Item 1. Business Unless the context otherwise requires, all references to “Red Mountain,” the “Company,” “we,” “our” and “us” refer to Red Mountain Resources, Inc. and its wholly owned subsidiaries, including Black Rock Capital, Inc. (“Black Rock”) and RMR Operating, LLC (“RMR Operating”).
Our Company Red Mountain Resources, Inc. is a growth-oriented energy company engaged in the acquisition, development and exploration of oil and natural gas properties in established basins with demonstrable prolific producing zones. Currently, we have established acreage positions and production in the Permian Basin of West Texas and Southeast New Mexico and the onshore Gulf Coast of Texas. Our focus is to grow production and reserves by acquiring and developing an inventory of long-life, low risk drilling opportunities in and around producing oil and natural gas properties. Our headquarters is located in Dallas, Texas.
As of August 31, 2012, we owned approximately 45.9% of the outstanding common stock of Cross Border Resources, Inc. (“Cross Border”). As of March 31, 2012, Cross Border had approximately 868,000 gross (295,000 net) acres, of which 26,000 net acres were located in the Permian Basin. The following disclosures about our properties, business, operations and financial results do not include Cross Border’s properties, business, operations or financial results.
History Red Mountain, a Florida corporation, was originally formed in January 2010 as Teaching Time, Inc. in order to design, develop, and market instructional products and services for the corporate, education, government, and healthcare e-learning industries. In March 2011, Teaching Time, Inc. determined to enter into oil and natural gas exploration, development and production and changed its name to Red Mountain Resources, Inc. to better reflect that plan. On March 22, 2011, we entered into a Plan of Reorganization and Share Exchange Agreement, as amended on June 17, 2011 and June 20, 2011 (the “Share Exchange Agreement”), with Black Rock Capital, LLC and The StoneStreet Group, Inc. (“StoneStreet”), the sole shareholder of Black Rock Capital, LLC. Alan W. Barksdale, our current President, Chief Executive Officer and Chairman of the Board, was the president and the sole member of Black Rock Capital, LLC and sole owner and the president of StoneStreet. On June 22, 2011, we completed a reverse merger pursuant to the Share Exchange Agreement in which we issued 27,000,000 shares of common stock to StoneStreet in exchange for 100% of the interests in Black Rock Capital, LLC. Concurrently with the closing, we retired 225,000,000 shares of common stock for no additional consideration. In connection with the reverse merger, the management of Black Rock Capital, LLC became our management.
While we were the legal acquirer in the reverse merger, Black Rock Capital, LLC was treated as the accounting acquirer and the transaction was treated as a recapitalization. As a result, at the closing, the historical financial statements of Black Rock became those of the Company. The description of our business presented below is that of our current business and all discussions of periods prior to the reverse merger describe the business of Black Rock.
Black Rock was originally formed on October 28, 2005 as an Arkansas limited liability company under the name “Black Rock Capital, LLC.” From inception through May 2010, Black Rock had no operations. Effective June 1, 2010, Black Rock purchased two separate oil and natural gas fields out of the bankruptcy estate of MSB Energy, Inc. located in Zapata County and Duval County in the onshore Gulf Coast of Texas. Effective May 31, 2011, Black Rock acquired our current interests in the Madera Prospect. In June 2011, Black Rock Capital, LLC filed Articles of Conversion with the Secretary of State for the State of Arkansas to convert Black Rock Capital, LLC into a corporation. The conversion became effective July 1, 2011 and, accordingly, Black Rock Capital, LLC was converted to Black Rock Capital, Inc. As a result of the conversion, our 100% membership interest in Black Rock Capital, LLC became an interest in all of the outstanding common stock of Black Rock.
Our Strengths Strong Management and Operations Team. Our team of managers, employees, consultants and directors combine to represent over 300 years of experience in the oil and natural gas industry as owners, investors, company builders, financiers, operators, geologists, service providers and petroleum engineers. In these various capacities, the Red Mountain team has participated in more than 10,000 wells in 20 states and 22 countries. We intend to utilize sophisticated geologic and 3-D seismic models to enhance the predictability and reproducibility of our operations. We also intend to utilize multi-zone, multi-stage hydraulic fracturing technology in completing wells to substantially increase near-term production, resulting in faster payback periods and higher rates of return and present values. Our team has applied these techniques to improve initial and ultimate production and returns for other organizations.
Existing Infrastructure. All of our properties are located within established oil and natural gas producing areas or existing fields. We seek to enhance existing production in these properties by using our engineering and geological expertise. These areas also have a fully developed transportation infrastructure, which allows us to transport our oil and natural gas to market without long-term delay or significant investment.
Our Strategy Pursue Growth Through Acquisitions that Leverage Our Expertise. Our primary strategy is to identify and acquire proven, undercapitalized plays with development potential. We continually review opportunities to acquire producing properties, undeveloped acreage and drilling prospects. We focus particularly on opportunities where we believe our operational efficiency, reservoir management and geological expertise will enhance value and performance.
Increase Reserves and Production Through Low-Risk Drilling Program and Acquisitions. We intend to achieve reserves and production growth over the next few years through a combination of acquisitions and a low-risk drilling program. In addition to our proved reserve base of 2,082 MBoe at May 31, 2012, we believe we have significant upside potential to convert our current probable and possible reserves interests into proved reserves. We plan to drill 10 wells during fiscal 2013 subject to financing and the outcomes of the initial wells to be drilled. If all of the drilling matches anticipated results, we believe it will result in an estimated increase of 4.7 MMBoe in proved reserves.
Maintain Operational Control. We intend to retain a high degree of operational control over our interests, through a high average working interest or acting as the operator in areas of significant exploration activity. This strategy is intended to provide us with controlling interests in a multi-year inventory of drilling locations, positioning us for reserve and production growth through drilling. We plan to control the timing, level and allocation of our drilling capital expenditures and the technology and methods utilized in the planning, drilling and completion process on related targets. We believe this flexibility to opportunistically pursue development on properties provides us with a meaningful competitive advantage.
Recent Developments Jackson Bough C Prospect. In April and August 2012, we acquired oil and natural gas interests in approximately 320 gross and net acres in the Jackson Bough C Prospect in Lea County, New Mexico for aggregate cash consideration of $78,000. We own a 100% working interest and an 80% net revenue interest in this property.
East and West Ranch Prospects. In April 2012, we acquired oil and natural gas interests in approximately 547 gross and net acres in the East Ranch Prospect in Pecos County, Texas for cash consideration of $421,000. In April 2012, we also acquired oil and natural gas interests in 878 gross and net acres in the West Ranch Prospect in Pecos County, Texas for cash consideration of $677,000. We own a 100% working interest and an 80% net revenue interest in these properties.
Cross Border. On May 23, 2011, Black Rock acquired 2,136,164 units in Cross Border, consisting of 2,136,164 shares of common stock and warrants to purchase 2,136,164 shares of common stock for a purchase price of $3.2 million. The warrants have an exercise price of $2.25 per share and are exercisable until May 26, 2016.
Through a series of privately negotiated stock purchase and sale agreements since August 2011 with a limited number of Cross Border’s stockholders, we acquired an additional 5,270,602 shares of common stock of Cross Border in exchange for 9,942,639 shares of our common stock and $287,532 in cash. As of August 31, 2012, we owned approximately 45.9% of the outstanding common stock of Cross Border.
On April 23, 2012, we entered into a Settlement Agreement with Cross Border to settle litigation filed by us against Cross Border. Pursuant to the Settlement Agreement and effective on May 8, 2012, the litigation was dismissed and Alan W. Barksdale, our Chairman of the Board, President and Chief Executive Officer, and Randell K. Ford and Paul N. Vassilakos, each a member of Red Mountain’s Board of Directors, were appointed as directors of Cross Border. Additionally, Earl Sebring (a consultant of Red Mountain) was subsequently appointed as Interim President of Cross Border and Kenneth Lamb (Controller of Red Mountain) was subsequently appointed as Chief Accounting Officer, Secretary and Treasurer of Cross Border.
Bamco. Mr. Barksdale is the receiver for Bamco Gas, LLC (“Bamco”). Bamco primarily owns oil and gas leasehold interests in various properties, including partial interests in the Frost Bank, La Duquesa and Resendez leases. We have proposed acquiring Bamco’s assets in exchange for issuing 2,375,000 shares of our common stock to Bamco’s receivership estate. The proposed asset acquisition is subject to confirmation by the court presiding over Bamco’s receivership. We expect the court to confirm the plan of acquisition during the second quarter of fiscal 2013.
Hunter Drilling. In March 2012, we formed a wholly owned subsidiary, Hunter Drilling, LLC (“Hunter Drilling”), to bid on certain assets in the pending bankruptcy proceeding of O&G Leasing, LLC and Performance Drilling Company, LLC (collectively, the “Debtors”). At an auction in the Bankruptcy Court, Hunter Drilling was the highest bidder for substantially all of the assets of the Debtors. The assets include five oil and natural gas drilling rigs and related parts and equipment. On July 19, 2012, we entered into an Asset Purchase Agreement (the “Purchase Agreement”) for the purchase and sale of these assets. The Purchase Agreement is subject to the Bankruptcy Court’s confirmation of a Plan of Reorganization filed by First Security Bank over a competing Plan of Reorganization filed by the Debtors and the entry of orders of the Bankruptcy Court approving the Purchase Agreement and the sale of the assets. If these orders are entered by the Bankruptcy Court, it is anticipated that the closing of the transactions contemplated by the Purchase Agreement will occur prior to the end of calendar year 2012. There can be no guarantee that we will be successful in our bid to purchase these assets on the terms described below or at all.
Pursuant to the terms of the Purchase Agreement, Hunter Drilling and the Company agreed (i) to pay $450,000 in cash at closing and (ii) to pay an additional $500,000 for the payment of certain administrative expenses, professional fees, cure amounts and other allowed claims if the amount of cash in the bankruptcy estate is insufficient to pay these claims. On July 19, 2012, Hunter Drilling paid $250,000 into an escrow account as an earnest money deposit, which will be applied toward the cash consideration.
In addition to the cash purchase price, we agreed to issue 1,509,307 shares of our common stock to the holders of Senior Series 2009A Debentures (the “2009A Debentures”) at an agreed price of $1.50 per share, for the payment of accrued and unpaid interest on the 2009A Debentures, subject to adjustment in certain limited circumstances. Hunter Drilling also agreed to issue Senior Secured Convertible Debentures with a term of approximately eight years that accrue interest at a rate of 6% per annum (the “Senior Secured Debentures”) to the holders of 2009A Debentures in the aggregate principal amount of $25,955,000 (the aggregate principal amount of debt held by such holders), subject to adjustment for (A) those 2009A Debentures that have been acquired by us in exchange for issuing shares of our common stock (the “Exchanged Senior Debentures”) and (B) those 2009A Debentures that are redeemed with cash provided by Hunter Drilling at closing. Hunter Drilling agreed to either acquire $2,345,000 in principal amount of 2009A Debentures prior to closing or to tender cash to acquire 2009A Debentures in a principal amount equal to the difference between the $2,345,000 and the principal amount of Exchanged Senior Debentures. Principal and interest on the Senior Secured Debentures will be paid quarterly based on an approximately eight year amortization schedule. The Senior Secured Debentures shall be secured by a first priority lien on the Purchased Assets, subject to certain exceptions. The Senior Secured Debentures are subject to conversion after the closing, in whole or in part at the option of the holders, into shares of our common stock at a conversion price of $2.00 per share of common stock until the first anniversary of the closing, with an increase in the
conversion price of $0.50 per share on each subsequent anniversary of closing until maturity, each subject to adjustment in certain limited circumstances. The Senior Secured Debentures can be prepaid without premium or penalty, subject to prior notice. In addition, Hunter Drilling is required to conduct a dutch auction on an annual basis that uses all excess cash of Hunter Drilling to purchase Senior Secured Debentures.
As part of the purchase price, we agreed to issue 697,110 shares of our common stock to the holders of the Series 2009B Debentures (the “2009B Debentures”) of the Debtors at an agreed price of $1.50 per share, for the payment of accrued and unpaid interest on the 2009B Debentures, subject to adjustment in certain limited circumstances. In addition, Hunter Drilling agreed to issue junior secured debentures with a term of approximately nine years that accrue interest at a rate of 6% per annum (the “Junior Secured Debentures”) to the holders of the 2009B Debentures in the aggregate principal amount of $7.6 million (the aggregate principal amount of debt held by such holders), subject to adjustment for (i) those 2009B Debentures that have been acquired by us in exchange for issuing shares of our common stock (the “Exchanged Junior Debentures”) and (ii) those 2009B Debentures that are redeemed with cash provided by Hunter Drilling at the closing of the transaction. Hunter Drilling agreed to acquire either $1.0 million in principal amount of the Exchanged Junior Debentures prior to the closing of the transaction or to tender cash to acquire 2009B Debentures in a principal amount equal to the difference between the $1.0 million and the principal amount of the Exchanged Junior Debentures.
In August 2012, we acquired an aggregate of $425,000 of 2009B Debentures and the rights to pre-petition interest from four holders in exchange for the issuance of an aggregate of 399,109 shares of the Company’s common stock. The issuance of the Company’s securities to the sellers of the 2009B Debentures was made on a private placement basis and was exempt pursuant to Section 4(2) of the Securities Act of 1933, as amended.
Our Properties Currently, our oil and natural gas properties are concentrated in the Permian Basin and the onshore Gulf Coast of Texas. The Permian Basin covers an area approximately 250 miles wide and 300 miles long in West Texas and Southeast New Mexico. The Permian Basin is one of the most prolific onshore oil and natural gas producing regions in the United States. It is characterized by an extensive production history, mature infrastructure, long reserve life and hydrocarbon potential in multiple producing formations. Our primary operations in the onshore Gulf Coast are in conventional fields that produce primarily from the Wilcox formation in Zapata and Duval Counties of Texas.
Permian Basin. As of May 31, 2012, we had interests in 6,985 gross (5,809 net) acres in the Permian Basin, consisting of the Madera Prospect, Pawnee Prospect, Cowden Lease, Shafter Lake Lease, Martin Lease, Jackson Bough C Prospect, East Ranch Prospect and West Ranch Prospect. We are the operator of each of these properties.
In the aggregate, as of May 31, 2012, these properties had 29 gross (26.9 net) producing wells and, during the month of May 2012, had daily average net production of 265 Boe/d, substantially all of which was oil. As of May 31, 2012, our Permian Basin properties had approximately 1,331.0 MBoe of proved reserves, of which 75.1% was oil. Of our proved reserves in the Permian Basin, 74.9% are from the Madera Prospect. During fiscal 2012, we derived approximately 54.4% of our revenue from the Madera Prospect.
Onshore Gulf Coast. As of May 31, 2012, we had interests in 2,298 gross (450 net) acres in the onshore Gulf Coast of Texas, consisting of the Villarreal Prospect, Frost Bank Prospect, Resendez Prospect and La Dusquesa Prospect. We are the operator of each of these properties, other than the Villarreal Prospect, which is operated by ConocoPhillips Company.
In the aggregate, as of May 31, 2012, these properties had 19 gross (4.0 net) wells and, during the month of May 2012, had daily average net production of 229 Boe/d, substantially all of which was natural gas. As of May 31, 2012, our onshore Gulf Coast properties had approximately 750.8 MBoe of proved reserves, substantially all of which was natural gas. Of our proved reserves in the onshore Gulf Coast, 75.3% are from the Villarreal Prospect. During fiscal 2012, we derived approximately 37.0% of our revenue from the Villarreal Prospect.
For more detailed information on our properties, see “Item 2. Properties.”
Planned Operations We plan to spend between $25.0 million and $30.0 million during fiscal 2013 to drill and complete wells or re-enter and complete wells, most of which will be spent in the Permian Basin. Our primary focus is on the Madera Prospect where we plan to drill up to six wells (3.6 net wells) and on the Cowden Prospect where we plan to drill up to three gross and net wells during fiscal 2013. We also plan to drill one gross and net well on the Jackson Bough C Prospect and one gross and net well on the East and West Ranch Prospects. We currently believe that cash on hand and cash flow from operations will not be sufficient to fund our fiscal 2013 development program and are seeking funding from third parties. If we do not raise additional funds, we may be required to curtail our fiscal 2013 development program. For more information on our capital needs, see Item 7 - “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
Marketing and Customers For fiscal 2012, we sold $3.2 million of oil to Andrews Oil Buyers, Inc. (“Andrews Oil”), representing approximately 50% of our total revenues. We sell our oil to Andrews Oil from our Good Chief State #1, Big Brave State #1 and Madera 24-2H wells pursuant to crude oil purchase contracts. The price of the oil delivered is based on the West Texas Intermediate price, subject to certain price adjustments. The purchase agreements continue until terminated by either party with thirty days prior written notice. We believe that the loss of Andrews Oil would not have a material adverse effect on us because alternative purchasers are readily available.
Competition The oil and natural gas industry is highly competitive and we compete with a substantial number of other companies that have greater resources than we do. The largest of these companies explore for, produce and market oil and natural gas, carry on refining operations and market the resultant products on a worldwide basis. The primary areas in which we encounter substantial competition are in our drilling and development operations, locating and acquiring prospective oil and natural gas properties and reserves and attracting and retaining highly skilled personnel. There is also competition between producers of oil and natural gas and other industries producing alternative energy and fuel. Furthermore, competitive conditions may be substantially affected by various forms of energy legislation and/or regulation considered from time to time by the United States government; however, it is not possible to predict the nature of any such legislation or regulation that may ultimately be adopted or its effects upon our future operations. Such laws and regulations may, however, substantially increase the costs of exploring for, developing or producing oil and natural gas and may prevent or delay the commencement or continuation of a given operation. The effect of these risks cannot be accurately predicted.
Insurance We currently maintain oil and gas commercial general liability protection relating to all of our oil and gas operations (including environmental and pollution claims) with a total limit of coverage in the amount of $2,000,000 (with no deductible) and excess liability protection with a total limit of $3,000,000 (with a deductible of $10,000).
As is common in the oil and gas industry, we will not insure fully against all risks associated with our business either because such insurance is not available or because premium costs are considered prohibitive. In addition, pollution and environmental risks generally are not fully insurable. A loss not fully covered by insurance could have a material adverse effect on our business, financial condition and results of operations.
Employees As of May 31, 2012, we had 17 employees, all of which were full-time employees, and engage additional part-time consultants on an as-needed basis. We are not a party to any collective bargaining agreements and have not experienced any strikes or work stoppages. We believe our relationships with our employees are good.
Hydraulic Fracturing Policies and Procedures We contract with third parties to conduct hydraulic fracturing as a means to maximize the productivity of our oil and natural gas wells in almost all of our wells. Hydraulic fracturing involves the injection of water,
sand, gel and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. All of our proved non-producing and proved undeveloped reserves associated with future drilling, completion and recompletion projects, or approximately 69% of our total estimated proved reserves as of May 31, 2012, will require hydraulic fracturing.
Although average drilling and completion costs for each area will vary, as will the cost of each well within a given area, on average approximately 50% of the drilling and completion costs for our wells are associated with hydraulic fracturing activities. These costs are treated in the same way that all other costs of drilling and completing our wells are treated and are built into and funded through our normal capital expenditures budget. A change to any federal and state laws and regulations governing hydraulic fracturing could impact these costs and adversely affect our business and financial results. See “Risk Factors - Federal and state legislative and regulatory initiatives as well as governmental reviews relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays as well as adversely affect our level of production.”
The protection of groundwater quality is important to us. Our policy and practice is to ensure our service providers follow all applicable guidelines and regulations in the areas where we have hydraulic fracturing operations. In addition, we send at least one of our own engineers or an experienced consultant to the well site to personally supervise each hydraulic fracture treatment.
We believe that the hydraulic fracturing operations on our properties are conducted in compliance with all state and federal regulations and in accordance with industry standard practices for groundwater protection. These protective measures include setting surface casing at a depth sufficient to protect fresh water zones as determined by applicable state regulatory agencies, and cementing the casing to create a permanent isolating barrier between the casing pipe and surrounding geological formations. The casing plus the cement are intended to prevent contact between the fracturing fluid and any aquifers during the hydraulic fracturing or other well operations. For recompletions of existing wells, the production casing is pressure tested prior to perforating the new completion interval. Injection rates and pressures are monitored at the surface during our hydraulic fracturing operations. Pressure is monitored on both the injection string and the immediate annulus to the injection string.
The vast majority of hydraulic fracturing treatments are made up of water and sand or other kinds of man-made propping agents. Our service providers track and report chemical additives that are used in the fracturing operation as required by the applicable governmental agencies.
Hydraulic fracturing requires the use of a significant amount of water. All produced water, including fracture stimulation water, is disposed of in a way that does not impact surface waters. All produced water is disposed of in permitted and regulated disposal facilities.
Environmental Matters and Regulation Our exploration, development and production operations are subject to various federal, state and local laws and regulations governing health and safety, the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may, among other things: require the acquisition of permits to conduct exploration, drilling and production operations; govern the amounts and types of substances that may be released into the environment in connection with oil and natural gas drilling and production; restrict the way we handle or dispose of our wastes or of naturally occurring radioactive materials generated by our operations; cause us to incur significant capital expenditures to install pollution control or safety related equipment operating at our facilities; limit or prohibit construction or drilling activities in sensitive areas such as wetlands, wilderness areas or areas inhabited by endangered or threatened species; impose specific health and safety criteria addressing worker protection; require investigatory and remedial actions to mitigate pollution conditions caused by our operations or attributable to former operations; impose obligations to reclaim and abandon well sites and pits and impose substantial liabilities on us for pollution resulting from our operations. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations and the issuance of orders enjoining some or all of our operations in affected areas.
Additionally, the United States Congress and federal and state agencies frequently revise environmental, health and safety laws and regulations, and their interpretations thereof, and any changes that result in more stringent and costly operational requirements or waste handling, disposal, cleanup and remediation requirements for the oil and natural gas industry could have a significant impact on our operating costs. The trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, and thus, any changes in environmental laws and regulations or new interpretations of enforcement policies that result in more stringent and costly waste handling, storage, transport, disposal or remediation requirements could have a material adverse effect on our financial condition and results of operations. We may be unable to pass on such increased compliance costs to our customers.
We believe that we are in substantial compliance with all existing environmental laws and regulations applicable to our current operations and that our continued compliance with existing requirements will not have a material adverse impact on our financial condition and results of operations. We have not incurred any material capital expenditures for remediation or pollution control activities during fiscal 2012, and we are not aware of any environmental issues or claims that will require material capital expenditures during fiscal 2013 or that will otherwise have a material impact on our financial condition and results of operations in the future. However, we cannot assure you that the passage of more stringent laws and regulations in the future will not have a negative impact on our business, financial condition or results of operations.
The following is a summary of the more significant existing environmental, health and safety laws and regulations to which our business is subject and for which compliance may have a material adverse impact on our capital expenditures, financial condition or results of operations.
Comprehensive Environmental Response, Compensation and Liability Act Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the “Superfund” law, and comparable state statutes impose joint and several liability for costs of investigation and remediation and for natural resource damages without regard to fault or 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 (“PRPs”) include the current and past owners or operators of a site where the release occurred and anyone who transported or disposed or arranged for the transport or disposal of a hazardous substance found at the site. CERCLA also authorizes the Environmental Protection Agency (the “EPA”) and, in some instances, third parties to take actions in response to threats to public health or the environment and to seek to recover from the PRPs the costs of such action. Many states have adopted comparable or more stringent state statutes.
Although CERCLA generally exempts “petroleum” from the definition of hazardous substance, in the course of our operations, we will generate, transport and dispose or arrange for the disposal of wastes that may fall within CERCLA’s definition of hazardous substances. Comparable state statutes may not contain a similar exemption for petroleum. We may also be the owner or operator of sites on which hazardous substances have been released.
Solid and Hazardous Waste Handling The Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes regulate the generation, transportation, treatment, storage, disposal and cleanup of solid and hazardous waste. Although oil and natural gas waste generally is exempt from regulations as hazardous waste under RCRA, we will generate waste as a routine part of our operations that may be subject to RCRA and not all state and local laws contain a comparable exemption. Further, there is no guarantee that the EPA or individual states will not adopt more stringent requirements for the handling of non-hazardous waste or categorize some non-hazardous waste as hazardous in the future. Any such change could result in an increase in our costs to manage and dispose of waste, which could have a material adverse effect on our financial condition and results of operations.
It is also possible that our oil and natural gas operations may require us to manage naturally occurring radioactive materials, or NORM. NORM is present in varying concentrations in sub-surface formations, including hydrocarbon reservoirs, and may become concentrated in scale, film and sludge in equipment that comes in contract with crude oil and natural gas production and processing streams. Some states have enacted regulations governing the handling, treatment, storage and disposal of NORM.
Clean Water Act The Clean Water Act and analogous state laws impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of produced water and other oil and natural gas wastes, and fill materials into state waters and waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of certain permits issued by the EPA or an analogous state agency. Spill prevention, control and countermeasure (“SPCC”) requirements under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. In addition, the Clean Water Act and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. The Clean Water Act also prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by a permit issued by the United States Army Corps of Engineers. Federal and state regulatory agencies can impose administrative, civil and criminal penalties, as well as require remedial or mitigation measures, for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations. In the event of an unauthorized discharge of wastes, we may be liable for penalties and costs of remediation.
