Item 1. Business
Overview
West Texas Resources, Inc. (the “company” or “we”) was incorporated under the laws of Nevada on December 9, 2010. We are engaged in the business of oil and gas exploration and development in North America. From inception to date, our activities have focused on the raising of capital and the investigation and acquisition of our initial oil and gas properties. We commenced revenue producing oil and gas operations effective as of April 1, 2013.
Our Strategy
Our objective is to become an independent energy company engaged in the acquisition, development and exploitation of oil and gas properties in North America in partnership with oil and gas producers. We will pursue strategic acquisitions of interests in oil and gas properties, including prospects with proven and unproven reserves, which we believe to have development potential. We intend to target both new and existing fields and producing wells to be revitalized.
At the present time, we have two employees, our chief executive officer and chief financial officer, Stephen Jones and John Kerr, respectively, each of whom has limited experience in the oil and gas exploration and development business. Subject to our receipt of significant additional capital, we intend to hire senior management and staff with experience in oil and gas exploration and development. Until such time, we intend to pursue an operating strategy that is based on our participation in exploration prospects as a non-operator. Based on that strategy, we intend to pursue the acquisition of oil and natural gas interests in partnership with other companies with exploration, development and production expertise. We will also pursue alliances with partners in the areas of geological and geophysical services and prospect generation, evaluation and prospect leasing. Pursuant to this strategy, we intend to engage and rely on third party geologists and geophysicists, among others, to review the available data concerning each potential acquisition on our behalf. In each case, we expect that the operator of the prospect will assemble the appropriate data and conduct the appropriate studies and that our consultants will conduct an independent review of the operator’s data and studies for purposes of advising us of the merits of each potential acquisition.
Oil and Gas Interests
September 2011, we acquired our initial property consisting of a 31.25% working interest in an exploratory oil and gas drilling prospect covering 120 acres in Eastland County, Texas. The Eastland County prospect includes two exploratory wells, known as Rutherford #1 and C.M. Knott #1, that had been operating at a minimum In level required to maintain the lease rights. In October 2011, the operator reentered the Rutherford #1 well and conducted drilling and casing activities, which were completed in November 2011. In January 2012, a third party conducted the fracture stimulation of the Rutherford #1. In February 2013, the operator placed a pump jack on the Rutherford #1 well, however no meaningful revenue has been derived from the well to date. During the three months ended June 30, 2013, we determined that our investment in the Eastland County prospect was impaired due to an unsuccessful fracture stimulation of the Rutherford #1. Accordingly, we recorded an impairment loss of $108,373 to write off the capitalized fracture stimulation costs. The operator has undertaken no further activity on the Eastland County prospect as of the date of this report.
In August 2013, we acquired a 7.24625% working interest (5.65158% net revenue interest) in the oil and gas leases, wells and attendant production in the Port Hudson field, Baton Rouge Parish, Louisiana, from Wells Fargo Energy Capital, Inc. for total consideration of $702,900. Our acquisition of the Port Hudson working interest was effective as of April 1, 2013. Accordingly, we have received revenue from the Port Hudson working interest commencing on April 1, 2013. The Port Hudson field has three producing wells that have produced a total of 1.1 million bbls to date with estimated total remaining recoverable proved developed producing reserves of 294,000 bbls, and 229,000 bbls of proven developed behind pipe reserves and are currently producing approximately 290 bbls per day. The operator of the Port Hudson field has no current plans for the further development of the field.
In September 2013, we acquired a 10.0167% working interest (7.2120% net revenue interest) in an offshore oil and gas field, known as West Cam 225, located in the shallow waters of the Gulf of Mexico near Cameron, Louisiana, from Enovation Resources, LLC for total consideration of $50,000. Concurrent with our purchase of the working interest, we also paid the operator $230,459 as our allocable share of the expenses associated with the West Cam 225 property. As of September 30, 2013, the West Cameron 225 field has proven reserves of 10.7 bcf of gas and 16.3 mbc or 1.8 million net equivalent bbls (130,000 net equivalent bbls net to West Texas Resources) and has two producing wells, the #7 and the D-1, that were previously shut-in and waiting on a sales pipeline connection. The pipeline was recently completed and tested and now the two wells are expected to come online at a combined rate of 2 mmcfd (200 mcfd net to the West Texas Resources). The operator presently intends to perform a dual recompletion on the D-1 well in the first half of 2014, at which time the two wells are expected to produce 7.5 mmcfd (750 mcfd net to West Texas Resources).
In addition to our participation in any continued development of the West Cam 225 property, and subject to our receipt of additional capital, we intend to pursue the acquisition of additional equity interests in other oil and gas properties in North America. However, as of the date of this report, we have no understandings or agreements in place concerning our acquisition of an interest in any other properties.
Marketing and Pricing
We derive revenue principally from the sale of oil and natural gas. As a result, our revenues are determined, to a large degree, by prevailing prices for crude oil and natural gas. Our operating partners sell our oil and natural gas on the open market at prevailing market prices. The market price for oil and natural gas is dictated by supply and demand, and we cannot accurately predict or control the price we may receive for our oil and natural gas.
Price decreases would adversely affect our revenues, profits and the value of our proved reserves. Historically, the prices received for oil and natural gas have fluctuated widely. Among the factors that can cause these fluctuations are:
·The domestic and foreign supply of natural gas and oil
·Overall economic conditions
·The level of consumer product demand
·Weather conditions
·The price and availability of competitive fuels such as heating oil and coal
·Political conditions in the Middle East and other natural gas and oil producing regions
·The level of oil and natural gas imports
·Domestic and foreign governmental regulations
·Potential price controls
We may enter into hedging arrangements to reduce our exposure to decreases in the prices of oil and natural gas. Hedging arrangements may expose us to risk of significant financial loss in some circumstances including circumstances where:
·There is a change in the expected differential between the underlying price in the hedging agreement and actual prices received
·Our production and/or sales of natural gas are less than expected
·Payments owed under derivative hedging contracts typically come due prior to receipt of the hedged month’s production revenue
·The other party to the hedging contract defaults on its contract obligations
In addition, hedging arrangements limit the benefit we would receive from increases in the prices for oil and natural gas. We cannot assure you that any hedging transactions we may enter into will adequately protect us from declines in the prices of oil and natural gas. On the other hand, we may choose not to engage in hedging transactions in the future. As a result, we may be more adversely affected by changes in oil and natural gas prices than our competitors who engage in hedging transactions.
Competition
The oil and gas industry is highly competitive and inherent difficulties exist for any new company seeking to enter an established field. Our proposed business will encounter numerous companies more experienced, better financed, and operationally organized to conduct acquisitions, development and exploration activities in the oil and gas industry in North America. Additionally, a small “start-up” such as us, with insignificant resources, is at a serious disadvantage against established competitors, including major oil companies.
Government Regulations
The following is a summary of the more significant existing environmental, health and safety laws and regulations applicable to the oil and natural gas industry and for which compliance may have a material adverse impact on the development or success of our proposed oil and gas operations.
Federal Income Tax. Federal income tax laws will significantly affect our operations. The principal provisions that will affect us are those that permit us, subject to certain limitations, to deduct as incurred, rather than to capitalize and amortize, our share of the domestic “intangible drilling and development costs” and to claim depletion on a portion of our domestic oil and natural gas properties based on 15% of our oil and natural gas gross income from such properties (up to an aggregate of 1,000 bbls per day of domestic crude oil and/or equivalent units of domestic natural gas).
Environmental Regulation. The exploration, development and production of oil and natural gas are subject to federal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may, among other things, require permits to conduct drilling, water withdrawal and waste disposal operations; govern the amounts and types of substances that may be disposed or released into the environment; limit or prohibit construction or drilling activities in sensitive areas such as wetlands, wilderness areas or areas inhabited by endangered or threatened species; require investigatory and remedial actions to mitigate pollution conditions arising from oil and gas operations or attributable to former operations; and impose obligations to reclaim and abandon well sites and pits. Failure to comply with these laws and regulations may result in the assessment of sanctions, including monetary penalties, the imposition of remedial obligations and the issuance of orders enjoining operations in affected areas.
The clear trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, and thus, any changes in environmental laws and regulations or re-interpretation of enforcement policies that result in more stringent and costly construction, drilling, water management, completion, waste handling, storage, transport, disposal, or remediation requirements or emission or discharge limits could have a material adverse effect on the development or success of our proposed oil and gas operations. Moreover, accidental releases or spills may occur in the course of our proposed oil and gas operations, and there can be no assurance that we will not incur significant costs and liabilities as a result of such releases or spills, including any third party claims for damage to property and natural resources or personal injury.
Hazardous Substances and Wastes. The Comprehensive Environmental Response, Compensation and Liability Act, as amended ("CERCLA"), also known as the Superfund law and comparable state laws impose joint and several liability, without regard to fault or legality of conduct, on certain classes of persons who are considered to be responsible for the release of a "hazardous substance" into the environment. These persons include current and prior owners or operators of the site where the release occurred and entities that disposed or arranged for the disposal of the hazardous substances found at the site. Under CERCLA, these "responsible persons" may be subject to strict joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain environmental and health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances into the environment. CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. We may generate materials in the course of our proposed operations that may be regulated as hazardous substances.
We may also generate wastes that are subject to the requirements of the Resource Conservation and Recovery Act, as amended ("RCRA"), and comparable state statutes. RCRA imposes strict requirements on the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. Drilling fluids, produced waters and most of the other wastes associated with the exploration, production and development of crude oil and natural gas are currently exempt from regulation as hazardous wastes under RCRA. However, it is possible that certain oil and natural gas exploration and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. In September 2010, the Natural Resources Defense Council filed a petition with the EPA requesting them to reconsider the RCRA exemption for exploration, production, and development wastes. To date, the EPA has not taken any action on the petition. Any change in the RCRA exemption for such wastes could result in an increase in costs to manage and dispose of wastes, which could have a material adverse effect on the development or success of our proposed oil and gas operations.
Air Emissions. The Clean Air Act, as amended, and comparable state laws and regulations restrict the emission of air pollutants from many sources and also impose various monitoring and reporting requirements. These laws and regulations may require our operating partners to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with air permit requirements or utilize specific equipment or technologies to control emissions. Obtaining permits has the potential to delay the development of oil and natural gas projects.
Water Discharges. The Federal Water Pollution Control Act, as amended ("Clean Water Act"), and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants into navigable waters. Pursuant to the Clean Water Act and analogous state laws, permits must be obtained to discharge produced waters and sand, drilling fluids, drill cuttings and other substances related to the oil and gas industry into onshore, coastal and offshore waters of the United States or state waters. Any such discharge of pollutants into regulated waters must be performed in accordance with the terms of the permit issued by EPA or the analogous state agency. Spill prevention, control and countermeasure requirements under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. In addition, the Clean Water Act and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities.
Climate Change. In December 2009, the EPA published its findings that emissions of carbon dioxide, methane and certain other GHGs present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth's atmosphere and other climatic changes. These findings allow the EPA to adopt and implement regulations that restrict emissions of GHGs under existing provisions of the federal Clean Air Act. Accordingly, the EPA has adopted regulations that require a reduction in emissions of GHGs from motor vehicles and also trigger permit review for GHG emissions from certain large stationary sources. The EPA's rules relating to emissions of GHGs from large stationary sources of emissions are currently subject to a number of legal challenges, but the federal courts have thus far declined to issue any injunctions to prevent the EPA from implementing, or requiring state environmental agencies to implement, the rules. In addition, Congress has actively considered legislation to reduce emissions of GHGs and almost one-half of the states have begun taking actions to control and/or reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. The adoption and implementation of any regulations imposing reporting obligations on, or limiting emissions of GHG gases from, our equipment and operations could require our operators to incur costs to reduce emissions of GHGs associated with our proposed operations or could adversely affect demand for the oil and natural gas we produce.
