ITEM 1. BUSINESS
Corporate History and Organization
We were incorporated under the laws of the State of Nevada on April 12, 2005 under the name “Carlin Gold Corporation”. On July 19, 2005, we changed our name to “Nevada Gold Corp.” On October 18, 2005, we changed our name to “Gulf States Energy, Inc.” and increased our authorized capital from 100,000,000 shares of common stock to 500,000,000 shares of common stock, par value $0.001 per share. On September 5, 2006, we changed our name to “Strategic American Oil Corporation”. On April 4, 2012 we completed a one new share for twenty-five old share (1:25) reverse stock split and as a result our authorized capital decreased from 500,000,000 shares of common stock to 20,000,000 shares of common stock. Also, effective April 4, 2012, we changed our name to “Duma Energy Corp.” Effective May 16, 2012, we increased our authorized capital from 20,000,000 shares to 500,000,000 shares of common stock.
We own 100% of the issued and outstanding share capital of (i) Penasco Petroleum Inc., a Nevada corporation, (ii) Galveston Bay Energy, LLC, a Texas limited liability company, (iii) SPE Navigation I, LLC, a Nevada limited liability company, and (iv) Namibia Exploration, Inc., a Nevada corporation.
Our principal offices are located at 800 Gessner, Suite 200, Houston, Texas, 77024. Our telephone number is (281) 408-4880 and our fax number is (281) 408-4879.
General
We are a natural resource exploration and production company engaged in the exploration, acquisition, development, and production of oil and gas properties in the United States and onshore in Namibia, Africa. As of July 31, 2013, we maintain developed acreage both onshore and offshore in Texas and Illinois. As of July 31, 2013, we were producing oil and gas from our working interest in three wells onshore in Texas and in four offshore fields in Galveston Bay, Texas. During September 2012, we acquired, through the acquisition of Namibia Exploration Inc., a 39% non-operated working interest in a concession located onshore in Namibia, Africa.
As part of our ongoing business strategy, we continue to review and evaluate acquisition opportunities in the continental United States and internationally.
Exploration and Production Activities
Our oil and gas interests as of July 31, 2013 were as follows:
Producing properties
Galveston Bay, Texas
Through our subsidiary, Galveston Bay Energy, LLC (“GBE”), we hold majority interests (approximately 93% working interest) and operate four fields in the shallow waters of Galveston Bay which is Southeast of Houston, Texas. Currently, we are producing the four fields that were acquired with GBE. The fields were shut-in in September 2008 due to a direct hit from Hurricane Ike. The then-owner went into bankruptcy and the properties were purchased out of bankruptcy by a private seller who performed reconstruction work on the fields and later sold them to us.
The Welder Lease (Barge Canal), Texas
We own 100% working interest (72.5% net revenue interest) in approximately 81 acres of an oil and gas lease (the “Welder Lease”) located in Calhoun County, Texas. As of the date of this annual report, two wells are producing gas and oil from the property. One of the wells is an oil well requiring gas lift to produce and the other well is a naturally flowing gas well. A third well is utilized for salt water disposal.
Palacios Prospect, Texas
In September 2011, we purchased a non-operated working interest in mineral leases covering 460 acres onshore in Duval County, Texas. Our working interest in the lease area is 6.70732% to the casing point of the first well drilled and 5.5% after the casing point of the initial well and for subsequent operations in the lease area. Our net revenue interest in the prospect is 4.125%. In April 2012, the operator successfully completed the Palacios #1 well, which produces primarily natural gas.
Illinois
In January 2011, we entered into a farmout agreement covering our 10% working interest in multiple leases in or near Markham City, Illinois. Core Minerals Management II, LLC (“Core”) operates the properties in accordance with this farmout agreement. After payout of the property, $1,350,000 or 29,000 barrels, whichever comes first, provided that we hold less than 25% working interest in the property at payout, our working interest will be adjusted to 25%. During fiscal 2012, the operator drilled wells in the contract area and commenced a pilot waterflood project to re-pressurize the reservoir and enhance recovery of oil from the area. The wells in the project area produce oil.
In September 2013, we conveyed our interest in the Illinois and Palacios properties to Carter E & P, LLC, a company owned by our former Vice President of Operations.
Unproved properties - USA
Chapman Ranch II Prospect, Texas
In April 2012, we acquired 25% working interest in Chapman Ranch II Prospect in Nueces County, Texas. The well was drilled in June 2012; however, all attempts to bring the well into production failed. Abandonment operations will commence in the near future when scheduled by the operator pending rig availability. We will share 25% of the abandonment cost.
Curlee, Melody, and Dix Prospects, Texas
During August 2012, we leased approximately 190 acres of land in Bee County, Texas. The operator of the project is Carter E&P, a company owned by our former Vice President of Operations. We acquired a 50% working interest in the project. We drilled the first well on the prospect during the year ended July 31, 2013. The well was not successful and it was plugged and abandoned.
In December 2012, we acquired 23% working interest in a 366.85 acre tract of property, the Dix Prospect, in San Patricio County, Texas. The operator of the project is Carter E&P, a company owned by our former Vice President of Operations. The initial well was drilled in May 2013, but it was determined that the well could not produce economically. Accordingly, the well was plugged and abandoned.
During April 2013, we purchased a 12.5% working interest in a 260.12 acre tract of property, the Melody Prospect, in Bee County, Texas. The operator of the project is Carter E&P, a company owned by our former Vice President of Operations. The well was drilled in June 2013 and it was a dry hole. Accordingly, the well was plugged and abandoned.
In September 2013, we conveyed our interest in the Curlee, Dix, and Melody prospects as well as our interest in the Illinois properties to Carter E & P, LLC, a company owned by our former Vice President of Operations.
Unproved property - Namibia
Through our subsidiary, Namibia Exploration, Inc. (“NEI”), we hold the rights to a 39% working interest (43.33% cost responsibility) in an onshore petroleum concession (the “Concession”), located in the Republic of Namibia, measuring approximately 5.3 million acres and covered by Petroleum Exploration License No. 0038 as issued by the Republic of Namibia Ministry of Mines and Energy. We hold our working interest in the Concession in partnership with the National Petroleum Corporation of Namibia Ltd. (“NPC Namibia”) and Hydrocarb Namibia Energy Corporation (“Hydrocarb Namibia”), a company chartered in the Republic of Namibia and which is a majority owned subsidiary of Hydrocarb Corporation (“Hydrocarb”), a company organized under the laws of the State of Nevada. Hydrocarb Namibia, as operator of the Concession, holds a 51% working interest (56.67% cost responsibility) in the Concession and NPC Namibia now a 10% carried working interest in the Concession.
The concession specifies the following minimum cost responsibilities on an 8/8ths basis:
1) Initial Exploration Period (expires September 2015): Perform a hydrocarbon potential study, gather and review existing technical data including reprocessing of seismic lines, and acquire and process 750 kilometers of new 2D seismic data. The minimum expenditure is $4,505,000.
2) First renewal exploration period (two years from end of the initial exploration period): Acquire 200 square kilometers of 3D seismic data, interpret and map the data, design a drilling program, drill one well, conduct an environmental study, and relinquish 25% of the Exploration license area. The minimum expenditure is $17,350,000.
3) Second Renewal (Production License) Exploration Period (25 years): report on reserves and production, conduct and environmental study. The minimum expenditure is $300,000.
Oil and Gas Reserves
The following table illustrates provides a summary of our oil and gas reserves as of our fiscal year ended July 31, 2013, as estimated by third party reservoir engineers.
Summary of Oil and Gas Reserves as of July 31, 2013 Based on Average Fiscal-Year Prices
Estimates of proved reserves at July 31, 2013 and 2012 were prepared by Ralph E. Davis Associates, Inc. (“RED”), our independent consulting petroleum engineers. The technical persons responsible for preparing the reserve estimates are independent petroleum engineers and geoscientists that meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers.
The reserves in this report have been estimated using deterministic methods. For wells classified as proved developed where sufficient production history existed, reserves were based on individual well performance evaluation and production decline curve extrapolation techniques. Although the SEC’s reserves rules allow probable and possible reserves to be disclosed separately, we have elected not to disclose probable and possible reserves in this report.
Internal Controls Over Reserves Estimates Our policies regarding internal controls over the recording of reserves estimates require reserves to be in compliance with the SEC definitions and guidance and prepared in accordance with generally accepted petroleum engineering principles. Our internal controls over reserve estimates also include the following:
· Utilization of an independent consulting petroleum engineer for the preparation of reserves estimates for 100% of our reserves and
· Involvement of personnel with appropriate background and experience to oversee the reserves estimate process and provide the requested data to the independent petroleum engineer.
Our Vice President, Craig Alexander, is the technical person primarily responsible for overseeing the preparation of our reserves estimates. Mr. Alexander has a Bachelor of Science degree in Petroleum Engineering and over 22 years of industry experience with positions of increasing responsibility in production and completion engineering and operations management. Mr. Alexander reports directly to our Chief Executive Officer.
Technologies Used in Reserves Estimation
The SEC’s updated rules expanded the technologies that a company can use to establish reserves. The SEC now allows use of techniques that have been proved effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.
We used a combination of production and pressure performance, wireline wellbore measurements, simulation studies, offset analogies, seismic data and interpretation, wireline formation tests, geophysical logs and core data to calculate our reserves estimates.
RED used the definitions for proved reserves set forth in Regulation S-X Rule 4-10(a) and subsequent SEC staff interpretations and guidance. In the conduct of the reserve study, RED did not independently verify the accuracy and completeness of information and data furnished by us with respect to ownership interests, oil and gas production, well test data, historical costs of operation and development, product prices, or any agreements relating to current and future operations of the fields and sales of production. However, if in the course of the reserve study something came to the attention of RED which brought into question the validity or sufficiency of any such information or data, RED did not rely on such information or data until it had satisfactorily resolved its questions relating thereto or had independently verified such information or data. RED did not perform a personal field inspection of our properties.
Changes in Proved Undeveloped Reserves
As of July 31, 2013, we reported 7,219.73 MMcfe of proved undeveloped reserves, which represents a decrease of 6,055.74 MMcfe from July 31, 2012. The following table shows of the changes in total proved undeveloped reserves for 2013:
Before our acquisition of GBE during the year ended July 31, 2011, we had no proved undeveloped reserves. Accordingly, we have no proved undeveloped reserves that have been undeveloped for five years since their original disclosure as proved undeveloped reserves.
During the year ended July 31, 2012, we began our development program with the drilling of the State Tract 9-12A#4 well in the Tex2 Sand. During the year ended July 31, 2013, we determined that the well was not successful. Operations for this well held acreage that was lost because of the inability to establish production prior to the end of the lease term. Based on the results of this well, and the loss of a portion of the acreage in the reservoir, the reserves ascribed to this drilling location and other locations were removed from the 2013 reserve report. This adjustment accounts for 76% of the decrease in estimated undeveloped reserves.
In addition, based upon further geologic interpretation, we determined that the reserves for a fourth drilling location did not justify the drilling of the well. This accounted for 23% of the decrease in estimated undeveloped reserves.
Production and Price History
The table below sets forth the net quantities of oil and gas production, net of royalties, attributable to us in the years ended July 31, 2013, 2012 and 2011. For the purposes of this table, the following terms have the following meanings: (i) “Bbl” means one stock tank barrel or 42 U.S. gallons liquid volume; (ii) “MBbls” means one thousand barrels of oil; (iii) “Mcf” means one thousand cubic feet; (iv) “Mcfe” means one thousand cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of oil; (v) “MMcfe/d” means one million cubic feet equivalent per day, determined by using the ratio of six Mcf of natural gas to one Bbl of oil; and (vi) “MMcf” means one million cubic feet.
(1) Taxes, transportation and production-related administrative expenditures are included in lease operating expenses.
Net production includes only production that is owned by us, whether directly or beneficially, and produced to our interest, less royalties and production due to others. Production of natural gas includes only marketable production of gas on an “as sold” basis. Production of natural gas includes only dry, residue and wet gas, depending on whether liquids have been extracted before we passed title, and does not include flared gas, injected gas and gas consumed in operations. Recovered gas, lift gas and reproduced gas are not included until sold.
Drilling and Other Exploratory Development Activities
The following tables set forth information regarding (i) the number of net productive and dry exploratory wells drilled and (ii) the number of net productive and dry development wells drilled during the years indicated, expressed separately for oil and gas. For the purposes of this subsection:
(1) A dry well is an exploratory, development, or extension well that proves to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.
(2) A productive well is an exploratory, development, or extension well that is not a dry well.
(3) Completion refers to installation of permanent equipment for production of oil or gas, or, in the case of a dry well, to reporting to the appropriate authority that the well has been abandoned.
(4) The number of wells drilled refers to the number of wells completed at any time during the fiscal year, regardless of when drilling was initiated. A net well or acre is deemed to exist when the sum of fractional ownership working interests in gross wells or acres equals one.
For the purposes of this subsection (i) one or more completions in the same bore hole have been counted as one well, and (ii) a well with one or multiple completions at least one of which is an oil completion has been classified as an oil well. We do not have any wells with multiple completions.
Present Activities
We own a 25% non-operated interest in a well that was drilled onshore in Nueces County, Texas beginning in June 2012. The well was originally completed to a non-economic zone. We conducted a series of recompletions and reworks during the year ended July 31, 2013. The operations were not successful, and the well will be plugged and abandoned during the year ended July 31, 2014.
Delivery Commitments
None.
Productive Wells
The following table sets forth information regarding the total gross and net productive wells as of November 12, 2013, expressed separately for oil and gas. All of our productive oil and gas wells were located in Texas. For the purposes of this subsection: (i) one or more completions in the same bore hole have been counted as one well, and (ii) a well with one or multiple completions at least one of which is an oil completion has been classified as an oil well. We do not have any wells with multiple completions.
A productive well is an exploratory well, development well, producing well or well capable of production, but does not include a dry well. A dry well, or a dry hole, is an exploratory or a development well found to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.
A gross well is a well in which a working interest is owned, and a net well is the result obtained when the sum of fractional ownership working interests in gross wells equals one. The number of gross wells is the total number of wells in which a working interest is owned, and the number of net wells is the sum of the fractional working interests owned in gross wells expressed as whole numbers and fractions thereof. The “completion” of a well means the installation of permanent equipment for the production of oil or gas, or, in the case of a dry hole, to the reporting of abandonment to the appropriate agency.
Acreage
The following table sets forth information regarding our gross and net developed and undeveloped oil and natural gas acreage under lease as of November 12, 2013.
(1) The gross acreage cited includes leasehold acreage to be earned under the farm-out agreements.
A developed acre is an acre spaced or assignable to productive wells, a gross acre is an acre in which a working interest is owned, and a net acre is the result that is obtained when the sum of fractional ownership working interests in gross acres equals one. The number of net acres is the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.
Undeveloped acreage is considered to be those lease acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or natural gas, regardless of whether or not such acreage contains proved reserves, but does not include undrilled acreage held by production under the terms of a lease. As is customary in the oil and gas industry, we can retain our interest in undeveloped acreage by drilling activity that establishes commercial production sufficient to maintain the lease or by payment of delay rentals during the remaining primary term of the lease. The oil and natural gas leases in which we have an interest are for varying primary terms; however, most of our developed lease acreage is beyond the primary term and is held so long as oil or natural gas is produced in commercial quantities or operations are commenced to restore production.
Plan of Operations
Our Plan of Operations is described in Item 7 - Management’s Discussion and Analysis of Financial Condition and Results of Operation.
Government Regulation
General
The availability of a ready market for oil and gas production depends upon numerous factors beyond our control. These factors include local, state, federal and international regulation of oil and gas production and transportation, as well as regulations governing environmental quality and pollution control, state limits on allowable rates of production by a well or proration unit, the amount of oil and gas available for sale, the availability of adequate pipeline and other transportation and processing facilities, and the marketing of competitive fuels. State and federal regulations are generally intended to prevent waste of oil and gas, protect rights to produce oil and gas between owners in a common reservoir, and control contamination of the environment.
Applicable legislation is under constant review for amendment or expansion. These efforts frequently result in an increase in the regulatory burden on companies in our industry and a consequent increase in the cost of doing business and decrease in profitability. Numerous federal and state departments and agencies issue rules and regulations imposing additional burdens on the oil and gas industry that are often costly to comply with and carry substantial penalties for non-compliance. Our production operations may be affected by changing tax and other laws relating to the petroleum industry, constantly changing administrative regulations and possible interruptions or termination by government authorities.
The transportation and certain sales of natural gas in interstate commerce are heavily regulated by agencies of the federal government and are affected by the availability, terms and cost of transportation. The price and terms of access to pipeline transportation are subject to extensive federal and state regulation. The Federal Energy Regulatory Commission (FERC) is continually proposing and implementing new rules and regulations affecting the natural gas industry, most notably interstate natural gas transmission companies that remain subject to the FERC’s jurisdiction. The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the natural gas industry. Some recent FERC proposals may, however, adversely affect the availability and reliability of interruptible transportation service on interstate pipelines.
State regulatory authorities have established rules and regulations requiring permits for drilling operations, drilling bonds and reports concerning operations. Many states have statutes and regulations governing various environmental and conservation matters, including the establishment of maximum rates of production from oil and gas wells, and restricting production to the market demand for oil and gas. Such statutes and regulations may limit the rate at which oil and gas could otherwise be produced. Most states impose a production or severance tax with respect to the production and sale of crude oil, natural gas and natural gas liquids within their respective jurisdictions. State production taxes are generally applied as a percentage of production or sales.
Oil and gas rights may be held by individuals and corporations, and, in certain circumstances, by governments having jurisdiction over the area in which such rights are located. As a general rule, parties holding such rights grant licenses or leases to third parties, such as us, to facilitate the exploration and development of these rights. The terms of the licenses and leases are generally established to require timely development. Notwithstanding the ownership of oil and gas rights, the government of the jurisdiction in which the rights are located generally retains authority over the manner of development of those rights.
Environmental
General. Our activities are subject to local, state and federal laws and regulations governing environmental quality and pollution control in the United States. The exploration, drilling and production from wells, natural gas facilities, including the operation and construction of pipelines, plants and other facilities for transporting, processing, treating or storing natural gas and other products, are subject to stringent environmental laws and regulations by state and federal authorities, including the Environmental Protection Agency (“EPA”). These laws and regulations may require the acquisition of a permit by operators before drilling commences, prohibit drilling activities on certain lands lying within wilderness areas, wetlands and other ecologically sensitive and protected areas, and impose substantial remedial liabilities for pollution resulting from drilling operations. Such regulation can increase our cost of planning, designing, installing and operating such facilities.
Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of significant investigatory or remedial obligations, and the imposition of injunctive relief that limits or prohibits our operations. Moreover, some environmental laws provide for joint and several strict liability for remediation of releases of hazardous substances, rendering a person liable for environmental damage without regard to negligence or fault on the part of such person. In addition, we may be subject to claims alleging personal injury or property damage as a result of alleged exposure to hazardous substances, such as oil and gas related products.
Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly waste handling, storage, transport, disposal or cleanup requirements could materially adversely affect our operations and financial position, as well as those of the oil and gas industry in general. While we believe that we are in substantial compliance with current environmental laws and regulations and have not experienced any material adverse effect from such compliance, there is no assurance that this trend will continue in the future.
Waste Disposal. We currently lease, and intend in the future to own or lease, additional properties that have been used for production of oil and gas for many years. Although we and our operators utilize operating and disposal practices that are standard in the industry, previous owners or lessees may have disposed of or released hydrocarbons or other wastes on or under the properties that we currently own or lease or properties that we may in the future own or lease. In addition, many of these properties have been operated in the past by third parties over whom we had no control as to such entities’ treatment of hydrocarbons or other wastes or the manner in which such substances may have been disposed of or released. State and federal laws applicable to oil and gas wastes and properties may require us to remediate property, including ground water, containing or impacted by previously disposed wastes (including wastes disposed of or released by prior owners or operators) or to perform remedial plugging operations to prevent future or mitigate existing contamination.
We may generate wastes, including hazardous wastes, that are subject to the federal Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes. The EPA has limited the disposal options for certain wastes that are designated as hazardous under RCRA. Furthermore, it is possible that certain wastes generated by our oil and gas projects that are currently exempt from treatment as hazardous wastes may in the future be designated as hazardous wastes, and therefore be subject to more rigorous and costly operating and disposal requirements.