The Oil Pollution Act of 1990 (“OPA 90”) and its regulations impose requirements on “responsible parties” related to the prevention of oil spills and liability for damages resulting from oil spills into or upon navigable waters, adjoining shorelines or in the exclusive economic zone of the United States. A “responsible party” under the OPA 90 may include the owner or operator of an onshore facility. The OPA 90 subjects responsible parties to strict, joint and several financial liability for removal costs and other damages, including natural resource damages, caused by an oil spill that is covered by the statute. It also imposes other requirements on responsible parties, such as the preparation of an oil spill contingency plan. Failure to comply with the OPA 90 may subject a responsible party to civil or criminal enforcement action. We may conduct operations on acreage located near, or that affects, navigable waters subject to the OPA 90. We believe that compliance with applicable requirements under the OPA 90 will not have a material and adverse effect on us.
Safe Drinking Water Act The Safe Drinking Water Act (the “SDWA”) regulates, among other things, underground injection operations. Hydraulic fracturing continues to be under intense regulatory scrutiny both at the federal level and at the state level. In past legislative sessions, the United States Congress considered two companion bills that if passed would have imposed on our hydraulic fracturing operations significantly more stringent requirements. In addition to subjecting the injection of hydraulic fracturing to the SDWA regulatory and permitting requirements, the proposed legislation would require the disclosure of the chemicals within the hydraulic fluids, which could make it easier for our competition to copy our operations and for third parties opposing hydraulic fracturing to initiate legal proceedings based on allegations that specific chemicals used in the process could adversely affect ground water. If this or similar legislation is enacted, we could incur substantial compliance costs and the requirements could negatively impact our ability to conduct fracturing activities on our assets.
Many states have considered or adopted legislation or regulations requiring the disclosure of the chemicals used in hydraulic fracturing. Texas has adopted such a program, which is administered by the Railroad Commission of Texas. The Wyoming Oil and Gas Conservation Commission also passed a rule requiring disclosure of hydraulic fracturing fluid. In addition, a number of states in which we plan to conduct, are currently conducting, or may in the future conduct, hydraulic fracturing operations regulatory reviews hydraulic fracturing and new regulations from such reviews could restrict or limit our access to shale formations or could delay our operations or make them more costly.
The BLM has proposed a comprehensive rule regulating hydraulic fracturing on federal and certain tribal lands. The rules impose disclosure requirements on the use of hydraulic fracturing chemicals. These proposed rules also require BLM approval prior to hydraulic fracturing. BLM also would require operators to meet other substantive requirements relating to well integrity and recordkeeping.
The EPA recently issued draft guidance under the SDWA, providing direction about how it will address the use of diesel in hydraulic fracturing activities. The draft guidance provides a definition of diesel fuels and discusses how the EPA’s Underground Injection Control rules will be applied to hydraulic fracturing. Further,
in March 2010, the EPA announced that it would conduct a wide-ranging study on the effects of hydraulic fracturing on drinking water resources. Interim results of the study are expected in 2012, with final results expected in 2014. The agency also announced that one of its enforcement initiatives for 2011 to 2013 would be to focus on environmental compliance by the energy extraction sector. This additional regulatory scrutiny could make it difficult to perform hydraulic fracturing and increase our costs of compliance and doing business.
Air Emissions Our operations are subject to federal, state and local regulations for the control of emissions from sources of air pollution under the Clean Air Act (“CAA”) and analogous state and local programs. Federal and state laws require new and modified sources of air pollutants to obtain permits prior to commencing construction and also impose various monitoring and reporting requirements. Major sources of air pollutants are subject to more stringent, federally imposed requirements including additional permits. Federal and state laws designed to control hazardous or toxic air pollutants may require installation of additional controls. Administrative enforcement actions for failure to comply strictly with air pollution regulations or permits are generally resolved by payment of monetary fines and correction of any identified deficiencies. Alternatively, regulatory agencies could bring lawsuits for civil penalties or require us to forego construction, modification or operation of certain air emission sources.
On April 17, 2012, the EPA signed final rules under the CAA regarding emissions from oil and natural gas operations. The EPA rule subjects oil and natural gas operations to regulation under the New Source Performance Standards (“NSPS”) and National Emissions Standards for Hazardous Air Pollutants (“NESHAPS”), programs under the CAA, and imposes new and amended requirements under both programs. The new rules, among other things, amend standards applicable to natural gas processing plants and would expand the NSPS to include all oil and natural gas operations, imposing requirements on those operations. The EPA also imposed NSPS standards for completions of hydraulically fractured natural gas wells, requiring the use of reduced emission completion techniques. The adopted rules allow in most circumstances, until January 1, 2015, facilities to combust natural gas that would escape during completion activities as an alternative to the reduced emission completion techniques. The NESHAPS proposal includes maximum achievable control technology standards for certain glycol dehydrators and storage vessels, and revises applicability provisions, alternative test protocols and the availability of the startup, shutdown and maintenance exemption. These new requirements may result in increased operating and compliance costs, increased regulatory burdens and delays in our operations. Compliance with such rules could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact our business.
Climate Change Legislation In response to certain scientific studies suggesting that emissions of carbon dioxide, methane and other greenhouse gases (“GHGs”) are contributing to the warming of the Earth’s atmosphere and other climatic changes, the United States Congress has considered legislation to reduce such emissions. To date, the United States Congress has failed to enact a comprehensive GHG program. Some states, either individually or on a regional level, have considered or enacted legal measures to reduce GHG emissions. Although most of the state-level initiatives have to date focused on large sources of GHG emissions, it is possible that smaller sources of emissions could become subject to GHG emission limitations. The cost of complying with these programs could be significant.
The EPA published finding that emissions of GHGs presented an endangerment to public health and the environment. These findings by the EPA allowed the agency to proceed through a rule-making process with the adoption and implementation of regulations that would restrict emissions of GHGs under existing provisions of the CAA. Consequently, the EPA adopted two sets of regulations that would require a reduction in emissions of GHGs from motor vehicles and could trigger permit review for GHG emissions from certain stationary sources. On June 3, 2010, the EPA published its final rule to address permitting of GHG emissions from stationary sources under the prevention of significant deterioration (“PSD”) and Title V permitting programs. The final rule tailors the PSD and Title V permitting programs to apply to qualifying stationary sources of GHG emissions in a multi-step process, beginning January 2, 2011, with the largest sources first
subject to permitting. In addition, the EPA has adopted a rule requiring the reporting of GHG emissions from specified large GHG emission sources in the United States. On November 8, 2010, the EPA finalized its regulations to expand its final rule on GHG emissions reporting to include onshore and offshore oil and natural gas production facilities and onshore oil and natural gas processing, transmission, storage and distribution facilities. Reporting of GHG emissions from such facilities will be required on an annual basis beginning in 2012 for emissions occurring in 2011. While we believe that we will be able to substantially comply with such reporting requirements without any material adverse effect to our financial condition, since such reporting requirements with respect to GHG emissions are new in the oil and natural gas industry, there can be no assurance that our reports will initially be in substantial compliance or that such requirements will not develop into more stringent and costly obligations that may have a significant impact on our operating costs. The adoption and implementation of any regulations imposing reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations or could adversely affect demand for the oil and natural gas we produce. Any one of these climate change regulatory and legislative initiatives could have a material adverse effect on our business, financial condition and results of operations.
Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts and floods and other climatic events; if any such effects were to occur, they could have a material adverse effect on our business and results of operations.
OSHA and Other Laws and Regulations on Employee Health and Safety To the extent not preempted by other applicable laws, we are subject to the requirements of the Occupational Safety and Health Act (“OSHA”) and comparable state statutes, where applicable. These laws and the implementing regulations strictly govern the protection of the health and safety of employees. The OSHA hazard communication standard, the EPA community right-to-know regulations under the Title III of CERCLA and similar state statutes, where applicable, require us to organize and maintain information about hazardous materials used or, as applicable, produced in our operations and that this information be provided to employees, state and local government authorities and, where applicable, citizens. OSHA may enforce workplace safety regulations through issuance of citations for violations of its standards, which include, but are not limited to, those regarding hazard communication, personal protective equipment, general environmental controls, and materials handling and storage. We believe that we are in substantial compliance with these requirements where applicable and with other applicable OSHA and comparable requirements.
National Environmental Policy Act Oil and natural gas exploration and production activities on federal lands may be subject to the National Environmental Policy Act (“NEPA”) which requires federal agencies, including the U.S. Department of the Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an Environmental Assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. All of our current exploration and production activities, as well as proposed exploration and development plans, on federal lands require governmental permits that are subject to the requirements of NEPA. This process has the potential to delay or impose additional conditions upon the development of oil and natural gas projects.
Endangered Species Act The Endangered Species Act, as amended (the “ESA”), and analogous state statutes restrict activities that may affect endangered and threatened species or their habitats. While some of our facilities may be located in areas that are designated as habitat for endangered or threatened species, we believe that we are in substantial compliance with the ESA. However, the designation of previously unidentified endangered or threatened species could cause us to incur additional costs or become subject to operating restrictions or bans in the affected areas.
Other Regulation of the Oil and Natural Gas Industry The oil and natural gas industry is extensively regulated by numerous federal, state and local authorities. In particular, oil and natural gas production and related operations are, or have been, subject to price controls, taxes and numerous other laws and regulations. These laws and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability.
Failure to comply with applicable laws and regulations can result in substantial penalties and possibly cessation of drilling and production operations. The regulatory burden on the industry increases the cost of doing business and affects profitability. We believe that we are in substantial compliance with existing requirements and such compliance will not have a material adverse effect on our financial condition, cash flows or results of operations. Nevertheless, such laws and regulations are frequently amended or reinterpreted. Therefore, we are unable to predict the future costs or impact of compliance. Additional proposals and proceedings that affect the oil and natural gas industry are regularly considered by the United States Congress, the states, the Federal Energy Regulatory Commission (“FERC”) and the courts. We cannot predict when or whether any such proposals may become effective.
Drilling and Production Our operations are subject to various types of regulation at the federal, state and local levels. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. The states and some counties and municipalities in which we operate also regulate one or more of the following:
• the location of wells;
• the method of drilling and casing wells;
• the surface use and restoration of properties upon which wells are drilled; and
• the plugging and abandonment of wells.
State laws, including Texas, regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploitation while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and natural gas we can produce from our wells or limit the number of wells or the locations at which we can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil and natural gas within its jurisdiction.
In addition, 11 states have enacted surface damage statutes (“SDAs”). These laws are designed to compensate for damage caused by mineral development. Most SDAs contain entry notification and negotiation requirements to facilitate contact between operators and surface owners and users. Most also contain bonding requirements and specific expenses for exploration and producing activities. Costs and delays associated with SDAs could impair operational effectiveness and increase development costs.
We do not control the availability of transportation and processing facilities used in the marketing of our production. For example, we may have to shut-in a productive natural gas well because of a lack of available natural gas gathering or transportation facilities.
If we conduct operations on federal, state or Indian oil and natural gas leases, these operations must comply with numerous regulatory restrictions, including various non-discrimination statutes, royalty and related valuation requirements, and certain of these operations must be conducted pursuant to certain on-site security regulations and other appropriate permits issued by the Bureau of Land Management, the Bureau of Ocean Energy Management, Regulation and Enforcement or other appropriate federal or state agencies.
Transportation of Oil Sales of oil are not currently regulated and are made at negotiated prices. Nevertheless, the United States Congress could reenact price controls in the future.
Our sales of oil are affected by the availability, terms and cost of transportation. The transportation of oil in common carrier pipelines is also subject to rate and access regulation. The FERC regulates interstate oil pipeline transportation rates under the Interstate Commerce Act. In general, interstate oil pipeline rates must be cost-based, although settlement rates agreed to by all shippers are permitted and market based rates may be permitted in certain circumstances. Effective January 1, 1995, the FERC implemented regulations establishing an indexing system (based on inflation) for transportation rates for oil that allowed for an annual increase or decrease in the cost of transporting oil to the purchaser, effective July 1 of each year. The FERC reviews the indexing methodology every five years. In its latest order on the methodology, issued in December 2010, the FERC concluded that an index level of the Producer Price Index for Finished Goods plus 2.65 percent should be established for the five-year period commencing July 1, 2011.
Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any way that is of material difference from those of our competitors who are similarly situated.
Further, interstate and intrastate common carrier oil pipelines must provide service on a non- discriminatory basis. Under this open access standard, common carriers must offer service to all similarly situated shippers requesting service on the same terms and under the same rates. When shipper nominations exceed full capacity, access is governed by prorationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our similarly situated competitors.
Transportation and Sales of Natural Gas Historically, the transportation and sale for resale of natural gas in interstate commerce has been regulated by the FERC under the Natural Gas Act of 1938 (the “NGA”), the Natural Gas Policy Act of 1978 (the “NGPA”), and regulations issued under those statutes. In the past, the federal government has regulated the prices at which natural gas could be sold. While sales by producers of natural gas can currently be made at market prices, the United State Congress could reenact price controls in the future. Deregulation of wellhead natural gas sales began with the enactment of the NGPA and culminated in adoption of the Natural Gas Wellhead Decontrol Act which removed all price controls affecting wellhead sales of natural gas effective January 1, 1993.
FERC regulates interstate natural gas transportation rates, and terms and conditions of service, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas. Since 1985, the FERC has endeavored to make natural gas transportation more accessible to natural gas buyers and sellers on an open and non-discriminatory basis. The FERC has stated that open access policies are necessary to improve the competitive structure of the interstate natural gas pipeline industry and to create a regulatory framework that will put natural gas sellers into more direct contractual relations with natural gas buyers by, among other things, unbundling the sale of natural gas from the sale of transportation and storage services. Beginning in 1992, the FERC issued a series of orders, beginning with Order No. 636, to implement its open access policies. As a result, the interstate pipelines’ traditional role of providing the sale and transportation of natural gas as a single service has been eliminated and replaced by a structure under which pipelines provide transportation and storage service on an open access basis to others who buy and sell natural gas. Although the FERC’s orders do not directly regulate natural gas producers, they are intended to foster increased competition within all phases of the natural gas industry.
The price at which we sell natural gas is not currently subject to federal rate regulation and, for the most part, is not subject to state regulation. However, with regard to our physical sales of these energy commodities, we are required to observe anti-market manipulation laws and related regulations enforced by
the FERC and/or the Commodity Futures Trading Commission (the “CFTC”). See “- Other Federal Laws and Regulations Affecting Our Industry - Energy Policy Act of 2005.” Should we violate the anti-market manipulation laws and regulations, we could also be subject to related third party damage claims by, among others, sellers, royalty owners and taxing authorities. In addition, pursuant to Order No. 704, some of our operations may be required to annually report to the FERC on May 1 of each year for the previous calendar year. Currently, Order No. 704 requires certain natural gas market participants to report information regarding their reporting of transactions to price index publishers and their blanket sales certificate status, as well as certain information regarding their wholesale, physical natural gas transactions for the previous calendar year depending on the volume of natural gas transacted. See “- Other Federal Laws and Regulations Affecting Our Industry - FERC Market Transparency Rules.”
Gathering services, which occur upstream of jurisdictional transmission services, are regulated by the states. In addition, intrastate natural gas transportation and facilities are also subject to regulation by state regulatory agencies, and certain transportation services provided by intrastate pipelines are also regulated by the FERC. The basis for regulation of intrastate natural gas transportation and gathering the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline and gathering pipeline rates and services varies from state to state. Insofar as such regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable basis, we believe that the regulation of similarly situated intrastate natural gas transportation in any states in which we operate and ship natural gas on an intrastate basis will not affect our operations in any way that is of material difference from those of our competitors. Like the regulation of interstate transportation rates, the regulation of intrastate transportation rates affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas.
State Natural Gas Regulation Various states, including Texas, regulate the drilling for, and the production, gathering and sale of, natural gas, including imposing severance taxes and requirements for obtaining drilling permits. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of natural gas resources. States may regulate rates of production and may establish maximum daily production allowables from natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but there can be no assurance that they will not do so in the future. The effect of these regulations may be to limit the amounts of natural gas that may be produced from our wells and to limit the number of wells or locations we can drill.
Other Federal Laws and Regulations Affecting Our Industry Energy Policy Act of 2005 On August 8, 2005, President Bush signed into law the Energy Policy Act of 2005 (the “EPAct 2005”). The EPAct 2005 is a comprehensive compilation of tax incentives, authorized appropriations for grants and guaranteed loans, and significant changes to the statutory policy that affects all segments of the energy industry. Among other matters, the EPAct 2005 amends the NGA to add an anti-manipulation provision which makes it unlawful for any entity to engage in prohibited behavior to be prescribed by the FERC, and furthermore provides the FERC with additional civil penalty authority. The EPAct 2005 provides the FERC with the power to assess civil penalties of up to $1.0 million per day for violations of the NGA and increases the FERC’s civil penalty authority under the NGPA from $5,000 per violation per day to $1.0 million per violation per day. On January 19, 2006, the FERC issued Order No. 670, a rule that implements the anti-manipulation provision of the EPAct 2005 and makes it unlawful for any entity, directly or indirectly, in connection with the purchase or sale of natural gas subject to the jurisdiction of the FERC, or the purchase or sale of transportation services subject to the jurisdiction of the FERC: (1) to use or employ any device, scheme or artifice to defraud; (2) to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or (3) to engage in any act, practice, or course of business that operates as a fraud or deceit upon any person. The anti-manipulation rules and enhanced civil penalty authority reflect an expansion of the FERC’s NGA enforcement authority. Should we fail to comply with all applicable FERC administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines.
FERC Market Transparency Rules On April 19, 2007, the FERC issued a final rule on the annual natural gas transaction reporting requirements, as amended by subsequent orders on rehearing, or Order No. 704. Under Order No. 704, wholesale buyers and sellers of more than 2.2 million MMBtu of physical natural gas in the previous calendar year, including interstate and intrastate natural gas pipelines, natural gas gatherers, natural gas processors, natural gas marketers and natural gas producers are required to report, on May 1 of each year, aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to or may contribute to the formation of price indices. It is the responsibility of the reporting entity to determine which individual transactions should be reported based on the guidance of Order No. 704. Order No. 704 also requires market participants to indicate whether they report prices to any index publishers and, if so, whether their reporting complies with the FERC’s policy statement on price reporting. In 2011, a federal appellate court determined that FERC does not have legal authority to impose reporting requirements on wholly-intrastate pipelines.
Additional proposals and proceedings that might affect the natural gas industry are pending before the United State Congress, the FERC and the courts. We cannot predict the ultimate impact of these or the above regulatory changes to our natural gas operations. We do not believe that we would be affected by any such action materially differently than similarly situated competitors.
Item 1A.
Item 1A. Risk Factors Risks Related to Our Business We currently do not have sufficient funds for our planned exploration or development activities for fiscal 2013 and will need additional capital to continue our operations beyond November 16, 2012, or sooner if demand for payment is made under either our line of credit or promissory note with First State Bank of Lonoke. The oil and natural gas industry is capital intensive. We make and expect to continue to make significant capital expenditures in our business for the exploration, development, production and acquisition of oil and natural gas reserves. Improvement in commodity prices may result in an increase in our actual capital expenditures.
We plan to spend between $25.0 million and $30.0 million during fiscal 2013 to drill and complete wells or re-enter and complete wells, most of which will be spent in the Permian Basin. However, as of May 31, 2012, we had a working capital deficit of $10.4 million. We currently do not have sufficient funds for our planned exploration or development activities for fiscal 2013 and will need additional capital to continue our operations beyond November 16, 2012, the maturity date of our $4.0 million senior secured promissory note with Hyman Belzberg, William Belzberg and Caddo Management, Inc. (collectively, the “Lenders”), or sooner if demand for payment is made under either our line of credit or promissory note with First State Bank of Lonoke. If we are unable to finance our operations on acceptable terms or at all, we may be forced to curtail or suspend our planned exploration and development activities and our business, financial condition and results of operations may be materially and adversely affected.
Our cash flows from operations and access to capital are subject to a number of variables, including:
• our proved reserves;
• the level of oil and natural gas we are able to produce from existing wells;
• the prices at which our oil and natural gas are sold;
• our ability to acquire, locate and produce new reserves; and
• the ability of our banks to lend.
Debt financing could lead to:
• a substantial portion of operating cash flow being dedicated to the payment of principal and interest;
• us being more vulnerable to competitive pressures and economic downturns; and
• restrictions on our operations, including our ability to pay dividends.
If sufficient capital resources are not available, we might be forced to cease operations entirely, curtail developmental and exploratory drilling and other activities or be forced to sell some assets on an untimely or unfavorable basis, which would have a material adverse effect on our business, financial condition and results of operations.
Our line of credit and promissory note with the First State Bank of Lonoke are due and payable on demand, and we may not have sufficient funds available to repay either of the loans if it is called earlier than we anticipate. As of May 31, 2012, we had $1.8 million outstanding under our line of credit, and $2.3 million outstanding under a promissory note, each with the First State Bank of Lonoke. First State Bank of Lonoke has the right to demand repayment of either of these loans at any time. We currently do not have sufficient cash to repay either of these loans in full if First State Bank of Lonoke were to demand repayment. We cannot provide any assurances that we will be able to raise the necessary amount of capital to repay these obligations or that we will be able to extend the maturity dates or otherwise refinance these obligations on acceptable terms or at all.
The line of credit is secured by a lien against our Villarreal, Frost Bank, Resendez and La Duquesa properties, 2,136,164 shares of Cross Border common stock owned by us and certain property owned by Ernest Bartlett, a co-signor to the line of credit. The promissory note is secured by a pledge of all of the common stock of Black Rock, 2,000,000 shares of our common stock held by StoneStreet and a lien against our Villarreal, Frost Bank, Resendez and La Duquesa properties. Upon a default, First State Bank of Lonoke would have the right to exercise its rights and remedies to collect, which would include foreclosing on our collateral. Accordingly, our inability to pay off either of these loans upon demand would have a material adverse effect on our business and, if First State Bank of Lonoke exercises its rights and remedies, we could be forced to seek bankruptcy protection.
Our outstanding debt contains covenants restricting certain actions we may take. First State Bank of Lonoke holds a secured lien against our Villarreal, Frost Bank, Resendez and La Duquesa properties, which accounted for approximately 39.7% of our revenue during fiscal 2012. Furthermore, First State Bank of Lonoke has a pledge of all of the common stock of Black Rock. Our line of credit and our promissory note with First State Bank of Lonoke also contain various covenants that Black Rock must comply with. Additionally, the promissory note from the Lenders is secured by first and second priority real property liens against certain of our properties and contains various restrictive covenants. As a result, neither we nor Black Rock is permitted to engage in certain activities without the prior consent of First State Bank of Lonoke or the Lenders, as the case may be. These include, among other things, acquiring or disposing of assets, merging with any company, materially changing Black Rock’s legal structure, management or ownership or incurring or assuming any additional debt. There is no assurance that, if requested, First State Bank of Lonoke or the Lenders will consent to any such action. Accordingly, our outstanding debt may adversely affect our operations.
Our business is difficult to evaluate because we have a limited operating history. Substantially all of our revenues are derived from Black Rock’s operations. Prior to June 2010, Black Rock had no operations. After Black Rock’s June 2010 acquisition of oil and natural gas properties in Zapata County and Duval County in the onshore Gulf Coast of Texas, it began to recognize revenue from its operations. Accordingly, we have a very short financial operating history and incurred a net loss of $12.4 million during the fiscal year ended May 31, 2012. As a result, there is only limited historical financial and operating information available upon which to base your evaluation of our performance.
We may have difficulty managing growth in our business, which could adversely affect our financial condition and results of operations. As a recently-formed company, growth in accordance with our business plan, if achieved, could place a significant strain on our financial, technical, operational and management resources. As we expand our activities and increase the number of projects we are evaluating or in which we participate, there will be additional demands on our financial, technical, operational and management resources. The failure to continue to upgrade our technical, administrative, operating and financial control systems or the occurrences of unexpected expansion difficulties, including the failure to recruit and retain experienced managers, geologists, engineers and other professionals in the oil and natural gas industry, could have a material adverse effect on our business, financial condition and results of operations and our ability to timely execute our business plan.
A substantial or extended decline in oil and natural gas prices may adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments. The price we receive for our oil and natural gas will heavily influence our revenue, profitability, access to capital and future rate of growth. Oil and natural gas are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil and natural gas have been volatile. These markets will likely continue to be volatile in the future. The prices we receive for our production depend on numerous factors beyond our control. These factors include the following:
• worldwide and regional economic conditions impacting the global supply and demand for oil and natural gas;
• the price and quantity of imports of foreign oil and natural gas;
• the actions of the Organization of Petroleum Exporting Countries, or OPEC, and other state-controlled oil companies relating to oil and natural gas price and production control;
• political conditions in or affecting other oil-producing and natural gas-producing countries, including the current conflicts in the Middle East and conditions in South America and Russia;
• the level of global oil and natural gas inventories;
• localized supply and demand fundamentals;
• the availability of refining capacity;
• price and availability of transportation and pipeline systems with adequate capacity;
• weather conditions and natural disasters;
• governmental regulations;
• speculation as to the future price of oil and the speculative trading of oil and natural gas futures contracts;
• price and availability of competitors’ supplies of oil and natural gas;
• energy conservation and environmental measures;
• technological advances affecting energy consumption;
• the price and availability of alternative fuels and energy sources; and
• domestic and international drilling activity.
