ITEM 1. BUSINESS.
We are an early-stage independent energy company engaged in the acquisition and development of oil in or near established oil-producing areas. We plan to build our cash flow and oil reserves through a focused acquisition and development program by:
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focusing our operations in the hydrocarbon-rich region of east Texas;
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drilling in areas which have a high proportion of oil relative to natural gas;
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lessening risk by concentrating on established areas with proven production; and
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using new screening technology which prevents sand accumulation in the well bores and allows for the recovery of more oil from mature fields.
In December 2011 we completed a $4,800,000 initial public offering. The offering consisted of 4,800,000 Units priced at $1.00 per Unit.
Batson Dome and Hull-Daisetta fields
Pursuant to three agreements, we acquired oil and gas leases covering 230 acres in the Batson Dome Field in Hardin County, Texas. In the first agreement, and in consideration for the assignment of a 40% working interest (32% net revenue interest) in leases covering 220 acres, we paid $40,000 in cash and issued a promissory note in the principal amount of $285,668. In the second agreement, and in consideration for the assignment of a 50% working interest (40% net revenue interest) in leases covering the same 220 acres, we paid $50,000 in cash and issued a promissory note in the principal amount of $357,085. The notes associated with the first and second agreements bore interest at 8% per year and were repaid in December 2010. In the third agreement, and in payment of $259,247 in cash, we acquired a 90% working interest in 10 acres adjacent to the 220 acres described above, as well as a 90% working interest (63% net revenue interest) in two producing oil wells and three shut- in wells located on the 10- acre lease. The leases and wells subject to the first and third agreements were acquired from C.F.O., Inc., a corporation controlled by Delton Drum, one of our officers. C.F.O., Inc. owns the remaining 10% working interest in the leases covering the 230 acres.
By agreement dated March 15, 2011, we entered into a farmout agreement with an unrelated third party pertaining to a 100-acre lease in the Batson Dome Field. Pursuant to the farmout agreement we have the option of drilling wells on the lease; provided however, that if we do not drill at least six wells in any twelve month period our right to drill any additional wells on the lease will terminate. For each well drilled, we will receive a partial assignment of the lease covering the two acres surrounding the well. We will have a 100% working interest (75% net revenue interest) in any wells we drill on the leased acreage. We estimate the cost of drilling and completing any well on this lease will be approximately $500,000. As of November 30, 2012, we had drilled three wells on this lease.
By agreement dated May 25, 2011, we entered into a farmout agreement with Exxon/Mobil Corporation pertaining to another 100-acre lease in the Batson Dome Field. Pursuant to the agreement, we have the obligation to commence drilling a well on the lease by June 14, 2013. Subject to the commencement of drilling the first well by June 14, 2013, and completing the well if we consider it to be productive of oil, we have the option of drilling additional wells on the lease; provided, however, that unless we commence drilling each well within 180 days of the date we complete or abandon the latest well drilled, our right to drill any additional wells on the lease will terminate. For each well drilled, we will receive a partial assignment of the lease covering the acreage surrounding the well. We will have a 100% working interest (75% net revenue interest) in any wells we drill on the leased acreage. We estimate the cost of drilling and completing any well on this lease will be approximately $1,000,000. As of November 30, 2012, we had not commenced any drilling operations on the lease subject to the farmout agreement.
Exxon/Mobil has the right to purchase any oil produced from any wells drilled on the lease. If Exxon/Mobil exercises this right, the price for any oil purchased will be based upon the price posted by Exxon/Mobil, in its discretion, or in the alternative, the market price for oil in the area, after deduction for costs of gathering, storing, dehydrating, treating, processing and transporting the oil. Although the agreement with Exxon/Mobil does not specify how the ‘‘posted’’ price will be determined, in the area of our wells the posted price typically approximates the price published by the New York Mercantile Exchange for West Texas Intermediate Crude Oil. If ExxonMobil, does not post the price, then any purchase will be at the market value price as determined by ExxonMobil, at the well, after deduction of all costs of gathering, storing, dehydrating, treating, processing, and transporting oil. However, we may elect to provide ExxonMobil with any bona fide term purchase offer for oil to be used in future market value determinations and ExxonMobil will consider any offer in determining the market value price.
By agreement dated January 6, 2012, we entered into a three-year farmout agreement with an unrelated third party pertaining to another 70-acre lease in the Batson Dome Field. We estimate the cost of drilling and completing any well on this lease will be approximately $1,000,000.
The Batson Dome Field is located in Hardin County, Texas approximately 50 miles northeast of Houston, and has multiple production zones. The oil produced from the field is light, sweet, high-quality crude with a specific gravity of 21 to 35 degrees. This field lies in flat wooded areas which allow easy access for the drilling and maintenance of wells. There are no significant man-made improvements other than oil wells and related equipment. There are no nearby residences.
The Batson Dome Field draws oil and negligible amounts of gas from an anhydrite and limestone reservoir in a caprock structure above a salt dome in the Miocene and Oligocene formations. Along with three other highly prolific salt dome fields-Spindletop, Sour Lake, and Humble-the Batson Dome Field helped to establish the basis of the Texas oil industry when these shallow fields produced the first Texas Gulf Coast oil.
A salt dome is a mushroom-shaped structure made of salt, commonly having an overlying caprock. Salt domes form as a consequence of the relative buoyancy of salt when buried beneath other types of sediment. The salt flows upward to form salt domes, sheets, pillars and other structures. Oil is commonly found in and around salt domes due to the abundance and variety of traps created by salt movement and the excellent sealing capabilities of salt.
The Batson Dome Field was first drilled in the early 1900s. The salt in the Batson Dome rises to a depth of approximately 800 feet at the cap of the dome, where the first oil was discovered in very shallow wells. Alternating sands and shales form oil reservoirs in the sand dipping away from the cap on all sides of the dome down to a depth of over 7,000 feet. The field has produced oil and a negligible amount of gas from an anhydrite and limestone reservoir in the cap as well as the Miocene and Frio Sands at depths of 400-4,000 feet and the Yegua Sands below 7,000 feet. Since no secondary or enhanced recovery has been attempted over the years, we believe there are opportunities for recovery of substantial undrained reserves through the drilling of new wells with closer spacing and the re-entry of old well bores in currently producing areas.
As mentioned above, we acquired two producing and three shut-in oil wells in the Batson Dome Field. As of November 30, 2012, the two wells were producing approximately one barrel of oil per day, net to our 63% net revenue interest. The three shut-in wells will need to be reworked, at an estimated cost of $125,000 per well, before they can be returned to production. As of November 30, 2012, one of the shut-in wells was being reworked.
As of November 30, 2012, we had drilled and completed twelve wells in the Batson Dome Field. Our share of the costs of drilling and completing these wells was approximately $7,200,000. During the three months ended November 30, 2012, these wells collectively produced approximately 16,000 barrels of oil. Each well has shown multiple potentially productive zones at various depths. In the event production from one zone falls off materially, we have the opportunity to open another zone to compensate for the decline.
By agreement dated May 1, 2012, we entered into a farmout agreement with an unrelated third party pertaining to a 45-acre lease in the Hull-Daisetta Field. Pursuant to the agreement, we have the obligation to commence drilling a well on the lease by January 31, 2013. Subject to the commencement of drilling the first well by January 31, 2013, and completing the well if warranted, we have the option of drilling additional wells on the lease; provided however, that unless we commence drilling each well within 180 days of the date the latest well is completed or abandoned, the right to drill any additional wells on the lease will terminate. We estimate the cost of drilling and completing any well on this lease will be approximately $750,000. As of November 30, 2012, we had not drilled any wells on this lease.
The Hull-Daisetta Field is located in the Liberty County, Texas, about 10 miles south of our Batson Dome Field. The Hull-Daisetta Field includes coverage of a salt dome formation with similar geological characteristics as the Batson salt dome. The field was first drilled in 1918 and has produced over 180 million barrels of oil to date. Our initial lease position is on the edge of the salt dome which contains old shut-in wells that were drilled and successfully produced a number of years ago. Our geologist believes that substantial volumes of oil remain in the field. The expected depths to the dome cap rock on this lease are around 5,000 feet.
The completion of oil wells in established areas, such as the Batson Dome and Hull-Daisetta fields, is, to a certain extent, less risky than drilling for oil in unproven areas where uncertainty exists as to whether relevant amounts of oil exist at all. However, the process of completing an oil well is nevertheless associated with considerable risk.
We plan on drilling and, if warranted, completing additional wells in the Batson Dome and Hull Daisetta fields. The wells will be drilled to a depth of approximately 3,000 to 4,000 feet to the Frio formation. Each well will take approximately ten days to drill and complete. Our share of the drilling and completion costs for each well is estimated to be approximately $450,000. We will have a 90% working interest (63%-67.5% net revenue interest) in any wells we drill in the Batson Dome Field.
Vanguard Net Profits, LLC, a Texas limited liability company (the ‘‘Fund’’), has a 20% net profits interest in the four wells drilled with the proceeds from our November and December 2010 sale of convertible notes. We have a 1% interest in the Fund. Thirty-three private investors hold the remaining 99% interest.
The holders of the convertible notes we sold in 2012 have a security interest in any leases acquired, or wells drilled, with the proceeds from the sale of the notes.
During the period from our inception to September 30, 2010, we did not drill any oil or gas wells.
The table shows the type and number of wells we drilled during the two years ended September 30, 2012.
As of November 30, 2012 we were not drilling or completing any wells, and we were reworking one well.
The following table shows, as of November 30, 2012, our producing wells, developed acreage, and undeveloped acreage, excluding service (injection and disposal) wells:
(1)
Undeveloped acreage includes leasehold interests on which wells have not been drilled or completed to the point that would permit the production of commercial quantities of natural gas and oil regardless of whether the leasehold interest is classified as containing proved undeveloped reserves.
The following table shows, as of November 30, 2012, the status of our gross acreage:
Acres that are Held by Production remain in force so long as oil or gas is produced from one or more wells on the particular lease. Leased acres that are not Held by Production require annual rental payments to maintain the lease until the first to occur of the following: the expiration of the lease or the time oil or gas is produced from one or more wells drilled on the leased acreage. At the time oil or gas is produced from wells drilled on the leased acreage, the lease is considered to be Held by Production.
The following table shows the years our leases, which are not Held By Production, will expire, unless a productive oil or gas well is drilled on the lease.
Proved Reserves
Below are estimates of our net proved reserves as of September 30, 2012, net to our interest. All of our proved reserves are located in Texas.
Estimates of volumes of proved reserves at September 30, 2012 are presented in barrels (Bbls) for oil and, for natural gas, in millions of cubic feet (Mcf) at the official temperature and pressure bases of the areas in which the gas reserves are located.
