources.
Clean Water Act. The Clean Water Act imposes restrictions and strict controls regarding the discharge of wastes, including produced waters and other oil and natural gas wastes, into waters of the United States, a term broadly defined. Permits must be obtained to discharge pollutants into federal waters. The Clean Water Act provides for civil, criminal and administrative penalties for unauthorized discharges of oil, hazardous substances and other pollutants. It imposes substantial potential liability for the costs of removal or remediation associated with discharges of oil or hazardous substances. State laws governing discharges to water also provide varying civil, criminal and administrative penalties and impose liabilities in the case of a discharge of petroleum or its derivatives, or other hazardous substances, into state waters. In addition, the EPA has promulgated regulations that may require us to obtain permits to discharge storm water runoff, including discharges associated with construction activities. In the event of an unauthorized discharge of wastes, we may be liable for penalties and costs.
Oil Pollution Act. The Oil Pollution Act of 1990 (“OPA”), which amends and augments oil spill provisions of the Clean Water Act, and similar legislation enacted in Texas, Louisiana and other coastal states, impose certain duties and liabilities on certain “responsible parties” related to the prevention of oil spills and damages resulting from such spills in United States waters and adjoining shorelines. A liable “responsible party” includes the owner or operator of a facility or vessel that is a source of an oil discharge or poses the substantial threat of discharge, or the lessee or permittee of the area in which a facility covered by OPA is located. OPA assigns joint and several liability, without regard to fault, to each liable party for oil removal costs, remediation of environmental damage and a variety of public and private damages. OPA also imposes ongoing requirements on a responsible party, including proof of financial responsibility to cover at least some costs of a potential spill. Few defenses exist to the liability imposed by OPA. In the event of an oil discharge, or substantial threat of discharge from our properties, vessels and pipelines, we may be liable for costs and damages.
We believe that we are in substantial compliance with current environmental laws and regulations in each of the jurisdictions in which we operate. Although we have not experienced any material adverse effect from such compliance, there is no assurance that this trend will continue in the future.
Competition
The oil and natural gas industry is intensely competitive in all phases, including the exploration for new production and the acquisition of equipment and labor necessary to conduct drilling activities. The competition comes from numerous major oil companies as well as numerous other independent operators. There is also competition between the oil and natural gas industry and other industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers. We are a minor participant in the industry and compete in the oil and natural gas industry with many other companies having far greater financial, technical and other resources.
Competitive conditions may be substantially affected by various forms of energy legislation and/or regulation considered from time to time by the government of the United States and other countries, as well as factors that we cannot control, including international political conditions, overall levels of supply and demand for oil and gas, and the markets for synthetic fuels and alternative energy sources. Intense competition occurs with respect to marketing, particularly of natural gas.
Employees
We currently have nineteen employees, all of whom are full-time employees.
Subsidiaries
We own 100% of the issued and outstanding share capital of (i) Penasco, a Nevada corporation, (ii) Galveston Bay Energy, LLC, a Texas corporation and (iii) SPE Navigation I, LLC, a Nevada limited liability corporation.
ITEM 1A.
ITEM 1A.
RISK FACTORS
An investment in our common stock involves a number of very significant risks. You should carefully consider the following risks and uncertainties in addition to other information in this annual report in evaluating our company and its business before purchasing shares of our common stock. Our business, operating results and financial condition could be seriously harmed due to any of the following risks. The risks described below may not be all of the risks facing our company. Additional risks not presently known to us or that we currently consider immaterial may also impair our business operations. You could lose all or part of your investment due to any of these risks.
Risks Related to Our Company
Because we have only recently commenced business operations, we face a high risk of business failure.
We were incorporated on April 12, 2005 and originally planned to explore for gold and other minerals, but we soon shifted our focus to oil and gas exploration. To date, we have not achieved profitability. Potential investors should be aware of the difficulties normally encountered by companies in the early stages of their life cycle and the high rate of failure of such enterprises. These potential problems include, but are not limited to, unanticipated problems relating to costs and expenses that may exceed current estimates. We have no history upon which to base any assumption as to the likelihood that our business will prove successful, and it’s possible we may never achieve profitable operations.
We may not be able to effectively manage the demands required of a new business in our industry, such that we may be unable to successfully implement our business plan or achieve profitability.
We have earned limited revenues to date and we have never been profitable. We may not be able to effectively execute our business plan or manage any growth, if any, of our business. Future development and operating results will depend on many factors, including access to adequate capital, the demand for oil and gas, price competition, our success in setting up and expanding distribution channels and whether we can control costs. Many of these factors are beyond our control. In addition, our future prospects must be considered in light of the risks, expenses and difficulties frequently encountered in establishing a new business in the oil and gas industry, which is characterized by intense competition, rapid technological change, highly litigious competitors and significant regulation. If we are unable to address these matters, or any of them, then we may not be able to successfully implement our business plan or achieve profitability.
Because we have earned limited revenues from operations, most of our capital requirements have been met through financing and we may not be able to continue to find financing to meet our operating requirements.
We will need to obtain additional financing in order to pursue our business plan. As of July 31, 2011, we had cash on hand of $1,082,099 and a working capital deficit of $3,773,504. Our business plan calls for expenses of approximately $3,000,000 over the next twelve months in connection with the exploration and development of our properties as well as corporate overhead. We currently have approximately $4,000,000 of cash due to our acquisition of SPE Navigation I, LLC. In the event that these funds are not sufficient to support our business plan, we will need to seek additional financing. We may not be able to obtain such financing at all or in amounts that would be sufficient for us to meet our current and expected working capital needs. Furthermore, in the event that our plans change, our assumptions change or prove inaccurate, we could be required to seek additional financing in greater amounts than is currently anticipated. Any inability to obtain additional financing when needed would have a material adverse effect on us, including possibly requiring us to significantly curtail or possibly cease our operations. In addition, any future equity financing may involve substantial dilution to our existing stockholders.
Because we have a history of losses and anticipate continued losses unless and until we are able to generate sufficient revenues to support our operations, we may lack the financial stability required to continue operations.
Since inception we have suffered recurring losses. We have funded our operations largely through the issuance of common stock in order to meet our strategic objectives. Our current level of oil production is not sufficient to completely fund our exploration and development budget, such that we anticipate that we may need additional financing in order to pursue our plan of operations. We anticipate that our losses will continue until such time, if ever, as we are able to generate sufficient revenues to support our operations.
Oil and gas resources, even if discovered, may not be commercially viable, which would cause our business to fail.
Even if oil and gas resources are discovered on our properties, we may not be able to achieve commercial production at all or at a level that would be sufficient to pay drilling and completion costs. Our properties may not contain commercial quantities of oil and gas. In addition, the cost of drilling, completing and operating wells is often uncertain. Drilling operations on our properties or on properties we may acquire in the future may be curtailed, delayed or cancelled as a result of numerous factors, including title problems, weather conditions, compliance with governmental requirements and shortages or delays in the delivery of equipment. Furthermore, completion of a well does not assure a profit or a recovery of drilling, completion and operating costs. As a result, our business, results of operations and financial condition may be materially adversely affected.
Actual production, revenues and expenditures with respect to reserves will likely vary from estimates, which could have a material adverse effect on our business, results of operations and financial condition.
There are numerous uncertainties inherent in estimating oil and natural gas reserves and their estimated values, including many factors beyond the control of the producer. Reservoir engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. Estimates of economically recoverable oil and natural gas reserves and of future net cash flows necessarily depend upon a number of variable factors and assumptions, such as historical production from the area compared with production from other producing areas, the assumed effects of regulations by governmental agencies and assumptions concerning future oil and natural gas prices, future operating costs, severance and excise taxes, development costs and work-over and remedial costs, all of which may in fact vary considerably from actual results. For these reasons, estimates of the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, classifications of such reserves based on risk of recovery, and estimates of the future net cash flows expected therefrom prepared by different engineers or by the same engineers but at different times may vary substantially, and such reserve estimates may be subject to downward or upward adjustment based upon such factors. Actual production, revenues and expenditures with respect to reserves will likely vary from estimates, when and if made, and such variances may be material, which could have a material adverse effect on our business, results of operations and financial condition.
Our future oil and natural gas production is highly dependent upon our ability to find or acquire reserves.
In general, the volume of production from oil and natural gas properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. Except to the extent we conduct successful exploration and development activities or acquire properties containing proved reserves, or both, our proved reserves, if any, will decline as reserves are produced. Our future oil and natural gas production is, therefore, highly dependent upon our level of success in finding or acquiring reserves in the future. The business of exploring for, developing or acquiring reserves is capital intensive. 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 would be impaired. The failure of an operator of our wells to adequately perform operations, or such operator’s breach of the applicable agreements, could adversely impact us. In addition, we may not obtain additional proved reserves or be able to drill productive wells at acceptable costs, in which case our business would fail.
Oil and gas resources may contain certain hazards which may, in turn, create certain liabilities or prevent the resources from being commercially viable.
Our properties may contain hazards such as unusual or unexpected formations and other conditions. Our projects may become subject to liability for pollution, fire, explosion, blowouts, cratering and oil spills, against which we cannot insure or against which we may decide to not insure. Such events could result in substantial damage to oil and gas wells, producing facilities and other property and/or result in personal injury. Costs or liabilities related to those events would have a material adverse effect on our business, results of operations, financial condition and cash flows.
Oil and gas prices are highly volatile, and a decline in oil and gas prices could have a material adverse effect on our business, results of operations, financial condition and cash flows.
Oil and gas prices and markets are highly volatile. Prices for oil and gas are subject to significant fluctuation in response to relatively minor changes in supply of and demand for oil and gas, market uncertainty and a variety of additional factors. Our profitability will be substantially dependent on prevailing prices for natural gas and oil. The amounts of and prices obtainable for our oil and gas production may be affected by market factors beyond our control, such as:
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the extent of domestic production;
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the amount of imports of foreign oil and gas;
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the market demand on a regional, national and worldwide basis;
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domestic and foreign economic conditions that determine levels of industrial production;
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political events in foreign oil-producing regions; and
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variations in governmental regulations and tax laws or the imposition of new governmental requirements upon the oil and gas industry.
These factors or any one of them could result in the decline in oil and gas prices, which could have a material adverse effect on our business, results of operations, financial condition and cash flows.
As a result of our intensely competitive industry, we may not gain enough market share to be profitable.
We compete in the sale of oil and natural gas on the basis of price and on the ability to deliver products. The oil and natural gas industry is intensely competitive in all phases, including the exploration for new production and the acquisition of equipment and labor necessary to conduct drilling activities. The competition comes from numerous major oil companies as well as numerous other independent operators in the United States and elsewhere. Because we are pursuing potentially large markets, our competitors include major, multinational oil and gas companies. There is also competition between the oil and natural gas industry and other industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers. We are a minor participant in the industry and compete in the oil and natural gas industry with many other companies having far greater financial, technical and other resources. If we are unable to compete successfully, we may never be able to sell enough product at a price sufficient to permit us to generate profits.
The oil and natural gas market is heavily regulated, and existing or subsequently enacted laws or regulations could limit our production, increase compliance costs or otherwise adversely impact our operations or revenues.
We are subject to various federal, state and local laws and regulations. These laws and regulations govern safety, exploration, development, taxation and environmental matters that are related to the oil and natural gas industry. To conserve oil and natural gas supplies, regulatory agencies may impose price controls and may limit our production. Certain laws and regulations require drilling permits, govern the spacing of wells and the prevention of waste and limit the total number of wells drilled or the total allowable production from successful wells. Other laws and regulations govern the handling, storage, transportation and disposal of oil and natural gas and any by-products produced in oil and natural gas operations. These laws and regulations could materially adversely impact our operations and our revenues.
Laws and regulations that affect us may change from time to time in response to economic or political conditions. Thus, we must also consider the impact of future laws and regulations that may be passed in the jurisdictions where we operate. We anticipate that future laws and regulations related to the oil and natural gas industry will become increasingly stringent and cause us to incur substantial compliance costs.
The nature of our operations exposes us to environmental liabilities.
Our operations create the risk of environmental liabilities. We may incur liability to governments or to third parties for any unlawful discharge of oil, gas or other pollutants into the air, soil or water. We could potentially discharge oil or natural gas into the environment in any of the following ways:
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from a well or drilling equipment at a drill site;
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from a leak in storage tanks, pipelines or other gathering and transportation facilities;
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from damage to oil or natural gas wells resulting from accidents during normal operations; or
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from blowouts, cratering or explosions.
Environmental discharges may move through the soil to water supplies or adjoining properties, giving rise to additional liabilities. Some laws and regulations could impose liability for failure to obtain the proper permits for, to control the use of, or to notify the proper authorities of a hazardous discharge. Such liability could have a material adverse effect on our financial condition and our results of operations and could possibly cause our operations to be suspended or terminated on such property.
We may also be liable for any environmental hazards created either by the previous owners of properties that we purchase or lease or by acquired companies prior to the date we acquire them. Such liability would affect the costs of our acquisition of those properties. In connection with any of these environmental violations, we may also be charged with remedial costs. Pollution and similar environmental risks generally are not fully insurable.
We could lose or fail to attract the personnel necessary to run our business.
Our success depends, to a large extent, on our ability to attract and retain key management and operating personnel. As we develop additional capabilities and expand the scope of our operations, we will require more skilled personnel. Recruiting personnel for the oil and gas industry is highly competitive. We may not be able to attract and retain qualified executive, managerial and technical personnel needed for our business. Our failure to attract or retain qualified personnel could delay or result in our inability to complete our business plan.
Our directors may experience conflicts of interest which may detrimentally affect our profitability.
Certain directors and officers may be engaged in, or may in the future be engaged in, other business activities on their own behalf and on behalf of other companies and, as a result of these and other activities, such directors and officers may become subject to conflicts of interest, which could have a material adverse effect on our business.
Risks Related to Our Common Stock
The trading price of our common stock may be volatile.
The price of our common shares may increase or decrease in response to a number of events and factors, including: trends in the oil and gas markets in which we operate; changes in the market price of oil and gas; current events affecting the economic situation in North America; changes in financial estimates; our acquisitions and financings; quarterly variations in our operating results; the operating and share price performance of other companies that investors may deem comparable; and purchase or sale of blocks of our common shares. These factors, or any of them, may materially adversely affect the prices of our common shares regardless of our operating performance.
A decline in the price of our common stock could affect our ability to raise further working capital and adversely impact our operations.
A decline in the price of our common stock could result in a reduction in the liquidity of our common stock and a reduction in our ability to raise additional capital for our operations. Because our operations to date have been largely financed through the sale of equity securities, a decline in the price of our common stock could have an adverse effect upon our liquidity and our continued operations. A reduction in our ability to raise equity capital in the future could have a material adverse effect upon our business plan and operations, including our ability to continue our current operations.
Our stock is a penny stock. Trading of our stock may be restricted by the SEC’s penny stock regulations and FINRA’s sales practice requirements, which may limit a stockholder’s ability to buy and sell our stock.
Our common stock will be subject to the “Penny Stock” Rules of the SEC, which will make transactions in our common stock cumbersome and may reduce the value of an investment in our common stock.
Our common stock is quoted on the OTC Bulletin Board, which is generally considered to be a less efficient market than markets such as NASDAQ or the national exchanges, and which may cause difficulty in conducting trades and difficulty in obtaining future financing. Further, our securities will be subject to the “penny stock rules” adopted pursuant to Section 15(g) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). The penny stock rules apply generally to companies whose common stock trades at less than $5.00 per share, subject to certain limited exemptions. Such rules require, among other things, that brokers who trade “penny stock” to persons other than “established customers” complete certain documentation, make suitability inquiries of investors and provide investors with certain information concerning trading in the security, including a risk disclosure document and quote information under certain circumstances. Many brokers have decided not to trade “penny stock” because of the requirements of the “penny stock rules” and, as a result, the number of broker-dealers willing to act as market makers in such securities is limited. In the event that we remain subject to the “penny stock rules” for any significant period, there may develop an adverse impact on the market, if any, for our securities. Because our securities are subject to the “penny stock rules”, investors will find it more difficult to dispose of our securities. Further, it is more difficult: (i) to obtain accurate quotations, (ii) to obtain coverage for significant news events because major wire services, such as the Dow Jones News Service, generally do not publish press releases about such companies, and (iii) to obtain needed capital.
In addition to the “penny stock” rules promulgated by the SEC, FINRA has adopted rules that require a broker-dealer to have reasonable grounds for believing that an investment is suitable for a customer when recommending the investment to that customer. Prior to recommending speculative low-priced securities to their non-institutional customers, broker-dealers must make reasonable efforts to obtain information about the customer’s financial status, tax status, investment objectives and other information. Under interpretations of these rules, FINRA believes that there is a high probability that speculative low priced securities will not be suitable for at least some customers. FINRA requirements make it more difficult for broker-dealers to recommend that their customers buy our common stock, which may limit your ability to buy and sell our stock and have an adverse effect on the market for our shares.
ITEM 1B.
ITEM 1B.
UNRESOLVED STAFF COMMENTS
None.
ITEM 2.
ITEM 2.
PROPERTIES
We hold certain oil and gas interests, as described in Item 1 hereto. In addition, we rent office space at 800 Gessner, Suite 200, Houston, Texas, 77024 for $6,300 per month and at 545 N. Upper Broadway, Suite 900, Corpus Christi, Texas, 78401 for $3,200 per month.
ITEM 3.
ITEM 3.
LEGAL PROCEEDINGS
We are a party to the following legal proceedings:
1. Cause No. 2011-37552; Strategic American Oil Corporation v. ERG Resources, LLC, et al.; In the 55th District Court, Harris County, Texas. The Company is a plaintiff in this suit. In this case, Company brings claims for injunctive relief, breach of contract and fraudulent inducement against the defendant regarding the purchase of Galveston Bay Energy, LLC from ERG. The Company intends to prosecute its claims and defenses vigorously. The case has had multiple hearings on the injunctive relief requests and more are scheduled. Discovery is commencing and is expected to proceed at a rapid pace.
2. Cause No. 2011-21308; James A. Whitson, Jr. vs. Galveston Bay Energy, LLC; In the 61st Judicial District Court, Harris County, Texas. The Company is a defendant in this case. It involves contracts regarding the use of processing plants for the oil and gas products produced by the producing properties owned by Mr. Whitson. The contracts were assigned to ERG Resources, LLC immediately prior to the purchase of GBE from ERG by the Company and the claims are actually against ERG but the contracts are in the name of GBE. The Company intends to prosecute its claims and defenses vigorously. At this time, Management considers the possibility of a finding against the company to be remote based upon the information known to date.
3. Cause No. 2011-54428; ERG Resources, LLC v. Galveston Bay Energy, LLC.; in the 125th Judicial District Court, Harris County, Texas. This is a companion case to the Whitson case in that it deals with the same operating agreements for the processing of product by the entities owned by ERG. It is an action seeking payments of charges and expenses by ERG that are refuted by GBE. The Company intends to prosecute its claims and defenses vigorously.
ITEM 4.
ITEM 4.
[REMOVED AND RESERVED]
PART II
ITEM 5.
ITEM 5.
MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Market Information
Shares of our common stock became quoted on the OTC Bulletin Board under the symbol “SGCA” on August 14, 2008.
The following tables set forth the high and low bid price per share of our common stock, as quoted on the OTC Bulletin Board, for the periods indicated. These over-the-counter market quotations reflect inter-dealer prices, without retail mark-up, markdown or commission and may not represent actual transactions.