Declines in oil and natural gas prices may materially adversely affect our financial condition, liquidity, and ability to finance planned capital expenditures and results of operations and may reduce the amount of oil and natural gas that we can produce economically. This could have a material adverse effect on our liquidity and financial condition.
Properties that we acquire may not produce as projected, and we may be unable to accurately predict reserve potential, identify liabilities associated with the properties or obtain protection from sellers against such liabilities. As part of our growth strategy, we intend to acquire additional interests in oil and natural gas properties. Any future acquisitions will require an assessment of recoverable reserves, title, future oil and natural gas prices, operating costs, potential environmental hazards and liabilities, potential tax and Employee Retirement Income Security Act liabilities, and other liabilities and other similar factors. Generally, it is not feasible for us to review in detail every individual property involved in an acquisition, and our review efforts are normally focused on the higher-valued properties. Even a detailed review of properties and records may not reveal existing or potential problems, nor will it permit us to become sufficiently familiar with the properties to assess fully their deficiencies and capabilities. We do not inspect every well that we acquire. Potential problems, such as deficiencies in the mechanical integrity of equipment or environmental conditions that may require significant remedial expenditures, are not necessarily observable even when we inspect a well. Any unidentified problems could result in material liabilities and costs that negatively impact our financial condition and results of operations.
Even if we are able to identify problems with an acquisition, the seller may be unwilling or unable to provide effective contractual protection or indemnity against all or part of these problems. Even if a seller agrees to provide indemnity, the indemnity may not be fully enforceable and may be limited by floors and caps on such indemnity. In addition, we may acquire oil and natural gas properties that contain commercially productive reserves which are less than predicted. Any of these factors could have a material adverse effect on our results of operations and reserve growth.
Our failure to successfully identify, complete and integrate future acquisitions of properties or businesses could reduce our earnings and slow our growth. There is intense competition for acquisition opportunities in our industry. Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions. Our ability to complete acquisitions is dependent upon, among other things, our ability to obtain debt and equity financing and, in some cases, regulatory approvals. Further, these acquisitions may be in geographic regions in which we do not currently operate, which could result in unforeseen operating difficulties and difficulties in coordinating geographically dispersed operations, personnel and facilities. In addition, if we enter into new geographic markets, we may be subject to additional and unfamiliar legal and regulatory requirements. Compliance with regulatory requirements may impose substantial additional obligations on us and our management, cause us to expend additional time and resources in compliance activities and increase our exposure to penalties or fines for non-compliance with such additional legal requirements. Completed acquisitions could require us to invest further in operational, financial and management information systems and to attract, retain, motivate and effectively manage additional employees. The inability to effectively manage the integration of acquisitions could reduce our focus on subsequent acquisitions and current operations, which, in turn, could negatively impact our earnings and growth. Our financial position and results of operations may fluctuate significantly from period to period, based on whether or not significant acquisitions are completed in particular periods.
We cannot control the development of the properties we do not operate, which may adversely affect our production, revenues and results of operations. We do not operate all of the properties in which we have an interest. As a result, we have limited ability to exercise influence over, and control the risks associated with, the operation of these properties. The success and timing of our drilling and development activities on those properties depend upon a number of factors outside of our control, including:
• the timing and amount of capital expenditures;
• the operators’ expertise and financial resources;
• the approval of other participants in drilling wells; and
• the selection of suitable technology.
As a result of any of the above or an operator’s failure to act in ways that are in our best interest, our allocated production revenues and results of operations could be adversely affected.
Drilling for and producing oil and natural gas are speculative activities and involve numerous risks and substantial and uncertain costs that could adversely affect us. Our future financial condition and results of operations will depend on the success of our acquisition, exploitation, development and production activities. Our oil and natural gas exploration and production activities are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially productive oil or natural gas reservoirs. Our decisions to acquire, explore, develop or otherwise exploit drilling locations or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. In addition, our cost of drilling, completing and operating wells is often uncertain before drilling commences. Overruns in budgeted expenditures are common risks that can make a particular project uneconomical. Further, many factors may curtail, delay or cancel our scheduled drilling projects, including the following:
• shortages of or delays in obtaining equipment and qualified personnel;
• facility or equipment malfunctions;
• unexpected operational events;
• pressure or irregularities in geological formations;
• adverse weather conditions, such as flooding;
• reductions in oil and natural gas prices;
• delays imposed by or resulting from compliance with regulatory requirements;
• proximity to and capacity of transportation facilities;
• title problems;
• limitations in the market for oil and natural gas; and
• costs and availability of drilling rigs, equipment, supplies, personnel and oilfield services.
Even if drilled, our completed wells may not produce reserves of oil or natural gas that are commercially productive or that meet our earlier estimates of economically recoverable reserves. A productive well may become uneconomic if water or other deleterious substances are encountered, which impair or prevent the production of oil and/or natural gas from the well. Our overall drilling success rate or our drilling success rate for activity within a particular project area may decline. Unsuccessful drilling activities could result in a significant decline in our production and revenues and materially harm our operations and financial condition by reducing our available cash and resources.
Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in our reserve estimates or underlying assumptions could materially affect the quantities and present values of our reserves. This Annual Report on Form 10-K contains estimates of our proved oil and natural gas reserves and PV-10 and standardized measure of our proved oil and natural gas reserves. The process of estimating oil and natural gas reserves is complex. It requires interpretations of available technical data and various assumptions, including assumptions relating to economic factors. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities of reserves and amount of PV-10 and standardized measure that we may report. The process of preparing these estimates requires the projection of production rates and timing of development expenditures and analysis of available geological, geophysical, production and engineering data, and the extent, quality and reliability of this data can vary. The process also requires economic assumptions relating to matters such as oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds.
Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves most likely will vary from our estimates. Any significant variance could materially affect the estimated quantities of reserves and amount of PV-10 and standardized measure that we may report. In addition, we may adjust estimates of proved reserves and amount of PV-10 and standardized measure to reflect production history, results of exploration and development, prevailing oil and natural gas prices and other factors, many of which are beyond our control. Moreover, there can be no assurance that our reserves will ultimately be produced or that our proved undeveloped reserves will be developed within the periods anticipated. Any significant variance in the assumptions could materially affect the estimated quantity our reserves and amount of PV-10 and standardized measure.
Investors should not assume that the PV-10 of our proved reserves is the current market value of our estimated oil and natural gas reserves. PV-10 is based on prices and costs in effect on the date of the estimate. Actual future prices, costs, and the volume of produced reserves may differ materially from those used in the PV-10 estimate.
Approximately 57% of our total estimated proved reserves as of May 31, 2012 were classified as proved undeveloped and may not be ultimately developed or produced. As of May 31, 2012, approximately 57% of our total estimated proved reserves were undeveloped. Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations. The future drilling of proved undeveloped reserves is highly dependent upon our ability to fund our capital expenditures, which we estimate will be approximately $25.0 million to $30.0 million for fiscal 2013. We cannot be sure that these estimated costs are accurate, and we may be unable to obtain sufficient capital. Further, our drilling efforts may be delayed or unsuccessful, and actual reserves may prove to be less than current reserve estimates, which could have a material adverse effect on our financial condition, future cash flows and results of operations.
If we are unable to find purchasers of our natural gas, it could harm our profitability. There generally are only a limited number of natural gas transmission companies with existing pipelines in the vicinity of a natural gas well or wells. In the event that producing natural gas properties are not subject to purchase contracts or that any such contracts terminate and other parties do not purchase our natural gas production, there is no assurance that we will be able to enter into purchase contracts with any transmission companies or other purchasers of natural gas and there can be no assurance regarding the price which such purchasers would be willing to pay for such natural gas. There presently exists an oversupply of natural gas in the marketplace, the extent and duration of which is not known. Such oversupply may result in reductions of purchases by principal natural gas pipeline purchasers.
If oil and natural gas prices decrease, we may be required to take write-downs of the carrying values of our oil and natural gas properties. We will review our proved oil and natural gas properties for impairment whenever events or changes in circumstances indicate that a decline in the recoverability of their carrying value may have occurred. Based on specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write down the carrying value of our oil and natural gas properties, which may result in a decrease in the amount of future permitted indebtedness available. A write-down constitutes a non-cash charge to earnings. We may incur impairment charges in the future, which could have a material adverse effect on our results of operations for the periods in which such charges are taken.
Unless we replace oil and natural gas reserves, our production and cash flows will decline. Our future success will depend on our ability to find, develop or acquire additional reserves that are commercially productive. If we are unable to replace reserves through drilling or acquisitions, our level of production and cash flows will be adversely affected. In general, production from oil and natural gas properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. Our total proved reserves decline as reserves are produced unless we conduct other successful exploration and development activities or acquire properties containing proved reserves, or both. Our ability to make the necessary capital investment to maintain or expand our asset base of oil and natural gas reserves would be impaired to the extent cash flow from operations is reduced and external sources of capital become limited or unavailable. We may not be successful in exploring for, developing or acquiring additional reserves. We also may not be successful in raising funds to acquire, explore or develop additional reserves.
Of our total undeveloped leasehold acreage, 32.7% is subject to leases that will expire in fiscal 2013 unless production is established on units containing the acreage or the leases are extended. Of our total undeveloped leasehold acreage, 32.7% is currently not held by production. Unless production in paying quantities is established on units containing these leases during their primary terms or we obtain extensions of the leases, these leases will expire in fiscal 2013. If our leases expire, we will lose our right to develop the related properties.
Our drilling plans for these areas are subject to change based upon various factors, including factors that are beyond our control. Such factors include drilling results, oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, gathering system and pipeline transportation constraints, and regulatory approvals.
Prospects that we decide to drill may not yield oil or natural gas in commercially viable quantities. Prospects that we decide to drill that do not yield oil or natural gas in commercially productive quantities will adversely affect our financial condition and results of operations. Our prospects are in various stages of evaluation, and may range from a prospect which is ready to drill to a prospect that will require substantial additional seismic data processing and interpretation and other technical analysis. There is no way to predict in advance of drilling and testing whether any particular prospect will yield oil or natural gas in sufficient quantities to recover drilling or completion costs or to be commercially productive. The use of seismic data and other technologies and the study of producing fields in the same area will not enable us to know
conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in commercial quantities. We cannot assure you that the analogies we draw from available data from other wells, more fully explored prospects or producing fields will be applicable to our drilling prospects.
Market conditions or transportation impediments may hinder access to oil and natural gas markets or delay production. Market conditions, the unavailability of satisfactory oil and natural gas transportation or the remote location of our drilling operations may restrict our access to oil and natural gas markets or delay production. The availability of a ready market for oil and natural gas production depends on a number of factors, including the demand for and supply of oil and natural gas, the proximity of reserves to pipelines or trucking and terminal facilities and the availability of trucks and other transportation equipment. We may be required to shut-in wells or delay initial production for lack of a viable market or because of inadequacy or unavailability of pipeline or gathering system capacity. When that occurs, we will be unable to realize revenue from those wells until the production can be tied to a gathering system. This can result in considerable delays from the initial discovery of a reservoir to the actual production of the oil and natural gas and realization of revenues.
Delays in obtaining permits by us for our operations could impact our business. We are required to obtain permits from one or more governmental agencies in order to perform drilling and completion activities, including hydraulic fracturing. Such permits are typically required by state agencies, but can also be required by federal and local governmental agencies. As with all governmental permitting processes, there is a degree of uncertainty as to whether a permit will be granted, the time it will take for a permit to be issued, and the conditions which may be imposed in connection with the granting of the permit. Hydraulic fracturing activities, which we estimate will represent approximately 50% of our forecasted development costs for fiscal 2013, has been particularly scrutinized. New York, for example, recently issued a moratorium currently in effect on the issuance of permits for inland drilling and completion activities. Subject to an Executive Order issued by Governor Paterson on December 13, 2010, the New York Department of Environmental Conservation will not issue permits for drilling and completion activities until it completes a final environmental impact study following public comment. Texas is not currently considering such a measure. In addition, on May 17, 2012, the Governor of Vermont signed a bill banning hydraulic fracturing in the state of Vermont. To date, Vermont is the first and only state to ban hydraulic fracturing. If we are unable to obtain the necessary permits for our operations, it could have a material adverse effect on our results of operations and profitability.
Our operations are subject to hazards inherent in the oil and natural gas industry. We implement hydraulic fracturing in our operations, a process involving the injection of fluids - usually consisting mostly of water but typically including small amounts of several chemical additives - as well as sand in order to create fractures extending from the wellbore through the rock formation to enable oil or natural gas to move more easily through the rock pores to a production well. Risks inherent to our industry include the potential for significant losses associated with damage to the environment. Equipment design or operational failures, or vehicle operator error can result in explosions and discharges of toxic gases, chemicals and hazardous substances, and, in rare cases, uncontrollable flows of natural gas or well fluids into environmental media, as well as personal injury, loss of life, long-term suspension or cessation of operations and interruption of our business and/or the business or livelihood of third parties, damage to geologic formations, environmental media and natural resources, equipment and/or facilities and property. In addition, we use and generate hazardous substances and wastes in our operations and may become subject to claims relating to the release of such substances into the environment. In addition, some of our current properties are, or have been, used for industrial purposes, which could contain currently unknown contamination that could expose us to governmental requirements or claims relating to environmental remediation, personal injury and/or property damage. These conditions could expose us to liability for personal injury, wrongful death, property damage, loss of oil and natural gas production, pollution and other environmental damages and, in an extreme case, could materially impair our profitability, competitive position or viability. Depending on the frequency and severity of such liabilities or losses, it is possible that our operating costs, insurability and relationships with employees and regulators could be materially impaired.
Our business and operations may be adversely affected by regulations affecting the oil and natural gas industry. Our business and operations are subject to and impacted by a wide array of federal, state, and local laws and regulations on the exploration for and development, production, and marketing of oil and natural gas, the operation of oil and natural gas wells, taxation, and environmental and safety matters. Many laws and regulations require drilling permits and govern the spacing of wells, rates of production, prevention of waste and other matters. The technical requirements of these laws and regulations are becoming increasingly stringent, complex and costly to implement. The high cost of compliance with applicable regulations may cause us to limit or discontinue our operation and development activities.
Changes in regulations and laws relating to the oil and natural gas industry could result in our operations being disrupted or curtailed by government authorities. For example, oil and natural gas exploration and production may become less cost effective and decline as a result of increasingly stringent environmental requirements (including land use policies responsive to environmental concerns and delays or difficulties in obtaining environmental permits). A decline in exploration and production, in turn could have a material adverse effect on our business, financial condition, results of operations and cash flows.
The unavailability or high cost of drilling rigs, equipment, supplies, personnel and oilfield services could adversely affect our ability to execute exploration plans on a timely basis and within budget. We are highly dependent upon third-party services. The cost of oilfield services typically fluctuates based on demand for those services. There is no assurance that we will be able to contract for such services on a timely basis or that the cost of such services will remain at a satisfactory or affordable level. Shortages or the high cost of drilling rigs, equipment, supplies or personnel could delay or adversely affect our exploration operations, which could have a material adverse effect on our business, financial condition or results of operations.
Production of oil and natural gas could be materially and adversely affected by natural disasters or severe or unseasonable weather. Production of oil and natural gas could be materially and adversely affected by natural disasters or severe weather. Repercussions of natural disasters or severe weather conditions may include:
• evacuation of personnel and curtailment of operations;
• damage to drilling rigs or other facilities, resulting in suspension of operations;
• inability to deliver materials to worksites; and
• damage to pipelines and other transportation facilities.
In addition, our hydraulic fracturing operations require significant quantities of water. Texas recently has experienced drought conditions. Any diminished access to water for use in hydraulic fracturing, whether due to usage restrictions or drought or other weather conditions, could curtail our operations or otherwise result in delays in operations or increased costs.
Operating hazards, natural disasters or other interruptions of our operations could result in potential liabilities, which may not be fully covered by our insurance. The oil and natural gas business generally, and our operations specifically, are subject to certain operating hazards such as:
• accidents resulting in serious bodily injury and the loss of life or property;
• liabilities from accidents or damage by our equipment;
• well blowouts;
• cratering (catastrophic failure);
• explosions;
• uncontrollable flows of oil, natural gas or well fluids;
• abnormally pressurized formations;
• fires;
• reservoir damage;
• oil spills;
• pollution and other damage to the environment; and
• releases of toxic gas.
In addition, our operations are susceptible to damage from natural disasters such as flooding or tornados, which involve increased risks of personal injury, property damage and marketing interruptions. The occurrence of one of these operating hazards may result in injury, loss of life, suspension of operations, environmental damage and remediation and/or governmental investigations and penalties. The payment of any of these liabilities could reduce, or even eliminate, the funds available for exploration and development, or could result in a loss of our properties. In addition, pollution and environmental risks generally are not fully insurable. If a significant accident or other event occurs and is not fully covered by insurance, it could materially adversely affect our financial condition, results of operations and cash flows.
Our insurance might be inadequate to cover our liabilities. Insurance costs are expected to continue to increase over the next few years, and we may decrease coverage and retain more risk to mitigate future cost increases. If we incur substantial liability, and the damages are not covered by insurance or are in excess of policy limits, then our business, results of operations and financial condition may be materially adversely affected.
We may not be able to keep pace with technological developments in our industry. The oil and natural gas industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. As others use or develop new technologies, we may be placed at a competitive disadvantage or competitive pressures may force us to implement those new technologies at substantial costs. In addition, other oil and natural gas companies may have greater financial, technical and personnel resources that allow them to enjoy technological advantages and may in the future allow them to implement new technologies before we can. We may not be able to respond to these competitive pressures and implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use now or in the future were to become obsolete or if we are unable to use the most advanced commercially available technology, our business, financial condition and results of operations could be materially adversely affected.
Competition in the oil and natural gas industry is intense, and many of our competitors have resources that are greater than ours. We operate in a highly competitive environment for developing and acquiring properties, marketing oil and natural gas and securing equipment and trained personnel. As a relatively small oil and natural gas company, many of our competitors, major and large independent oil and natural gas companies, possess and employ financial, technical and personnel resources substantially greater than ours. Those companies may be able to develop and acquire more prospects and productive properties than our financial or personnel resources permit. Our ability to acquire additional prospects and discover reserves in the future will depend on our ability to evaluate and select suitable properties and execute our exploration and development activities in a highly competitive environment. Also, there is substantial competition for capital available for investment in the oil and natural gas industry. Larger competitors may be better able to withstand sustained periods of unsuccessful drilling and absorb the burden of changes in laws and regulations more easily than we can, which would adversely affect our competitive position. We may not be able to compete successfully in the future in developing reserves, acquiring prospective oil and natural gas properties and reserves, attracting and retaining highly skilled personnel and raising additional capital.
We may be unable to diversify our operations to avoid any downturn in the oil and natural gas industry. Because of our limited financial resources, it is unlikely that we will be able to diversify our operations the way companies with greater financial resources are able to do. Our inability to diversify our activities will subject us to economic fluctuations within the oil and natural gas industry and therefore increase the risks associated with our operations as limited to one industry.
Certain federal income tax deductions currently available with respect to oil and natural gas exploration and development may be eliminated as a result of future legislation. President Obama’s proposed Fiscal Year 2013 Budget includes proposed legislation that would, if enacted into law, make significant changes to United States tax laws, including the elimination or postponement of certain key United States federal income tax incentives currently available to oil and natural gas exploration and production companies. These changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and natural gas properties, (ii) the elimination of the current deduction for intangible drilling and development costs, (iii) the elimination of the deduction for certain domestic production activities and (iv) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could become effective. The passage of any legislation as a result of these proposals or any other similar changes in United States federal income tax laws could eliminate certain tax deductions that are currently available with respect to oil and natural gas exploration and development.
Federal and state legislative and regulatory initiatives as well as governmental reviews relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays as well as adversely affect our level of production. Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons from tight formations. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The process is typically regulated by state oil and gas commissions. However, the EPA has asserted federal regulatory authority over certain hydraulic fracturing practices. Also, legislation has been introduced, but not enacted, in Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process. Certain states, including Texas, and municipalities have adopted, or are considering adopting, regulations that have imposed, or that could impose, more stringent permitting, disclosure, disposal and well construction requirements on hydraulic fracturing operations. For example, in December 2011, the Railroad Commission of Texas finalized regulations requiring public disclosure of all the chemicals in fluids used in the hydraulic fracturing process. Local ordinances or other regulations may regulate or prohibit the performance of well drilling in general and hydraulic fracturing in particular. If new laws or regulations that significantly restrict or regulate hydraulic fracturing are adopted, such legal requirements could cause project delays and make it more difficult or costly for us to perform fracturing to stimulate production from a formation. These delays or additional costs could adversely affect the determination of whether a well is commercially viable. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that we are ultimately able to produce in commercial quantities.
In addition, a number of federal agencies are analyzing, or have been requested to review, a variety of environmental issues associated with hydraulic fracturing. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices, and a committee of the United States House of Representatives has conducted an investigation of hydraulic fracturing practices. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with initial results expected to be available by late 2012 and final results by 2014. Moreover, the EPA announced on October 20, 2011 that it is also launching a study regarding wastewater resulting from hydraulic fracturing activities and currently plans to propose standards by 2014 that such wastewater must meet before being transported to a treatment plant. On August 16, 2012, the EPA published final rules under the CAA that, among other things, imposed NSPS standards for completions of hydraulically fractured natural gas wells, requiring the use of reduced emission completion techniques.
In addition, the U.S. Department of Energy is conducting an investigation into hydraulic fracturing practices the agency could recommend to better protect the environment from drilling using hydraulic
fracturing completion methods. Also, the U.S. Department of the Interior is considering disclosure requirements or other mandates for hydraulic fracturing on federal lands. Additionally, certain members of Congress have called upon the U.S. Government Accountability Office to investigate how hydraulic fracturing might adversely affect water resources; the Securities and Exchange Commission (“SEC”) to investigate the natural gas industry and any possible misleading of investors or the public regarding the economic feasibility of pursuing natural gas deposits in shales by means of hydraulic fracturing; and the U.S. Energy Information Administration to provide a better understanding of that agency’s estimates regarding natural gas reserves, including reserves from shale formations, as well as uncertainties associated with those estimates. These ongoing or proposed studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory mechanisms.
Our business exposes us to liability and extensive regulation on environmental matters, which could result in substantial expenditures. Our operations are subject to numerous U.S. federal, state and local laws and regulations relating to the protection of the environment, including those governing the discharge of materials into the water and air, the generation, management and disposal of hazardous substances and wastes and the clean-up of contaminated sites. We could incur material costs, including clean-up costs, fines and civil and criminal sanctions, injunctive relief and third-party claims for property damage and personal injury as a result of violations of, or liabilities under, environmental laws and regulations. Such laws and regulations not only expose us to liability for our own activities, but may also expose us to liability for the conduct of others or for actions by us that were in compliance with all applicable laws at the time those actions were taken. In addition, we could incur substantial expenditures complying with environmental laws and regulations, including future environmental laws and regulations which may be more stringent, for example, the regulation of GHG emissions under the federal CAA, or state or regional regulatory programs. Regulation of GHG emissions by the EPA, or various states in the United States in areas in which we conduct business, could have an adverse effect on our operations and demand for our oil and natural gas production. Moreover, the EPA has shown a general increased scrutiny on the oil and gas industry through its GHG, CAA and SDWA regulations.
On August 16, 2012, the EPA published final rules under the CAA regarding emissions from oil and natural gas operations. The EPA rule subjects oil and natural gas operations to regulation under the NSPS and NESHAPS, programs under the CAA, and imposes new and amended requirements under both programs. The new rules, among other things, amend standards applicable to natural gas processing plants and would expand the NSPS to include all oil and natural gas operations, imposing requirements on those operations. The EPA also imposed NSPS standards for completions of hydraulically fractured natural gas wells, requiring the use of reduced emission completion techniques. The adopted rules allow facilities, in most circumstances until January 1, 2015, to combust natural gas that would escape during completion activities as an alternative to the reduced emission completion techniques. The NESHAPS rules includes MACT standards for certain glycol dehydrators and storage vessels, and revises applicability provisions, alternative test protocols and the availability of the startup, shutdown and maintenance exemption. These new requirements may result in increased operating and compliance costs, increased regulatory burdens and delays in our operations.
The EPA’s implementation of climate change regulations could result in increased operating costs and reduced demand for our oil and natural gas production. Although federal legislation regarding the control of emissions of GHGs, for the present, appears unlikely, the EPA has been implementing regulatory measures under existing CAA authority and some of those regulations may affect our operations. GHGs are certain gases, including carbon dioxide, a product of the combustion of natural gas, and methane, a primary component of natural gas, that may be contributing to the warming of the Earth’s atmosphere, resulting in climatic changes. These GHG regulations could require us to incur increased operating costs and could have an adverse effect on demand for our oil and natural gas production.