Endangered Species. The federal Endangered Species Act ("ESA") restricts activities that may affect endangered or threatened species or their habitats. The designation of previously unidentified species as endangered or threatened on properties where we operate could subject us to additional costs or cause our oil and gas activities to be subject to operating restrictions or bans.
Employee Health and Safety. Our proposed operations are subject to a number of federal and state laws and regulations, including the federal Occupational Safety and Health Act, as amended ("OSHA"), and comparable state statutes, whose purpose is to protect the health and safety of workers. In addition, the OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information be maintained concerning hazardous materials used or produced in oil and gas operations and that this information be provided to employees, state and local government authorities and citizens.
State Regulation. Texas regulates the drilling for, and the production and gathering of, oil, natural gas and natural gas liquids, including requirements relating to drilling permits, the location, spacing and density of wells, unitization and pooling of interests, the method of drilling, casing and equipping of wells, the protection of fresh water sources, the orderly development of common sources of supply of oil, natural gas and natural gas liquids, the operation of wells, allowable rates of production, the use of fresh water in oil, natural gas and natural gas liquids operations, saltwater injection and disposal operations, the plugging and abandonment of wells and the restoration of surface properties, the prevention of waste of oil, natural gas and natural gas liquids resources, the protection of the correlative rights of oil, natural gas and natural gas liquids owners and, where necessary to avoid unfair, unjust or discriminatory service, the fees, terms and conditions for the gathering of natural gas. The effect of these regulations may be to limit the number of wells that our operating partners may drill, impact the locations at which our operating partners may drill wells, restrict the amounts of oil and natural gas that may be produced from wells drilled by our operating partners and increase the costs of operations.
Hydraulic Fracturing. We expect to participate in exploration and drilling projects that seek to recover oil and natural gas through the use of hydraulic fracturing. Hydraulic fracturing, which involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production, is typically regulated by state oil and gas commissions. However, the EPA recently asserted federal regulatory authority over certain hydraulic fracturing practices. Also, legislation has been introduced in Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process. In addition, some states have adopted, and other states are considering adopting, regulations that could restrict hydraulic fracturing in certain circumstances. For instance, in June 2011, Texas adopted a law that requires disclosure to the Railroad Commission of Texas of the additives and other chemicals contained in hydraulic fracturing fluids used in the state, subject to certain trade secret protections. If new laws or regulations that significantly restrict hydraulic fracturing are adopted at the Texas state level, such legal requirements could make it more difficult or costly for our operating partners to perform fracturing to stimulate production in the play and thereby affect the determination of whether a well is commercially viable. In addition, if hydraulic fracturing is regulated at the federal level, fracturing activities could become subject to additional permit requirements or operational restrictions and also to associated permitting delays and potential increases in costs. Restrictions on hydraulic fracturing could also reduce the amount of oil or natural gas and natural gas liquids that our operating partners are ultimately able to produce in commercial quantities from our oil and gas properties.
Employees
As of the date of this report, we have two employees, our chief executive officer and chief financial officer. For the foreseeable future, we intend to use the services of independent consultants and contractors to perform various professional services related to our oil and gas operations. Subject to our receipt of significant additional capital, we intend to hire senior management and staff with experience in oil and gas exploration and development. Until such time, we intend to rely on third party consultants to advise and assist us on our oil and gas operations.
Available Information
Our website is located at www.westtexasresources.com. The information on or accessible through our website is not part of this annual report on Form 10-K. A copy of this annual report on Form 10-K is located at the SEC’s Public Reference Room at 100 F Street, NE, Washington, D.C. 20549. Information on the operation of the Public Reference Room can be obtained by calling the SEC at 1-800-SEC-0330. The SEC also maintains an internet site that contains reports and other information regarding our filings at www.sec.gov.
Glossary of Oil and Natural Gas Terms
The following is a description of the meanings of some of the oil and natural gas industry terms used in this report.
bbl. Stock tank barrel, or 42 U.S. gallons liquid volume, used in this report in reference to crude oil or other liquid hydrocarbons.
bcf. Billion cubic feet of natural gas.
boe. Barrels of crude oil equivalent, determined using the ratio of six mcf of natural gas to one bbl of crude oil, condensate or natural gas liquids.
boe/d. boe per day.
Completion. The process of treating a drilled well followed by the installation of permanent equipment for the production of natural gas or oil, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.
Condensate. Hydrocarbons which are in the gaseous state under reservoir conditions and which become liquid when temperature or pressure is reduced. A mixture of pentanes and higher hydrocarbons.
Development well. A well drilled within the proved area of a natural gas or oil reservoir to the depth of a stratigraphic horizon known to be productive.
Drilling locations. Total gross locations specifically quantified by management to be included in the Company’s multi-year drilling activities on existing acreage. The Company’s actual drilling activities may change depending on the availability of capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, drilling results and other factors.
Dry hole. A well found to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.
Exploratory well. A well drilled to find and produce natural gas or oil reserves not classified as proved, to find a new reservoir in a field previously found to be productive of natural gas or oil in another reservoir or to extend a known reservoir.
Field. An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.
Formation. An identifiable layer of rocks named after its geographical location and dominant rock type.
Fracture or fracturing. Hydraulic fracturing, a common practice that is used to stimulate production of oil and natural gas from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand and chemicals under pressure into a formation to fracture the surrounding rock and stimulate production.
Lease. A legal contract that specifies the terms of the business relationship between an energy company and a landowner or mineral rights holder on a particular tract of land and typically grants to the energy company a fee simple determinable estate in the minerals.
Leasehold. Mineral rights leased in a certain area to form a project area.
mbbls. Thousand barrels of crude oil or other liquid hydrocarbons.
mboe. Thousand barrels of crude oil equivalent, determined using the ratio of six mcf of natural gas to one bbl of crude oil, condensate or natural gas liquids
mcf. Thousand cubic feet of natural gas.
mcfe. Thousand cubic feet equivalent, determined using the ratio of six mcf of natural gas to one bbl of crude oil, condensate or natural gas liquids.
mmbbls. Million barrels of crude oil or other liquid hydrocarbons.
mmboe. Million barrels of crude oil equivalent, determined using the ratio of six mcf of natural gas to one bbl of crude oil, condensate or natural gas liquids.
mmbtu. Million British Thermal Units.
mmcf. Million cubic feet of natural gas.
Net acres, net wells, or net reserves. The sum of the fractional working interest owned in gross acres, gross wells, or gross reserves, as the case may be.
ngl. Natural gas liquids, or liquid hydrocarbons found in association with natural gas.
Overriding royalty interest. Is similar to a basic royalty interest except that it is created out of the working interest. For example, an operator possesses a standard lease providing for a basic royalty to the lessor or mineral rights owner of 1/8 of 8/8. This then entitles the operator to retain 7/8 of the total oil and natural gas produced. The 7/8 in this case is the 100% working interest the operator owns. This operator may assign his working interest to another operator subject to a retained 1/8 overriding royalty. This would then result in a basic royalty of 1/8, an overriding royalty of 1/8 and a working interest of 3/4. Overriding royalty interest owners have no obligation or responsibility for developing and operating the property. The only expenses borne by the overriding royalty owner are a share of the production or severance taxes and sometimes costs incurred to make the oil or gas salable.
Plugging and abandonment. Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another or to the surface. Regulations of all states require plugging of abandoned wells.
Present value of future net revenues (PV-10). The present value of estimated future revenues to be generated from the production of proved reserves, before income taxes, of proved reserves calculated in accordance with Financial Accounting Standards Board guidelines, net of estimated production and future development costs, using prices and costs as of the date of estimation without future escalation, without giving effect to hedging activities, non-property related expenses such a general and administrative expenses, debt service and depreciation, depletion and amortization, and discounted using an annual discount rate of 10%.
Production. Natural resources, such as oil or gas, taken out of the ground.
Proved oil and gas reserves. Proved oil and gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be economically recoverable in future years from known reservoirs under existing economic conditions, operating methods, and government regulations-prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
(i)Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes (A) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and (B) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.
(ii)Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the "proved" classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.
(iii)Estimates of proved reserves do not include the following: (A) oil that may become available from known reservoirs but is classified separately as "indicated additional reserves"; (B) crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors; C) crude oil, natural gas, and natural gas liquids, that may occur in undrilled prospects; and (D) crude oil, natural gas, and natural gas liquids, that may be recovered from oil shales, coal, gilscnite, and other such sources.
Proved developed oil and gas reserves. Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as "proved developed reserves" only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.
Proved undeveloped reserves. Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.
Productive well. A well that is found to be capable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.
Project. A targeted development area where it is probable that oil or natural gas can be produced from new wells.
Prospect. A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.
Recompletion. The process of re-entering an existing well bore that is either producing or not producing and completing new reservoirs in an attempt to establish or increase existing production.
Reserves. Oil, natural gas and gas liquids thought to be accumulated in known reservoirs.
Reservoir. A porous and permeable underground formation containing a natural accumulation of producible nature gas and/or oil that is confined by impermeable rock or water barriers and is separate from other reservoirs.
Secondary Recovery. A recovery process that uses mechanisms other than the natural pressure of the reservoir, such as gas injection or water flooding, to produce residual oil and natural gas remaining after the primary recovery phase.
Shut-in. A well that has been capped (having the valves locked shut) for an undetermined amount of time. This could be for additional testing, could be to wait for pipeline or processing facility, or a number of other reasons.
Standardized measure. The present value of estimated future cash inflows from proved oil and natural gas reserves, less future development, abandonment, production and income tax expenses, discounted at 10% per annum to reflect timing of future cash flows and using the same pricing assumptions as were used to calculate PV-10. Standardized measure differs from PV-10 because standardized measure includes the effect of future income taxes.
Successful. A well is determined to be successful if it is producing oil or natural gas, or awaiting hookup, but not abandoned or plugged.
Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.
Water flood. A method of secondary recovery in which water is injected into the reservoir formation to displace residual oil and enhance hydrocarbon recovery.
Working interest. The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production and requires the owner to pay a share of the costs of drilling and production operations.
Item 1A.
Item 1A. Risk Factors
There are numerous and varied risks, known and unknown, that may prevent us from achieving our goals. If any of these risks actually occur, our business, financial condition or results of operation may be materially adversely affected. In such case, the trading price of our common stock could decline and investors could lose all or part of their investment.
We are an early stage company and have limited assets. We were formed in 2010 and commenced revenue producing oil and gas operations effective as of April 1, 2013. As an early stage company, we are subject to all risks inherent in a new venture. The likelihood of our success must be considered in light of problems, expenses, complications and delays frequently encountered in connection with the development of a new business. We do not have a significant operating history and, as a result, there is a limited amount of information about us on which to make an investment decision.
We will require additional capital in order to achieve commercial success and, if necessary, to finance future losses from operations as we endeavor to build revenue, but we do not have any commitments to obtain such capital. The business of oil and gas acquisition, drilling and development is capital intensive and the level of operations attainable by an oil and gas company is directly linked to and limited by the amount of available capital. As of September 30, 2013, we had total current assets of $185,580 and a working capital deficit of $(64,424). We believe that our ability to achieve commercial success and our continued growth will be dependent on our ability to access capital either through the additional sale of our equity or debt securities, bank lines of credit, project financing or cash generated from oil and gas operations. Therefore, a principal part of our plan of operations is to acquire the additional capital required to finance the acquisition of such properties and our share of the development costs. We will seek additional working capital through the sale of our securities and, subject to the successful deployment of our cash on hand, we will endeavor to obtain additional capital through bank lines of credit and project financing. However, as of the date of this report, we have no commitments for the sale of our securities or our acquisition of additional capital through any other means nor can there be any assurance that any funds will be available on commercially reasonable terms, if at all.