CERCLA. The federal Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the “Superfund” law, generally imposes joint and several liability for costs of investigation and remediation and for natural resource damages, without regard to fault or the legality of the original conduct, on certain classes of persons with respect to the release into the environment of substances designated under CERCLA as hazardous substances. These classes of persons or so-called potentially responsible parties include the current and certain past owners and operators of a facility where there is or has been a release or threat of release of a hazardous substance and persons who disposed of or arranged for the disposal of the hazardous substances found at such a facility. CERCLA also authorizes the EPA and, in some cases, third parties to take action in response to threats to the public health or the environment and to seek to recover from the potentially responsible parties the costs of such action. Although CERCLA generally exempts petroleum from the definition of hazardous substances, we may have generated and may generate wastes that fall within CERCLA’s definition of hazardous substances. We may in the future be an owner of facilities on which hazardous substances have been released by previous owners or operators of our properties that are named as potentially responsible parties related to their ownership or operation of such property.
Air Emissions. Our projects are subject to local, state and federal regulations for the control of emissions of air pollution. Major sources of air pollutants are subject to more stringent, federally imposed permitting requirements, including additional permits. Producing wells, gas plants and electric generating facilities generate volatile organic compounds and nitrogen oxides. Some of our producing wells may be in counties that are designated as non-attainment for ozone and may be subject to restrictive emission limitations and permitting requirements. If the ozone problems in the applicable states are not resolved by the deadlines imposed by the federal Clean Air Act, or on schedule to meet the standards, even more restrictive requirements may be imposed, including financial penalties based upon the quantity of ozone producing emissions. If we fail to comply strictly with air pollution regulations or permits, we may be subject to monetary fines and be required to correct any identified deficiencies. Alternatively, regulatory agencies could require us to forego construction, modification or operation of certain air emission sources.
Clean Water Act. The Clean Water Act imposes restrictions and strict controls regarding the discharge of wastes, including produced waters and other oil and natural gas wastes, into waters of the United States, a term broadly defined. Permits must be obtained to discharge pollutants into federal waters. The Clean Water Act provides for civil, criminal and administrative penalties for unauthorized discharges of oil, hazardous substances and other pollutants. It imposes substantial potential liability for the costs of removal or remediation associated with discharges of oil or hazardous substances. State laws governing discharges to water also provide varying civil, criminal and administrative penalties and impose liabilities in the case of a discharge of petroleum or its derivatives, or other hazardous substances, into state waters. In addition, the EPA has promulgated regulations that may require us to obtain permits to discharge storm water runoff, including discharges associated with construction activities. In the event of an unauthorized discharge of wastes, we may be liable for penalties and costs.
Oil Pollution Act. The Oil Pollution Act of 1990 (“OPA”), which amends and augments oil spill provisions of the Clean Water Act, and similar legislation enacted in Texas, Louisiana and other coastal states, impose certain duties and liabilities on certain “responsible parties” related to the prevention of oil spills and damages resulting from such spills in United States waters and adjoining shorelines. A liable “responsible party” includes the owner or operator of a facility or vessel that is a source of an oil discharge or poses the substantial threat of discharge, or the lessee or permittee of the area in which a facility covered by OPA is located. OPA assigns joint and several liability, without regard to fault, to each liable party for oil removal costs, remediation of environmental damage and a variety of public and private damages. OPA also imposes ongoing requirements on a responsible party, including proof of financial responsibility to cover at least some costs of a potential spill. Few defenses exist to the liability imposed by OPA. In the event of an oil discharge, or substantial threat of discharge from our properties, vessels and pipelines, we may be liable for costs and damages.
We believe that we are in substantial compliance with current environmental laws and regulations in each of the jurisdictions in which we operate. Although we have not experienced any material adverse effect from such compliance, there is no assurance that this trend will continue in the future.
Competition
The oil and natural gas industry is intensely competitive in all phases, including the exploration for new production and the acquisition of equipment and labor necessary to conduct drilling activities. The competition comes from numerous major oil companies as well as numerous other independent operators. There is also competition between the oil and natural gas industry and other industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers. We are a minor participant in the industry and compete in the oil and natural gas industry with many other companies having far greater financial, technical and other resources.
Competitive conditions may be substantially affected by various forms of energy legislation and/or regulation considered from time to time by the government of the United States and other countries, as well as factors that we cannot control, including international political conditions, overall levels of supply and demand for oil and gas, and the markets for synthetic fuels and alternative energy sources. Intense competition occurs with respect to marketing, particularly of natural gas.
Employees
We currently have twelve full-time employees and one part-time employee.
Subsidiaries
We own 100% of the issued and outstanding share capital of (i) Penasco Petroleum Inc., a Nevada corporation, (ii) Galveston Bay Energy, LLC, a Texas limited liability company, (iii) SPE Navigation I, LLC, a Nevada limited liability company, and (iv) Namibia Exploration, Inc., a Nevada corporation.
ITEM 1A.
ITEM 1A. RISK FACTORS
An investment in our common stock involves a number of very significant risks. You should carefully consider the following risks and uncertainties in addition to other information in this annual report in evaluating our company and its business before purchasing shares of our common stock. Our business, operating results and financial condition could be seriously harmed due to any of the following risks. The risks described below may not be all of the risks facing our company. Additional risks not presently known to us or that we currently consider immaterial may also impair our business operations. You could lose all or part of your investment due to any of these risks.
Risks Related to Our Company
Because we have only recently commenced business operations, we face a high risk of business failure.
We were incorporated on April 12, 2005 and originally planned to explore for gold and other minerals, but we soon shifted our focus to oil and gas exploration. Revenues were limited until our acquisition of GBE in 2011 and to date, we have not achieved profitability. Potential investors should be aware of the difficulties normally encountered by companies in the early stages of their life cycle and the high rate of failure of such enterprises. These potential problems include, but are not limited to, unanticipated problems relating to costs and expenses that may exceed current estimates. We have no actual company history upon which to base any assumption as to the likelihood that our business will prove successful, and it is possible, although not anticipated, that we may never achieve profitable operations.
We may not be able to effectively manage the demands required of a new business in our industry, such that we may be unable to successfully implement our business plan or achieve profitability.
We have earned limited revenues until recently (the past two years) and we have never achieved annual profitability. We may not be able to effectively execute our business plan or manage any growth, if any, of our business. Future development and operating results will depend on many factors, including access to adequate capital, the demand for oil and gas, price competition, and whether we can control costs. Many of these factors are beyond our control. In addition, our future prospects must be considered in light of the risks, expenses and difficulties frequently encountered in establishing a new business in the oil and gas industry, which is characterized by intense competition, rapid technological change, highly litigious competitors and significant regulation. If we are unable to address these matters, or any of them, then we may not be able to successfully implement our business plan or achieve profitability.
Because we have earned limited revenues from operations, most of our capital requirements have been met through financing and we may not be able to continue to find financing to meet our operating requirements.
We may need to obtain additional financing in order to pursue our business plan. As of July 31, 2013, we had cash and cash equivalents of $317,881 and a working capital deficit of $4,182,058. As such, unless our cash flow from operations is sufficient, we will need additional financing to pursue the exploration and development of our properties and pay for corporate overhead. We may not be able to obtain such financing at all or in amounts that would be sufficient for us to meet our current and expected working capital needs. Furthermore, in the event that our plans change or our assumptions change or prove inaccurate, we could be required to seek additional financing in greater amounts than is currently anticipated. Any inability to obtain additional financing when needed would have a material adverse effect on us, including possibly requiring us to significantly curtail or possibly cease our operations. In addition, any future equity financing may involve substantial dilution to our existing stockholders.
Because we have a history of losses and anticipate continued losses unless and until we are able to generate sufficient revenues to support our operations, we may lack the financial stability required to continue operations.
Since inception we have suffered recurring losses. We have funded our operations largely through the issuance of common stock in order to meet our strategic objectives. Our current level of oil and gas production is not sufficient to completely fund our exploration and development budget, such that we anticipate that we may need additional financing in order to pursue our plan of operations. We anticipate that our losses will continue until such time, if ever, as we are able to generate sufficient revenues to support our operations.
Costs of drilling, completing and operating wells is uncertain, and we may not achieve sufficient production to cover such costs.
The cost of drilling, completing and operating wells is often uncertain. We may not be able to achieve commercial production of oil and gas to pay such costs. Drilling operations on our properties or on properties we may acquire in the future may be curtailed, delayed or cancelled as a result of numerous factors, including title problems, weather conditions, compliance with governmental requirements and shortages or delays in the delivery of equipment. Furthermore, completion of a well does not assure a profit or a recovery of drilling, completion and operating costs. As a result, our business, results of operations and financial condition may be materially adversely affected.
Actual production, revenues and expenditures with respect to reserves will likely vary from estimates, which could have a material adverse effect on our business, results of operations and financial condition.
There are numerous uncertainties inherent in estimating oil and natural gas reserves and their estimated values, including many factors beyond the control of the producer. Reservoir engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. Estimates of economically recoverable oil and natural gas reserves and of future net cash flows necessarily depend upon a number of variable factors and assumptions, such as historical production from the area compared with production from other producing areas, the assumed effects of regulations by governmental agencies and assumptions concerning future oil and natural gas prices, future operating costs, severance and excise taxes, development costs and work-over and remedial costs, all of which may in fact vary considerably from actual results. For these reasons, estimates of the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, classifications of such reserves based on risk of recovery, and estimates of the future net cash flows expected there from prepared by different engineers or by the same engineers but at different times may vary substantially, and such reserve estimates may be subject to downward or upward adjustment based upon such factors. Actual production, revenues and expenditures with respect to reserves will likely vary from estimates, when and if made, and such variances may be material, which could have a material adverse effect on our business, results of operations and financial condition.
Our future oil and natural gas production is highly dependent upon our ability to find or acquire reserves.
In general, the volume of production from oil and natural gas properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. Except to the extent we conduct successful exploration and development activities or acquire properties containing proved reserves, or both, our proved reserves, if any, will decline as reserves are produced. Our future oil and natural gas production is, therefore, highly dependent upon our level of success in finding or acquiring reserves in the future. The business of exploring for, developing or acquiring reserves is capital intensive. To the extent cash flow from operations is reduced and external sources of capital become limited or unavailable, our ability to make the necessary capital investment to maintain or expand our asset base of oil and natural gas reserves would be impaired. The failure of an operator of our wells to adequately perform operations, or such operator’s breach of the applicable agreements, could adversely impact us. In addition, we may not obtain additional proved reserves or be able to drill productive wells at acceptable costs, in which case our business would fail.
Oil and gas resources may contain certain hazards which may, in turn, create certain liabilities or prevent the resources from being commercially viable.
Our properties may contain hazards such as unusual or unexpected formations and other conditions. Our projects may become subject to liability for pollution, fire, explosion, blowouts, cratering and oil spills, against which we cannot insure or against which we may decide to not insure. Such events could result in substantial damage to oil and gas wells, producing facilities and other property and/or result in personal injury. Costs or liabilities related to those events would have a material adverse effect on our business, results of operations, financial condition and cash flows.
Oil and gas prices are highly volatile, and a decline in oil and gas prices could have a material adverse effect on our business, results of operations, financial condition and cash flows.
Oil and gas prices and markets are highly volatile. Prices for oil and gas are subject to significant fluctuation in response to relatively minor changes in supply of and demand for oil and gas, market uncertainty and a variety of additional factors. Our profitability will be substantially dependent on prevailing prices for natural gas and oil. The amounts of and prices obtainable for our oil and gas production may be affected by market factors beyond our control, such as:
● the extent of domestic production;
● the amount of imports of foreign oil and gas;
● the market demand on a regional, national and worldwide basis;
● domestic and foreign economic conditions that determine levels of industrial production;
● political events in foreign oil-producing regions; and
● variations in governmental regulations and tax laws or the imposition of new governmental requirements upon the oil and gas industry.
These factors or any one of them could result in the decline in oil and gas prices, which could have a material adverse effect on our business, results of operations, financial condition and cash flows.
As a result of our intensely competitive industry, we may not gain enough market share to be profitable.
We compete in the sale of oil and natural gas on the basis of price and on the ability to deliver products. The oil and natural gas industry is intensely competitive in all phases, including the exploration for new production and the acquisition of equipment and labor necessary to conduct drilling activities. The competition comes from numerous major oil companies as well as numerous other independent operators in the United States and elsewhere. Because we are pursuing potentially large markets, our competitors include major, multinational oil and gas companies. There is also competition between the oil and natural gas industry and other industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers. We are a minor participant in the industry and compete in the oil and natural gas industry with many other companies having far greater financial, technical and other resources. If we are unable to compete successfully, we may never be able to sell enough product at a price sufficient to permit us to generate profits.
The oil and natural gas market is heavily regulated, and existing or subsequently enacted laws or regulations could limit our production, increase compliance costs or otherwise adversely impact our operations or revenues.
We are subject to various federal, state and local laws and regulations. These laws and regulations govern safety, exploration, development, taxation and environmental matters that are related to the oil and natural gas industry. To conserve oil and natural gas supplies, regulatory agencies may impose price controls and may limit our production. Certain laws and regulations require drilling permits, govern the spacing of wells and the prevention of waste and limit the total number of wells drilled or the total allowable production from successful wells. Other laws and regulations govern the handling, storage, transportation and disposal of oil and natural gas and any by-products produced in oil and natural gas operations. These laws and regulations could materially adversely impact our operations and our revenues.
Laws and regulations that affect us may change from time to time in response to economic or political conditions. Thus, we must also consider the impact of future laws and regulations that may be passed in the jurisdictions where we operate. We anticipate that future laws and regulations related to the oil and natural gas industry will become increasingly stringent and cause us to incur substantial compliance costs.
The nature of our operations exposes us to environmental liabilities.
Our operations create the risk of environmental liabilities. We may incur liability to governments or to third parties for any unlawful discharge of oil, gas or other pollutants into the air, soil or water. We could potentially discharge oil or natural gas into the environment in any of the following ways:
● from a well or drilling equipment at a drill site;
● from a leak in storage tanks, pipelines or other gathering and transportation facilities;
● from damage to oil or natural gas wells resulting from accidents during normal operations; or
● from blowouts, cratering or explosions.
Environmental discharges may move through the soil to water supplies or adjoining properties, giving rise to additional liabilities. Some laws and regulations could impose liability for failure to obtain the proper permits for, to control the use of, or to notify the proper authorities of a hazardous discharge. Such liability could have a material adverse effect on our financial condition and our results of operations and could possibly cause our operations to be suspended or terminated on such property.
We may also be liable for any environmental hazards created either by the previous owners of properties that we purchase or lease or by acquired companies prior to the date we acquire them. Such liability would affect the costs of our acquisition of those properties. In connection with any of these environmental violations, we may also be charged with remedial costs. Pollution and similar environmental risks generally are not fully insurable.
We could lose or fail to attract the personnel necessary to run our business.
Our success depends, to a large extent, on our ability to attract and retain key management and operating personnel. As we develop additional capabilities and expand the scope of our operations, we will require more skilled personnel. Recruiting personnel for the oil and gas industry is highly competitive. We may not be able to attract and retain qualified executive, managerial and technical personnel needed for our business. Our failure to attract or retain qualified personnel could delay or result in our inability to complete our business plan.
Our directors may experience conflicts of interest which may detrimentally affect our profitability.
Certain directors and officers may be engaged in, or may in the future be engaged in, other business activities on their own behalf and on behalf of other companies and, as a result of these and other activities, such directors and officers may become subject to conflicts of interest, which could have a material adverse effect on our business.
Risks Related to Our Common Stock
The trading price of our common stock may be volatile.
The price of our common shares may increase or decrease in response to a number of events and factors, including: trends in the oil and gas markets in which we operate; changes in the market price of oil and gas; current events affecting the economic situation in North America; changes in financial estimates; our acquisitions and financings; quarterly variations in our operating results; the operating and share price performance of other companies that investors may deem comparable; and purchase or sale of blocks of our common shares. These factors, or any of them, may materially adversely affect the prices of our common shares regardless of our operating performance.
A decline in the price of our common stock could affect our ability to raise further working capital and adversely impact our operations.
A decline in the price of our common stock could result in a reduction in the liquidity of our common stock and a reduction in our ability to raise additional capital for our operations. Because our operations to date have been largely financed through the sale of equity securities, a decline in the price of our common stock could have an adverse effect upon our liquidity and our continued operations. A reduction in our ability to raise equity capital in the future could have a material adverse effect upon our business plan and operations, including our ability to continue our current operations.
Our stock is a penny stock. Trading of our stock may be restricted by the SEC’s penny stock regulations and FINRA’s sales practice requirements, which may limit a stockholder’s ability to buy and sell our stock.
Our common stock will be subject to the “Penny Stock” Rules of the SEC, which will make transactions in our common stock cumbersome and may reduce the value of an investment in our common stock.
Our common stock is quoted on the OTC Bulletin Board, which is generally considered to be a less efficient market than markets such as NASDAQ or the national exchanges, and which may cause difficulty in conducting trades and difficulty in obtaining future financing. Further, our securities will be subject to the “penny stock rules” adopted pursuant to Section 15(g) of the Exchange Act. The penny stock rules apply generally to companies whose common stock trades at less than $5.00 per share, subject to certain limited exemptions. Such rules require, among other things, that brokers who trade “penny stock” to persons other than “established customers” complete certain documentation, make suitability inquiries of investors and provide investors with certain information concerning trading in the security, including a risk disclosure document and quote information under certain circumstances. Many brokers have decided not to trade “penny stock” because of the requirements of the “penny stock rules” and, as a result, the number of broker-dealers willing to act as market makers in such securities is limited. In the event that we remain subject to the “penny stock rules” for any significant period, there may develop an adverse impact on the market, if any, for our securities. Because our securities are subject to the “penny stock rules”, investors will find it more difficult to dispose of our securities. Further, it is more difficult: (i) to obtain accurate quotations, (ii) to obtain coverage for significant news events because major wire services, such as the Dow Jones News Service, generally do not publish press releases about such companies, and (iii) to obtain needed capital.
In addition to the “penny stock” rules promulgated by the SEC, FINRA has adopted rules that require a broker-dealer to have reasonable grounds for believing that an investment is suitable for a customer when recommending the investment to that customer. Prior to recommending speculative low-priced securities to their non-institutional customers, broker-dealers must make reasonable efforts to obtain information about the customer’s financial status, tax status, investment objectives and other information. Under interpretations of these rules, FINRA believes that there is a high probability that speculative low priced securities will not be suitable for at least some customers. FINRA requirements make it more difficult for broker-dealers to recommend that their customers buy our common stock, which may limit your ability to buy and sell our stock and have an adverse effect on the market for our shares.
ITEM 1B.
ITEM 1B.
UNRESOLVED STAFF COMMENTS
None.
ITEM 2.
ITEM 2. PROPERTIES
We hold certain oil and gas interests, as described in Item 1 hereto. In addition, we rent office space at 800 Gessner, Suite 200, Houston, Texas, 77024 for $6,900 per month and at 545 N. Upper Broadway, Suite 900, Corpus Christi, Texas, 78401 for $3,200 per month. In September 2013, we terminated our lease in Corpus Christi.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
As of July 31, 2013, we were party to the following legal proceedings:
1. Cause No. 2011-37552; Strategic American Oil Corporation v. ERG Resources, LLC, et al.; In the 55th District Court, Harris County, Texas. The Company is a plaintiff in this suit. In this case, Company brought claims for injunctive relief, breach of contract and fraudulent inducement against the defendant regarding the purchase of Galveston Bay Energy, LLC from ERG. The Company intends to prosecute its claims and defenses vigorously. As of the date of filing of this report, the Company is no longer seeking injunctive relief. Additionally, the below listed case has been consolidated into this case since the subject matter of the below case is subsumed within the subject matter of this case. From this point forward, there will be only this one piece of litigation. The trial was held in October 2013. The judge ruled in favor of ERG and that Duma is liable to pay the charges in the below-mentioned case and a portion of ERG’s attorney fees. Duma is in the process of post-trial motions and no judgment has been entered as of this date.
2. Cause No. 2011-54428; ERG Resources, LLC v. Galveston Bay Energy, LLC, in the 125th Judicial District Court, Harris County, Texas. This case deals with the operating agreements for the processing of product by the entities owned by ERG. It is an action seeking payments of charges and expenses by ERG that are refuted by GBE. The Company intends to prosecute its claims and defenses vigorously. As indicated above, this case has been consolidated into the case listed above. As such, the claims in this case will be decided in cause No. 2011-37552, which was tried in October 2013.
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
Market Information
Shares of our common stock became quoted on the OTC Bulletin Board under the symbol “SGCA” on August 14, 2008. On May 17, 2012, in connection with our name change, our symbol changed to “DUMA”.