On June 3, 2010, the EPA published its so-called GHG tailoring rule that will phase in federal prevention of significant deterioration permit requirements for new sources and modifications, and Title V operating permits for all sources, that have the potential to emit specific quantities of GHGs. Those permitting provisions, should they become applicable to our operations, could require controls or other measures to
reduce GHG emissions from new or modified sources, and we could incur additional costs to satisfy those requirements. On November 30, 2010, the EPA published a rule establishing GHG reporting requirements for sources in the petroleum and natural gas industry, requiring those sources to monitor, maintain records on, and annually report their GHG emissions, with the first annual report for 2011 being due in September 2012. Although this rule does not limit the amount of GHGs that can be emitted, it requires us to incur costs to monitor, record keep and report GHG emissions associated with our operations.
We have identified material weaknesses in our internal control over financial reporting. These material weaknesses, if not corrected, could affect the reliability of our financial statements and have other adverse consequences. Under Section 404 of the Sarbanes-Oxley Act of 2002, we are required to furnish a report by our management on internal control over financial reporting. This report must contain, among other matters, an assessment of the effectiveness of our internal control over financial reporting, including a statement as to whether or not our internal control over financial reporting is effective. This assessment must include disclosure of any material weaknesses in our internal control over financial reporting identified by our management.
We have identified material weaknesses in our internal control over financial reporting as of May 31, 2012 relating primarily to the (i) lack of accounting expertise to appropriately apply GAAP for complex or non-recurring transactions and (ii) lack of sufficient accounting personnel to properly design and implement internal control over financial reporting. Failure to have effective internal controls could lead to a misstatement of our financial statements. If, as a result of deficiencies in our internal controls, we cannot provide reliable financial statements, our business decision process may be adversely affected, our business and operating results could be harmed, investors could lose confidence in our reported financial information, the price of our common shares could decrease and our ability to obtain additional financing, or additional financing on favorable terms, could be adversely affected. In addition, failure to maintain effective internal control over financial reporting could result in investigations or sanctions by regulatory authorities.
We intend to take further action to remediate the material weaknesses and improve the effectiveness of our internal control over financial reporting. However, we can give no assurances that the measures we may take will remediate the material weaknesses identified or that any additional material weaknesses will not arise in the future due to our failure to implement and maintain adequate internal control over financial reporting. In addition, even if we are successful in strengthening our controls and procedures, those controls and procedures may not be adequate to prevent or identify irregularities or ensure the fair presentation of our financial statements included in our periodic reports filed with the SEC.
Our business may suffer if we lose key personnel. We depend to a large extent on the services of our officers, including Alan Barksdale, our President and Chief Executive Officer, Hilda Kouvelis, our Chief Accounting Officer, and Tommy Folsom, Executive Vice President and Director of Exploration and Production for RMR Operating. These individuals have extensive experience and expertise in evaluating and analyzing producing oil and natural gas properties and drilling prospects, maximizing production from oil and natural gas properties and developing and executing financing strategies. Although we have employment agreements with Ms. Kouvelis and Mr. Folsom, we do not currently have an employment agreement with Mr. Barksdale and he is free to terminate his employment with us at any time and compete with us immediately thereafter. The loss of any of these individuals could have a material adverse effect on our operations. We do not maintain key-man life insurance with respect to any management personnel. Our success will be dependent on our ability to continue to retain and utilize skilled technical personnel.
Our officers and directors are engaged in other business activities and conflicts of interest may arise in their daily activities which may not be resolved in our favor. Certain conflicts of interest may exist between us and our officers and directors. Our officers and directors have other business interests to which they devote their attention, and we expect they will continue to do so, although our officers will devote the majority of their business time to our affairs. As a result, conflicts of
interest or potential conflicts of interest may arise from time to time that can be resolved only through the officers or directors exercising such judgment as is consistent with fiduciary duties to their other business interests and to us. These conflicts of interest may not be resolved in our favor.
Compliance with changing regulation of corporate governance and public disclosure will result in additional expenses and pose challenges for our management. Changing laws, regulations and standards relating to corporate governance and public disclosure, including the Dodd-Frank Act and the rules and regulations promulgated thereunder, the Sarbanes-Oxley Act and SEC regulations, have created uncertainty for public companies and significantly increased the costs and risks associated with accessing the U.S. public markets. Our management team will need to devote significant time and financial resources to comply with both existing and evolving standards for public companies, which will lead to increased general and administrative expenses and a diversion of management time and attention from revenue generating activities to compliance activities.
Risks Related to Our Common Stock We may raise additional capital in the future through issuances of securities and such additional funding may be dilutive to shareholders or impose operational restrictions. We may raise additional capital in the future to help fund our operations through sales of shares of our common stock or securities convertible into shares of our common stock, as well as issuances of debt. Such additional financing may be dilutive to our shareholders, and debt financing, if available, may involve restrictive covenants which may limit our operating flexibility, including the ability to pay dividends. If additional capital is raised through the issuances of shares of our common stock or securities convertible into shares of our common stock, the percentage ownership of existing shareholders will be reduced. These shareholders may experience additional dilution in net book value per share and any additional equity securities may have rights, preferences and privileges senior to those of the holders of our common stock.
We do not intend to pay dividends in the future. We have not paid dividends on our common stock and do not intend to pay dividends in the foreseeable future. The payment of cash dividends in the future will be dependent on our revenues and earnings, if any, capital requirements and general financial condition and will be entirely within the discretion of our board of directors at such time. It is the present intention of our board of directors to retain earnings, if any, to fund our future growth, and there is no assurance we will ever pay dividends in the future. As a result, any gain you will realize on our securities will result solely from the appreciation of such securities.
Our articles of incorporation permit us to issue preferred stock that could diminish the rights of holders of our common stock and restrict a takeover attempt that you may favor. Our articles of incorporation permit our board to issue up to 100,000,000 shares of preferred stock and to establish by resolution one or more series of preferred stock and the powers, designations, preferences and participating, optional or other special rights of each series of preferred stock. The preferred stock may be issued on terms that are unfavorable to the holders of our common stock, including the grant of superior voting rights, the grant of preferences in favor of preferred shareholders in the payment of dividends and upon our liquidation and the designation of conversion rights that entitle holders of our preferred stock to convert their shares into our common stock on terms that are dilutive to holders of our common stock. The issuance of preferred stock in future offerings may make a takeover or change in control of us more difficult.
Because we are quoted on the OTC Bulletin Board instead of an exchange or national quotation system, our investors may have more difficulty selling their stock or may experience negative volatility in the market price of our stock. Our common stock is traded on the OTCBB, which is subject to greater volatility than a national exchange or quotation system. This volatility may be caused by a variety of factors, including the lack of readily available price quotations, the absence of consistent administrative supervision of bid and ask quotations, lower trading volume, and market conditions. Investors in our common stock may experience high
fluctuations in the market price and volume of the trading market for our securities. These fluctuations, when they occur, have a negative effect on the market price for our common stock. Accordingly, our stockholders may not be able to realize a fair price from their shares when they determine to sell them or may have to hold them for a substantial period of time until the market for our common stock improves.
Trading in our common stock has been limited, and our stock price could potentially be subject to substantial fluctuations. Trading in our common stock has been limited. Historically, our stock price has been affected substantially by a relatively modest volume of transactions and could be again so affected. If our stock price falls, our stockholders may not be able to sell their stock when desired or at desirable prices.
The value of our common stock might be affected by matters not related to our own operating performance. The value of our common stock may be affected by matters that are not related to our operating performance and which are outside of our control. These matters include the following:
• general domestic and worldwide economic conditions;
• industry conditions, including fluctuations in the price of oil and natural gas;
• governmental regulation of the oil and natural gas industry, including environmental regulation and regulation of fracture stimulation activities;
• liabilities inherent in oil and natural gas operations;
• geological, technical, drilling and processing problems;
• unanticipated operating events which can reduce production or cause production to be shut in or delayed;
• failure to obtain industry partner and other third party consents and approvals, when required;
• stock market volatility and market valuations;
• competition for, among other things, capital, acquisition of reserves, undeveloped land and skilled personnel;
• political conditions in oil and natural gas producing regions;
• revenue and operating results failing to meet expectations in any particular period;
• investor perception of the oil and natural gas industry;
• limited trading volume of our common stock;
• announcements relating to our business or the business of our competitors;
• the sale of assets;
• our liquidity; and
• our ability to raise additional funds.
In the past, companies that have experienced volatility in the trading price of their common stock have been the subject of securities class action litigation. We might become involved in securities class action litigation in the future. Such litigation often results in substantial costs and diversion of management’s attention and resources and could have a material adverse effect on our business, financial condition and results of operation.
Our common stock is subject to penny stock regulation. Our shares are subject to the provisions of Section 15(g) and Rule 15g-9 of the Exchange Act, commonly referred to as the “penny stock” rule, which set forth certain requirements for transactions in penny stocks. The SEC generally defines penny stock to be any equity security that has a market price less than $5.00 per
share, subject to certain exceptions. Rule 3a51-1 provides that any equity security is considered to be penny stock unless that security is: registered and traded on a national securities exchange meeting specified criteria set by the SEC; authorized for quotation on the NASDAQ Stock Market; issued by a registered investment company; excluded from the definition on the basis of price (at least $5.00 per share) or the registrant's net tangible assets; or exempted from the definition by the SEC. Since our shares are deemed to be “penny stock”, trading in the shares will be subject to additional sales practice requirements on broker-dealers who sell penny stock to persons other than established customers and accredited investors.
FINRA Sales Practice requirements may also limit a stockholder's ability to buy and sell our stock. In addition to the “penny stock” rules described above, the Financial Industry Regulatory Authority (“FINRA”) has adopted rules that require that in recommending an investment to a customer, a broker-dealer must have reasonable grounds for believing that the investment is suitable for 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 Not applicable.
Item 2.
Item 2. Properties Our oil and natural gas properties are located in the Permian Basin of West Texas and Southeastern New Mexico and the onshore Gulf Coast of Texas. The following is a map showing the location of our properties as of May 31, 2012.
Summary of Geographic Areas of Operations The following table sets forth summary reserve information attributable to our principal geographic areas of operations as of May 31, 2012.
Permian Basin The following is a description of our properties in the Permian Basin as of May 31, 2012.
Madera Prospect. The Madera Prospect consists of 1,925 gross (1,154 net) acres in Lea County, New Mexico. Our interests in the Madera Prospect include four gross (2.9 net) producing wells with an average working interest of 73.5% and an average net revenue interest of 55.1%. RMR Operating is the operator of the Madera Prospect.
We drilled and completed our first horizontal well, the Madera 24-2H, on the Madera Prospect in January 2012. The well was drilled to a vertical depth of 9,028 feet and a lateral length of 4,620 feet and initially produced at a rate of 1,043 Boe/d, comprised of 86% oil. Consistent with anticipated well performance, during May 2012, the Madera 24-2H averaged 324 Boe/d, comprised of 74% oil. A portion of the other working interest owners elected not to participate in the drilling and completion of the Madera 24-2H well. As a result, we increased our ownership from a 39.7% working interest (29.8% net revenue interest) to a 96.5% working interest (72.4% net revenue interest). Our ownership will revert to a 39.7% working interest (29.8% net revenue interest) when we recover an amount equal to 300% of the costs to drill and complete the well plus operating costs through that date.
The Madera Prospect contains an additional four proved undeveloped locations and two shut-in wells with behind pipe reserves (4.1 net wells) that target the Delaware Sands and Strawn formations. As of May 31, 2012, the Madera Prospect had estimated proved reserves of 996.6 MBoe, of which 821.2 MBoe were proved undeveloped, and had net daily average production for the month of May 2012 of 247 Boe/d. During fiscal 2012, 88% of the revenue from the Madera Prospect was from oil.
Pawnee Prospect. We own oil and natural gas interests in approximately 1,896 gross and (1,766) net acres in the Pawnee Prospect in Lea County, New Mexico, with an average working interest of 100% and an average net revenue interest of 75.1%. This acreage targets the Tansill, Yates and Delaware formations. RMR Operating is the operator of the Pawnee Prospect. We have a total of nine wells on the Pawnee Prospect, seven of which we acquired in December 2011 in exchange for the assumption of the plugging liability. There are six gross and net producing wells, two of which we drilled during fiscal 2012. We completed the Big Brave State #1 well in January 2012 and the Good Chief State #1 well in December 2011, with initial production rates of 52 Boe/d and 28 Boe/d, respectively, consisting of substantially all oil production. Both wells are marginal producers, and we plan to evaluate the wells for potential conversion to salt water disposal wells. As of May 31, 2012, the Pawnee Prospect had estimated proved reserves of 2.7 MBoe and had net daily average production for the month of May 2012 of 7 Boe/d, all of which was oil production.
Cowden Lease. We own oil and natural gas interests in approximately 760 gross (740 net) acres plus 48 acres of surface property in the Cowden Lease in Ector County, Texas. There are 19.0 gross (18.0 net) producing wells on the Cowden Lease with an average working interest of 94.7% and an average net revenue interest of 72.7%. The Cowden Lease is held by production. RMR Operating is the operator of the Cowden Lease. The Cowden Lease is located between the Harper and Donnelly San Andres fields on the Central Basin Platform and produces from the San Andres formation. It has five proved undeveloped drilling locations (five net wells). As of May 31, 2012, the Cowden Lease had estimated proved reserves of 260.7 MBoe, of which 240.9 MBoe were proved undeveloped, and had net daily average production for the month of May 2012 of 11 Boe/d, all of which was oil production.
Shafter Lake Lease. We own oil and natural gas interests in approximately 322 gross (187 net) acres within the Shafter Lake San Andres field in Andrews County, Texas. The Shafter Lake Lease is horizontally severed and is held by production below 4,520 feet. We own all rights from the surface of the land to approximately 4,520 feet below the surface of the land. RMR Operating is the operator of the Shafter Lake Lease. There are three proved undeveloped locations on these leases (1.8 net wells) which target the Grayburg and San Andres formations. We hold a 58.1% working interest and a 39.7% net revenue interest in this acreage. As of May 31, 2012, our Shafter Lake Lease had estimated proved reserves of 71.0 MBoe, all of which were proved undeveloped, and no production.
Martin Lease. We own oil and natural gas interests in approximately 337 gross and net acres in Andrews County, Texas. The Martin Lease is horizontally severed and is held by production above 5,000 feet. We own the deep rights from 5,000 feet below the surface of the land. The target horizons on the Martin Lease are the Clearfork, Grayburg and San Andres formations. We own a 100% working interest and a 75% net revenue interest, and RMR Operating is the operator. As of May 31, 2012, our Martin Lease had no proved reserves or production. In the event we elect to perform operations on this property, RMR Operating will be the operator.
West Ranch Prospect. We own oil and natural gas interests in approximately 878 gross and net acres in Pecos County, Texas. There are multiple target horizons in this prospect. We own a 100% working interest and an 80% net revenue interest, and RMR Operating is the operator. As of May 31, 2012, the West Ranch Prospect had no proved reserves or production.
East Ranch Prospect. We own oil and natural gas interests in approximately 547 gross and net acres in Pecos County, Texas. There are multiple target horizons in this prospect. We own a 100% working interest and an 80% net revenue interest, and RMR Operating is the operator. As of May 31, 2012, the East Ranch Prospect had no proved reserves or production.
Jackson Bough C Prospect. We own oil and natural gas interests in approximately 320 gross (200 net) acres in Lea County, New Mexico. There are multiple target horizons in this prospect. We own a 100% working interest and an 80% net revenue interest, and RMR Operating is the operator. As of May 31, 2012, the Jackson Bough C Prospect had no proved reserves or production.
Onshore Gulf Coast The following is a description of our properties in the onshore Gulf Coast as of May 31, 2012.
Villarreal Prospect. The Villarreal Prospect covers 1,099 gross (153 net) acres in Zapata County, Texas. We own an average working interest of 13.9% and an average net revenue interest of 10.5% in this acreage. We have 15 gross wells on the prospect, 12 of which were producing from the Wilcox formation (1.7 net wells). During fiscal 2012, we elected to participate in all of the drilling operations commenced by ConocoPhillips Company, the operator of the property, consisting of well repairs and the drilling of two new wells. The operator completed one well, which began production in November 2011, and determined not to proceed with the second well because low gas prices made it marginally economic. We incurred total development costs for the Villarreal Prospect of $1.5 million for fiscal 2012. As of May 31, 2012, the Villarreal Prospect had estimated proved reserves of 565.6 MBoe and had net daily average production for the month of May 2012 of 217 Boe/d, all of which was natural gas.
Frost Bank Prospect. The Frost Bank Prospect covers 998 gross (239 net) acres in Duval County, Texas. We own an average working interest of 32.0% and an average net revenue interest of 24.0% in this acreage. There are eight gross wells on the Frost Bank Prospect, five of which are producing (1.6 net wells) from the Wilcox formation and three of which have behind pipe reserves (1.0 net wells). There is one proved undeveloped location. RMR Operating is the operator of the Frost Bank Prospect. As of May 31, 2012, the Frost Bank Prospect had estimated proved reserves of 182.0 MBoe, 98.0% of which are proved non-producing, and had net daily average production for the month of May 2012 of 8 Boe/d, all of which was natural gas.
Resendez and La Duquesa Prospect. The Resendez and La Duquesa Prospect covers 201 gross acres (58 net) in Zapata County, Texas. There are two producing wells (0.7 net wells) from the Wilcox formation and two shut-in wells on the acreage. We own a 23.1% working interest and a 17.3% net revenue interest in the Resendez wells and a 50.1% working interest and a 37.6% net revenue interest in the La Duquesa wells. RMR Operating is the operator of these wells. As of May 31, 2012, the Resendez and La Duquesa Prospect had estimated proved reserves of 3.2 MBoe and had net daily average production for the month of May 2012 of 4 Boe/d, all of which was natural gas.
Title to Properties As is customary in the oil and natural gas industry, we generally conduct a preliminary title examination prior to the acquisition of properties or leasehold interests. Prior to commencement of operations on such acreage, a thorough title examination will usually be conducted and any significant defects will be remedied
before proceeding with operations. We believe the title to our leasehold properties is good, defensible and customary with practices in the oil and natural gas industry, subject to such exceptions that we believe do not materially detract from the use of such properties. With respect to our properties of which we are not the record owner, we rely instead on contracts with the owner or operator of the property or assignment of leases, pursuant to which, among other things, we generally have the right to have our interest placed on record.
Our properties are generally subject to royalty, overriding royalty and other interests customary in the industry, liens incident to agreements, current taxes and other burdens, minor encumbrances, easements and restrictions. We do not believe any of these burdens will materially interfere with our use of these properties. Substantially all of our material properties are pledged as collateral under either our line of credit and senior secured promissory note with First State Bank of Lonoke or our senior secured promissory note with the Lenders.
Summary of Oil and Natural Gas Reserves The following disclosure does not include any reserves attributable to our interests in Cross Border.
Proved Reserves The following table sets forth our estimated net proved reserves as of May 31, 2012.
(1) Prices used are based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the period June 2011 through May 2012. For oil volumes, the average NYMEX posted price of $97.06 per Bbl is adjusted for quality, transportation fees and a regional price differential. For natural gas volumes, the average Henry Hub spot price of $3.34 per Mcf is adjusted for energy content, transportation fees and a regional price differential. The adjusted oil and natural gas prices of $93.05 per barrel and $3.62 per Mcf, respectively, are held constant throughout the lives of the properties.
The following table sets forth our estimated PV-10 and standardized measure of discounted net cash flows as of May 31, 2012.
(1) PV-10 is a non-GAAP financial measure as defined by the SEC. The closest GAAP measure to PV-10 is the standardized measure of discounted net cash flows. The standardized measure differs from PV-10 because standardized measure includes the effect of future income taxes. We believe that the presentation of PV-10 is relevant and useful to our investors as supplemental disclosure to the standardized measure, or after-tax amount, because it presents the discounted future net cash flows attributable to our proved reserves before taking into account future corporate income taxes and our current tax structure. The following table provides a reconciliation of our PV-10 to our standardized measure:
Estimates of proved developed and undeveloped reserves are inherently imprecise and are continually subject to revision based on production history, results of additional exploration and development, price changes and other factors. See “- Qualifications of Technical Persons and Internal Controls Over Reserves Estimation Process.”
At May 31, 2012, our estimated proved reserves were 2,082 MBoe, a decrease of 19.5% compared to 2,586 MBoe at May 31, 2011. During fiscal 2012, we added estimated proved reserves of 338 MBoe through our acquisitions, which were offset by production of 176 MBoe and downward revisions in previous estimates of 666 MBoe. The downward revisions were primarily comprised of 453 MBoe due to the removal of two proved undeveloped locations from the reserve report because we determined those wells would not be drilled based upon current gas prices and 151 MBoe due to lower production than expected from two new wells.
Proved Undeveloped Reserves Our proved undeveloped reserves at May 31, 2012 were 1,196 MBoe, consisting of 842 MBbls of oil and 2,126 MMcf of natural gas. During fiscal 2012, we converted 156 MBoe of proved undeveloped reserves to proved developed producing reserves, primarily due to the completion of the Madera 24-2H well and the completion of one well on the Villarreal Prospect. As of May 31, 2012, estimated future development costs relating to the development of our proved undeveloped reserves was $27.2 million. All of our currently identified proved undeveloped reserves are scheduled to be drilled by May 31, 2015.
Qualifications of Technical Persons and Internal Controls Over Reserves Estimation Process Our reserve reports were prepared by Forrest A. Garb & Associates, Inc. (“Garb”), and Lee Engineering, each independent petroleum engineers. Garb estimated, in accordance with petroleum engineering and evaluation principles set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserve Information promulgated by the Society of Petroleum Engineers (“SPE Standards”) and definitions and guidelines established by the SEC, 100% of the proved reserve information for our onshore Gulf Coast properties as of May 31, 2012. Lee Engineering estimated, in accordance with SPE Standards and definitions and guidelines established by the SEC, 100% of the proved reserve information for our Permian Basin properties as of May 31, 2012.
The technical persons responsible for preparing the reserves estimates presented herein meet the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Natural Gas Reserves Information promulgated by the Society of Petroleum Engineers.
The principal person at Garb who prepared the reserve report for the Company is William D. Harris III, P.E., who joined Garb in August 1998 and is now the Chief Executive Officer. Previously, he was a Vice President with DeGolyer and MacNaughton where he prepared and supervised engineering studies and reserve and appraisal reports for fields in many countries. Mr. Harris holds a B.S. in Petroleum Engineering from Texas A&M University and a M.B.A. from Southern Methodist University. He is a member of the Society of Petroleum Engineers and is a registered professional engineer in the State of Texas.
The principal person at Lee Engineering who prepared the reserve report for the Company is Robert Lee. Mr. Lee has 32 years of experience as a qualified reserve estimator and/or auditor and has been an independent consultant with Lee Engineering since 1996. Mr. Lee holds a B.S. in Petroleum Engineering from the University of Missouri-Rolla. He is a member of the Society of Petroleum Engineers and is a registered professional engineer in the State of Texas.
We have an internal staff of geoscience professionals who work closely with our independent petroleum engineers to ensure the integrity, accuracy and timeliness of data furnished to them in their reserves estimation process. Our technical team consults regularly with representatives of Garb and Lee Engineering. We review with them our properties and discuss methods and assumptions used in their preparation of our fiscal year-end reserves estimates. While we have no formal committee specifically designated to review reserves reporting and the reserves estimation process, a copy of each of the Garb and Lee Engineering reserve reports is reviewed with representatives of Garb and Lee Engineering and our internal technical staff before we
disseminate any of the information. Additionally, our senior management reviews and approves the Garb and Lee Engineering reserve reports and any internally estimated significant changes to our proved reserves on an annual basis.
Estimates of oil and natural gas reserves are projections based on a process involving an independent third party engineering firm’s collection of all required geologic, geophysical, engineering and economic data, and such firm’s complete external preparation of all required estimates and are forward-looking in nature. These reports rely upon various assumptions, including assumptions required by the SEC, such as constant oil and natural gas prices, operating expenses and future capital costs. The process also requires assumptions relating to availability of funds and timing of capital expenditures for development of our proved undeveloped reserves. These reports should not be construed as the current market value of our reserves. The process of estimating oil and natural gas reserves is also dependent on geological, engineering and economic data for each reservoir. Because of the uncertainties inherent in the interpretation of this data, we cannot be certain that the reserves will ultimately be realized. Our actual results could differ materially. See “Note 17 - Supplemental Information Relating to Oil and Natural Gas Producing Activities (Unaudited)” to our audited consolidated financial statements for additional information regarding our oil and natural gas reserves.
Under SEC rules, proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil and/or natural gas actually recovered will equal or exceed the estimate. To achieve reasonable certainty, Garb and Lee Engineering employ technologies consistent with the standards established by the Society of Petroleum Engineers. The technologies and economic data used in the estimation of our proved reserves include, but are not limited to, well logs, geologic maps and available downhole and production data, seismic data and well test data.
Summary of Oil and Natural Gas Properties and Projects Production, Price and Cost History The following table presents net production sold, average sales prices and production costs and expenses for the fiscal years ended May 31, 2012 and 2011.