‘‘Bbl’’ refers to one stock tank barrel, or 42 U.S. gallons liquid volume, in reference to crude oil or other liquid hydrocarbons. ‘‘Mcf’’ refers to one thousand cubic feet. A BOE (i.e., barrel of oil equivalent) combines Bbls of oil and Mcf of gas by converting each six Mcf of gas to one Bbl of oil. Below are estimates of our present value of estimated future net revenues from our proved reserves based upon the standardized measure of discounted future net cash flows relating to proved oil and gas reserves in accordance with the provisions of Accounting Standards Codification Topic 932, Extractive Activities-Oil and Gas. The standardized measure of discounted future net cash flows is determined by using estimated quantities of proved reserves and the periods in which they are expected to be developed and produced based on period-end economic conditions. The estimated future production is based upon benchmark prices that reflect the unweighted arithmetic average of the first-day-of-the-month price for oil and gas during the twelve months period ended September 30, 2012. The resulting estimated future cash inflows are then reduced by estimated future costs to develop and produce reserves based on period-end cost levels. No deduction has been made for depletion, depreciation or for indirect costs, such as general corporate overhead. Present values were computed by discounting future net revenues by 10% per year.
Nova Resources, Inc. prepared the estimates of our proved reserves, future production and income attributable to our leasehold interests as of September 30, 2012. Nova is an independent petroleum engineering firm that provides petroleum consulting services to the oil and gas industry. The estimates of drilled reserves, future production and income attributable to certain leasehold and royalty interests are based on technical analysis conducted by engineers employed at Nova.
Joseph V. Rochefort was the technical person primarily responsible for overseeing the preparation of the reserve report. Mr. Rochefort earned a Bachelor’s Degree in Physics and Geophysics from Texas Christian University and a Masters Degree in Geology from Texas Tech University. Mr. Rochefort has more than 28 years of practical experience in the estimation and evaluation of petroleum reserves.
Delton Drum, our Vice President of Field Operations, oversaw the preparation of the reserve estimates by Nova. Mr. Drum has over 30 years experience in oil and gas exploration and development, with over 15 years of experience in the Batson Dome Field. We do not have a reserve committee and we do not have any specific internal controls regarding the estimates of our reserves.
Our proved reserves include only those amounts which we reasonably expect to recover in the future from known oil and gas reservoirs under existing economic and operating conditions, at current prices and costs, under existing regulatory practices and with existing technology. Accordingly, any changes in prices, operating and development costs, regulations, technology or other factors could significantly increase or decrease estimates of proved reserves.
Proved reserves were estimated by performance methods, the volumetric method, analogy, or a combination of methods utilizing present economic conditions and limited to those proved reserves economically recoverable. The performance methods include decline curve analysis that utilize extrapolations of historical production and pressure data available through September 30, 2012 in those cases where such data were considered to be definitive.
Forecasts for future production rates are based on historical performance from wells currently on production in the region with an economic cut-off for production based upon the projected net revenue being equal to the projected operating expenses. No further reserves or valuation were given to any wells beyond their economic cut-off. Where no production decline trends have been established due to the limited historical production records from wells on the properties, surrounding wells historical production records were used and extrapolated to wells of the property. Where applicable, the actual calculated present decline rate of any well was used to determine future production volumes to be economically recovered. The calculated present rate of decline was then used to determine the present economic life of the production from the reservoir.
For wells currently on production, forecasts of future production rates were based on historical performance data. If no production decline trend has been established, future production rates were held constant, or adjusted for the effects of curtailment where appropriate, until a decline in ability to produce was anticipated. An estimated rate of decline was then applied to economic depletion of the reserves. If a decline trend has been established, this trend was used as the basis for estimating future production rates.
Proved developed non-producing and undeveloped reserves were estimated primarily by the performance and historical extrapolation methods. Test data and other related information were used to estimate the anticipated initial production rates from those wells or locations that are not currently producing. For reserves not yet on production, sales were estimated to commence at a date we determined to be reasonable.
In general, the volume of production from our oil and gas properties declines as reserves are depleted. Except to the extent we acquire additional properties containing proved reserves or conduct successful exploration and development activities, or both, our proved reserves will decline as reserves are produced. Accordingly, volumes generated from our future activities are highly dependent upon the level of success in acquiring or finding additional reserves and the costs incurred in doing so.
Future Operations
We plan to evaluate other undeveloped oil prospects and participate in drilling activities on those prospects which, in our opinion, are favorable for the production of oil. Initially, we plan to concentrate our activities in East Texas. Our strategy is to acquire prospects in or adjacent to existing fields with further development potential and minimal risk in the same area. The extent of our activities will primarily be dependent upon available capital.
If we believe a geographical area indicates geological and economic potential, we will attempt to acquire leases or other interests in the area. We may then attempt to sell portions of our leasehold interests in a prospect to third parties, thus sharing the risks and rewards of the exploration and development of the prospect with the other owners. One or more wells may be drilled on a prospect, and if the results indicate the presence of sufficient oil reserves, additional wells may be drilled on the prospect.
We may also:
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acquire a working interest in one or more prospects from others and participate with the other working interest owners in drilling and if warranted, completing oil wells on a prospect;
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purchase producing oil properties; or
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enter into farmin agreements with third parties. A farmin agreement will obligate us to pay the cost of drilling, and if warranted completing a well, in return for a majority of the working and net revenue interest in the well.
Title to properties which we may acquire will be subject to one or more of the following: royalty, overriding royalty, carried, net profits, working and other similar interests and contractual arrangements customary in the oil industry; liens for current taxes not yet due; and other encumbrances. In the case of undeveloped properties, investigation of record title will be made at the time of acquisition. Title reviews will be obtained before commencement of drilling operations.
Although we normally obtain title reports for oil leases we acquire, we have not in the past obtained, and we may not in the future obtain, title opinions pertaining to leases. A title report shows the history of a particular oil and gas lease, as shown by the records of the county clerk and recorder, state oil or gas commission, or the Bureau of Land Management, depending on the nature of the lease. In contrast, in a title opinion, an attorney expresses an opinion as to the persons or persons owning interests in a particular oil and gas lease.
Government Regulation
Although our sale of oil will not be regulated, federal, state and local agencies have promulgated extensive rules and regulations applicable to our oil exploration, production and related operations. Most states, including Texas, require permits for drilling operations, drilling bonds and the filing of reports concerning operations and impose other requirements relating to the exploration of oil. Texas and other states also have statutes or regulations addressing conservation matters including provisions for the unitization or pooling of oil properties, the establishment of maximum rates of production from oil wells and the regulation of spacing, plugging and abandonment of such wells. The statutes and regulations of Texas and other states limit the rate at which oil is produced from wells. The federal and state regulatory burden on the oil industry increases our cost of doing business and affects our profitability. Because these rules and regulations are amended or reinterpreted frequently, we are unable to predict the future cost or impact of complying with those laws.
As with the oil and natural gas industry in general, our properties are subject to extensive and changing federal, state and local laws and regulations designed to protect and preserve our natural resources and the environment. The recent trend in environmental legislation and regulation is generally toward stricter standards, and this trend is likely to continue. These laws and regulations often require a permit or other authorization before construction or drilling commences and for certain other activities; limit or prohibit access, seismic acquisition, construction, drilling and other activities on certain lands lying within wilderness and other protected areas; impose substantial liabilities for pollution resulting from our operations; and require the reclamation of certain lands.
The permits required for many of our operations are subject to revocation, modification and renewal by issuing authorities. Governmental authorities have the power to enforce compliance with their regulations, and violations are subject to fines, injunctions or both. In the opinion of our management, we are in substantial compliance with current applicable environmental laws and regulations, and we have no material commitments for capital expenditures to comply with existing environmental requirements. Nevertheless, changes in existing environmental laws and regulations or in interpretations thereof could have a significant impact on us, as well as the oil and natural gas industry in general. The Comprehensive Environmental Response, Compensation and Liability Act (‘‘CERCLA’’) and comparable state statutes impose strict and joint and several liabilities on owners and operators of certain sites and on persons who disposed of or arranged for the disposal of ‘‘hazardous substances’’ found at such sites. It is not uncommon for the neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. The Resource Conservation and Recovery Act (‘‘RCRA’’) and comparable state statutes govern the disposal of ‘‘solid waste’’ and ‘‘hazardous waste’’ and authorize imposition of substantial fines and penalties for noncompliance. Although CERCLA currently excludes petroleum from its definition of ‘‘hazardous substance,’’ state laws affecting our operations impose clean-up liability relating to petroleum and petroleum related products. In addition, although RCRA classifies certain oil field wastes as ‘‘non-hazardous,’’ such exploration and production wastes could be reclassified as hazardous wastes, thereby making such wastes subject to more stringent handling and disposal requirements.
Competition and Marketing
We will be faced with strong competition from many other companies and individuals engaged in the oil business, some of which are very large, well-established energy companies with substantial capabilities and established earnings records. We may be at a competitive disadvantage in acquiring oil prospects since we must compete with these individuals and companies, many of which have greater financial resources and larger technical staffs. In addition, although we use new screening technology which prevents sand accumulation in the well bores and allows for the recovery of more oil from mature fields, larger companies have the ability to manage their risk by diversification.
Exploration for and the production of oil are affected by the availability of pipe, casing and other tubular goods and certain other oil field equipment including drilling rigs and tools. We will depend upon independent drilling contractors to furnish rigs, equipment and tools to drill our wells. Higher prices for oil may result in competition among operators for drilling equipment, tubular goods and drilling crews which may affect our ability expeditiously to drill, complete, recomplete and work-over wells.
The market for oil is dependent upon a number of factors beyond our control, which at times cannot be accurately predicted. These factors include the extent of competitive domestic production and imports of oil, the availability of other sources of energy, fluctuations in seasonal supply and demand, and governmental regulation. In addition, there is always the possibility that new legislation may be enacted which would impose price controls or additional excise taxes upon crude oil. As of November 30, 2012, all of our oil production was being sold to an independent oil company. The agreement with the independent oil company is on a month-to-month basis, and the price at which we sell our oil is established each month. The oil is transferred by truck from the field to a nearby refinery. We do not expect to have any difficulty in selling the oil produced from our wells in the foreseeable future.
On June 23, 2011, 28 member countries of the International Energy Agency agreed to release 60 million barrels of oil, including 30 million barrels from the United States’ Strategic Petroleum Reserve, in the subsequent months in response to the ongoing disruption of oil supplies from Libya. The market price for crude oil is significantly affected by policies adopted by the member nations of Organization of Petroleum Exporting Countries (‘‘OPEC’’). Members of OPEC establish prices and production quotas among themselves for petroleum products from time to time with the intent of controlling the current global supply and consequently price levels. We are unable to predict the effect, if any, that OPEC or other countries will have on the amount of, or the prices received for, crude oil.
Employees and Offices
As of November 30, 2012, we had one full-time employee and two part-time employees.
Our principal offices are located at 1330 Post Oak Blvd., Suite 1600, Houston, Texas 77056. Our offices, consisting of approximately 1,200 square feet, are leased until February 28, 2013 at a rate of $2,900 per month.
We also maintain a satellite office in Los Angeles, California. This office consists of 500 square feet and is rented for $5,700 per month pursuant to a lease which expires on June 30, 2013.
Our office leases include fully furnished offices, utilities, administrative support and covered parking.
Subsidiaries
We conduct business in Texas through VE Corporation, a Colorado corporation and our wholly owned subsidiary. In addition, we own a 1% interest in Vanguard Net Profits, LLC, a Texas limited liability company. Thirty-three private investors own the remaining 99% interest.
ITEM 1A.
ITEM 1A. RISK FACTORS.
Investors should be aware that and investment in our securities involves certain risks, including those described below, which could adversely affect the value of our common stock. We do not make, nor have we authorized any other person to make, any representation about the future market value of our common stock. In addition to the other information contained in this report, the following factors should be considered carefully in evaluating an investment in our securities.