The following tables set forth the high and low bid price per share of our common stock, as quoted on the OTC Bulletin Board, for fiscal 2012 and OTCQB, a marketplace for U.S. reporting companies operated by OTC Markets Group, for fiscal 2013. These over-the-counter market quotations reflect inter-dealer prices, without retail mark-up, markdown or commission and may not represent actual transactions. We do not have any securities that are currently traded on any other exchange or quotation system.
Holders
As of November 12, 2013, we had 88 shareholders of record.
Dividend Policy
No dividends have been declared or paid on our common stock. We have incurred recurring losses and do not currently intend to pay any cash dividends in the foreseeable future.
Securities Authorized For Issuance Under Compensation Plans
The following table sets forth information as of July 31, 2013:
Equity Compensation Plan Information
2013 Stock Incentive Plan
During February 2013, the Board of Directors authorized and approved the adoption of the 2013 Stock Incentive Plan (2013 Plan). An aggregate of 2,650,000 shares of common stock may be issued under the plan.
The Plan is administered by the Board of Directors, which has substantial discretion to determine persons, amounts, time, price, exercise terms, and restrictions of the grants, if any.
An award may not be exercised after the termination date of the award and may be exercised following the termination of an eligible participant’s continuous service only to the extent provided by the administrator under the 2013 Plan. If the administrator under the 2013 Plan permits a participant to exercise an award following the termination of continuous service for a specified period, the award terminates to the extent not exercised on the last day of the specified period or the last day of the original term of the award, whichever occurs first. In the event an eligible participant’s service has been terminated for “cause”, he or she shall immediately forfeit all rights to any of the awards outstanding.
The foregoing summary of the 2013 Plan is not complete and is qualified in its entirety by reference to the 2013 Plan, a copy of which is filed herewith.
During the year ended July 31, 2013, we granted 600,000 options to purchase shares of our common stock under the 2013 Plan. During the year ended July 31, 2013, 108,000 options to purchase shares of our common stock expired unexercised, which increased the number of shares available to be issued under the 2013 Plan.
Recent Sales of Unregistered Securities
Other than listed below, we have previously disclosed in our Quarterly Reports on Form 10-Q and/or Current Reports on Form 8-K all unregistered equity securities that we issued during our fiscal year ended July 31, 2013.
On February 11, 2013, we granted stock options to purchase an aggregate of 600,000 shares of our common stock to three of our directors. The options are exercisable at a price of $2.20 per share for a period of ten years, expiring on February 11, 2023. When granted, the options were subject to the following vesting schedule: 1/5 of such options to vest on each day that is six, 12, 18, 24 and 30 months from February 11, 2013. The grant of options was exempt from the registration requirements under the Securities Act pursuant to Rule 506 of Regulation D. In October 2013, we determined to accelerate the vesting of such options, such that all such options that had not yet vested became fully vested in October 2013.
Subsequent to our fiscal year ended July 31, 2013, as disclosed in our Current Report on Form 8-K as filed with the SEC on November 5, 2013, we issued 1,859,879 common shares to one creditor in connection with debt settlement. This issuance was exempt from the registration requirements under the Securities Act pursuant to Rule 506 of Regulation D.
ITEM 6.
ITEM 6.
SELECTED FINANCIAL DATA
We are a smaller reporting company as defined by Rule 12b-2 of the Exchange Act and are not required to provide the information required under this item.
ITEM 7.
ITEM 7.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion of our financial condition, changes in financial condition, plan of operations and results of operations should be read in conjunction with (i) our audited consolidated financial statements as at July 31, 2013 and 2012 and (ii) the section entitled “Business”, included in this annual report. The discussion contains forward-looking statements that involve risks, uncertainties and assumptions. Our actual results may differ materially from those anticipated in these forward-looking statements as a result of many factors, including, but not limited to, those set forth under “Risk Factors” and elsewhere in this annual report.
Executive Summary
To put into context the accomplishments of the last fiscal year, the following table shows the comparison for the last four years in certain key areas. Our focus, managerially, is on building revenue and cash flow. Our acquisition strategy will be driven by these same two criteria. We believe that shareholder returns and value will be most enhanced, at least in the short term, by focusing on increasing both revenue and cash flow.
Recent Highlights:
• Acquired new aerial gravity magnetic survey data over entire 5.3 million acre concession in Namibia, Africa.
• Partially completed first project of multi-well development program in Galveston Bay, averaging between approximately 60 barrels of oil per day.
• Eliminated more than $3 million of liability from the books by issuing stock to Hydrocarb.
• Hired Chuck Dommer as President to spearhead the operations and exploration efforts domestically and internationally.
• Shut-down offices in Corpus Christi and eliminated redundant personnel. Cost savings are estimated to be approximately $30,000 monthly.
Near Term Focus and Plans:
• Continue multi-well development program in Galveston Bay to enhance production, cash flow and reserves.
• Seek new partner to assist in financing new 2D seismic acquisition program in Namibia.
• Add new independent directors that can enhance our growth opportunities and expand the Company’s influence.
• Up-list to either NASDAQ or NYSE MKT stock markets to maximize liquidity and access to capital.
• Negotiate acquisition of Hydrocarb in order to better maximize shareholder value and gain operational synergy.
Plan of Operations
In Galveston Bay, Texas we plan to continue enhancing the production from our four productive fields. Our development program includes primarily reworking, infrastructure improvements, and recompletions, as well drilling, as to exploit the known reserves in at least 18 wells. Internal estimates show the projects, if successful, can almost quadruple current production enhancing cash flow significantly. Due to the fact that a large proportion of current operating costs in Galveston Bay are fixed it is expected that as production grows an increasing percentage of the revenue will contribute to positive cash flow. We plan to fund these projects as long as working capital and cash-flow permits and pending success of previous projects. If we are able to secure either bank or equity financing in the near future, this development plan can be accelerated.
In Namibia, Africa, in conjunction with the operator, Hydrocarb Energy Corp., we plan to interpret the newly acquired aerial gravity magnetic survey data and develop the acquisition plan for new 2D seismic data over the concession. This will include seeking a new partner that will, at least partially, carry us through the seismic acquisition program. 3D seismic will later be utilized for those identified structures which appear most prospective. Drilling of the first well is several years away. In the meanwhile, our goals are to increase the value and decrease the risk profile of our concession acreage in Namibia. Along these lines, Hydrocarb has engaged Netherland Sewell and Associates to conduct a resource estimate to confirm our belief that the concession could contain at least one billion barrels of oil.
Results of Operations
The following table sets out our consolidated losses for the periods indicated:
We recorded a net loss of $40,475,095, or $3.11 per basic and diluted common share, during the fiscal year ended July 31, 2013, as compared to a net loss of $4,579,724, or $0. 45 per basic and diluted common share, during the fiscal year ended July 31, 2012.
The changes in results were predominantly due to the factors below:
· Revenues decreased due to lower oil prices and to lower gas volumes produced in the current fiscal year in comparison to fiscal 2012.
· Lease operating expenses increased primarily due to the resumption of operations in one of our fields in Galveston Bay at the end of April 2012. Because it was shut in during the majority of the year ended July 31, 2012 and it was operating during the entire year ended July 31, 2013, costs were lower in 2012.
· Depreciation, depletion, and amortization increased because of an increase in the amortization rate, which was attributable to a reduction in estimated reserves in our reserve study dated July 31, 2013.
· Accretion increased because of an increase in the estimated asset retirement obligation due to change in estimates which occurred during the year ended July 31, 2013.
· Consulting fees - related party pertain to warrants granted as compensation to a company for investor relations and public relations services. This company is a related party, as it is controlled by the father-in-law of our CEO, Jeremy Driver. The warrant grant occurred in April 2011 and consisted of immediately vesting warrants and warrants that vest in accordance with a market condition. The warrants that vested immediately were valued using the Black-Sholes option pricing method and the expense was recognized on the vesting date. The warrants with a market condition are valued using a lattice model and the expense is amortized over the service period. See Note 9 - Capital Stock for more information about these warrants.
· Acquisition related costs - related party: During the year ended July 31, 2013, we incurred $37,234,752 of expense in conjunction with our acquisition of NEI. The transaction, which is a related party transaction, is discussed in detail in Note 2 of our Consolidated Financial Statements. This charge is the most significant difference in the results of operations from the comparable period in fiscal 2012. 2,490,000 shares of common stock were issued to the sellers of NEI and up to 22,410,000 additional shares of Duma common stock may be issued based on the achievement of certain market conditions over the next ten years. The estimated fair value of our commitment to issue the 22,410,000 shares was charged to expense as of the date of the transaction as required by relevant accounting standards. The estimated fair value of the contingently issuable shares was $31,612,000, the bulk of the charge. During the year ended July 31, 2012, we incurred an expense of $4,367,750 due to the excess of the fair value of the purchase price of SPE over the carrying value in the net assets acquired in the SPE acquisition, which was a separate related party transaction involving similar parties.
· Our decrease in general and administrative expenses is primarily attributable to a one-time stock grant, which resulted in approximately $600,000 of expense, which occurred during the year ended July 31, 2012. In addition, we experienced a decrease in legal, compliance, and professional expenses due to a general decrease in litigation during the current year. The decrease in expense was offset by an approximately $300,000 increase in the expenses associated with a compensation package, which included stock option grants and cash compensation, for independent directors that was adopted in February 2013.
· We incurred a loss on the sale of securities during the year ended July 31, 2013 due to the sale of securities that had declined in value since the time of acquisition. During the comparable year in 2012, we sold securities at a gain.
· We re-measured our derivative warrants at fair value at every reporting date until the derivative feature expired in October and November 2012. Change in the fair value of the derivative warrants, as determined using a lattice model, during the year ending July 31, 2013 was lower compared to the change in fair value for year ended July 31, 2012, which resulted in a minor decrease in the gain recognized.
· We recognized an income tax benefit during the year ended July 31, 2012 due to the ability to use tax assets, which had previously been reserved, because of a tax gain generated by the gain on sale of securities that had been acquired with the purchase of SPE and which had a significant built in capital gain when they were acquired. Our actual tax expense for fiscal 2012, based on tax returns completed during fiscal 2013, was lower than our estimate, which caused a further tax benefit in 2013. Since the tax benefit arose because we had acquired deferred tax liability in a business combination, we do not expect to reflect future tax benefits.
We consider the increase in acquisition-related costs-related party to be one time and non-recurring. We do not hold available of sale securities as of the year ended July 31, 2013 and as such we do not expect any further gains or losses attributable to available for sale securities. We consider the rest of the elements to be ongoing and part of our normal operations.
The following table sets forth our cash and working capital as of July 31, 2013 and July 31, 2012:
Subject to the availability of additional financing, in order to maximize production from our Galveston Bay properties, we plan approximately $2.4 million in capital expenditures in the next 12 months on the properties to include upgrading production facilities, new flowlines, recompletion of existing shut-in wells, and other projects aimed specifically at increasing production.
At July 31, 2013, we had $317,881 of cash on hand and a working capital deficit of $4,182,058. As such, our working capital alone on July 31, 2013 was insufficient to enable us to pay our lease operating costs, to pay our general and administrative expenses, and to also pursue our plan of operations over the next 12 months. Subsequent to July 2013, we settled approximately $1.8 million of the current liabilities then outstanding with the issuance of common stock. Additionally, our cash flow from operations has improved due to the partial completion of the first project in our multi-well development plan, and we believe it, in conjunction with the possible sale of some of our producing properties, will support the payment of outstanding obligations as well as our general and administrative expenses.
Our plan of operations over the next twelve months is dependent, at least in part, upon one or more of the following occurring:
1.
Raising capital through the sale of equity;
2.
Raising capital through the sale of working interest in our producing properties;
3.
Borrowing money from lenders to perform the work;
4.
Freeing up previously restricted cash (State bonding requirement) as shut-in wells are brought back into production and/or as wells are plugged;
5.
Performing work one project at a time (capital permitting) and using the increased cash flow to fund the next projects.
Our plan of operations over the next twelve months will always be subject to available capital which will be determined by the success of projects that are currently in progress or will begin soon. It is even possible that given a high degree success in recently initiated projects and upcoming projects we could actually exceed our planned operations and have more internally-derived funds available for capital expenditures for the next 12 months. As management, we will determine the best use of our capital given the circumstances at the time.
Various conditions outside of our control may detract from our ability to raise the capital needed to execute our plan of operations, including the price of oil as well as the overall market conditions in the international and domestic economies. We recognize that the United States economy and others have suffered through a period of uncertainty during which the capital markets have been highly volatile, and that there is no certainty that these markets will stabilize or improve. We also recognize that the price of oil decreased from approximately $140 per barrel in 2008 to under $40 per barrel in February of 2009. If the price of oil drops to levels seen in previous years, we recognize that it will adversely affect our cash flow from operations and our ability to raise additional capital. Any of these factors could have a material adverse impact upon our ability to raise capital or obtain financing and, as a result, upon our short-term or long-term liquidity.
Net Cash Provided by Operating Activities
During the year ended July 31, 2013, net cash provided by operating activities was $438,707 compared to net cash provided by operating activities of $626,076 during the year ended July 31, 2012.
Net Cash Provided by (Used in) Investing Activities
During the year ended July 31, 2013, we used cash of $951,841in investing activities compared to cash provided of $858,287 during the year ended July 31, 2012. . The use of cash in 2013 primarily consisted of investment in oil and gas assets. Investing activities during fiscal 2012 consist primarily of proceeds from the sale of available for sale securities, offset by the purchase of oil and gas properties.
Net Cash Used in Financing Activities
Financing activities during the year ended July 31, 2013 used cash of $271,972 compared to $1,463,475 used during the year ended July 31, 2012. This was primarily attributable to repayments of notes payable during the both these years.
Critical Accounting Policies
The financial statements have been prepared in conformity with accounting principles generally accepted in the United States of America and the rules of the Securities and Exchange Commission (“SEC”). The preparation of financial statements in conformity with U.S. generally accepted accounting principles requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods.
We regularly evaluate the accounting policies and estimates that we use to prepare our consolidated financial statements. In general, our estimates are based on historical experience, on information from third party professionals, and on various other assumptions that are believed to be reasonable under the facts and circumstances. Actual results could differ from those estimates made by management.
We believe that our critical accounting policies and estimates include the accounting for oil and gas properties, long-lived assets reclamation costs, the fair value of our warrant derivative liability, and accounting for stock-based compensation.
Oil and Natural Gas Properties
We account for our oil and natural gas producing activities using the full cost method of accounting as prescribed by the United States Securities and Exchange Commission (SEC). Under this method, subject to a limitation based on estimated value, all costs incurred in the acquisition, exploration, and development of proved oil and natural gas properties, including internal costs directly associated with acquisition, exploration, and development activities, the costs of abandoned properties, dry holes, geophysical costs, and annual lease rentals are capitalized within a cost center. Costs of production and general and administrative corporate costs unrelated to acquisition, exploration, and development activities are expensed as incurred.
Costs associated with unevaluated properties are capitalized as oil and natural gas properties but are excluded from the amortization base during the evaluation period. When we determine whether the property has proved recoverable reserves or not, or if there is an impairment, the costs are transferred into the amortization base and thereby become subject to amortization.
We assess all items classified as unevaluated property on at least an annual basis for inclusion in the amortization base. We assess properties on an individual basis or as a group if properties are individually insignificant. The assessment includes consideration of the following factors, among others: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; the assignment of proved reserves; and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate that there would be impairment, or if proved reserves are assigned to a property, the cumulative costs incurred to date for such property are transferred to the amortizable base and are then subject to amortization.
Capitalized costs included in the amortization base are depleted using the unit of production method based on proved reserves. Depletion is calculated using the capitalized costs included in the amortization base, including estimated asset retirement costs, plus the estimated future expenditures to be incurred in developing proved reserves, net of estimated salvage values.
The net book value of all capitalized oil and natural gas properties within a cost center, less related deferred income taxes, is subject to a full cost ceiling limitation which is calculated quarterly. Under the ceiling limitation, costs may not exceed an aggregate of the present value of future net revenues attributable to proved oil and natural gas reserves discounted at 10 percent using current prices, plus the lower of cost or market value of unproved properties included in the amortization base, plus the cost of unevaluated properties, less any associated tax effects. Any excess of the net book value, less related deferred tax benefits, over the ceiling is written off as expense. Impairment expense recorded in one period may not be reversed in a subsequent period even though higher oil and gas prices may have increased the ceiling applicable to the subsequent period. During the years ended July 31, 2013 and 2012, the ceiling exceeded the net book value of the property and it was not necessary to record an impairment charge.
Sales or other dispositions of oil and natural gas properties are accounted for as adjustments to capitalized costs, with no gain or loss recorded unless the ratio of cost to proved reserves would significantly change.
Asset Retirement Obligation
We record the fair value of an asset retirement cost, and corresponding liability as part of the cost of the related long-lived asset and the cost is subsequently allocated to expense using a systematic and rational method. We record an asset retirement obligation to reflect our legal obligations related to future plugging and abandonment of our oil and natural gas wells and gathering systems. We estimate the expected cash flow associated with the obligation and discount the amount using a credit-adjusted, risk-free interest rate. At least annually, we reassess the obligation to determine whether a change in the estimated obligation is necessary. We evaluate whether there are indicators that suggest the estimated cash flows underlying the obligation have materially changed. Should those indicators suggest the estimated obligation may have materially changed on an interim basis (quarterly), we will update our assessment accordingly. Additional retirement obligations increase the liability associated with new oil and natural gas wells and gathering systems as these obligations are incurred.
Fair Value
Accounting standards regarding fair value of financial instruments define fair value, establish a three-level hierarchy which prioritizes and defines the types of inputs used to measure fair value, and establish disclosure requirements for assets and liabilities presented at fair value on the consolidated balance sheets.
Fair value is the amount that would be received from the sale of an asset or paid for the transfer of a liability in an orderly transaction between market participants. A liability is quantified at the price it would take to transfer the liability to a new obligor, not at the amount that would be paid to settle the liability with the creditor.
The three-level hierarchy is as follows:
● Level 1 inputs consist of unadjusted quoted prices for identical instruments in active markets.
● Level 2 inputs consist of quoted prices for similar instruments.
● Level 3 valuations are derived from inputs which are significant and unobservable and have the lowest priority.
Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. We have determined that certain warrants outstanding during the period covered by these financial statements qualify as derivative financial instruments under the provisions of FASB ASC Topic No. 815-40, “Derivatives and Hedging - Contracts in an Entity’s Own Stock.” These warrant agreements include provisions designed to protect holders from a decline in the stock price (‘down-round’ provision) by reducing the exercise price in the event we issue equity shares at a price lower than the exercise price of the warrants. As a result of this down-round provision, the exercise price of these warrants could be modified based upon a variable that is not an input to the fair value of a ‘fixed-for-fixed’ option as defined under FASB ASC Topic No. 815-40 and consequently, these warrants must be treated as a liability and recorded at fair value at each reporting date.
The fair value of these warrants was determined using a lattice model with any change in fair value during the period recorded in earnings as “Gain (loss) on derivative warrant liability.”
Significant inputs used to calculate the fair value of the warrants include expected volatility, risk-free interest rate and management’s assumptions regarding the likelihood of a future repricing of these warrants pursuant to the down-round provision.
We had no financial assets and liabilities that were accounted for at fair value on a recurring basis as of July 31, 2013.
The following table sets forth the changes in the fair value measurement of our Level 3 derivative warrant liability during the years ended July 31, 2013 and 2012:
The unrealized gain on changes in fair value was recorded as a reduction of the derivative liability and as an unrealized gain on the change in fair value of the liability in our statement of operations.
The warrant agreement provides that the anti-dilution provisions expire three years after the issuance of the warrants. Accordingly, the provision for warrants to purchase 408,065 and 206,400 shares of common stock expired on October 15, 2012 and November 13, 2012, respectively. As of each those dates, the fair value of the warrant was determined for a final mark to market adjustment and the outstanding warrant derivative liability was reclassified to additional paid-in capital, as the warrants were no longer derivatives.
Stock-Based Compensation
ASC 718, “Compensation-Stock Compensation” requires recognition in the financial statements of the cost of employee services received in exchange for an award of equity instruments over the period the employee is required to perform the services in exchange for the award (presumptively the vesting period). We measure the cost of employee services received in exchange for an award based on the grant-date fair value of the award.
We account for non-employee share-based awards based upon ASC 505-50, “Equity-Based Payments to Non-Employees.” ASC 505-50 requires the costs of goods and services received in exchange for an award of equity instruments to be recognized using the fair value of the goods and services or the fair value of the equity award, whichever is more reliably measurable. The fair value of the equity award is determined on the measurement date, which is the earlier of the date that a performance commitment is reached or the date that performance is complete. Generally, our awards do not entail performance commitments. When an award vests over time such that performance occurs over multiple reporting periods, we estimate the fair value of the award as of the end of each reporting period and recognize an appropriate portion of the cost based on the fair value on that date. When the award vests, we adjust the cost previously recognized so that the cost ultimately recognized is equivalent to the fair value on the date the performance is complete.