On November 11, 2011, the low bid price of our common stock was $0.10 per share, the high ask price of our common stock was $0.11 per share, and the closing price was $0.11 per share. We do not have any securities that are currently traded on any other exchange or quotation system.
Holders
As of November 14, 2011, we had 117 shareholders of record.
Dividend Policy
No dividends have been declared or paid on our common stock. We have incurred recurring losses and do not currently intend to pay any cash dividends in the foreseeable future.
Securities Authorized For Issuance Under Compensation Plans
The following table sets forth information as of July 31, 2011:
Equity Compensation Plan Information
2009 Restated Stock Incentive Plan
On May 21, 2009, our Board of Directors authorized and approved the adoption of the 2009 Restated Stock Incentive Plan (the “2009 Plan”), which absorbs and replaces the 2007 Stock Incentive Plan, under which an aggregate of 10,000,000 of our shares may be issued.
The purpose of the 2009 Plan is to enhance our long-term stockholder value by offering opportunities to our directors, officers, employees and eligible consultants to acquire and maintain stock ownership in order to give these persons the opportunity to participate in our growth and success, and to encourage them to remain in our service.
The 2009 Plan is to be administered by our Board of Directors or a committee appointed by and consisting of two or more members of the Board of Directors, which shall determine, among other things, (i) the persons to be granted awards under the 2009 Plan; (ii) the number of shares or amount of other awards to be granted; and (iii) the terms and conditions of the awards granted. The Company may issue restricted shares, options, stock appreciation rights, deferred stock rights, dividend equivalent rights, among others, under the 2009 Plan. An aggregate of 10,000,000 of our shares may be issued pursuant to the grant of awards under the 2009 Plan.
An award may not be exercised after the termination date of the award and may be exercised following the termination of an eligible participant’s continuous service only to the extent provided by the administrator under the 2009 Plan. If the administrator under the 2009 Plan permits a participant to exercise an award following the termination of continuous service for a specified period, the award terminates to the extent not exercised on the last day of the specified period or the last day of the original term of the award, whichever occurs first. In the event an eligible participant’s service has been terminated for “cause”, he or she shall immediately forfeit all rights to any of the awards outstanding.
The foregoing summary of the 2009 Plan is not complete and is qualified in its entirety by reference to the 2009 Plan, a copy of which has been filed with the SEC.
During the year ended July 31, 2011, we granted options to purchase no shares of our common stock under the 2009 Plan.
2010 Stock Incentive Plan
During August 2010, the Board of Directors authorized and approved the adoption of the 2010 Stock Incentive Plan (the “2010 Plan”). An aggregate of 5,000,000 shares of our common stock may be issued under the plan.
The purpose of the 2010 Plan is to enhance our long-term stockholder value by offering opportunities to our directors, officers, employees and eligible consultants to acquire and maintain stock ownership in order to give these persons the opportunity to participate in our growth and success, and to encourage them to remain in our service.
The 2010 Plan is to be administered by our Board of Directors or a committee appointed by and consisting of two or more members of the Board of Directors, which shall determine, among other things, (i) the persons to be granted awards under the 2010 Plan; (ii) the number of shares or amount of other awards to be granted; and (iii) the terms and conditions of the awards granted. The Company may issue restricted shares, options, stock appreciation rights, deferred stock rights, dividend equivalent rights, among others, under the 2010 Plan. An aggregate of 5,000,000 of our shares may be issued pursuant to the grant of awards under the 2010 Plan.
An award may not be exercised after the termination date of the award and may be exercised following the termination of an eligible participant’s continuous service only to the extent provided by the administrator under the 2010 Plan. If the administrator under the 2010 Plan permits a participant to exercise an award following the termination of continuous service for a specified period, the award terminates to the extent not exercised on the last day of the specified period or the last day of the original term of the award, whichever occurs first. In the event an eligible participant’s service has been terminated for “cause”, he or she shall immediately forfeit all rights to any of the awards outstanding.
The foregoing summary of the 2010 Plan is not complete and is qualified in its entirety by reference to the 2010 Plan, a copy of which is being filed as an exhibit to this annual report on Form 10-K.
During the year ended July 31, 2011, we granted options to purchase 1,400,000 shares of our common stock to consultants under the 2010 Plan.
2011 Stock Incentive Plan
During April 2011, the Board of Directors authorized and approved the adoption of the 2011 Stock Incentive Plan (the “2011 Plan”). An aggregate of 25,000,000 shares of our common stock may be issued under the plan.
The purpose of the 2011 Plan is to enhance our long-term stockholder value by offering opportunities to our directors, officers, employees and eligible consultants to acquire and maintain stock ownership in order to give these persons the opportunity to participate in our growth and success, and to encourage them to remain in our service.
The 2011 Plan is to be administered by our Board of Directors or a committee appointed by and consisting of two or more members of the Board of Directors, which shall determine, among other things, (i) the persons to be granted awards under the 2011 Plan; (ii) the number of shares or amount of other awards to be granted; and (iii) the terms and conditions of the awards granted. The Company may issue restricted shares, options, stock appreciation rights, deferred stock rights, dividend equivalent rights, among others, under the 2011 Plan. An aggregate of 25,000,000 of our shares may be issued pursuant to the grant of awards under the 2011 Plan.
An award may not be exercised after the termination date of the award and may be exercised following the termination of an eligible participant’s continuous service only to the extent provided by the administrator under the 2011 Plan. If the administrator under the 2011 Plan permits a participant to exercise an award following the termination of continuous service for a specified period, the award terminates to the extent not exercised on the last day of the specified period or the last day of the original term of the award, whichever occurs first. In the event an eligible participant’s service has been terminated for “cause”, he or she shall immediately forfeit all rights to any of the awards outstanding.
The foregoing summary of the 2011 Plan is not complete and is qualified in its entirety by reference to the 2011 Plan, a copy of which is being filed as an exhibit to this annual report on Form 10-K.
During the year ended July 31, 2011, we granted options to purchase 20,000,000 shares of our common stock under the 2011 Plan.
Recent Sales of Unregistered Securities
During our fourth quarter ended July 31, 2011, we issued the following unregistered equity securities:
As previously disclosed in our Current Report on Form 8-K as filed with the SEC on September 30, 2011, effective September 9, 2011, we issued an aggregate of 4,739,630 restricted common shares in a private placement offering to five subscribers (each, a "Subscriber" at a deemed issuance price of $0.10 per share. The offering was made to such Subscribers in connection with and in consideration, in part, of each such Subscriber's prior subscription and/or finder's fee subscription in and to the Company which was completed in October and/or November of 2009 (each being a "Prior Subscription") in accordance with the terms and conditions of certain subscription materials entered into at such time as between the Company and each Subscriber (collectively, the "Prior Subscription Materials"). Although the Prior Subscription Materials did include various price protection (i.e., ratchet) provisions (each a "Ratchet"), the Ratchet provisions did not extend to the circumstance in which a particular Subscriber would have exercised any of their pre-Ratchet $0.23 exercise price warrants forming part of their Prior Subscription units in and to our Company (each a "Warrant") in advance of an actual Ratchet event taking place. As a consequence, and in consideration of each Subscriber having exercised certain of their Prior Subscription Warrants prior to a subsequent event that triggered a Ratchet event that reduced the exercise price of the other Warrants in such series to $0.10 per Warrant Share, our Company offered to such Subscribers an aggregate of 4,739,630 common shares at a deemed issuance subscription price of $0.10 per common share, in full and complete satisfaction of the number of Ratchet common shares which each Subscriber would have been entitled to on a post-Ratchet basis, should they have exercised their Warrants on a post-Ratchet basis rather than on a pre-Ratchet basis. Our Company relied on exemptions from registration under the United States Securities Act of 1933, as amended, provided by and Regulation S (with respect to three of the Subscribers) and Rule 506 of Regulation D (with respect to the remaining two Subscribers).
As previously disclosed in our Current Report on Form 8-K as filed with the SEC on September 30, 2011, effective September 26, 2011, in connection with a Share Purchase Agreement described in Item 1 above, we issued a total of 95,000,000 restricted common shares to the three Sellers. We relied on exemptions from registration under the United States Securities Act of 1933, as amended, provided by Rule 506 of Regulation D.
ITEM 6.
ITEM 6.
SELECTED FINANCIAL DATA
We are a smaller reporting company as defined by Rule 12b-2 of the Exchange Act and are not required to provide the information required under this item.
ITEM 7.
ITEM 7.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion of our financial condition, changes in financial condition, plan of operations and results of operations should be read in conjunction with (i) our audited consolidated financial statements as at July 31, 2011 and 2010 and (ii) the section entitled “Business”, included in this annual report. The discussion contains forward-looking statements that involve risks, uncertainties and assumptions. Our actual results may differ materially from those anticipated in these forward-looking statements as a result of many factors, including, but not limited to, those set forth under “Risk Factors” and elsewhere in this annual report.
Recent Activities
2011 Private Placement
During the year ended July 31, 2011, we completed a private placement in which we sold 92,390,000 shares of common stock for $0.10 per share to raise gross proceeds of $9,239,000 (the “2011 private placement”). We paid $206,381 in cash offering costs and netted $9,032,619 from this transaction. We used substantially all of the proceeds of the private placement to fund our acquisition of Galveston Bay Energy, LLC (“GBE”) as described below.
Acquisition of GBE
On February 15, 2011 we closed on the acquisition of a private Texas oil and gas company, GBE, which owns working interests in and operates producing oil and natural gas properties and its related facilities in four fields located in Galveston Bay, Texas.
Immediately following our acquisition of GBE, we sold 15% of our own aggregate working interest in the Galveston Bay fields for $1.4 million in cash to SPE Navigation 1, LLC (“SPE”), a company controlled by Michael Watts, who is the father-in-law of Jeremy Driver, a Director and our Chief Executive Officer. Effective May 1, 2011, SPE acquired an additional 10% of our aggregate working interest in the Galveston Bay fields for an additional $1.15 million. As a result of these transactions, GBE became our wholly owned subsidiary and owns approximately 53% of the aggregate net revenue interest in the four fields.
Acquisition of SPE
On September 26, 2011, we closed on the acquisition of 100% of the membership interests of SPE for 95,000,000 shares of Strategic common stock. SPE’s assets at the time of purchase were 25% working interest in GBE’s historical interest in the Galveston Bay fields, as discussed above, and one million shares of Hyperdynamics common stock. Hyperdynamics is a public company traded on the NYSE. On the date we obtained control of SPE, September 23, 2011, the closing market price of Hyperdynamics common stock was $3.90 per share. Thus, the value of our Hyperdynamics stock was $3,900,000. As of the date of filing, we had sold a portion of the HDY common stock for net proceeds of approximately $4,000,000. We believe the acquisition of SPE provided liquidity sufficient to fund our activities and plan of operations.
Additionally, with the purchase of SPE, we now own approximately 93% of the working interest and approximately 72% of the aggregate net revenue in the Galveston Bay fields. In order to maximize production from our Galveston Bay properties, we plan approximately $2.6 million in improvements in the next 12 months to the properties to include upgrading production facilities, new pipelines, recompletion of existing shut-in wells, and various other projects aimed specifically at increasing production. In March 2011, we secured an initial line of credit from a commercial bank for up to $5,000,000 to support our work on these properties.
Other projects
In January 2011, we farmed out our Markham City North, Illinois prospect to Core Minerals Management II, LLC (“Core”). We retained a 10% working interest, carried to the Earnings Threshold, $1,350,000. The arrangement is more fully described in Note 3 - Oil and Gas Properties of our Financial Statements. In June 2011, Core acquired two existing wells from another operator and has assigned a ten percent (10%) working interest in both wells to Penasco. One of the acquired wells will be used as a water injection well and the other will be used as a production monitor well. In September 2011, Core commenced drilling of three wells in the Markham City, Illinois project area. Two wells were completed in October 2011, one of which is producing oil and the other of which is shut in pending further evaluation. The third well will be used as a water supply well. As of October 1, 2011, Core had expended approximately $600,000 towards the Earnings Threshold.
In September 2011, we purchased a non-operated working interest in mineral leases covering 460 acres onshore in Duval County, Texas. Under the agreement, the operator will commence drilling a well on or before December 31, 2011. Our working interest in the lease area is 6.70732% to the casing point of the first well drilled and 5.5% after the casing point of the initial well and for subsequent operations in the lease area. Our net revenue interest in the prospect is 4.125%. As of November 15, 2011, we had paid $40,385 for the cash call on the initial well.
The following table sets out our consolidated losses for the periods indicated:
We recorded a net loss of $10,285,243, or $0.09 per basic and diluted common share, during the year ended July 31, 2011, as compared to a net loss of $3,491,876, or $0.08 per basic and diluted common share, during the year ended July 31, 2010.
The changes in results were predominantly due to the factors below:
·
Revenues, lease operating expense, depreciation, depletion, and amortization expense, and accretion expense increased substantially because of the inclusion of the results of our new subsidiary, GBE. We purchased GBE on February 15, 2011. Our consolidated financial statements include GBE’s results from February 15, 2011 through July 31, 2011. Through GBE, we produced from approximately 26 active oil and gas wells in four fields. This represents a substantial increase in our operations.
·
We recorded an impairment charge during the year ended July 31, 2011 because the net book value of our oil and gas properties exceeded the ceiling by $140,029 on January 31, 2011.
·
Consulting fees reduced because we incurred expenses in 2010 for investor relations programs that we did not continue in 2011.
·
Consulting fees - related party increased due to our granting warrants as compensation to a company for investor relations and public relations services. This company is a related party, as it is controlled by the father-in-law of our CEO, Jeremy Driver.
·
Acquisition related costs in 2011 were attributable to stock granted to consultants as finders’ fees for their role in effecting the acquisition of GBE and we also paid due diligence fees.
·
Share return and settlement in 2011 related to a settlement with an officer and a director, Amiel David and Alan Gaines, in which they received cash and warrants and returned the stock previously granted to them in conjunction with the acquisition of GBE.
·
Warrant modification expense was $743,189 in the year ended July 31, 2010. The modification expense is a result of a modification of original terms of certain investor warrants. The modification extended the term of a total of 5,577,939 outstanding warrants resulting in an incremental cost of $743,189. The $743,189 represents the estimated incremental fair market value of the awards immediately prior to and subsequent to the modification.
·
We opened a new location in Houston, Texas, hired additional accounting staff, and hired an operations manager and regulatory manager for GBE, which increased our general and administrative expense.
·
GBE maintains a letter of credit to satisfy a Texas Railroad Commission requirement and has a line of credit with a commercial bank. Because of these arrangements, interest expense increased.
·
During 2011, we settled certain of our accounts payable by the issuance of common stock that, at the date of issuance, had a fair value in excess of the amount of debt being settled. We therefore recognized a net loss on the settlements of $50,737.
·
We continue to re-measure our derivative warrants at fair value at every reporting date. Because the February 2011 private placement triggered the warrant ratchet provisions, we had more warrants outstanding with a lower exercise price as of July 31, 2011; this increased the loss on derivative warrant liability during the year ended July 31, 2011.
We do not expect the increase in acquisition costs, related party consulting expenses and settlement expense to be recurring expenses. The increases in revenue, lease operating expense, depreciation, depletion, and amortization expense, accretion expense, general and administrative expense, and interest expense are associated with the operations of GBE and will be an ongoing element in our financial results.
Liquidity and Capital Resources
The following table sets forth our cash and working capital as of July 31, 2011 and July 31, 2010:
Subject to the availability of additional financing, in order to maximize production from our Galveston Bay properties, we plan approximately $2,5 million in improvements in the next 12 months to the properties to include upgrading production facilities, new pipelines, recompleting of existing shut-in wells, and other projects aimed specifically at increasing production. In March 2011, we secured an initial line of credit from a commercial bank for up to $5.0 million to support our work on these properties. Additionally, our acquisition of SPE and subsequent sale of the securities we acquired provided approximately $4 million of additional cash.
At July 31, 2011, we had $1,082,099 of cash on hand and a working capital deficit of $ 3,773,504 ($2,543,223 is attributable to a warrant derivative liability which would ordinarily be settled in stock). As such, our working capital on July 31, 2011 was not sufficient to enable us to pursue our lease operating costs, to pay our general and administrative expenses, and to pursue our plan of operations over the next 12 months. However, the recent acquisition of SPE Navigation I, LLC has supplied sufficient current assets to meet our estimated capital requirements during the next 12 months.
Various conditions outside of our control may detract from our ability to raise the capital needed to execute our plan of operations, including the price of oil as well as the overall market conditions in the international and local economies. We recognize that the United States economy has suffered through a period of uncertainty during which the capital markets have been depressed from levels established in recent years, and that there is no certainty that these levels will stabilize or reverse. We also recognize that the price of oil decreased from approximately $140 per barrel in 2008 to under $40 per barrel in February of 2009. During our fiscal year ended July 31, 2011, oil price levels increased as to a high of $114 per barrel, but they have decreased to approximately $93 per barrel as of late October 2011. If the price of oil drops to levels seen in previous years, we recognize that it will adversely affect our ability to raise additional capital. Any of these factors could have a material impact upon our ability to raise financing and, as a result, upon our short-term or long-term liquidity.
Net Cash Used in Operating Activities
Net cash used in operating activities during the year ended July 31, 2011 has decreased in comparison to the prior year; we used cash of $2,266,201 compared to $2,632,842 during the year ended July 31, 2010. This decrease is attributable to decreases in management and consulting fees in 2011 and to increased net cash flows from our new subsidiary, GBE. Prior to our acquisition of GBE, operating activities have primarily used cash as a result of the operating and organizational activities such as consulting and professional fees, direct operating costs, management fees and travel and promotion. Because of the start-up nature of our business up through the fiscal year ended July 31, 2010, the bulk of our operating costs have been consulting, management, and general and administrative costs. With our acquisition of GBE, we expect to derive a much greater percentage of our cash flows from operations from revenues and direct operating costs. Because the GBE properties will increase our contribution margin from our core activities, the acquisition should continue to enhance our cash flows from operations.
Net Cash Used in Investing Activities
During the year ended July 31, 2011, investing activities used cash of $7,451,193 compared to a use of cash of $575,412 during the year ended July 31, 2010. The changes between such periods relates primarily to proceeds from the sale of working interest in our Kenedy and Dixon projects, offset by the purchase of GBE, in fiscal 2011. Our future cash flows used in investing will increase due to our planned investment in the fields that we acquired when we acquired GBE.
Net Cash Provided by Financing Activities
As we have had limited revenues since inception, we have financed our operations primarily through private placements of our common stock. Financing activities during the year ended July 31, 2011 provided cash of $10,551,642 compared to $3,437,312 during the year ended July 31, 2010. This was primarily attributable to our significant private placement in fiscal 2011.
Critical Accounting Policies
The financial statements have been prepared in conformity with accounting principles generally accepted in the United States of America and the rules of the Securities and Exchange Commission (“SEC”). The preparation of financial statements in conformity with U.S. generally accepted accounting principles requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods.
We regularly evaluate the accounting policies and estimates that we use to prepare our consolidated financial statements. In general, our estimates are based on historical experience, on information from third party professionals, and on various other assumptions that are believed to be reasonable under the facts and circumstances. Actual results could differ from those estimates made by management.
We believe that our critical accounting policies and estimates include the accounting for oil and gas properties, long-lived assets reclamation costs, the fair value of our warrant derivative liability, and accounting stock-based compensation.