Our failure to obtain capital may restrict our operations. We may need additional capital to fund our operating losses and to expand our business. We do not know what the terms of any future capital raising may be but any future sale of our equity securities would dilute the ownership of existing stockholders and could be at prices substantially below the market price of our common stock. Our failure to obtain the capital which we require may result in the slower implementation of our business plan. There can be no assurance that we will be able to obtain the capital which we will need.
Drilling. Oil exploration is not an exact science, and involves a high degree of risk. The primary risk lies in the drilling of dry holes or drilling and completing wells which, though productive, do not produce oil in sufficient amounts to return the amounts expended and produce a profit. Hazards, such as unusual or unexpected formation pressures, downhole fires, blowouts, loss of circulation of drilling fluids and other conditions are involved in drilling and completing wells and, if such hazards are encountered, completion of any well may be substantially delayed or prevented. In addition, adverse weather conditions can hinder or delay operations, as can shortages of equipment and materials or unavailability of drilling, completion, and/or work-over rigs. Even though a well is completed and is found to be productive, water and/or other substances may be encountered in the well, which may impair or prevent production or marketing of oil from the well.
Exploratory drilling involves substantially greater economic risks than development drilling because the percentage of wells completed as producing wells is usually less than with development drilling. Exploratory drilling itself can involve varying degrees of risk and can generally be divided into higher risk attempts to discover a reservoir in a completely unproven area or relatively lower risk efforts in areas not too distant from existing reservoirs. While exploration adjacent to or near existing reservoirs may be more likely to result in the discovery of oil than in completely unproven areas, exploratory efforts are nevertheless high risk activities.
Although the completion of a well is, to a certain extent, less risky than drilling, the process of completing a well is nevertheless associated with considerable risk. In addition, even if a well is completed as a producer, the well for a variety of reasons may not produce sufficient oil in order to repay the investment in the well. As a result, there is considerable economic risk associated with our activities.
Economic Factors in Oil Exploration. The acquisition, exploration and development of oil properties, and the production and sale of oil are subject to many factors which are outside our control. These factors include, among others, general economic conditions, proximity to pipelines, oil import quotas, supply, demand, and price of other fuels and the regulation of production, refining, transportation, pricing, marketing and taxation by Federal, state, and local governmental authorities.
Title Uncertainties. Interests that we will acquire in properties may be subject to royalty and overriding royalty interests, liens incident to operating agreements, liens for current taxes and other burdens and encumbrances, easements and other restrictions, any of which may subject us to future undetermined expenses. We do not intend to purchase title insurance, title memos, or title certificates for any leasehold interests we acquire. It is possible that at some point we will have to undertake title work involving substantial costs. In addition, it is possible that we may suffer title failures resulting in significant losses.
Uninsured Risks. The drilling of wells involves hazards such as blowouts, unusual or unexpected formations, pressures or other conditions which could result in substantial losses or liabilities to third parties. Although we intend to acquire adequate insurance, or to be named as an insured under coverage acquired by others (e.g., the driller or operator), we may not be insured against all such losses because such insurance may not be available, premium costs may be deemed unduly high, or for other reasons. Accordingly, uninsured liabilities to third parties could result in the loss of our funds or property.
Government Regulation. Our operations are affected from time to time and in varying degrees by political developments and Federal and state laws and regulations regarding the development, production and sale of crude oil. These regulations require permits for drilling of wells and also cover the spacing of wells, the prevention of waste, and other matters. Rates of production of oil have for many years been subject to Federal and state conservation laws and regulations and the petroleum industry is subject to Federal tax laws. In addition, the production of oil may be interrupted or terminated by governmental authorities due to ecological and other considerations. Compliance with these regulations may require a significant capital commitment by and expense to us and may delay or otherwise adversely affect our proposed operations.
From time to time legislation has been proposed relating to various conservation and other measures designed to decrease dependence on foreign oil. No prediction can be made as to what additional legislation may be proposed or enacted. Oil producers may face increasingly stringent regulation in the years ahead and a general hostility towards the oil and gas industry on the part of a portion of the public and of some public officials. Future regulation will probably be determined by a number of economic and political factors beyond our control or the oil and gas industry.
Environmental Laws. Our activities will be subject to existing federal and state laws and regulations governing environmental quality and pollution control. Compliance with environmental requirements and reclamation laws imposed by Federal, state, and local governmental authorities may necessitate significant capital outlays and may materially affect our earnings. It is impossible to predict the impact of environmental legislation and regulations (including regulations restricting access and surface use) on our operations in the future although compliance may necessitate significant capital outlays, materially affect our earning power or cause material changes in our intended business. In addition, we may be exposed to potential liability for pollution and other damages.
The sale of common stock described above, or the perception that such sales could occur, may adversely affect the market price of our common stock.
Any decline in the price of our common stock may encourage short sales, which could place further downward pressure on the price of our common stock. Short selling is a practice of selling shares which are not owned by a seller at that time, with the expectation that the market price of the shares will decline in value after the sale, providing the short seller a profit.
ITEM 1B.
ITEM 1B. UNRESOLVED STAFF COMMENTS.
Not Applicable
ITEM 2.
ITEM 2. PROPERTIES.
See Item 1 of this report.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS.
None.
ITEM 4.
ITEM 4. MINE SAFETY DISCLOSURE.
Not applicable.
PART II
ITEM 5.
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES.
In December 2011 we completed our initial public offering. The offering consisted of 4,800,000 Units priced at $1.00 per Unit. Each unit consisted of one share of our common stock and one Class A warrant. The Units began trading under the symbol “VNGEU” on the Over-The-Counter Bulletin Board (OTCBB) on November 29, 2011. On December 10, 2011 the Units separated into shares of common stock and warrants. The shares of common stock traded under the symbol (OTCBB: VNGE) and the Class A warrants trade under the symbol (OTCBB: VNGEW). Each Class A warrant entitles the holder to purchase one share of our common stock at a price of $1.50 per share at any time on or before November 29, 2016.
Shown below is the range of high and low closing prices for our common stock for the periods indicated as reported by the FINRA. The market quotations reflect inter-dealer prices, without retail mark-up, mark-down or commissions and may not necessarily represent actual transactions.
Holders of our common stock are entitled to receive dividends as may be declared by the Board of Directors. Our Board of Directors is not restricted from paying any dividends but is not obligated to declare a dividend. No cash dividends have ever been declared and it is not anticipated that cash dividends will ever be paid.
Our Articles of Incorporation authorize our Board of Directors to issue up to 5,000,000 shares of preferred stock. The provisions in the Articles of Incorporation relating to the preferred stock allow our directors to issue preferred stock with multiple votes per share and dividend rights which would have priority over any dividends paid with respect to the holders of our common stock. The issuance of preferred stock with these rights may make the removal of management difficult even if the removal would be considered beneficial to shareholders generally, and will have the effect of limiting shareholder participation in certain transactions such as mergers or tender offers if these transactions are not favored by our management.
As of November 30, 2012, we had approximately 475 shareholders of record.
We have not declared or paid any dividends on our common stock since our inception, and we do not anticipate declaring or paying any dividends on our common stock for the foreseeable future. We currently intend to retain any future earnings to finance future growth. Any future determination to pay dividends will be at the discretion of our board of directors and will depend on our financial condition, results of operations, capital requirements and other factors the board of directors considers relevant.
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
The following discussion should be read in conjunction with our financial statements included as part of this report.
Results of Operations
We were incorporated in Colorado on June 21, 2010 and commenced operations on July 19, 2010. We are in the early stages of implementing our business plan.
During the period of our inception to September 30, 2010 we did not generate any revenue. Accordingly, a comparison of our operating results for the year ended September 30, 2011 with the comparable period in 2010 would not be meaningful.
In November and December 2010 we entered into two agreements to acquire oil and gas leases covering 220 acres in the Batson Dome Field in Hardin County, Texas. In the first agreement, and in consideration for the assignment of a 40% working interest (32% net revenue interest) in leases covering 220 acres, we paid $40,000 in cash and issued a promissory note in the principal amount of $285,668. In the second agreement, and in consideration for the assignment of a 50% working interest (40% net revenue interest) in leases covering the same 220 acres, we paid $50,000 in cash and issued a promissory note in the principal amount of $357,085. The notes associated with the first and second agreements bore interest at 8% per year and were repaid in December 2010.
In December 2010, we acquired two producing and three shut-in oil wells in the Batson Dome Field. As of November 30, 2012, the two wells were producing approximately one barrel of oil per day, net to our 63% net revenue interest. As of November 30, 2012, one shut-in well was being reworked and one shut-in well was plugged and abandoned. We estimate the costs of reworking the shut-in wells will be $375,000.
As of November 30, 2012, we had drilled and completed twelve wells in the Batson Dome Field. Our share of the costs of drilling and completing these wells was approximately $7,200,000. Each of these wells has shown multiple potentially productive zones at depths ranging from 2,100 to 3,700 feet. During the three months ended November 30, 2012 we produced approximately 16,000 bbls of oil.
Material changes in our Statement of Operations for the year ended September 30, 2012 as compared to the same period in the prior year are discussed below:
Operating expenses requiring cash for the year ended September 30, 2012 consisted primarily of:
●
lease operating expenses;
●
general and administrative expenses; and
●
interest expense.
The factors that will most significantly affect our future operating results will be:
●
the sale prices of crude oil;
●
the amount of production from oil wells in which we have an interest;
●
lease operating expenses;
●
the availability of drilling rigs, drill pipe and other supplies and equipment required to drill and complete oil wells; and
●
corporate overhead costs.
Our revenues will also be significantly affected by our ability to maintain and increase oil production.
Other than the foregoing we do not know of any trends, events or uncertainties that have had, or are reasonably expected to have, a material impact on our revenues or expenses.
Liquidity and Capital Resources
In July 2010, we sold 4,900,000 shares of our common stock at a price of $0.001 per share to our officers and directors and third parties. In July, August, and September, 2010, we sold 1,012,500 shares of our common stock to a group of private investors at a price of $0.40 per share.
In November and December 2010, we sold 34 units in a private offering at a price of $100,000 per unit. Each unit consisted of one promissory note in the principal amount of $100,000 and 50,000 Series A warrants. At any time after April 30, 2011, the notes can be converted into shares of our common stock, initially, at a conversion price of $1.00 per share. Each Series A warrant entitles the holder to purchase one share of our common stock at a price of $4.00 per share at any time on or before October 31, 2014. The notes bear interest at 8% per year. In June, July and September 2012 notes in the principal amount of $3,075,000 were surrendered in payment of the notes sold in 2012. The remaining notes, which had an outstanding principal balance of $325,000, were repaid in October 2012.
In February and March 2011, we sold 1,500,000 units at a price of $1.00 per unit. Each unit consisted of one share of our common stock and one Series C warrant. Each Series C warrant allows the holder to purchase one share of our common stock at a price of $2.00 per share. In March 2011, we issued 453,322 shares of our common stock to a placement agent upon the exercise of warrants which had an exercise price of $0.10 per share.