We recognize the cost associated with share-based awards that have a graded vesting schedule on a straight-line basis over the requisite service period of the entire award.
See Note 1 of our Consolidated Financial Statements for our year ended July 31, 2013 for a summary of other significant accounting policies.
Off-Balance Sheet Arrangements
We have not entered into any off-balance sheet arrangements that have or are reasonably likely to have a current or future effect on our financial condition, changes of financial condition, revenues, expenses, results of operations, liquidity, capital expenditures or capital resources that is material to investors. See Note 12 of our Consolidated Financial Statements for a description of our multi-year commitments.
ITEM 7A.
ITEM 7A.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
We are a “smaller reporting company” as defined by Rule 12b-2 of the Exchange Act and are not required to provide the information required under this item.
ITEM 8.
ITEM 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
DUMA ENERGY CORP.
Index to Consolidated Financial Statements
The Board of Directors
Duma Energy Corp.
Houston, Texas
We have audited the accompanying consolidated balance sheets of Duma Energy Corp. and its subsidiaries (collectively, the “Company”) as of July 31, 2013 and 2012 and the related consolidated statements of operations and comprehensive loss, cash flows and changes in stockholders’ equity for each of the years then ended. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatements. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Duma Energy Corp. and its subsidiaries as of July 31, 2013 and 2012, and the results of their operations and their cash flows for each of the year then ended in conformity with accounting principles generally accepted in the United States of America.
/s/ MaloneBailey, LLP
www.malone-bailey.com
Houston, Texas
November 12, 2013
DUMA ENERGY CORP.
CONSOLIDATED BALANCE SHEETS
The accompanying notes are an integral part of these consolidated financial statements
DUMA ENERGY CORP.
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE LOSS
The accompanying notes are an integral part of these consolidated financial statements
DUMA ENERGY CORP.
CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY
On April 4, 2012, the Company effected a one-for-25 reverse stock split. All share and per share amounts have been retroactively restated to reflect the reverse split.
The accompanying notes are an integral part of these consolidated financial statements
DUMA ENERGY CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
The accompanying notes are an integral part of these consolidated financial statements
DUMA ENERGY CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS (CONTINUED)
The accompanying notes are an integral part of these consolidated financial statements
DUMA ENERGY CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1 - Description of Business and Summary of Significant Accounting Policies
Description of business and basis of presentation
Duma Energy Corp. (“we”, “us”, “Duma”, the “Company”) was formed for the purpose of oil and gas exploration, development, and production. We own 100% of Penasco Petroleum Inc. (“Penasco”), a Nevada corporation incorporated on November 23, 2005 and 100% of Galveston Bay, LLC, (“GBE”), a Texas limited liability company, 100% of SPE Navigation I, LLC (“SPE”) a Nevada limited liability company and 100% of Namibia Exploration, Inc. (“NEI”) a Nevada corporation. The financial statements have been prepared in conformity with accounting principles generally accepted in the United States of America and the rules of the Securities and Exchange Commission (“SEC”).
Reclassifications
Certain prior year amounts have been reclassified to conform with the current presentation.
Principles of consolidation
The accompanying consolidated financial statements include the accounts of Duma and our wholly owned subsidiaries, Penasco, SPE, GBE and NEI. All significant intercompany accounts and transactions have been eliminated in consolidation.
Use of estimates
The preparation of the consolidated financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the respective reporting periods. We base our estimates and judgments on historical experience and on various other assumptions and information that we believe to be reasonable under the circumstances. Estimates and assumptions about future events and their effects cannot be perceived with certainty and, accordingly, these estimates may change as new events occur, as more experience is acquired, as additional information is obtained and as our operating environment changes.
Significant areas requiring management’s estimates and assumptions include the determination of the fair value of transactions involving stock-based compensation and financial instruments, estimates of the costs and timing of asset retirement obligations, and oil and natural gas proved reserve quantities. Oil and natural gas proved reserve quantities which form the basis for the calculation of amortization of oil and natural gas properties and for asset impairment tests. Management emphasizes that reserve estimates are inherently imprecise and that estimates of more recent reserve discoveries are more imprecise than those for properties with long production histories.
Actual results may differ from the estimates and assumptions used in the preparation of our consolidated financial statements.
Cash and cash equivalents
Cash and cash equivalents are all highly liquid investments with an original maturity of three months or less at the time of purchase and are recorded at cost, which approximates fair value.
Our functional currency is the United States dollars. Transactions denominated in foreign currencies are translated into their United States dollar equivalents using current exchange rates. Monetary assets and liabilities are translated using exchange rates that prevailed as of the balance sheet date. Non-monetary assets and liabilities are translated using exchange rates that prevailed as of the transaction date. Revenue, if applicable and expenses are translated using average exchange rates over the accounting period. We have had no revenue denominated in foreign currencies. Gains or losses resulting from foreign currency transactions are included in results of operations.
Receivables and allowance for doubtful accounts
Oil and gas revenues receivable are recorded at the invoiced amount and do not bear any interest. We regularly review collectability and establish or adjust an allowance for uncollectible amounts as necessary using the specific identification method. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote. Management has determined that a reserve for uncollectible amounts was not required in the periods presented.
Accounts receivable - related party includes the oil and gas revenue receivable from our Barge Canal properties, which, up until September 1, 2013, were operated by a company owned by one of our former officers who was also a director, and joint interest billings receivable from two working interest partners who are related to the Chief Financial Officer and the Chief Executive Officer.
Other receivables consist of joint interest billings due to us from participants holding a working interest in oil and gas properties that we operate.
We regularly review collectability and establish or adjust an allowance for uncollectible amounts as necessary using the specific identification method. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote. As of July 31, 2013 and 2012, we have reserved $58,585 and $1,302, respectively, for potentially uncollectable other receivables.
Available for sale securities
We invest in marketable equity securities which are classified as available for sale. The first in first out method is used to determine the cost basis of our equity securities sold. Available-for-sale securities are marked to market based on the fair values of the securities determined in accordance with ASC Section 820 (Fair Value Measurement), with the unrealized gains and losses, net of tax, reported as a component of Accumulated other comprehensive income (loss).
Other current assets
Other current assets consist primarily of prepaid insurance, prepaid interest expense, prepayments made towards properties not operated by us, and accrued interest on our deposits.
Concentrations
Our operations are concentrated in Texas and the majority of our operations are conducted offshore in Galveston Bay. We operate in the oil and gas exploration and production industry. If the oil and natural gas exploration and production industry as a whole were adversely affected, for example by weather, supply shortages, or other factors, we would also experience adverse effects. Because our properties are offshore, we are also vulnerable to adverse weather.
For the year ended July 31, 2013, 85% of our revenue was attributable to one purchaser. At July 31, 2013, this same purchaser accounted for 76% of our accounts receivable. For the year ended July 31, 2012, 67% of our revenue was attributable to one purchaser. At July 31, 2012, this same purchaser accounted for 79% of our accounts receivable.
We place cash with high quality financial institutions and at times may exceed the federally insured limits. We have not experienced a loss in such accounts nor do we expect any related losses in the near term.
Oil and natural gas properties
We account for our oil and natural gas producing activities using the full cost method of accounting as prescribed by the United States Securities and Exchange Commission (SEC). Under this method, subject to a limitation based on estimated value, all costs incurred in the acquisition, exploration, and development of proved oil and natural gas properties, including internal costs directly associated with acquisition, exploration, and development activities, the costs of abandoned properties, dry holes, geophysical costs, and annual lease rentals are capitalized within a cost center. Costs of production and general and administrative corporate costs unrelated to acquisition, exploration, and development activities are expensed as incurred.
Costs associated with unevaluated properties are capitalized as oil and natural gas properties but are excluded from the amortization base during the evaluation period. When we determine whether the property has proved recoverable reserves or not, or if there is an impairment, the costs are transferred into the amortization base and thereby become subject to amortization.
We assess all items classified as unevaluated property on at least an annual basis for inclusion in the amortization base. We assess properties on an individual basis or as a group if properties are individually insignificant. The assessment includes consideration of the following factors, among others: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; the assignment of proved reserves; and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate that there would be impairment, or if proved reserves are assigned to a property, the cumulative costs incurred to date for such property are transferred to the amortizable base and are then subject to amortization.
Capitalized costs included in the amortization base are depleted using the unit of production method based on proved reserves. Depletion is calculated using the capitalized costs included in the amortization base, including estimated asset retirement costs, plus the estimated future expenditures to be incurred in developing proved reserves, net of estimated salvage values.
Sales or other dispositions of oil and natural gas properties are accounted for as adjustments to capitalized costs, with no gain or loss recorded unless the ratio of cost to proved reserves would significantly change.
Impairment
The net book value of all capitalized oil and natural gas properties within a cost center, less related deferred income taxes, is subject to a full cost ceiling limitation which is calculated quarterly. Under the ceiling limitation, costs may not exceed an aggregate of the present value of future net revenues attributable to proved oil and natural gas reserves discounted at 10 percent using current prices, plus the lower of cost or market value of unproved properties included in the amortization base, plus the cost of unevaluated properties, less any associated tax effects. Any excess of the net book value, less related deferred tax benefits, over the ceiling is written off as expense. Impairment expense recorded in one period may not be reversed in a subsequent period even though higher oil and gas prices may have increased the ceiling applicable to the subsequent period. During the years ended July 31, 2013 and July 31, 2012, the ceiling exceeded the net book value of the property and it was not necessary to record an impairment charge.
Asset retirement obligation
We record the fair value of an asset retirement cost, and corresponding liability as part of the cost of the related long-lived asset and the cost is subsequently allocated to expense using a systematic and rational method. We record an asset retirement obligation to reflect our legal obligations related to future plugging and abandonment of our oil and natural gas wells and gathering systems. We estimate the expected cash flow associated with the obligation and discount the amount using a credit-adjusted, risk-free interest rate. At least annually, we reassess the obligation to determine whether a change in the estimated obligation is necessary. We evaluate whether there are indicators that suggest the estimated cash flows underlying the obligation have materially changed. Should those indicators suggest the estimated obligation may have materially changed on an interim basis (quarterly), we will update our assessment accordingly. Additional retirement obligations increase the liability associated with new oil and natural gas wells and gathering systems as these obligations are incurred.
Restricted cash
Restricted cash consists of certificates of deposit that have been posted as collateral for letters of credit supporting bonds guaranteeing remediation of our oil and gas properties in Texas and escrow funds deposited directly with regulatory authorities. As of July 31, 2013 and 2012, restricted cash totaled $6,920,739 and $6,890,000, respectively.
Other assets
Other assets at July 31, 2013 and 2012 consisted primarily of prepaid land use fees, which are payments that cover multiple years (typically ten years) rental for easements and surface leases. These are paid as they come due on an ongoing basis and amortized over the rental period. In addition, other assets also include a domain name for $30,267, which is an intangible asset with an indefinite life due to the fact that it is renewable annually for nominal cost. We evaluate intangible assets with an indefinite life for possible impairment at least annually by comparing the fair value of the asset with its carrying value.
Property and equipment, other than oil and gas
Property and equipment are stated at cost, less accumulated depreciation. Depreciation is computed using the straight-line method over the estimated useful lives of the related asset, generally three to five years. Fully depreciated assets are retained in property and accumulated depreciation accounts until they are removed from service. We perform ongoing evaluations of the estimated useful lives of the property and equipment for depreciation purposes. Maintenance and repairs are expensed as incurred.
Impairment of long-lived assets
We periodically review our long-lived assets, other than oil and gas property, for impairment whenever events or changes in circumstances indicate that the carrying amount of the assets may not be fully recoverable. We recognize an impairment loss when the sum of expected undiscounted future cash flows is less than the carrying amount of the asset. The amount of impairment is measured as the difference between the asset’s estimated fair value and its book value. We recorded no impairment on our non-oil and gas long-lived assets during the years ended July 31, 2013 and 2012, respectively.
Advances
Advances consist of prepayments received from working interest partners pertaining to their share of the costs of drilling oil and gas wells. Partners are billed in advance for the estimated cost to drill a well and as the work proceeds, the prepayment is applied against their share of the actual drilling cost. As of July 31, 2013 and 2012, advances totaled $180,804 and $55,161, respectively.
Revenue recognition
We recognize revenue when persuasive evidence of an arrangement exists, services have been rendered, the sales price is fixed or determinable, and collectability is reasonably assured. We follow the “sales method” of accounting for oil and natural gas revenue, so we recognize revenue on all natural gas or crude oil sold to purchasers, regardless of whether the sales are proportionate to our ownership in the property. Actual sales of gas are based on sales, net of the associated volume charges for processing fees and for costs associated with delivery, transportation, marketing, and royalties in accordance with industry standards. Operating costs and taxes are recognized in the same period in which revenue is earned. Severance and ad valorum taxes are reflected as a component of lease operating expense.
Income taxes
We account for income taxes using the asset and liability method. Under this method, deferred income tax assets and liabilities are determined based on differences between the financial reporting and tax basis of assets and liabilities and are measured using the enacted tax rates and laws that will be in effect when the differences are expected to be recovered or settled. Deferred tax assets are reduced by a valuation allowance if, based on the weight of available evidence, it is more likely than not that some portion or all of the deferred tax assets will not be realized.
Fair value
Accounting standards regarding fair value of financial instruments define fair value, establish a three-level hierarchy which prioritizes and defines the types of inputs used to measure fair value, and establish disclosure requirements for assets and liabilities presented at fair value on the consolidated balance sheets.
Fair value is the amount that would be received from the sale of an asset or paid for the transfer of a liability in an orderly transaction between market participants. A liability is quantified at the price it would take to transfer the liability to a new obligor, not at the amount that would be paid to settle the liability with the creditor.
The three-level hierarchy is as follows:
● Level 1 inputs consist of unadjusted quoted prices for identical instruments in active markets.
● Level 2 inputs consist of quoted prices for similar instruments.
● Level 3 valuations are derived from inputs which are significant and unobservable and have the lowest priority.
Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. We have determined that certain warrants outstanding during the period covered by these financial statements qualify as derivative financial instruments under the provisions of FASB ASC Topic No. 815-40, “Derivatives and Hedging - Contracts in an Entity’s Own Stock.” (See Note 8 - Fair Value).
The fair value of these warrants was determined using a lattice model with any change in fair value during the period recorded in earnings as “Gain on derivative warrant liability.”
Significant inputs used to calculate the fair value of the warrants include expected volatility, risk-free interest rate and management’s assumptions regarding the likelihood of a future repricing of these warrants pursuant to the down-round provision.
We had no financial assets and liabilities that were accounted for at fair value on a recurring basis as of July 31, 2013 and our derivative warrant liability was our only financial asset or liability that was accounted for at fair value, using a Level 3 valuation technique, on a recurring basis as of July 31, 2012. The carrying amounts reported in the balance sheet for cash, accounts receivable, accounts receivable - related party, accounts payable and accrued expenses, and notes payable approximate their fair market value based on the short-term maturity of these instruments.
Stock-based compensation
ASC 718, “Compensation-Stock Compensation” requires recognition in the financial statements of the cost of employee services received in exchange for an award of equity instruments over the period the employee is required to perform the services in exchange for the award (presumptively the vesting period). We measure the cost of employee services received in exchange for an award based on the grant-date fair value of the award.
We account for non-employee share-based awards based upon ASC 505-50, “Equity-Based Payments to Non-Employees.” ASC 505-50 requires the costs of goods and services received in exchange for an award of equity instruments to be recognized using the fair value of the goods and services or the fair value of the equity award, whichever is more reliably measurable. The fair value of the equity award is determined on the measurement date, which is the earlier of the date that a performance commitment is reached or the date that performance is complete. Generally, our awards do not entail performance commitments. When an award vests over time such that performance occurs over multiple reporting periods, we estimate the fair value of the award as of the end of each reporting period and recognize an appropriate portion of the cost based on the fair value on that date. When the award vests, we adjust the cost previously recognized so that the cost ultimately recognized is equivalent to the fair value on the vesting date, which is presumed to be the date performance is complete.
We recognize the cost associated with share-based awards that have a graded vesting schedule on a straight-line basis over the requisite service period of the entire award.
Stock Split
On April 4, 2012, we effected a 1-for-25 reverse stock split. All share and per share amounts have been retroactively restated to reflect the reverse split. This presentation is consistent with the guidance in ASC 260-10-55-12, Earnings Per Share, which requires retroactive restatement of earnings per share if a capital structure change due to a stock dividend, stock split or reverse split occurs after the date of the latest balance sheet, but before the release of the financial statements or the effective date of the registration statement, whichever is later.
Earnings per share
We compute basic earnings per share using the weighted average number of shares of common stock outstanding during each period. Diluted earnings per share includes the dilutive effects of common stock equivalents on an “as if converted” basis. For the years ended July 31, 2013 and 2012, potential dilutive securities had an anti-dilutive effect and were not included in the calculation of diluted net loss per common share.
Contingencies
Legal
We are subject to legal proceedings, claims and liabilities which arise in the ordinary course of business. We accrue for losses associated with legal claims when such losses are probable and can be reasonably estimated. These accruals are adjusted as additional information becomes available or circumstances change. Legal fees are charged to expense as they are incurred. See Note 12 - Commitments and Contingencies for more information on legal proceedings.
Environmental
We accrue for losses associated with environmental remediation obligations when such losses are probable and can be reasonably estimated. These accruals are adjusted as additional information becomes available or circumstances change. Costs of future expenditures for environmental remediation obligations are not discounted to their present value. Recoveries of environmental remediation costs from other parties are recorded at their undiscounted value as assets when their receipt is deemed probable.
Accumulated Other Comprehensive Income (Loss), net of tax
We follow the provisions of ASC 220, "Comprehensive Income", which establishes standards for reporting comprehensive income. In addition to net loss, comprehensive loss includes all changes to equity during a period, except those resulting from investments and distributions to the owners of the Company. The components of accumulated other comprehensive loss:
Recent accounting pronouncements
Recently issued or adopted accounting pronouncements are not expected to have, or did not have, a material impact on our financial position or results from operations.
Note 2 - Acquisitions
SPE Navigation I, LLC
On September 23, 2011, Duma acquired SPE, which owned 25% of the working interest in the oil and gas properties originally owned by Galveston Bay Energy, LLC and 1,000,000 shares of Hyperdynamics Corporation, a public company traded on the New York Stock Exchange (NYSE:HDY). The total purchase price consisted of 3,799,998 shares of Duma’s common stock. We acquired 100% of the membership interest in SPE and thus SPE is our wholly owned subsidiary.
The transaction was a related party transaction because SPE was owned by companies controlled by our CEO, his brother-in-law, and his sister-in-law, and SPE was managed by our CEO’s father-in-law. The purchase price was calculated as $9,500,000, based on the quoted market price of our stock on the date of the acquisition. The assets and liabilities were recorded at fair value on the date of the acquisition, $5,132,250. The excess purchase price over the net assets acquired was $4,367,750, which was recorded as an acquisition-related expense because this was a related party transaction.
As of the acquisition date, the working interests previously owned by SPE were conveyed to GBE. Thus, all oil and gas revenues after the SPE acquisition were attributed to GBE. Our consolidated statements for 2013 include the results of SPE, and accordingly the 100% acquired working interest, for the entire year. Our consolidated statements for 2012 include the results of SPE after September 23, 2011.
Supplemental pro forma information (unaudited)
The unaudited pro forma results presented below for the year ended July 31, 2012 have been prepared to give effect to the purchase of SPE as if it had been consummated on August 1, 2011. The unaudited pro forma results do not purport to represent what our results of operations actually would have been if the acquisition had been completed on such date or to project our results of operations for any future date or period.
Namibia Exploration, Inc.