Oil and Natural Gas Properties
We account for our oil and natural gas producing activities using the full cost method of accounting as prescribed by the United States Securities and Exchange Commission (SEC). Under this method, subject to a limitation based on estimated value, all costs incurred in the acquisition, exploration, and development of proved oil and natural gas properties, including internal costs directly associated with acquisition, exploration, and development activities, the costs of abandoned properties, dry holes, geophysical costs, and annual lease rentals are capitalized within a cost center. Costs of production and general and administrative corporate costs unrelated to acquisition, exploration, and development activities are expensed as incurred.
Costs associated with unevaluated properties are capitalized as oil and natural gas properties but are excluded from the amortization base during the evaluation period. When we determine whether the property has proved recoverable reserves or not, or if there is an impairment, the costs are transferred into the amortization base and thereby become subject to amortization.
We assess all items classified as unevaluated property on at least an annual basis for inclusion in the amortization base. We assess properties on an individual basis or as a group if properties are individually insignificant. The assessment includes consideration of the following factors, among others: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; the assignment of proved reserves; and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate that there would be impairment, or if proved reserves are assigned to a property, the cumulative costs incurred to date for such property are transferred to the amortizable base and are then subject to amortization.
Capitalized costs included in the amortization base are depleted using the units of production method based on proved reserves. Depletion is calculated using the capitalized costs included in the amortization base, including estimated asset retirement costs, plus the estimated future expenditures to be incurred in developing proved reserves, net of estimated salvage values.
The net book value of all capitalized oil and natural gas properties within a cost center, less related deferred income taxes, is subject to a full cost ceiling limitation which is calculated quarterly. Under the ceiling limitation, costs may not exceed an aggregate of the present value of future net revenues attributable to proved oil and natural gas reserves discounted at 10 percent using current prices, plus the lower of cost or market value of unproved properties included in the amortization base, plus the cost of unevaluated properties, less any associated tax effects. Any excess of the net book value, less related deferred tax benefits, over the ceiling is written off as expense. Impairment expense recorded in one period may not be reversed in a subsequent period even though higher oil and gas prices may have increased the ceiling applicable to the subsequent period. During the year ended July 31, 2011, we recorded a $140,029 impairment charge because the net book value of our oil and gas properties exceeded the ceiling.
Beginning December 31, 2009, full cost companies use the un-weighted arithmetic average first day of the month price for oil and natural gas for the 12-month period preceding the calculation date. Prior to December 31, 2009, companies used the price in effect at the end of each accounting period and had the option, under certain circumstances, to elect to use subsequent commodity prices if they increased after the end of the accounting quarter.
Sales or other dispositions of oil and natural gas properties are accounted for as adjustments to capitalized costs, with no gain or loss recorded unless the ratio of cost to proved reserves would significantly change.
Asset Retirement Obligation
We record the fair value of an asset retirement cost, and corresponding liability as part of the cost of the related long-lived asset and the cost is subsequently allocated to expense using a systematic and rational method. We record an asset retirement obligation to reflect our legal obligations related to future plugging and abandonment of our oil and natural gas wells and gas gathering systems. We estimate the expected cash flow associated with the obligation and discount the amount using a credit-adjusted, risk-free interest rate. At least annually, we reassess the obligation to determine whether a change in the estimated obligation is necessary. We evaluate whether there are indicators that suggest the estimated cash flows underlying the obligation have materially changed. Should those indicators suggest the estimated obligation may have materially changed on an interim basis (quarterly), we will accordingly update our assessment. Additional retirement obligations increase the liability associated with new oil and natural gas wells and gas gathering systems as these obligations are incurred.
Fair Value
Accounting standards regarding fair value of financial instruments define fair value, establish a three-level hierarchy which prioritizes and defines the types of inputs used to measure fair value, and establish disclosure requirements for assets and liabilities presented at fair value on the consolidated balance sheets.
Fair value is the amount that would be received from the sale of an asset or paid for the transfer of a liability in an orderly transaction between market participants. A liability is quantified at the price it would take to transfer the liability to a new obligor, not at the amount that would be paid to settle the liability with the creditor.
The three-level hierarchy is as follows:
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Level 1 inputs consist of unadjusted quoted prices for identical instruments in active markets.
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Level 2 inputs consist of quoted prices for similar instruments.
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Level 3 valuations are derived from inputs which are significant and unobservable and have the lowest priority.
Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. We have determined that certain warrants outstanding as of the date of these financial statements qualify as derivative financial instruments under the provisions of FASB ASC Topic No. 815-40, “Derivatives and Hedging - Contracts in an Entity’s Own Stock.” These warrant agreements include provisions designed to protect holders from a decline in the stock price (‘down-round’ provision) by reducing the exercise price in the event we issue equity shares at a price lower than the exercise price of the warrants. As a result of this down-round provision, the exercise price of these warrants could be modified based upon a variable that is not an input to the fair value of a ‘fixed-for-fixed’ option as defined under FASB ASC Topic No. 815-40 and consequently, these warrants must be treated as a liability and recorded at fair value at each reporting date.
The fair value of these warrants was determined using a lattice model with any change in fair value during the period recorded in earnings as “Gain (loss) on derivative warrant liability.”
Significant inputs used to calculate the fair value of the warrants include expected volatility, risk-free interest rate and management’s assumptions regarding the likelihood of a future repricing of these warrants pursuant to the down-round provision.
The following table sets forth by level within the fair value hierarchy our financial assets and liabilities that were accounted for at fair value on a recurring basis as of July 31, 2011.
The following table sets forth the changes in the fair value measurement of our Level 3 derivative warrant liability during the year ended July 31, 2011:
The $1,040,523 change in fair value was recorded as a reduction of the derivative liability and as a $1,206,788 unrealized loss on the change in fair value of the liability in our statement of operations and a $166,265 adjustment to paid-in capital related to the exercise during the period of warrants classified as derivative liabilities.
The carrying amounts reported in the balance sheet for cash, accounts receivable, accounts receivable - related party, accounts payable and accrued expenses, and convertible notes payable approximate their fair market value based on the short-term maturity of these instruments.
Stock-Based Compensation
ASC 718, “Compensation-Stock Compensation” requires recognition in the financial statements of the cost of employee services received in exchange for an award of equity instruments over the period the employee is required to perform the services in exchange for the award (presumptively the vesting period). We measure the cost of employee services received in exchange for an award based on the grant-date fair value of the award.
We account for non-employee share-based awards based upon ASC 505-50, “Equity-Based Payments to Non-Employees.” ASC 505-50 requires the costs of goods and services received in exchange for an award of equity instruments to be recognized using the fair value of the goods and services or the fair value of the equity award, whichever is more reliably measurable. The fair value of the equity award is determined on the measurement date, which is the earlier of the date that a performance commitment is reached or the date that performance is complete. Generally, our awards do not entail performance commitments. When an award vests over time such that performance occurs over multiple reporting periods, we estimate the fair value of the award as of the end of each reporting period and recognize an appropriate portion of the cost based on the fair value on that date. When the award vests, we adjust the cost previously recognized so that the cost ultimately recognized is equivalent to the fair value on the date the performance is complete.
We recognize the cost associated with share-based awards that have a graded vesting schedule on a straight-line basis over the requisite service period of the entire award.
See Note 1 of our consolidated financial statements for our year ended July 31, 2011 for a summary of other significant accounting policies.
Off-Balance Sheet Arrangements
We have not entered into any off-balance sheet arrangements that have or are reasonably likely to have a current or future effect on our financial condition, changes of financial condition, revenues, expenses, results of operations, liquidity, capital expenditures or capital resources that is material to investors.
ITEM 7A.
ITEM 7A.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
We are a smaller reporting company as defined by Rule 12b-2 of the Exchange Act and are not required to provide the information required under this item.
ITEM 8.
ITEM 8.
FINANCIAL STATEMENTS
STRATEGIC AMERICAN OIL CORPORATION
Index to Consolidated Financial Statements
The Board of Directors
Strategic American Oil Corporation
Houston, Texas
We have audited the accompanying consolidated balance sheets of Strategic American Oil Corporation and its subsidiaries (collectively, the “Company”) as of July 31, 2011 and 2010 and the related consolidated statement of operations, cash flows and changes in stockholders’ equity for each of the years then ended. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatements. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. 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 Strategic American Oil Corporation and its subsidiaries as of July 31, 2011 and 2010, and the results of their operations and their cash flows for each of the year then ended in conformity with accounting principles generally accepted in the United States of America.
/s/ MaloneBailey, LLP
www.malone-bailey.com
Houston, Texas
November 15, 2011
STRATEGIC AMERICAN OIL CORPORATION
CONSOLIDATED BALANCE SHEETS
The accompanying notes are an integral part of these consolidated financial statements
STRATEGIC AMERICAN OIL CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
The accompanying notes are an integral part of these consolidated financial statements
STRATEGIC AMERICAN OIL CORPORATION
CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY
The accompanying notes are an integral part of these consolidated financial statements
STRATEGIC AMERICAN OIL CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
The accompanying notes are an integral part of these consolidated financial statements
STRATEGIC AMERICAN OIL CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS (CONTINUED)
The accompanying notes are an integral part of these consolidated financial statements
STRATEGIC AMERICAN OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1 - Description of Business and Summary of Significant Accounting Policies
Description of business and basis of presentation
Strategic American Oil Corporation (“we”, “us”, “Strategic”, the “Company”) was formed for the purpose of oil and gas exploration, development, and production. We were incorporated as Carlin Gold Corporation on April 12, 2005 in Nevada, U.S.A. On July 11, 2005, we changed our name to Nevada Gold Corp., on October 18, 2005 we changed our name to Gulf States Energy Inc. and on September 5, 2006, we changed our name to Strategic American Oil Corporation. We own 100% of Penasco Petroleum Inc. (“Penasco”), a Nevada corporation incorporated on November 23, 2005 and 100% of Galveston Bay, LLC, (“GBE”) a Texas limited liability company. The financial statements have been prepared in conformity with accounting principles generally accepted in the United States of America and the rules of the Securities and Exchange Commission (“SEC”).
Reclassifications
Certain prior year amounts have been reclassified to conform with the current presentation.
Principles of consolidation
The accompanying consolidated financial statements include the accounts of Strategic and our wholly owned subsidiaries, Penasco and GBE. All significant intercompany accounts and transactions have been eliminated in consolidation.
Use of estimates
The preparation of the consolidated financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the respective reporting periods. We base our estimates and judgments on historical experience and on various other assumptions and information that we believe to be reasonable under the circumstances. Estimates and assumptions about future events and their effects cannot be perceived with certainty and, accordingly, these estimates may change as new events occur, as more experience is acquired, as additional information is obtained and as our operating environment changes.
Significant areas requiring management’s estimates and assumptions include the determination of the fair value of transactions involving stock-based compensation and financial instruments and oil and natural gas proved reserve quantities. Oil and natural gas proved reserve quantities which form the basis for the calculation of amortization of oil and natural gas properties and for asset impairment tests. Management emphasizes that reserve estimates are inherently imprecise and that estimates of more recent reserve discoveries are more imprecise than those for properties with long production histories.
Actual results may differ from the estimates and assumptions used in the preparation of our consolidated financial statements.
Cash and cash equivalents
Cash and cash equivalents are all highly liquid investments with an original maturity of three months or less at the time of purchase and are recorded at cost, which approximates fair value.
Our functional currency is the United States dollars. Transactions denominated in foreign currencies are translated into their United States dollar equivalents using current exchange rates. Monetary assets and liabilities are translated using exchange rates that prevailed as of the balance sheet date. Non-monetary assets and liabilities are translated using exchange rates that prevailed as of the transaction date. Revenue, if applicable and expenses are translated using average exchange rates over the accounting period. We have had no revenue denominated in foreign currencies. Gains or losses resulting from foreign currency transactions are included in results of operations.
Receivables and allowance for doubtful accounts
Oil and gas revenues receivable are recorded at the invoiced amount and do not bear any interest. We regularly review collectability and establish or adjust an allowance for uncollectible amounts as necessary using the specific identification method. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote. There were no reserves for uncollectible amounts in the periods presented.
Accounts receivable - related party is the revenue receivable from our Barge Canal properties, which are operated by a company owned by one of our officers, who is also a director.
Other receivables consist of joint interest billings due to us from participants holding a working interest in oil and gas properties that we operate. We regularly review collectability and establish or adjust an allowance for uncollectible amounts as necessary using the specific identification method. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote. As of July 31, 2011, we have reserved approximately $72,000 for potentially uncollectable other receivables.
Other current assets
Other current assets consist primarily of prepaid insurance, prepaid interest, and loan origination costs associated with our line of credit. (See Note 6 - Line of Credit)
Concentrations
Our operations are concentrated in Texas and the majority of our operations are conducted offshore in Galveston Bay. We operate in the oil and gas exploration and production industry. If the oil and natural gas exploration and production industry were adversely affected, we would experience adverse effects. Because our properties are offshore, we are also vulnerable to adverse weather.
For the year ended July 31, 2011, 77.4% of our revenue was attributable to one purchaser. At July 31, 2011, this same purchaser accounted for 79% of our accounts receivable. A second purchaser accounted for an additional 12.3% of our accounts receivable at July 31, 2011.
We place cash with high quality financial institutions and at times may exceed the federally insured limits. We have not experienced a loss in such accounts nor do we expect any related losses in the near term.
Oil and natural gas properties
We account for our oil and natural gas producing activities using the full cost method of accounting as prescribed by the United States Securities and Exchange Commission (SEC). Under this method, subject to a limitation based on estimated value, all costs incurred in the acquisition, exploration, and development of proved oil and natural gas properties, including internal costs directly associated with acquisition, exploration, and development activities, the costs of abandoned properties, dry holes, geophysical costs, and annual lease rentals are capitalized within a cost center. Costs of production and general and administrative corporate costs unrelated to acquisition, exploration, and development activities are expensed as incurred.
Costs associated with unevaluated properties are capitalized as oil and natural gas properties but are excluded from the amortization base during the evaluation period. When we determine whether the property has proved recoverable reserves or not, or if there is an impairment, the costs are transferred into the amortization base and thereby become subject to amortization.
We assess all items classified as unevaluated property on at least an annual basis for inclusion in the amortization base. We assess properties on an individual basis or as a group if properties are individually insignificant. The assessment includes consideration of the following factors, among others: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; the assignment of proved reserves; and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate that there would be impairment, or if proved reserves are assigned to a property, the cumulative costs incurred to date for such property are transferred to the amortizable base and are then subject to amortization.
Capitalized costs included in the amortization base are depleted using the units of production method based on proved reserves. Depletion is calculated using the capitalized costs included in the amortization base, including estimated asset retirement costs, plus the estimated future expenditures to be incurred in developing proved reserves, net of estimated salvage values.
Beginning December 31, 2009, full cost companies use the un-weighted arithmetic average first day of the month price for oil and natural gas for the 12-month period preceding the calculation date. Prior to December 31, 2009, companies used the price in effect at the end of each accounting period and had the option, under certain circumstances, to elect to use subsequent commodity prices if they increased after the end of the accounting quarter.
Sales or other dispositions of oil and natural gas properties are accounted for as adjustments to capitalized costs, with no gain or loss recorded unless the ratio of cost to proved reserves would significantly change.
Impairment
The net book value of all capitalized oil and natural gas properties within a cost center, less related deferred income taxes, is subject to a full cost ceiling limitation which is calculated quarterly. Under the ceiling limitation, costs may not exceed an aggregate of the present value of future net revenues attributable to proved oil and natural gas reserves discounted at 10 percent using current prices, plus the lower of cost or market value of unproved properties included in the amortization base, plus the cost of unevaluated properties, less any associated tax effects. Any excess of the net book value, less related deferred tax benefits, over the ceiling is written off as expense. Impairment expense recorded in one period may not be reversed in a subsequent period even though higher oil and gas prices may have increased the ceiling applicable to the subsequent period. During the year ended July 31, 2011, we recorded a $140,029 impairment charge because the net book value of our oil and gas properties exceeded the ceiling as of January 31, 2011.
Asset retirement obligation
We record the fair value of an asset retirement cost, and corresponding liability as part of the cost of the related long-lived asset and the cost is subsequently allocated to expense using a systematic and rational method. We record an asset retirement obligation to reflect our legal obligations related to future plugging and abandonment of our oil and natural gas wells and gas gathering systems. We estimate the expected cash flow associated with the obligation and discount the amount using a credit-adjusted, risk-free interest rate. At least annually, we reassess the obligation to determine whether a change in the estimated obligation is necessary. We evaluate whether there are indicators that suggest the estimated cash flows underlying the obligation have materially changed. Should those indicators suggest the estimated obligation may have materially changed on an interim basis (quarterly), we will accordingly update our assessment. Additional retirement obligations increase the liability associated with new oil and natural gas wells and gas gathering systems as these obligations are incurred.
Note receivable
We received a note receivable for the sale of oil and gas property in November 2010 (See Note 3 - Oil and Gas Properties). We will be paid 5% of the oil production from the property we sold until the note is paid off. Because of the time frame during which we expect to collect the note, we have classified the note receivable as long term. We estimate the realizable value of the note as $50,000, based on the operating environment in the lease area and the time frame for projected collection.
Restricted cash
Restricted cash consists of certificates of deposit that have been posted as collateral supporting a reclamation bond guaranteeing remediation of our oil and gas properties in Texas. As of July 31, 2011 and 2010, restricted cash totaled $6,716,850 and $40,000, respectively.
Other assets
Other assets at July 31, 2011 consisted primarily of prepaid land use fees, which are payments that cover multiple years (typically ten years) rental for easements and surface leases. We acquired prepaid land use fees as part of our acquisition of Galveston Bay Energy, LLC (see Note 2 - Acquisition of Galveston Bay Energy, LLC) and we pay for rentals as they come due on an ongoing basis. Other assets at July 31, 2010 consisted primarily of cash deposited with our operator that supported a reclamation bond guaranteeing remediation of our oil and gas properties in Louisiana.
Property and equipment, other than oil and gas
Property and equipment are stated at cost, less accumulated depreciation. Depreciation is computed using the straight-line method over the estimated useful lives of the related asset, generally three to five years. Fully depreciated assets are retained in property and accumulated depreciation accounts until they are removed from service. We perform ongoing evaluations of the estimated useful lives of the property and equipment for depreciation purposes. Maintenance and repairs are expensed as incurred.
Impairment of long-lived assets
We periodically review our long-lived assets, other than oil and gas property, for impairment whenever events or changes in circumstances indicate that the carrying amount of the assets may not be fully recoverable. We recognize an impairment loss when the sum of expected undiscounted future cash flows is less than the carrying amount of the asset. The amount of impairment is measured as the difference between the asset’s estimated fair value and its book value. We recorded no impairment on our non-oil and gas long-lived assets during the years ended July 31, 2011 and 2010, respectively.
Revenue recognition
We recognize revenue when persuasive evidence of an arrangement exists, services have been rendered, the sales price is fixed or determinable, and collectability is reasonably assured. We follow the “sales method” of accounting for oil and natural gas revenue, so we recognize revenue on all natural gas or crude oil sold to purchasers, regardless of whether the sales are proportionate to our ownership in the property. Actual sales of gas are based on sales, net of the associated volume charges for processing fees and for costs associated with delivery, transportation, marketing, and royalties in accordance with industry standards. Operating costs and taxes are recognized in the same period in which revenue is earned. Taxes are reflected as a component of lease operating expense.
Income taxes
We account for income taxes using the asset and liability method. Under this method, deferred income tax assets and liabilities are determined based on differences between the financial reporting and tax basis of assets and liabilities and are measured using the enacted tax rates and laws that will be in effect when the differences are expected to be recovered or settled. Deferred tax assets are reduced by a valuation allowance if, based on the weight of available evidence, it is more likely than not that some portion or all of the deferred tax assets will not be realized.