In December 2011 we sold 4,800,000 units in an initial public offering at a price of $1.00 per unit. Net proceeds to us from this offering, after payment of the underwriting discounts and offering expenses, were approximately $3,498,900. Each unit consisted of one share of common stock and one Class A warrant. Each Class A warrant entitles its holder to purchase one share of common stock at an exercise price of $1.50. The Class A warrants are exercisable at any time on or before November 29, 2016.
In June, July and September 2012 we sold convertible secured promissory notes to a group of private investors. The notes bear interest at 15% per year, are payable quarterly, mature on June 30, 2015, and are convertible into shares of our common stock at a conversion price of $1.25 per share, subject to adjustment. Notes in the cumulative principal amount of $5,179,500 were sold for cash and notes in the cumulative principal amount of $3,075,000 were exchanged for notes that we sold in 2010. Net proceeds from this financing:
●
were used to pay the remaining balance ($325,000) of our 2010 notes; and
●
will be used to fund a drilling program in our fields located in Southeast Texas.
Our sources and (uses) of funds for the two years ended September 30, 2012 are shown below:
As of November 30, 2012, our operating expenses were approximately $150,000 per month, which amount includes salaries and other corporate overhead, but excludes lease operating and interest expenses.
By agreement dated March 15, 2011, we entered into a farmout agreement with an unrelated third party pertaining to a 100-acre lease in the Batson Dome Field. As of November 30, 2012 we had drilled three wells on the lease. Pursuant to the farmout agreement we have the option of drilling additional wells on the lease, subject to certain conditions. We estimate the cost of drilling and completing any well on this lease will be approximately $500,000.
By agreement dated May 25, 2011, we entered into a farmout agreement with Exxon/Mobil Corporation pertaining to another 100-acre lease adjacent to our existing leases in the Batson Dome Field. Pursuant to the agreement, we have the obligation to commence drilling a well on the lease by June 14, 2013. Subject to the commencement of drilling the first well by June 14, 2013, and completing the well if warranted, we have the option of drilling additional wells on the lease; provided however, that unless we commence drilling each well within 180 days of the date we complete or abandon the latest well drilled, our right to drill any additional wells on the lease will terminate. We estimate the cost of drilling and completing any well on this lease will be approximately $1,000,000.
By agreement dated January 6, 2012, we entered into a three-year farmout agreement with an unrelated third party pertaining to another 70-acre lease in the Batson Dome Field. We estimate the cost of drilling and completing any well on this lease will be approximately $1,000,000.
By agreement dated May 1, 2012, we entered into a farmout agreement with an unrelated third party pertaining to a 45-acre lease in the Hull-Daisetta Field. Pursuant to the agreement, we have the obligation to commence drilling a well on the lease by January 31, 2013. Subject to the commencement of drilling the first well by January 31, 2013, and completing the well if warranted, we have the option of drilling additional wells on the lease; provided however, that unless we commence drilling each well within 180 days of the date the latest well is completed or abandoned, the right to drill any additional wells on the lease will terminate. We estimate the cost of drilling and completing any well on this lease will be approximately $750,000.
We estimate we will spend approximately $7,000,000 during the twelve months ending November 30, 2013 for drilling and completing wells and for various other projects.
Any cash generated by our operations, after payment of general, administrative and lease operating expenses, will be used to drill and, if warranted, complete oil wells, acquire oil and gas leases covering lands which we believe are favorable for the production of oil, and to fund working capital reserves. Our capital expenditure plans are subject to periodic revision based upon the availability of funds and expected return on investment.
We expect that our principal source of cash flow will be from the sale of crude oil reserves which are depleting assets. Cash flow from the sale of oil production depends upon the quantity of production and the price obtained for the production. An increase in prices will permit us to finance our operations to a greater extent with internally generated funds, may allow us to obtain equity financing more easily or on better terms, and lessens the difficulty of obtaining financing. However, price increases heighten the competition for oil prospects, increase the costs of exploration and development, and, because of potential price declines, increase the risks associated with the purchase of producing properties during times that prices are at higher levels.
A decline in oil prices (i) will reduce our cash flow which in turn will reduce the funds available for exploring for and replacing oil reserves, (ii) will increase the difficulty of obtaining equity and debt financing and worsen the terms on which such financing may be obtained, (iii) will reduce the number of oil prospects which have reasonable economic terms, (iv) may cause us to permit leases to expire based upon the value of potential oil reserves in relation to the costs of exploration, (v) may result in marginally productive oil wells being abandoned as non-commercial, and (vi) may increase the difficulty of obtaining financing. However, price declines reduce the competition for oil properties and correspondingly reduce the prices paid for leases and prospects.
We plan to generate profits by drilling productive oil wells. However, we plan to obtain the funds required to drill, and if warranted, complete new wells (including any wells pertaining to our farmout agreements) with any net cash generated by our operations, through the sale of our securities, from loans from third parties or from third parties willing to pay our share of the cost of drilling and completing the wells as partners/participants in the resulting wells. We do not have any commitments or arrangements from any person to provide us with any additional capital. We may not be successful in raising the capital needed to drill oil wells. Any wells which may be drilled by us may not produce oil.
Other than as disclosed above, we do not know of any:
●
Trends, demands, commitments, events or uncertainties that will result in, or that are reasonably likely to result in, any material increase or decrease in our liquidity; or
●
Significant changes in our expected sources and uses of cash.
Contractual Obligations
Our material future contractual obligations as of September 30, 2012 were as follows:
(1)
These notes were repaid in October 2012.
Critical Accounting Policies and New Accounting Pronouncements
See Note 2 to the financial statements included as part of this report, for a description of our critical accounting policies and the potential impact of the adoption of any new accounting pronouncements.
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
Not applicable.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
See the financial statements and accompanying notes included with this report.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.
None.
ITEM 9A.
ITEM 9A. CONTROLS AND PROCEDURES.
An evaluation was carried out under the supervision and with the participation of our management, including our Principal Executive and Financial Officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report on Form 10-K. Disclosure controls and procedures are procedures designed with the objective of ensuring that information required to be disclosed in our reports filed under the Securities Exchange Act of 1934, such as this Form 10-K, is recorded, processed, summarized and reported, within the time period specified in the Securities and Exchange Commission’s rules and forms, and that such information is accumulated and is communicated to our management, including our Principal Executive and Financial Officer, or persons performing similar functions, as appropriate, to allow timely decisions regarding required disclosure. Based on that evaluation, our management concluded that, as of September 30, 2012, our disclosure controls and procedures were effective.
Management's Report on Internal Control over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting and for the assessment of the effectiveness of internal control over financial reporting. As defined by the Securities and Exchange Commission, internal control over financial reporting is a process designed by, or under the supervision of our Principal Executive and Financial Officer and implemented by our Board of Directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of our financial statements in accordance with U.S. generally accepted accounting principles.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Warren Dillard, our Principal Executive and Financial Officer, evaluated the effectiveness of our internal control over financial reporting as of September 30, 2012 based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission, or the COSO Framework. Management’s assessment included an evaluation of the design of our internal control over financial reporting and testing of the operational effectiveness of those controls.
Based on this evaluation, management concluded that our internal control over financial reporting was effective as of September 30, 2012.
Changes in Internal Control Over Financial Reporting
There was no change in our internal control over financial reporting that occurred during the period covered by this report that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
ITEM 9B.
ITEM 9B. OTHER INFORMATION.
None.
PART III
ITEM 10.
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE.
Our officers and directors are listed below. Our directors are generally elected at our annual shareholders’ meeting and hold office until the next annual shareholders’ meeting, or until their successors are elected and qualified. Our executive officers are elected by our directors and serve at their discretion.
The principal occupations of our officers and directors during the past several years are as follows:
Warren M. Dillard has been our President, Chief Executive, Financial and Accounting Officer and a director since June 2010. Since February 2011 Mr. Dillard has been our Principal Financial and Accounting Officer. Since 2005, Mr. Dillard has served as the President and a director of Enercor, Inc., a private corporation involved in oil and gas exploration and development in the western United States. Since the spring of 2010, Mr. Dillard’s involvement with Enercor has been minimal. Mr. Dillard holds a degree in Accounting from Texas A & M University and an MBA in Finance from the Harvard Business School.
R. Gerald Bailey has been our Chairman of the Board and a director since June 2010 and has approximately 45 years of experience as a petroleum engineer. Currently, Mr. Bailey is serving as chairman of BCM Energy Partners, Inc., an oil production firm. Since 1997, Mr. Bailey has served as the chairman of Bailey Petroleum, LLC, a consulting firm for oil and gas exploration and development corporations. Between 1993 and 1997, Mr. Bailey served as the President of Exxon Corporation, Arabian Gulf. He received a BS in Chemical Engineering from the University of Houston, and a MS in Chemical Engineering from New Jersey Institute of Technology.
Michael L. Fraim, PhD. has been our Vice President for Technology since June 2010. Since 2006, Dr. Fraim has served as the Vice President, Technology for Ephraim Oil, LLC. Between 2004 and 2006, Dr. Fraim was employed by Alamos Consulting in Albuquerque, New Mexico. From time to time over the past five years, Dr. Fraim has been engaged on an independent contractor/consultant basis by various energy companies. Most recently, Mr. Fraim has been providing consulting services to large oil and gas companies through Texas A&M University. Dr. Fraim holds a bachelor’s degree, a masters degree and a PH.D degree in petroleum engineering from Texas A & M University.
Delton C. Drum has been our Vice President for Field Operations since June 2010. Since 2003, Mr. Drum has been the President of C.F.O., Inc., an oil and gas firm involved in drilling and operating oil and gas wells. Since 1995, Mr. Drum has served as the Chief Executive Officer of Drum Equipment/ Drum Oil & Gas, Inc. Mr. Drum has approximately 30 years of experience in the oil and gas industry as an operator, driller and well owner.
Steven M. Powers has been a director since June 2010. Since February 2011, Mr. Powers has been our Vice President of Business Development and our Secretary. Since 2005, Mr. Powers has served as Chief Executive Officer, Chairman and a director of Enercor, Inc., a private corporation involved in oil and gas exploration and development. Prior to his association with Enercor, Mr. Powers was a real estate developer. Mr. Powers holds a degree in philosophy from the University of California at Santa Barbara as well as an MBA from the University of California at Los Angeles.
Rick A. Wilber has been a director since June 2010. Mr. Wilber has been a director of Synergy Resources Corporation, a publicly traded oil and gas exploration and development corporation, since September 2008. Mr. Wilber has been a Director of Ultimate Software Group Inc. since October 2002 and serves as a member of its audit and compensation committees. Since 1984, Mr. Wilber has been a private investor in, and a consultant to, numerous development stage companies. Mr. Wilber holds a Bachelor of Science degree from the U.S. Military Academy at West Point.
John P. Barton has been a director since June 2010. Since 2007, Mr. Barton has served as a managing partner of Energy Capital Partners, LLC, a venture capital firm. Since 2005, Mr. Barton has been a partner of Cambridge Energy Partners, LLC., an oil and gas investment firm. From time to time over the past five years Mr. Barton has been engaged on an independent contractor/consultant basis by various energy companies. Most recently, Mr. Barton has provided consulting services to Synergy Resources Corporation. Mr. Barton holds a degree in Economics and Finance from Millikin University.
We believe that each of our directors’ experience in oil and gas exploration and business development qualifies him to serve as one of our directors.