Our management has limited experience in operating an oil and gas business. At the present time, we have two employees, our chief executive officer and our chief financial officer, Stephen Jones and John Kerr, respectively, who also serve as the sole members of our board of directors. Mr. Jones and Mr. Kerr each has limited experience in the oil and gas business. We intend to expand our management team and board of directors with personnel who have experience in the oil and gas business, however we have no agreements or understandings in place as of the date of this report concerning the appointment of any additional officers or directors. We do not expect to be able to attract senior management or directors with significant oil and gas experience until such time as we raise significant additional capital. Until such time, if ever, as we do, the success of our company will be dependent on the decisions and actions undertaken by Mr. Jones and Mr. Kerr.
We have limited management and staff and will be dependent for the foreseeable future upon consultants and partnering arrangements. At the present time, we have two employees, our chief executive officer and our chief financial officer, Stephen Jones and John Kerr, respectively. We have developed an operating strategy that is based on our participation in exploration prospects in North America as a non-operator for the foreseeable future. We intend to use the services of independent consultants and contractors to perform various professional services, including reservoir engineering, land, legal, environmental and tax services. We will also pursue alliances with partners in the areas of geological and geophysical services and prospect generation, evaluation and prospect leasing. As a non-operator working interest owner, we intend to rely on outside operators to drill, produce and market our natural gas and oil. Our dependence on third party consultants, service providers and operators creates a number of risks, including but not limited to:
·the possibility that such third parties may not be available to us as and when needed; and
·the risk that we may not be able to properly control the timing and quality of work conducted with respect to our projects.
Our estimated reserves of oil and gas are based on our internal analysis and have not been prepared or reviewed by independent oil and gas engineers. We acquired our initial working interests in developed oil and gas properties, the Port Hudson field and the West Cam 225 field, in August and September 2013, respectively. To date, we have not retained an independent oil and gas engineering firm to audit the proven reserves associated with those properties. While we have undertaken an internal analysis of the proven reserves associated with both properties using data we consider to be relevant and reasonably reliable, we have not undertaken all of the procedures or used all of the technologies or techniques that an independent oil and gas engineering firm might use in auditing our oil and gas reserves. There can be no assurance that an independent audit of or oil and gas reserves would conclude that our oil and gas reserves are materially lower than our internal estimates.
Our estimated reserves and future production rates are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our estimated reserves. Numerous uncertainties are inherent in estimating quantities of oil and natural gas reserves and future production. It is not possible to measure underground accumulations of oil or natural gas in an exact way. Oil and natural gas reserve engineering is complex, requiring subjective estimates of underground accumulations of oil and natural gas and assumptions concerning future oil and natural gas and prices, future production levels and operating and development costs. In estimating our level of oil and natural gas reserves, we make certain assumptions that may prove to be incorrect, including assumptions relating to:
·the level of oil and natural gas prices;
·future production levels;
·capital expenditures;
·operating and development costs;
·the effects of regulation;
·the accuracy and reliability of the underlying engineering and geologic data; and
·the availability of funds.
If these assumptions prove to be incorrect, our estimates of our reserves, the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, the classifications of reserves based on risk of recovery and our estimates of the future net cash flows from our estimated reserves could change significantly. Moreover, the variability is likely to be higher for probable and possible reserve estimates.
Our standardized measure is calculated using unhedged oil, natural gas and NGL prices and is determined in accordance with the rules and regulations of the SEC. Over time, we may make material changes to reserve estimates to take into account changes in our assumptions and the results of actual development and production. The reserve estimates we make for wells or fields that do not have a lengthy production history are less reliable than estimates for wells or fields with lengthy production histories. A lack of production history may contribute to inaccuracy in our estimates of proved reserves, future production rates and the timing of development expenditures.
Shortages or increases in costs of equipment, services and qualified personnel could delay the drilling of exploratory wells and adversely affect our future results of operations and the price of our common stock. The demand for qualified and experienced personnel to conduct field operations, geologists, geophysicists, engineers and other professionals in the oil and natural gas industry can fluctuate significantly, often in correlation with oil and natural gas prices, causing periodic shortages. Historically, there have been shortages of drilling rigs and other equipment as demand for rigs and equipment has increased along with the number of wells being drilled. These factors also cause significant increases in costs for equipment, services and personnel. Higher oil and natural gas prices generally stimulate demand and result in increased prices for drilling rigs, crews and associated supplies, equipment and services. Shortages of field personnel and equipment or price increases could significantly hinder the ability of our operating partners to conduct drilling operations, which could adversely affect our results of operations and stock price.
Our industry is highly competitive which may adversely affect our performance, including our ability to participate in ready to drill prospects. Oil and gas exploration and development companies operate in a highly competitive environment. In addition to capital, the principal resources necessary for the exploration and production of oil and natural gas are:
·leasehold prospects under which oil and natural gas reserves may be discovered;
·drilling rigs and related equipment to explore for such reserves; and
·knowledgeable personnel to conduct all phases of oil and natural gas operations.
Numerous large, well-financed firms with large cash reserves are engaged in the acquisition of oil and gas properties in North America. We and our operating partners will face competition in acquisitions, development, exploration and production from major oil companies, numerous independents, individual proprietors and others. We expect competition to be intense for available target oil and gas properties. Such competition could have a material adverse effect on our financial condition and operating results. We and our operating partners may not be able to compete successfully against current and future competitors and competitive pressures faced by us may materially adversely affect our business, financial condition, and results of operations.
Drilling for and producing oil and natural gas are high risk activities with many uncertainties that could delay the anticipated drilling schedule for exploratory wells and adversely affect our future results of operations and stock price. The drilling and completion of exploratory wells are subject to numerous risks beyond our control or the control of our operating partners, including risks that could delay the proposed drilling schedules and the risk that drilling will not result in commercially viable oil and natural gas production. Drilling for oil and natural gas can be unprofitable if dry wells are drilled and if productive wells do not produce sufficient revenues to return a profit. The decisions by us and our operating partners to develop or otherwise exploit certain prospects will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. The costs of drilling, completing and operating wells are often uncertain before drilling commences. Overruns in budgeted expenditures are common risks that can make a particular project uneconomical. Even if an exploratory well is successfully completed, it may not pay out the capital costs spent to drill it. Drilling and production operations on an exploratory well may be curtailed, delayed or canceled as a result of various factors, including the following:
·delays imposed by or resulting from compliance with regulatory requirements including permitting;
·unusual or unexpected geological formations and miscalculations;
·shortages of or delays in obtaining equipment and qualified personnel;
·equipment malfunctions, failures or accidents;
·lack of available gathering facilities or delays in construction of gathering facilities;
·lack of available capacity on interconnecting transmission pipelines;
·lack of adequate electrical infrastructure;
·unexpected operational events and drilling conditions;
·pipe or cement failures and casing collapses;
·pressures, fires, blowouts, and explosions;
·lost or damaged drilling and service tools;
·loss of drilling fluid circulation;
·uncontrollable flows of oil, natural gas and natural gas liquids water or drilling fluids;
·natural disasters;
·environmental hazards, such as oil, natural gas and natural gas liquids leaks, pipeline ruptures and discharges of toxic gases or fluids;
·adverse weather conditions such as extreme cold, fires caused by extreme heat or lack of rain, and severe storms or tornadoes;
·reductions in oil, natural gas and natural gas liquids prices;
·oil and natural gas property title problems; and
·market limitations for oil, natural gas and natural gas liquids.
If any of these or other similar industry operating risks occur, we could have substantial losses. Substantial losses also may result from injury or loss of life, severe damage to or destruction of property, clean-up responsibilities, regulatory investigation and penalties and suspension of operations.
Market conditions for oil and natural gas, and particularly volatility of prices for oil and natural gas, could adversely affect our revenue, cash flows, profitability and growth. Our project revenue, cash flows, profitability and future rate of growth depend substantially upon prevailing prices for oil and natural gas. Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow money or raise additional capital. Lower prices may also make it uneconomical for our operating partners to commence or continue production levels of natural gas and crude oil. Prices for oil and natural gas are subject to large fluctuations in response to relatively minor changes in the supply and demand for oil and natural gas, market uncertainty and a variety of other factors beyond our control or the control of our operating partners, including:
·regional, domestic and foreign supply, and perceptions of supply, of oil, natural gas and natural gas liquids;
·the price of foreign imports;
·U.S. and worldwide political and economic conditions;
·the level of demand, and perceptions of demand, for oil, natural gas and natural gas liquids;
·weather conditions and seasonal trends;
·anticipated future prices of oil, natural gas and natural gas liquids, alternative fuels and other commodities;
·technological advances affecting energy consumption and energy supply;
·the proximity, capacity, cost and availability of pipeline infrastructure, treating, transportation and refining capacity;
·acts of force majeure;
·domestic and foreign governmental regulations and taxation;
·energy conservation and environmental measures; and
·the price and availability of alternative fuels.
For oil, from 2007 through December 2013, the highest monthly NYMEX settled price was $140.00 per bbl and the lowest was $41.68 per bbl. For natural gas, from 2007 through December 2013, the highest monthly NYMEX settled price was $13.35 per mmbtu and the lowest was $2.04 per mmbtu. In addition, the market price of oil and natural gas is generally higher in the winter months than during other months of the year due to increased demand for oil and natural gas for heating purposes during the winter season.
Lower oil and natural gas prices will reduce our revenues and may ultimately reduce the amount of oil and natural gas that is economic to produce from our oil and gas properties. As a result, our operating partners could determine during periods of low oil and natural gas prices to shut in or curtail production from any operating wells. In addition, our operating partners could determine during periods of low oil and natural gas prices to plug and abandon marginal wells that otherwise may have been allowed to continue to produce for a longer period under conditions of higher prices. Specifically, our operating partners may abandon any well or property if it reasonably believes that the well or property can no longer produce oil or natural gas in commercially economic quantities. This could result in termination of our portion of the royalty interest relating to the abandoned well or property.
Investigations of oil and gas properties do not eliminate the risks associated with the selection and the acquisition of such properties. Although we will engage third-party consultants to perform a review of the oil and properties proposed to be acquired, such reviews are subject to uncertainties. It generally is not feasible to review in detail every individual property involved in an acquisition. Even a detailed review of all properties and records may not reveal existing or potential problems; nor will it permit our consultants to become sufficiently familiar with the properties to assess fully their deficiencies and capabilities. Inspections are not always performed on every well, and potential problems, such as mechanical integrity of equipment and environmental conditions that may require significant remedial expenditures, are not necessarily observable even when an inspection is undertaken.
Oil and gas exploration and development is subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of conducting our operations or expose us to significant liabilities. Our proposed oil and natural gas exploration and production operations are subject to complex and stringent laws and regulations. In order to conduct operations in compliance with these laws and regulations, oil and gas operators must obtain and maintain numerous permits, approvals and certificates from various federal, state and local governmental authorities. Substantial costs may be incurred by our operating partners in order to maintain compliance with these existing laws and regulations. Further, in light of the explosion and fire on the drilling rig Deepwater Horizon in the Gulf of Mexico, as well as recent incidents involving the release of oil and natural gas and fluids as a result of drilling activities in the United States, there has been a variety of regulatory initiatives at the federal and state level to restrict oil and natural gas drilling operations in certain locations. Any increased regulation or suspension of oil and natural gas exploration and production, or revision or reinterpretation of existing laws and regulations, that arises out of these incidents or otherwise could result in delays and higher operating costs, which will be passed along to us by way of our equity interest in the property. Such costs or significant delays could have a material adverse effect on our business, financial condition and results of operations.
Laws and regulations governing oil and natural gas exploration and production may also affect production levels. Oil and gas operators are required to comply with federal and state laws and regulations governing conservation matters, including provisions related to the unitization or pooling of the oil, natural gas and natural gas liquids properties; the establishment of maximum rates of production from wells; the spacing of wells; and the plugging and abandonment of wells. These and other laws and regulations can limit the amount of oil and natural gas operators can produce from their wells, limit the number of wells they can drill, or limit the locations at which they can conduct drilling operations, which in turn could negatively impact our business, financial condition and results of operations.