(1) The Madera Prospect had net production sold of 46,162 Boe and 0 Boe for the fiscal years ended May 31, 2012 and 2011, respectively. The Villarreal Prospect had net production sold of 115,816 Boe and 144,922 Boe for the fiscal years ended May 31, 2012 and 2011, respectively.
Developed and Undeveloped Acreage The following table presents our total gross and net developed and undeveloped acreage by region as of May 31, 2012:
(1) “Gross” means the total number of acres in which we have a working interest.
(2) “Net” means the sum of the fractional working interests that we own in gross acres.
The primary terms of our oil and natural gas leases expire at various dates. Much of our developed acreage is held by production, which means that these leases are active as long as we produce oil or natural gas from the acreage or comply with certain lease terms. Upon ceasing production, these leases will expire. The following table summarizes by year our gross and net undeveloped acreage scheduled to expire in the next five years.
(1) “Gross” means the total number of acres in which we have a working interest.
(2) “Net” means the sum of the fractional working interests that we own in gross acres.
Productive Wells The following table presents the total gross and net productive wells by area and by oil or natural gas completion as of May 31, 2012:
(1) “Gross” means the total number of wells in which we have a working interest.
(2) “Net” means the sum of the fractional working interests that we own in gross wells.
Drilling Activity The following table summarizes the number of net productive and dry development wells and net productive and dry exploratory wells we drilled during the periods indicated and refers to the number of wells completed during the period, regardless of when drilling was initiated. At May 31, 2012, we had no wells being drilled and one gross (0.14 net) well awaiting completion on our Villarreal Prospect.
Item 3.
Item 3. Legal Proceedings We are not a party to, and none of our properties are the subject of, any material pending legal proceedings, nor are we aware of any material legal proceedings contemplated by any government authority.
Item 4.
Item 4. Mine Safety Disclosures Not applicable.
PART II
Item 5.
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Market Price for Our Common Stock Our common stock is quoted on the OTCBB under the symbol “RDMP.” The following table sets forth the range of high and low bid prices for our common stock for the periods indicated since the common stock commenced public trading on September 16, 2010. The over-the-counter market quotations reflect inter-dealer prices, without retail mark-up, mark-down or commission and may not necessarily represent actual transactions.
* Commencing on September 16, 2010.
Holders As of August 31, 2012, there were approximately 300 beneficial holders of our common stock.
Dividends We have not paid any cash dividends on our common stock to date. The payment of any dividends is within the discretion of our Board of Directors. It is the present intention of the Board of Directors to retain all earnings, if any, for use in the business operations and, accordingly, the Board does not anticipate declaring any dividends in the foreseeable future. The payment of dividends in the future, if any, will be contingent upon our revenues and earnings, if any, capital requirements and our general financial condition.
Sales of Unregistered Securities We have not made any sales of unregistered securities during the fiscal year ended May 31, 2012 that was not disclosed previously in a Quarterly Report on Form 10-Q or in a Current Report on Form 8-K, except as follows:
In November 2011, we issued 200,000 shares of our common stock to a broker as payment for a fee related to obtaining the $4.0 million loan from the Lenders. These shares were issued in reliance upon an exemption from registration under Section 4(2) of the Securities Act of 1933, as amended, as the shares were issued to a sophisticated investor with such knowledge and experience in financial and business matters that such broker was capable of evaluating the merits and risks of the investment. No underwriting discounts or commissions were paid with respect to the foregoing issuances.
On December 30, 2011, we entered into a consulting agreement with St. Bernard Financial Services, Inc. In connection with the agreement we paid the consultants $100,000 in cash and issued them 100,000 shares of common stock. These shares were issued in reliance upon an exemption from registration under Section 4(2) of the Securities Act of 1933, as amended, as the shares were issued to a sophisticated investor with such knowledge and experience in financial and business matters that it was capable of evaluating the merits and risks of the investment.
Item 6.
Item 6. Selected Financial Data Not applicable.
Item 7.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and the related notes to those statements included elsewhere in this Annual Report on Form 10-K. In addition to historical financial information, the following discussion and analysis contains forward-looking statements that involve risks, uncertainties and assumptions. Our results and the timing of selected events may differ materially from those anticipated in these forward-looking statements as a result of many factors, including those discussed under “Risk Factors” and elsewhere in this Annual Report on Form 10-K.
Overview We are a growth-oriented energy company engaged in the acquisition, development and exploration of oil and natural gas properties in established basins with demonstrable prolific producing zones. Currently, we have established acreage positions and production in the Permian Basin of West Texas and Southeast New Mexico and the onshore Gulf Coast of Texas. Our focus is to grow production and reserves by acquiring and developing an inventory of long-life, low risk drilling opportunities in and around producing oil and natural gas properties.
During fiscal 2012, we derived 54.4% of our revenue from the Madera Prospect in the Permian Basin and 37.0% of our revenue from the Villarreal Prospect in the onshore Gulf Coast of Texas. During fiscal 2012, we derived approximately 54.2% of our revenue from the sale of oil and approximately 45.8% of our revenue from the sale of natural gas.
As of August 31, 2012, we owned approximately 45.9% of the outstanding common stock of Cross Border. As of March 31, 2012, Cross Border had approximately 868,000 gross (295,000 net) acres, of which 26,000 net acres were located in the Permian Basin. The following disclosures about our financial results do not include Cross Border’s financial results.
History Red Mountain was originally formed in January 2010 as Teaching Time, Inc. in order to design, develop, and market instructional products and services for the corporate, education, government, and healthcare e-learning industries. In March 2011, Teaching Time, Inc. determined to enter into oil and natural gas exploration, development and production and changed its name to Red Mountain Resources, Inc. to better reflect that plan. On March 22, 2011, we entered into a Share Exchange Agreement with Black Rock Capital, LLC and StoneStreet, the sole shareholder of Black Rock Capital, LLC. Alan W. Barksdale, our current President, Chief Executive Officer and Chairman of the Board, was the president and the sole member of Black Rock Capital, LLC and the sole owner and the president of StoneStreet. On June 22, 2011, we completed a reverse merger pursuant to the Share Exchange Agreement in which we issued 27,000,000 shares of common stock to StoneStreet in exchange for 100% of the interests in Black Rock Capital, LLC. Concurrently with the closing, we retired 225,000,000 shares of common stock for no additional consideration. In connection with the reverse merger, the management of Black Rock Capital, LLC became our management.
While we were the legal acquirer in the reverse merger, Black Rock Capital, LLC was treated as the accounting acquirer and the transaction was treated as a recapitalization. As a result, at the closing, the historical financial statements of Black Rock became those of the Company.
From inception through May 2010, Black Rock had no operations. Effective June 1, 2010, Black Rock purchased two separate oil and natural gas fields out of the bankruptcy estate of MSB Energy, Inc. located in Zapata County and Duval County in the onshore Gulf Coast of Texas. Effective May 31, 2011, Black Rock acquired our current interests in the Madera Prospect. Effective July 1, 2011, Black Rock Capital, LLC was converted to Black Rock Capital, Inc., and our 100% membership interest in Black Rock Capital, LLC became an interest in all of the outstanding common stock of Black Rock.
Recent Acquisitions In April and August 2012, we acquired oil and natural gas interests in approximately 320 gross and net acres in the Jackson Bough C Prospect in Lea County, New Mexico for cash consideration of $66,000. We own a 100% working interest and an 80% net revenue interest in this property.
In April 2012, we acquired oil and natural gas interests in approximately 547 gross and net acres in the East Ranch Prospect in Pecos County, Texas for cash consideration of $421,000. In April 2012, we also acquired oil and natural gas interests in 878 gross and net acres in the West Ranch Prospect in Pecos County, Texas for cash consideration of $677,000. We own a 100% working interest and an 80% net revenue interest in these properties.
During fiscal 2012, we made multiple acquisitions of oil and natural gas leases in the Pawnee Prospect totaling 2,215 gross acres (2,045 net) and seven wellbores in Lea County, New Mexico in the Permian Basin for aggregate cash consideration of $729,000 and the assumption of plugging liabilities of $166,000.
In November 2011, we acquired 760 gross (740 net) acres plus 48 acres of surface property in the Cowden Lease located in Ector County, Texas for $1.2 million. We acquired a 100% working interest with a 75.0% net revenue interest in two leases covering 640 gross and net acres; a 100% working interest with a 79.4% net revenue interest in one lease covering 40 acres; and a 75.0% working interest with a 62.8% net revenue interest in one lease covering 80 acres. At acquisition, the Cowden Lease contained 17 producing wells.
In August 2011, we acquired a 58.1% working interest with a 39.7% net revenue interest in the Shafter Lake Lease for $0.3 million in cash and 250,000 shares of our common stock. The Shafter Lake Lease is approximately 322 gross (187 net) acres located in Andrews County, Texas.
In the aggregate, production from these acquired properties during fiscal 2012 accounted for 3.8 Mboe, or 2%, of our production and $0.4 million, or 6.2%, of our total oil and natural gas sales.
Significant Fiscal 2012 Operations In January 2012, we drilled and completed our first horizontal well, the Madera 24-2H, on the Madera Prospect at a cost of $5.6 million. The well was drilled to a vertical depth of 9,028 feet and a lateral length of 4,620 feet and initially produced at a rate of 1,043 Boe/d, comprised of 86% oil. Consistent with anticipated well performance, during May 2012, the Madera 24-2H well averaged 342 Boe/d, comprised of 74% oil. A portion of the other working interest owners elected not to participate in the drilling and completion of the Madera 24-2H well. As a result, we increased our ownership from a 39.7% working interest (29.8% net revenue interest) to a 96.5% working interest (72.4% net revenue interest). Our ownership will revert to its original interest when we recover an amount equal to 300% of the costs to drill and complete the well plus operating costs through that date. During fiscal 2012, we produced 37.9 MBoe from the Madera 24-2H well and generated $3.3 million of revenue.
We completed the Big Brave State #1 well in January 2012 and the Good Chief State #1 well in December 2011 on the Pawnee Prospect at a cost of $5.1 million. The Big Brave State #1 well and the Good Chief State #1 well had initial production rates of 52 Boe/d and 28 Boe/d, respectively, consisting of substantially all oil production. Both wells are marginal producers, and we plan to evaluate the wells for potential conversion to salt water disposal wells.
During fiscal 2012, we elected to participate in all of the drilling operations on the Villarreal Prospect commenced by ConocoPhillips Company, the operator of the property, consisting of well repairs plus the drilling of two new wells. The operator completed one well, which began production in November 2011, and determined not to proceed with the second well because low gas prices made it marginally economic. We incurred total development costs for the Villarreal Prospect of $1.5 million for fiscal 2012.
Planned Operations We plan to spend between $25.0 million and $30.0 million during fiscal 2013 to drill and complete wells or re-enter and complete wells, most of which will be spent in the Permian Basin. Our primary focus is on the Madera Prospect where we plan to drill up to six wells (3.6 net wells) and on the Cowden Prospect where we plan to drill up to three gross and net wells during fiscal 2013. We also plan to drill one gross and net well on the Jackson Bough C Prospect and one gross and net well on the East and West Ranch Prospects. We currently believe that cash on hand and cash flow from operations will not be sufficient to fund our fiscal 2013 development program and are seeking funding from third parties. If we do not raise additional funds, we may be required to curtail our fiscal 2013 development program.
Critical Accounting Policies and Estimates Our discussion and analysis of our financial condition and results of operations is based upon our consolidated financial statements, which have been prepared in accordance with U.S. generally accepted accounting principles (“GAAP”). The preparation of these consolidated financial statements requires management to make estimates and judgments that affect the reported amounts of assets, liabilities, revenue and expenses, and related disclosures. Our significant accounting policies are described in “Note 3 - Significant Accounting Policies” to our consolidated financial statements included in this Annual Report on Form 10-K. We have identified below policies that are of particular importance to the portrayal of our financial position and results of operations and which require the application of significant judgment by management. These estimates are based on historical experience, information received from third parties, and on various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates under different assumptions or conditions.
We believe the following critical accounting policies affect the significant judgments and estimates used in the preparation of our consolidated financial statements.
Oil and Gas Properties Effective June 1, 2011, we follow the successful efforts method of accounting for our oil and natural gas producing activities. The change in accounting principle has been applied retroactively to prior periods. Costs to acquire mineral interests in oil and natural gas properties and to drill and equip development wells and related asset retirement costs are capitalized. Costs to drill exploratory wells are capitalized pending determination of whether the wells have proved reserves. If we determine that the wells do not have proved reserves, the costs are charged to expense. There were no exploratory wells capitalized pending determination of whether the wells have proved reserves at May 31, 2012 or 2011. Geological and geophysical costs, including seismic studies and costs of carrying and retaining unproved properties, are charged to expense as incurred. We capitalize interest on expenditures for significant exploration and development projects that last more than six months while activities are in progress to bring the assets to their intended use. Through May 31, 2012, we had capitalized no interest costs because our exploration and development projects generally lasted less than six months. Costs incurred to maintain wells and related equipment are charged to expense as incurred.
On the sale or retirement of a complete unit of a proved property, the cost and related accumulated depreciation, depletion and amortization are eliminated from the property accounts, and the resultant gain or loss is recognized. On the retirement or sale of a partial unit of proved property, the cost is charged to accumulated depreciation, depletion and amortization, with a resulting gain or loss recognized in income.
Capitalized amounts attributable to proved oil and natural gas properties are depleted by the unit-of-production method over proved reserves using the unit conversion ratio of six Mcf of natural gas to one Boe. The ratio of six Mcf of natural gas to one Boe is based on energy equivalency, rather than price equivalency. Given current price differentials, the price for a Boe for natural gas differs significantly from the price for a barrel of oil.
It is common for operators of oil and natural gas properties to request that joint interest owners pay for large expenditures, typically for drilling new wells, in advance of the work commencing. This right to call for cash advances is typically found in the operating agreement that joint interest owners in a property adopt. We record these advance payments in prepaid and other current assets in its property account and release this account when the actual expenditure is later billed to it by the operator.
On the sale of an entire interest in an unproved property for cash or cash equivalents, gain or loss on the sale is recognized, taking into consideration the amount of any recorded impairment if the property had been assessed individually. If a partial interest in an unproved property is sold, the amount received is treated as a reduction of the cost of the interest retained.
Impairment of Long-Lived Assets We evaluate our long-lived assets for potential impairment in their carrying values whenever events or changes in circumstances indicate such impairment may have occurred. Oil and natural gas properties are evaluated for potential impairment by field. Other properties are evaluated for impairment on a specific asset basis or in groups of similar assets, as applicable. An impairment on proved properties is recognized when the estimated undiscounted future net cash flows of an asset are less than its carrying value. If an impairment occurs, the carrying value of the impaired asset is reduced to its estimated fair value, which is generally estimated using a discounted cash flow approach. If the results of an assessment indicate that the properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized.
Unproved oil and natural gas properties do not have producing properties. As reserves are proved through the successful completion of exploratory wells, the cost is transferred to proved properties. The cost of the remaining unproved basis is periodically evaluated by management to assess whether the value of a property has diminished. To do this assessment, management considers estimated potential reserves and future net revenues from an independent expert, our history in exploring the area, our future drilling plans per our capital drilling program prepared by our reservoir engineers and operations management and other factors associated with the area. Impairment is taken on the unproved property cost if it is determined that the costs are not likely to be recoverable. The valuation is subjective and requires management to make estimates and assumptions which, with the passage of time, may prove to be materially different from actual results.
Recent Accounting Pronouncements In May 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2011-04, Fair Value Measurements (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs (“ASU 2011-04”). ASU 2011-04 changes the wording used to describe many of the requirements in GAAP for measuring fair value and for disclosing information about fair value measurements to ensure consistency between GAAP and International Financial Reporting Standards (“IFRS”). ASU 2011-04 also expands the disclosures for fair value measurements that are estimated using significant unobservable (Level 3) inputs. This new guidance is to be applied prospectively. ASU 2011-04 became effective for interim and annual periods beginning after December 15, 2011. The adoption of this amendment did not have a material impact on our consolidated financial statements.
On June 16, 2011, the FASB issued ASU No. 2011-05 Comprehensive Income (Topic 220): Presentation of Comprehensive Income (“ASU 2011-05”). ASU 2011-05 requires entities to report items of other comprehensive income on either part of a single contiguous statement of comprehensive income or in a separate statement of comprehensive income immediately following the statement of income. On December 23, 2011, the FASB issued an update to this pronouncement, ASU No. 2011-12 Comprehensive Income (Topic 220): Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05. The update defers the specific requirement to present items that are reclassified from accumulated other comprehensive income to net income separately with their respective components of net income and other comprehensive income. While early adoption is permitted, the amendments are effective for fiscal years, and interim periods within those years, beginning after December 15, 2011 and must be applied retrospectively. Presently, we do not have any transactions which require the reporting of comprehensive income; therefore, we do not anticipate any material impact from this pronouncement.
On December 16, 2011, the FASB issued ASU No. 2011-11 Balance Sheet (Topic 210), Disclosures about Offsetting Assets and Liabilities (“ASU 2011-11”). ASU 2011-11 requires entities to disclose both gross information and net information about both instruments and transactions eligible for offset in the statement of financial position and instruments and transactions subject to an agreement similar to a master netting arrangement. Application of ASU 2011-11 is required for annual reporting periods beginning on or after January 1, 2013 and interim periods within those annual periods. We do not expect the adoption of this amendment to have a material impact on our consolidated financial statements.
Results of Operations Fiscal Year Ended May 31, 2012 Compared to Fiscal Year Ended May 31, 2011 The following table sets forth summary information regarding our oil and natural gas sales, net production sold, average sales prices and production costs and expenses for the fiscal years ended May 31, 2012 and 2011.
(1) Boe/d is calculated based on actual calendar days during the period.
Revenues and Production Oil and Natural Gas Production. During the fiscal year ended May 31, 2012, we had total production of 169,614 Boe, compared to total production of 150,055 Boe during the fiscal year ended May 31, 2011. The increase in total production was primarily attributable to completion of the Madera 24-2H well on the Madera Prospect, partially offset by lower natural gas production. For the fiscal year ended May 31, 2012, 21.8% of our production was oil and 78.2% was natural gas, compared to 100% natural gas for the fiscal year ended May 31, 2011.
Oil and Natural Gas Sales. During the fiscal year ended May 31, 2012, we had oil and natural gas sales of $6.3 million, as compared to $3.7 million during the fiscal year ended May 31, 2011. The increase in oil and natural gas sales was primarily attributable to 46.1 MBoe of production from the Madera Prospect partially offset by lower natural gas production and lower average prices for natural gas sales. For fiscal 2011, we had no oil production.
Costs and Expenses Exploration Expense. Exploration expense was $0.3 million for the fiscal year ended May 31, 2012, as compared to no exploration expense for the fiscal year ended May 31, 2011. Exploration expense increased due to $0.1 million of expired leases and $0.2 million of other well data and evaluation costs.
Production Taxes. Production taxes were $0.4 million for the fiscal year ended May 31, 2012, as compared to $0.2 million for the fiscal year ended May 31, 2011. The increase in production taxes was attributable to increased production from the Madera and Pawnee Prospects and the Cowden Lease.
Lease Operating Expenses. During the fiscal year ended May 31, 2012, we incurred lease operating expenses of $0.9 million, as compared to $0.2 million during the fiscal year ended May 31, 2011. The increase in lease operating expenses was attributable to our acquisition of the Madera and Pawnee Prospects and the Cowden Lease.
Natural Gas Transportation and Marketing Expenses. For the fiscal year ended May 31, 2012, natural gas transportation and marketing expenses was $0.2 million, as compared to $0.2 million for the fiscal year ended May 31, 2011.
Depreciation, Depletion, Amortization and Impairment. For the fiscal year ended May 31, 2012, depreciation, depletion, amortization and impairment was $5.1 million, as compared to $0.7 million for the fiscal year ended May 31, 2011. The increase in depreciation, depletion, amortization and impairment was attributable to increased production, oil and natural gas property additions, and $1.0 million of impairment on the Pawnee Prospect primarily due to a decline in the reserves and production associated with our Pawnee wells.
General and Administrative Expense. General and administrative expense was $6.2 million for the fiscal year ended May 31, 2012, as compared to $0.3 million for the fiscal year ended May 31, 2011. The increase in general and administrative expense for the fiscal year ended May 31, 2012 was due primarily to $2.9 million of acquisition-related due diligence and transaction costs as well as expenditures related to the reverse merger and creation of company infrastructure. We incurred $3.3 million of personnel, office and public company expenses as compared to $0.3 million for the year ended May 31, 2011.
Other Expense. Other expense was $5.6 million for the fiscal year ended May 31, 2012, as compared to other income of $0.7 million for the fiscal year ended May 31, 2011. The increase in other expense was primarily attributable to increased interest expense due to $6.7 million aggregate principal amount of promissory notes and $2.75 million aggregate principal amount of convertible promissory notes issued during fiscal 2012, a $2.7 million loss on note receivable due to the uncertainty of collection of the note receivable and a $0.8 million change in fair value of warrant liability due to an increase in the price of our common stock at the time of exercise of certain warrants.
Liquidity and Capital Resources General Our primary sources of liquidity are cash flow from operations, borrowings under our line of credit and promissory notes and the issuance of convertible notes and common stock. Our ability to fund planned capital expenditures and to make acquisitions depends upon our future operating performance, availability of borrowings under our line of credit and availability of equity and debt financing, which is affected by prevailing economic conditions in our industry and financial, business and other factors, some of which are beyond our control. Our cash flow from operations is mainly influenced by the prices we receive for our oil and natural gas production and the quantity of oil and natural gas we produce. Prices for oil and natural gas are affected by national and international economic and political conditions, national and global supply and demand for hydrocarbons, seasonal weather influences and other factors beyond our control.
Capital Expenditures Most of our capital expenditures are for the exploration, development, production and acquisition of oil and natural gas reserves. For fiscal 2012, we had capital expenditures of $17.6 million for the acquisition and exploration of oil and natural gas properties and $0.6 million for other property and equipment. We anticipate capital expenditures of between $25.0 million and $30.0 million for fiscal 2013. See “- Planned Operations” for more information about our planned capital expenditures.
Liquidity At May 31, 2012, we had $0.2 million in cash and cash equivalents, $8.1 million outstanding under various promissory notes and $2.75 million outstanding under various convertible promissory notes. At May 31, 2012, we had a working capital deficit of $10.4 million compared to a working capital deficit of $10.4 million at May 31, 2011.
We currently do not have sufficient funds to continue operations beyond November 16, 2012, the maturity date of our senior secured promissory note with the Lenders, or sooner if First State Bank of Lonoke demands payment under either our line of credit or promissory note. We are exploring available financing options, including the sale of debt or equity. If we are unable to finance our operations on acceptable terms or at all, our business, financial condition and results of operations may be materially and adversely affected.
Financings Black Rock issued an unsecured promissory note dated March 4, 2011 to Capital Growth Investment Trust, a shareholder of the Company, in the principal amount of $90,000. The promissory note accrued interest at 3.25% per annum and, in May 2011, Black Rock repaid the promissory note in full.
Black Rock issued an unsecured promissory note dated March 4, 2011, as amended September 28, 2011, to Robert Hersov, an unaffiliated lender, in the principal amount of $150,000. The proceeds from the promissory note were used to fund Black Rock's acquisition of the Madera Prospect. The promissory note, as amended, accrued interest at 3.25% per annum and matured on November 30, 2011.
We issued an unsecured promissory note to Robert Hersov in February 2011, as amended in September 2011, and to Fiordaliso Investments Limited and Capital Growth Investment Trust in March and April 2011, in an aggregate principal amount of $212,500. Fiordaliso Investments Limited and Capital Growth Investment Trust were shareholders of the Company and Robert Hersov was an unaffiliated lender. The proceeds from the promissory note were used to fund working capital. The promissory notes, as amended, accrued interest at 10.0% per annum and matured on November 30, 2011.
We issued an unsecured promissory note dated May 24, 2011, as amended in September 2011, to each of Michael J. Garnick, Bel-Cal Properties and William F. Miller, III, each an unaffiliated lender, in an aggregate principal amount of $2,450,000. These promissory notes, as amended, accrued interest at 10% per annum and matured on November 30, 2011. As a condition for issuing the promissory notes, on November 16, 2011, we issued an aggregate of 600,000 shares of our common stock to Mr. Garnick, Bel-Cal Properties and Mr. Miller. The proceeds from the promissory notes were used to purchase a portion of the Cross Border units and shares. In July and August 2011, Black Rock repaid a portion of the amounts owed under the promissory notes held by Mr. Garnick, Bel-Cal Properties and Mr. Miller. On October 25, 2011, Mr. Garnick entered into a new 10% convertible note providing for the remaining $200,000 owed to him to be due on April 15, 2013 and cancelled the old promissory note.
On November 30, 2011, we repaid in full all the remaining principal and interest related to the promissory notes payable to Mr. Hersov, Fiordaliso Investments Limited, Capital Growth Investment Trust, Bel-Cal Properties and Mr. Miller, and the convertible note issued to Mr. Garnick, which amounted to $1.4 million.