Fair value
Accounting standards regarding fair value of financial instruments define fair value, establish a three-level hierarchy which prioritizes and defines the types of inputs used to measure fair value, and establish disclosure requirements for assets and liabilities presented at fair value on the consolidated balance sheets.
Fair value is the amount that would be received from the sale of an asset or paid for the transfer of a liability in an orderly transaction between market participants. A liability is quantified at the price it would take to transfer the liability to a new obligor, not at the amount that would be paid to settle the liability with the creditor.
The three-level hierarchy is as follows:
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Level 1 inputs consist of unadjusted quoted prices for identical instruments in active markets.
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Level 2 inputs consist of quoted prices for similar instruments.
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Level 3 valuations are derived from inputs which are significant and unobservable and have the lowest priority.
Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. We have determined that certain warrants outstanding as of the date of these financial statements qualify as derivative financial instruments under the provisions of FASB ASC Topic No. 815-40, “Derivatives and Hedging - Contracts in an Entity’s Own Stock.” (See Note 8 - Derivative Warrant Liability).
The fair value of these warrants was determined using a lattice model with any change in fair value during the period recorded in earnings as “Gain (loss) on derivative warrant liability.”
Significant inputs used to calculate the fair value of the warrants include expected volatility, risk-free interest rate and management’s assumptions regarding the likelihood of a future repricing of these warrants pursuant to the down-round provision.
Our derivative warrant liability is our only financial asset or liability that is accounted for at fair value, using a Level 3 valuation technique, on a recurring basis as of July 31, 2011.The carrying amounts reported in the balance sheet for cash, accounts receivable, accounts receivable - related party, accounts payable and accrued expenses, and notes payable approximate their fair market value based on the short-term maturity of these instruments.
Stock-based compensation
ASC 718, “Compensation-Stock Compensation” requires recognition in the financial statements of the cost of employee services received in exchange for an award of equity instruments over the period the employee is required to perform the services in exchange for the award (presumptively the vesting period). We measure the cost of employee services received in exchange for an award based on the grant-date fair value of the award.
We account for non-employee share-based awards based upon ASC 505-50, “Equity-Based Payments to Non-Employees.” ASC 505-50 requires the costs of goods and services received in exchange for an award of equity instruments to be recognized using the fair value of the goods and services or the fair value of the equity award, whichever is more reliably measurable. The fair value of the equity award is determined on the measurement date, which is the earlier of the date that a performance commitment is reached or the date that performance is complete. Generally, our awards do not entail performance commitments. When an award vests over time such that performance occurs over multiple reporting periods, we estimate the fair value of the award as of the end of each reporting period and recognize an appropriate portion of the cost based on the fair value on that date. When the award vests, we adjust the cost previously recognized so that the cost ultimately recognized is equivalent to the fair value on the date the performance is complete.
We recognize the cost associated with share-based awards that have a graded vesting schedule on a straight-line basis over the requisite service period of the entire award.
Earnings per share
We compute basic loss per share using the weighted average number of shares of common stock outstanding during each period. Diluted loss per share includes the dilutive effects of common stock equivalents on an “as if converted” basis. For the years ended July 31, 2011 and 2010, potential dilutive securities had an anti-dilutive effect and were not included in the calculation of diluted net loss per common share.
Contingencies
Legal
We are subject to legal proceedings, claims and liabilities which arise in the ordinary course of business. We accrue for losses associated with legal claims when such losses are probable and can be reasonably estimated. These accruals are adjusted as additional information becomes available or circumstances change. Legal fees are charged to expense as they are incurred. See Note 13 - Commitments and Contingencies for more information on legal proceedings.
Environmental
We accrue for losses associated with environmental remediation obligations when such losses are probable and can be reasonably estimated. These accruals are adjusted as additional information becomes available or circumstances change. Costs of future expenditures for environmental remediation obligations are not discounted to their present value. Recoveries of environmental remediation costs from other parties are recorded at their undiscounted value as assets when their receipt is deemed probable.
Recent accounting pronouncements
In December 2010, the FASB issued ASU No. 2010-29, Disclosure of Supplementary Pro Forma Information for Business Combinations. The standard clarifies that an entity is required to disclose pro forma revenue and earnings as though the business combination(s) that occurred during the current year had occurred as of the beginning of the comparable prior annual reporting period only. In addition, this standard expands the supplemental pro forma disclosures to include a description of the nature and amount of material, nonrecurring pro forma adjustments directly attributable to the business combination included in the reported pro forma revenue and earnings. This pronouncement is effective for annual reporting periods beginning after December 15, 2010, with early adoption prohibited. We currently comply with these disclosures and thus this standard will not have any impact on previously issued financial statements.
In May 2011, the FASB issued Accounting Standards Update No. 2011-04, “Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs” (“ASU 2011-04”). The amendments in ASU 2011-04 will provide clarification of certain fair value concepts such as principal market determination; valuation premise and highest and best use; measuring fair value of instruments with offsetting market or counterparty credit risks; blockage factor and other premiums and discounts; and liabilities and instruments classified in shareholders’ equity. In addition, the pronouncement will provide guidance for new disclosures such as transfers between Level 1 and Level 2 of the fair value hierarchy; Level 3 fair value measurements; an entity’s use of an asset when it is different from its highest and best use; and fair value hierarchy disclosures for financial instruments not measured at fair value but disclosed. This pronouncement is effective for reporting periods beginning after December 15, 2011, with early adoption prohibited. The new guidance will require prospective application. We believe the adoption of this guidance will primarily affect certain disclosures related to fair value and will not have a material impact on our consolidated financial position or results of operations.
In June 2011, the FASB issued Accounting Standards Update No. 2011-05, “Presentation of Comprehensive Income” (“ASU 2011-05”). This pronouncement will bring consistency to the way reporting entities disclose comprehensive income in their consolidated financial statements and related notes. ASU 2011-05 will no longer permit disclosure of comprehensive income in either the statement of shareholders’ equity or in a note to the consolidated financial statements. Instead, reporting entities will have two options for presenting comprehensive income. The first option presents comprehensive income in a single statement, which includes two components: net income and other comprehensive income. The second option allows the presentation of comprehensive income in two separate but consecutive statements: one for net income and the other for other comprehensive income. This pronouncement is effective for reporting periods beginning after December 15, 2011, with early adoption permitted. The new guidance will require retrospective application. We believe the adoption of this guidance will affect our presentation of comprehensive income, if any, and will not have a material impact on its consolidated financial position or results of operations.
Other recently issued or adopted accounting pronouncements are not expected to have, or did not have, a material impact on our financial position or results from operations.
Note 2 - Acquisition of Galveston Bay Energy, LLC
Acquisition of Galveston Bay Energy, LLC (“GBE”)
On February 15, 2011 we closed on the acquisition of a private Texas oil and gas company named Galveston Bay Energy, LLC (“GBE”) which owns working interests in and operates producing oil and natural gas properties and its related facilities in four fields located in Galveston Bay, Texas. GBE holds both proved producing, proved shut-in, proved non-producing, and proved undeveloped reserves. We acquired 100% of the membership interest in GBE and thus GBE is our wholly owned subsidiary. Our consolidated financial statements include the results of GBE for the period from February 15, 2011 through July 30, 2011; specifically, our consolidated results include revenues from GBE of $2,890,950 and earnings of $589,055.
Immediately following our acquisition of GBE, we sold 15% of our own aggregate working interest in the Galveston Bay fields for $1,400,000 in cash to SPE Navigation 1, LLC (“SPE”), a company controlled by Michael Watts, who is the father-in-law of Jeremy Driver, a Director and our Chief Executive Officer. SPE paid for its working interest by wiring the funds directly to the seller of the property. Our agreement with SPE provided that SPE could acquire an additional 10% working interest in the properties for $1,150,000 paid within 90 days of the acquisition. Effective May 1, 2011, SPE acquired an additional 10% of our aggregate working interest in the Galveston Bay fields for an additional $1,150,000 pursuant to our agreement.
The seller was paid $10,397,376 cash in February and March 2011, which included the purchase price of $9,900,000 and the settlement of certain then - outstanding liabilities of GBE. SPE paid $1,400,000 of the purchase price directly to the seller and we paid $8,500,000 to the seller. The acquisition was funded primarily by proceeds from our private placement (see Note 10 - Capital Stock). The following table summarizes the preliminary allocation of the purchase price to the assets acquired and liabilities assumed recognized at the acquisition date:
Acquisition-related costs
We incurred $2,617,099 of acquisition-related costs, such as due diligence and finders’ fees. Acquisition-related costs include cash payments of $70,757. Additionally, we granted 15,914,634 shares of common stock to three individuals, as detailed below, as finders’ fees for their roles in the acquisition of GBE. The shares were valued, based on the closing stock price on the date of grant, at $2,546,342, which was recorded as a current period expense.
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On February 15, 2011, we granted 914,634 shares of common stock to a consultant for his role in bringing us the opportunity to make the acquisition. The shares were valued at $146,341 based on the closing stock price on the grant date and recorded in expense as acquisition-related costs.
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On February 15, 2011, we granted 15 million shares of common stock to Alan D. Gaines in part as compensation for bringing us the opportunity to make the acquisition described above and in part as new director and officer compensation. 50% of shares vested that date and are valued at $1,200,000 based on the closing stock price on the grant date and recorded in expense as acquisition-related costs. Our agreement with Mr. Gaines provided for a proportional increase in the shares awarded if we raise in excess of $11 million within three months of the closing of the GBE transaction, inclusive of the $9,239,000 raised in the 2011 private placement. The remaining shares were scheduled to vest as follows: 3,750,000 on February 15, 2012 and 3,750,000 on February 15, 2013. However, Mr. Gaines returned the stock he received and forfeited the unvested stock when he separated from Strategic in April 2011.
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On February 15, 2011, we granted 15 million shares of common stock to Amiel David in part as compensation for bringing us the opportunity to make the acquisition described above and in part as new director and officer compensation. 50% of shares vested on that date and are valued at $1,200,000 based on the closing stock price on the grant date and recorded in expense as acquisition-related costs. Our agreement with Mr. David provides for a proportional increase in the shares awarded if we raise in excess of $11 million within three months of the closing of the GBE transaction, inclusive of the $9,239,000 raised in the 2011 private placement. The remaining shares were scheduled to vest as follows: 3,750,000 on February 15, 2012 and 3,750,000 on February 15, 2013. However, Mr. David returned the stock he received and forfeited the unvested stock when he separated from Strategic in April 2011.
Supplemental pro forma information (unaudited)
The unaudited pro forma results presented below for the years ended July 31, 2011 and 2010 have been prepared to give effect to the purchase described above as if it had been consummated on August 1, 2009. The unaudited pro forma results do not purport to represent what our results of operations actually would have been if this acquisition had been completed on such date or to project our results of operations for any future date or period.
Note 3 - Oil and Gas Properties
Oil and natural gas properties as of July 31, 2011 and 2010 consisted of the following:
Evaluated properties
Galveston Bay properties
In February 2011, we acquired a company that operates producing oil and natural gas properties and its related facilities in four fields located in Galveston Bay, Texas. The transaction is more fully described in Note 2 - Acquisition of Galveston Bay Energy, LLC. The portion of the purchase price for the company that was allocated to Oil and Gas Properties was $9,840,834, which includes assumed asset retirement obligations of $5,843,330.
Immediately following our acquisition of GBE, we sold 25% of our own aggregate working interest in the Galveston Bay fields for $2,550,000 in cash to SPE Navigation 1, LLC (“SPE”), a company controlled by Michael Watts, who is the father-in-law of Jeremy Driver, a Director and our Chief Executive Officer as described in Note 2 - Acquisition of Galveston Bay Energy, LLC. In conjunction with its working interest purchase, SPE also assumed 25% of the asset retirement obligations associated with the properties, which totaled $1,523,573. As a result of these transactions, GBE is our wholly owned subsidiary and owns approximately 53% of the aggregate net revenue interest in the four fields. In accordance with the Full Cost accounting rules, this transaction was accounted for as a reduction of our oil and gas properties and no gain or loss was recognized.
GBE has interests in multiple leases with the State of Texas General Land Office in Galveston Bay. With the acquisition of GBE, our primary operations are offshore in Galveston Bay.
Subsequent to the balance sheet date, we repurchased SPE’s working interest. As a result, as of September 1, 2011, our aggregate net revenue interest has increased to approximately 72%. (see Note 15 - Subsequent Events)
Onshore property
We own interests in properties in Louisiana, Texas, and Illinois. As of July 31, 2011, our interests in these properties were as follows:
Illinois
As of July 31, 2010, we owned 100% working interest in multiple leases in or near Markham City, Illinois. In January 2011, we farmed out our Markham City North, Illinois prospect to Core Minerals Management II, LLC (“Core”). Under the farmout agreement, we retained a 10% working interest and assigned the balance of our working interest in the Markham City prospect to Core. Core became the operator of the property. Our working interest is carried until the Core meets the “Earnings Threshold” of $1,350,000. Core will perform exploration activities on the prospect. Core will spud the initial well by June 30, 2011 or the working interest reverts to us. If Core does not expend one-half of the Earnings Threshold by April 1, 2012, our working interest reverts to 50% and if Core does not expend the entire Earnings Threshold by January 24, 2013, Core will reassign to us working interest equal to the proportion of the Earning Threshold which up to that time it has not spent. After payout of the property, $1,350,000 or 29,000 barrels, provided that we hold less than 25% working interest in the property at payout, our working interest will be adjusted to 25%. There were no proceeds or payments associated with this transaction, thus there was no immediate accounting impact to this transaction.
The farmout agreement was modified in March 2011 to extend the deadline for spudding the initial well to September 30, 2011. Additionally, in June 2011, Core acquired two existing wells from another operator and has assigned a ten percent (10%) working interest in both wells to Penasco. One of the acquired wells will be used as a water injection well and the other will be used as a production monitor well. The wells and lease that the wells are on are subject to the farmout agreement. Finally, in July 2011, Penasco assigned a ninety percent (90%) working interest in multiple leases to Core and the leases assigned leases are subject to the farmout agreement.
In September 2011, Core commenced drilling of three wells in the Markham City, Illinois project area as more fully discussed in Note 15 - Subsequent Events.
Texas
We own 100% working interest (90% after payout) and a 72.5% net revenue interest (65.25% after payout) in approximately 81 acres of an oil and gas lease (the “Welder Lease”) located in Calhoun County, Texas. There are two productive wells on the property, which is operated by a company owned by one of our officers.
We own a 3% working interest in approximately 138 acres of an oil and gas lease (the “Janssen Lease”) located in Karnes County, Texas.
Louisiana
We own a 6.25% overriding royalty interest in properties located in Franklin and Richland parishes in Louisiana (the “Holt” and “Strahan” properties). As of July 31, 2010, we held 97% working interest in the Holt property and 100% working interest in the Strahan property. In November 2010, we sold our working interest in the Holt and Strahan properties for $100,000 and a retained overriding royalty interest of 6.25%. The buyer assumed the asset retirement obligation, which was $38,775, associated with the property. We executed a note receivable for the purchase price of $100,000. The buyer will pay 5% of its production revenue, net of severance tax, until the balance is repaid. We estimate the realizable value of the note as $50,000, based on the operating environment in the lease area and the time frame for projected collection. As of July 31, 2011, the balance on the note was $45,355. The proceeds and the assumption of the asset retirement obligation were treated as a reduction of capitalized costs in accordance with rules governing full cost companies.
As of July 31, 2010 we owned working interest in the Dixon lease, a 160 acre tract in Franklin Parish, Louisiana which had two producing oil wells. In September 2010, we sold our interest in the Dixon lease for cash proceeds of $75,000. The buyer assumed the asset retirement obligation, which was $12,132, associated with the property. The proceeds and the assumption of the asset retirement obligation were treated as a reduction of capitalized costs in accordance with rules governing full cost companies.
Unevaluated Properties
Additions to unevaluated property during the year ended July 31, 2011 include interest capitalized of $51,671, exploration costs of $98,224 and acquisition costs of $67,204. As of July 31, 2010, we had accumulated $734,533 of costs associated with unevaluated properties. During the year ended July 31, 2011, we reclassified properties with accumulated costs of $751,631 from unevaluated to evaluated properties based on our determination that reserves would or would not be assigned to the properties as follows:
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In August 2010, we entered into an agreement with a consultant to assist in marketing our Kenedy Ranch lease to investors. Under the terms of the agreement, the consultant would receive a 5% working interest, carried to the casing point, carved out from our retained portion of the lease. In September 2010 we assigned 81.25% working interest in the Kenedy Ranch lease to Chinn Exploration Company (“Chinn”) for $200,000 cash. The agreement provided that Chinn would operate the property and would drill a test well within 18 months of the date of the agreement. We retained an 18.75% working interest and our marketing consultant received a 5% working interest carved out from our interest. Thus, after compensation of the consultant, our working interest in Kenedy Ranch was 13.75%. The cash proceeds we received in conjunction with this agreement were treated as a reduction of capitalized cost in accordance with rules governing full cost companies. We declined to participate further in the project and thus determined that reserves would not be assigned. We reclassified the net accumulated costs, $166,361, which includes capitalized interest of $46,969, and is net of the $200,000 of cost recovery to evaluated property.
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As of December 31, 2010, we had drilled two dry holes on our Koliba lease. We determined that we would not perform further exploration activities and reclassified the accumulated costs, $103,681, including capitalized interest of $7,110, to evaluated property.
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During the quarter ended January 31, 2011, we determined that we would not pursue further exploration activities on multiple leases in Texas, Louisiana, and Illinois, and reclassified the accumulated costs, $198,705, to evaluated property.
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During the fourth quarter of 2011, we reclassified the accumulated costs pertaining to our Markham City North prospect, $282,884, including capitalized interest of $43,529, to evaluated property. In September 2011, the operator of the lease drilled three wells on the lease, one of which is productive. Accordingly, we expect to assign reserves to the prospect.
In September 2011, we purchased an interest in leases in Duval County, Texas, as more fully discussed in Note 15 - Subsequent Events.
Note 4 - Impairment
We account for our oil and natural gas producing activities using the full cost method of accounting as prescribed by the United States Securities and Exchange Commission (“SEC”). Under this method, subject to a limitation based on estimated value, all costs incurred in the acquisition, exploration, and development of proved oil and natural gas properties, including internal costs directly associated with acquisition, exploration, and development activities, the costs of abandoned properties, dry holes, geophysical costs, and annual lease rentals are capitalized within a cost center.
We evaluated our capitalized costs using the full cost ceiling test as prescribed by the Securities and Exchange Commission at the end of each reporting period. As of January 31, 2011, the net book value of oil and gas properties exceeded the ceiling amount by $140,029 and, accordingly, an impairment charge was recorded. As of July 31, 2011, the net book value of oil and gas properties did not exceed the ceiling amount and thus, there was no impairment.
Changes in production rates, levels of reserves, future development costs, and other factors will determine our actual ceiling test calculation and impairment analyses in future periods.
Note 5 - Asset Retirement Obligation
The following is a reconciliation of our asset retirement obligation liability as of July 31, 2011 and 2010:
Note 6 - Line of Credit
On March 17, 2011, GBE secured a one year revolving line of credit of up to $5,000,000 with a commercial bank. The note carries interest at a rate of prime + 1% (currently 6%) with a minimum interest rate of 5%. Interest is payable monthly. We must use proceeds from the line of credit solely to enhance our Galveston Bay properties. The note is collateralized by our Galveston Bay properties and substantially all GBE’s assets. Strategic has also executed a parental guarantee of payment. As of July 31, 2011, we had outstanding $1,360,573 on this line of credit. We have $3,639,427 available on the line of credit as of July 31, 2011. In November 2011, we repaid $500,000 of the line of credit.