New laws or regulations, or changes to existing laws or regulations may unfavorably impact our proposed operations, could result in increased operating costs and have a material adverse effect on our financial condition and results of operations. For example, Congress is currently considering legislation that, if adopted in its proposed form, would subject companies involved in oil and natural exploration and production activities to, among other items, additional regulation of and restrictions on hydraulic fracturing of wells, the elimination of most U.S. federal tax incentives and deductions available to oil and natural gas exploration and production activities, and the prohibition or additional regulation of private energy commodity derivative and hedging activities.
These and other potential regulations could increase operating costs, reduce revenue, delay proposed operations, increase direct and third party post production costs associated with the oil and gas properties or otherwise alter the proposed operations of oil and gas properties in which we hold an equity interest, which could have a material adverse effect on our financial condition, results of operations and stock price.
Oil and gas operations are subject to environmental laws and regulations that could adversely affect the cost, manner or feasibility of conducting operations or result in significant costs and liabilities. Oil and natural gas exploration and production operations are subject to stringent and comprehensive federal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may impose numerous obligations that are applicable to the operation of the properties in which we hold an interest including the acquisition of a permit before conducting drilling; water withdrawal or waste disposal activities; the restriction of types, quantities and concentration of materials that can be released into the environment; the limitation or prohibition of drilling activities on certain lands lying within wilderness, wetlands and other protected areas; and the imposition of substantial liabilities for pollution resulting from operations. Numerous governmental authorities, such as the U.S. Environmental Protection Agency ("EPA") and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them, often requiring difficult and costly actions. Failure to comply with these laws and regulations may result in the assessment of administrative, civil or criminal penalties; the imposition of investigatory or remedial obligations; and the issuance of injunctions limiting or preventing some or all of the proposed operations.
There is inherent risk of incurring significant environmental costs and liabilities in the performance of oil and gas operations due to the handling of petroleum hydrocarbons and wastes, because of air emissions and wastewater discharges related to such operations, and as a result of historical industry operations and waste disposal practices. Under certain environmental laws and regulations, our operating partner could be subject to joint and several strict liability for the removal or remediation of previously released materials or property contamination regardless of whether our operating partner was responsible for the release or contamination or if the operations were in compliance with all applicable laws at the time those actions were taken. Private parties, including the owners of properties upon which our operating partners intend to drill wells and facilities where petroleum hydrocarbons or wastes are taken for reclamation or disposal may also have the right to pursue legal actions to enforce compliance, as well as to seek damages for contamination even in the absence of non-compliance, with environmental laws and regulations or for personal injury or property damage. In addition, the risk of accidental spills or releases could expose our operating partners to significant liabilities. All of the foregoing costs and liabilities of our operating partners may be passed along to us by way of our equity interest on the subject oil and gas property, which in turn could have a material adverse effect on our financial condition, results of operations and stock price. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly construction, drilling, water management, completion, waste handling, storage, transport, disposal or cleanup requirements could require our operating partners to make significant expenditures to attain and maintain compliance. We would be responsible for our pro rata share of such costs, which may have a material adverse effect on our results of operations, financial condition or stock price.
Climate change laws and regulations restricting emissions of "greenhouse gases" could result in increased operating costs and reduced demand for oil and natural gas while the physical effects of climate change could disrupt production and cause our operating partners to incur significant costs in preparing for or responding to those effects. On December 15, 2009, the EPA published its findings that emissions of carbon dioxide, methane and other greenhouse gases ("GHGs") present a danger to public health and the environment. These findings allow the agency to adopt and implement regulations that restrict emissions of GHGs under existing provisions of the federal Clean Air Act. Accordingly, the EPA has adopted regulations that require a reduction in emissions of GHGs from motor vehicles and also trigger permit review for GHG emissions from certain large stationary sources. The EPA's rules relating to emissions of GHGs from large stationary sources of emissions are currently subject to a number of political and legal challenges, but the federal courts have thus far declined to issue any injunctions to prevent EPA from implementing, or requiring state environmental agencies to implement, the rules. In addition, on October 30, 2009, the EPA published a final rule requiring the reporting of GHG emissions from specified large GHG emission sources in the United States, beginning in 2011 for emissions occurring in 2010. On November 30, 2010, the EPA published a final rule that expands its October 2009 final rule on reporting of GHG emissions to require certain owners and operators of onshore oil and natural gas production to monitor greenhouse gas emissions beginning in 2011 and to report those emissions beginning in 2012. Both houses of Congress have from time to time considered legislation to reduce emissions of GHGs and almost one-half of the states, either individually or through multi-state regional initiatives, already have begun implementing legal measures to reduce emissions of GHGs. The adoption and implementation of any regulations imposing reporting obligations on, or limiting emissions of GHGs from the equipment and operations of our operating partners could require our operating partners to incur costs to reduce emissions of GHGs associated with our operations or could adversely affect demand for the oil and natural gas. All of the foregoing costs and liabilities of our operating partners may be passed along to us by way of our equity interest on the subject oil and gas property, which in turn could have a material adverse effect on our financial condition, results of operations and stock price. Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse gases in the Earth's atmosphere may produce climate change that could have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events; if any such effects were to occur, they could have an adverse effect on our assets and operations.
Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays as well as adversely affect our results of operations, financial condition or stock price. Our operating partners may from time to time engage in a production technique known as hydraulic fracturing, an important and common practice used to stimulate production of hydrocarbons from tight formations, such as shales. The process involves the injection of water or other liquids, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The process is typically regulated by state oil and gas commissions. However, the EPA recently asserted federal regulatory authority over certain hydraulic fracturing practices. Also, legislation has been introduced into Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process. In addition, some states have adopted, and other states are considering adopting, regulations that could restrict hydraulic fracturing in certain circumstances. For instance, in June 2011, Texas adopted a law that requires disclosure to the Railroad Commission of Texas of the additives and other chemicals contained in hydraulic fracturing fluids used in the state, subject to certain trade secret protections. If new laws or regulations that significantly restrict or regulate hydraulic fracturing are adopted, such legal requirements could make it more difficult or costly for our operating partners to perform fracturing to stimulate production from our oil and gas interests and thereby affect the determination of whether a well is commercially viable. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas our operating partners are ultimately able to produce in commercial quantities from our oil and gas interests.
Hydraulic fracturing operations may result environmental contamination and other operational risks that could subject us to significant costs, liabilities and loss of investment. Hydraulic fracturing is a process that involves the injection of water or other liquids, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The process involves the risk that liquids and chemicals injected into the well may migrate into and contaminate water aquifers and wells or surrounding land. The process also involves the risk that water and liquids that are retrieved from the fractured well may be improperly disposed of, thus creating another potential for water or ground contamination. Our operating partners face the possibility of significant costs and liabilities in the event of any environmental contamination resulting from the hydraulic fracturing of wells in which we have an interest, in which event we may become liable for our pro rata share of such costs and liabilities. Also, even in the absence of any actual contamination, we can face significant costs if the operator is required to defend any lawsuits or investigations that allege contamination. Finally, any actual or alleged environmental contamination resulting from a drilling operation on an oil and gas property in which we have an interest can lead to the suspension or abandonment of that property and the loss of our entire investment in such property.
No Dividends. We do not expect to pay cash dividends on our common stock in the foreseeable future.
No Active Trading market. Our common shares are traded on the OTC Market under the symbol “WTXR.” However, we consider our common stock to be “thinly traded” and any last reported sale prices may not be a true market-based valuation of the common stock. Also, the present volume of trading in our common stock may not provide investors sufficient liquidity in the event you wish to sell your common shares. There can be no assurance that an active market for our common stock will develop. In addition, the stock market in general, and early stage public companies in particular, have experienced extreme price and volume fluctuations that have often been unrelated or disproportionate to the operating performance of such companies. If we are unable to develop a market for our common shares, you may not be able to sell your common shares at prices you consider to be fair or at times that are convenient for you, or at all.
Our common stock may be considered to be a “penny stock” and, as such, any the market for our common stock may be further limited by certain SEC rules applicable to penny stocks. To the extent the price of our common stock remains below $5.00 per share or we have a net tangible assets of $2,000,000 or less, our common shares will be subject to certain “penny stock” rules promulgated by the SEC. Those rules impose certain sales practice requirements on brokers who sell penny stock to persons other than established customers and accredited investors (generally institutions with assets in excess of $5,000,000 or individuals with net worth in excess of $1,000,000). For transactions covered by the penny stock rules, the broker must make a special suitability determination for the purchaser and receive the purchaser’s written consent to the transaction prior to the sale. Furthermore, the penny stock rules generally require, among other things, that brokers engaged in secondary trading of penny stocks provide customers with written disclosure documents, monthly statements of the market value of penny stocks, disclosure of the bid and asked prices and disclosure of the compensation to the brokerage firm and disclosure of the sales person working for the brokerage firm. These rules and regulations adversely the affect the ability of brokers to sell our common shares and limit the liquidity of our securities.
Item 1B.
Item 1B. Unresolved Staff Comments
Not applicable.
Item 2.
Item 2. Properties
Company Executive Offices
Our executive offices are located in 5729 Lebanon Road., Suite 144, Frisco, Texas 75034. We believe that our current facilities are adequate for our foreseeable needs.
Oil and Gas Interests
In September 2011, we acquired our initial property consisting of a 31.25% working interest in an exploratory oil and gas drilling prospect covering 120 acres in Eastland County, Texas. The Eastland County prospect includes two exploratory wells, known as Rutherford #1 and C.M. Knott #1, that had been operating at a minimum level required to maintain the lease rights. In October 2011, the operator reentered the Rutherford #1 well and conducted drilling and casing activities, which were completed in November 2011. In January 2012, a third party conducted the fracture stimulation of the Rutherford #1. In February 2013, the operator placed a pump jack on the Rutherford #1 well, however no meaningful revenue has been derived from the well to date. During the three months ended June 30, 2013, we determined that our investment in the Eastland County prospect was impaired due to an unsuccessful fracture stimulation of the Rutherford #1. Accordingly, we recorded an impairment loss of $108,373 to write off the capitalized fracture stimulation costs. The operator has undertaken no further activity on the Eastland County prospect as of the date of this report.
In August 2013, we acquired a 7.24625% working interest (5.65158% net revenue interest) in the oil and gas leases, wells and attendant production in the Port Hudson field, Baton Rouge Parish, Louisiana, from Wells Fargo Energy Capital, Inc. for total consideration of $702,900. Our acquisition of the Port Hudson working interest was effective as of April 1, 2013. Accordingly, we have received revenue from the Port Hudson working interest commencing on April 1, 2013. The Port Hudson field has three producing wells that have produced a total of 1.1 million bbls to date with estimated total remaining recoverable proved developed producing reserves of 294,000 bbls, and 229,000 bbls of proven developed behind pipe reserves and are currently producing approximately 290 bbls per day. The operator of the Port Hudson field has no current plans for the further development of the property.
In September 2013, we acquired a 10.0167% working interest (7.2120% net revenue interest) in an offshore oil and gas field, known as West Cam 225, located in the shallow waters of the Gulf of Mexico near Cameron, Louisiana, from Enovation Resources, LLC for total consideration of $50,000. Concurrent with our purchase of the working interest, we also paid the operator $230,459 as our allocable share of the expenses associated with the West Cam 225 property. As of September 30, 2013, the West Cameron 225 field has proven reserves of 10.7 bcf of gas and 16.3 mbc or 1.8 million net equivalent bbls (130,000 net equivalent bbls net to West Texas Resources) and has two producing wells, the #7 and the D-1, that were previously shut-in and waiting on a sales pipeline connection. The pipeline was recently completed and tested and now the two wells are expected to come online at a combined rate of 2 mmcfd (200 mcfd net to the West Texas Resources). The operator presently intends to perform a dual recompletion on the D-1 well in the first half of 2014, at which time the two wells are expected to produce 7.5 mmcfd (750 mcfd net to West Texas Resources).