On June 29, 2011, in connection with the reverse merger, Black Rock, Mr. Barksdale and Mr. Bartlett issued a $2.7 million promissory note to First State Bank of Lonoke, which accrues interest at a rate of 6% per annum. If First State Bank of Lonoke declares a default, interest will accrue on the principal at a rate of 18%. The promissory note is payable on demand, or if no demand is made, must be paid on June 29, 2014. In addition, we must make a principal payment of $540,000 on June 29, 2013. The note may be prepaid at any time without penalty.
On September 15, 2011, we borrowed $100,000, interest free, from StoneStreet Operating Company, LLC (“StoneStreet Operating”) for working capital purposes, and the loan was repaid in full on September 26, 2011. On October 19, 2011, we borrowed an additional $180,000, interest free, from StoneStreet Operating for working capital purposes, and the loan was repaid in full on October 26, 2011.
Beginning March 2011, we commenced a private placement of common stock at a price of $1.00 per share, which terminated in November 2011. We sold an aggregate of 16,206,000 shares of common stock raising gross proceeds of $16.2 million. As of May 31, 2012, we had used approximately $6.9 million of the net proceeds for the Madera Prospect, Pawnee Prospect, Shafter Lake Lease and Cowden Lease acquisitions, approximately $3.4 million of the net proceeds for the acquisition of shares of Cross Border common stock, and approximately $1.6 million to fund our ongoing drilling program. In connection with the private placement, we granted three investors each the right to purchase an additional $3.0 million worth of shares of our common stock. In December 2011, one of these investors fully exercised its right to purchase 2,727,272 shares of common stock at $1.10 per share, raising gross cash proceeds of $3.0 million. During February, March and April 2012, the other two investors (and their assignees) exercised their rights to purchase 4,310,818 shares of common stock at $1.10 per share, raising gross cash proceeds of $4.7 million. We used the proceeds from the option exercises for working capital purposes.
We issued a senior secured promissory note dated November 16, 2011 to Hyman Belzberg, William Belzberg and Caddo Management, Inc. in an aggregate principal amount of $4.0 million. Upon issuance of the promissory note, the Lenders advanced $0.5 million to us. Upon perfection of the Lenders’ security interest in the collateral for the promissory note, the Lenders advanced to us the remaining $3.5 million for the acquisition of the Cowden Lease and to fund drilling expenditures on the Madera Prospect. The senior secured promissory note accrues interest at a rate of 12% per annum, payable monthly, and matures on the earlier of November 16, 2012 or the date the senior secured promissory note is terminated, whether by its terms, by prepayment or by acceleration.
We issued a convertible promissory note dated November 25, 2011 to Personalversorge der Autogrill Schweiz AG in the principal amount of $1.5 million and to Hohenplan Privatstiftung in the principal amount of $1.0 million. We also issued a convertible promissory note dated November 30, 2011 to SST Advisors, Inc. in the principal amount of $250,000. We used the proceeds to pay off the promissory notes payable to Mr. Hersov, Fiordaliso Investments Limited, Capital Growth Investment Trust, Mr. Garnick, Bel-Cal Properties and Mr. Miller on November 30, 2011, and for working capital purposes. The convertible promissory notes are due and payable on November 25, 2013 and bear interest at the rate of 10% per annum.
We issued a convertible promissory note dated July 30, 2012 in the principal amount of $1.0 million to Hohenplan Privatstiftung. The promissory note accrues interest at a fixed rate of 10% per annum. The entire principal amount of the promissory note together with accrued but unpaid interest is due on July 30, 2013, subject to a 12-month extension at the holder’s option.
Cash Flows Net cash used in operating activities was $1.2 million for the fiscal year ended May 31, 2012, compared to net cash provided by operating activities of $1.7 million for the fiscal year ended May 31, 2011. The decrease in net cash provided by operating activities was primarily due to a $12.4 million loss, partially offset by $5.1 million of non-cash depreciation, depletion, amortization and impairment, $1.4 million of amortization of debt issuance costs, $0.8 million of loss on warrant liability, and a $2.7 million loss on notes receivable.
Net cash used in investing activities increased to $18.3 million for the fiscal year ended May 31, 2012 from $3.6 million for the fiscal year ended May 31, 2011 due to an increase in capital expenditures, primarily for the continued development of our oil and natural gas properties and for the acquisitions of the Pawnee Prospect, Shafter Lake Lease and Cowden Lease.
During the fiscal year ended May 31, 2012, net cash provided by financing activities was $19.5 million, as compared to $2.0 million during the fiscal year ended May 31, 2011. Net cash provided by financing activities during the fiscal year ended May 31, 2012 was primarily comprised of $16.4 million net proceeds from the issuance of our common stock, $4.5 million of net proceeds from the issuances of notes payable and under our line of credit, and $2.5 million proceeds from convertible notes payable, partially offset by $3.8 million of payments on notes payable.
Indebtedness Line of Credit with First State Bank On June 18, 2010, Black Rock, Mr. Barksdale and Ernest Bartlett, the managing member of a shareholder of the Company, entered into a three year, $3.5 million line of credit with First State Bank of Lonoke. Loans borrowed under the line of credit accrue interest at the bank’s reference rate plus 275 basis points (6% at May 31, 2012) and are payable on demand, or if no demand is made, mature on June 18, 2013. The line of credit is secured by a lien against (i) our Villarreal, Frost Bank, Resendez and La Duquesa properties, (ii) 2,136,164 shares of Cross Border common stock owned by us and (iii) certain property owned by Mr. Bartlett. As co-signers, Mr. Barksdale and Mr. Bartlett are personally obligated for the repayment of borrowings under this line of credit.
Pursuant to the terms of the line of credit, until amounts outstanding under the line of credit are repaid, Black Rock may not, without the lender’s consent, among other things and subject to certain exceptions, (i) cease business or engage in any new line of business that is materially different from its current business; (ii) enter into any merger, consolidation, or acquisition of substantially all of the assets of another entity; (iii) materially change its legal structure, management, ownership or financial condition; (iv) effect a domestication, conversion or interest exchange; (v) incur indebtedness or (vi) sell, lease, assign, transfer or dispose of substantially all of its assets.
The promissory note has substantially the same events of default as the June 29, 2011 promissory note discussed below under “- Replacement Note and Bamco Note Receivable.” In addition, an event of default includes the removal of Mr. Barksdale as president and chief executive officer of Black Rock.
On June 18, 2010, Black Rock, Mr. Barksdale and Mr. Bartlett borrowed $3.5 million and issued a $3.5 million promissory note to First State Bank of Lonoke under the line of credit. Pursuant to the promissory note, the loan is payable on demand, or if no demand is made, is due on June 18, 2013. Borrowings may be repaid at any time without penalty. If First State Bank of Lonoke declares a default under the loan, interest will accrue on the principal at a rate of 18% per annum. In addition, pursuant to the promissory note, First State Bank of Lonoke will lock box all funds from net production due to Black Rock. Funds received are first applied to accrued interest, and any remaining amount of funds is applied to the outstanding principal.
As of May 31, 2012, we had $1.8 million outstanding and $1.7 million remaining available for borrowing under the line of credit and were in compliance with all of the covenants under the line of credit described above.
Replacement Note and Bamco Note Receivable As a condition to the reverse merger pursuant to the Share Exchange Agreement with Black Rock and StoneStreet, First State Bank of Lonoke required Black Rock to assume and acquire a loan of $2.7 million from First State Bank of Lonoke (the “Bamco Note Receivable”) that had previously been issued by Bamco. Bamco is in receivership, and Mr. Barksdale is the receiver. As a result, the note payable from Bamco to First State Bank was cancelled, and Black Rock executed a new note to First State Bank of Lonoke (the “Replacement Note”), which became the only outstanding promissory note due to First State Bank of Lonoke related to Bamco. Due to the uncertainty about collection or realizing the value of the Bamco Note Receivable, management deemed it necessary to fully impair the value of the Bamco Note Receivable, which was recorded as a loss on note receivable of $2.7 million in our Consolidated Statement of Operations for the fiscal year ended May 31, 2012. No interest income was recognized on the Bamco Note Receivable.
The Replacement Note accrues interest at a rate of 6% per annum. If First State Bank of Lonoke declares a default, interest will accrue on the principal at a rate of 18% per annum. The Replacement Note is payable on demand, or if no demand is made, must be paid on June 29, 2014. In addition, we must make a principal payment of $540,000 on June 29, 2013. The Replacement Note may be prepaid at any time without penalty.
The Replacement Note is secured by (i) a pledge of all of the common stock of Black Rock; (ii) 2,000,000 shares of our common stock held by StoneStreet and (iii) a lien against our Villarreal, Frost Bank, Resendez and La Duquesa properties. As co-signers, Mr. Barksdale and Mr. Bartlett are personally obligated for the repayment of borrowings under this Replacement Note.
Pursuant to the terms of a commercial loan agreement related to the Replacement Note, until amounts outstanding under the loan are repaid, Black Rock may not, without the lender’s consent, among other things and subject to certain exceptions, (i) cease business or engage in any new line of business that is materially different from its current business; (ii) enter into any merger, consolidation, or acquisition of substantially all of the assets of another entity; (iii) materially change its legal structure, management, ownership or financial condition; (iv) effect a domestication, conversion or interest exchange; (v) incur indebtedness or (vi) sell, lease, assign, transfer or dispose of substantially all of its assets.
An event of default includes, among other events, the following occurrences by any of Black Rock, Mr. Barksdale or Mr. Bartlett: (i) failure to make payment when due; (ii) insolvency or bankruptcy of the Company, any co-signer, endorser, surety or guarantor; (iii) the death or declaration of incompetency of any co-signer or majority owner or partner; (iv) merger; (v) dissolution; (vi) reorganization; (vii) name change; (viii) failure to perform any condition or keep any promise or covenant under the loan agreement; (ix) default of any other agreements with First State Bank of Lonoke; (x) a misrepresentation in any verbal or written statement or financial information; (xi) failure to satisfy or appeal a judgment; (xii) use of the property securing the loan in a manner or for a purpose that threatens confiscation by a legal authority; (xiii) a transfer of all or substantially all of Black Rock or the co-signer’s property; (xiv) a determination by First State Bank of Lonoke that the value of its security has declined or is impaired; (xv) a material change in business, ownership, management or financial condition; or (xvi) First State Bank of Lonoke’s determination in good faith that its prospect for payment are impaired for any reason.
In addition, pursuant to the Replacement Note, First State Bank of Lonoke will lock box all funds from net production due to Black Rock. Funds received are first applied to accrued interest, and any remaining amount of funds is applied to the outstanding principal.
As of May 31, 2012, we had $2.3 million outstanding under the Replacement Note and were in compliance with all of the covenants under the Replacement Note described above.
Senior Secured Promissory Note We issued a senior secured promissory note dated November 16, 2011 payable to the Lenders in an aggregate principal amount of $4.0 million. The senior secured promissory note accrues interest at a rate of 12% per annum, is payable monthly and matures on the earlier of November 16, 2012 or the date the senior secured promissory note is terminated, whether by its terms, by prepayment or by acceleration. Upon an event of default, interest will accrue on all outstanding principal and interest at a rate of 18% above the per annum rate otherwise applicable.
All of our obligations are guaranteed, jointly and severally, by Black Rock and RMR Operating. The promissory note is our senior obligation and is secured by (i) second priority real property liens against our Villarreal, Frost Bank, Resendez and La Duquesa properties; (ii) a first priority real property lien against all of our then existing properties; and (iii) a stock pledge agreement with the Lenders, dated November 30, 2011, with respect to a second lien on 2,136,164 shares of Cross Border common stock owned by us.
The promissory note contains customary non-financial covenants governing the conduct of our business and the maintenance of our properties. Under the terms of the senior secured promissory note, for so long as the promissory note is outstanding, we are prohibited from incurring any future indebtedness secured by all or any portion of the collateral without the prior written consent of Lenders.
An event of default under the senior secured promissory note includes, among other things, (i) failure to make payments when due; (ii) any representation or warranty proves false; (iii) failure to comply with any covenant; (iv) violation of any provision of the note; (v) bankruptcy or insolvency; (vi) the Lenders determine in their sole and absolute discretion that the promissory note or related documents shall, for any reason, fail or cease to create a valid and perfected lien on or security interest in any or all of the collateral or the collateral shall be compromised, encumbered, cancelled, expired, terminated or otherwise rescinded; (vii) the Lenders determine in their sole but reasonable discretion that we are unable in the ordinary course of business to pay our debts as they are due or our debts exceed the fair market value of all of our assets and property or (viii) a default under any of our material agreements.
As of May 31, 2012, we had $4.0 million outstanding under the senior secured promissory note and were in compliance with all of the covenants under the senior secured promissory note described above.
Convertible Promissory Notes On November 25, 2011, we issued convertible promissory notes to Hohenplan Privatstiftung, Personalversorge der Autogrill Schweiz AG and SST Advisors, Inc. in an aggregate principal amount of $2.75 million. The convertible promissory notes are due and payable on November 25, 2013 and bear interest at the rate of 10% per annum. Prior to repayment, the holders of the convertible promissory notes have the option of converting all or any portion of the unpaid balance of the convertible promissory notes (including accrued and unpaid interest) into shares of our common stock at a conversion price equal to $1.00 per share, subject to standard anti-dilution provisions. The value of the beneficial conversion feature of the three convertible promissory notes was $1.2 million as of May 31, 2012. The beneficial conversion feature has been recorded as a discount to the convertible notes payable and to additional paid-in-capital and will be amortized to interest expense over the life of the convertible promissory notes. We amortized $0.4 million to interest expense during the fiscal year ended May 31, 2012.
We issued a convertible promissory note dated July 30, 2012 in the principal amount of $1.0 million to Hohenplan Privatstiftung. The promissory note accrues interest at a fixed rate of 10% per annum. The entire principal amount of the promissory note together with accrued but unpaid interest is due on July 30, 2013, subject to a 12-month extension at the holder’s option. The holder has the option of converting all or a portion of the principal amount of the note, plus accrued but unpaid interest, into shares of our common stock. Subject to adjustment upon certain events, the conversion price is equal to the lower of (a) $1.50 and (b) the lowest price at which our common stock is sold in an equity financing for cash after the date of the note and prior to the maturity date. We have granted the holder piggyback registration rights and agreed to include the resale of any shares of common stock that may be received upon conversion of the note in a future registration statement filed by us, other than a registration statement (i) filed in connection with any employee stock option or other benefit plan, (ii) for an exchange offer or offering of securities solely to our existing shareholders, (iii) for an offering of debt that is convertible into any of our equity securities or (iv) for a dividend reinvestment plan.
Contractual Obligations The following table presents a summary of our contractual obligations at May 31, 2012:
Off-Balance Sheet Arrangements As of May 31, 2012, we did not have any off-balance sheet arrangements as defined by Regulation S-K.
Item 7A.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk Not applicable.
Item 8.
Item 8. Financial Statements and Supplementary Data Our consolidated financial statements required by this item are included in this report beginning on page and are incorporated herein by reference.
Item 9.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure Not applicable.
Item 9A.
Item 9A. Controls and Procedures Evaluation of Disclosure Controls and Procedures Disclosure controls and procedures are controls and other procedures that are designed to ensure that information required to be disclosed by us in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed in the reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives.
Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we evaluated the effectiveness of our disclosure controls and procedures as of May 31, 2012 and, based on that evaluation, and as a result of the material weaknesses described below, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were not effective at the reasonable assurance level.
Management’s Report on Internal Control Over Financial Reporting Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act. Internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of our financial statements for external purposes in accordance with GAAP. Internal control over financial reporting includes policies and procedures that: (i) pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of our assets; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of our financial statements in accordance with GAAP, and that our receipts and expenditures are being made only in accordance with the authorizations of our management and board of directors and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on our financial statements.
Because of inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or that the degree of compliance with the policies or procedures may deteriorate. However, these inherent limitations are known features of the financial reporting process. Therefore, it is possible to design into the process safeguards to reduce, though not eliminate, this risk.
Our management, under the supervision and with the participation of our principal executive officer and principal financial and accounting officer, assessed the effectiveness of our internal control over financial reporting as of May 31, 2012 based on criteria established in Internal Control - Integrated Framework created by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on this assessment, our management concluded that our internal control over financial reporting was not effective as of May 31, 2012 because of the identification of the material weaknesses identified below.
A material weakness (as defined in Rule 12b-2 under the Exchange Act) is a deficiency, or combination of deficiencies, in internal control over financial reporting such that there is a reasonable possibility that a material misstatement in our annual or interim financial statements will not be prevented or detected on a timely basis. During the course of our assessment, management identified the following material weaknesses:
• lack of accounting expertise to appropriately apply GAAP for complex or non-recurring transactions; and
• lack of sufficient accounting personnel to properly design and implement internal control over financial reporting.
This Annual Report on Form 10-K does not include an attestation report of our independent registered public accounting firm regarding internal control over financial reporting as such report is not required for non-accelerated filers.
Management’s Plan for Remediation of Our Material Weaknesses Management will continue to review and assess our system of internal control over financial reporting as well as the new members of our accounting staff and their increased levels of accounting expertise. During this review and assessment, we will continue to implement enhancements to our system of internal controls where appropriate. Finally, we will continue to evaluate the employees and contractors involved in the preparation of our financial statements, the need to engage outside consultants with accounting and tax expertise to assist us in accounting for complex transactions and the hiring of additional accounting staff as necessary to timely prepare our financial statements. Management currently believes it will be able to remedy the material weaknesses described above over the next 12 months.
Changes in Internal Control Over Financial Reporting There have been no changes in our internal control over financial reporting that occurred during our last fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting, except that we took the following steps to strengthen our internal control over financial reporting:
• We implemented certain anti-fraud controls in our check writing procedures.
• We increased the number of balance sheet accounts that are required to be formally reconciled and increased the amount of detail required to support such account balances.
Item 9B.
Item 9B. Other Information None.
PART III Item 10.
Item 10. Directors, Executive Officers and Corporate Governance Directors and Executive Officers Our current directors and executive officers are as follows:
Name
Age
Position
Alan W. Barksdale
President, Chief Executive Officer and Chairman of the Board of Directors
Hilda D. Kouvelis
Chief Accounting Officer and Executive Vice President
Tommy W. Folsom
Executive Vice President and Director of Exploration and Production of RMR Operating
Lynden B. Rose
Director
Paul N. Vassilakos
Director
Richard Y. Roberts
Director
Randell K. Ford
Director
Alan W. Barksdale has been our Chief Executive Officer and Chairman of the Board of Directors since June 2011, our President since July 2012, and served as our Interim Acting Chief Financial Officer from June 2011 to August 2011. Mr. Barksdale has also served as President of Black Rock since its inception. Mr. Barksdale has also been the owner and president of StoneStreet and president and manager of StoneStreet Group, advisory and management services and merchant banking firms, since 2008. Mr. Barksdale has also been the president of AWB Enterprises, Inc., a holding company, since November 2011. From January 2004 to April 2010, Mr. Barksdale served as a director in the Capital Markets Group of Crews & Associates, an investment banking firm. From August 2003 to October 2003, Mr. Barksdale served as an investment banker at Stephens Inc., an investment banking firm. From 2002 to 2003, Mr. Barksdale was an investment banker at Crews & Associates. Mr. Barksdale has served as the non-executive chairman of the board for Cross Border, an oil and gas exploration company, since May 2012. Mr. Barksdale’s experience in operating, managing, financing and investing in more than 100 wells in Louisiana, Mexico and Texas, combined with his over ten years of capital markets experience and contacts and relationships, provides our Board of Directors with invaluable management and operational direction.
In 2004, the National Association of Securities Dealers, Inc. (“NASD”) alleged that Mr. Barksdale solicited an attorney to make contributions to officials of an issuer with which Stephens Inc. was engaging in municipal securities business when Mr. Barksdale was employed as an investment banker of Stephens Inc. Without admitting or denying the allegations, Mr. Barksdale entered into an acceptance, waiver and consent decree that provided for a 30-day suspension from associating with any NASD member and a $5,000 fine.
Hilda D. Kouvelis has served as our Chief Accounting Officer since February 2012 and was appointed Executive Vice President in July 2012. Ms. Kouvelis has more than 25 years of industry accounting and finance experience. From January 2005 until June 2011, she was employed with TransAtlantic Petroleum Ltd., an international oil and natural gas company engaged in the acquisition, exploration, development and production of oil and natural gas, serving as its Chief Financial Officer from January 2007 until April 2011 and as its Vice President from May 2007 to April 2011. She also served as its controller from January 2005 to January 2007. Since leaving TransAtlantic Petroleum Ltd. in June 2011, she has been a private consultant advising on accounting matters and acquisitions.
Tommy W. Folsom has been RMR Operating’s Executive Vice President and Director of Exploration and Production since August 2012 and served as our Executive Vice President and Director of Exploration and Production from September 2011 to August 2012. Mr. Folsom is the founder of Enerstar Resources O & G, LLC (“Enerstar”), an oil company involved in the drilling, re-completion, re-entry and acquisition of properties and leases in the United States, and has served as its President since its formation in 1994. From 1996 to August 2011, Mr. Folsom served as the Operations Manager of Murchison Oil and Gas, Inc., a privately-held independent oil and gas company engaged in the acquisition, development and production of oil and gas resources in the United States.
Lynden B. Rose served as our Corporate Secretary from March 2011 to August 2012 and has served as a director since February 2011. Mr. Rose has been a partner in the law firm of Stanley, Frank & Rose, LLP in Houston since 2007. Since 1992, he also has served as counsel to The Rose Law Firm. From 2004 until 2007, Mr. Rose was a partner in the law firm of Lynden B. Rose, P.C. Since 2003, Mr. Rose also served as President of LM Rose Consulting Group, and since 1991, he has served as President of Rose Sports Management, Inc. Mr. Rose has served as a director of Latitude Solutions, Inc., which specializes in the development and deployment of water remediation technologies, since April 2011. Mr. Rose has served as secretary and a director of Rio Bravo Oil, Inc., which is engaged in the acquisition, development, and exploration of oil and natural gas properties, since February 2012. As an experienced attorney and member of the Oil, Gas and Energy Resources Law Section of the State Bar of Texas, Mr. Rose adds to our Board of Directors his valuable legal perspective in the oil and gas industry.
Paul N. Vassilakos has been a director since October 2011. Mr. Vassilakos also previously served as our President and Chief Executive Officer from February 2011 to March 2011. From November 2011 through February 2012, Mr. Vassilakos served as Chief Executive Officer, Chief Financial Officer and director of Soton Holdings Group, Inc., a publicly held company now known as Rio Bravo Oil, Inc. Mr. Vassilakos has been the assistant treasurer of Cullen Agricultural Holding Corp. (“CAH”) since October 2009. CAH is a development stage agricultural company which was formed in connection with the business combination between Triplecrown Acquisition Corp. and Cullen Agricultural Technologies, Inc. in October 2009. In July 2007, Mr. Vassilakos founded Petrina Advisors, Inc., a privately held advisory firm providing investment banking services, and has served as its president since its formation. Mr. Vassilakos also founded and, since December 2006, serves as the vice president of Petrina Properties Ltd., a privately held real estate holding company. From February 2002 through June 2007, Mr. Vassilakos served as vice president of Elmsford Furniture Corp., a privately held furniture retailer in the New York area. Mr. Vassilakos has also served on the board of directors of Cross Border since May 2012. Mr. Vassilakos brings extensive public company and capital markets experience, as well as his professional contacts and experience, to our Board of Directors.
Richard Y. Roberts has been a director since October 2011. Mr. Roberts co-founded a regulatory and legislative consulting firm, Roberts, Raheb & Gradler LLC, in March 2006. He was a partner with Thelen Reid & Priest LLP, a national law firm, from January 1997 to March 2006. From August 1995 to January 1997, Mr. Roberts was a consultant at Princeton Venture Research, Inc., a private consulting firm. From 1990 to 1995, Mr. Roberts was a commissioner of the SEC. Mr. Roberts is currently a director of CAH. He was a director of Nyfix, Inc. from September 2005 to December 2009, Endeavor Acquisition Corp. from July 2005 to December 2007, a director of Victory Acquisition Corp. from January 2007 to April 2009 and a director of Triplecrown Acquisition Corp. from June 2007 to October 2009. Mr. Roberts’ experience at the SEC, and his experience as a director of other public companies, as well as his professional contacts and relationships, provides our Board of Directors with necessary insight into the requirements and needs of an emerging public company.
Randell K. Ford has been a director since November 2011. Mr. Ford has worked in the oil and gas industry for over 40 years. Since 1993, Mr. Ford has been the President of R. K. Ford and Associates, Inc., a consulting firm based in the Permian Basin in Midland, Texas that specializes in drilling, engineering and completion of oil and gas wells. Currently, Mr. Ford is a partner in Western Drilling Inc., an onshore drilling services company. While serving as President, Division Drilling Engineer, Principal and various other oilfield service positions, Mr. Ford has drilled, managed, consulted or invested in over 4,000 wells located domestically in 18 states and internationally in 12 countries. Mr. Ford has also served on the board of directors of Cross Border since May 2012. Our Board of Directors benefits from Mr. Ford’s operational expertise, stemming from his over 40 years of experience in the oil and gas industry.