On August 7, 2012, we entered into a Share Exchange Agreement (the “Agreement”), which was closed on September 6, 2012, under which we purchased Namibia Exploration, Inc. ("NEI"), a corporation organized under the laws of the state of Nevada for the issuance of up to 24,900,000 shares of our common stock as described below. Prior to the acquisition, NEI was directly and indirectly owned and controlled by the CEO, his brother-in-law, and his father-in-law. As a result, the acquisition was accounted for as an asset purchase from an entity under common control and the asset was recorded at NEI’s historical cost. NEI originally acquired the concession from a subsidiary of Hydrocarb Corporation (“Hydrocarb”) in exchange for a farm-in fee, as discussed below, totaling $2,400,000, payable over two years. Hydrocarb is partly owned by the uncle of the Chief Executive Officer’s wife and brother-in-law. Because the $2,400,000 fee was a related party transaction, and accordingly presumed not to be arms-length, and because there was substantial uncertainty about the realizability of the fees paid to Hydrocarb given that the concession was unproved, management concluded that Hydrocarb’s historical expenditures of $562,048 (which consists primarily of fees paid to the Namibian government for the concession) represented the fair value of the asset and NEI’s cost basis in the asset. The farm-in agreement also provides for preferential offerings of other international oil and gas opportunities similar to the concession in Namibia.
NEI was formed in February 2012 and its sole asset was this oil and gas concession in Namibia, Africa. NEI had no operations other than ownership of this oil and gas concession; and accordingly, the transaction was accounted for as an asset purchase. Duma has assumed payment of the fee, as described below. Due to the fact that the former owners of NEI had no significant historical cost basis in NEI and the fact that the acquisition is accounted for as a related party transaction, the consideration that Duma paid beyond NEI’s cost basis ($562,048) is considered compensatory and thus an expense of the acquisition. The consideration included stock granted at the closing of the transaction as well as series of stock grants that are contingent upon the achievement of certain market conditions. The value of the total consideration, including contingent stock and the liabilities assumed in excess of NEI’s assets, was computed as described below. $37,234,752 is reflected in our statement of operations as Acquisition-related costs - related party in conjunction with this transaction.
As a result of the completion of the acquisition, NEI became a wholly-owned subsidiary of Duma. NEI holds the rights to 39% working interest (43.33% cost responsibility) in an onshore petroleum concession (the “Concession"), located in the Republic of Namibia, measuring approximately 5.3 million acres and covered by Petroleum Exploration License No. 0038 as issued by the Republic of Namibia Ministry of Mines and Energy.
The assignment of the 39% working interest to NEI from Hydrocarb Namibia, the operator of the concession, is subject to the prior approval of the government of the Republic of Namibia, which was obtained during August 2012. Duma now holds working interest in the Concession in partnership with the National Petroleum Corporation of Namibia Ltd. ("NPC Namibia") and Hydrocarb Namibia Energy Corporation ("Hydrocarb Namibia"), a company chartered in the Republic of Namibia and which is a majority owned subsidiary of Hydrocarb Corporation ("Hydrocarb"), a company organized under the laws of the State of Nevada. Hydrocarb Namibia, as operator of the Concession, now holds at 51% working interest (56.67% cost responsibility) in the Concession and NPC Namibia now holds a 10% carried working interest in the Concession. We have entered into a joint operating agreement with Hydrocarb Namibia effective August 29, 2012, that covers operations for the Concession.
Consideration for the acquisition of NEI
Pursuant to the terms of the Agreement, Duma issued 2,490,000 shares of common stock in September 2012 at the closing. Additional shares are required to be issued as consideration for the Acquisition, in accordance with the following milestones which must be reached within 10 years after the closing of the acquisition:
(a) a further 2,490,000 of the Shares will be issued when and if Duma's 10-day volume-weighted average market capitalization reaches $82,000,000;
(b) a further 7,470,000 of the Shares will be issued when and if Duma's 10-day volume-weighted average market capitalization reaches $196,000,000; and
(c) a further and final 12,450,000 of the Shares will be issued when and if Duma's 10-day volume-weighted average market capitalization reaches $434,000,000.
Duma will maintain 100% ownership of NEI after Closing even if one or more of the market capitalization milestones have not been attained within 10 years from the Closing. The accounting for this stock award is discussed in the section “Valuation” below.
Hydrocarb agreement
In conjunction with the execution of the Agreement, and as a condition of Closing, Duma has entered into a Consulting Services Agreement with Hydrocarb (the "Consulting Agreement"), whereby Hydrocarb will provide various consulting services with respect to Duma's business ventures in Namibia and whereby Hydrocarb has acknowledged and agreed that the obligations of NEI under its existing Farmin Opportunity Report with Hydrocarb (the "FOR") will be satisfied in exchange for Duma paying a consulting fee (the "Fee") to Hydrocarb of $2,400,000 as follows:
(a) payment on the later of the effective date of the Consulting Agreement or 15 days from the receipt of the working interest assignment under the FOR to be processed by Hydrocarb to be signed by Namibia's Minister of Mines and Energy, by Duma to Hydrocarb of $800,000 in cash or stock (at a deemed conversion price which equates to the then previous 60-day volume-weighted average trading price of Duma's common stock) or a combination of cash and stock. Duma has the sole and absolute discretion to select the manner of payment.
(b) for the remaining $1,600,000 by way of the issuance of a promissory note in favor of Hydrocarb in the principal amount of $1,600,000 (the "Promissory Note"), with interest accruing on the principal amount at the rate of 5% per annum, calculated semi-annually and payable in arrears, and of which $800,000 of the principal amount plus accrued interest is due on or before the first anniversary of the effective date and the remaining $800,000 of the principal amount plus accrued interest is due on or before the second anniversary of the effective date. Duma has the sole and absolute discretion to select whether payment of the note will be in stock (at a deemed conversion price which equates to the then previous 60-day volume-weighted average trading price of Duma's common stock), cash, or a combination of cash and stock.
Duma is required to pay a late fee of 10% per quarter for any outstanding balance of the Fee under the Consulting Agreement which will commence 30 calendar days from the date that the Fee or portion of the Fee is due, which may only be paid in cash. Duma has not yet paid the first installment as described in (a) above. Thus, the fee, which totals $320,000 as of July 31, 2013, has been accrued and it is characterized as interest expense. The fee is included in the balance sheet caption “Accounts payable and accrued expenses”.
Valuation
NEI’s cost basis in the concession is $562,048. Since Duma acquired the liability due to Hydrocarb, Duma acquired a net liability of $1,837,952. The assets and liabilities were recorded at NEI’s carrying value on the date of the acquisition and the excess purchase price over the net assets acquired was recorded as an acquisition-related expense (compensation) because this was a related party transaction. The purchase price consists of the 2,490,000 shares that were awarded at closing, which were valued using the closing market price of the stock on the date of grant, and the contingent stock grant. The fair value of equity compensation that vests upon the attainment of a market condition (in this case, market capitalization) must be estimated and recorded on the date of the grant. The fair value of the contingent stock grant was valued in accordance with ASC 820 - Fair Value Measurements. The determination of fair value used a market approach weighted at 75% and the income approach (discounted cash flows) weighted at 25%. The computations included consideration of projections of the future results of Duma and NEI, using multiple probability-weighted scenarios, and projections of Duma’s capital structure.
As of July 31, 2013, we had recognized $37,234,752 of expense associated with the acquisition of NEI, which consisted of the assumption of NEI’s net liability of $1,837,952, $3,784,800 associated with the 2,490,000 shares issued at the closing date of the acquisition and $31,612,000 associated with the contingent consideration.
Note 3 - Available for Sale Securities
Beginning in the quarter ended October 31, 2011, we owned marketable equity securities, which are classified as available for sale.
We acquired securities with a market value of $3,900,000 in conjunction with our acquisition of SPE. (See Note 2 - Acquisitions - SPE Navigation I, LLC). During the year ended July 31, 2012, we received cash proceeds of $4,009,548 from sales of securities with a cost basis of $3,546,431; thus, we had a realized gain on sale of available for sale securities of $463,117. During the year ended July 31, 2012, we also purchased securities at a market price of $702,959 and reclassified $6,383 unrealized loss from other comprehensive loss into earnings.
During September 2012, we received cash proceeds of $145,237 from sales of securities with a cost basis of $607,201; thus, we had a realized loss on sale of available for sale securities of $461,964. In October 2012, we recognized an other than temporary impairment of $275,327 resulting in a new cost basis in the stock of $174,000.
During December 2012, we received cash proceeds of $142,637 from sales of securities with a cost basis of $198,593; thus, we had a realized loss on sale of available for sale securities of $55,956. We reclassified $743,082 unrealized loss from other comprehensive loss into earnings in conjunction with these sales and the impairment.
As of July 31, 2013, we do not hold any available for sale securities.
Note 4 - Oil and Gas Properties
Oil and natural gas properties as of July 31, 2013 and July 31, 2012 consisted of the following:
Evaluated properties
We incurred geological and geophysical costs of $157,818 during the year ended July 31, 2013.
Offshore property
Our subsidiary, GBE, has interests in multiple leases with the State of Texas General Land Office in Galveston Bay. Through GBE, our primary operations are offshore in Galveston Bay. Significant changes to our offshore assets in Galveston Bay during the year ended July 31, 2013 include:
● costs associated with a development well, the State Tract 9-12A#4 well in Galveston Bay totaling $447,511;
● costs for a recompletion in Galveston Bay totaling $361,372; and
● increase in asset retirement obligations of $803,788 primarily due to changes in timing and in estimated costs for the gathering systems located in Galveston Bay.
Onshore property
As of July 31, 2013, we owned interests in properties in Texas and Illinois as follows:
Illinois
We owned 10% working interest in multiple leases in or near Markham City, Illinois that are operated by Core Minerals Management II, LLC (“Core”) in accordance with a farmout agreement, which we entered into during January 2011. After payout of the property, $1,350,000 or 29,000 barrels, whichever comes first, provided that we hold less than 25% working interest in the property at payout, our working interest will be adjusted to 25%. During fiscal 2012, the operator drilled wells in the contract area and commenced a pilot waterflood project to re-pressurize the reservoir and enhance recovery of oil from the area. The wells in the project area produce oil.
Texas
We own 100% working interest and a 72.5% net revenue interest in approximately 81 acres of an oil and gas lease (the “Welder Lease”) located in Calhoun County, Texas. There are two productive wells on the property, which was operated by a company owned by one of our former officers until September 1, 2013. Effective September 1, 2013, we took over operations of the lease.
In September 2011, we purchased a non-operated working interest in mineral leases covering 460 acres onshore in Duval County, Texas (the “Palacios Lease”). Under the agreement, the operator commenced drilling a well, the Palacios #1, during November 2011. Our working interest in the lease area is 6.70732% to the casing point of the first well drilled and 5.5% after the casing point of the initial well and for subsequent operations in the lease area. Our net revenue interest in the prospect is 4.125%. The well produces primarily gas.
In April 2012, we acquired 25% working interest in Chapman Ranch II Prospect in Nueces County, Texas (the “Chapman Prospect”). According to the terms of the agreement, we would pay 31.25% of costs to casing point of the initial well and of the plug and abandonment costs if the initial well is a dry hole and 25% of costs after casing point. For subsequent wells, we would pay 25% of the costs before and after the casing point. The well was drilled in June 2012; however, the first completion zone was non-economic. $265,639 in costs, including acquisition costs of $58,805 and drilling costs of $206,834, were reflected as unevaluated property as of July 31, 2012. During October 2012, we participated in a recompletion operation which resulted in the completion of the well into an upper zone, however commercial production was not established. Another rework operation was attempted in June 2013, which was unsuccessful. Because of the lack of success, management determined that there would be no reserves ascribed and the prospect is classified as evaluated as of the July 31, 2013.
During August 2012, we leased approximately 190 acres of land in Bee County, Texas (the “Curlee Prospect”). The operator of the project was Carter E&P, a company owned by our former Vice President of Operations. We had a 50% working interest in the project, 25% of which was carried to the casing point by the other participants in the initial well. Because we took a 25% additional interest, the portion of the working interest that we pay, prior to the casing point, is 33.3%. After the casing point and for all costs in future wells, we will be responsible for 50% of the costs. We paid $45,931 in acquisition and land costs for this prospect. We received a bonus of $51,589 from the other parties in the well, which was reflected as a reduction of capitalized costs in accordance with full cost accounting. During the quarter ended October 31, 2012, we drilled a well on the property, the Curlee No. 1 well, which was plugged and abandoned.
In December 2012, we acquired a 366.85 acre tract of property, the Dix Prospect, in San Patricio County, Texas. We paid $76,938 in acquisition and land costs. In February 2013, we sold 75% working interest in the prospect to partners on a third for a quarter basis, under which the 75% interest holders will carry 25% of the working interest to the casing point of the initial well drilled on the prospect. We also sold 2% of the carried working interest to Carter E&P, a company owned by our former Vice President of Operations. Thus we retained a 23% working interest which is carried to the casing point of the initial well. We received proceeds of $109,328 from the other parties in the prospect, which was reflected as a reduction of capitalized costs in accordance with full cost accounting. The initial well was drilled in May 2013, but it was determined that the well could not produce economically. Accordingly, it was not completed.
During April 2013, we purchased a 12.5% working interest in a 260.12 acre tract of property, the Melody Prospect, in Bee County, Texas. The operator of the project is Carter E&P, a company owned by our former Vice President of Operations. We incurred acquisition costs of $7,355 on the prospect. The well was drilled in June 2013 and it was a dry hole.
We incurred $210,588 of exploratory drilling costs during the year ended July 31, 2013 on the Chapman, Curlee, Dix, and Melody prospects.
Effective September 1, 2013, we conveyed our interest in the Dix, Melody, Curlee, Palacios and Illinois properties to Carter E&P in conjunction with our termination of Steven Carter as Vice President of Operations for $0 cash proceeds and the assumption of the abandonment liabilities.
Sales of properties
As of July 31, 2012, we owned a 6.25% overriding royalty interest in properties located in Franklin and Richland parishes in Louisiana (the “Holt” and “Strahan” properties). We also had a note receivable from the sale of our working interests in these properties, which had been fully reserved. In September 2012, we conveyed the overriding royalty interests to the operator and released the operator from any further liability from the note receivable in exchange for $50,000 cash. We allocated the cash proceeds between the note receivable and the overriding royalty interests based on the relative fair value of the balance on the note and the projected present value of the income streams from the royalty interests. The portion attributable to the overriding royalty interest, $32,146, was treated as a reduction of capitalized costs in accordance with rules governing full cost companies.
During December 2012, we sold our 3% working interest in the producing Janssen lease located in Karnes County, Texas. We received $2,500 as cash proceeds in conjunction with the sale. The buyer assumed the asset retirement obligation for the well, which was $438. In accordance with full cost rules, we recognized no gain or loss on the sale.
We received proceeds of $160,917 in conjunction with sales of interest in the Dix and Curlee prospects, as described above.
Unevaluated Properties
Namibia, Africa.
In September 2012, we acquired a 39% (43.33% cost responsibility) working interest in a concession in Namibia, Africa, as discussed in Note 2 - Acquisitions - Namibia Exploration, Inc. This property is a 5.3 million-acre concession in northern Namibia in Africa.
We have incurred total costs of $713,655, including NEI’s cost basis at the time we acquired the property, which was $562,048. The concession specifies the following minimum cost responsibilities on an 8/8ths basis:
1) Initial Exploration Period (expires September 2015): Perform a hydrocarbon potential study, gather and review existing technical data including reprocessing of seismic lines, and acquire and process 750 kilometers of new 2D seismic data. The minimum expenditure is $4,505,000.
2) First renewal exploration period (two years from end of the initial exploration period): Acquire 200 square kilometers of 3D seismic data, interpret and map the data, design a drilling program, drill one well, conduct an environmental study, and relinquish 25% of the Exploration license area. The minimum expenditure is $17,350,000.
3) Second Renewal (Production License) Exploration Period (25 years): report on reserves and production, conduct and environmental study. The minimum expenditure is $300,000.
As of July 31, 2013, approximately $900,000 has been expended towards the initial exploration period.
Note 5 - Impairment
We account for our oil and natural gas producing activities using the full cost method of accounting as prescribed by the United States Securities and Exchange Commission (“SEC”). Under this method, subject to a limitation based on estimated value, all costs incurred in the acquisition, exploration, and development of proved oil and natural gas properties, including internal costs directly associated with acquisition, exploration, and development activities, the costs of abandoned properties, dry holes, geophysical costs, and annual lease rentals are capitalized within a cost center.
We evaluated our capitalized costs using the full cost ceiling test as prescribed by the Securities and Exchange Commission at the end of each reporting period. As of July 31, 2013 and July 31, 2012, the net book value of oil and gas properties did not exceed the ceiling amount and thus, there was no impairment.
Changes in production rates, levels of reserves, future development costs, and other factors will determine our actual ceiling test calculation and impairment analyses in future periods.
Note 6 - Asset Retirement Obligation
The following is a reconciliation of our asset retirement obligation liability as of July 31, 2013 and 2012:
Note 7 - Notes Payable
Installment Notes Payable
In February 2012, we entered into a premium financing arrangement to pay principal of $209,244 in conjunction with our commercial insurance program renewal. We were obligated to make nine payments of $24,578 per month, which include principal and interest, beginning in March 2012. As of July 31, 2012, $96,252 remained unpaid on the note. As of July 31, 2013, the note payable balance was $0.
In May 2012, we entered into a note payable of $18,375 to purchase a vehicle. The note carries an interest rate of 6.93% and is payable beginning in June 2012, in 36 installments of $567 per month. The principal balance owed on the note payable was $17,451 and $11,678 as of July 31, 2012 and July 31, 2013, respectively.
In September 2012, we entered into a note payable of $1,600,000 with Hydrocarb Corporation, as described in Note 2 - Acquisitions - Namibia Exploration, Inc. The note carries interest of 5%; which is calculated semi-annually and payable with principal payments. Principal of $800,000 is due on August 7, 2013 and $800,000 is due on August 7, 2014. In October 2013, we paid off the note and accrued interest and fees associated with the note.
In March 2013, we financed our commercial insurance program using a note payable for $260,905. Under the note, we are obligated to make nine payments of $29,591 per month, which include principal and interest, beginning in March 2013. As of July 31, 2013, $115,958 remained outstanding on this note.
In June 2013, the outstanding balance on our line of credit, $300,000, was replaced by a term loan that matures on June 22, 2015. Under the term loan, we are obligated to make twenty four monthly payments of $12,500 principal reduction plus interest for the month. The note carries interest at prime + 1%, currently 6%. As of July 31, 2013, $275,000 remained outstanding on this note. As of November 12, 2013, the date of this report, $250,000 remained outstanding on the note.
As of July 31, 2013, future maturities on our notes payable were as follows:
Line of Credit
On March 17, 2011, GBE secured a one year revolving line of credit of up to with a commercial bank. The note specified interest at a rate of prime + 1% with a minimum interest rate of 5%. The initial interest rate was 6%. Interest is payable monthly. We must use proceeds from the line of credit solely to enhance our Galveston Bay properties. The note is collateralized by our Galveston Bay properties and substantially all GBE’s assets. Duma also executed a parental guarantee of payment. As of July 31, 2012 the amount outstanding under the line of credit was $300,000. The note was extended several times during fiscal 2013 and finally replaced by a term loan note in June 2013.
Note 8 - Fair Value
We had no financial assets and liabilities that were accounted for at fair value on a recurring basis as of July 31, 2013.
The following table sets forth by level within the fair value hierarchy our financial assets and liabilities that were accounted for at fair value on a recurring basis as of July 31, 2012.
Derivative Warrant Liability
Effective July 31, 2009, we adopted FASB ASC Topic No. 815-40 (formerly EITF 07-05) which defines determining whether an instrument (or embedded feature) is indexed to an entity’s own stock. This literature specifies that a contract that would otherwise meet the definition of a derivative but is both (a) indexed to our own stock and (b) classified in stockholders’ equity in the statement of financial position, would not be considered a derivative financial instrument and provides a new two-step model to be applied in determining whether a financial instrument or an embedded feature is indexed to an issuer’s own stock and thus able to qualify for the scope exception.
Certain warrants we issued during the year ended July 31, 2010 were not afforded equity treatment because these warrants had a down-round ratchet provision on the exercise price. As a result, the warrants were not considered indexed to our own stock, and as such, the fair value of the embedded derivative liability was reflected on the balance sheet and all future changes in the fair value of these warrants were recognized currently in earnings in our consolidated statement of operations under the caption “Gain (loss) on warrant derivative liability” until such time as the warrants are exercised or the down-ratchet provision expires. The total fair values of the warrants issued during the year ended July 31, 2010, were determined using a lattice model and have been recognized as a derivative liability as described below.
The warrants were valued using a multi-nomial lattice model with the following assumptions:
· The stock price on the valuation date would fluctuate with our projected volatility;
· Warrant holders would exercise at target price multiples of the market price trigger prices. The target price multiple reduces as the warrants approach maturity;
· Warrant holders would exercise the warrant at maturity if the stock price was above two times the reset exercise price;
· An annual reset event would occur at 65% discount to market price;
· The projected volatility was based on historical volatility. Because we did not have sufficient trading history to determine our own historical volatility, we used the volatility of a group of comparable companies combined with our own historical volatility from May 2009, when we began trading.