We incurred $66,076 of loan origination fees which are being amortized straight line over one year, the term of the loan. As of July 31, 2011, $24,057 had been amortized.
Note 7 - Notes Payable
2009 Convertible note payable
During March 2009, we sold $150,000 convertible debentures, convertible at the greater of $0.25 per share or 90% of the current market price. The investor also received warrants to purchase 600,000 shares of common stock at an exercise price of $.60 per share for an exercise period that expired September 25, 2010. We retained the right to redeem the convertible promissory notes at any time upon giving certain notice to the holder(s), and subject to paying a 20% premium. The debentures carry interest at 15% to be accrued semiannually and payable in arrears. This sale resulted in net cash proceeds of $150,000.
We analyzed the convertible debentures for derivative accounting consideration under FASB ASC Topic No. 815-10 (formerly SFAS 133) and ASC Topic No. 815-40 (formerly EITF 00-19). We determined the conversion feature met the criteria for classification in stockholders’ equity as the terms limit the number of shares to be delivered upon conversion by specifying the floor on the conversion price. Therefore, derivative accounting is not applicable for the convertible instruments.
We evaluated the warrants for derivative accounting consideration under FASB ASC Topic No. 815-10 (formerly SFAS 133) and ASC Topic No. 815-40 (formerly EITF 00-19). We have concluded that the warrants, limiting the number of shares issuable, meet the criteria for classification in stockholders’ equity. Therefore, derivative accounting is not applicable for the warrants.
The intrinsic value of the beneficial conversion feature was $58,779. The relative fair value of the warrants and the intrinsic value of the beneficial conversion feature totaling $150,000 were recorded as a discount to the notes. The discount was amortized and charged to interest expense over the life of the note using the effective interest rate of 278% per annum.
During the year ended July 31, 2011, we accrued interest of $16,042 at the contracted rate of 15% on the principal outstanding on the note.
As of July 31, 2011 and July 31, 2010, $150,000 and $104,564 of the discount had been amortized, respectively. The note was scheduled to mature in September 2010 and the principal and interest was repaid in full during our 2011 fiscal year.
2010 Promissory Notes
We issued promissory notes for funds received from two private lenders of $20,000 and $25,000 during January 2011. The principal on the notes are due after one year and bear interest at 15% per annum payable on a quarterly basis. During 2011 the notes and the accrued interest thereon were extinguished with the issuance of 466,360 shares of common stock valued, using the closing stock price on the date of the extinguishment, at $46,636. Because the amount extinguished was less than the principal and accrued interest, we experienced a gain on this extinguishment of $1,013.
During the year ended July 31, 2011, we issued promissory notes for funds received from three directors, two of whom were also officers of Strategic, for aggregate proceeds of $203,300. In February 2011, we paid $13,577 of principal on the notes payable using common stock. The notes are more fully described in Note 11 - Related Party Transactions.
On February 15, 2011, one of the lenders resigned as a director of the company. Accordingly, his outstanding $175,000 note payable is no longer classified as a related party debt.
Subsequent to the balance sheet date, the principal and interest on the 2010 Promissory Notes were paid in full.
Insurance Note Payable
In addition, we financed our commercial insurance program using a note payable in installments that include principal and interest of $20,384 per month for nine months. The monthly payments include interest at an annual percentage rate of 4.95%. At July 31, 2011, there was $80,596 remaining outstanding on this note. In September 2011, we purchased additional financed insurance coverage which resulted in the addition of $18,667 to the note. The installments payable on the note increased to $26,704, effective for the three remaining payments on the note.
Note 8 - Derivative Warrant Liability
Effective July 31, 2009, we adopted FASB ASC Topic No. 815-40 (formerly EITF 07-05) which defines determining whether an instrument (or embedded feature) is indexed to an entity’s own stock. This literature specifies that a contract that would otherwise meet the definition of a derivative but is both (a) indexed to our own stock and (b) classified in stockholders’ equity in the statement of financial position, would not be considered a derivative financial instrument and provides a new two-step model to be applied in determining whether a financial instrument or an embedded feature is indexed to an issuer’s own stock and thus able to qualify for the scope exception.
Certain warrants we issued during the year ended July 31, 2010 are not afforded equity treatment because these warrants have a down-round ratchet provision on the exercise price. As a result, the warrants are not considered indexed to our own stock, and as such, the fair value of the embedded derivative liability is reflected on the balance sheet and all future changes in the fair value of these warrants will be recognized currently in earnings in our consolidated statement of operations under the caption “Gain (loss) on warrant derivative liability” until such time as the warrants are exercised or expire. The total fair values of the warrants issued during the year ended July 31, 2010, were determined using a lattice model and have been recognized as a derivative liability as described below.
The warrants were valued using a multi-nomial lattice model with the following assumptions:
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The stock price on the valuation date would fluctuate with our projected volatility;
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Warrant holders would exercise at target price multiples of the market price trigger prices. The target price multiple reduces as the warrants approach maturity;
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Warrant holders would exercise the warrant at maturity if the stock price was above two times the reset exercise price;
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An annual reset event would occur at 65% discount to market price;
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The projected volatility was based on historical volatility. Because we do not have sufficient trading history to determine our own historical volatility, we used the volatility of a group of comparable companies combined with our own historical volatility from May 2009, when we began trading.
The following table provides the basis for the volatility curve used in the model:
The total fair value of the warrants issued during October 2009, amounting to $3,349,984, was recognized as a derivative liability on the date of issuance. The fair value on the date of issuance includes the net cash proceeds from the sale of stock of $2,042,112, the value of accounts payable and debt settled of $310,000, and an unrealized loss as of the date of issuance of $997,872.
The exercise price of all the 6,030,000 warrants issued to investors, consultants, and for finders’ fees in November 2009 is subject to “reset” provisions in the event we subsequently issue common stock, stock warrants, stock options or convertible debt with a stock price, exercise price or conversion price lower than $0.35. If these provisions are triggered, the exercise price of all their warrants will be reduced.
The total fair value of the warrants issued during November 2009, amounting to $1,467,759, was recognized as a derivative liability on the date of issuance. The fair value on the date of issuance includes net cash proceeds from the sale of stock of $1,016,750, the fair value of warrants granted to a consultant for business development services of $12,170, and an unrealized loss as of the date of issuance of $438,839.
In April 2010, the exercise price of the 19,007,500 derivative warrants issued during October and November 2009 was reduced from $0.35 to $0.23 per share. These warrants are measured at fair value, with changes in fair value recognized currently in earnings in our consolidated statement of operations under the caption “Gain (loss) on derivative warrant liability. Thus, the impact of the repricing is included in earnings as a part of the recurring measurement of the warrants’ fair value.
2,775,870 of the warrants classified as derivatives and issued during October 2009 were exercised during April 2010 for $638,450. This reduced the derivative liability by $702,229 and increased the additional paid-in capital by the same amount.
870,000 of the warrants classified as derivatives and issued during November 2009 were exercised during the year ended July 31, 2011 for $200,100. This reduced the derivative liability by $166,265 and increased the additional paid-in capital by the same amount.
The following table sets forth by level within the fair value hierarchy our financial assets and liabilities that were accounted for at fair value on a recurring basis as of July 31, 2011.
The following table sets forth the changes in the fair value measurement of our Level 3 derivative warrant liability during the year ended July 31, 2011:
The $1,040,523 change in fair value was recorded as a reduction of the derivative liability and as a $1,206,788 unrealized loss on the change in fair value of the liability in our statement of operations and a $166,265 adjustment to paid-in capital related to the exercise during the period of warrants classified as derivative liabilities.
The following table sets forth the changes in the fair value measurement of our Level 3 derivative warrant liability during the year ended July 31, 2010:
The $1,878,332 change in fair value was recorded as a reduction of the derivative liability and as a $1,176,103 unrealized gain on the change in fair value of the liability in our statement of operations and an $702,229 adjustment to paid in capital related to the exercise during the period of warrants classified as derivative liabilities.
Note 9 - Share Return and Settlement
As discussed in Note 2 - Acquisition of Galveston Bay Energy, LLC, we granted 30 million shares to Alan D. Gaines and Amiel David in part as compensation for bringing us the opportunity to make the GBE acquisition and in part as new director and officer compensation. 50% of shares vested that date and are valued at $1,200,000 based on the closing stock price on the grant date and recorded in expense as acquisition-related costs. However, Mr. Gaines and Mr. David returned the stock they received and forfeited the unvested stock when they separated from Strategic in April 2011.
The return of the 15,000,000 shares of Strategic’s common stock held by Mr. Gaines and Mr. David in April 2011 was subject to a settlement agreement whereby they would:
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Receive $1,043,750 cash,
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Receive warrants to purchase 10,000,000 shares of common stock at an exercise price of $0.10 and a three year term, and
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Return the 15,000,000 shares of common stock that they had received in February 2011 to Strategic.
Cash settlement involving unvested equity awards effectively vests the award; accordingly, we recognized $1,800,000 of compensation cost for the unvested 15,000,000 shares of common stock on the date of the settlement agreement. The stock was valued using the closing stock price on the settlement date.
In summary, the transactions involving Mr. David and Mr. Gaines are recognized on the income statement as follows:
The warrants had an estimated fair value of $991,240 as computed using the Black-Scholes option pricing model with an expected life of three years, a risk free interest rate of .61%, a dividend yield of 0%, and an expected volatility of 150.43%.
The fair value of the cash and equity based consideration that Mr. Gaines and Mr. David received in the settlement was, therefore, $2,034,990. The fair value of the settlement did not exceed the value of compensation associated with the award that was previously recognized, $4,200,000 as detailed above. Thus, there was no additional expense incurred in the settlement. The cash settlement was debited directly to additional paid-in capital and the return of stock was credited to paid-in capital and debited to common stock.
Note 10 - Capital Stock
Share Capital
Our capitalization at July 31, 2011 was 500,000,000 authorized common shares with a par value of $0.001 per share.
Common Stock Issuances
Stock issued for cash, net of share issuance costs, and for warrants exercised for cash:
On October 15, 2009, we completed a private placement for 10,950,000 units at a subscription price of $0.20 per Unit for gross proceeds of $2,190,000. Each Unit is comprised of one common share and one warrant to purchase the same number of shares of common stock. The warrants to purchase 10,950,000 shares of common stock had an exercise price of $0.35 per warrant share and expire five years from the date of issuance. The purchase price for 1,000,000 units, or $200,000, was collected during the year ended July 31, 2009, and the shares were deemed as issued as of July 31, 2009. The proceeds from this placement, net of finder’s fees paid in cash, were allocated to the warrants because the warrants contain a down round ratchet provision and are derivatives (see Note 8 - Derivative Warrant Liability) and fair value of the warrants was classified as a liability.
In November 2009, we completed a private placement for 5,250,000 units at a subscription price of $0.20 per Unit for gross proceeds of $1,050,000. Each Unit is comprised of one common share and one warrant to purchase the same number of shares of common stock. The warrants to purchase 5,250,000 shares of common stock had an exercise price of $0.35 per warrant share and expire five years from the date of issuance. The proceeds, net of finder’s fees, were allocated to the warrants because the warrants contain a down round ratchet provision and are derivatives (see Note 8 - Derivative Warrant Liability) and fair value of the warrants was classified as a liability.
We paid $181,138 of cash offering costs associated with the placements completed in October and November 2009. Accordingly, the net cash proceeds raised from these placements totaled $2,858,862. The warrants contain a down round ratchet provision and are derivatives (see Note 8 - Derivative Warrant Liability) and thus the net proceeds were allocated to the warrants. The fair value of the warrants was classified as a liability.
In addition, during October and November 2009, we granted warrants to purchase 1,207,500 shares of common stock at $.35 per share which expire five years from the date of issuance as finder’s fees. The fair value of the warrants was calculated using a lattice model as $300,925. The warrants contain a down round ratchet provision and are derivatives (see Note 8 - Derivative Warrant Liability) and the fair value of the warrants was classified as a liability at issuance.
In April 2010, an aggregate of 2,775,870 share purchase warrants were exercised for net proceeds of $638,450. The warrants were derivative warrants; accordingly, the warrant derivative liability as of the date of exercise, $702,229, was reclassified to paid-in capital. A total value of $1,340,679 was recorded in conjunction with this transaction.
During October 2010, an aggregate of 870,000 share purchase warrants were exercised for net proceeds of $200,100. The warrants were derivative warrants; accordingly, the warrant derivative liability associated with these warrants as of the date of exercise, $166,265 was reclassified to paid-in capital.
During February 2011, we completed a private placement in which we sold 92,390,000 shares of common stock for $0.10 per share to raise gross proceeds of $9,239,000 (the “2011 private placement”). We paid $142,800 in cash offering costs as finders’ fees and $63,581 in associated legal costs, resulting in net cash proceeds of $9,032,619. Additionally, we granted 1,500,000 shares of common stock and warrants to purchase common stock as detailed below as finders’ fees. All costs associated with this transaction, including the shares and warrants granted as finders’ fees, were recorded as a reduction in the private placement proceeds, and reflected as an adjustment to equity.
In connection with the 2011 private placement, we granted equity based compensation for finders’ fees in conjunction with the offering as follows: 1,500,000 shares of common stock, warrants to purchase 1,300,000 shares of common stock at an exercise price of $0.10 per share with a contractual term of three years, and warrants to purchase 128,000 shares of common stock at an exercise price of $0.10 per share with a contractual term of three years. The stock was valued as $240,000 using the closing stock price on the date of grant.
The fair value of the warrants to purchase 1,300,000 shares of common stock, as computed using the Black-Scholes option pricing model with an expected life of three years, a risk free interest rate of 1.41%, a dividend yield of 0%, and an expected volatility of 150.78%, was $177,506. The fair value of the warrants to purchase 128,000 shares of common stock, as computed using the Black-Scholes option pricing model with an expected life of three years, a risk free interest rate of 1.22%, a dividend yield of 0%, and an expected volatility of 151.24%, was $15,108. As finders’ fees, the cost of the compensation reflected in equity.
This capital raise triggered the anti-dilution provisions of the units previously sold in October and November 2009. The investors involved in the previous capital raise received 17,750,000 shares of common stock in accordance with these provisions. Additionally, the exercise price of the warrants issued with the 2009 raise decreased to $0.10 per share and the warrant holders received warrants to purchase an additional 15,982,369 shares of common stock. The additional warrants received in this transaction contain the same price reset provision as the original warrants and accordingly are derivative warrants as more fully described in Note 8 - Derivative Warrant Liability.
For debt:
In September 2009, we settled $143,800 of outstanding accounts payable to consultants with Units comprised of one common share and one warrant to purchase the same number of shares of common stock. The warrants had an exercise price of $0.40 per share and expire three years from the date of issuance. 479,332 Units at a price of $0.30 per Unit were used to settle the accounts payable. The proceeds were allocated to the warrants and stock, respectively, based on their relative fair values as $44,325 and $99,475.
In October 2009, we settled $122,885 of outstanding accounts payable to consultants, officers, and directors with Units having the same terms as the October 2009 private placement. Thus, 614,417 Units at a price of $0.20 per Unit were used to settle the accounts payable. Each Unit is comprised of one common share and one warrant to purchase the same number of shares of common stock. The warrants to purchase 617,417 shares of common stock had an exercise price of $0.35 per share and expire five years from the date of issuance. The proceeds were allocated to the warrants, which contain a down-round ratchet provision and are derivatives (see Note 8 - Derivative Warrant Liability) and classified as a liability.
During February 2011, we settled accounts payable to consultants totaling $129,375 with the issuance of 1,293,750 shares of common stock. The fair value of the stock, as determined using the closing stock price on the date of grant, was $181,127; the excess fair value over the outstanding debt, which was recognized as a loss on settlement of accounts payable, was $51,750.
During April 2011, we settled accounts payable to a consultant and notes payable (See Note 7 - Notes Payable) totaling $51,174 with the issuance of 501,610 shares of common stock. The fair value of the stock, as determined using the closing stock price on the date of grant, was $50,162; the outstanding debt exceeded fair value by $1,013 and was recognized as a gain on settlement of accounts payable.
For debt - related party:
In October 2009, we settled $187,116 of principal and interest outstanding on notes payable to three related parties with Units having the same terms as the October 2009 private placement. Thus, 935,583 Units at a price of $0.20 per Unit were used to settle the debt. Each Unit is comprised of one common share and one warrant to purchase the same number of shares of common stock. The warrants to purchase 935,583 shares of common stock had an exercise price of $0.35 per share and expire five years from the date of issuance. The proceeds were allocated to the warrants, which contain a down-round ratchet provision and are derivatives (see Note 8 - Derivative Warrant Liability) and was classified as a liability.
During February 2011, we settled accounts payable to officers and directors and $13,577 of principal on notes payable to officers totaling $66,539 with the issuance of 665,390 shares of common stock. The fair value of the stock, as determined using the closing stock price on the date of grant, was $93,155; the excess fair value over the outstanding debt, which was recognized as additional compensation costs, was $26,616.
During April 2011, we settled accounts payable to officers and directors totaling $95,290 with the issuance of 952,900 shares of common stock. The fair value of the stock, as determined using the closing stock price on the date of grant, was $95,290.
For services:
During the year ended July 31, 2010, we issued 1,493,294 shares of common stock to consultants and directors for services valued at $519,115. The shares were valued using the closing market price on the date of grant.
During the year ended July 31, 2011, we issued 500,000 shares of common stock to consultants for services valued at $82,008. The shares were valued using the closing market price on the date of grant.
We granted 15,914,634 shares of common stock to three individuals, as detailed below, as finders’ fees for their roles in the acquisition of GBE (See Note 2 - Acquisition of Galveston Bay Energy, LLC). The shares were valued, based on the closing stock price on the date of grant, at $2,546,342. 15,000,000 of the shares granted were later returned to the Company as described in Note 9 - Share Return and Settlement.
We settled accounts payable and notes payable due to related parties, as discussed below. Because the fair value of the stock issued exceeded the outstanding debt, we recognized $26,616 as compensation.
Deemed dividend:
Our 2011 capital raise triggered the anti-dilution provisions of the units previously sold in October and November 2009. The investors involved in the previous capital raise received 17,750,000 shares of common stock in accordance with these provisions. The value of the shares that were issued, based upon the closing stock price on the date of issuance, was $2,840,000 and was treated as a deemed dividend.
Share return and settlement
Two individuals returned 15 million shares that had been issued in conjunction with the acquisition of GBE as part of a settlement that is described in Note 9 - Share Purchase and Settlement. The settlement resulted in additional expense of $756,250.
Stock Compensation Plans
Strategic may grant up to 40,000,000 shares of common stock under several historical stock-based compensation plans (the “Plans”). During April 2011, the Board of Directors authorized and approved the adoption of the 2011 Stock Incentive Plan (the “2011 Plan”). An aggregate of 25,000,000 shares of our common stock may be issued under the 2011 Plan. During August 2010, the Board of Directors authorized and approved the adoption of the 2010 Stock Incentive Plan (the “2010 Plan”). An aggregate of 5,000,000 shares of our common stock may be issued under the 2010 Plan. An aggregate of 10,000,000 of our shares may be issued under the 2009 Re-Stated Stock Incentive Plan (the “2009 Plan”). The Plans are administered by the Board of Directors which has substantial discretion to determine persons, amounts, time, price, exercise terms, and restrictions of the grants, if any.