In addition to our participation in any continued development of the West Cam 225 prospect, and subject to our receipt of additional capital, we intend to pursue the acquisition of additional equity interests in other oil and gas properties in North America. However, as of the date of this report, we have no understandings or agreements in place concerning our acquisition of an interest in any other properties.
Estimated Proved Reserves
The following table sets forth our estimated proved reserves as of September 30, 2013:
The estimated proven reserves set forth above are based on the SEC disclosure rules which require disclosure of oil and gas proved reserves by significant geographic area, using the arithmetic 12-month average first-day-of the-moth prices for the year, as opposed to using year-end prices. The estimated dollar value of our proved reserves represents the present value, discounted at 10% per annum, or PV-10, of the estimated future cash flows before income taxes. The unweighted arithmetic first-day-of the-moth prices for the 12 months prior to September 30, 2013 were $95.17/bbl for oil and $3.61/mcf for natural gas. We converted natural gas to oil equivalent at a ratio of six mcf to one boe.
All of our reserves are located within the continental U.S. and consist of our net interests in the estimated proven reserves at the Port Hudson and West Cam 225 fields. The reserve analysis set forth above was prepared by consultants retained by us and has not been confirmed by independent third party oil and gas engineers. For a discussion of the risks associated with our internal reserve estimates, please read "Item 1A. Risk Factors - Our estimated reserves of oil and gas are based on our internal analysis and have not been prepared or reviewed by independent oil and gas engineers.”
The data in the table above represents estimates only. Oil and natural gas reserve engineering is inherently a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured exactly. The accuracy of any reserve estimate is a function of the quality of available data and engineering and geological interpretation and judgment. Accordingly, reserve estimates may vary from the quantities of oil and natural gas that are ultimately recovered. For a discussion of risks associated with reserve estimates generally, please read "Item 1A. Risk Factors-Our estimated reserves and future production rates are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our estimated reserves.”
Acreage
The following tables summarize by geographic area our developed and undeveloped acreage as of September 30, 2013.
__________
1 Developed acreage is acreage spaced for or assignable to productive wells.
2 Undeveloped acreage is oil and gas acreage on which wells have not been drilled or completed to a point that would permit the production of economic quantities of oil or gas regardless of whether such acreage contains proved reserves.
3 A gross acre is an acre in which we own a working interest. The number of gross acres is the total number of acres in which we own a working interest.
4 A net acre is the amount of a gross acre represented by our working interest. The number of net acres is the sum of the fractional working interests owned in acres expressed as whole numbers and fractions thereof.
Productive Wells
The following table summarizes by geographic area our gross and net interests in producing oil and gas wells as of September 30, 2013. Productive wells are producing wells and wells capable of production, including gas wells awaiting pipeline connections and oil wells awaiting connection to production facilities. Wells that are dually completed in more than one producing horizon are counted as one well. A gross well is a well in which we hold a working interest. A net well is the amount of a gross well represented by our working interest and the number of net wells is the sum of all of our fractional interests in gross wells in which we hold a working interest.
Drilling and Other Exploratory Activities
We were incorporated in December 2010 and did not participate in any drilling, or other exploratory or development, activity during the fiscal year ended September 30, 2011. In October 2011, we participated in our first drilling operation, which took place at our initial prospect, located in Eastland County, Texas. The Eastland County prospect includes two wells, known as Rutherford #1 and C.M. Knott #1, that had been operating at a minimum level required to maintain the lease rights. In October 2011, the operator of the prospect reentered the Rutherford #1 well and conducted drilling and casing activities, which were completed in November 2011. In January 2012, a third party conducted the fracture stimulation of the Rutherford #1. In February 2013, the operator placed a pump jack on the Rutherford #1 well, however no meaningful revenue has been derived from the well to date. Our activity on the Rutherford #1 represents our only participation in drilling, exploratory or development activity to date. As of the date of this report, we have no wells in the process of drilling or completion other than the Rutherford #1.
Item 3.
Item 3. Legal Proceedings
As of the date of this report, there are no pending legal proceedings to which we or our properties are subject, except for routine litigation incurred in the normal course of business.
Item 4.
Item 4. Mine Safety Disclosures
Inapplicable.
PART II
Item 5.
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Repurchases of Equity Securities
Market Information
Our common stock has been quoted on the OTC Market under the symbol “WTXR” since October 24, 2012. The high and low sale prices for our common shares on the OTC Market between October 24, 2012 and the date of this report is $0.25 and $1.25. However, we consider our common stock to be “thinly traded” and any reported sale prices may not be a true market-based valuation of the common stock.
Holders of Record
As of January 10, 2014, there were approximately 160 holders of record of our common stock.
Dividend Policy
We have never declared or paid cash dividends on our common stock. We presently intend to retain earnings to finance the operation and expansion of our business.
Equity Compensation Plan Information
We have adopted the West Texas Resources, Inc. 2011 Stock Incentive Plan providing for the grant of non-qualified stock options and incentive stock options to purchase shares of our common stock and for the grant of restricted and unrestricted share grants. We have reserved 3,000,000 shares of our common stock under the plan. All officers, directors, employees and consultants to our company are eligible to participate under the plan. The purpose of the plan is to provide eligible participants with an opportunity to acquire an ownership interest in our company.
The following table sets forth certain information as of September 30, 2013 about our stock plans under which our equity securities are authorized for issuance.
Unregistered Sales of Equity Securities and Use of Proceeds
During the fiscal year ended September 30, 2013 and through the date of this report, we conducted the private placement sale of 972,900 shares of our common stock at the offering price of $0.50 per share to 39 parties for the gross proceeds of $486,450, including the conversion of $41,000 of shareholder advances. The issuances were exempt under Section 4(a)(2) of the Securities Act of 1933 and Rule 506 there under. All of the investors were accredited investors, as such term is defined in Rule 501 under the Securities Act. The offering was conducted by our management. No sales commissions or finders’ fees were paid by us or anyone else.
Item 6.
Item 6. Selected Financial Data
Not applicable.
Item 7.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
General
We were formed on December 9, 2010 under the laws of Nevada for the purpose of oil and gas exploration and development in North America. We commenced revenue producing oil and gas operations effective as of April 1, 2013.
September 2011, we acquired our initial property consisting of a 31.25% working interest in an exploratory oil and gas drilling prospect covering 120 acres in Eastland County, Texas. The Eastland County prospect includes two exploratory wells, known as Rutherford #1 and C.M. Knott #1, that had been operating at a minimum In level required to maintain the lease rights. In October 2011, the operator reentered the Rutherford #1 well and conducted drilling and casing activities, which were completed in November 2011. In January 2012, a third party conducted the fracture stimulation of the Rutherford #1. In February 2013, the operator placed a pump jack on the Rutherford #1 well, however no meaningful revenue has been derived from the well to date. During the three months ended June 30, 2013, we determined that our investment in the Eastland County prospect was impaired due to an unsuccessful fracture stimulation of the Rutherford #1. Accordingly, we recorded an impairment loss of $108,373 to write off the capitalized fracture stimulation costs. The operator has undertaken no further activity on the Eastland County prospect as of the date of this report.
In August 2013, we acquired a 7.24625% working interest (5.65158% net revenue interest) in the oil and gas leases, wells and attendant production in the Port Hudson field, Baton Rouge Parish, Louisiana, from Wells Fargo Energy Capital, Inc. for total consideration of $702,900. Our acquisition of the Port Hudson working interest was effective as of April 1, 2013. Accordingly, we have received revenue from the Port Hudson working interest commencing on April 1, 2013. The Port Hudson field has three producing wells that have produced a total of 1.1 million bbls to date with estimated total remaining recoverable proved developed producing reserves of 294,000 bbls, and 229,000 bbls of proven developed behind pipe reserves and are currently producing approximately 290 bbls per day. The operator of the Port Hudson field has no current plans for the further development of the property.
In September 2013, we acquired a 10.0167% working interest (7.2120% net revenue interest) in an offshore oil and gas field, known as West Cam 225, located in the shallow waters of the Gulf of Mexico near Cameron, Louisiana, from Enovation Resources, LLC for total consideration of $50,000. Concurrent with our purchase of the working interest, we also paid the operator $230,459 as our allocable share of the expenses associated with the West Cam 225 property. As of September 30, 2013, the West Cameron 225 field has proven reserves of 10.7 bcf of gas and 16.3 mbc or 1.8 million net equivalent bbls (130,000 net equivalent bbls net to West Texas Resources) and has two producing wells, the #7 and the D-1, that were previously shut-in and waiting on a sales pipeline connection. The pipeline was recently completed and tested and now the two wells are expected to come online at a combined rate of 2 mmcfd (200 mcfd net to the West Texas Resources). The operator presently intends to perform a dual recompletion on the D-1 well in the first half of 2014, at which time the two wells are expected to produce 7.5 mmcfd (750 mcfd net to West Texas Resources).
Results of Operations
We commenced revenue producing oil and gas operations effective as of April 1, 2013. During the fiscal year ended September 30, 2013, we had $214,601 of revenue, all of which was oil and gas sales derived from our working interest in the Port Hudson field which we acquired effective as of April 1, 2013. For the fiscal years ended September 30, 2013 and 2012, we incurred a net loss of ($294,012) and ($166,370), respectively. Our net loss for fiscal year ended September 30, 2013 included a non-cash impairment charge of $108,373, which is described above.
Subject to our receipt of additional capital, our plan of operations over the next 12 months is to pursue the acquisition of additional equity interests in oil and gas properties to be thereafter exploited by us in conjunction with other oil and gas producers. As of the date of this report, we have no understandings or agreements in place concerning our acquisition of an interest in any other properties.
At the present time, we have two employees, our chief executive officer and chief financial officer, Stephen Jones and John Kerr, respectively, each of whom has limited experience in the oil and gas exploration and development business. Subject to our receipt of significant additional capital, we intend to hire senior management and staff with experience in oil and gas exploration. Until such time, we intend to pursue an operating strategy that is based on our participation in exploration prospects as a non-operator. Based on that strategy, our plan of operations over the next 12 months is to pursue the acquisition of oil and natural gas interests in partnership with other companies with exploration, development and production expertise. We will also pursue alliances with partners in the areas of geological and geophysical services and prospect generation, evaluation and prospect leasing. Pursuant to this strategy, we intend to engage and rely on third party geologists and geophysicists, among others, to review the available data concerning each potential acquisition. In each case, we expect that the operator of the prospect will assemble the appropriate data and conduct the appropriate studies and that our consultants will conduct an independent review of the operator’s data and studies for purposes of advising us of the merits of each potential acquisition.
The business of oil and gas acquisition, drilling and development is capital intensive and the level of operations attainable by an oil and gas company is directly linked to and limited by the amount of available capital. Therefore, a principal part of our plan of operations is to acquire the additional capital required to finance the acquisition of such properties and our share of the development costs. As explained under “Financial Condition” below, we will seek additional working capital through the sale of our securities and, subject to the successful deployment of our cash on hand, we will endeavor to obtain additional capital through bank lines of credit and project financing.
Financial Condition
As of September 30, 2013, we had total assets of $1,187,689 and negative working capital of $(64,424). In November 2012, we commenced the private placement sale of up to 5,000,000 shares of our common stock at $0.50 per share. To date, we have sold 972,900 shares of our common stock at $0.50 per share, including 890,800 shares for cash consideration of $445,450 and 82,000 shares issued in conversion of $41,000 of shareholder advances. In addition to the capital from the sale of our common shares, our principal shareholder, Gary Bryant, loaned us a total of $547,762 during the fourth fiscal quarter for purposes of financing a portion of the Port Hudson and West Cam 225 acquisitions, including a loan for $417,762, which bears interest on the unpaid principal amount at the rate of 8% per annum and is payable over a four year period at the amortized rate of $10,198 per month, and another loan for $130,000, which bears interest on the unpaid principal amount at the rate of 6% per annum and is payable on January 6, 2015. Our obligations under both loans are secured by our working interest in the Port Hudson field and all principal and interest under each loan is convertible, at the option of the holder, into our common shares at the rate of $0.50 per share.