Corporate Governance We do not have separate standing audit, nomination or compensation committees. Our three independent directors, Messrs. Roberts, Rose and Vassilakos, perform the functions of our audit committee, nomination and compensation committees. Our Board has not determined that we have an “audit committee financial expert,” as defined in SEC rules, serving on the Board. However, the Board believes that our independent directors
have sufficient knowledge in financial and auditing matters to perform the functions of our audit committee. The Board accordingly does not believe it is necessary at this time to recruit a new director in order to name an audit committee financial expert.
Code of Ethics Our Board of Directors has adopted a code of ethics that applies to our directors, officers, and employees. A copy of our code of ethics is available on our website at
www.redmountainresources.com/investor-information under the “Governance” heading. We intend to post any amendments to, or waivers from, our code of ethics that apply to our principal executive officer, principal financial officer, and principal accounting officer on our website at
www.redmountainresources.com/investor-information.
Section 16(a) Beneficial Ownership Reporting Compliance Section 16(a) of the Exchange Act (“Section 16(a)”) requires our executive officers and directors, and persons who beneficially own more than 10% of our equity securities, to file reports of ownership and changes in ownership with the SEC. Based solely on our review of Forms 3, 4 and 5 furnished to us as required under the rules of the Exchange Act, we have no knowledge of any failure to report on a timely basis any transaction required to be disclosed under Section 16(a) except: (i) an untimely Form 4 filed on November 15, 2011 by Mr. Folsom, reporting the acquisition of 60,000 shares of our common stock on November 4, 2011 and (ii) an untimely Form 3 filed on July 8, 2011 by StoneStreet for its initial statement of beneficial ownership of our common stock on June 22, 2011.
Item 11.
Item 11. Executive Compensation On June 22, 2011, we changed our fiscal year end from January 31 to May 31. The following table sets forth information concerning compensation of our Named Executive Officers for the fiscal year ended January 31, 2011, the period from February 1, 2011 to May 31, 2011 and the fiscal year ended May 31, 2012. The Named Executive Officers are: our Chief Executive Officer, our Executive Vice President and Director of Exploration and Production of RMR Operating, our former Chief Executive Officer and our former Executive Vice President and Director of Finance.
Summary Compensation Table
(1) Mr. Barksdale has served as Chief Executive Officer since June 22, 2011 and as President since July 25, 2012. From June 22, 2011 to August 8, 2011, Mr. Barksdale also served as Interim Acting Chief Financial Officer.
(2) Mr. Folsom served as our Executive Vice President and Director of Exploration and Production from September 30, 2011 until August 1, 2012 and has served as RMR Operating’s Executive Vice President and Director of Exploration and Production since August 1, 2012.
(3) Mr. Hanley served as Executive Vice President and Director of Finance from August 8, 2011 until his departure on April 16, 2012.
(4) Mr. Koock served as President, Chief Executive Officer and Interim Acting Chief Financial Officer of the Company from March 15, 2011 until his resignation on June 22, 2011 and as a director of the Company from February 2, 2011 until his resignation on June 22, 2011. In February 2011, he was issued 50,000 shares (on a post-split basis) of common stock for his services as an officer and director.
(5) The amounts shown represent the aggregate grant date fair value of the stock awards granted to Mr. Koock in accordance with ASC 718, Compensation - Stock Compensation.
Employment Agreements Mr. Barksdale entered into an employment agreement with us effective June 17, 2011. Under the agreement, Mr. Barksdale served as our Chief Executive Officer, Secretary, and Interim Chief Financial Officer. He also served as Manager of RMR Operating and as President of Black Rock. Under the agreement, Mr. Barksdale received a base salary of $25,000 per month. Pursuant to the employment agreement, Mr. Barksdale was entitled to receive an annual performance bonus based on performance objectives and parameters to be determined by the Board of Directors and an initial award of stock options, in a mutually agreeable amount. However, no such bonus or stock options were awarded. Mr. Barksdale was also entitled to a car allowance of $1,500 per month pursuant to the employment agreement. The agreement expired on December 31, 2011. Mr. Barksdale remains employed as an at-will employee and continues to be compensated in accordance with the terms as were set forth in his employment agreement.
Mr. Folsom entered into an employment agreement with us effective September 14, 2011, as amended July 27, 2012. Under the agreement, as amended, Mr. Folsom serves as Executive Vice President and Director of Exploration and Production of RMR Operating. Under the agreement, Mr. Folsom is entitled to a base salary of $20,000 per month and an annual performance bonus. The performance bonus is to be determined
based upon objectives determined annually by our Board of Directors, but will not be less than $250,000 per year (pro-rated for any partial year). The performance bonus is payable in cash, our common stock, or a combination thereof as determined by Mr. Folsom. As of August 31, 2012, Mr. Folsom elected to receive his fiscal 2012 bonus 50% in cash and 50% in stock options; however, the stock options will not be issued until approval of the Company’s Long-Term Incentive Plan. See “- Long-Term Incentive Plan.” Pursuant to the employment agreement, Mr. Folsom is entitled to receive additional equity grants in the discretion of our Board of Directors on the same basis as other similarly situated senior executives. We are required to provide Mr. Folsom with disability, accident, medical, life and hospitalization insurance, as well as other benefits provided to similarly situated senior executives. In lieu of these benefits, Mr. Folsom may elect to receive a lump sum payment for such benefits not to exceed 7% of his salary. Mr. Folsom is also entitled to either a vehicle provided by us plus reimbursement for the cost of fuel, maintenance and insurance, or a $1,000 per month vehicle allowance plus reimbursement for the cost of fuel. If Mr. Folsom’s employment is terminated by us without “cause” or by Mr. Folsom for “good reason” (as each term is defined below), he will be entitled to receive a lump sum payment equal to the lesser of three months of his base salary or the base salary for the remainder of the term of the agreement. If the agreement is terminated upon Mr. Folsom’s death or total disability, we are required to pay Mr. Folsom or his estate the greater of any death or long-term disability payment, as applicable, due under any plan or policy, or the amount of the minimum annual performance bonus that would be paid to Mr. Folsom for the remainder of the term of the agreement. Under the agreement, Mr. Folsom is prohibited from disclosing confidential information about us. The agreement expires on December 31, 2016.
Mr. Hanley entered into an employment agreement with us effective August 1, 2011. Under the agreement, Mr. Hanley served as our Executive Vice President and Director of Finance and received a base salary of $13,750 per month. Mr. Hanley’s agreement expired on December 31, 2011 and he served as an at will employee until his departure in April 2012.
Ms. Kouvelis entered into an employment agreement with us effective February 1, 2012. Under the agreement, Ms. Kouvelis serves as our Chief Accounting Officer. The agreement provides for Ms. Kouvelis to receive a base salary of $170,000 per year. On July 25, 2012, the Board appointed Ms. Kouvelis as Executive Vice President of the Company and its subsidiaries and on July 27, 2012, her employment agreement was amended to increase to her base salary to $200,000. Pursuant to the employment agreement, Ms. Kouvelis is entitled to receive an annual performance bonus based on performance objectives and parameters to be determined by the Board of Directors. The performance bonus is payable in cash, shares of our common stock, or a combination thereof as determined by the Board of Directors. Ms. Kouvelis is also entitled to receive an initial stock option grant in an amount to be determined by the Board of Directors with a value of not less than $42,500. As of August 10, 2012, neither the performance objectives and parameters nor the size of the initial stock option grant had been determined, but both are required by the agreement to be determined by December 31, 2012. Pursuant to the employment agreement, Ms. Kouvelis is entitled to receive additional equity grants in the discretion of our Board on the same basis as other similarly situated senior executives. We are required to provide Ms. Kouvelis with disability, accident, medical, life and hospitalization insurance, as well as other benefits provided to similarly situated senior executives. If Ms. Kouvelis is terminated by us without “cause” or by Ms. Kouvelis for “good reason” (as each term is defined below), she will be entitled to receive a lump sum payment equal to the lesser of six months of her base salary or the base salary for the remainder of the term. Under the agreement, Ms. Kouvelis is prohibited from disclosing confidential information about us and she has agreed not to compete with us during the term of her employment and for six months thereafter. The agreement expires on January 31, 2015.
“Cause” in Mr. Folsom and Ms. Kouvelis’ employment agreements is defined as the conviction by the executive of any felony or crime involving moral turpitude, the executive’s willful and intentional failure or refusal to follow instructions of the Board of Directors, a material breach in the performance of the executive’s obligations under the agreement, the executive’s violation of any of our written policies if the executive knows or should know such action constitutes a violation thereof, or the executive’s act of misappropriation, embezzlement, intentional fraud or similar conduct, or other dishonest conduct in his or her relations with us. “Good reason” in each of the employment agreements is defined as a material reduction in
the executive’s salary or benefits or duties, authority or responsibilities, the relocation of the executive’s work location to a location more than 50 miles from his current location, or the failure of a successor to assume and perform under the agreement.
We pay insurance premiums on behalf of each of our employees for life insurance policies pursuant to which such employee is entitled to life insurance equal to one year’s salary.
Long-Term Incentive Plan On August 29, 2012, the Board of Directors adopted, subject to shareholder approval, the Red Mountain Resources, Inc. 2012 Long-Term Incentive Plan (the “Incentive Plan”). The Incentive Plan provides for the granting of incentive stock options, nonqualified stock options, stock appreciation rights, restricted stock, restricted stock units, performance awards, and dividend equivalent rights which may be granted singly, in combination, or in tandem. The Incentive Plan is intended to enable the Company to remain competitive and innovative in the Company’s ability to attract, motivate, reward, and retain the services of key employees, certain key contractors, and outside directors. If the Incentive Plan is approved by our stockholders, the maximum number of shares of common stock authorized and available for issuance under the Incentive Plan would be 8,200,000 shares.
Director Compensation Prior to October 20, 2011, we did not have a compensation program for our non-employee directors. On October 20, 2011, our Board of Directors approved a compensation program for non-employee directors, as follows:
• Each non-employee director receives an annual cash fee of $35,000;
• Each chairman of the audit committee and compensation committee (if any such committees then exist) receives an additional annual cash fee of $10,000 and $5,000, respectively;
• Each non-employee director receives a cash fee of $1,000 and $500 for each Board and committee meeting, respectively, such director participates in; and
• Each non-employee director annually receives $50,000 paid in shares of our common stock at a price equal to the last sales price of our common stock on the OTCBB on the date of issuance.
All directors are reimbursed for their costs incurred in attending meetings of the Board of Directors or of the committees on which they serve. All cash compensation is paid quarterly within 30 days of the beginning of each quarter. The stock grant is paid annually on May 31st of each year (or the next business day if May 31st is not a business day) and pro rated for partial service in any given year. The term of office for each director is one year, or until his or her successor is elected at our annual stockholders meeting and qualified.
Director Compensation Table The table below reflects compensation paid to non-employee directors for the fiscal year ended May 31, 2012. Mr. Barksdale serves as a director and our President and Chief Executive Officer. As such, information about his compensation is listed in the Summary Compensation Table above. Mr. Barksdale did not receive any additional compensation for his service as a director.
(1) Each non-employee director who served on the Board of Directors on or before the non-employee director compensation program was adopted received annual compensation pro rated for service from October 20, 2011 (the date such program was adopted) through May 31, 2012, in addition to cash fees for meetings in which such director participated.
(2) Mr. Ford received compensation pro rated for service from the date of his appointment to the Board of Directors on November 21, 2011 through May 31, 2012, in addition to cash fees for meetings in which Mr. Ford participated.
(3) The amounts shown represent the aggregate grant date fair value of the stock awards granted to such director in accordance with ASC 718, Compensation - Stock Compensation.
Risk Management Relating to Compensation Policies Due to the limited nature of compensation that we currently pay, particularly performance - based compensation, we do not believe there are any risks arising from our compensation policies and practices that are reasonably likely to have a material adverse effect on us.
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
The following table sets forth information regarding the beneficial ownership of our common stock as of August 31, 2012 by (i) each person known by us to be the beneficial owner of more than 5% of our outstanding shares of common stock; (ii) each of our Named Executive Officers and directors and (iii) all of our executive officers and directors as a group.
* Less than one percent.
(1) Unless noted otherwise, the address for the above individuals or entity is 2515 McKinney Ave., Suite 900, Dallas, Texas 75201. Unless noted otherwise, each of the above persons has sole voting and investment power with respect to all shares of common stock beneficially owned by them.
(2) Based on 86,884,463 shares of common stock issued and outstanding on August 31, 2012.
(3) These shares are owned by StoneStreet. Alan Barksdale (our President, Chief Executive Officer and Chairman of the Board) is the sole shareholder and president of StoneStreet and may be deemed to beneficially own these shares. Of these shares, 8,000,000 shares are subject to a lockup agreement and will be released on December 21, 2012.
(4) The beneficial ownership of shares reported herein for Mr. Koock are to the best of the Company’s knowledge. This information assumes that Mr. Koock has not sold the 50,000 shares issued for his service as an officer and director of the Company in February 2011, nor purchased additional shares of the Company’s common stock.
(5) Does not include shares beneficially owned by Mr. Koock, who no longer serves as an executive officer of the Company.
Equity Compensation Plans As of May 31, 2012, we did not have any equity compensation plans under which equity securities are authorized for issuance.
Item 13.
Item 13. Certain Relationships and Related Transactions, and Director Independence Certain Relationships and Related Transactions Mr. Barksdale is the receiver for Bamco. Bamco primarily owns oil and gas leasehold interests in various properties, including partial interests in the Frost Bank, La Duquesa and Resendez leases. We have proposed acquiring Bamco’s assets in exchange for issuing 2,375,000 shares of our common stock to Bamco’s receivership estate. The proposed asset acquisition is subject to confirmation by the court presiding over Bamco’s receivership. We expect the court to confirm the plan of acquisition during the second quarter of fiscal 2013.
In October 2011, we entered into a subscription agreement with Randell K. Ford for the sale of 750,000 shares of our common stock to Mr. Ford in a private placement at a price of $1.00 per share. Mr. Ford became a director of the Company in November 2011.
On August 12, 2011, we purchased 218,535 shares of common stock of Cross Border from Mr. Ford in exchange for the issuance of 273,169 shares of our common stock.
On June 22, 2011, as part of the acquisition of Black Rock, we issued StoneStreet 27,000,000 shares of common stock. Mr. Barksdale is the sole shareholder of StoneStreet. On June 22, 2011, Mr. Barksdale and StoneStreet entered into a lock-up agreement with us with respect to 18,000,000 shares of common stock then held by StoneStreet. Pursuant to the lock-up agreement, 3,000,000 shares were to be released on June 21, 2012 and the remaining 15,000,000 shares were to be released on December 21, 2012. On September 12, 2011, StoneStreet assigned 7,000,000 shares subject to the lock-up agreement to several third parties after receiving the consent from the Company to release it from the lockup restrictions with respect to such shares, leaving it with 11,000,000 shares. As a result, the lock-up agreement now covers 11,000,000 shares. Of such shares, 3,000,000 were released as of June 21, 2012 and are now permitted to be sold. The remaining 8,000,000 shares may not be sold until December 21, 2012. In connection with the assignment, the transferees agreed to have 100,000 shares of common stock cancelled in exchange for the Company releasing the shares from the lockup restrictions.
StoneStreet Operating served as the operator for the Frost Bank, Resendez and La Duquesa properties from June 1, 2011 to December 31, 2011. Mr. Barksdale is the president and manager of StoneStreet Operating. For the fiscal year ended May 31, 2012, StoneStreet Operating paid us $146,166 of oil and gas revenues attributable to the properties, and we paid StoneStreet Operating $14,550 for acting as operator of the properties.
During the fiscal year ended May 31, 2012, we also paid StoneStreet Operating approximately $90,796 as reimbursement for operating and corporate expenses incurred by StoneStreet Operating on our behalf and $20,260 as payment for condensate proceeds that were payable to StoneStreet Operating. At May 31, 2012, $11,629 was payable to StoneStreet Operating for reimbursement of expenses.
On September 15, 2011, we borrowed $100,000, interest free, from StoneStreet Operating for working capital purposes and the loan was repaid in full on September 26, 2011. On October 19, 2011, we borrowed an additional $180,000, interest free, from StoneStreet Operating for working capital purposes and the loan was repaid in full on October 26, 2011.
On January 28, 2011, Black Rock funded a $25,000 one year certificate of deposit in order for StoneStreet Operating to secure an additional letter of credit for the benefit of the Railroad Commission of Texas. Subsequent to funding, Black Rock assigned the certificate of deposit to StoneStreet Operating. The certificate of deposit was liquidated on November 2, 2011 and the proceeds of $25,141 were returned to Black Rock.
We entered into an arrangement with R.K. Ford and Associates and Cabal Energy relating to the operations of the Good Chief State #1 and Big Brave State #1 wells, and a contract for drilling services with Western Drilling on our Madera 24-2H well. Each of these entities are owned or partially owned by Mr. Ford. During the fiscal year ended May 31, 2012, we paid an aggregate of $5.0 million to these entities for engineering, drilling and completion services. In addition, we are a party to a lease agreement with R.K. Ford
and Associates, pursuant to which we lease office space in Midland, Texas. During the fiscal year ended May 31, 2012, we paid $25,200 to R.K. Ford and Associates pursuant to the lease agreement.
We are a party to a consulting agreement with Enerstar Resources O&G, LLC. This entity is partially owned by Tommy Folsom, Executive Vice President and Director of Exploration and Production for RMR Operating and formerly the Executive Vice President and Director of Exploration and Production for the Company. During the fiscal year ended May 31, 2012, we paid an aggregate of $5,745 to this entity.
Independence of Directors The standards relied upon the Board in determining whether a director is “independent” are those set forth in the rules of the NYSE MKT LLC (formerly, NYSE Amex). The NYSE MKT LLC generally defines “independent directors” as a person other than an executive officer or employee of a company, who does not have a relationship with the company that would interfere with the director’s exercise of independent judgment in carrying out the responsibilities of a director. Consistent with these standards, our Board of Directors has affirmatively determined that Messrs. Rose, Vassilakos and Roberts are our independent directors.
Item 14.
Item 14. Principal Accountant Fees And Services Aggregate fees for professional services provided to us by Hein & Associates LLP, our principal accountant for the fiscal year ended May 31, 2012, and LJ Soldinger Associates LLC, our principal accountant for the fiscal year ended May 31, 2011, were as follows:
(a) Audit services billed consisted of the audits of our annual consolidated financial statements, audits of internal control over financial reporting and reviews of our quarterly condensed consolidated financial statements.
(b) Audit-related fees principally include costs incurred related to audit-related work regarding proposed acquisitions.
(c) Tax fees include tax compliance and tax planning.
Audit Committee Approval We do not have a separately designated audit committee. As such, our three independent directors act as our audit committee. All of the foregoing services were pre-approved by our independent directors.
We do not have a formal pre-approval policy. In accordance with Section 10A(i) of the Exchange Act, before we engage our independent registered public accounting firm to render audit or non-audit services, our independent directors have pre-approved, and will continue to pre-approve, such services.
PART IV Item 15.
Item 15. Exhibits and Financial Statement Schedules (a) The following documents are filed as part of this Annual Report on Form 10-K:
1. Reports of Independent Registered Public Accounting Firms
Consolidated Balance Sheets as of May 31, 2012 and 2011
Consolidated Statements of Operations for the Years Ended May 31, 2012 and 2011
Consolidated Statements of Cash Flows for the Years Ended May 31, 2012 and 2011
Consolidated Statements of Stockholders’ Equity for the Years Ended May 31, 2012 and 2011
Notes to Financial Statements
2. Exhibits required to be filed by Item 601 of Regulation S-K
The exhibits required to be filed by this Item 15 are set forth in the Exhibit Index accompanying this report.
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Board of Directors and Stockholders
Red Mountain Resources, Inc. and subsidiaries
We have audited the accompanying consolidated balance sheet of Red Mountain Resources, Inc. and subsidiaries (the “Company”) as of May 31, 2012, and the related consolidated statements of operations, stockholders’ equity, and cash flows for the year 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 audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides 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 Red Mountain Resources, Inc. and subsidiaries as of May 31, 2012, and the results of their operations and their cash flows for the year then ended, in conformity with accounting principles generally accepted in the United States of America.
The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 2 to the consolidated financial statements, the Company has incurred a net loss from operations and its current liabilities exceed its total current assets. These factors raise substantial doubt about the Company’s ability to continue as a going concern. Management’s plans in regard to these matters are also described in Note 2. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.
As discussed in Note 4 to the consolidated financial statements, the Company has elected to change its method of accounting for oil and natural gas activities retrospectively effective as of June 1, 2010.
We also have audited the adjustments to the 2011 consolidated financial statements to retrospectively apply the equity method accounting for Cross Border Resources, Inc., as described in Note 5. In our opinion, such adjustments are appropriate and have been properly applied. We were not engaged to audit, review, or apply any procedures to the 2011 consolidated financial statements of the Company other than with respect to the adjustments and, accordingly, we do not express an opinion or any other form of assurance on the 2011 consolidated financial statements taken as a whole.
/s/ Hein & Associates LLP
Dallas, Texas
September 12, 2012
Report of Independent Registered Public Accounting Firm To the Board of Directors and Stockholders
Red Mountain Resources, Inc.
We have audited, before the effects of the adjustments to retrospectively apply the change in accounting described in Note 5, the balance sheet of Red Mountain Resources, Inc. (formerly Black Rock Capital, Inc. and Black Rock Capital, LLC) as of May 31, 2011, and the related statement of operations, stockholders' equity, and cash flows for the year then ended (the “Prior Year” comparative financial statements before the effects of the adjustments discussed in Note 5 are not presented herein). The Prior Year comparative financial statements are the responsibility of the company's management. Our responsibility is to express an opinion on these financial statements based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
In our opinion, the comparative Prior Year financial statements, before the effects of the adjustments to retrospectively applying the equity method of accounting as described in Note 5, present fairly, in all material respects, the financial position of Red Mountain Resources, Inc. (formerly Black Rock Capital, Inc. and Black Rock Capital, LLC) as of May 31, 2011, and the results of its operations and its cash flows for the year then ended in conformity with U.S. generally accepted accounting principles.
We were not engaged to audit, review, or apply any procedures to the adjustments to retrospectively apply the change in accounting described in Note 5 (relating to the equity method accounting for Cross Border Resources, Inc.) and, accordingly, we do not express an opinion or any other form of assurance about whether such adjustments are appropriate and have been properly applied. Those adjustments were audited by Hein & Associates LLP.
/s/ L J Soldinger Associates, LLC
Deer Park, IL
September 22, 2011 (except with respect to our opinion on the financial statements insofar as it relates to the effects of the changes in accounting for oil and gas operations discussed in Note 4, as to which the date is October 21, 2011 and the effects relating to the retrospective presentation of the recapitalization of the company in the statements of stockholders’ equity and related sections of the balance sheet as described in Note 1 as to which the date is September 11, 2012)
Red Mountain Resources, Inc. and Subsidiaries
Consolidated Balance Sheets
(in thousands)
The accompanying notes are an integral part of these consolidated financial statements.
The accompanying notes are an integral part of these consolidated financial statements.
Red Mountain Resources, Inc. and Subsidiaries
Consolidated Statements of Operations
(in thousands, except per share amounts)
The accompanying notes are an integral part of these consolidated financial statements.
Red Mountain Resources, Inc. and Subsidiaries
Consolidated Statements of Cash Flows
(in thousands)
The accompanying notes are an integral part of these consolidated financial statements.
The accompanying notes are an integral part of these consolidated financial statements.
Red Mountain Resources, Inc. and Subsidiaries
Consolidated Statements of Stockholders’ Equity
(in thousands)
(1) Reflects shares and amount of common stock outstanding at May 31, 2011 on a pro forma basis after giving effect to the issuance of 27,000,000 shares of common stock to The StoneStreet Group, Inc. and the retirement of 225,000,000 shares of common stock in connection with the reverse merger with Black Rock Capital, LLC in June 2011, and the conversion of Black Rock Capital, LLC to a corporation, as if these transactions had occurred on June 1, 2010.
The accompanying notes are an integral part of these consolidated financial statements.
Red Mountain Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements 1. Organization Red Mountain Resources, Inc. is a growth-oriented energy company engaged in the acquisition, development and exploration of oil and natural gas properties in established basins with demonstrable prolific producing zones. Currently, the Company has established acreage positions and production in the Permian Basin of West Texas and Southeast New Mexico and the onshore Gulf Coast of Texas. The Company’s focus is to grow production and reserves by acquiring and developing an inventory of long-life, low risk drilling opportunities in and around producing oil and natural gas properties. Unless the context otherwise requires, the terms “Red Mountain” and “Company” refer to Red Mountain Resources, Inc. and its consolidated subsidiaries.