For the years ended July 31, 2011 and 2010, compensation expense associated with option grants was $466,409 and $639,469, respectively. In addition, we granted stock valued at $2,654,551 and $519,115, respectively, as described above.
The fair value of each option or warrant award is estimated using the Black-Scholes valuation model. Expected volatility is based solely on historical volatility because we do not have traded options. Prior to May 2009, the volatility was determined by referring to the average historical volatility of a peer group of public companies because we did not have sufficient trading history to determine our own historical volatility. Beginning with computations after May 2009, when there was an active trading market for our stock, we have included our own historical volatility in determining the volatility used. We will continue to use a peer group until we have sufficient trading history to determine our own historical volatility.
The expected term calculation for stock options is based on the simplified method as described in the Securities and Exchange Commission Staff Accounting Bulletin number 107. We use this method because we do not have sufficient historical information on exercise patterns to develop a model for expected term. The risk-free interest rate is based on the U. S. Treasury yield in effect at the time of grant for an instrument with a maturity that is commensurate with the expected term of the stock options. The dividend yield rate of zero is based on the fact that we have never paid cash dividends on our common stock and we do not intend to pay cash dividends on our common stock.
The following table details the significant assumptions used to compute the fair market values of stock options granted:
Options granted to non-employees
The following table provides information about options granted to non-employees under our stock incentive plans during the years ended July 31, 2011 and 2010:
(1)
Excluding those options deemed re-issued in the repricing discussed below
We account for options granted to non-employees under the provisions of ASC 505-50 and record the associated expense at fair value on the final measurement date. Because there is no disincentive for nonperformance for these awards, the final measurement date occurs when the services are complete, which is the vesting date. For the options granted to non-employees on a graded vesting schedule, we estimate the fair value of the award as of the end of each reporting period and recognize an appropriate portion of the cost based on the fair value on that date. When the award vests, we adjust the cost previously recognized so that the cost ultimately recognized is equivalent to the fair value on the date the performance is complete.
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A summary of the grants made during the years ended July 31, 2011 and 2010 follows: In April 2011, options to purchase 12,500,000 shares of common stock with an exercise price of $0.10 per share and a term of ten years were granted to an officer and director of the company. The options vest 20% each six months over the 30 months following the award.
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In April 2011, options to purchase 1,000,000 shares of common stock with an exercise price of $0.10 per share and a term of ten years were granted to a director who also provides consulting services to us. The options vest 20% each six months over the 30 months following the award.
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In August 2010, options to purchase 1,400,000 shares of common stock with an exercise price of $0.20 per share and a term of three years were granted to one of our officers. The options vest 25% each six months over the 18 months following the award with the first 25% or 350,000 shares vesting immediately.
·
In November 2009, options to purchase 2,500,000 shares of common stock with an exercise price of $0.20 per share and a term of three years were granted to our new CEO. The initial fair value of the options was $770,020. Options to purchase 625,000 shares (25% of the award) vested immediately; the remaining options vest 25% each six months over the following 18 months. The expected term of the options that vested immediately, computed using the simplified method, was two years. The expected term of the options with graded vesting, computed using the simplified method, was 2.125 years.
·
In November 2009, options to purchase 100,000 shares of common stock with an exercise price of $.20 per share and a term of three years were granted to employee consultant as a signing bonus. The fair value of the options was $31,445. The options vest 25% each six months over the 24 months following the award. The expected term of the options, computed using the simplified method, was two years.
Options granted to employees
The following table provides information about options granted to employees under our stock incentive plans during the years ended July 31, 2011 and 2010:
A summary of the grants made during the year ended July 31, 2011 and 2010 follows:
In April 2011, options to purchase 6,500,000 shares of common stock with an exercise price of $0.10 per share and a term of ten years were granted to five employees. The options vest 20% each six months over the 30 months following the award. Because the grantees were employees, the awards are accounted for under the provisions of ASC 718. Accordingly, they are measured at fair value on the date of grant and the expense associated with the grant will be amortized over the 30 month vesting period on a straight line basis.
During the year ended July 31, 2010, we granted no options to employees.
Option Repricing
During April 2011, the Board of Directors approved the repricing of all of the then outstanding options to $0.10 per share. On the date of the repricing, options to purchase 7,530,000 shares were outstanding. The modification was accounted for as a cancellation of the original grant and a new award. The fair value of the modification was computed by comparing the fair value of the options immediately prior to the award with their original terms to the fair value of the repriced options. At the time of the repricing, options to purchase 6,155,000 shares were vested. The expense associated with the modification of these options, $88,759, was recognized in expense on the date of the repricing. The remaining options to purchase 1,375,000 shares were granted to non-employees and an estimate of the fair value of the modified grant will be recognized at each reporting date with an adjustment to the estimate as of the vesting date to reflect the current fair value.
The following table details the significant assumptions used to compute the effects of the repricing:
Based on the fair value of the options as of July 31, 2011, there was $1,626,360 of unrecognized compensation costs related to non-vested share based compensation arrangements.
Summary information regarding stock options issued and outstanding as of July 31, 2011 is as follows:
Warrants
We issued or modified the following warrants during the years ended July 31, 2011 and 2010:
With debt and equity:
During September 2009, we issued warrants to purchase 939,498 shares of common stock with an exercise price of $0.40 per share and a three year term in conjunction with the sale of stock and the settlement of accounts payable.
In October 2009, we issued warrants to purchase 12,500,000 shares of common stock with an exercise price of $0.35 per share and a five year term in conjunction with the sale of stock and the settlement of accounts payable and debt to related parties. We also issued as finder’s fees warrants to purchase 477,500 shares of common stock with an exercise price of $0.35 and a five year term. The warrants contain a down round ratchet provision and are derivatives (see Note 8 - Derivative Warrant Liability)
In November 2009, we issued warrants to purchase 5,250,000 shares of common stock with an exercise price of $0.35 per warrant share and a five year term. We also issued as finder’s fees warrants to purchase 730,000 shares of common stock with an exercise price of $0.35. The warrants contain a down round ratchet provision and are derivatives (see Note 8 - Derivative Warrant Liability)
During the year ended July 31, 2010, we issued warrants to purchase 100,000 shares of common stock with an exercise price of $.25 per share and a three year term with a promissory note payable. We recognized the relative fair value of the warrants of $16,000 as a discount on the note and a component of stockholders’ equity. The fair value of the warrants was estimated using the Black-Scholes option pricing model with an expected life of three years, a risk free interest rate of 1.39%, a dividend yield of 0%, and an expected volatility of 142%. In addition, we adjusted the debt discount related to the convertible note payable issued in March 2009 by increasing it by $12,067 during the year ended July 31, 2010.
In connection with our 2011 private placement, and the Share return and settlement discussed in Note 8 we issued a total of 27,410,369 warrants to purchase our common stock.
For services:
During the year ended July 31, 2010, we granted warrants to purchase 50,000 shares of common stock to a consultant. The compensation expense associated with this grant was expensed in the year ended July 31, 2010 and was $12,170. The warrants have a down-round ratchet provision on the exercise price; thus, the fair value of the warrants was classified as a liability.
With debt - related party:
During the year ended July 31, 2010, we issued warrants to purchase 100,000 shares of common stock with an exercise price of $.25 per share and a three year term with a promissory note payable to a related party. We recognized the relative fair value of the warrants of $16,000 as a discount on the note and a component of stockholders’ equity. The fair value of the warrants was estimated using the Black-Scholes option pricing model with an expected life of three years, a risk free interest rate of 1.39%, a dividend yield of 0%, and an expected volatility of 142%.
Warrant modifications
During August 2009, we extended the term of 5,158,238 warrants which were originally issued in conjunction with equity issues during 2006, 2007, and 2008. The modification resulted in modification expense of $679,199 which was calculated as the difference in the fair value of the warrants immediately before and after the modification using the Black-Scholes option pricing model. The following table details the significant assumptions used to compute the fair market value of the warrant modification:
During February 2010, we extended the term of 419,701 warrants from February 12, 2010 to February 12, 2011. These warrants were originally issued for finder’s fees. The modification resulted in modification expense of $63,990 which was calculated as the difference in the fair value of the warrants immediately before and after the modification using the Black-Scholes option pricing model. The following table details the significant assumptions used to compute the fair market value of the warrant modification:
During April 2010, we reduced the exercise price of warrants to purchase 19,007,500 shares of common stock from $.35 per share to $.23 per share. Because the warrants were derivative warrants, the repricing was included in the recurring measurement of the warrants’ fair value. (See Note 8 - Derivative Warrant Liability).
On February 15, 2011, we entered into a consulting agreement with Geoserve Marketing, LLC (“Geoserve”), a company controlled by Michael Watts, who is the father-in-law of Jeremy Driver, a Director and our Chief Executive Officer. We amended this agreement effective on March 9, 2011. Geoserve will provide investor relations services. The agreement has a three year term. The consulting agreement as amended provides that we will compensate Geoserve with warrants to purchase 20,000,000 shares of common stock at an exercise price of $0.10 per share with a five year term (expiring February 15, 2016) as prepayment for the first year of service. We may terminate the agreement after the first year with thirty days’ notice. On February 15, 2011, the first tranche of warrants to purchase 20,000,000 shares of common stock vested. The warrants had an estimated fair value of $2,885,807 as computed using the Black-Scholes option pricing model with an expected life of five years, a risk free interest rate of 2.35%, a dividend yield of 0%, and an expected volatility of 134.26%. We recognized the $2,885,807 as consulting expense - related party in year ended July 31, 2011.
If our common stock attains a five day average closing price of $.30 per share, an additional 15,000,000 warrants with an exercise price of $0.10 and an expiration date of February 15, 2016 shall be issued. If our common stock attains a five day average closing price of $.60 per share, an additional 15,000,000 warrants with an exercise price of $0.10 and an expiration date of February 15, 2016 shall be issued. The fair value of warrants that vest upon the attainment of a market condition must be estimated and amortized over the lower of the implicit or derived service period of the warrants. The fair value of the warrants and the derived service period were valued using a lattice model that values the liability of the warrants based on a probability weighted discounted cash flow model. This model is based on future projections of the various potential outcomes. The warrants to purchase 15,000,000 shares of common stock at $.30 per share and 15,000,000 shares of common stock at $.60 per share will be amortized over the derived service periods of 2.07 years and 2.49 years, respectively. As of July 31, 2011, the fair value of the warrants to purchase 15,000,000 shares of common stock at $.30 per share was $355,072 and the fair value of the warrants to purchase 15,000,000 shares at $.60 per share was $188,691. We recognized $79,752 of expense associated with these warrants during the year ended July 31, 2011.
Summary information regarding common stock warrants issued and outstanding as of July 31, 2011, is as follows:
Warrants outstanding and exercisable as of July 31, 2011:
Warrants outstanding and exercisable as of July 31, 2010:
Note 11 - Related Party Transactions
A company controlled by one of our officers operates our Barge Canal properties. Revenues generated from these properties were $458,959 and $295,574 for the years ended July 31, 2011 and 2010, respectively. In addition, lease operating costs incurred from these properties were $176,096 and $229,067 for the years ended July 31, 2011 and 2010, respectively.
As of July 31, 2011 and 2010, respectively, we had outstanding accounts receivable associated with these properties of $69,880 and $28,975 and no accounts payable.
From time to time, officers, directors, and family members of officers and directors have loaned us funds. The following table provides a summary of related party debt outstanding as of:
Additionally, one of our directors loaned us $185,000 during November and December 2010. This director resigned in February 2011 and his outstanding debt at the time of his resignation, $175,000, is classified as a non-related party note payable.
In February 2011, we settled $13,577 of the outstanding notes payable to two of the then related parties with the issuance of 135,769 shares of common stock using a conversion rate of $0.10 per share. The stock was valued using the closing stock price on the transaction date at $19,006; the excess fair value of $5,429 was recorded as compensation expense.
During 2011, we entered into a consulting contract with a company controlled by Michael Watts, the father-in-law of Jeremy Driver, our Chief Executive Officer and a Director, as described below. We also sold 25% of the working interest we acquired when we acquired Galveston Bay Energy, LLC for $2,550,000 to a different company, SPE Navigation I, LLC, controlled by Mr. Watts (See Note 3 - Oil and Gas Properties). Subsequent to the balance sheet date, we purchased SPE for 95,000,000 shares of Strategic common stock. As of July 31, 2011, SPE owed us $213,866 in joint interest receivables and we owed $497,108 of revenue payable to SPE. Subsequent to the balance sheet date, we remitted $282,052 to SPE in conjunction with these balances.
On February 15, 2011, we entered into a consulting agreement with Geoserve Marketing, LLC (“Geoserve”), a company controlled by Michael Watts, who is the father-in-law of Jeremy Driver, a Director and our Chief Executive Officer. We amended this agreement effective on March 9, 2011. Geoserve will provide investor relations services. The agreement has a three year term. The consulting agreement as amended provides that we will compensate Geoserve with warrants to purchase 20,000,000 shares of common stock at an exercise price of $0.10 per share with a five year term (expiring February 15, 2016) as prepayment for the first year of service. If our common stock attains a five day average closing price of $.30 per share, an additional 15,000,000 warrants with an exercise price of $0.10 and an expiration date of February 15, 2016 shall be issued. If our common stock attains a five day average closing price of $.60 per share, an additional 15,000,000 warrants with an exercise price of $0.10 and expiration date of February 15, 2016. We recognized $2,929,550, as detailed in Note 10 - Capital Stock. The contract permits us to terminate the agreement after the first year with thirty days’ notice.
Note 12 - Income Taxes
Our net loss before income taxes totaled $(10,285,243) and $(3,491,876) for the years ended July 31, 2011 and 2010, respectively. We therefore had no provision for income taxes for either period.
The reconciliation of our income tax provision at the statutory rate to the reported income tax expense is as follows:
Our deferred income taxes reflect the net tax effects of operating loss and tax credit carry forwards and temporary differences between carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which temporary differences representing net future deductible amounts become deductible.
Components of deferred tax assets as of July 31, 2011 and 2010 are as follows:
The valuation allowance is evaluated at the end of each year, considering positive and negative evidence about whether the deferred tax asset will be realized. At that time, the allowance will either be increased or reduced; reduction could result in the complete elimination of the allowance if positive evidence indicates that the value of the deferred tax assets is no longer impaired and the allowance is no longer required.
We have no positions for which it is reasonable that the total amounts of unrecognized tax benefits at July 31, 2011 will significantly increase or decrease within 12 months.
Generally, our income tax years 2007 through 2010 remain open and subject to examination by Federal tax authorities or the tax authorities in Louisiana and Texas which are the jurisdictions where we have our principal operations. No material amounts of the unrecognized income tax benefits have been identified to date that would impact our effective income tax rate.
As of July 31, 2011, we had approximately $7,101,990 of U.S. federal and state net operating loss carry-forward (“NOLs”) available to offset future taxable income, which begins expiring in 2026, if not utilized. Future tax benefits that may arise as a result of these losses have not been recognized in these financial statements. The deferred tax asset generated by the loss carry-forward has been fully reserved due to the uncertainty we will be able to realize the benefit from it.
Our ability to use our NOLs would be limited if it was determined that we underwent an “ownership change” under Section 382 (“Section 382”) of the Internal Revenue Code. Based upon the information available to us, along with our evaluation of various scenarios, we believe that our 2011 private placement caused us to experience an “ownership change”.
In order to determine whether an “ownership change” occurred, we had to compare the percentage of shares owned by each 5.0% shareholder immediately after the close of the testing date to the lowest percentage of shares owned by such 5.0% shareholder at any time during the testing period (which is generally a three year rolling period). The amount of the increase in the percentage of Company shares owned by each 5.0% shareholder whose share ownership percentage has increased is added together with increases in share ownership of other 5.0% shareholders, and an “ownership change” occurs if the aggregate increase in ownership by all such 5.0% shareholders exceeds 50%. The issuance of our common shares as part of the 2011 private placement caused such threshold to be exceeded.
As a result of experiencing an “ownership change”, we will only be allowed to use a limited amount of NOLs to offset our taxable income subsequent to the “ownership change.” The annual limit pursuant to Section 382 (the “382 Limitation”) is obtained by multiplying (i) the aggregate value of our outstanding equity immediately prior to the “ownership change” (reduced by certain capital contributions made during the immediately preceding two years and certain other items) by (ii) the federal long-term tax-exempt interest rate in effect for the month of the “ownership change.” As our ownership change occurred in February 2011, the federal long-term tax-exempt interest rate applicable to our limitation is 4.47%. Therefore, based on the factors in place at the time of our ownership change, we believe our annual limitation will be an estimated $239,600.
If we were to have taxable income in excess of the 382 Limitation following a Section 382 “ownership change,” we would not be able to offset tax on the excess income with the NOLs. Although any loss carryforwards not used as a result of any Section 382 Limitation would remain available to offset income in future years (again, subject to the Section 382 Limitation) until the NOLs expire, the “ownership change” will significantly defer the utilization of the loss carryforwards, accelerate payment of federal income tax and may cause some of the NOLs to expire unused.
Note 13 - Commitments and Contingencies
Contingencies
Legal
We are subject to legal proceedings, claims and liabilities which arise in the ordinary course of business. We accrue for losses associated with legal claims when such losses are probable and can be reasonably estimated. These accruals are adjusted as additional information becomes available or circumstances change. Legal fees are charged to expense as they are incurred.
Environmental
We accrue for losses associated with environmental remediation obligations when such losses are probable and can be reasonably estimated. These accruals are adjusted as additional information becomes available or circumstances change. Costs of future expenditures for environmental remediation obligations are not discounted to their present value. Recoveries of environmental remediation costs from other parties are recorded at their undiscounted value as assets when their receipt is deemed probable.
There is soil contamination at a tank facility owned by GBE. While it is probable that remediation will be required, we are evaluating the extent of the contamination, the activities that will be required to perform the remediation, and whether the Seller will be required to assume the remediation. The cost of the remediation is currently not estimable and has not been reflected in our financial results.
Commitments
We have the following contract obligations:
We pay $14,583 per month as a management fee pursuant to a contract with our Vice President of Operations. The contract automatically renews every three months as of November 30, 2008.
In June 2011, we entered into a consulting agreement with a company controlled by our former CFO. Under the terms of the agreement, the former CFO will provide business services for a term of one year and will receive $8,000 per month.
In March 2011, we executed a lease for office space in Houston, Texas. The lease term is three years and we have an option to extend the lease for an additional three years. Our scheduled rent is $6,406 per month plus common area maintenance cost for the first year, $6,673 plus common area maintenance cost for the second year, and $6,940 per month plus common area maintenance cost for the third year.
During July 2011, we signed a new lease for office space in Corpus Christi, Texas. Our scheduled rent is $3,199 per month and the lease term is 3 years.
Rent expense during the years ended July 31, 2011 and 2010 was $67,737 and $31,739, respectively. Future lease commitments are $116,061, $119,265, and $100,848 for the years ended July 31, 2012, 2013, and 2014, respectively.
The following table details our payment obligations related to our operating leases and to our debt that are due during the years ended July 31,
Prior to our purchase of GBE, the seller executed a Compression and Handling Agreement (the “PHA”) between the seller and GBE. Under the terms of the PHA, oil, natural gas, and salt water would be disposed of through the seller’s facility. Under the agreement, we are responsible for approximately a flat fee of $3,000 per month for the surface lease and a gauging fee, our pro-rata share of repairs at the facility, and compression, salt water disposal, and other charges based on the volumes disposed of through the facility. This contract was terminated subsequent to year-end.