The following table sets forth the changes in the fair value measurement of our Level 3 derivative warrant liability during the years ended July 31, 2013 and 2012:
The unrealized gain on changes in fair value was recorded as a reduction of the derivative liability and as an unrealized gain on the change in fair value of the liability in our statement of operations.
The warrant agreement provides that the anti-dilution provisions expire three years after the issuance of the warrants. Accordingly, the provision for warrants to purchase 408,065 and 206,400 shares of common stock expired on October 15, 2012 and November 13, 2012, respectively. As of each those dates, the fair value of the warrant was determined for a final mark to market adjustment and the outstanding warrant derivative liability was reclassified to additional paid-in capital, as the warrants were no longer derivatives.
Note 9 - Capital Stock
On April 4, 2012, we effected a reverse stock split of our authorized, issued and outstanding shares of common stock on a one new share for twenty-five old share basis (1:25). The effect of the reverse stock split has been retroactively applied to all periods presented.
As a result of the reverse split, our authorized share capital decreased from 500,000,000 shares of common stock to 20,000,000 shares of common stock and correspondingly, our issued and outstanding share capital decreased from 269,742,986 shares of common stock to 10,791,003 shares of common stock.
Effective May 16, 2012, Duma increased the number of its authorized shares of common stock from 20,000,000 shares, par value $0.001 per share, to 500,000,000 shares, par value $0.001 per share.
Our capitalization at July 31, 2013 was 500,000,000 authorized common shares with a par value of $0.001 per share.
Common Stock Issuances
During August 2011, we granted 189,585 shares of common stock to certain investors who had participated in our October and November 2009 equity raises, and as a consequence owned derivative warrants. These investors had exercised some of their warrants prior to our equity raise in February 2011, which triggered the down-round ratchet provision in the warrants. The warrant contracts specify that the ratchet adjustment is not made for warrants that were exercised prior to the repricing event. As a consequence of their warrant exercises, they had forfeited their contractual right to receive ratchet warrant shares. However, management granted stock to these investors as a goodwill gesture. The stock grant was treated as an investor relations expense and valued at $592,452. The shares were valued using the closing market price on the date of grant.
During December 2011 we granted 13,036 shares of common stock as compensation for services valued at $27,703. The shares were valued using the closing market price on the date of the grant.
During the quarter ended April 30, 2012, we canceled 2,431 shares that had previously been deemed issued to two consultants. No adjustment to compensation was made in conjunction with this settlement.
During September 2011, we issued 3,799,998 shares of common stock to the members of SPE Navigation I, LLC towards acquisition of SPE. The purchase price was calculated as $9,500,000, based on the quoted market price of our stock on the date of the acquisition.
During September 2012, we issued 2,490,000 shares of common stock to the owners of Namibia Exploration, Inc. (“NEI”) for the acquisition of NEI. The shares were valued at $3,784,800, based on the quoted market price of our stock on the date of the acquisition. Additionally, $31,612,000 was recognized in conjunction with our commitment to issue additional stock if certain market conditions are achieved. (See Note 2 - Acquisitions - Namibia Exploration, Inc.)
Stock Compensation Plans
A new 2013 Stock Incentive Plan (2013 Plan) was approved by the Board during February 2013. The 2013 Plan replaced our prior stock incentive plans. Duma may grant up to 2,650,000 shares of common stock under the 2013 Plan. The Plan is administered by the Board of Directors, which has substantial discretion to determine persons, amounts, time, price, exercise terms, and restrictions of the grants, if any.
The fair value of each option or warrant award is estimated using the Black-Scholes valuation model. Expected volatility is based solely on historical volatility because we do not have traded options. Prior to May 2009, the volatility was determined by referring to the average historical volatility of a peer group of public companies because we did not have sufficient trading history to determine our own historical volatility. Beginning with computations after May 2009, when there was an active trading market for our stock, we have included our own historical volatility in determining the volatility used. As of October 2013, we determined that 4.5 years of trading history was sufficient to determine historical volatility; accordingly valuations from October 2013 onwards will be performed without using a peer group.
The expected term calculation for stock options is based on the simplified method as described in the Securities and Exchange Commission Staff Accounting Bulletin number 107. We use this method because we do not have sufficient historical information on exercise patterns to develop a model for expected term. The risk-free interest rate is based on the U. S. Treasury yield in effect at the time of grant for an instrument with a maturity that is commensurate with the expected term of the stock options. The dividend yield rate of zero is based on the fact that we have never paid cash dividends on our common stock and we do not intend to pay cash dividends on our common stock.
Options granted to non-employees
The following table details the significant assumptions used to compute the fair market values of stock options granted or revalued during the years ended July 31:
In February 2013, options to purchase an aggregate of 600,000 shares of common stock with an exercise price of $2.20 per share and a term of ten years were granted to our three independent directors. The options vest 20% each six months over the 30 months following the award. The fair value of the total option award on the date of grant was $1,196,589. The fair market value of this award was estimated using the Black-Sholes option pricing model.
No options were granted to non-employees during the year ended July 31, 2012. Expense during 2012 consists of the amortization of options granted prior to July 31, 2012.
The following table provides information about options granted to non-employees under our stock incentive plans during the years ended July 31, 2013 and 2012:
Based on the fair value of the options as of July 31, 2013, there was $1,011,847 of unrecognized compensation costs related to non-vested share based compensation arrangements granted to non-employees.
We account for options granted to non-employees under the provisions of ASC 505-50 and record the associated expense at fair value on the final measurement date. Because there is no disincentive for nonperformance for these awards, the final measurement date occurs when the services are complete, which is the vesting date. For the options granted to non-employees on a graded vesting schedule, we estimate the fair value of the award as of the end of each reporting period and recognize an appropriate portion of the cost based on the fair value on that date. When the award vests, we adjust the cost previously recognized so that the cost ultimately recognized is equivalent to the fair value on the vesting date, which is presumed to be the date the performance is complete.
Options granted to employees
The following table provides information about options granted to employees under our stock incentive plans during the years ended July 31, 2013 and 2012:
During the year ended July 31, 2011, options to purchase 260,000 shares of common stock with an exercise price of $2.50 per share and a term of ten years were granted to five employees. The options vest 20% each six months over the 30 months following the award. Because the grantees were employees, the awards are accounted for under the provisions of ASC 718. Accordingly, they are measured at fair value on the date of grant and the expense associated with the grant will be amortized over the 30 month vesting period on a straight line basis. As of July 31, 2013, we had $56,917 in unamortized compensation expense associated with options granted to employees.
No options were granted to employees during the years ended July 31, 2013 or 2012.
Summary information regarding stock options issued and outstanding as of July 31, 2013 is as follows:
Summary information regarding nonvested stock options as of July 31, 2013 is as follows:
Warrants
Warrants granted to related party
During the year ended July 31, 2011, we entered into a consulting agreement with Geoserve Marketing, LLC (“Geoserve”), a company controlled by Michael Watts, who is the father-in-law of Jeremy Driver, a Director and our Chief Executive Officer. Under the terms of the agreement, we granted warrants to purchase 1,200,000 shares of common stock that have a market condition. If our common stock attains a five day average closing price of $7.50 per share, 600,000 warrants with an exercise price of $2.50 and an expiration date of February 15, 2016 shall be exercisable (“Warrant B”). If our common stock attains a five day average closing price of $15.00 per share, 600,000 warrants with an exercise price of $2.50 and an expiration date of February 15, 2016 shall be exercisable (“Warrant C”). The fair value of warrants that vest upon the attainment of a market condition must be estimated and amortized over the lower of the implicit or derived service period of the warrants. Previously recognized expense is not reversed in the event of a subsequent decline in the fair value of market condition equity based compensation. The fair value of the warrants and the derived service period were valued using a lattice model that values the liability of the warrants based on a probability weighted discounted cash flow model. This model is based on future projections of the various potential outcomes. Warrant B and Warrant C will be amortized over the derived service periods of 2.08 years and 2.49 years, respectively. The following table reflects information regarding Warrant B and Warrant C as of July 31, 2013 and 2012:
Summary information regarding common stock warrants issued and outstanding as of July 31, 2013, is as follows:
Warrants outstanding and exercisable as of July 31, 2013:
Warrants outstanding and exercisable as of July 31, 2012:
Note 10 - Related Party Transactions
During the years ended July 31, 2013 and 2012, a company controlled by one of our former officers, Carter E & P (“Carter”) operated several properties onshore in South Texas, including our Barge Canal properties. Although he was not a related party after September 2013, we considered the transactions with his company during his tenure as an officer of Duma as related party transactions because they were not compensation or ordinary course of business, and because he was a related party at the time they occurred. Revenues generated, lease operating costs, and contractual overhead charges, which are included in lease operating costs incurred from these properties, were as follows:
In February 2013, we sold a 2% working interest in a 366.85 acre tract of unevaluated property, the Dix prospect, in San Patricio County, Texas to Carter. Carter paid cash of $1,541, the proportional share of the land acquisition costs.
In August 2013, we closed our Corpus Christi office and terminated this officer. In conjunction with the office closure and termination, we assumed operatorship of the Barge Canal properties effective September 1, 2013. In addition, we conveyed multiple properties located in the South Texas and Illinois area to this officer for $0 cash consideration and assumption of the associated asset retirement obligations. (See Note 4 - Oil and Gas Properties)
The father of the Chief Financial Officer and a company controlled by the father-in-law of the Chief Executive Officer each purchased a 5% working interest in the ST 9-12A #4 well. As of July 31, 2012, these parties owed $42,646 in billed and unbilled joint interest billings. As of July 31, 2013, the company controlled by the father-in-law of the Chief Executive Officer owed us $84,806. We also had an advance outstanding from the father of the Chief Financial Officer, which was reflected in the caption “Due to related parties”, of $15,046.
In November 2011, we paid $6,423 principal on a note payable due to a director. We also paid the associated accrued interest of $416.
In October 2011, we paid $8,300 of principal on a note payable due to an officer and director of Duma. We also paid the accrued interest associated with the note of $413.
During 2011, we entered into a consulting contract with a company controlled by Michael Watts, the father-in-law of Jeremy Driver, our Chief Executive Officer and a Director, as detailed in Note 9 - Capital Stock. We recognized expense of $196,384 and 189,372 from this contract during the years ended July 31, 2013 and 2012, respectively.
During the quarter ended October 2012, we purchased NEI for up to 24,900,000 shares of Duma common stock, as described in Note 2 - Acquisitions - Namibia Exploration, Inc.
Note 11 - Income Taxes
Our net loss before income taxes totaled $(40,598,044) and $(5,700,195) for the years ended July 31, 2013 and 2012, respectively.
We recognized an income tax benefit during the year ended July 31, 2013 because the estimated tax liability for 2012 exceeded the actual tax liability.
We recognized a large income tax benefit during the year ended July 31, 2012 primarily due to intangible drilling costs and dry hole costs that resulted in tax losses and the utilization of net operating losses that offset the recognized tax gain on securities sold during the year. The securities were acquired with SPE (See Note 2 - Acquisitions) and had built-in capital gains on the purchase date, which resulted in the recognition of a deferred tax liability on the date of purchase. In accordance with purchase accounting, the utilization of the tax losses, which were possible because the gains existed, was recognized as a tax benefit and the purchase price accounting remained unchanged. A portion of the stock acquired in the purchase of SPE was not sold during the year. We determined that current deferred tax assets existed that are sufficient to offset deferred tax liability on unrecognized tax gain on these available for sale securities and accordingly we adjusted the valuation allowance for our deferred tax assets, which resulted in a further tax benefit.
The reconciliation of our income tax provision at the statutory rate to the reported income tax expense is as follows:
Our deferred income taxes reflect the net tax effects of operating loss and tax credit carry forwards and temporary differences between carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which temporary differences representing net future deductible amounts become deductible.
Components of deferred tax assets as of July 31, 2013 and 2012 are as follows:
The valuation allowance is evaluated at the end of each year, considering positive and negative evidence about whether the deferred tax asset will be realized. At that time, the allowance will either be increased or reduced; reduction could result in the complete elimination of the allowance if positive evidence indicates that the value of the deferred tax assets is no longer impaired and the allowance is no longer required.
We have no positions for which it is reasonable that the total amounts of unrecognized tax benefits at July 31, 2013 will significantly increase or decrease within 12 months.
Generally, our income tax years 2010 through 2013 remain open and subject to examination by Federal tax authorities or the tax authorities in Louisiana and Texas which are the jurisdictions where we have our principal operations. No material amounts of the unrecognized income tax benefits have been identified to date that would impact our effective income tax rate.
As of July 31, 2013, we had approximately $10,813,165 of U.S. federal and state net operating loss carry-forward (“NOLs”) available to offset future taxable income, which begins expiring in 2027, if not utilized. Future tax benefits that may arise as a result of these losses have not been recognized in these financial statements. The deferred tax asset generated by the loss carry-forward has been fully reserved due to the uncertainty we will be able to realize the benefit from it.
Our ability to use our NOLs would be limited if it was determined that we underwent an “ownership change” under Section 382 (“Section 382”) of the Internal Revenue Code. Based upon the information available to us, along with our evaluation of various scenarios, we believe that our 2011 private placement caused us to experience an “ownership change”.
In order to determine whether an “ownership change” occurred, we had to compare the percentage of shares owned by each 5.0% shareholder immediately after the close of the testing date to the lowest percentage of shares owned by such 5.0% shareholder at any time during the testing period (which is generally a three year rolling period). The amount of the increase in the percentage of Company shares owned by each 5.0% shareholder whose share ownership percentage has increased is added together with increases in share ownership of other 5.0% shareholders, and an “ownership change” occurs if the aggregate increase in ownership by all such 5.0% shareholders exceeds 50%. The issuance of our common shares as part of the 2011 private placement caused such threshold to be exceeded.
As a result of experiencing an “ownership change”, we will only be allowed to use a limited amount of NOLs to offset our taxable income subsequent to the “ownership change.” The annual limit pursuant to Section 382 (the “382 Limitation”) is obtained by multiplying (i) the aggregate value of our outstanding equity immediately prior to the “ownership change” (reduced by certain capital contributions made during the immediately preceding two years and certain other items) by (ii) the federal long-term tax-exempt interest rate in effect for the month of the “ownership change.” As our ownership change occurred in February 2011, the federal long-term tax-exempt interest rate applicable to our limitation is 4.47%. Therefore, based on the factors in place at the time of our ownership change, we believe our annual limitation would be an estimated $239,600. On September 6, 2012, we acquired Namibia Exploration, Inc. We believe the transaction may have resulted in a second “ownership change”, which would further limit the availability of NOLs incurred prior to the transaction.
If we were to have taxable income in excess of the 382 Limitation following a Section 382 “ownership change,” we would not be able to offset tax on the excess income with the NOLs. Although any loss carryforwards not used as a result of any Section 382 Limitation would remain available to offset income in future years (again, subject to the Section 382 Limitation) until the NOLs expire, the “ownership change” will significantly defer the utilization of the loss carryforwards, accelerate payment of federal income tax and may cause some of the NOLs to expire unused.
Note 12 - Commitments and Contingencies
Contingencies
Legal
We are subject to legal proceedings, claims and liabilities which arise in the ordinary course of business. We accrue for losses associated with legal claims when such losses are probable and can be reasonably estimated. These accruals are adjusted as additional information becomes available or circumstances change. Legal fees are charged to expense as they are incurred.
A state regulator has requested that we renew certain pipeline easements located in Galveston Bay. The easements in question were originally obtained by another company whose successor filed for bankruptcy protection. Our subsidiary, Galveston Bay Energy, LLC purchased certain assets from the bankruptcy estate; however, based on the bankruptcy court’s order and the purchase and sale agreement, we believe the pipelines and easements in question were not included in assets purchased. The easements in question were scheduled to renew at various dates between 2012 and 2021. Based on current posted rates, the cost of renewal of all of the easements would be approximately $400,000. We have engaged legal counsel to dispute the regulator’s claim. If we are obligated to renew these easements, they would be part of the asset retirement obligation that was acquired with our subsidiary, Galveston Bay Energy, LLC. As such, the potential liability for these easements is factored into the computation of the asset retirement obligation (See Note 6) that is estimated using the guidance in ASC 410-20.
Environmental
We accrue for losses associated with environmental remediation obligations when such losses are probable and can be reasonably estimated. These accruals are adjusted as additional information becomes available or circumstances change. Costs of future expenditures for environmental remediation obligations are not discounted to their present value. Recoveries of environmental remediation costs from other parties are recorded at their undiscounted value as assets when their receipt is deemed probable.
There is soil contamination at a tank facility owned by GBE. Depending on the technique used to perform the remediation, we estimate the cost range to be between $150,000 and $900,000. We cannot determine a most likely scenario, thus we have recognized the lower end of the range. We have submitted a remediation plan to the appropriate authorities and have not yet received a response. For the year ended July 31, 2013 and July 31, 2012, $150,000 has been recognized and is included in the balance sheet caption “Accounts payable and accrued expenses.”
Commitments
We have the following contract obligations:
In March 2011, we executed a lease for office space in Houston, Texas. The lease term is three years and we have an option to extend the lease for an additional three years. Our scheduled rent is $6,406 per month plus common area maintenance cost for the first year, $6,673 plus common area maintenance cost for the second year, and $6,940 per month plus common area maintenance cost for the third year.
During September 2013, we terminated our lease for office space in Corpus Christi, Texas.
Rent expense during the years ended July 31, 2013 and 2012 was $127,867 and $117,392, respectively.
The following table details our payment obligations related to our operating leases and to our debt that are due during the years ended July 31,
In April 2012, we executed a Compression and Handling Agreement (the “PHA”) with another operator. Under the terms of the PHA, oil, natural gas, and salt water from one of our fields would be disposed of through the operator’s facility. Under the agreement, we are responsible for approximately a flat fee of $1,000 per month as a gauging fee, our pro-rata share of repairs at the facility, and compression, salt water disposal, and other charges based on the volumes disposed of through the facility.
Letters of Credit
Oil and gas operators in the State of Texas are required to obtain a letter of credit in favor of the Railroad Commission of Texas as security that they will meet their obligations to plug and abandon the wells they operate. We have two letters of credit in the amount of $6,610,000 and $180,000 issued by Green Bank. These letters of credit are collateralized by a certificate of deposit held with the bank for the same amount. In addition, we have a letter of credit in the amount of $40,000 issued by a commercial bank in favor of the landowner of the Welder lease as security that we will meet our obligations with regard to the salt water disposal well located on the lease. The letter of credit is collateralized by a certificate of deposit held with the bank for the same amount. We pay a 1.5% per annum fee in conjunction with these letters of credit.
During the year ended July 31, 2012, we paid the fees associated with the Greenbank letters quarterly. In June 2013, when we renewed the letters of credit, we prepaid the entire years’ interest upfront. We amortized these fees on a straight-line basis. The following table reflects the prepaid balances as of July 31,
Note 13 - Additional Financial Statement Information
Other receivables
Other receivables consist of joint interest billings due to us from participants holding a working interest in oil and gas properties that we operate. We regularly review collectability and establish or adjust an allowance for uncollectible amounts as necessary using the specific identification method. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote. As of July 31, 2013 and 2012, we have reserved $58,585 and $1,302, respectively, for potentially uncollectable other receivables.
Other current assets
Other current assets consisted of the following:
Property and Equipment
Property and equipment consisted of the following:
Accounts payable and accrued expenses
Accounts payable and accrued expenses consisted of the following:
Note 14 - Subsequent Events
In August 2013, 120,000 of the 600,000 options granted to our independent directors became vested and the fair market value of these options on the date of vesting was $16,184. The fair market value was estimated using the Black-Sholes option pricing model with an expected life of 6.5 years, a risk free interest rate of 2.01%, a dividend yield of 0%, and a volatility factor of 144.01%.
In October 2013, the board accelerated the vesting of the remaining 480,000 options so that they became fully and immediately vested. The fair value of the options on the date of vesting of $851,096 was recognized immediately as an expense. The fair market value was estimated using the Black-Sholes option pricing model with an expected life of 6.5 years, a risk free interest rate of 2.09%, a dividend yield of 0%, and a volatility factor of 117.31%.
In October 2013, we issued 1,859,879 shares of common stock to Hydrocarb Corporation to settle the $2,400,000 consulting fee described in Note 2 - Acquisitions - Namibia Exploration, Inc., $553,640 of interest and late fees associated with the fee, and $635,937 of joint interest billings payable to Hydrocarb for its work on the Namibian concession.