Our ability to achieve commercial success is dependent on our ability to obtain additional capital either through the additional sale of our equity or debt securities, bank lines of credit, project financing or cash generated from oil and gas operations. We will seek to obtain additional working capital through the sale of our securities and, subject to the successful deployment of our cash on hand, we will endeavor to obtain additional capital through bank lines of credit and project financing. However, we have no agreements or understandings with any third parties at this time for our receipt of additional working capital and we have no history of generating cash from oil and gas operations. We may not be able to obtain access to capital as and when needed and, if so, the terms of any available financing may not be subject to commercially reasonable terms.
Off-Balance Sheet Arrangements
We do not have any off-balance sheet financing arrangements.
Item 7A.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Not applicable.
Item 8.
Item 8. Financial Statements and Supplementary Data
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and
Stockholders of West Texas Resources, Inc.
We have audited the accompanying balance sheets of West Texas Resources, Inc. as of September 30, 2013 and 2012, and the related statements of operations, stockholders’ equity, and cash flows for each of the two years in the period ended September 30, 2013. West Texas Resources, Inc.’s management is responsible for these financial statements. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. 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 also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, 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 financial statements referred to above present fairly, in all material respects, the financial position of West Texas Resources, Inc. as of September 30, 2013 and 2012, and the results of its operations and its cash flows the years ended September 30, 2013 in conformity with accounting principles generally accepted in the United States of America.
/s/ Farber Hass Hurley LLP
Granada Hills, California
January 14, 2014
West Texas Resources, Inc.
Balance Sheets
See accompanying notes to these financial statements.
West Texas Resources, Inc.
STATEMENTS OF OPERATIONS
See accompanying notes to these financial statements.
West Texas Resources, Inc.
STATEMENTS OF SHAREHOLDERS' EQUITY
For the Years Ended September 30, 2013 and
See accompanying notes to these financial statements.
West Texas Resources, Inc.
STATEMENTS OF CASH FLOWS
See accompanying notes to these financial statements
WEST TEXAS RESOURCES, INC.
NOTES TO FINANCIAL STATEMENTS
September 30, 2013 and 2012
1. Organization and Summary of Significant Accounting Policies
Organization and business
West Texas Resources, Inc., a Nevada corporation (the “Company”), was incorporated under the laws of Nevada on December 9, 2010 under the name Texas Resources Energy, Inc. On June 30, 2011, the Company changed its name to West Texas Resources, Inc. The Company is engaged in the acquisition, exploration and development of oil and gas properties in North America.
The Company is no longer considered to be in the development stage as principal operations have commenced and significant income has been recognized. As such, the cumulative amounts and other disclosure required for development stage companies are omitted in the September 30, 2013 statements.
Oil and gas properties
The Company uses the successful efforts method of accounting for oil and gas producing activities. Costs to acquire mineral interests in oil and gas properties, to drill and equip exploratory wells that find proved reserves, to drill and equip development wells and related asset retirement costs are capitalized. Costs to drill exploratory wells that do not find proved reserves, geological and geophysical costs, and costs of carrying and retaining unproved properties are expensed.
Unproved oil and gas properties that are individually significant are periodically assessed for impairment of value, and a loss is recognized at the time of impairment by providing an impairment allowance. Other unproved properties are amortized based on the Company's experience of successful drilling and average holding period. Capitalized costs of producing oil and gas properties, after considering estimated residual salvage values, are depreciated and depleted by the unit-of-production method.
On the sale or retirement of a complete unit of a proved property, the cost and related accumulated depreciation, depletion, and amortization are eliminated from the property accounts, and the resultant gain or loss is recognized. On the retirement or sale of a partial unit of proved property, the cost is charged to accumulated depreciation, depletion, and amortization with a resulting gain or loss recognized in income. On the sale of an entire interest in an unproved property for cash or cash equivalent, gain or loss on the sale is recognized, taking into consideration the amount of any recorded impairment if the property had been assessed individually. If a partial interest in an unproved property is sold, the amount received is treated as a reduction of the cost of the interest retained.
Impairment of long-lived assets
The Company accounts for the impairment and disposition of long-lived assets in accordance with ASC 360-10-35, Impairment or Disposal of Long-Lived Assets. In accordance with ASC 360-10-35, long-lived assets are reviewed for events of changes in circumstances, which indicate that their carrying value may not be recoverable. During the year ended September 30, 2013, the Company determined that the investment in one of its oil and gas properties was impaired due to an unsuccessful fracking process. Accordingly, the Company recorded impairment loss of $108,373 for the capitalized fracking costs.
Asset retirement obligations
ASC 410-20, Asset Retirement Obligations, clarifies that a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. The obligation to perform the asset retirement activity is unconditional even though uncertainty exists about the timing and/or method of settlement. ASC 410-20 requires a liability to be recognized for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated.
WEST TEXAS RESOURCES, INC.
NOTES TO FINANCIAL STATEMENTS
September 30, 2013 and 2012
Cash, cash equivalents, and other cash flow statement supplemental information
The Company considers all liquid investments with an original maturity of three months or less that are readily convertible into cash to be cash equivalents. The Company places its cash equivalents with high credit quality financial institutions. Accounts at these institutions are insured by the Federal Deposit Insurance Corporation (FDIC) up to $250,000. The Company performs ongoing evaluations of these institutions to limit its concentration of risk exposure. Management believes this risk is not significant due to the financial strength of the financial institutions utilized by the Company.
Furniture, fixtures and equipment
Furniture, fixtures and equipment are carried at cost depreciated using the straight-line method over their estimated useful lives. Gain or loss on retirement or sale or other disposition of these assets is included in income in the period of disposition.
Use of estimates
The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect certain reported amounts and disclosures. Accordingly, actual results could differ from those estimates.
Income taxes
The Company reports certain expenses differently for financial and tax reporting purposes and, accordingly, provides for the related deferred taxes. Income taxes are accounted for under the liability method in accordance with ASC 740, Income Taxes.
Management has considered its tax positions and believes that all of the positions taken by the Company in its Federal and State tax returns are more likely than not to be sustained upon examination. The Company is subject to examination by U.S. Federal and State tax authorities from 2010 to the present, generally for three years after they are filed.
Basic and diluted net income (loss) per share
Basic net income (loss) per share is based upon the weighted average number of common shares outstanding. Diluted net income (loss) per share is based on the assumption that all dilutive convertible shares and stock options were converted or exercised. Dilution is computed by applying the treasury stock method. Under this method, options and warrants are assumed to be exercised at the beginning of the period (or at the time of issuance, if later), and as if funds obtained thereby were used to purchase common stock at the average market price during the period. For years ended September 30, 2013 and 2012, all common stock equivalents were anti-dilutive.
WEST TEXAS RESOURCES, INC.
NOTES TO FINANCIAL STATEMENTS
September 30, 2013 and 2012
Stock-based payments
Compensation costs for all share-based awards are measured based on the grant date fair value and are recognized over the vesting period. The Company has no awards with market or performance conditions. Excess tax benefits will be recognized as an addition to additional paid-in-capital.
Fair value of financial instruments
The accounting standards regarding fair value of financial instruments and related fair value measurements defines financial instruments and requires disclosure of the fair value of financial instruments held by the Company. The Company considers the carrying amount of cash and other current assets and liabilities to approximate their fair values because of the short period of time between the origination of such instruments and their expected realization.
The Company has also adopted ASC 820-10 which defines fair value, establishes a three-level valuation hierarchy for disclosures of fair value measurement and enhances disclosure requirements for fair value measures. The three levels are defined as follows:
·Level 1 inputs to the valuation methodology are quoted prices (unadjusted) for identical assets or liabilities in active markets.
·Level 2 inputs to the valuation methodology include quoted prices for similar assets and liabilities in active markets, and inputs that are observable for the assets or liability, either directly or indirectly, for substantially the full term of the financial instruments.
·Level 3 inputs to the valuation methodology are unobservable and significant to the fair value.
As of September 30, 2013 and 2012, the Company did not identify any assets or liabilities that are required to be presented on the balance sheet at fair value in accordance with ASC 820-10.
Recent Accounting Pronouncements
In July 2012, the Financial Accounting Standards Board (“FASB”) issued ASU 2012-02, Intangibles-Goodwill and Other (Topic 350): Testing Indefinite-Lived Intangible Assets for Impairment, to simplify the manner in which entities test indefinite-lived intangible assets for impairment. The ASU permits an entity to first assess qualitative factors to determine whether events and circumstances indicate that it is more likely than not that the indefinite-lived intangible asset is impaired as a basis for determining whether it is necessary to perform a quantitative impairment test. The ASU is effective for annual and interim impairment tests performed for fiscal years beginning after September 15, 2012, with early adoption permitted. The implementation of the standard did not have a significant impact on the Company’s financial statements.
WEST TEXAS RESOURCES, INC.
NOTES TO FINANCIAL STATEMENTS
September 30, 2013 and 2012
2. Equipment
In August 2011, the Company purchased a water truck for $35,759 cash. In October 2011, the Company's water truck was placed in service pursuant to a lease arrangement with an unaffiliated third party. The lease required the lessee to pay the Company $2,500 per month plus 10% of the revenue collected by the lessee from its use or sublease of the truck. The lease was for a term of two years and the lessee had the option to purchase the truck at the end of the lease term for 75% of the Company's purchase price. During the year ended September 30, 2012, the Company terminated the lease and wrote off the lease income receivable of $5,616 as bad debt expense due to the lessee’s cash flow problems.
The Company calculated the depreciation of the truck using straight-line method with a useful life of three years. For the three months ended December 31, 2012, the Company recorded depreciation expense of $2,980.
On December 31, 2012, the Company entered into an agreement with a third party to sell the water truck for a cash amount of $25,000 and recorded a receivable of $21,316, net of a replacement cost of tires of $3,684. The Company received cash of $21,316 as full payment of the sale on January 3, 2013. In addition, the Company paid $4,858 in title fees and commission for selling the water truck in January 2013. For the year ended September 30, 2013, the Company recorded loss on the disposal of a fixed asset of $5,265.
3. Oil and Gas Properties
In September 2011, the Company acquired a 31.25% working interest in an exploratory oil and gas drilling prospect covering 120 acres in Eastland County, Texas, for $127,123 cash.
In October 2011, the operator of the Company's Eastland County prospect began drilling and fracturing operations. As of September 30, 2013, no revenue has yet to be derived from the wells.
During the year ended September 30, 2013, the Company determined that the investment in the Eastland County oil and gas properties was impaired due to unsuccessful fracking process. Accordingly, the Company recorded impairment loss of $108,373 to write off the capitalized fracking costs. In addition, the Company determined and recorded its share of the asset retirement obligation of $10,000 for the year ended September 30, 2013.
Effective April 1, 2013, the Company acquired a 7.24625% working interest in the oil and gas leases, wells and attendant production in the Port Hudson field, Baton Rouge Parish, Louisiana, for a total consideration of $702,900. The Port Hudson field has three producing wells with estimated total remaining recoverable proved developed producing reserves of 294,000 bbls and 229,000 bbls of proven developed behind pipes reserves. The wells are currently producing approximately 290 bbls per day. The Company’s working interest is subject to certain overriding royalty interests, subject to which it has a 5.65158% net revenue interest in the Port Hudson Field. The Company also assessed the asset retirement obligation on the Port Hudson field. Because the total cost of abandonment for the producing wells and related facilities will be substantially offset by the salvage value of the tangible equipment, the remaining costs will be insignificant. As a result, the Company did not record asset retirement obligation for the year ended September 30, 2013.
WEST TEXAS RESOURCES, INC.