Oil and gas operators in the State of Texas are required to obtain a letter of credit in favor of the Railroad Commission of Texas as security that they will meet their obligations to plug and abandon the wells they operate. We have a letter of credit in the amount of $6,610,000 issued by Green Bank. We pay a 1.5% per annum fee in conjunction with this letter of credit. The fee, $99,400, was prepaid in June 2011 and will be amortized on a straight line basis through the letter of credit’s renewal in October 2012.
Note 14 - Additional Financial Statement Information
Other receivables
Other receivables consist of joint interest billings due to us from participants holding a working interest in oil and gas properties that we operate. We regularly review collectability and establish or adjust an allowance for uncollectible amounts as necessary using the specific identification method. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote. As of July 31, 2011, we have reserved approximately $72,000 for potentially uncollectable other receivables.
Other current assets
Property and Equipment
Property and equipment consisted of the following:
Depreciation expense was $3,534 and $3,172 for the years ended July 31, 2011 and 2010, respectively. Management reviewed its fixed assets and capitalization policy as of July 31, 2010. We incurred a loss on retirement due to the write off of leasehold improvements of $7,560. In addition, we determined that equipment was in use in our oil and gas operations and we reclassified the net book value of the equipment to oil and gas properties as of July 31, 2010.
Accounts payable and accrued expenses
Note 15 - Subsequent Events
In August 2011, we granted 4,739,630 shares of common stock to certain investors who had participated in the October and November 2009 equity raises. These investors had exercised warrants to purchase common stock prior to the February 2011 equity raise and as a consequence had forfeited their contractual right to receive ratchet warrant shares. The stock grant was treated as an investor relations expense and valued at $616,152 based on the closing market price of Strategic’s common stock on the date of grant.
In September 2011, the entity from which we purchased GBE sued GBE alleging non-payment of approximately $225,000 in invoices related to the PHA that is described in Note 13 - Commitments and Contingencies. The invoices relate to the period from March 2011 to September 2011. We dispute the invoices because they include charges that we believe were not provided for in the PHA. We have accrued approximately $125,101 as of July 31, 2011 associated with this contingency.
On September 23, 2011, Strategic acquired SPE, the holder of 25% of GBE’s historical working interest in our offshore properties for a total purchase price of 95,000,000 shares of our common stock. The effective date of the purchase was September 1, 2011. Thus, effective September 1, 2011, we owned 100% of GBE’s original working interest in the offshore properties. In addition to working interest in GBE’s oil and gas properties, SPE owned 1,000,000 shares of Hyperdynamics Corporation, a public company traded on the New York Stock Exchange (NYSE:HDY). The preliminary allocation of the purchase price is as follows:
We are evaluating whether there are deferred tax effects of this purchase. Such tax effects may affect the final purchase price allocation. Subsequent to the purchase of SPE, we sold a portion of the Hyperdynamics shares that we acquired for proceeds of $4,000,000, approximately $40,000 of which we reinvested into common stock of another public company. This common stock is classified as available for sale.
In September 2011, we purchased a non-operated working interest in mineral leases covering 460 acres onshore in Duval County, Texas. Under the agreement, the operator will commence drilling a well on or before December 31, 2011. Our working interest in the lease area is 6.70732% to the casing point of the first well drilled and 5.5% after the casing point of the initial well and for subsequent operations in the lease area. Our net revenue interest in the prospect is 4.125%. As of November 15, 2011, we had paid $40,385 for the cash call on the initial well.
In September 2011, Core commenced drilling of three wells in the Markham City, Illinois project area. Two wells were completed in October 2011, one of which is producing oil and the other of which is shut in pending further evaluation. The third well will be used as a water supply well. As of October 1, 2011, Core had expended approximately $600,000 towards the Earnings Threshold. In accordance with our farmout agreement, we will be required to contribute our 10% working interest share toward operations in the area after the Earnings Threshold, $1,350,000, has been met.
Note 16 - Supplemental Oil and Gas Information (Unaudited)
The following supplemental information regarding our oil and gas activities is presented pursuant to the disclosure requirements promulgated by the SEC and ASC 932, Extractive Activities -Oil and Gas, (ASC 932).
Users of this information should be aware that the process of estimating quantities of “proved” and “proved developed” oil and natural gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various reservoirs make these estimates generally less precise than other estimates included in the financial statement disclosures.
Proved reserves represent estimated quantities of natural gas, crude oil and condensate that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions in effect when the estimates were made. Proved developed reserves are proved reserves expected to be recovered through wells and equipment in place and under operating methods used when the estimates were made. In the following table, natural gas liquids are included in natural gas reserves. The oil and natural gas liquids price as of July 31, 2011 and 2010 is based on the 12-month un-weighted average of the first of the month prices of the NYMEX (Cushing, OK WTI) posted price which equates to $90.41 and $76.51 per barrel, respectively. The gas price as of July 31, 2011 and 2010 is based on the 12-month un-weighted average of the first of the month prices of the NYMEX (Cushing, OK WTI) spot price which equates to $4.19 and $4.51 per MMbtu, respectively. The base prices were adjusted for heating content, premiums and product differentials based on historical revenue statements. All prices are held constant in accordance with SEC guidelines. All proved reserves are located in the United States; specifically, in on-shore and off-shore Texas and on-shore Louisiana.
The following table illustrates our estimated net proved reserves, including changes, and proved developed reserves for the periods indicated, as estimated by third party reservoir engineers. Our proved reserves are located in the United States of America, our home country.
Proved Reserves
The SEC amended its definitions of oil and natural gas reserves effective December 31, 2009. Previous periods were not restated for the new rules. Key revisions include a change in pricing used to prepare reserve estimates to a 12-month un-weighted average of the first-day-of-the-month prices, the inclusion of non-traditional resources in reserves, definitional changes, and allowing the application of reliable technologies in determining proved reserves, and other new disclosures (Revised SEC rules). The Revised SEC rules did not affect the quantities of our proved reserves.
The reserves in this report have been estimated using deterministic methods. For wells classified as proved developed producing where sufficient production history existed, reserves were based on individual well performance evaluation and production decline curve extrapolation techniques. For undeveloped locations and wells that lacked sufficient production history, reserves were based on analogy to producing wells within the same area exhibiting similar geologic and reservoir characteristics, combined with volumetric methods. The volumetric estimates were based on geologic maps and rock and fluid properties derived from well logs, core data, pressure measurements, and fluid samples. Well spacing was determined from drainage patterns derived from a combination of performance-based recoveries and volumetric estimates for each area or field. Proved undeveloped locations were limited to areas of uniformly high quality reservoir properties, between existing commercial producers.
Capitalized Costs Related to Oil and Gas Activities
The following table illustrates the total amount of capitalized costs relating to oil and natural gas producing activities and the total amount of related accumulated depreciation, depletion and amortization. All oil and gas properties are located in the United States of America.
Costs Incurred in Oil and Gas Activities
All costs incurred associated with oil and gas activities were incurred in the United States of America. Costs incurred in property acquisition, exploration and development activities were as follows.
Costs Excluded
At July 31, 2011 we had no excluded costs.
Changes in Costs Excluded by Country
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves
The following Standardized Measure of Discounted Future Net Cash Flow information has been developed utilizing ASC 932, Extractive Activities -Oil and Gas, (ASC 932) procedures and based on estimated oil and natural gas reserve and production volumes. It can be used for some comparisons, but should not be the only method used to evaluate us or our performance. Further, the information in the following table may not represent realistic assessments of future cash flows, nor should the Standardized Measure of Discounted Future Net Cash Flow be viewed as representative of our current value.
We believe that the following factors should be taken into account when reviewing the following information:
●
future costs and selling prices will probably differ from those required to be used in these calculations;
●
due to future market conditions and governmental regulations, actual rates of production in future years may vary significantly from the rate of production assumed in the calculations;
●
a 10% discount rate may not be reasonable as a measure of the relative risk inherent in realizing future net oil and natural gas revenues; and
●
future net revenues may be subject to different rates of income taxation.
Under the Standardized Measure, the future cash inflows were estimated by applying the un-weighted 12-month average of the first day of the month cash price quotes, except for volumes subject to fixed price contracts, to the estimated future production of year-end proved reserves. Estimates of future income taxes are computed using current statutory income tax rates including consideration for estimated future statutory depletion and tax credits. The resulting net cash flows are reduced to present value amounts by applying a 10% discount factor.
The Standardized Measure is as follows:
Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves
The following is a summary of the changes in the Standardized Measure of discounted future net cash flows for our proved oil and natural gas reserves during each of the years in the two year period ended July 31, 2011:
The following schedule includes only the revenues from the production and sale of gas, oil, condensate and NGLs. The income tax expense is calculated by applying the current statutory tax rates to the revenues after deducting costs, which include DD&A allowances, after giving effect to permanent differences. The results of operations exclude general office overhead and interest expense attributable to oil and gas activities.
Results of Operations for Producing Activities
ITEM 9.
ITEM 9.
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
As we previously reported in our Current Report on Form 8-K filed with the Securities and Exchange Commission on September 29, 2010, during the fiscal year ended July 31, 2011, we changed our certifying accountants.
ITEM 9A.
ITEM 9A.
CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
Our management, with the participation of our Principal Executive Officer and Principal Financial Officer, has evaluated the effectiveness of our disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report. Based on such evaluation, our Principal Executive Officer and Principal Financial Officer have concluded that, as of the end of the period covered by this report, our disclosure controls and procedures were not effective, due to the deficiencies in our internal control over financial reporting as described below.
Management’s Report on Internal Control over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting.
As of July 31, 2011, we assessed the effectiveness of our internal control over financial reporting based on the criteria for effective internal control over financial reporting established in Internal Control -Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) and SEC guidance on conducting such assessments. Based on that evaluation, we concluded that, as at July 31, 2011, our internal controls and procedures were not effective to detect the inappropriate application of US GAAP rules as more fully described below. This was due to deficiencies that existed at the time in which the internal control procedures were implemented that adversely affected our internal controls and that may be considered to be a material weakness.
The matters involving internal controls and procedures that our management considered to be material weaknesses under the standards of the Public Company Accounting Oversight Board were: (1) inadequate entity level controls due to: (i) weak tone at the top to implement an effective control environment, and (ii) ineffective audit committee due to a lack of a majority of independent members (1 of 3) on the current audit committee and a lack of a majority of outside directors on our board of directors; (2) inadequate segregation of duties consistent with control objectives; and (3) insufficient written policies and procedures for accounting and financial reporting with respect to the requirements and application of US GAAP and SEC disclosure requirements.
Management believes that the material weaknesses set forth in items (2) and (3) above did not have a material adverse effect on our financial results for the year ended July 31, 2011. However, we believe that the material weaknesses in entity level controls set forth in item (1) results in ineffective oversight in the establishment and monitoring of required internal controls and procedures, which could result in a material misstatement in our financial statements in future periods.
We are committed to improving our financial organization. As part of this commitment, when resources become available to us we will i) expand our personnel to improve segregation of duties consistent with control objectives, ii) appoint one or more outside directors to our board of directors who shall be appointed to our audit committee resulting in a fully functioning audit committee who will undertake the oversight in the establishment and monitoring of required internal controls and procedures such as reviewing and approving estimates and assumptions made by management; and iii) prepare and implement sufficient written policies and checklists which will set forth procedures for accounting and financial reporting with respect to the requirements and application of US GAAP and SEC disclosure requirements.
We will continue to monitor and evaluate the effectiveness of our internal controls and procedures over financial reporting on an ongoing basis and are committed to taking further action by implementing additional enhancements or improvements, or deploying additional human resources as may be deemed necessary.
Changes in Internal Control over Financial Reporting
There have been no changes in our internal control over financial reporting during our fourth quarter of our fiscal year ended July 31, 2011 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
ITEM 9B.
ITEM 9B.
OTHER INFORMATION
Not applicable.
ITEM 10.
ITEM 10.
DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Officers and Directors
Our directors and executive officers and their respective ages as of the date of this annual report are as follows:
The following describes the business experience of each of our directors and executive officers, including other directorships held in reporting companies:
Jeremy Glenn Driver, President, Chief Executive Officer, Chairman and a director
Mr. Driver has been Chief Executive Officer since December 2009 and a director of the Company since June 2010. He served as President of the Company from December 2009 until February 15, 2011, and once again became President on April 1, 2011. He is an oil and gas operations and financial professional with a background in land-based E&P operations with public companies. Prior to joining the Company, Mr. Driver served as President of HYD Resources Corporation (a wholly-owned subsidiary of publicly traded firm Hyperdynamics Corporation) with operations primarily focused in Texas and Louisiana from 2005 to 2008. He was able to lead the operational turnaround of that company and bring it to profitability, later being divested at a profit. Mr. Driver has also served as the President of KD Navigation, an investment and holding company in Texas since 2007. Mr. Driver also served as an active duty officer in the United States Air Force until 2005, specializing in foreign intelligence as a Chinese Linguist. Mr. Driver holds a Masters of Business Administration and a Master of Science in Accounting from Northeastern University, Boston, MA. He also earned his Bachelor of Science in Liberal Studies - Chinese Language from Excelsior College.
Sarah Berel-Harrop, Secretary, Treasurer and Chief Financial Officer
Ms. Berel-Harrop has been our Secretary, Treasurer and Chief Financial Officer since May 25, 2011. Ms. Berel-Harrop has 14 years of experience in financial accounting and reporting in both audit and industry positions. She received a B.A. degree from Cornell University and a Master in Business Administration from University of Texas - Austin. From 2006 to 2009, Ms. Berel-Harrop worked with Hyperdynamics Corporation. She was responsible for the company's financial accounting and reporting, and, from June 2008 through June 2009, served as the company's Chief Financial Officer. From July 2009 through March 2011, Ms. Berel-Harrop operated an accounting firm as a sole practitioner. From March 1, 2011 through the present, she has been Strategic American Oil Corporation's Controller. Ms. Berel-Harrop is a Certified Public Accountant licensed in the state of Texas. She is a member of the AICPA and the Texas State Board of Public Accountancy, Houston Chapter.
Leonard G. Garcia
Mr. Garcia has been a director since April 17, 2006 and has served as our Land Manager from February 2006 to the present date. In addition, Mr. Garcia served as our President and Chief Executive Officer from April 17, 2006 until August 5, 2007. From August 2004 to the present date, Mr. Garcia has also served as the Land Manager for Uranium Energy Corp., a uranium exploration company that has been publicly traded on the American Stock Exchange since September 2007. Mr. Garcia is an Independent Petroleum Landman with over thirty years experience in oil and gas title research, lease negotiations and acquisitions, contracts, exploration and production. Prior to August 2004, Mr. Garcia worked under contract for various companies, including Harkins & Co., Sun Oil Company, Oryx Energy Co., Texaco, Monsanto Exploration and Production Company, Trans Texas Energy, Kerr-McGee Oil & Gas Corp., and Mestena Oil & Gas. His corporate experience includes serving as Chief Executive Officer of Texas corporations with annual sales in excess of eighteen million dollars. Mr. Garcia attended the University of Texas-Austin, The University of Texas-Pan American and Texas A&M University-Kingsville. He currently resides in Austin, Texas.
Steven L. Carter, Vice President of Operations
Mr. Carter has served as our Vice President of Operations since December 20, 2006 and as a director since July 2010. Mr. Carter is a registered professional engineer with thirty years of management and engineering experience in oil and gas exploration, production operations, reservoir management and drilling. Mr. Carter served as Operations Manager and Operations Engineer for T-C Oil Company from 1990 to June 2003, where he managed significant production, supervised drilling, provided economic evaluations and designed project workovers, as well as performing numerous other engineering services. In July 2003, Mr. Carter started Carter E&P, LLC, an independent oil and gas company, where he has worked from 2003 to the present. Mr. Carter has a B.S. in Petroleum Engineering from the University of Texas at Austin.
Term of Office
Our directors are appointed for a one-year term to hold office until the next annual general meeting of our stockholders or until they resign or are removed from the board in accordance with our bylaws. Our officers are appointed by our Board of Directors and hold office until they resign or are removed from office by the Board of Directors.
Significant Employees
We have no significant employees other than our executive officers.
Audit Committee
As a result of the resignation of Alan P. Lindsay and Randall Reneau as directors of the Company, who served as members of our audit committee, we currently do not have a separate audit committee; rather, our board of directors operates as our audit committee. In addition, our board of directors has determined that we do not currently have an audit committee financial expert (as such term is defined in Item 407 of Regulation S-K) serving on our board.
We have an audit committee charter that was adopted by our board of directors. As our Company ramps up operations, we would like to appoint additional directors to our board with a goal of, among other things, establishing a separately functioning audit committee that has at least one financial expert as a member.
Family Relationships
There are no family relationships among our directors and officers.
Involvement in Certain Legal Proceedings
Except as disclosed in this annual report, during the past ten years none of the following events have occurred with respect to any of our directors or executive officers:
1.
A petition under the Federal bankruptcy laws or any state insolvency law was filed by or against, or a receiver, fiscal agent or similar officer was appointed by a court for the business or property of such person, or any partnership in which he was a general partner at or within two years before the time of such filing, or any corporation or business association of which he was an executive officer at or within two years before the time of such filing;
2.
Such person was convicted in a criminal proceeding or is a named subject of a pending criminal proceeding (excluding traffic violations and other minor offenses);
3.
Such person was the subject of any order, judgment, or decree, not subsequently reversed, suspended or vacated, of any court of competent jurisdiction, permanently or temporarily enjoining him from, or otherwise limiting, the following activities:
i.
Acting as a futures commission merchant, introducing broker, commodity trading advisor, commodity pool operator, floor broker, leverage transaction merchant, any other person regulated by the Commodity Futures Trading Commission, or an associated person of any of the foregoing, or as an investment adviser, underwriter, broker or dealer in securities, or as an affiliated person, director or employee of any investment company, bank, savings and loan association or insurance company, or engaging in or continuing any conduct or practice in connection with such activity;
ii.
Engaging in any type of business practice; or
iii.
Engaging in any activity in connection with the purchase or sale of any security or commodity or in connection with any violation of Federal or State securities laws or Federal commodities laws;
4.
Such person was the subject of any order, judgment or decree, not subsequently reversed, suspended or vacated, of any Federal or State authority barring, suspending or otherwise limiting for more than 60 days the right of such person to engage in any activity described in paragraph (3)(i) above, or to be associated with persons engaged in any such activity;
5.
Such person was found by a court of competent jurisdiction in a civil action or by the Commission to have violated any Federal or State securities law, and the judgment in such civil action or finding by the Commission has not been subsequently reversed, suspended, or vacated;
6.
Such person was found by a court of competent jurisdiction in a civil action or by the Commodity Futures Trading Commission to have violated any Federal commodities law, and the judgment in such civil action or finding by the Commodity Futures Trading Commission has not been subsequently reversed, suspended or vacated;
7.
Such person was the subject of, or a party to, any Federal or State judicial or administrative order, judgment, decree, or finding, not subsequently reversed, suspended or vacated, relating to an alleged violation of:
i.
Any Federal or State securities or commodities law or regulation; or
ii.
Any law or regulation respecting financial institutions or insurance companies including, but not limited to, a temporary or permanent injunction, order of disgorgement or restitution, civil money penalty or temporary or permanent cease-and-desist order, or removal or prohibition order; or
iii.
Any law or regulation prohibiting mail or wire fraud or fraud in connection with any business entity; or
8.