Rick Wilber and John Barton are the members of our compensation committee. Our Board of Directors serves as our audit committee.
Rick Wilber and John Barton are independent, as that term is defined in Section 803 A(2) of the NYSE MKT Company Guide. Warren Dillard acts as our financial expert.
We have adopted a code of ethics applicable to our principal executive, financial and accounting officers and persons performing similar functions.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
The following table summarizes the compensation received by our principal executive and financial officers during the two years ended September 30, 2012.
(1)
The dollar value of base salary (cash and non-cash) earned.
(2)
The dollar value of bonus (cash and non-cash) earned.
(3)
The value of the shares of restricted stock issued as compensation for services computed in accordance with ASC 718 on the date of grant.
(4)
The value of all stock options computed in accordance with ASC 718 on the date of grant.
(5)
All other compensation received that could not be properly reported in any other column of the table.
The following shows the amounts we expect to pay to our officers and directors during the twelve months ending November 30, 2013 and the amount of time these persons expect to devote to us.
Michael Fraim provides consulting services from time to time and is compensated on the basis of actual time spent.
Delton Drum is compensated through his company, C.F.O., Inc., which is the operator for any wells we drill in the Batson Dome Field. We entered into an operating agreement with C.F.O., Inc. dated October 1, 2010. As operator, C.F.O., Inc. receives $2,500 per month for each well being drilled or completed, subject to reductions for days when a well, or wells, are not being drilled. In addition, C.F.O., Inc. is paid $250 per month for each operating well. We may remove C.F.O., Inc. for good cause if it fails to cure a default under the operating agreement within 30 days’ notice from us of a default. C.F.O., Inc. is required to carry insurance for our benefit and may not undertake any single project requiring an expenditure in excess of $5,000 without our prior authorization, except in the case of an emergency. The operating agreement will remain in effect so long as the oil leases covered by the agreement continue in operation.
We have an employment agreement with Warren Dillard which provides that Mr. Dillard is paid a base salary of $12,500 per month, plus an amount equal to the federal and state taxes that he is required to pay with respect to his base salary. The employment agreement with Mr. Dillard can be terminated at any time, by either party, upon 10 days’ notice, without cause.
We have an employment agreement with R. Gerald Bailey. Pursuant to the agreement, we will pay Mr. Bailey $20,000 per month Our agreement with Mr. Bailey is terminable at any time, by either party without cause or penalty.
We have an employment agreement with Steven Powers. Pursuant to the agreement, Mr. Powers devotes approximately 40% of his time to our business and we pay him a base salary of $7,500 per month, plus an amount equal to the federal and state taxes that he is required to pay with respect to his base salary. The employment agreement with Mr. Powers can be terminated at any time, by either party, upon 10 days’ notice, without cause.
We do not have any employment or compensation agreements with Rick Wilber or John Barton.
Non-Qualified Stock Option Plan. We have a non-qualified stock option plan which authorizes the issuance of up to 1,500,000 shares of our common stock to persons that exercise options granted pursuant to the plan. Our employees, directors, officers, consultants and advisors are eligible to be granted options pursuant to the plan, provided, however, that bona fide services must be rendered by such consultants or advisors and such services must not be in connection with the offer or sale of securities in a capital-raising transaction. In the future, the exercise price for options granted pursuant to the plan will not be less than 85% of the fair market value of our common stock on the date of grant.
The following tables show all options granted pursuant to the Non-Qualified Stock Option Plan. As of November 30, 2012, none of the options had been exercised. The options are fully vested.
(1)
Any options which have not been exercised will automatically terminate upon the option holder’s death, 90 days after the date the option holder voluntarily resigns as an officer, director or employee or in the event the option holder is terminated for cause. For purposes of these options, cause is defined as (i) the failure by the option holder to substantially perform his duties and obligations owed to us (other than any failure resulting from incapacity due to physical or mental illness); (ii) engaging in misconduct or a breach of fiduciary duty which is, or potentially is,materially injurious to us; (iii) commission of a felony; or (iv) the commission of a crime which is, or potentially is, materially injurious to us.
Long-Term Incentive Plans. We do not provide our officers or employees with pension, stock appreciation rights, long-term incentive or other plans.
Employee Pension, Profit Sharing or other Retirement Plans. We do not have a defined benefit, pension plan, profit sharing or other retirement plan, although we may adopt one or more of such plans in the future.
Compensation of Directors During Year Ended September 30, 2012. During the year ended September 30, 2012, we did not compensate our directors for acting as such.
Compensation Committee Interlocks and Insider Participation. Rick Wilber and John Barton are the members of our compensation committee. During the year ended September 30, 2012, both Mr. Wilber and Mr. Barton participated in deliberations concerning executive officer compensation. During the year ended September 30, 2012, none of our officers was also a member of the compensation committee or a director of another entity, which other entity had one of its executive officers serving as one of our directors.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS.
The following table shows the beneficial ownership of our common stock, as of November 30, 2012, by (i) each person whom we know beneficially owns more than 5% of the outstanding shares of our common stock, (ii) each of our officers, (iii) each of our directors, and (iv) all the officers and directors as a group. Unless otherwise indicated, each owner has sole voting and investment powers over his shares of common stock. Unless otherwise indicated, beneficial ownership is determined in accordance with the Rule 13d-3 promulgated under the Securities and Exchange Act of 1934, as amended, and includes voting or investment power with respect to shares beneficially owned.
______________
* Less than 1%
(1)
Assumes none of our outstanding notes is converted and none of our outstanding warrants is exercised.
(2)
Shares are beneficially held through trusts or other entities under the control of this beneficial owner.
(3)
Includes 200,000 shares issuable upon exercise of an option that is currently exercisable.
(4)
Includes 100,000 shares issuable upon exercise of an option that is currently exercisable.
(5)
Includes 150,000 shares issuable upon exercise of an option that is currently exercisable.
(6)
Includes 100,000 shares owned by Mr. Barton's wife.
(7)
Includes 750,000 shares issuable upon exercise of options that are currently exercisable.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE.
In July 2010, we sold 4,900,000 shares of our common stock at a price of $0.001 per share to our officers and directors and unrelated third parties.
We acquired working interests in our oil and gas leases in the Batson Dome Field, as well as two producing and three shut-in oil wells, from C.F.O., Inc., a corporation controlled by Delton Drum, one of our officers. C.F.O., Inc., which retained a 10% working interest in these leases and wells, paid $200,000 for the leases and wells sold to us. We pay C.F.O., Inc. to operate our oil wells. We believe that the terms of the transactions with C.F.O., Inc. were at least as favorable to us as those generally available from unaffiliated third parties.
We have not issued any preferred stock or made any loans to, or guaranteed any loans on behalf of, any of our founders, officers, directors, five percent or greater stockholders, or any affiliates of the foregoing persons (each an ‘‘Affiliated Person’’). In the future, we will not engage in material affiliated transactions with any Affiliated Person unless the terms of such transactions are approved by a majority of our independent directors who (i) do not have an interest in the transaction and (ii) are independent under state law definitions of independence requiring that the director neither be an officer nor beneficially own 5% or more of our common stock. Material affiliated transactions include and are not limited to the following transactions between us and any Affiliated Person: issuances of common or preferred stock to any Affiliated Person; making any loan to, or forgiving any loan with any Affiliated Person; and guaranteeing any loan on behalf of any Affiliated Person. We will enter into future material affiliated transactions only on terms that are no less favorable to us than those that can be obtained from unaffiliated third parties.
Prior to engaging into future material affiliated transactions, we will appoint, as necessary, and maintain at least two independent directors on our board of directors who are independent under state law definitions of independence requiring that the director neither be an officer nor beneficially own 5% or more of our common stock.
We will provide our independent directors with access to our legal counsel, at our expense, or independent legal counsel in connection with any material affiliated transaction involving our founders, officers, directors, five percent or greater stockholders, or any affiliates of the foregoing persons. Our officers, directors, and counsel will (a) conduct due diligence necessary to assure that there is a reasonable basis for our representations regarding the approval process for material affiliated transactions, and (b) consider whether to embody the representations in our articles of incorporation or bylaws.
ITEM 14.
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES.
Briggs & Veselka Co. audited our financial statements for the two years ended September 30, 2012. The following table shows the fees billed to us during the periods presented by Briggs & Veselka.
Audit fees represent amounts billed for professional services rendered for the audit of our annual financial statements and reviews of our quarterly financial statements.
Audit-related fees represent amounts billed for the preparation of a comfort letter in connection with our initial public offering, consents related to other regulatory filing, audit/review of interim financial statements included in our registration statement on Form S-1, and consulting related to the implementation of accounting standards.
Tax fees include professional services for tax return preparation and income tax audit support.
All other fees includes professional services related to assistance with acquisitions.
The policy of our directors is to pre-approve all audit and non-audit services provided by our independent auditors.
PART IV
ITEM 15.
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES.
The following exhibits are filed with this Registration Statement:
___________________
*
Incorporated by reference to the same exhibit filed with the Company’s Registration Statement on Form S-1 (File # 333-174194).
**
Incorporated by reference to the same exhibit filed with the Company’s registration statement on Form S-1 (File # 333-180987).
CONTENTS
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders of
Vanguard Energy Corporation
We have audited the accompanying consolidated balance sheets of Vanguard Energy Corporation ("the Company") as of September 30, 2012 and 2011 and the related consolidated statements of operations, changes in stockholders' equity, and cash flows for each of the years then ended. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based upon our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States of America). 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 audits 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. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of September 30, 2012 and 2011, and the results of its operations and its cash flows for each of the years then ended, in conformity with accounting principles generally accepted in the United States of America.
/s/ Briggs & Veselka Co.
Briggs & Veselka Co.
Houston, Texas
December 27, 2012
VANGUARD ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS
The accompanying notes are an integral part of these consolidated financial statements.
VANGUARD ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
The accompanying notes are an integral part of these consolidated financial statements.
VANGUARD ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY
The accompanying notes are an integral part of these consolidated financial statements.
VANGUARD ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
The accompanying notes are an integral part of these consolidated financial statements.
VANGUARD ENERGY CORPORATION
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1 - ORGANIZATION
Organization-Vanguard Energy Corporation (the "Company") was organized under the laws of the State of Colorado on June 21, 2010. The Company conducts business in Texas through VE Corporation, a Colorado corporation and wholly owned subsidiary. The Company commenced operations on July 19, 2010 and is engaged in the acquisition, development and operation of onshore oil and gas properties in Texas.
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Principles of Consolidation and Basis of Presentation- The consolidated financial statements include the accounts of Vanguard Energy Corporation and its subsidiaries. All significant intercompany accounts and transactions have been eliminated in consolidation.
The Company's fiscal year-end is September 30. The accompanying financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") and pursuant to the accounting and disclosure rules and regulations of the U.S. Securities and Exchange Commission ("SEC"). A summary of the significant accounting policies applied in the preparation of the accompanying financial statements follows.
Management Estimates-The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, as well as certain financial statement disclosures. While management believes that the estimates and assumptions used in the preparation of the financial statements are appropriate, actual results could differ from these estimates. Significant estimates made in preparing these financial statements include the fair value of acquired assets and liabilities (Note 3), asset retirement obligations (Note 4), participation, conversion feature and warrant liabilities (Note 5), income taxes (Note 6) and the estimate of proved oil and gas reserves and related present value estimates of future net cash flows therefrom (Note 12).