NOTES TO FINANCIAL STATEMENTS
September 30, 2013 and 2012
On September 6 , 2013, the Company acquired a 10.0167% working interest (7.2120% net revenue interest) in an offshore oil and gas field, known as West Cam 225, located in the shallow waters of the Gulf of Mexico near Cameron, Louisiana. The Company’s purchase price for the working interest was $50,000. In addition to the purchase price, the Company paid $230,459 to the operator of the West Cam 225 field in payment of the Company’s allocable share of the costs for development. Pursuant to the operating agreement, a fee of $0.31 per MCF is to be deducted from production revenue as accrual of asset retirement fund. The Company did not record asset retirement obligation for the year ended September 30, 2013.
As of September 30, 2013 and 2012, total oil and gas properties amounted to $1,002,109 and $145,873, respectively.
4. Notes Payable
Related Party Notes Payable
On August 14, 2013, the Company entered into a loan agreement with a shareholder, Gary Bryant, pursuant to which Mr. Bryant loaned the Company $417,762, the proceeds of which were used to partially finance the acquisition of the Port Hudson interest described in Note 3 above. The loan bears interest on the unpaid principal amount at the rate of 8% per annum. All principal and interest are payable over a four year period, commencing November 1, 2013, at the amortized rate of $10,198 per month. The Company’s obligations under the loan are secured by its working interest in the Port Hudson field.
On September 6, 2013, the Company entered into another loan agreement with Mr. Gary Bryant, pursuant to which Mr. Bryant loaned the Company $130,000, the proceeds of which were used to partially finance the Company’s payment of its allocable expenses associated with its working interest in the West Cam 225 field, described in Note 3 above. The loan bears interest on the unpaid principal amount at the rate of 6% per annum. All principal and interest were payable on December 6, 2013 and are convertible into shares of the Company’s common stock, at the option of the holder, at the rate of $0.50 per share. The Company’s obligations under the loan are secured by its working interest in the Port Hudson field. At the same time, the Company entered into an amendment to its loan agreement with Mr. Bryant dated August 14, 2013, in the original principal amount of $417,762, to provide that all principal and interest under that loan agreement are convertible into shares of the Company’s common stock, at the option of the holder, at the rate of $0.50 per share.
Other Notes Payable
On September 6, 2013, the Company entered into a second loan agreement with an unrelated party pursuant to which the lender loaned the Company $100,000, the proceeds of which were used to partially finance the Company’s payment of its allocable expenses associated with its working interest in the West Cam 225 field, described in Note 3 above. The loan bears interest on the unpaid principal amount at the rate of 6% per annum. All principal and interest were payable on November 5, 2013. The Company’s obligations under the loan are secured by its working interest in the West Cam 225 field. In connection with the loan, the Company granted the lender a warrant to purchase 200,000 shares of its common stock, at an exercise price of $0.50 per share, over a two year period expiring on September 5, 2015.
WEST TEXAS RESOURCES, INC.
NOTES TO FINANCIAL STATEMENTS
September 30, 2013 and 2012
The Company determined that the fair value of the above conversion options and the warrants using the Black - Scholes model with the variables listed below:
·Volatility: 160%
·Risk free rate of return: 0.01% to 0.875%
·Expected term: 0.25 to 4 years
In connection with the issuance of the above notes, the Company recorded a note discount of $647,762, which is to be amortized over the lives of the notes. For the year ended September 30, 2013, the Company recorded amortization of note discount of $106,388 as interest expense.
As of the date of this report, the $417,762 note due to Mr. Gary Bryant is current. The maturity date of the $130,000 note has been extended to January 6, 2015. For the $100,000 noted due to the unrelated party, the Company has repaid $70,000 and the maturity date of the outstanding balance of $30,000 has been extended to March 5, 2014.
5. Shareholder Advances
During the years ended September 30, 2013 and 2012, a shareholder advanced a total amount of $21,000 and $35,000, respectively, as advances to the Company to support its daily operations. These advances are due on demand and do not bear any interest. In the fiscal year 2013, $41,000 of shareholder advances were converted into 82,000 shares of the Company’s common stock. As of September 30, 2013 and 2012, the total outstanding amount due to the shareholder was $15,000 and $35,000, respectively.
6. Shareholders’ Equity
The Company is authorized to issue 200,000,000 shares of common stock, par value of $0.001, and 10,000,000 shares of preferred stock, par value of $0.001.
Between January 2011 and October 2012, the Company conducted the private placement sale of 962,000 shares of its common stock at $.25 per share for the gross proceeds of $240,500. No commissions were incurred with respect to the sale of those shares.
In November 2012, the Company commenced the private placement sale of up to 5,000,000 shares of its common stock at $0.50 per share. The shares are being offered by the Company’s executive officers on a straight best-efforts basis and no commissions will be paid to the Company’s executive officers. However, in the event the Company engages finders or FINRA member firms, the Company expects to pay finders’ fees or sales commissions of up to 10% of the gross offering proceeds. During the year ended September 30, 2013, the Company entered into various subscription agreements with accredited investors to sell 972,900 shares of the Company’s common stock at $0.50 per share, including 82,000 share of common stock that were issued in conversion of $41,000 of shareholder advances referred to in Note 5 above. The total amount of $445,450 of cash proceeds was received upon signing of the subscription agreements.
WEST TEXAS RESOURCES, INC.
NOTES TO FINANCIAL STATEMENTS
September 30, 2013 and 2012
As of September 30, 2013 and 2012, the Company had 14,079,400 and 13,106,500 shares of common stock issued and outstanding and had not issued any of its preferred stock.
On September 15, 2011, the Company adopted the West Texas Resources, Inc. 2011 Stock Incentive Plan (the “Plan”) providing for the grant of non-qualified stock options and incentive stock options to purchase its common stock and for grant of restricted and unrestricted grants. The Company has reserved 3,000,000 shares of its common stock under the Plan. All officers, directors, employees and consultants to the Company are eligible to participate under the Plan. The purpose of the Plan is to provide eligible participants with an opportunity to acquire an ownership interest in the Company.
The Company granted options to certain consultants to purchase 400,000 shares of the Company’s common stock. The options vest immediately and expire on September 15, 2016. The fair value of each share-based award was estimated using the Black-Scholes option pricing model or a lattice model. The fair value of these options, determined to be $65,402, was included in general and administrative expenses for the year ended September 30, 2011.
The following assumptions were used in the fair value method calculation:
·Volatility: 83%
·Risk free rate of return: 1%
·Expected term: 5 years
The following information applies to all options outstanding at September 30, 2013:
·Weighted average exercise price: $0.25
·Options outstanding and exercisable: 400,000
·Average remaining life: 3.0 years
7. Supplementary Oil and Gas Information (unaudited)
Proved oil and gas reserve quantities are based on estimates prepared by management on behalf of West Texas Resources in accordance with guidelines established by the Securities and Exchange Commission (SEC).
There are numerous uncertainties inherent in estimating quantities of proved reserves and projecting future rates of production and timing of development expenditures. The following reserve data represents those estimates only and should not be construed as being exact.
All of the reserves are located in the United States.
WEST TEXAS RESOURCES, INC.
NOTES TO FINANCIAL STATEMENTS
September 30, 2013 and 2012
The information for the Company’s interests of reserves as of September 30, 2013 are as follows:
Net Remaining reserves
Total Proved Net Developed Reserves
8. Subsequent Events
Events subsequent to September 30, 2013 have been evaluated through the date these financial statements were issued to determine whether they should be disclosed to keep the financial statements from being misleading. The following events occurred since September 30, 2013:
·In November 2013, Mr. Gary Bryant advanced to the Company $15,000 to support its daily operations. These advances are due on demand and do not bear any interest. As of the date of the report, the advances are outstanding.
Item 9.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Not applicable.
Item 9A.
Item 9A. Controls and Procedures
(a) Evaluation of Disclosure Controls and Procedures.
Our management, with the participation of our chief executive officer and chief financial officer evaluated the effectiveness of our disclosure controls and procedures pursuant to Rule 15a-15 under the Securities Exchange Act of 1934, as amended (the “Exchange Act”). Based upon that evaluation, our management, including our chief executive officer and chief financial officer, concluded that for the reasons described below our disclosure controls and procedures were not effective as of September 30, 2013 in ensuring all material information required to be filed has been made known in a timely manner.
(b) Changes in internal control over financial reporting.
There were no changes to our internal control over financial reporting, as defined in Rules 15a-15(f) under the Exchange Act that occurred during the fiscal quarter ended September 30, 2013 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
(c) Management’s report on internal controls over financial reporting.
Our management is responsible for establishing and maintaining adequate internal controls over financial reporting, as defined under Rule 15a-15(f) under the Exchange Act. Our management has assessed the effectiveness of our internal controls over financial reporting as of September 30, 2013 based on the framework established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). Our internal control system was designed to provide reasonable assurance to our management and board of directors regarding the preparation and fair presentation of published financial statements. An internal control material weakness is a significant deficiency, or aggregation of deficiencies, that does not reduce to a relatively low level the risk that material misstatements in financial statements will be prevented or detected on a timely basis by employees in the normal course of their work. Our management assessed the effectiveness of our internal control over financial reporting as of September 30, 2013, and this assessment identified the following material weaknesses in our internal control over financial reporting:
·Due to our small size, we do not maintain effective internal controls to assure segregation of duties as we have only two employees who are responsible for initiating and approving of transactions, thereby creating the segregation of duties weakness;
·Our board of directors does not have an audit committee or a financial expert to maintain effective oversight of our financial reporting process; and
·Lack of formal policies or procedures to provide assurance that relevant information is identified, captured, processed, and reported in an appropriate and timely fashion.
Based on that evaluation, management concluded that our internal control over financial reporting was not effective as of September 30, 2013.
This annual report does not include an attestation report of our registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by our registered public accounting firm pursuant to the rules of the Securities and Exchange Commission that permit us to provide only management’s report in this annual report.
Item 9B.
Item 9B. Other Information
Not applicable.
PART III
Item 10.
Item 10. Directors, Executive Officers and Corporate Governance
Set forth below are our directors and officers.
Mr. Jones has served as our chairman of the board and president and chief executive officer since our founding on December 9, 2010. From February 2010 to December 2010, Mr. Jones also served as president and chief executive officer of Russian Resources Energy, Inc. Mr. Jones has served as vice president of mergers and acquisitions for Newport Capital Consultants, Inc., a Bartonville, Texas based financial and management and consulting firm, since 2004. Mr. Jones holds a BSB degree in marketing from Oklahoma City University.
Mr. Kerr has served as our chief financial officer and a member of our board of directors since our founding on December 9, 2010. For over the past five years, Mr. Kerr has served as a vice president of Newport Capital Consultants, Inc.
Mr. Jones and Mr. Kerr are each the son-in-law of Gary Bryant, our principal stockholder. Mr. Bryant is the chief executive officer and owner of Newport Capital Consultants, Inc. Newport Capital Consultants, Inc. is an affiliate of our company.
Mr. Jones and Mr. Kerr have each committed to provide their full time to our company, however from our inception to date, and until such time as we receive significant additional capital, their duties to our company will not require their full business time. Until such time as they are required to provide their full time to our company, they will continue to provide services on a limited basis to Newport Capital Consultants, provided that their provision of services to Newport Capital Consultants does not interfere with or otherwise impair their provision of services to our company.
Audit and Compensation Committees
As of the date of this report, we have not established an audit or compensation committee in light of the fact that all of our directors also serve as executive officers of our corporation.
Code of Ethics
We have adopted a code of ethics for all our employees, including our chief executive officer, principal financial officer and principal accounting officer or controller, and/or persons performing similar functions.