Such person was the subject of, or a party to, any sanction or order, not subsequently reversed, suspended or vacated, of any self-regulatory organization (as defined in Section 3(a)(26) of the Exchange Act), any registered entity (as defined in Section 1(a)(29) of the Commodity Exchange Act), or any equivalent exchange, association, entity or organization that has disciplinary authority over its members or persons associated with a member.
There are currently no legal proceedings to which any of our directors or officers is a party adverse to us or in which any of our directors or officers has a material interest adverse to us.
Code of Conduct
We have adopted a Code of Conduct that applies to all directors and officers. The code describes the legal, ethical and regulatory standards that must be followed by the directors and officers of the Company and sets forth high standards of business conduct applicable to each director and officer. As adopted, the Code of Conduct sets forth written standards that are designed to deter wrongdoing and to promote, among other things:
1.
honest and ethical conduct, including the ethical handling of actual or apparent conflicts of interest between personal and professional relationships;
2.
compliance with applicable governmental laws, rules and regulations;
3.
the prompt internal reporting of violations of the code to the appropriate person or persons identified in the code; and
4.
accountability for adherence to the code.
A copy of our Code of Conduct is incorporated by reference to our Form 10-K for the fiscal year ended July 31, 2009.
Compliance with Section 16(a) of the Exchange Act
Section 16(a) of the Exchange Act requires our directors and officers, and the persons who beneficially own more than 10% of our common stock, to file reports of ownership and changes in ownership with the SEC. Copies of all filed reports are required to be furnished to us pursuant to Rule 16a-3 promulgated under the Exchange Act. Based solely on the reports received by us and on the representations of the reporting persons, we believe that these persons have complied with all applicable filing requirements during the year ended July 31, 2011, except as follows:
Section 16(a) of the Exchange Act requires our directors and officers, and the persons who beneficially own more than 10% of our common stock, to file reports of ownership and changes in ownership with the SEC. Copies of all filed reports are required to be furnished to us pursuant to Rule 16a-3 promulgated under the Exchange Act. Based solely on the reports received by us and on the representations of the reporting persons, we believe that these persons have complied with all applicable filing requirements during the year ended July 31, 2011, except as set forth below:
ITEM 11.
ITEM 11.
EXECUTIVE COMPENSATION
Compensation Discussion and Analysis
The following table sets forth the compensation paid to our executive officers during our fiscal years ended July 31, 2011 and 2010:
Summary Compensation
(1)
Randall Reneau resigned as our President and CEO in December 2009. Randall Reneau received varying amounts per month for the fiscal year ending July 31, 2010 for the provision of management consulting services provided by Mr. Reneau to us on a monthly basis and from time to time. In December 2009, Mr. Reneau received a stock bonus of 68,571 shares of common stock. The stock was valued at $0.40 per share, the market closing price on the date of grant.
(2)
Johnathan Lindsay resigned as our Secretary, Treasurer and CFO on May 25, 2011. Johnathan Lindsay received varying amounts per month for the fiscal years ending July 31, 2009 and 2010 for the provision of management consulting services provided by Mr. Lindsay to us on a monthly basis and from time to time. In December 2009, Mr. Lindsay received a stock bonus of 68,571 shares of common stock. The stock was valued at $0.40 per share, the market closing price on the date of grant. Additionally, during the year ended July 31, 2011, Strategic repriced outstanding options to purchase 900,000 shares of common stock from an exercise price of $.35 per share to $0.10 per share. We reflected $12,193, the difference between the fair value of the outstanding award and the fair value of the repriced award as of the date of modification as compensation during the year ended July 31, 2011. The fair values were determined using the Black-Sholes option pricing method.
(3)
During the year ended July 31, 2011, Mr. Carter was awarded options to purchase 12,500,000 shares of common stock, with a ten year term, and exercisable at $0.10 per share. 1/5 of the options vest each six months, beginning six months after the date of grant. As of July 31, 2011, none of these options had vested. Mr. Carter also received options to purchase 1,400,000 shares of common stock with a three year term, exercisable at $.35 per share. ¼ of the shares vest each month beginning with the date of grant. This option and options to purchase 600,000 shares at $.35 per share (total 2,000,000 shares) were repriced and the new exercise price was $0.10 per share. The aggregate fair value on the dates of grant of the options, computed using the Black-Sholes option pricing method, was $1,408,779. The difference between the fair value of the outstanding award and the fair value of the repriced award as of the date of modification was $33,339. During the year, options to purchase 700,000 shares vested and we recorded $251,018 as compensation expense associated with Mr. Carter’s awards.
(4)
During the year ended July 31, 2011, Strategic repriced outstanding options to purchase 2,500,000 shares of common stock from an exercise price of $.35 per share to $0.10 per share. We reflected $31,239, the difference between the fair value of the outstanding award and the fair value of the repriced award as of the date of modification as compensation during the year ended July 31, 2011. The fair values were determined using the Black-Sholes option pricing method. Additionally, we recognized $68,015 in expense during the year ended July 31, 2011 associated with options granted in November 2009. The aggregate grant date fair value of the options granted in November 2009, valued using the Black-Sholes option pricing method, was $770,020.
(5)
Sarah Berel-Harrop was appointed as our Secretary, Treasurer and CFO on May 25, 2011. During the year ended July 31, 2011, she received 204,000 shares of common stock valued using the market closing price on the dates of grant. Option awards include the aggregate grant date fair value of options to purchase 3,000,000 shares of common stock, with a ten year term, and exercisable at $0.10 per share. 1/5 of the options vest each six months, beginning six months after the date of grant. As of July 31, 2011, none of the options had vested and we had recognized $29,708 of expense associated with these options.
(6)
Amiel David served as President from February 15, 2011 until April 1, 2011. See Note 8 - Share Return and Settlement in our Consolidated Financial Statements for details of his compensation during the year.
See Note 10 - Capital Stock in our Consolidated Financial Statements for a discussion of the assumptions used in our option valuations.
The following table sets forth information as at July 31, 2011 relating to outstanding equity awards for each Named Executive Officer:
Outstanding Equity Awards at Year End
(1)
Warrants issued with settlement as described in Note 8 - Share Return and Settlement in our Consolidated Financial Statements.
Director Compensation
We do not have a standard director compensation arrangement. Compensation is negotiated with each director on a case by case basis. Mr. Carter and Mr. Driver receive compensation for management services provided to the Company and they do not receive separate compensation for their services as directors. The following table provides information regarding compensation during the year ended July 31, 2011 earned by directors who are not executive officers. Our directors who are executive officers do not receive additional compensation for their service as directors and their compensation is disclosed in the “Summary Compensation” Table above.
(1)
Leonard Garcia received varying amounts per month for the fiscal year ended July 31, 2011 for the provision of land work management consulting services provided by Mr. Garcia to us on a monthly basis and from time to time. Option awards include the aggregate grant date fair value of options to purchase 1,000,000 shares of common stock, with a ten year term, and exercisable at $0.10 per share. As of July 31, 2011, none of the options had vested and we had recognized $9,903 of expense associated with these options. We valued the options at $98,813 using the Black-Sholes option pricing method. Additionally, during the year, Strategic repriced outstanding options to purchase 900,000 shares of common stock from an exercise price of $.35 per share to $0.10 per share. We reflected $12,193, the difference between the fair value of the outstanding award and the fair value of the repriced award as of the date of modification as compensation during the year ended July 31, 2011. The fair value was determined using the Black-Sholes option pricing method.
(2)
Alan Lindsay resigned as a director on December 31, 2010. He received stock in February 2011 that, in part, settled fees that were earned and reported as “Fees Earned or Paid in Cash” during 2010. The full value of the stock award is shown in 2011 and the amount reported last year has been shown as a reduction of compensation in order not to double count this compensation.
(3)
Randall Reneau resigned as a director on February 28, 2011. During the year, Strategic repriced outstanding options to purchase 900,000 shares of common stock from an exercise price of $.35 per share to $0.10 per share. We reflected $12,193, the difference between the fair value of the outstanding award and the fair value of the repriced award as of the date of modification as compensation during the year ended July 31, 2011. The fair values were determined using the Black-Sholes option pricing method.
(4)
Alan D. Gaines served as a director from February 15, 2011 until April 1, 2011. See Note 8 - Share Return and Settlement in our Consolidated Financial Statements for details of his compensation during the year.
See Note 10 - Capital Stock in our Consolidated Financial Statements for a discussion of the assumptions used in our option valuations.
Employment, Consulting and Services Agreements
The following summary of certain material terms of the employment, consulting or services agreements we have entered into with certain of our officers or employees is not complete and is qualified in its entirety to the full text of each such agreement, which have been filed with the SEC as described in the list of exhibits to this annual report.
Carter Professional Services Agreement
On December 20, 2006, our Board of Directors authorized and approved the execution of the “Carter Professional Services Agreement”. The term of the agreement is two years expiring on November 30, 2008. Pursuant to the terms and provisions of the Carter Professional Services Agreement: (i) Steven Carter shall provide duties to us commensurate with his current executive position as our Vice President of Operations; (ii) we shall pay to Mr. Carter a monthly fee of $10,000; (iii) we approved the issuance of 500,000 shares of our common stock at a price of $0.001 per share; (iv) we approved the granting of an aggregate of not less than 600,000 options to purchase shares of our common stock at $0.35 for a ten year term; and (v) the Carter Professional Services Agreement may be terminated without cause by either of us by providing prior written notice of the intention to terminate at least 90 days (in the case of our Company after the initial term) or 30 days (in the case of Mr. Carter) prior to the effective date of such termination. In June 2011, the Company determined to increase Mr. Carter’s monthly fee under this agreement to $14,583.33 per month.
Jeremy G. Driver Agreement
Effective December 1, 2009, we entered into an executive services agreement with Mr. Driver, pursuant to which he is to perform such duties and responsibilities as set out in the agreement and as our Board of Directors may from time to time reasonably determine and assign as is customarily performed by a person in an executive position with our Company. In consideration for his services under the agreement, we have agreed:
●
to pay Mr. Driver a monthly fee of $8,333.33;
●
to pay Mr. Driver a one-time signing bonus of $20,000;
●
to provide Mr. Driver with industry standard bonuses, from time to time, based, in part, on the performance of the Company and the achievement by Mr. Driver of reasonable management objectives, as determined by the Company’s Board of Directors in good faith;
●
to provide Mr. Driver with three weeks paid vacation;
●
to provide Mr. Driver with a monthly benefits stipend of $450 together with full participation, at the Company’s expense, in the Company’s current medical services and life insurance benefits programs for management and employees; and
●
to grant Mr. Driver incentive stock options to purchase not less than an aggregate of 2,500,000 common shares of the Company, at an exercise price $0.20 per optioned common share, vesting as to one-quarter of said stock options on the date of grant (that being as to 625,000) and on each day which is six months thereafter in succession for each remaining one-quarter of the optioned common shares, and all being exercisable for a period of three years from the date of grant and in accordance with the provisions of the Company’s current Stock Incentive Plan.
The initial term of the agreement is one year ending on December 1, 2010, and the agreement is subject to automatic renewal on a monthly basis unless either the Company or Mr. Driver provides written notice of an intention not to renew the agreement not later than 30 days prior to the end of the then-current initial term or renewal of the agreement. In June 2011, the Company determined to increase Mr. Driver’s monthly fee under this agreement to $14,583.33 per month.
ITEM 12.
ITEM 12.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
The following table sets forth certain information concerning the number of shares of our common stock owned beneficially as of November 14, 2011 by: (i) each person (including any group) known to us to own more than 5% of our shares of common stock; (ii) each of our directors; (iii) each of our officers; and (iv) our officers and directors as a group. To our knowledge, each holder listed possesses sole voting and investment power with respect to the shares shown.
(1)
Under Rule 13d-3 of the Exchange Act a beneficial owner of a security includes any person who, directly or indirectly, through any contract, arrangement, understanding, relationship, or otherwise has or shares: (i) voting power, which includes the power to vote, or to direct the voting of shares; and/or (ii) investment power, which includes the power to dispose or direct the disposition of shares. In addition, shares are deemed to be beneficially owned by a person if the person has the right to acquire the shares within 60 days of the date as of which the information is provided.
(2)
Based on the 269,417,069 shares of our common stock issued and outstanding as of November 14, 2011.
(3)
This figure includes (i) 49,216,667 shares of common stock held by KD Navigation Inc. and (ii) vested stock options to purchase 2,500,000 shares of our common stock.
(4)
This figure includes (i) 585,713 shares of common stock and (ii) vested stock options to purchase 4,150,000 shares of our common stock.
(5)
This figure includes (i) 1,096,254 shares of common stock, (ii) vested stock options to purchase ,900,000 shares of our common stock, and (iii) stock purchase warrants to purchase 49,825 shares of our common stock.
(6)
This figure includes (i) 219,000 shares of common stock and (ii) vested stock options to purchase 600,000 shares of our common stock.
(7)
This figure includes (i) 51,117,634 shares of common stock, (ii) vested stock options to purchase 8,350,000 shares of our common stock, and (iii) stock purchase warrants to purchase 49,825 shares of our common stock.
Changes in Control
We are unaware of any contract, or other arrangement or provision, the operation of which may at a subsequent date result in a change of control of our company.
ITEM 13.
ITEM 13.
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE
Except as described below, none of the following parties has had any material interest, direct or indirect, in any transaction with us during our last two fiscal years or in any presently proposed transaction that has or will materially affect us:
1.
any of our directors or officers;
2.
any person proposed as a nominee for election as a director;
3.
any person who beneficially owns, directly or indirectly, shares carrying more than 5% of the voting rights attached to our outstanding shares of common stock; or
4.
any member of the immediate family (including spouse, parents, children, siblings and in-laws) of any of the above persons.
We had transactions with certain of our officers and directors during our two fiscal years ended July 31, 2010 as follows:
Geoserve Marketing LLC
On February 15, 2011, we entered into a Consulting Agreement with Geoserve Marketing, LLC, a company controlled by Michael Watts, who is the father-in-law of Jeremy Driver, a Director and our Chief Executive Officer. Effective March 17, 2011, this agreement was amended. The Consulting Agreement, as amended, provides that Geoserve is to provide consulting services to the Company as an independent contractor for a term of three years. The Agreement provides that the Company will compensate Geoserve with warrants according to the following schedule: (i) upon signing, Geoserve shall be issued five-year term warrants to purchase 20,000,000 restricted shares of common stock at an exercise price of $0.10 per share (previously granted and vested as of the execution of the original agreement on February 15, 2011). If the Company's stock price reaches a five-day average closing price of $0.30 per share, the Company shall grant Geoserve an additional 15,000,000 share purchase warrants at an exercise price of $0.10 per share and a five-year term. If the Company's stock price reaches a five-day average closing price of $0.60 per share, the Company shall grant Geoserve a further 15,000,000 share purchase warrants at an exercise price of $0.10 per share and a five-year term. The Company may terminate the agreement after the first year with thirty days notice.
Galveston Bay
Immediately following our acquisition of Galveston Bay Energy, LLC, on February 15, 2011, we sold 15% of our own aggregate working interest in the Galveston Bay fields for $1,400,000 in cash to SPE Navigation 1, LLC (“SPE”), a company controlled by Michael Watts, who is the father-in-law of Jeremy Driver, a Director and our Chief Executive Officer. SPE had the right to acquire an additional 10% of our own aggregate working interest in the Galveston Bay fields within 90 days for $1,150,000.
Effective on September 26, 2011, we closed on our acquisition of SPE from CW Navigation, Inc., KD Navigation, Inc. and KW Navigation, Inc., each a Texas corporation (collectively, the "Sellers"). The material assets of SPE consist of certain oil and gas working interests in and to four producing oil and gas fields located in Galveston Bay, Texas, together with one million shares of Hyperdynamics Corporation (NYSE: HDY). Pursuant to the terms of the Company's Purchase and Sale Agreement with the Sellers and SPE regarding this matter, the Company acquired the Sellers' 100% interest in SPE for total consideration consisting of 95,000,000 restricted common shares of the Company issued at a deemed issuance price of $0.10 per share. CW Navigation, Inc. is owned 100% by the brother-in-law of Jeremy Driver, the Company's Chief Executive Officer and a director. KD Navigation, Inc. is owned 100% by Mr. Driver's wife. KW Navigation, Inc. is owned 100% by Mr. Driver's sister-in-law.
Barge Canal Properties
A company controlled by one of our officers operates our Barge Canal properties. Revenues generated from these properties were $458,959 and $295,574 for the years ended July 31, 2011 and 2010, respectively. In addition, lease operating costs incurred from these properties were $176,096 and $229,067 for the years ended July 31, 2011 and 2010, respectively.
As of July 31, 2011 and 2010, respectively, we had outstanding accounts receivable associated with these properties of $69,880 and $28,975 and no accounts payable.
Director Loan
In November and December 2010, one of our former directors, Randall Reneau, loaned us $185,000. The interest rate on the notes was 6% and the principal was due as follows: $10,000 on demand and $175,000 in December 2011. We issued stock in payment of the $10,000 note payable in February 2011. We repaid the remaining note payable balance in November 2011.
Independent Directors
Leonard Garcia is an independent director of our Company as provided in the listing standards of the NYSE Amex Equities Exchange.
ITEM 14.
ITEM 14.
PRINCIPAL ACCOUNTING FEES AND SERVICES
Our current independent auditor, Malone & Bailey, P.C., served as our independent registered public accounting firm and audited our financial statements for the fiscal year ended July 31, 2011 and 2010. Aggregate fees for professional services rendered to us by our auditor are set forth below:
Audit Fees
Audit fees are the aggregate fees billed for professional services rendered by our independent auditors for the audit of our annual financial statements, the review of the financial statements included in each of our quarterly reports and services provided in connection with statutory and regulatory filings or engagements.
Audit Related Fees
Audit related fees are the aggregate fees billed by our independent auditors for assurance and related services that are reasonably related to the performance of the audit or review of our financial statements and are not described in the preceding category.
Tax Fees
Tax fees are billed by our independent auditors for tax compliance, tax advice and tax planning.
All Other Fees
All other fees include fees billed by our independent auditors for products or services other than as described in the immediately preceding three categories.
Policy on Pre-Approval of Services Performed by Independent Auditors
It is our audit committee’s policy to pre-approve all audit and permissible non-audit services performed by the independent auditors. We approved all services that our independent accountants provided to us in the past two fiscal years.
ITEM 15.
ITEM 15.
EXHIBITS
The following exhibits are filed with this Annual Report on Form 10-K:
*
Filed herewith.
(1)
Filed as an exhibit to our registration statement on Form S-1/A (Amendment No.1) filed with the Securities and Exchange Commission on February 8, 2008.
(2)
Filed as an exhibit to our Current Report on Form 8-K filed with the Securities and Exchange Commission on October 16, 2009.
(3)
Filed as an exhibit to our Current Report on Form 8-K filed with the Securities and Exchange Commission on November 16, 2009.
(4)
Filed as an exhibit to our Annual Report on Form 10-K filed with the Securities and Exchange Commission on November 12, 2009.
(5)
Filed as an exhibit to our Current Report on Form 8-K filed with the Securities and Exchange Commission on December 3, 2009.
(6)
Filed as an exhibit to our Current Report on Form 8-K filed with the Securities and Exchange Commission on October 20, 2010.
(7)
Filed as an exhibit to our Current Report on Form 8-K filed with the Securities and Exchange Commission on February 22, 2011.
(8)
Filed as an exhibit to our Current Report on Form 8-K filed with the Securities and Exchange Commission on September 22, 2011.
SIGNATURES
Pursuant to the requirements of Section 13 and 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.
STRATEGIC AMERICAN OIL CORPORATION
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 and on the dates indicated.