Reclassifications - Certain amounts previously presented for prior periods have been reclassified to conform to the current presentation. The reclassifications had no effect on net loss, working capital or equity previously reported.
Cash and Cash Equivalents-The Company considers all highly liquid instruments purchased with a maturity date of three months or less to be cash equivalents.
Oil and Gas Properties-The Company follows the full cost accounting method to account for oil and natural gas properties, whereby costs incurred in the acquisition, exploration and development of oil and gas reserves are capitalized. Such costs include lease acquisition, geological and geophysical activities, rentals on nonproducing leases, drilling, completing and equipping of oil and gas wells and administrative costs directly attributable to those activities and asset retirement costs. Disposition of oil and gas properties are accounted for as a reduction of capitalized costs, with no gain or loss recognized unless such adjustment would significantly alter the relationship between capital costs and proved reserves of oil and gas, in which case the gain or loss is recognized to operations.
The capitalized costs of oil and gas properties, excluding unevaluated and unproved properties, are amortized as depreciation, depletion and amortization expense using the units-of-production method based on estimated proved recoverable oil and gas reserves.
The costs associated with unevaluated and unproved properties, initially excluded from the amortization base, relate to unproved leasehold acreage, wells and production facilities in progress and wells pending determination of the existence of proved reserves, together with capitalized interest costs for these projects. Unproved leasehold costs are transferred to the amortization base with the costs of drilling the related well once a determination of the existence of proved reserves has been made or upon impairment of a lease. Costs associated with wells in progress and completed wells that have yet to be evaluated are transferred to the amortization base once a determination is made whether or not proved reserves can be assigned to the property. Costs of dry wells are transferred to the amortization base immediately upon determination that the well is unsuccessful.
VANGUARD ENERGY CORPORATION
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All items classified as unproved property are assessed on a quarterly basis for possible impairment or reduction in value. Properties are assessed on an individual basis or as a group if properties are individually insignificant. The assessment includes consideration of various factors, including, but not limited to, the following: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; assignment of proved reserves; and economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and become subject to amortization.
Under full cost accounting rules for each cost center, capitalized costs of evaluated oil and gas properties, including asset retirement costs, less accumulated amortization and related deferred income taxes, may not exceed an amount (the "cost ceiling") equal to the sum of (a) the present value of future net cash flows from estimated production of proved oil and gas reserves, based on current prices and operating conditions, discounted at ten percent (10%), plus (b) the cost of properties not being amortized, plus (c) the lower of cost or estimated fair value of any unproved properties included in the costs being amortized, less (d) any income tax effects related to differences between the book and tax basis of the properties involved. If capitalized costs exceed this limit, the excess is charged to operations. For purposes of the ceiling test calculation, current prices are defined as the unweighted arithmetic average of the first day of the month price for each month within the 12 month period prior to the end of the reporting period. Prices are adjusted for basis or location differentials. Unless sales contracts specify otherwise, prices are held constant for the productive life of each well. Similarly, current costs are assumed to remain constant over the entire calculation period.
Given the volatility of oil and gas prices, it is reasonably possible that the estimate of discounted future net cash flows from proved oil and gas reserves could change in the near term. If oil and gas prices decline in the future, even if only for a short period of time, it is possible that impairments of oil and gas properties could occur. In addition, it is reasonably possible that impairments could occur if costs are incurred in excess of any increases in the present value of future net cash flows from proved oil and gas reserves, or if properties are sold for proceeds less than the discounted present value of the related proved oil and gas reserves.
Revenue Recognition-Oil and gas sales result from undivided interests held by the Company in oil and gas properties. Sales of oil and gas produced from oil and gas operations are recognized when the product is delivered to the purchaser and title transfers to the purchaser. The Company had no natural gas sales imbalance positions at September 30, 2012 or 2011. Charges for gathering and transportation are included in production expenses.
Asset Retirement Obligations-The Company records a liability for asset retirement obligations ("ARO") associated with its oil and gas wells when those assets are placed in service. The corresponding cost is capitalized as an asset and included in the carrying amount of oil and gas properties and is depleted over the useful life of the properties. Subsequently, the ARO liability is accreted to its then-present value.
Inherent in the fair value calculation of an ARO are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the fair value of the existing ARO liability, a corresponding adjustment is made to the oil and gas property balance. Settlements greater than or less than amounts accrued as ARO are recorded as a gain or loss upon settlement.
Capitalized Interest-Interest is capitalized as part of the historical cost of developing and constructing assets for significant projects. Significant oil and gas investments in unproved properties, significant exploration and development projects for which depreciation, depletion and amortization expense is not currently recognized, and exploration or development activities that are in progress qualify for interest capitalization. Interest is capitalized until the asset is ready for service. Capitalized interest is determined by multiplying the Company's weighted-average borrowing cost on debt by the average amount of qualifying costs incurred. Once an asset subject to interest capitalization is completed and placed in service, the associated capitalized interest is expensed through depletion or impairment, along with other capitalized costs related to that asset.
VANGUARD ENERGY CORPORATION
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
Debt Issuance Costs-Costs incurred in connection with the issuance of long-term debt are capitalized and amortized over the term of the related debt.
Participation Liability-The participation liability associated with outstanding long-term debt is recorded at fair value as determined utilizing a present value factor of 10 applied to proved developed reserves. Payments made for the participation liability are reported as interest expense. Changes in the fair value of the participation liability are recorded as additions or deductions to the discount on the long-term debt to the extent this debt remains outstanding. Once the associated debt is repaid, changes in the participation liability are recorded to other expense in the statements of operations.
Conversion Feature Liability and Warrant Liabilities-The conversion feature liability and warrant liabilities are recorded at fair value based upon valuation models utilizing relevant factors such as expected life, estimated volatility, risk-free interest and expected dividend rate. Changes in the fair value of these liabilities are reported in the statements of operations.
Stock-Based Compensation-The Company accounts for employee stock-based compensation using the fair value method. The fair value attributable to stock options is calculated based on the Black-Scholes option pricing model and is amortized to expense over the service period which is equivalent to the time required to vest the stock options.
Income Taxes-Income taxes are provided based on the liability method for financial reporting purposes. Under this method deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to reverse. Valuation allowances are established when necessary to reduce deferred income tax assets to the amount expected to be realized.
Uncertain tax positions are recognized in the financial statements only if that position is more likely than not of being sustained upon examination by taxing authorities, based on the technical merits of the position. The Company recognizes interest and penalties related to uncertain tax positions in income tax expense.
The Company is required to file federal income tax returns in the United States and in various state and local jurisdictions. The Company's tax returns filed since inception are subject to examination by taxing authorities in the jurisdictions in which it operates in accordance with the normal statutes of limitations in the applicable jurisdiction.
Earnings (Loss) Per Share-Basic earnings (loss) per share have been calculated based upon the weighted-average number of common shares outstanding. The weighted-average number of common shares outstanding used in the computations of earnings (loss) per share was 11,901,830 for 2012 and 7,170,906 for 2011. The calculation of diluted weighted-average shares outstanding for 2012 and 2011 excludes 19,751,560 shares and 8,110,000 shares, respectively, issuable pursuant to outstanding warrants, stock options and debt conversion features because their effect is anti-dilutive.
Concentration of Credit Risk-The Company is subject to credit risk resulting from the concentration of its oil and natural gas receivables with significant purchasers. One purchaser accounted for all of the Company's oil and gas sales revenues for 2012 and 2011. The Company does not require collateral. While the Company believes its recorded receivable will be collected, in the event of default the Company would follow normal collection procedures. The Company does not believe the loss of this purchaser would materially impact its operating results as oil and gas are fungible products with well-established markets and numerous purchasers.
VANGUARD ENERGY CORPORATION
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
At times, the Company maintains deposits in federally insured financial institutions in excess of federally insured limits. Management monitors the credit ratings and concentration of risk with these financial institutions on a continuing basis to safeguard cash deposits.
Fair Value Measurements-The carrying value of cash and cash equivalents, accounts receivable, and accounts payable, as reflected in the balance sheets, approximate fair value because of the short-term maturity of these instruments. The estimated fair value of long-term debt was determined by discounting future cash flows using rates currently available to the Company for debt with similar terms and remaining maturities. The Company calculated that the estimated fair value of the long term debt is not significantly different than the carrying value of the debt. The participation liability associated with outstanding long-term debt was determined by utilizing a present value factor of 10 applied to proved developed reserves associated with the wells drilled with the proceeds of the notes.
Fair value is defined as the price that would be received to sell an asset or price paid to transfer a liability in an orderly transaction between market participants at the measurement date. Inputs used in determining fair value are classified for disclosure purposes according to a hierarchy that prioritizes those inputs based upon the degree to which they are observable. The three levels of the fair-value-measurement hierarchy are as follows:
●
Level 1-Observable inputs that reflect quoted prices (unadjusted) for identical assets or liabilities in active markets.
●
Level 2-Inputs that reflect quoted prices for identical assets or liabilities in markets that are not active; quoted prices for similar assets or liabilities in active markets; inputs other than quoted prices that are observable for the asset or the liability; or inputs that are derived principally from or corroborated by observable market data by correlation or other means.
●
Level 3-Unobservable inputs reflecting the Company's own assumptions incorporated in valuation techniques used to determine fair value. These assumptions are required to be consistent with market participant assumptions that are reasonably available.
In determining fair value, the Company utilizes observable market data when available, or models that incorporate observable market data. In addition to market information, the Company incorporates transaction-specific details that, in management's judgment, market participants would take into account in measuring fair value. The Company utilizes the most observable inputs available for the valuation technique employed. If a fair value measurement reflects inputs at multiple levels within the hierarchy, the fair-value measurement of both financial and nonfinancial assets and liabilities are characterized based upon the lowest level of input that is significant to the fair value measurement.
Recently Issued Accounting Pronouncements - In April 2010, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2010-13. ASU 2010-13 provides amendments to Topic 718, Stock Compensation, to clarify that an employee share-based payment award with an exercise price denominated in the currency of a market in which a substantial portion of the entity's equity securities trades should not be considered to contain a condition that is not a market, performance, or service condition. Therefore, an entity would not classify such an award as a liability if it otherwise qualifies as equity. The amendments in ASU No. 2010-13 are effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2010. The Company’s adoption of the new guidance did not have a material effect on the Company’s consolidated financial statements.
VANGUARD ENERGY CORPORATION
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
In December 2010, the FASB issued ASU 2010-29, which addresses diversity in practice concerning the interpretation of the pro forma revenue and earnings disclosure requirements for business combinations. This ASU specifies that if a public entity presents comparative financial statements, the entity should disclose revenue and earnings of the combined entity as though the business combination(s) that occurred during the current year had occurred as of the beginning of the comparable prior annual reporting period only. This ASU also expands the supplemental pro forma disclosures to include a description of the nature and amount of material, nonrecurring pro forma adjustments directly attributable to the business combination included in the reported pro forma revenue and earnings. ASU 2010-29 is effective prospectively for business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2010. The adoption of this guidance did not have a material impact on the Company's financial statements.