Limitation of Liability of Directors and Indemnification of Directors and Officers
Nevada corporate law provides that corporations may include a provision in their articles of incorporation relieving directors of monetary liability for breach of their fiduciary duty as directors, provided that such provision shall not eliminate or limit the liability of a director (i) for any breach of the director's duty of loyalty to the corporation or its stockholders, (ii) for acts or omissions not in good faith and which involve a breach of the director’s duty to the corporation or intentional misconduct or a knowing violation of law, (iii) for unlawful payment of a dividend or unlawful stock purchase or redemption, or (iv) for any transaction from which the director derived an improper personal benefit. Our articles of incorporation provides that directors are not liable to us or our stockholders for monetary damages for breach of their fiduciary duty as directors to the fullest extent permitted by Nevada law. In addition to the foregoing, our bylaws provide that we may indemnify directors, officers, employees or agents to the fullest extent permitted by law and we have agreed to provide such indemnification to each of our directors.
The above provisions in our articles of incorporation and bylaws and in the written indemnity agreements may have the effect of reducing the likelihood of derivative litigation against directors and may discourage or deter stockholders or management from bringing a lawsuit against directors for breach of their fiduciary duty, even though such an action, if successful, might otherwise have benefited us and our stockholders. However, we believe that the foregoing provisions are necessary to attract and retain qualified persons as directors.
Insofar as indemnification for liabilities arising under the Securities Act may be permitted to our directors, officers and controlling persons pursuant to the foregoing provisions, or otherwise, we have been advised that in the opinion of the Securities and Exchange Commission, such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable.
Item 11.
Item 11. Executive Compensation
Summary Compensation Table
The following table sets forth the compensation paid by us to our chief executive officer and to all other executive officers for services rendered during the fiscal years ended September 30, 2013 and 2012.
Narrative Disclosure to Summary Compensation Table
We have no employment agreements with executive management. Prior to November 30, 2011, neither of our executive officers received any compensation for their services to the company, other than our award of an option to purchase 200,000 shares of our common stock to our chief financial officer, John Kerr. Commencing December 1, 2011, each of our executive officers receives a salary of $3,000 per month. Our executive officers are not entitled to receive any other compensatory benefits or consideration, such as medical or life insurance, car allowances or the like. At such time as our executive officers provide their full business time to our company on a continuous basis, we expect to adjust upward the compensation and benefits payable to our executive officers appropriately.
Outstanding Equity Awards at September 30, 2013
Compensation of Directors
We have not paid any directors’ fees or other compensation to our directors for their services as directors. All of our directors receive reimbursement for out-of-pocket expenses for attending board of directors meetings. We intend to appoint additional members to the board of directors, including outside or non-officer members to the board. There are no understandings or arrangements at this time concerning the appointment of additional directors to our board, and we do not expect to be able to attract directors with significant oil and gas experience until such time as we raise significant additional capital. Any future outside directors may receive an attendance fee for each meeting of the board of directors. From time to time we may also engage certain future outside members of the board of directors to perform services on our behalf and we will compensate such persons for the services which they perform.
Section 16(A) Beneficial Ownership Reporting Compliance
Because our common stock is not registered under the Exchange Act, our officers, directors and 10% stockholders are not required to file with the SEC beneficial ownership reports under Section 16 of the Exchange Act.
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
The following table sets forth certain information regarding the beneficial ownership of our common stock as of the date of this report by:
·each person who is known by us to be the beneficial owner of more than five percent (5%) of our issued and outstanding shares of common stock;
·each of our directors, executive officers and nominees to become directors; and
·all directors and executive officers as a group.
(1)The percentage amounts for each reported person are based on 14,079,400 common shares issued and outstanding as of the date of this report.
(2)The address for the stockholder is 5729 Lebanon Road, Suite 144, Frisco, Texas 75034.
(3)The shares for John D. Kerr include 200,000 shares underlying a presently exercisable option.
(4)Gary and Suzanne Bryant are married, however they disclaim any interest in the shares held by the other. The address for the Gary and Suzanne Bryant is 980 Noble Champions Way, Bartonville, Texas 76226.
(5)The address for the Danilo Cacciamatta is 1360 Temple Hills Dr., Laguna Beach, CA 92651.
Item 13.
Item 13. Certain Relationships and Related Transactions, and Director Independence
Related Party Transactions, Promoters and Director Independence
In addition to our executive officers and directors, Mr. Gary Bryant may be deemed to be a promoter of our company. Mr. Bryant and his wife, Suzanne Bryant, each purchased 100,000 shares of our common stock, at a purchase price of $0.25 per share, in connection with our 2011 private placement of common shares. From time to time, Mr. Bryant provides us with advances of funds. The advances are unsecured and do not accrue interest on the principal amount. During the fiscal year ended September 30, 2013, Mr. Bryant agreed to convert $41,000 of advances into 82,000 shares of our common stock at the rate of $0.50 per share. At the same time, Mr. Bryant purchased 24,000 shares of our common at a price of $0.50 per share. As of September 30, 2013 and 2012, the total outstanding amount of advances from Mr. Bryant were $15,000 and $35,000, respectively.
In addition to the advances provided by Mr. Bryant, during the fourth fiscal quarter of 2013 Mr. Bryant loaned us a total of $547,762 for purposes of financing a portion of the Port Hudson and West Cam 225 acquisitions, including a loan for $417,762, which bears interest on the unpaid principal amount at the rate of 8% per annum and is payable over a four year period at the amortized rate of $10,198 per month, and another loan for $130,000, which bears interest on the unpaid principal amount at the rate of 6% per annum and is payable on January 6, 2015. Our obligations under both loans are secured by our working interest in the Port Hudson field and all principal and interest under each loan is convertible, at the option of the holder, into our common shares at the rate of $0.50 per share.
Except for above-mentioned advances, loans and stock purchases by Mr. and Mrs. Bryant, and compensation paid or payable by us to our executive officers and reported elsewhere in this report, we have not entered into any other transactions of any value with any of our directors, officers, principal stockholders, promoters or any of their family members or affiliates, including entities of which they are also officers or directors or in which they have a financial interest. We have, however, adopted a policy that any transactions that we might enter into with related parties or promoters will only be on terms consistent with industry standards and approved by a majority of the disinterested directors of our board.
Item 14.
Item 14. Principal Accountant Fees and Services
The following table sets forth the aggregate fees billed to us for services rendered to us for the years ended September 30, 2013 and 2012 by our independent registered public accounting firm, Farber Hass Hurley LLP, for the audit of our consolidated financial statements for the years ended September 30, 2013 and 2012, and assistance with the reporting requirements thereof, the review of our condensed consolidated financial statements included in our quarterly reports on Form 10-Q, the filing of our Form 8-K, the filing of our Form S-1and accounting and auditing assistance relative to acquisition accounting and reporting.
PART IV
Item 15.
Item 15. Exhibits and Financial Statement Schedules
(a) Financial statements
Reference is made to the Index and Financial Statements under Item 8 in Part II hereof where these documents are listed.
(b) Financial statement schedules
Financial statement schedules are either not required or the required information is included in the consolidated financial statements or notes thereto filed under Item 8 in Part II hereof.
(c) Exhibits
The exhibits to this Annual Report on Form 10-K are set forth below. The exhibit index indicates each management contract or compensatory plan or arrangement required to be filed as an exhibit.
Number
Exhibit Description
Method of Filing
3.1
Articles of Incorporation of the Registrant
Incorporated by reference from the Registrant’s Registration Statement on Form S-1 filed on December 9, 2011.
3.2
Amendment to Articles of Incorporation of the Registrant
Incorporated by reference from the Registrant’s Registration Statement on S-1 filed on December 9, 2011.
3.3
Bylaws of the Registrant
Incorporated by reference from the Registrant’s Registration Statement on S-1 filed on December 9, 2011.
10.1
West Texas Resources, Inc. 2011 Stock Incentive Plan*
Incorporated by reference from the Registrant’s Registration Statement on S-1 filed on December 9, 2011.
10.2
Lease Agreement dated August 22, 2011 between Registrant and Bay Energy Services, Inc.
Incorporated by reference from the Registrant’s Registration Statement on S-1 filed on December 9, 2011.
10.3
Form of Registration Rights Agreement dated January 24, 2011 between Registrant and Selling Stockholders
Incorporated by reference from the Registrant’s Registration Statement on S-1 filed on December 9, 2011.
10.4
Assignment dated September 30, 2011 between Registrant and West Texas Royalties, Inc.
Incorporated by reference from the Amendment No. 1 to Registrant’s Registration Statement on S-1 filed on January 23, 2012.
10.5
Joint Operating Agreement between Registrant and West Texas Royalties, Inc.
Incorporated by reference from the Amendment No. 1 to Registrant’s Registration Statement on S-1 filed on January 23, 2012.
10.6
Letter Agreement dated July 3, 2013 between the Registrant and Wells Fargo Energy Capital, Inc.
Incorporated by reference from the Registrant’s Quarterly Report on Form 10-Q filed on August 19, 2013
10.7
Letter Agreement dated August 1, 2013 between Registrant and Gulfex Resources, LLC
Incorporated by reference from the Registrant’s Quarterly Report on Form 10-Q filed on August 19, 2013
10.8
Loan Agreement dated August 14, 2013 between Registrant and Gary Bryant
Incorporated by reference from the Registrant’s Quarterly Report on Form 10-Q filed on August 19, 2013
10.9
Promissory Note dated August 14, 2013 made by Registrant in favor of Gary Bryant
Incorporated by reference from the Registrant’s Quarterly Report on Form 10-Q filed on August 19, 2013
10.10
Letter Agreement dated August 16, 2013 between Registrant and Enovation Resources LLC.
Incorporated by reference from the Registrant’s Quarterly Report on Form 10-Q filed on August 19, 2013
10.11
Loan Agreement dated September 5, 2013 between Registrant and Gary Bryant, as amended on January 10, 2014
Filed electronically herewith
10.12
Loan Agreement dated September 5, 2013 between Registrant and Lake Oswego Oil Company, LLC, as amended on January 10, 2014.
Filed electronically herewith
14.1
West Texas Resources, Inc. Code of Ethics
Incorporated by reference from the Registrant’s Annual Report on Form 10-K filed on January 14, 2013
21.1
List of subsidiaries of Registrant.
Incorporated by reference from the Registrant’s Registration Statement on S-1 filed on December 9, 2011.
31.1
Certification under Section 302 of the Sarbanes-Oxley Act of 2002.
Filed electronically herewith.
31.2
Certification under Section 302 of the Sarbanes-Oxley Act of 2002.
Filed electronically herewith.
32.1
Certifications Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350.
Filed electronically herewith.
101.INS**
XBRL Instance Document
Filed electronically herewith
101.SCH**
XBRL Taxonomy Extension Schema Document
Filed electronically herewith
101.CAL**
XBRL Taxonomy Extension Calculation Linkbase Document
Filed electronically herewith
101.LAB**
XBRL Taxonomy Extension Label Linkbase Document
Filed electronically herewith
101.PRE**
XBRL Taxonomy Extension Presentation Linkbase Document
Filed electronically herewith
101.DEF**
XBRL Taxonomy Extension Definition Linkbase Document
Filed electronically herewith
* Indicates management compensatory plan, contract or arrangement.
** Pursuant to applicable securities laws and regulations, we are deemed to have complied with the reporting obligation relating to the submission of interactive data files in such exhibits and are not subject to liability under any anti-fraud provisions of the federal securities laws as long as we have made a good faith attempt to comply with the submission requirements and promptly amend the interactive data files after becoming aware that the interactive data files fail to comply with the submission requirements. Users of this data are advised that, pursuant to Rule 406T, these interactive data files are deemed not filed and otherwise are not subject to liability.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this annual report on Form 10-K to be signed on its behalf by the undersigned, thereunto duly authorized.
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.
Signature
Title
Date
/s/ Stephen E. Jones
Chief Executive Officer
January 14, 2014
Stephen E. Jones
(Principal Executive Officer)
/s/John D. Kerr
Chief Accounting Officer
January 14, 2014
John D. Kerr
(Principal Financial Officer)