Note 15 - Supplemental Oil and Gas Information (Unaudited)
The following supplemental information regarding our oil and gas activities is presented pursuant to the disclosure requirements promulgated by the SEC and ASC 932, Extractive Activities -Oil and Gas, (ASC 932).
Users of this information should be aware that the process of estimating quantities of “proved” and “proved developed” oil and natural gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various reservoirs make these estimates generally less precise than other estimates included in the financial statement disclosures.
Proved reserves represent estimated quantities of natural gas, crude oil and condensate that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions in effect when the estimates were made. Proved developed reserves are proved reserves expected to be recovered through wells and equipment in place and under operating methods used when the estimates were made. In the following table, natural gas liquids are included in natural gas reserves. The oil and natural gas liquids price as of July 31, 2013 and 2012 is based on the 12-month un-weighted average of the first of the month prices of the NYMEX (Cushing, OK WTI) posted price which equates to $92.52 and $95.07 per barrel, respectively. The gas price as of July 31, 2013 and 2012 is based on the 12-month un-weighted average of the first of the month prices of the NYMEX (Cushing, OK WTI) spot price which equates to $3.51and $3.02 per MMbtu, respectively. The base prices were adjusted for heating content, premiums and product differentials based on historical revenue statements. All prices are held constant in accordance with SEC guidelines. All proved reserves are located in the United States; specifically, primarily in on-shore and off-shore Texas.
The following table illustrates our estimated net proved reserves, including changes, and proved developed reserves for the periods indicated, as estimated by third party reservoir engineers. Our proved reserves are located in the United States of America, our home country.
Proved Reserves
The reserves in the report have been estimated using deterministic methods. For wells classified as proved developed producing where sufficient production history existed, reserves were based on individual well performance evaluation and production decline curve extrapolation techniques. For undeveloped locations and wells that lacked sufficient production history, reserves were based on analogy to producing wells within the same area exhibiting similar geologic and reservoir characteristics, combined with volumetric methods. The volumetric estimates were based on geologic maps and rock and fluid properties derived from well logs, core data, pressure measurements, and fluid samples. Well spacing was determined from drainage patterns derived from a combination of performance-based recoveries and volumetric estimates for each area or field. Proved undeveloped locations were limited to areas of uniformly high quality reservoir properties, between existing commercial producers.
Capitalized Costs Related to Oil and Gas Activities
The following table illustrates the total amount of capitalized costs relating to oil and natural gas producing activities and the total amount of related accumulated depreciation, depletion and amortization.
Costs Incurred in Oil and Gas Activities
Costs incurred in property acquisition, exploration and development activities for the year ended July 31, 2013 were as follows.
Costs incurred in property acquisition, exploration, and development activities for the year ended July 31, 2012 were all incurred in the USA. The following table provides information about the costs incurred:
Costs Excluded
Our excluded costs as of July 31, 2013 relate to costs incurred in the concession acquired in Namibia, Africa. The concession provides for a multi-year exploration program as described in Note 4 - Oil and Gas Properties. The program provides that an initial well be drilled by September 2017. Accordingly, we anticipate including the excluded costs in the amortization base within the next four to five years. All costs that were excluded as of July 31, 2013 were incurred during that year.
Costs Excluded by Year Incurred
Costs excluded as of July 31, 2012 consisted of acquisition and drilling costs associated with a project onshore in Texas, the Chapman Ranch prospect. During the year ended July 31, 2013, we incurred additional acquisition and exploration costs for this project as well as other projects onshore in Texas. All such costs were classified as evaluated as of July 31, 2013 because they were not successful in discovering oil and gas reserves.
Changes in Costs Excluded by Country
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves
The following Standardized Measure of Discounted Future Net Cash Flow information has been developed utilizing ASC 932, Extractive Activities -Oil and Gas, (ASC 932) procedures and based on estimated oil and natural gas reserve and production volumes. It can be used for some comparisons, but should not be the only method used to evaluate us or our performance. Further, the information in the following table may not represent realistic assessments of future cash flows, nor should the Standardized Measure of Discounted Future Net Cash Flow be viewed as representative of our current value.
We believe that the following factors should be taken into account when reviewing the following information:
● future costs and selling prices will probably differ from those required to be used in these calculations;
● due to future market conditions and governmental regulations, actual rates of production in future years may vary significantly from the rate of production assumed in the calculations;
● a 10% discount rate may not be reasonable as a measure of the relative risk inherent in realizing future net oil and natural gas revenues; and
● future net revenues may be subject to different rates of income taxation.
Under the Standardized Measure, the future cash inflows were estimated by applying the un-weighted 12-month average of the first day of the month cash price quotes, except for volumes subject to fixed price contracts, to the estimated future production of year-end proved reserves. Estimates of future income taxes are computed using current statutory income tax rates including consideration for estimated future statutory depletion and tax credits. The resulting net cash flows are reduced to present value amounts by applying a 10% discount factor. All proved reserves are located in the United States of America.
The Standardized Measure is as follows:
Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves
The following is a summary of the changes in the Standardized Measure of discounted future net cash flows for our proved oil and natural gas reserves during each of the years in the two year period ended July 31, 2013:
The following schedule includes only the revenues from the production and sale of gas, oil, condensate and NGLs. The income tax expense is calculated by applying the current statutory tax rates to the revenues after deducting costs, which include DD&A allowances, after giving effect to permanent differences. The results of operations exclude general office overhead and interest expense attributable to oil and gas activities.
Results of Operations for Producing Activities
ITEM 9.
ITEM 9.
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A.
ITEM 9A.
CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
Our management, with the participation of our Principal Executive Officer and Principal Financial Officer, has evaluated the effectiveness of our disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report. Based on such evaluation, our Principal Executive Officer and Principal Financial Officer have concluded that, as of the end of the period covered by this report, our disclosure controls and procedures were not effective, due to the deficiencies in our internal control over financial reporting as described below.
Management’s Report on Internal Control over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting.
As of July 31, 2013, we assessed the effectiveness of our internal control over financial reporting based on the criteria for effective internal control over financial reporting established in Internal Control -Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) and SEC guidance on conducting such assessments. We utilized the original (1992) COSO Framework to conduct our assessment. Based on that evaluation, we concluded that, as at July 31, 2013, our internal controls and procedures were not effective to detect the inappropriate application of accounting principles generally accepted in the United States of America as more fully described below. This was due to deficiencies that existed at the time in which the internal control procedures were implemented that adversely affected our internal controls and that may be considered to be a material weakness.
The matters involving internal controls and procedures that our management considered to be material weaknesses under the standards of the Public Company Accounting Oversight Board were: (1) while the Company has implemented written policies and procedures for accounting and financial reporting with respect to the requirements and application of US GAAP and SEC disclosure requirements, we have not conducted a formal assessment of whether the policies that have been implemented address the specific risks of misstatement; accordingly, we could not conclude whether the control activities are designed effectively nor whether they operate effectively; and (2) we do not have an effective mechanism for monitoring the system of internal controls.
Management believes that the material weaknesses set forth above did not have a material adverse effect on our financial results for the year ended July 31, 2013.
We are committed to improving our financial organization. Our control weaknesses are largely a function not having sufficient staff. As resources become available, we plan to augment our staff so that we can devote more effort to addressing our control deficiencies. Additionally, as financial resources become available, we will consider engaging third party consultants to assist with control activities.
We will continue to monitor and evaluate the effectiveness of our internal controls and procedures over financial reporting on an ongoing basis and are committed to taking further action by implementing additional enhancements or improvements, or deploying additional human resources as may be deemed necessary.
Changes in Internal Control over Financial Reporting
During our fourth quarter of our fiscal year ended July 31, 2013, we implemented and documented entity-level controls, formalized risk assessment processes, and adopted additional policies and procedures that improved our internal control over financial reporting.
ITEM 9B.
ITEM 9B.
OTHER INFORMATION
Not applicable.
PART III
ITEM 10.
ITEM 10.
DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Officers and Directors
Our directors and executive officers and their respective ages as of the date of this annual report are as follows:
The following describes the business experience of each of our directors and executive officers, including other directorships held in reporting companies:
Jeremy Glenn Driver, Chief Executive Officer and a director
Mr. Driver has been Chief Executive Officer since December 2009 and a director of the Company since June 2010. He served as President of the Company from December 2009 until February 15, 2011, and once again became President on April 1, 2011. Effective October 27, 2013, Mr. Driver resigned as President. He remains Chief Executive Officer. He is an oil and gas operations and financial professional with a background in land-based E&P operations with public companies. Prior to joining the Company, Mr. Driver served as President of HYD Resources Corporation (a wholly-owned subsidiary of publicly traded firm Hyperdynamics Corporation) with operations primarily focused in Texas and Louisiana from 2005 to 2008. He was able to lead the operational turnaround of that company and bring it to profitability, later being divested at a profit. Mr. Driver also served as an active duty officer in the United States Air Force until 2005, specializing in foreign intelligence as a Chinese Linguist. Mr. Driver holds a Masters of Business Administration and a Master of Science in Accounting from Northeastern University, Boston, MA. He also earned his Bachelor of Science in Liberal Studies - Chinese Language from Excelsior College.
Sarah Berel-Harrop, Secretary, Treasurer and Chief Financial Officer
Ms. Berel-Harrop has been our Secretary, Treasurer and Chief Financial Officer since May 25, 2011. Ms. Berel-Harrop has approximately 16 years of experience in financial accounting and reporting in both audit and industry positions. She received a B.A. degree from Cornell University and a Master in Business Administration from University of Texas - Austin. From 2006 to 2009, Ms. Berel-Harrop worked with Hyperdynamics Corporation. She was responsible for the company’s financial accounting and reporting, and, from June 2008 through June 2009, served as the company’s Chief Financial Officer. From July 2009 through March 2011, Ms. Berel-Harrop operated an accounting firm as a sole practitioner. From March 1, 2011 through the May 2011, she was Duma Energy Corp.’s Controller. In May 2011, Ms. Berel-Harrop became Duma’s CFO. Ms. Berel-Harrop is a Certified Public Accountant licensed in the state of Texas. She is a member of the AICPA and the Texas State Board of Public Accountancy, Houston Chapter.
Charles F. Dommer, President
Charles F. Dommer was appointed President on October 27, 2013. Mr. Dommer is an exploration and development executive with 35 years of managerial positions for international and domestic oil and gas exploitation, exploration and acquisitions. Mr. Dommer has managed many major projects in the competitive arena of oil and gas exploration and development. From December 2010 until present, Mr. Dommer has served as the Vice President of Exploration and Development for Hydrocarb Corporation. From January 2000 to December 2010, Mr. Dommer served as President for Trans Global Engineering, Inc., of Denver, Colorado, primarily directing production operations as Chief Geologist (Vice President of Exploration and Production) for Lukoil-AIK in Russia. Mr. Dommer’s past experience includes Senior Geologist at Phillips Petroleum Company, located in Texas, and the establishment of a Geology and Reservoir Engineering Department in Siberia as Chief Geologist (Vice President of Exploration and Production) for Occidental Petroleum Joint Venture, Vanyoganneft. Mr. Dommer has a B.S. Geology degree from Arizona State University.
Kent P. Watts, Chairman and a director
Mr. Watts was appointed to the board of directors and as Chairman on October 11, 2013. Mr. Watts is currently and has been Chairman and Chief Executive Officer of Hydrocarb Corporation since November 2009. Hydrocarb owns rights in 21,000 square kilometer oil and gas concession onshore the country of the Republic of Namibia with a northern of Angola. The company has subsidiaries in Windhoek, Namibia and Abu Dhabi, UAE. Its subsidiary, Otaiba Hydrocarb LLC in the UAE, holds an oil field services license approved by the Supreme petroleum council of the UAE. Between June 1997 and October 2009 he was the founder, Chairman, and Chief Executive Officer for Hyperdynamics Corporation (NYSE:HDY). In 2006 Mr. Watts became the Founder and Chairman of American Friends of Guinea (AFG), a non-profit organization. He remains Chairman of AFG. He holds a BBA from the University of Houston and he is a licensed Certified Public Accountant and Real Estate Broker in the State of Texas.
Pasquale Scaturro, Director
Mr. Scaturro was appointed to the board of directors on October 11, 2013. Mr. Scaturro is a geophysicist and geologist with 29 years of experience in the oil and gas industry. His areas of experience include oil and gas exploration and development, prospect evaluation, 2-D and 3-D seismic survey program design, parameter selection, data acquisition, processing, detailed seismic workstation interpretation, prospect evaluation, project planning, and GIS and data base design. Mr. Scaturro's International experience includes projects in the Middle East, Africa, Russia and other former Soviet Union countries, Asia and South America. Mr. Scaturro has substantial training and mentoring experience around the world. From January 2012 to present, Mr. Scaturro has served as President and Chief Operating Officer for Hydrocarb Corporation. From January 1992 to December 2009 he served as president for Exploration Specialists, Inc., Denver, Colorado. Mr. Scaturro also served as a director for Hyperdynamics Corporation (NYSE:HDY) from April 2009 until December 2009. Past experience includes Senior Geophysicist for Amoco Production Company and McMoRan Oil and Gas Company. Mr. Scaturro has a B.S. Geology/Geophysics degree from Northern Arizona State University.
S. Chris Herndon
Mr. Herndon has been a director since October 11, 2012. Mr. Herndon is an experienced financial and management professional with more than 30 years of experience. Currently, Mr. Herndon serves as Partner of Cyrus Partners, an investment company focusing on the energy, healthcare, and real estate sectors. Beginning in 2002 through 2011, Mr. Herndon served as Chief Financial Officer and Partner of AppOne, a financial technology company designed to serve the auto finance industry. From 1996 to 2001, Mr. Herndon served as CEO and Partner of The Mattress Firm, growing the organization from 100 stores to 275 stores before selling the firm to Bain Capital. Mr. Herndon was also a Registered Investment Advisor with Malachi Financial Services from 1994 to 1996. From 1983 to 1994, Mr. Herndon served as Chief Financial Officer and Controller of Duer Wagner and Co., an oil and gas operator in Texas. From 1982 to 1983 he served as a Public Accountant with Price Waterhouse.
Mr. Herndon is a graduate of Texas Christian University where he earned his Bachelor of Business Administration and Accounting, after which he became a Certified Public Accountant (CPA) in 1985. He is actively involved with several charities locally and internationally.
Term of Office
Our directors are appointed for a one-year term to hold office until the next annual general meeting of our stockholders or until they resign or are removed from the board in accordance with our bylaws. Our officers are appointed by our Board of Directors and hold office until they resign or are removed from office by the Board of Directors.
Significant Employees
Other than Craig Alexander, our Vice President, the Company has no significant employees other than our executive officers. Mr. Alexander has been with the company since early 2011. Before joining our Company, he was employed by Galveston Bay Energy serving as Operations Manager. Mr. Alexander has more than 21 years of oil and gas experience in production and completion engineering and operations management with Erskine Energy, Millennium Offshore Group, and Amerada Hess Corporation. He is a graduate of the University of Texas at Austin with a B.S. in Petroleum Engineering.
Audit Committee
Our board of directors has established an Audit Committee, which was originally comprised of Leonard Garcia, John Brewster and S. Chris Herndon. Mr. Garcia and Mr. Brewster resigned from the board of directors prior to the date of this report, and the vacancies created by their resignations have not been filled. Accordingly, Mr. Herndon is the sole member of the audit committee. The Audit Committee operates pursuant to a charter adopted by the board.
Mr. Herndon is an “independent” director of the Company as that term is defined in Rule 121 of the NYSE MKT Equities Exchange listing standards. The Board of Directors of the Company has determined that Mr. Herndon qualifies as an audit committee financial expert pursuant to SEC rules.
Family Relationships
Other than disclosed below, there are no family relationships among our directors and officers.
Kent Watts, who is the Chairman and a director, is the uncle of Jeremy Driver’s wife. Jeremy Driver is the Chief Executive Officer and a director.
Involvement in Certain Legal Proceedings
Except as disclosed in this annual report, during the past ten years none of the following events have occurred with respect to any of our directors or executive officers:
1. A petition under the Federal bankruptcy laws or any state insolvency law was filed by or against, or a receiver, fiscal agent or similar officer was appointed by a court for the business or property of such person, or any partnership in which he was a general partner at or within two years before the time of such filing, or any corporation or business association of which he was an executive officer at or within two years before the time of such filing;
2. Such person was convicted in a criminal proceeding or is a named subject of a pending criminal proceeding (excluding traffic violations and other minor offenses);
3. Such person was the subject of any order, judgment, or decree, not subsequently reversed, suspended or vacated, of any court of competent jurisdiction, permanently or temporarily enjoining him from, or otherwise limiting, the following activities:
i. Acting as a futures commission merchant, introducing broker, commodity trading advisor, commodity pool operator, floor broker, leverage transaction merchant, any other person regulated by the Commodity Futures Trading Commission, or an associated person of any of the foregoing, or as an investment adviser, underwriter, broker or dealer in securities, or as an affiliated person, director or employee of any investment company, bank, savings and loan association or insurance company, or engaging in or continuing any conduct or practice in connection with such activity;
ii. Engaging in any type of business practice; or
iii. Engaging in any activity in connection with the purchase or sale of any security or commodity or in connection with any violation of Federal or State securities laws or Federal commodities laws;
4. Such person was the subject of any order, judgment or decree, not subsequently reversed, suspended or vacated, of any Federal or State authority barring, suspending or otherwise limiting for more than 60 days the right of such person to engage in any activity described in paragraph (3)(i) above, or to be associated with persons engaged in any such activity;
5. Such person was found by a court of competent jurisdiction in a civil action or by the Commission to have violated any Federal or State securities law, and the judgment in such civil action or finding by the Commission has not been subsequently reversed, suspended, or vacated;
6. Such person was found by a court of competent jurisdiction in a civil action or by the Commodity Futures Trading Commission to have violated any Federal commodities law, and the judgment in such civil action or finding by the Commodity Futures Trading Commission has not been subsequently reversed, suspended or vacated;
7. Such person was the subject of, or a party to, any Federal or State judicial or administrative order, judgment, decree, or finding, not subsequently reversed, suspended or vacated, relating to an alleged violation of:
i. Any Federal or State securities or commodities law or regulation; or
ii. Any law or regulation respecting financial institutions or insurance companies including, but not limited to, a temporary or permanent injunction, order of disgorgement or restitution, civil money penalty or temporary or permanent cease-and-desist order, or removal or prohibition order; or
iii. Any law or regulation prohibiting mail or wire fraud or fraud in connection with any business entity; or
8. Such person was the subject of, or a party to, any sanction or order, not subsequently reversed, suspended or vacated, of any self-regulatory organization (as defined in Section 3(a)(26) of the Exchange Act), any registered entity (as defined in Section 1(a)(29) of the Commodity Exchange Act), or any equivalent exchange, association, entity or organization that has disciplinary authority over its members or persons associated with a member.
There are currently no legal proceedings to which any of our directors or officers is a party adverse to us or in which any of our directors or officers has a material interest adverse to us.
Code of Conduct
We have adopted a Code of Conduct that applies to all directors and officers. The code describes the legal, ethical and regulatory standards that must be followed by the directors and officers of the Company and sets forth high standards of business conduct applicable to each director and officer. As adopted, the Code of Conduct sets forth written standards that are designed to deter wrongdoing and to promote, among other things:
1. honest and ethical conduct, including the ethical handling of actual or apparent conflicts of interest between personal and professional relationships;
2. full, fair accurate, timely and understandable disclosure in reports and documents that we file with, or submit to, the SEC and in other public communications made by us;
2. compliance with applicable governmental laws, rules and regulations;
3. the prompt internal reporting of violations of the code to the appropriate person or persons identified in the code; and
4. accountability for adherence to the code.
We revised the Code of Conduct during the year ended July 31, 2013. A copy of our Code of Conduct is filed as Exhibit 14.1 to this Form 10-K.
Compliance with Section 16(a) of the Exchange Act
Section 16(a) of the Exchange Act requires our directors and officers, and the persons who beneficially own more than 10% of our common stock, to file reports of ownership and changes in ownership with the SEC. Copies of all filed reports are required to be furnished to us pursuant to Rule 16a-3 promulgated under the Exchange Act. Based solely on the reports received by us and on the representations of the reporting persons, we believe that these persons have complied with all applicable filing requirements during the year ended July 31, 2013, except as follows:
ITEM 11.
ITEM 11.