In May 2011, the FASB issued ASU 2011-04, which clarifies some existing fair value measurement concepts, eliminates wording differences between U.S. GAAP and International Financial Reporting Standards (“IFRS”), and in some limited cases, changes some fair value measurement principles to achieve convergence between U.S. GAAP and IFRS. ASU 2011-04 is effective for the Company beginning after December 15, 2011. The adoption of this guidance did not have a material impact on the Company's financial statements.
Various other accounting standards updates were recently issued, most of which represented technical corrections to the accounting literature or were applicable to specific industries, and are not expected to a have a material impact on the Company's financial position, results of operations or cash flows.
NOTE 3 -ACQUISITIONS
By agreement dated March 15, 2011, the Company entered into a farmout agreement with an unrelated third party pertaining to a 100-acre lease in the Batson Dome Field. As of September 30, 2012, the Company had drilled three wells on the lease. Pursuant to the farmout agreement the Company has the option of drilling additional wells on the lease; provided however, that if it does not drill at least six wells in any twelve month period the right to drill any additional wells on the lease will terminate. The estimated cost of drilling and completing any well on this lease is approximately $500,000.As of September 30, 2012, the Company had drilled three wells on this lease.
By agreement dated May 25, 2011, the Company entered into a farmout agreement with an unrelated third party pertaining to a 100-acre lease in the Batson Dome Field. Pursuant to the agreement, the Company had the obligation to commence drilling a well on the lease by June 14, 2012. In June 2012, the Company paid $10,000 to extend the agreement, whereby it now has an obligation to commence drilling by June 14, 2013. Subject to the commencement of drilling the first well by June 14, 2013, and completing the well if warranted, the Company has the option of drilling additional wells on the lease; provided however, that unless the Company commences drilling each well within 180 days of the date the latest well is completed or abandoned, the right to drill any additional wells on the lease will terminate. The estimated cost of drilling and completing any well on this lease is approximately $1,000,000. As of September 30, 2012, the Company had not commenced any drilling operations on the lease subject to the farmout agreement.
By agreement dated January 6, 2012, the Company entered into a three-year farmout agreement with an unrelated third party pertaining to another 70-acre lease in the Batson Dome Field. The estimated cost of drilling and completing any well on this lease is approximately $1,000,000.
VANGUARD ENERGY CORPORATION
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
By agreement dated May 1, 2012, the Company entered into a farmout agreement with an unrelated third party pertaining to a 45-acre lease in the Hull-Daisetta Field. Pursuant to the agreement, the Company has the obligation to commence drilling a well on the lease by January 31, 2013. Subject to the commencement of drilling the first well by January 31, 2013, and completing the well if warranted, the Company has the option of drilling additional wells on the lease; provided however, that unless the Company commences drilling each well within 180 days of the date the latest well is completed or abandoned, the right to drill any additional wells on the lease will terminate. The estimated cost of drilling and completing any well on this lease is approximately $750,000. As of September 30, 2012, the Company had not drilled any wells on this lease.
On September 30, 2010, the Company acquired a forty percent (40%) working interest in mineral leases for 220 acres in Hardin County, Texas, within the area known as the Batson Dome Field, from C.F.O., Inc., a corporation controlled by Delton Drum, one of the Company’s officers, for the total consideration of $325,668, consisting of a cash payment of $40,000 and a secured 90-day promissory note for $285,668. On October 1, 2010, the Company acquired an additional fifty percent (50%) working interest in the Batson Dome Field for the total consideration of $407,085, consisting of a cash payment of $50,000 and a secured 90-day promissory note for $357,085. The 90-day promissory notes bore interest at eight percent (8%) per annum and were repaid in December 2010. Although the leases are in a previously developed oil and gas field, these purchases excluded any interest in existing well bores or surface equipment.
On December 16, 2010, and in payment of $259,247 in cash, the Company acquired a ninety percent (90%) working interest in 10 acres adjacent to its existing 220 acres under lease in the Batson Dome Field, as well as a ninety percent (90%) working interest in two producing oil wells and three shut in wells located on the 10 acre lease. The leases and wells were acquired from C.F.O., Inc. This purchase was accounted for under the acquisition method of accounting and, as such, the assets and liabilities of the acquired properties are recognized at their estimated fair values as of the date of the acquisition. The estimated fair value of these properties approximates the consideration paid, which the Company concluded approximates the fair value that would be paid by a typical market participant. Acquisition-related costs of approximately $15,000 were expensed. The purchase price for the acquisition was allocated as follows:
The unaudited financial information in the table below summarizes the combined results of the Company's operations and the properties acquired, on a pro forma basis, as though the purchase had taken place at the October 1, 2010. The pro forma information is based on the Company's results of operations for 2012 and 2011 on historical results of the properties acquired, and on estimates of the effect of the transactions to the combined results. Because the acquisitions occurred in prior periods, the 2012 pro forma amounts are the same as the actual amounts. The pro forma information is not necessarily indicative of results that actually would have occurred had the transaction been in effect for the periods indicated, or of results that may occur in the future.
VANGUARD ENERGY CORPORATION
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
Through these acquisitions, the Company owns a ninety percent (90%) working interest in mineral leases for 230 acres in the Batson Dome Field. C.F.O., Inc. is a related party and owns the remaining ten percent (10%) working interest and is the operator for the mineral leases pursuant to a joint operating agreement between the Company and C.F.O., Inc. The Company has recorded a receivable from C.F.O., Inc. for their 10% share of capital expenditures. At September 30, 2012, this amount totaled $238,940 and is expected to be repaid within the next twelve months from C.F.O., Inc.’s share of production or from other sources.
NOTE 4 - ASSET RETIREMENT OBLIGATIONS
During the fiscal years presented, the Company brought a number of oil and gas wells into productive status and will have asset retirement obligations once the wells are permanently removed from service. The primary obligations involve the removal and disposal of surface equipment, plugging and abandoning the wells, and site restoration. For the purpose of determining the fair value of ARO incurred during the fiscal years presented, the Company used the following assumptions:
VANGUARD ENERGY CORPORATION
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
The following table shows the change in the Company's ARO for 2011 and 2012:
VANGUARD ENERGY CORPORATION
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTE 5 - LONG-TERM DEBT
2010 Convertible Promissory Notes - In December 2010, the Company completed the issuance of $3,400,000 in Convertible Promissory Notes, due and payable on October 31, 2012 and convertible, at the holder’s option, into common stock of the Company at $1.00 per share at any time after April 30, 2011. The 2010 Convertible Promissory Notes bear interest at 8% per year, payable quarterly. In addition, the note holders were issued 1,700,000 Series A warrants to purchase the Company’s common stock at $4.00 per share any time on or before October 31, 2014 and were additionally granted a twenty percent (20%) net profits interest payable quarterly from any net profits generated from wells drilled and completed with the proceeds of the notes. The notes are secured by the oil and gas leases acquired, and any oil or gas wells drilled on the leases, with the proceeds from the sale of the notes.
Direct costs of $400,051 were incurred in connection with the issuance of the 2010 Convertible Promissory Notes. The Company also issued the placement agent Series B warrants for the purchase of up to 340,000 shares of common stock at a price of $1.20 per share at any time prior to October 31, 2014, 170,000 shares of common stock at a price of $4.00 per share at any time prior to October 31, 2014, and 453,322 shares of common stock at a price of $0.10 per share at any time prior to March 31, 2011. As of September 30, 2012, 453,322 warrants have been exercised. The warrants also provide for adjustment to their exercise prices under certain circumstances.
During 2012, $3,075,000 of the 2010 Convertible Promissory Notes outstanding were surrendered in exchange for new 2012 Convertible Promissory Notes as discussed below. The remaining notes, which had an outstanding principal balance of $325,000, were repaid in October 2012.
2012 Convertible Promissory Notes - During 2012, the Company issued $8,254,500 of Convertible Promissory Notes, due and payable on June 30, 2015 and convertible at the holder’s option, into common stock of the Company at $1.25 per share. The Convertible Promissory Notes bear interest at 15% per year, payable quarterly. Of the total amount raised, $5,179,500 represented new cash investors and $3,075,000 represented investors from the 2010 convertible note offering who chose to roll their investment in that earlier offering into the Company's new offering. Net proceeds from this financing are being used to fund an accelerated developmental drilling program in the Company's oil fields located in Southeast Texas and to pay any of the 2010 Convertible Promissory Notes that remain outstanding on October 31, 2012, the maturity date of those notes.
Except in certain circumstances, the conversion price of the 2012 Convertible Promissory Notes will be lowered if the Company sells any additional shares of common stock or any securities convertible into common stock, at a price below the then applicable conversion price. The conversion price will also be proportionately adjusted in the event of any stock split, or capital reorganization. On or prior to December 31, 2013, the Company may repay the Notes, without penalty, upon twenty days written notice to the Note holders if, during any twenty trading days within a period of thirty consecutive trading days, the closing price of the Company’s common stock is $2.25 or greater and the Company’s common stock has an average daily trading volume of 100,000 shares or more during the twenty trading days. After December 31, 2013 the Company may prepay the Notes upon twenty days written notice to the Note holders.
Direct costs of $813,780 were incurred in connection with the issuance of the 2012 Convertible Promissory Notes. The Company recognized a loss on debt extinguishment of $410,639 related to the investors who chose to roll their investment in the 2010 Convertible Promissory Notes into the new offering. The placement agents for this offering received a cash commission of $619,905 as well as 537,360 Series E warrants. Each Series E warrant entitles the holder to purchase one share of the Company’s common stock. The Series E warrants may be exercised at any time on or before June 30, 2017 at a price of $1.55 per share.
Total Indebtedness under Convertible Promissory Notes - The Company’s combined gross outstanding balance of the 2010 and 2012 Convertible Promissory Notes was $8,579,500 as of September 30, 2012. As of September 30, 2012, the combined unamortized discount on the 2010 and 2012 Convertible Promissory Notes totaled $713,332. Interest expense for the amortization of debt issuance costs and discount on the notes was $965,748 and $485,910 for the years ended September 30, 2012 and 2011, respectively. The combined effective interest rate of the 2010 and 2012 Convertible Promissory Notes (net of the participation liability discussed below) was 26.5% as of September 30, 2012.
VANGUARD ENERGY CORPORATION
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
Net Profits Interest Participation Liability - The note holder’s twenty percent (20%) net profits interest granted with the issuance of the 2010 Convertible Promissory Notes is owned by Vanguard Net Profits, LLC, a Texas limited liability company (the “Fund”). The Company has a 1% interest in the Fund and is the Fund’s manager. Persons that purchased the Company’s 2010 Convertible Promissory Notes own the remaining interest in the Fund.
The Company has recognized a participation liability related to the net profits interest granted. This participation liability is reflected in the liability section of the balance sheets at its estimated fair value of $1,573,605 as of September 30, 2012 and $1,172,315 as of September 30, 2011. At any time, the Company may purchase the net profits interests held by the Fund for $3,400,000.
The Company estimated the fair value of the participation liability utilizing a present value factor of 10 applied to proved developed reserves associated with the wells drilled and completed with the proceeds of the notes. Changes in the fair value of the participation liability are recorded as additions or deductions to the discount on the long-term debt to the extent 2010 Convertible Promissory Notes remain outstanding. Otherwise, changes in the participation liability are recorded to other expense in the statements of operations.
The Company incurred expense associated with this net profits interest during the years ended September 30, 2012 and 2011 of $97,535 and $108,503, respectively. This amount is reported as interest expense in the statement of operations. The Company also made payments under this arrangement of $375,470 and $329,006 during the years ended September 30, 2012 and 2011, respectively.
NOTE 6 - INCOME TAXES
The provision for income taxes consists of the following:
VANGUARD ENERGY CORPORATION
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
The provision for income taxes differs from the amount computed by applying the federal statutory income tax rate (34%) on operations as follows:
The components of the net deferred tax asset were as follows:
A valuation allowance has been established to offset reported deferred tax assets. The Company's accumulated net operating losses were approximately $8.8 million at September 30, 2012 and begin to expire if not utilized in the year 2030.
VANGUARD ENERGY CORPORATION
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTE 7 - STOCKHOLDERS' EQUITY
Preferred Stock-5,000,000 shares authorized, none issued or outstanding.
Common Stock-The Company is authorized to issue an aggregate of 50,000,000 shares of common stock with $0.00001 par value. In July 2010, the Company sold 4,900,000 shares of common stock at $0.001 per share in a private placement. In September 2010, the Company completed a second private placement of 1,012,500 shares of common stock at $0.40 per share. Net proceeds from the private placements were used for general corporate purposes, including capital expenditures.
In February and March 2011, the Company sold 1,500,000 units at a price of $1.00 per unit to private investors. Each unit consisted of one share of common stock and one Series C warrant. Each Series C warrant allows the holder to purchase one share of Company common stock at a price of $2.00 per share at any time prior to February 28, 2016. The Company also issued the placement agent Series D warrants for the purchase of up to 150,000 shares of common stock at a price of $1.20 per share at any time prior to February 28, 2016.
On December 2, 2011 the Company sold 4,800,000 units in an initial public offering at a price of $1.00 per unit. Each unit consisted of one share of the Company's common stock and one Class A warrant. Each Class A warrant entitles its holder to purchase one share of the Company's common stock at an exercise price of $1.50. The Class A warrants are exercisable at any time on or before November 29, 2016. The underwriters for the offering were paid a commission of $432,000 (9% of the gross offering proceeds) and a non-accountable expense allowance of $144,000 (3% of the gross offering proceeds). The underwriters also received warrants to purchase up to 480,000 units. Proceeds from the IPO were approximately $3,498,900 net of the underwriters’ discount and offering expenses.
During the years ended September 30, 2012 and 2011, the Company issued 60,690 and 15,000 shares, respectively, of restricted stock for investor relations consulting services. The Company recognized expense of $59,700 during 2012 and $15,000 during 2011 related to the issuance of these shares.
Following the above issuances of common stock, the Company has 12,741,512 shares issued and outstanding as of September 30, 2012.
VANGUARD ENERGY CORPORATION
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
Warrants-The following table summarizes certain information regarding outstanding warrants as of September 30, 2012 and 2011:
(1) Exercised in March 2011.
NOTE 8 - STOCK-BASED COMPENSATION
On January 10, 2011, the Board of Directors approved a Non-Qualified Stock Option Plan (the "Plan") which authorizes the issuance of up to 1,500,000 shares of Company common stock to persons that exercise options granted pursuant to the Plan. The Company's employees, directors, officers, consultants and advisors are eligible to be granted options pursuant to the Plan, provided however that bona fide services must be rendered by such consultants or advisors, and such services must not be in connection with the offer or sale of securities in a capital-raising transaction.
VANGUARD ENERGY CORPORATION
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
Options for the purchase of 850,000 shares of the Company's common stock were issued to members of executive management and the Board of Directors on January 10, 2011. The stock options have an exercise price of $1.00 per share and were fully vested on the date of grant. The fair value of each stock option grant was estimated on the date of grant using the Black-Scholes option pricing model and the following assumptions:
No stock options have been exercised to date. The Company recognized stock-based compensation expense of $243,731 during 2011 related to the issuance of these options.
NOTE 9 - COMMITMENTS AND CONTINGENCIES
Environmental Matters - The Company, as an owner or lessee and operator of oil and gas properties, is subject to various federal, state and local laws and regulations relating to discharge of materials into, and protection of, the environment. These laws and regulations may, among other things, impose liability on the lessee under an oil and gas lease for the cost of pollution clean-up resulting from operations and subject to the lessee to liability for pollution damages. In some instances, the Company may be directed to suspend or cease operations in the affected area. The Company maintains insurance coverage, which is believed customary in the industry, although the Company is not fully insured against all environmental risks.
The Company manages its exposure to environmental liabilities on properties to be acquired by identifying existing problems and assessing the potential liability. The Company also conducts periodic reviews, on a Company-wide basis, to identify changes in its environmental risk profile.
Management Agreements - In June 2010, the Company entered into an agreement with an entity controlled by its Chief Executive Officer ("CEO") to provide for his personal part-time management consulting services for $7,500 per month, on a month-to-month basis. Also in June 2010, the Company entered into a consulting services agreement with its Chairman of the Board to provide for his personal part-time management consulting services for $3,000 per month, on a month-to-month basis. Beginning in January 2011, the monthly payments were increased to $12,500 for the CEO and $10,000 for the Chairman. In May 2011, these consulting arrangements were replaced with employment agreements for each executive.
Office Lease - The Company leases office space under an operating lease. Rent expense for 2012 and 2011 totaled $81,641 and $47,076, respectively. Future minimum payments on office leases are shown below.
VANGUARD ENERGY CORPORATION
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
Contractual Obligations - The Company’s material future contractual obligations by fiscal year as of September 30, 2012 were as follows:
The Company has no contractual capital commitments outstanding at September 30, 2012. Management estimates the Company will spend approximately $7,000,000 during fiscal year 2013 for drilling and completing wells in the Batson Dome Field and various other projects.
NOTE 10 - FAIR VALUE OF FINANCIAL INSTRUMENTS
The following table summarizes the financial liabilities measured at fair value on a recurring basis as of September 30, 2012 and 2011:
Assets and liabilities that are not recognized or disclosed on a recurring basis include those measured at fair value in a business combination and the initial recognition of asset retirement obligations.
VANGUARD ENERGY CORPORATION
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
The following tables present a reconciliation of those liabilities measured at fair value on a recurring basis using significant unobservable inputs (Level 3):
NOTE 11 - SUPPLEMENTAL CASH FLOW INFORMATION
VANGUARD ENERGY CORPORATION
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTE 12 - SUPPLEMENTAL INFORMATION RELATING TO OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)
Results of operations. Results of operations for producing activities consist of all activities for the exploration, production and sale of oil and gas. Net revenues from production include only the revenues from the production and sale of oil and natural gas. Production costs are those incurred to operate and maintain wells and related equipment and facilities used in oil and gas operations. Income tax expense is calculated by applying the current statutory tax rates to the revenues after deducting costs, which include depreciation, depletion and amortization allowances, after giving effect to permanent differences. The results of operations exclude general office overhead and interest expense attributable to oil and gas activities.
Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development. Amounts reported as costs incurred include both capitalized costs and costs charged to expense during the year for oil and gas property acquisition, exploration and development activities. Costs incurred also include new asset retirement obligations established in the current year, as well as increases or decreases to the asset retirement obligations resulting from changes to cost estimates during the year. Exploration costs presented below include the costs of drilling and equipping successful exploration wells, as well as dry hole costs, leasehold impairments, geological and geophysical expenses, and the costs of retaining undeveloped leaseholds. Development costs include the costs of drilling and equipping development wells, and construction of related production facilities.
VANGUARD ENERGY CORPORATION
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
Capitalized costs. Capitalized costs include the cost of properties, equipment and facilities for oil and natural-gas producing activities. Capitalized costs for proved properties include costs for oil and natural-gas leaseholds where proved reserves have been identified, development wells, and related equipment and facilities, including development wells in progress. Capitalized costs for unproved properties include costs for acquiring oil and gas leaseholds where no proved reserves have been identified.
Costs Not Being Amortized. The following table sets forth a summary of oil and gas property costs not being amortized at September 30, 2012, by the period in which such costs were incurred. There are no individually significant properties or significant development projects included in costs not being amortized. The majority of the evaluation activities are expected to be completed within five years.
VANGUARD ENERGY CORPORATION
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
Oil and Gas Reserve Information. Nova Resources, Inc., an independent engineering firm, prepared the estimates of the proved reserves, future production, and income attributable to the leasehold interests as of September 30, 2012 and 2011. The estimated proved net recoverable reserves presented below include only those quantities that were expected to be commercially recoverable at prices and costs in effect at the balance sheet dates under the then existing regulatory practices and with conventional equipment and operating methods. Proved Developed Reserves represent only those reserves estimated to be recovered through existing wells. Proved Undeveloped Reserves include those reserves that may be recovered from new wells on undrilled acreage or from existing wells on which a relatively major expenditure for recompletion or secondary recovery operations is required. All of the Company's Proved Reserves are located onshore in the continental United States of America.
Discounted future cash flow estimates like those shown below are not intended to represent estimates of the fair value of oil and gas properties. Estimates of fair value should also consider unproved reserves, anticipated future oil and gas prices, interest rates, changes in development and production costs and risks associated with future production. Because of these and other considerations, any estimate of fair value is subjective and imprecise.
The following table sets forth estimates of the proved oil and gas reserves (net of royalty interests) for the Company and changes therein, for the periods indicated.
VANGUARD ENERGY CORPORATION
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
Estimated Quantities of Proved Reserves
Standardized Measure of Discounted Future Net Cash Flows. The Standardized Measure related to proved oil and gas reserves is summarized below. Future cash inflows were computed by applying a twelve month average of the first day of the month prices to estimated future production, less estimated future expenditures (based on year end costs) to be incurred in developing and producing the proved reserves, less estimated future income tax expense. Future income tax expenses are calculated by applying appropriate year-end tax rates to future pretax net cash flows, less the tax basis of properties involved. Future net cash flows are discounted at a rate of 10% annually to derive the standardized measure of discounted future net cash flows. This calculation procedure does not necessarily result in an estimate of the fair market value or the present value of the Company.
VANGUARD ENERGY CORPORATION
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
Standardized Measure of Oil and Gas
The following table sets forth the changes in standardized measure of discounted future net cash flows relating to proved oil and gas reserves for the periods indicated.
Changes in Standardized Measure
VANGUARD ENERGY CORPORATION
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTE 13 - QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
(1)
The sum of the individual quarterly income (loss) per share amounts may not agree with year-to-date net income per common share as each quarterly computation is based on the weighted-average number of common shares outstanding during that period. Securities deemed anti-dilutive were excluded from each quarter in which the Company reported a net loss.
SIGNATURES
In accordance with Section 13 or 15(d) of the Exchange Act, the Registrant has caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized on the 27th day of December, 2012.
VANGUARD ENERGY CORPORATION
By:
/s/ Warren Dillard
Warren Dillard, Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of l934, 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/ Warren M. Dillard
Principal Executive, Financial and Accounting Officer and Director
December 27, 2012
Warren M. Dillard
/s/ Gerald Bailey
Director
December 27, 2012
Gerald Bailey
/s/ Steven M. Powers
Director
December 27, 2012
Steven M. Powers