EXECUTIVE COMPENSATION
Summary Compensation of Named Executive Officers
The following table sets forth the compensation paid to our executive officers (as well as one non-executive officer with respect to whom disclosure would have been provided but for the fact that he was not an executive officer) (collectively, our “Named Executive Officers”) during our fiscal years ended July 31, 2013 and 2012:
Summary Compensation
(1) Mr. Driver resigned as President on October 27, 2013 but continues to serve as Chief Executive Officer.
(2) During the year ended July 31, 2012, Sarah Berel-Harrop received 13,036 shares of common stock (on a post-stock consolidation basis) valued using the market closing price on the date of grant. 2/3 of the stock grant related to amounts accrued and included as compensation for the year ended July 31, 2011.
(3)
Mr. Carter’s employment as Vice President Operations was terminated effective August 30, 2013.
Outstanding Equity Awards
The following table sets forth information as at July 31, 2013 relating to outstanding equity awards for each Named Executive Officer:
Outstanding Equity Awards at Year End
(1)
Mr. Carter’s employment as Vice President Operations was terminated effective August 30, 2013.
Director Compensation
Our directors who are also executive officers receive compensation for management services provided to the Company and thus they do not receive separate compensation for their services as directors. In February 2013, we adopted a standard compensation package for independent directors as follows:
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$30,000 per year for serving on the board of directors,
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$2,000 per year for serving as a committee chair,
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Meeting fees of $2,000 per meeting for any board meetings other than four quarterly regular meetings, and
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Meeting fees of $1,500 per meeting for any committee meetings other than four quarterly regular meetings.
The following table provides information regarding compensation during the year ended July 31, 2013 earned by directors who are not executive officers. Our directors who are executive officers do not receive additional compensation for their service as directors and their compensation is disclosed in the “Summary Compensation” Table above.
(1)
In February 2013, we granted options to purchase 200,000 shares of common stock with exercise price of $2.20 per share and a 10 year term to each of the independent directors. The options vest 20% each six months over the 30 months following the award. were valued using the Black-Sholes option pricing model with an expected life of 6.5 years, a risk free interest rate of 1.35%, a dividend yield of 0%, and a volatility factor of 142.06%. Subsequent to our fiscal year ended July 31, 2013 (in October 2013), we determined to accelerate the vesting of such options, such that all such options that had not yet vested became fully vested in October 2013.
(2)
In addition to his independent director compensation, during the year ended July 31, 2013, Leonard Garcia received $2,081 for land work management consulting services provided by Mr. Garcia. Mr. Garcia discontinued providing these services in September 2012. Subsequent to the Company’s fiscal year ended July 31, 2013 (on October 31, 2013), Mr. Garcia resigned as a director.
(3)
Mr. Brewster served as a director of our Company from October 11, 2012 until November 1, 2013.
Employment, Consulting and Services Agreements
The following summary of certain material terms of the employment, consulting or services agreements we have entered into with certain of our officers or employees is not complete and is qualified in its entirety to the full text of each such agreement, which have been filed with the SEC as described in the list of exhibits to this annual report.
Carter Professional Services Agreement
On December 20, 2006, our Board of Directors authorized and approved the execution of the “Carter Professional Services Agreement”. The initial term of the agreement was two years expiring on November 30, 2008, and the agreement was amended to increase Mr. Carter’s compensation in June 2011. Pursuant to the terms and provisions of the Carter Professional Services Agreement: (i) Steven Carter shall provide duties to us commensurate with his current executive position as our Vice President of Operations; (ii) we would pay to Mr. Carter a monthly fee of $14,583.33; (iii) we approved the issuance of 20,000 shares of our common stock at a price of $0.025 per share (on a post-share consolidation basis); (iv) we approved the granting of an aggregate of not less than 24,000 options to purchase shares of our common stock at $8.75 per share (amended to be $2.50 per share) for a ten year term (on a post-share consolidation basis); and (v) the Carter Professional Services Agreement may be terminated without cause by either of us by providing prior written notice of the intention to terminate at least 90 days (in the case of our Company after the initial term) or 30 days (in the case of Mr. Carter) prior to the effective date of such termination. In August, 2013, we terminated the agreement. In accordance with the terms of the agreement, he will receive his fee through the end of November 2013.
Jeremy G. Driver Agreement (2009)
Effective December 1, 2009, we entered into an executive services agreement with Mr. Driver, which was revised in June 2011 to increase his monthly fee, pursuant to which he is to perform such duties and responsibilities as set out in the agreement and as our Board of Directors may from time to time reasonably determine and assign as is customarily performed by a person in an executive position with our Company. In consideration for his services under the agreement, as amended, we have agreed:
● to pay Mr. Driver a monthly fee of $14,583.33;
● to pay Mr. Driver a one-time signing bonus of $20,000;
● to provide Mr. Driver with industry standard bonuses, from time to time, based, in part, on the performance of the Company and the achievement by Mr. Driver of reasonable management objectives, as determined by the Company’s Board of Directors in good faith;
● to provide Mr. Driver with three weeks paid vacation;
● to provide Mr. Driver with a monthly benefits stipend of $450 together with full participation, at the Company’s expense, in the Company’s current medical services and life insurance benefits programs for management and employees; and
● to grant Mr. Driver incentive stock options to purchase not less than an aggregate of 100,000 common shares of the Company, at an exercise price $5.00 per share (amended to be $2.50 per share), vesting as to one-quarter of said stock options on the date of grant (that being as to 25,000) and on each day which is six months thereafter in succession for each remaining one-quarter of the optioned common shares, and all being exercisable for a period of three years from the date of grant and in accordance with the provisions of the Company’s current Stock Incentive Plan.
The initial term of the agreement was one year ending on December 1, 2010, and the agreement is subject to automatic renewal on a monthly basis unless either the Company or Mr. Driver provides written notice of an intention not to renew the agreement not later than 30 days prior to the end of the then-current initial term or renewal of the agreement. In October 2013, this agreement was terminated and we entered into a new employment agreement with Mr. Driver, as described below.
Jeremy G. Driver Agreement (2013)
On October 11, 2013, we entered into a new agreement with Mr. Driver, which was modified on October 27, 2013 and is effective October 1, 2013. In consideration for his services under the agreement, as amended, we have agreed and to provide Mr. Driver with a monthly salary of $14,583.33, participation in company benefits programs, and four weeks paid vacation. The agreement provides for Mr. Driver to be paid six months’ salary as severance in the event of
·
termination by the Company for other than cause,
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termination by Mr. Driver for “Good Reason”, which includes a diminishment of job functions or responsibilities and attempts by the Company to relocate Mr. Driver, or
·
termination by Mr. Driver for any reason within 90 days of a change in control of the Company.
The initial term of the agreement is one year ending on October 1, 2014, and the agreement is subject to automatic renewal for consecutive one year periods unless either the Company or Mr. Driver provides written notice of an intention not to renew the agreement not later than 60 days prior to the end of the then-current initial term or renewal of the agreement.
Sarah Berel-Harrop Agreement
On October 11, 2013, we entered into an employment agreement with Ms. Berel-Harrop, which is effective October 1, 2013. In consideration for her services under the agreement, as amended, we have agreed and to provide Ms. Berel-Harrop with a monthly salary of $12,500, participation in company benefits programs, and three weeks paid vacation. The agreement provides for Ms. Berel-Harrop to be paid six months’ salary as severance in the event of
·
termination by the Company for other than cause,
·
termination by Ms. Berel-Harrop for “Good Reason”, which includes a diminishment of job functions or responsibilities and attempts by the Company to relocate Ms. Berel-Harrop, or
·
termination by Ms. Berel-Harrop for any reason within 90 days of a change in control of the Company.
The initial term of the agreement is one year ending on October 1, 2014, and the agreement is subject to automatic renewal for consecutive one year periods unless either the Company or Ms. Berel-Harrop provides written notice of an intention not to renew the agreement not later than 60 days prior to the end of the then-current initial term or renewal of the agreement.
Craig Alexander Agreement
On October 11, 2013, we entered into an employment agreement with Mr. Alexander, which is effective October 1, 2013. In consideration for his services under the agreement, as amended, we have agreed and to provide Mr. Alexander with a monthly salary of $15,417.67, participation in company benefits programs, and three weeks paid vacation. The agreement provides for Mr. Alexander to be paid six months’ salary as severance in the event of
·
termination by the Company for other than cause,
·
termination by Mr. Alexander for “Good Reason”, which includes a diminishment of job functions or responsibilities and attempts by the Company to relocate Mr. Alexander, or
·
termination by Mr. Alexander for any reason within 90 days of a change in control of the Company.
The initial term of the agreement is one year ending on October 1, 2014, and the agreement is subject to automatic renewal for consecutive one year periods unless either the Company or Mr. Alexander provides written notice of an intention not to renew the agreement not later than 60 days prior to the end of the then-current initial term or renewal of the agreement.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
The following table sets forth certain information concerning the number of shares of our common stock owned beneficially as of November 12, 2013 by: (i) each person (including any group) known to us to own more than 5% of our shares of common stock; (ii) each of our directors; (iii) each of our officers; and (iv) our officers and directors as a group. To our knowledge, each holder listed possesses sole voting and investment power with respect to the shares shown.
(1) Under Rule 13d-3 of the Exchange Act a beneficial owner of a security includes any person who, directly or indirectly, through any contract, arrangement, understanding, relationship, or otherwise has or shares: (i) voting power, which includes the power to vote, or to direct the voting of shares, and/or (ii) investment power, which includes the power to dispose or direct the disposition of shares. In addition, shares are deemed to be beneficially owned by a person if the person has the right to acquire the shares within 60 days of the date as of which the information is provided.
(2) Based on the 15,140,882 shares of our common stock issued and outstanding as of November 12, 2013.
(3) This figure includes (i) 1,936,416 shares of common stock held by KD Navigation Inc., which is solely owned by Mr. Driver’s wife, and (ii) 1,935,416 shares of common stock held by KW Navigation Inc., which is owned 50% by Mr. Driver’s wife and 50% by Christopher Watts (see footnote 7 below).
(4) This figure includes (i) 21,796 shares of common stock and (ii) vested stock options to purchase 120,000 shares of our common stock.
(5) This figure includes (i) 10,300 shares of common stock and (ii) vested stock options to purchase 200,000 shares of our common stock.
(6) This figure includes (i) 3,938,535 shares of common stock and (ii) vested stock options to purchase 320,000 shares of our common stock.
(7) Represents (i) 1,935,416 shares held by CW Navigation Inc., which is solely owned by Mr. Watts, and (ii) 1,935,416 shares held by KW Navigation Inc., which is owned 50% by Mr. Watts and 50% by the wife of Jeremy Driver (see footnote 3 above).
(8) The 1,935,416 shares held by KW Navigation Inc. (representing 12.8% of the Company’s issued and outstanding stock as of November 12, 2013) is included in the beneficial ownership figures in the table for each of Jeremy Glenn Driver and Christopher Watts (see footnotes 3 and 7 above).
Changes in Control
We are unaware of any contract, or other arrangement or provision, the operation of which may at a subsequent date result in a change of control of our company.
ITEM 13.
ITEM 13.
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE
Except as described below, none of the following parties has had any material interest, direct or indirect, in any transaction with us during our last two fiscal years or in any presently proposed transaction that has or will materially affect us:
1. any of our directors or officers;
2. any person who beneficially owns, directly or indirectly, shares carrying more than 5% of the voting rights attached to our outstanding shares of common stock; or
3. any member of the immediate family (including spouse, parents, children, siblings and in-laws) of any of the above persons.
Galveston Bay
Immediately following our acquisition of Galveston Bay Energy, LLC, on February 15, 2011, we sold 15% of our own aggregate working interest in the Galveston Bay fields for $1,400,000 in cash to SPE Navigation 1, LLC (“SPE”), a company controlled by Michael Watts, who is the father-in-law of Jeremy Driver, a Director and our Chief Executive Officer. SPE had the right to acquire an additional 10% of our own aggregate working interest in the Galveston Bay fields within 90 days for $1,150,000.
Effective on September 26, 2011, we closed on our acquisition of SPE from CW Navigation Inc., KD Navigation Inc. and KW Navigation Inc., each a Texas corporation (collectively, the “Sellers”). The material assets of SPE consist of certain oil and gas working interests in and to four producing oil and gas fields located in Galveston Bay, Texas, together with one million shares of Hyperdynamics Corporation (NYSE: HDY). Pursuant to the terms of the Company’s Purchase and Sale Agreement with the Sellers and SPE regarding this matter, the Company acquired the Sellers’ 100% interest in SPE for total consideration consisting of 3,800,000 restricted common shares of the Company issued at a deemed issuance price of $2.50 per share (on a post-share consolidation basis). CW Navigation Inc. is owned 100% by the brother-in-law of Jeremy Driver, our Chief Executive Officer and a director. KD Navigation Inc. is owned 100% by Mr. Driver’s wife. KW Navigation Inc. was owned 100% by Mr. Driver’s sister-in-law as of September 26, 2011 and is now 50% owned by Mr. Driver’s wife and 50% owned by Mr. Driver’s brother-in-law.
Namibia Exploration, Inc.
We entered into a Share Exchange Agreement, dated August 7, 2012 (the “Share Exchange Agreement”) with each of Namibia Exploration, Inc. (“NEI”), a company organized under the laws of the state of Nevada, and the shareholders of NEI (each a “Vendor” and collectively, the “Vendors”), whereby we acquired the right to acquire all of the issued and outstanding common shares in the capital of NEI from the Vendors in exchange for the issuance of up to 24,900,000 restricted common shares of Duma to the Vendors (the “Acquisition Shares”) on a pro-rata basis in accordance with each Vendor’s percentage ownership in NEI (the “Acquisition”). NEI holds the rights to a 39% working interest in an onshore petroleum concession (the “Concession”), located in the Republic of Namibia, measuring approximately 5.3 million acres and covered by Petroleum Exploration License No. 0038 as issued by the Republic of Namibia Ministry of Mines and Energy.
We completed the Acquisition on September 6, 2012, and as a result, NEI became a wholly-owned subsidiary of Duma. As a result, Duma, through NEI, has acquired and been assigned a 39% working interest (43.33% cost responsibility) in and to the Concession. Duma now holds its indirect working interest in the Concession in partnership with the National Petroleum Corporation of Namibia Ltd. (“NPC Namibia”) and Hydrocarb Namibia Energy Corporation (“Hydrocarb Namibia”), a company chartered in the Republic of Namibia and which is a majority owned subsidiary of Hydrocarb Corporation (“Hydrocarb”), a company organized under the laws of the State of Nevada. Hydrocarb Namibia, as operator of the Concession, now holds at 51% working interest (56.67% cost responsibility) in the Concession and NPC Namibia now holds a 10% carried working interest in the Concession. The assignment of the 39% working interest to NEI from Hydrocarb Namibia received the approval of the government of the Republic of Namibia on August 23, 2012.
Pursuant to the terms of the Share Exchange Agreement, Duma is required to issue the Acquisition Shares, as consideration for the Acquisition, in accordance with the following milestones which must be reached within 10 years after the closing of the Acquisition (the “Closing”):
(a) 2,490,000 of the Acquisition Shares have been issued;
(b) a further 2,490,000 of the Acquisition Shares will be issued when and if Duma’s 10-day volume-weighted average market capitalization reaches $82,000,000;
(c) a further 7,470,000 of the Acquisition Shares will be issued when and if Duma’s 10-day volume-weighted average market capitalization reaches $196,000,000; and
(d) a further and final 12,450,000 of the Acquisition Shares will be issued and if Duma’s 10-day volume-weighted average market capitalization reaches $434,000,000.
Duma will maintain 100% ownership of NEI after Closing even if one or more of the market capitalization milestones have not been attained within 10 years from the Closing.
The Vendors under the Share Exchange Agreement were Michael Watts (the father-in-law of Jeremy Driver, our Chief Executive Officer and a director), CW Navigation Inc. (which is 100% owned by Mr. Driver’s brother-in-law), KW Navigation Inc. (which is 50% owned by Mr. Driver’s wife and 50% owned by Mr. Driver’s brother-in-law), and KD Navigation Inc. (which is 100% owned by Mr. Driver’s wife).
Carter E & P, LLC
A company controlled by one of our former officers (Steven Carter) operated our Barge Canal properties, the Curlee Prospect in Bee County, Texas and the Dix Prospect in San Patricio County, Texas. Revenues generated from these properties were $643,203 and $569,476 for the years ended July 31, 2013 and 2012, respectively. In addition, lease operating costs incurred from these properties were $224,047 and $181,113 for the years ended July 31, 2013 and 2012, respectively.
As of July 31, 2013 and 2012, respectively, we had outstanding accounts receivable associated with these properties of $91,967 and $74,972 and no accounts payable.
Working Interest
During January 2012, we sold half of our working interest in a well, the State Tract 9-12A#4, to third parties. The father of our Chief Financial Officer, George Bert Harrop, and a company controlled by the father-in-law of the Chief Executive Officer, Lifestream, LLC, each purchased a 5% interest in the well. The costs associated with the drilling and completion operations on the well through July 31, 2012 were approximately $6.6 million for all participants. Mr. Harrop’s and Lifestream’s share of the operations were $91,806 and $330,151 each during the years ended July 31, 2013 and July 31, 2012, respectively.
Independent Directors
S. Chris Herndon is an independent director of our Company as provided in the listing standards of the NYSE MKT Equities Exchange.
ITEM 14.
ITEM 14.
PRINCIPAL ACCOUNTING FEES AND SERVICES
Our current independent auditor, MaloneBailey, LLP, served as our independent registered public accounting firm and audited our financial statements for the fiscal year ended July 31, 2013 and 2012. Aggregate fees for professional services rendered to us by our auditor are set forth below:
Audit Fees
Audit fees are the aggregate fees billed for professional services rendered by our independent auditors for the audit of our annual financial statements, the review of the financial statements included in each of our quarterly reports and services provided in connection with statutory and regulatory filings or engagements.
Audit Related Fees
Audit related fees are the aggregate fees billed by our independent auditors for assurance and related services that are reasonably related to the performance of the audit or review of our financial statements and are not described in the preceding category. Specifically, during the year ended July 31, 2013, the independent auditor billed $1,500 for services provided in conjunction with responding to an SEC comment letter.
Tax Fees
Tax fees are billed by our independent auditors for tax compliance, tax advice and tax planning.
All Other Fees
All other fees include fees billed by our independent auditors for products or services other than as described in the immediately preceding three categories
Policy on Pre-Approval of Services Performed by Independent Auditors
It is our audit committee’s policy to pre-approve all audit and permissible non-audit services performed by the independent auditors. We approved all services that our independent accountants provided to us in the past two fiscal years.
PART IV
ITEM 15.
ITEM 15.
EXHIBITS
The following exhibits are filed with this Annual Report on Form 10-K:
* Filed herewith.
(1) Filed as an exhibit to our registration statement on Form S-1/A (Amendment No.1) filed with the Securities and Exchange Commission on February 8, 2008.
(2) Filed as an exhibit to our Current Report on Form 8-K filed with the Securities and Exchange Commission on October 16, 2009.
(3) Filed as an exhibit to our Current Report on Form 8-K filed with the Securities and Exchange Commission on November 16, 2009.
(4) Filed as an exhibit to our Annual Report on Form 10-K filed with the Securities and Exchange Commission on November 12, 2009.
(5) Filed as an exhibit to our Current Report on Form 8-K filed with the Securities and Exchange Commission on December 3, 2009.
(6) Filed as an exhibit to our Current Report on Form 8-K filed with the Securities and Exchange Commission on October 20, 2010.
(7) Filed as an exhibit to our Current Report on Form 8-K filed with the Securities and Exchange Commission on February 22, 2011.
(8) Filed as an exhibit to our Current Report on Form 8-K filed with the Securities and Exchange Commission on September 22, 2011.
(9) Filed as an exhibit to our Annual Report on Form 10-K filed with the Securities and Exchange Commission on November 15, 2011.
(10) Filed as an exhibit to our Current Report on Form 8-K filed with the Securities and Exchange Commission on April 4, 2012.
(11) Filed as an exhibit to our Current Report on Form 8-K filed with the Securities and Exchange Commission on May 17, 2012.
(12) Filed as an exhibit to our Current Report on Form 8-K filed with the Securities and Exchange Commission on August 8, 2012.
(13) Filed as an exhibit to our Current Report on Form 8-K filed with the Securities and Exchange Commission on September 12, 2012.
(14) Filed as an exhibit to our Current Report on Form 8-K filed with the Securities and Exchange Commission on September 19, 2013.
(15) Filed as an exhibit to our Current Report on Form 8-K filed with the Securities and Exchange Commission on October 16, 2013.
SIGNATURES
Pursuant to the requirements of Section 13 and 15 (d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
DUMA ENERGY CORP.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.