The Company is a Florida corporation originally formed in January 2010 as Teaching Time, Inc. in order to design, develop, and market instructional products and services for the corporate, education, government and healthcare e-learning industries. In March 2011, Teaching Time, Inc. determined to enter into oil and natural gas exploration, development and production and changed its name to Red Mountain Resources, Inc. to better reflect that plan. On March 22, 2011, the Company entered into a Plan of Reorganization and Share Exchange Agreement, as amended on June 17, 2011 and June 20, 2011 (the “Share Exchange Agreement”), with Black Rock Capital, LLC and The StoneStreet Group, Inc. (“StoneStreet”), the sole shareholder of Black Rock Capital, LLC. Alan W. Barksdale, the Company’s current president, chief executive officer and chairman of the board, was the president and the sole member of Black Rock Capital, LLC and the sole owner and the president of StoneStreet. On June 22, 2011, the Company completed a reverse merger pursuant to the Share Exchange Agreement in which the Company issued 27,000,000 shares of common stock to StoneStreet in exchange for 100% of the interests in Black Rock Capital, LLC. Concurrently with the closing, the Company retired 225,000,000 shares of common stock for no additional consideration. In connection with the reverse merger, the management of Black Rock Capital, LLC became the Company’s management, and the Company eliminated the notes payable from Black Rock Capital, LLC to the Company in the amount of $5.8 million, which is reflected as notes payable-related party in the Company’s Consolidated Balance Sheet for the fiscal year ended May 31, 2011.
While the Company was the legal acquirer in the reverse merger, Black Rock Capital, LLC was treated as the accounting acquirer and the transaction was treated as a recapitalization. As a result, at the closing, the historical financial statements of Black Rock Capital, LLC became those of the Company. Effective July 1, 2011, Black Rock Capital, LLC was converted to Black Rock Capital, Inc. (“Black Rock”), and the Company’s 100% membership interest in Black Rock Capital, LLC became an interest in all of the outstanding common stock of Black Rock. This resulted in the Company’s Consolidated Statement of Stockholders’ Equity for the fiscal year ended May 31, 2011 and the related sections of the Company’s Consolidated Balance Sheet as of May 31, 2011 being revised to reflect the recapitalization of Black Rock Capital, Inc. and the resulting retroactive presentation of the 27,000,000 shares that recapitalized Black Rock Capital, Inc.
2. Going Concern These consolidated financial statements have been prepared on the basis of accounting principles applicable to a going concern. These principles assume that the Company will be able to realize its assets and discharge its obligations in the normal course of operations for the foreseeable future.
The Company incurred a net loss of $12.4 million during the fiscal year ended May 31, 2012. At May 31, 2012, the outstanding principal amount of the Company’s debt was $10.9 million, and the Company had a working capital deficit of $10.4 million. Of the outstanding debt, $4.0 million is due November 16, 2012 under a senior secured promissory note payable to Hyman Belzberg, William Belzberg and Caddo Management, Inc. (collectively, the “Lenders”), and an aggregate of $4.1 million is due on demand under a line of credit and promissory note with First State Bank of Lonoke (“FSB”). The Company currently does not have sufficient funds to repay these obligations. The Company is exploring available financing options, including the sale of debt or equity. If the Company is unable to finance its operations on acceptable terms or
Red Mountain Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements 2. Going Concern - (continued) at all, its business, financial condition and results of operations may be materially and adversely affected. As a result of the recurring losses from operations and a working capital deficiency, there is substantial doubt regarding the Company’s ability to continue as a going concern. The accompanying financial statements do not include any adjustments to reflect the possible future effects on the recoverability and classification of assets or the amounts and classifications of liabilities that may result from the possible inability of the Company to continue as a going concern.
3. Summary of Significant Accounting Policies Consolidation, basis of presentation and significant estimates The accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) and include the accounts of the Company and its wholly-owned subsidiaries. Intercompany accounts and transactions are eliminated. In preparing the accompanying financial statements, management has made certain estimates and assumptions that affect reported amounts in the financial statements and disclosures of contingencies. Significant assumptions are required in the valuation of proved oil and natural gas reserves, which affect the Company’s estimate of depletion expense as well as its impairment analyses. Significant assumptions also are required in the Company’s estimation of accrued liabilities, share-based compensation and asset retirement obligations. Changes in facts and circumstances may result in revised estimates and actual results may differ from these estimates.
Reclassification Certain amounts have been reclassified to conform with the current period presentation. The amounts reclassified did not have an effect on the Company’s results of operations or stockholders’ equity.
Cash and cash equivalents The Company considers all highly liquid debt instruments purchased with an original maturity of three months or less to be cash equivalents. At times, the amount of cash and cash equivalents on deposit in financial institutions exceeds federally insured limits. The Company monitors the soundness of the financial institutions and believes the Company’s risk is negligible.
Restricted cash Restricted cash is classified as current based on the terms of the agreement. Restricted cash at May 31, 2012 and 2011 represents cash held in U.S. banks as collateral for standby letters of credit issued in connection with the Company’s oil and natural gas production activities.
Financial instruments The carrying amounts of financial instruments, including cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities and long-term debt, approximate fair value as of May 31, 2012 and 2011.
Oil and natural gas properties Effective June 1, 2011, the Company follows the successful efforts method of accounting for its oil and natural gas producing activities. The change in accounting principle has been applied retroactively to prior periods. Costs to acquire mineral interests in oil and natural gas properties and to drill and equip development wells and related asset retirement costs are capitalized. Costs to drill exploratory wells are capitalized pending determination of whether the wells have proved reserves. If the Company determines that the wells do not have proved reserves, the costs are charged to expense. There were no exploratory wells capitalized pending determination of whether the wells have proved reserves at May 31, 2012 or 2011. Geological and
Red Mountain Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements 3. Summary of Significant Accounting Policies - (continued) geophysical costs, including seismic studies and costs of carrying and retaining unproved properties, are charged to expense as incurred. The Company capitalizes interest on expenditures for significant exploration and development projects that last more than six months while activities are in progress to bring the assets to their intended use. Through May 31, 2012, the Company had capitalized no interest costs because its exploration and development projects generally lasted less than six months. Costs incurred to maintain wells and related equipment are charged to expense as incurred.
On the sale or retirement of a complete unit of a proved property, the cost and related accumulated depreciation, depletion and amortization are eliminated from the property accounts, and the resultant gain or loss is recognized. On the retirement or sale of a partial unit of proved property, the cost is charged to accumulated depreciation, depletion and amortization, with a resulting gain or loss recognized in income.
Capitalized amounts attributable to proved oil and natural gas properties are depleted by the unit-of-production method over proved reserves using the unit conversion ratio of six Mcf of gas to one barrel of oil equivalent (“Boe”). The ratio of six Mcf of natural gas to one Boe is based upon energy equivalency, rather than price equivalency. Given current price differentials, the price for a Boe for natural gas differs significantly from the price for a barrel of oil.
It is common for operators of oil and natural gas properties to request that joint interest owners pay for large expenditures, typically for drilling new wells, in advance of the work commencing. This right to call for cash advances is typically found in the operating agreement that joint interest owners in a property adopt. The Company records these advance payments in prepaid and other current assets in its property account and releases this account when the actual expenditure is later billed to it by the operator.
On the sale of an entire interest in an unproved property for cash or cash equivalents, gain or loss on the sale is recognized, taking into consideration the amount of any recorded impairment if the property had been assessed individually. If a partial interest in an unproved property is sold, the amount received is treated as a reduction of the cost of the interest retained.
Impairment of long-lived assets The Company evaluates its long-lived assets for potential impairment in their carrying values whenever events or changes in circumstances indicate such impairment may have occurred. Oil and natural gas properties are evaluated for potential impairment by field. Other properties are evaluated for impairment on a specific asset basis or in groups of similar assets, as applicable. An impairment on proved properties is recognized when the estimated undiscounted future net cash flows of an asset are less than its carrying value. If an impairment occurs, the carrying value of the impaired asset is reduced to its estimated fair value, which is generally estimated using a discounted cash flow approach. If the results of an assessment indicate that the properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized.
Unproved oil and natural gas properties do not have producing properties. As reserves are proved through the successful completion of exploratory wells, the cost is transferred to proved properties. The cost of the remaining unproved basis is periodically evaluated by management to assess whether the value of a property has diminished. To do this assessment, management considers estimated potential reserves and future net revenues from an independent expert, the Company’s history in exploring the area, the Company’s future drilling plans per its capital drilling program prepared by the Company’s reservoir engineers and operations management and other factors associated with the area. Impairment is taken on the unproved property cost if it is determined that the costs are not likely to be recoverable. The valuation is subjective and requires management to make estimates and assumptions which, with the passage of time, may prove to be materially different from actual results.
Red Mountain Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements 3. Summary of Significant Accounting Policies - (continued) Revenue and accounts receivable The Company recognizes revenue for its production when the quantities are delivered to, or collected by, the purchaser. Prices for such production are generally defined in sales contracts and are readily determinable based on certain publicly available indices. All transportation costs are included in lease operating expense.
Accounts receivable - oil and natural gas sales consist of uncollateralized accrued revenues due under normal trade terms, generally requiring payment within 30 to 60 days of production. Accounts receivable - other consist of amounts owed from interest owners of the Company’s operated wells. No interest is charged on past-due balances. Payments made on all accounts receivable are applied to the earliest unpaid items. The Company reviews accounts receivable periodically and reduces the carrying amount by a valuation allowance that reflects its best estimate of the amount that may not be collectible.
Dependence on major customers For the fiscal year ended May 31, 2012, approximately 50% of the Company’s revenues were attributable to sales of oil to one customer, and approximately 41% of the Company’s revenues were received from one operator pursuant to a joint operating agreement. For the fiscal year ended May 31, 2011, the Company had no major customers, and approximately 95% of the Company's revenues was received from one operator pursuant to a joint operating agreement. The Company believes that there are potential alternative purchasers and that it may be necessary to establish relationships with new purchasers. However, there can be no assurance that the Company can establish such relationships and that those relationships will result in an increased number of purchasers. Although the Company is exposed to a concentration of credit risk, the Company believes that all of its purchasers are credit worthy. The Company had no bad debt for the fiscal years ended May 31, 2012 and 2011.
Other property Furniture, fixtures and equipment are carried at cost. Depreciation of furniture, fixtures and equipment is provided using the straight-line method over estimated useful lives ranging from three to ten years. Gain or loss on retirement or sale or other disposition of assets is included in income in the period of disposition.
Income taxes The Company is subject to U.S. federal income taxes along with state income taxes in Texas, New Mexico and Arkansas. When tax returns are filed, it is highly certain that some positions taken would be sustained upon examination by the taxing authorities, while others are subject to uncertainty about the merits of the position taken or the amount of the position that would be ultimately sustained. The benefit of a tax position is recognized in the financial statements in the period during which, based on all available evidence, management believes it is more likely than not that the position will be sustained upon examination, including the resolution of appeals or litigation processes, if any. Tax positions taken are not offset or aggregated with other positions. Tax positions that meet the more-likely-than-not recognition threshold are measured as the largest amount of tax benefit that is more than 50% likely of being realized upon settlement with the applicable taxing authority. The portion of the benefits associated with tax positions taken that exceeds the amount measured as described above is reflected as a liability for unrecognized tax benefits in the accompanying balance sheet along with any associated interest and penalties that would be payable to the taxing authorities upon examination. Interest and penalties associated with unrecognized tax benefits are classified as additional income taxes in the Company’s Consolidated Statements of Operations. The Company accrues interest and penalties, if any, related to unrecognized tax benefits as a component of income tax expense.
Deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to the differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using the tax rate in effect for the year in
Red Mountain Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements 3. Summary of Significant Accounting Policies - (continued) which those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the year of the enacted tax rate change. In addition, a valuation allowance is established to reduce any deferred tax asset for which it is determined that it is more likely than not that some portion of the deferred tax asset will not be realized.
Prior to its conversion to a corporation effective July 1, 2011, Black Rock Capital, LLC was organized as a limited liability company and as such was not generally subject to income taxes. Pro forma income tax provision presented in the Company’s Consolidated Statements of Operations for the fiscal year ended May 31, 2011 and footnote 4, reflects income tax provision on a pro forma basis after giving effect to the conversion of Black Rock Capital, LLC to a corporation, as if the conversion had occurred on June 1, 2010 and the Company was therefore subject to income taxes.
Asset retirement obligations Asset retirement obligations (“AROs”) associated with the retirement of tangible long-lived assets are recognized as liabilities with an increase to the carrying amounts of the related long-lived assets in the period incurred. The cost of the tangible asset, including the asset retirement cost, is depreciated over the useful life of the asset. AROs are recorded at estimated fair value, measured by reference to the expected future cash outflows required to satisfy the retirement obligations discounted at the Company’s credit-adjusted risk-free interest rate. Accretion expense is recognized over time as the discounted liabilities are accreted to their expected settlement value. If estimated future costs of AROs change, an adjustment is recorded to both the ARO and the long-lived asset. Revisions to estimated AROs can result from changes in retirement cost estimates, revisions to estimated inflation rates and changes in the estimated timing of abandonment.
Share-based compensation The Company measures and records compensation expense for all share-based payment awards to employees and outside directors based on estimated grant date fair values. The Company recognizes compensation costs for awards granted over the requisite service period based on the grant date fair value.
Earnings per common share The Company reports basic earnings per common share, which excludes the effect of potentially dilutive securities, and diluted earnings per common share, which includes the effect of all potentially dilutive securities, unless their impact is anti-dilutive.
Pro forma basic and diluted earnings per share and pro forma basic and diluted weighted average shares outstanding on the Company’s Consolidated Statements of Operations for the fiscal year ended May 31, 2011 reflects basic and diluted earnings per share and basic and diluted weighted average shares outstanding on a pro forma basis after giving effect to (i) the issuance of 27,000,000 shares of common stock to StoneStreet, (ii) the retirement of 225,000,000 shares of common stock in connection with the reverse merger and (iii) the conversion of Black Rock Capital, LLC to a corporation, as if these transactions had occurred on June 1, 2010.
Pro forma financial information As discussed in Note 1, Black Rock Capital, LLC was originally organized in the form of a limited liability company. Following closing of the reverse merger, effective July 1, 2011, its capital structure was changed to that of a corporation. The change resulted in the post-merger company becoming obligated for the tax liabilities for the portion of income generated subsequent to the date of the merger, whereas the previous income and associated liability was passed through to the Black Rock Capital, LLC members. Pro forma information reflected on the face of the Company’s Consolidated Statements of Operations reflects income tax provision, net income, basic and diluted earnings per share and basic and diluted weighted average shares outstanding for the fiscal year ended May 31, 2011 on a pro forma basis after giving effect to (i) the issuance
Red Mountain Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements 3. Summary of Significant Accounting Policies - (continued) of 27,000,000 shares of common stock to StoneStreet, (ii) the retirement of 225,000,000 shares of common stock in connection with the reverse merger and (iii) the conversion of Black Rock Capital, LLC to a corporation, as if these transactions had occurred on June 1, 2010. This presentation reflects the Company generating current deferred tax liability for earnings during the period presented.
Investments Investments in companies that are not consolidated, but over which the Company exercises significant influence, are accounted for under the equity method of accounting. Whether or not the Company exercises significant influence with respect to an investee depends on an evaluation of several factors, including, among others, ownership level. Under the equity method of accounting, an investee company’s accounts are not reflected within the Company’s Consolidated Balance Sheets and Consolidated Statements of Operations; however, the Company’s share of the earnings or losses of the investee company is reflected in the Company’s Consolidated Statements of Operations and the Company’s carrying value in an equity method investee company is reflected in the Company’s Consolidated Balance Sheets. The Company evaluates these investments for other-than-temporary declines in value each quarterly period. Any impairment found to be other than temporary would be recorded through a charge to earnings.
Recent Accounting Pronouncements In May 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2011-04, Fair Value Measurements (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs (“ASU 2011-04”). ASU 2011-04 changes the wording used to describe many of the requirements in GAAP for measuring fair value and for disclosing information about fair value measurements to ensure consistency between GAAP and International Financial Reporting Standards (“IFRS”). ASU 2011-04 also expands the disclosures for fair value measurements that are estimated using significant unobservable (Level 3) inputs. This new guidance is to be applied prospectively. ASU 2011-04 became effective for interim and annual periods beginning after December 15, 2011. The adoption of this amendment did not have a material impact on the Company’s consolidated financial statements.
On June 16, 2011, the FASB issued ASU No. 2011-05 Comprehensive Income (Topic 220): Presentation of Comprehensive Income (“ASU 2011-05”). ASU 2011-05 requires entities to report items of other comprehensive income on either part of a single contiguous statement of comprehensive income or in a separate statement of comprehensive income immediately following the statement of income. On December 23, 2011, the FASB issued an update to this pronouncement, ASU No. 2011-12 Comprehensive Income (Topic 220): Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05. The update defers the specific requirement to present items that are reclassified from accumulated other comprehensive income to net income separately with their respective components of net income and other comprehensive income. While early adoption is permitted, the amendments are effective for fiscal years, and interim periods within those years, beginning after December 15, 2011 and must be applied retrospectively. Presently, the Company does not have any transactions which require the reporting of comprehensive income; therefore, the Company does not anticipate any material impact from this pronouncement.
On December 16, 2011, the FASB issued ASU No. 2011-11 Balance Sheet (Topic 210), Disclosures about Offsetting Assets and Liabilities (“ASU 2011-11”). ASU 2011-11 requires entities to disclose both gross information and net information about both instruments and transactions eligible for offset in the statement of financial position and instruments and transactions subject to an agreement similar to a master netting arrangement. Application of ASU 2011-11 is required for annual reporting periods beginning on or after January 1, 2013 and interim periods within those annual periods. The Company does not expect the adoption of this amendment to have a material impact on its consolidated financial statements.
Red Mountain Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements 4. Change in Accounting Policy The Company elected to adopt the successful efforts method of accounting for accounting of its oil and natural gas activities, effective June 1, 2011. The change from the full cost method to successful efforts method is a change in accounting principle. This change in accounting principle is deemed to be material in reporting the Company’s financial statements and therefore the change must be retrospectively adjusted for the cumulative effect for the prior fiscal year. The Company believes the successful efforts method of accounting provides more transparency in presenting the Company’s successes or failures and will more fairly reflect the true cost of its properties and the reserves directly associated with those properties. Further, the successful efforts method of accounting is the preferred method of accounting for oil and natural gas properties. Under this method, property acquisition costs, whether the property is proved or unproved, are capitalized as incurred. For other costs incurred under this method, a direct relationship between costs incurred and specific reserves discovered is required before costs are permitted to be capitalized. Costs that cannot be directly related to the discovery of specific oil and natural gas reserves are expensed immediately as incurred.
The change resulted in a net increase in depletion and impairment expense of $1.0 million and a net decrease of $0.3 million for the fiscal years ended May 31, 2012 and 2011, respectively. There was a $1.0 million decrease in gross oil and natural gas properties for the fiscal year ended May 31, 2012 between the two methods for impairment expense incurred by the Company. There were no changes to gross oil and natural gas properties due to impairment for the fiscal year ended May 31, 2011. The changes increased loss from operations by $1.0 million for the fiscal year ended May 31, 2012 as reported on the Company’s Consolidated Statements of Operations and decreased retained earnings by $1.0 million as reported on the Company’s Consolidated Balance Sheets and Consolidated Statements of Stockholders’ Equity. The change did not impact cash flows from operations, investing or financing activities.
Red Mountain Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements 4. Change in Accounting Policy - (continued) The following tables compare the Company’s statement of operations and balance sheet information under the successful efforts method of accounting and the full cost method of accounting:
(1) Reflects net income (loss), income tax provision, basic and diluted net income per share and basic and diluted weighted average common shares outstanding for the fiscal year ended May 31, 2011 on a pro forma basis after giving effect to (i) the issuance of 27,000,000 shares of common stock to StoneStreet, (ii) the retirement of 225,000,000 shares of common stock in connection with the reverse merger and (iii) the conversion of Black Rock Capital, LLC to a corporation, as if these transactions had occurred on June 1, 2010 and the Company was therefore subject to income taxes.
Red Mountain Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements 4. Change in Accounting Policy - (continued)
5. Investment in Cross Border Resources, Inc. On May 23, 2011, the Company entered into a securities purchase agreement with Cross Border Resources, Inc. (“Cross Border”), pursuant to which the Company purchased 2,136,164 units of Cross Border for a purchase price of $3.2 million. Each unit included one share of common stock of Cross Border and one warrant to acquire an additional share of common stock of Cross Border. The warrants have an exercise price of $2.25 per share. The warrants are exercisable until May 26, 2016. As of May 31, 2011, the Company owned approximately 13.2% of Cross Border’s outstanding common stock valued at $4.8 million based on the closing market price on that date.
During the fiscal year ended May 31, 2012, the Company entered into several stock purchase and sale agreements with a limited number of stockholders pursuant to which the Company acquired 2,701,261 shares of common stock of Cross Border from such stockholders in exchange for the issuance of 4,803,957 shares of the Company's common stock and $287,532 in cash. As of May 31, 2012, the Company owned approximately 30.0% of Cross Border’s outstanding common stock valued at $9.0 million based on the closing market price on that date.
Due to increased ownership in Cross Border during the fiscal year ended May 31, 2012, the Company retroactively applied the equity method of accounting to all periods presented. The difference between the Company’s gross investment of $7.6 million in Cross Border and equity share of net assets totaling $5.2 million has been allocated to the Company’s investment in Cross Border’s oil and natural gas properties. The excess basis of the Company’s gross investment over the equity share of net assets is depleted each quarter based upon Cross Border’s depletion rate calculated on its oil and natural gas properties. The depletion for the fiscal year ended May 31, 2012 was $243,921.
Due to timing differences in the Company’s and Cross Border’s fiscal year ends and quarterly periods and due to the lack of financial information for Cross Border for the current quarterly period, the Company books its share of Cross Border’s financial activity on a two-month lag. In accordance with the equity method of accounting, the investment is initially recorded at cost and adjusted to reflect the Company’s share of changes in Cross Border’s capital. It is further adjusted to recognize the Company’s share of Cross Border’s earnings as they occur, rather than as dividends or other distributions are received. The Company’s share of
Red Mountain Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements 5. Investment in Cross Border Resources, Inc. - (continued) Cross Border’s earnings would also include any other-than-temporary declines in fair value recognized during the period. Changes in the Company’s proportionate share of the underlying equity of Cross Border which result from Cross Border’s issuance of additional equity securities are recognized as increases or decreases in stockholders’ equity, net of any related tax effects. The Company recognized a loss in its equity investment for net losses by Cross Border of $71,998 and $0 for the fiscal years ended May 31, 2012 and 2011, respectively, in the Company’s Consolidated Statements of Operations.
The following represents Cross Border’s summarized unaudited financial information as of and for the twelve months ended March 31, 2012 and 2011:
As of May 31, 2012 and 2011, the Company held 2,136,164 common stock purchase warrants for the purchase of common stock of Cross Border. The warrants have an exercise price of $2.25 per share and are exercisable until May 26, 2016. The Company valued the warrants as of May 31, 2012 and 2011 at $1.5 million and $1.2 million, respectively, using the Black-Scholes valuation model with a volatility based on the historical closing price of common stock of industry peers and the closing price of Cross Border’s common stock on the OTCBB at year-end. The changes in fair value have been recorded in unrealized gain (loss) on investment in Cross Border warrants in the Company’s Consolidated Statements of Operations. In determining this valuation, the Company used the following inputs:
6. Acquisitions In April 2011, the Company acquired two oil and natural gas leases located in the Madera Prospect in Lea County, New Mexico. These fields consist of approximately 1,925 gross acres (1,154 net to the working interests). The purchase price of this property was approximately $4.8 million in cash, including approximately $27,000 in acquisition related costs. The fair value of assets acquired was $4.9 million, offset by an asset retirement obligation of $0.1 million. At acquisition, the two leases comprised a 100% working
Red Mountain Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements 6. Acquisitions - (continued) interest and a 75% net revenue interest in one producing well, a 55.5% working interest and a 41.6% net revenue interest in a second producing well and a 41.4% working interest and a 31.0% net revenue interest in a shut-in well.
No revenue or earnings from the acquired Madera properties are included in the Company's Consolidated Statements of Operations for the twelve months ended May 31, 2011.
The following table presents unaudited pro forma comparative data that reflects the Company's revenue, income before income taxes, net income and income per share for the twelve months ended May 31, 2011, as if the Madera properties had been acquired as of June 1, 2010:
In April 2012, the Company acquired oil and natural gas interests in approximately 547 gross and net acres in the East Ranch Prospect in Pecos County, Texas for cash consideration of $421,000. In April 2012, the Company also acquired oil and natural gas interests in 989 gross and net acres in the West Ranch Prospect in Pecos County, Texas for cash consideration of $677,000. The Company owns a 100% working interest and an 80% net revenue interest in these properties.
On November 1, 2011, the Company acquired oil and natural gas interests plus surface property in Ector County, Texas (the “Cowden Lease”) for $1.2 million. The fair value of assets acquired was $1.6 million, offset by an asset retirement obligation of $0.4 million. At acquisition, the Cowden Lease contained 17 producing wells. The Company acquired a 100% working interest with a 75.0% net revenue interest in two leases; a 100% working interest with a 79.4% net revenue interest in one lease; and a 75.0% working interest with a 62.8% net revenue interest in one lease.
In August 2011, the Company acquired a 58% working interest with a 40% net revenue interest in unproved oil and gas interests within the Shafter Lake San Andres field in Andrews County, Texas for $250,000 in cash and 250,000 shares of the Company’s common stock. On the date of issuance, the common stock was valued at $250,000, consistent with the price of the Company’s common stock sold in a private placement that commenced in March 2011 (the “private placement value”), as the fair value of assets acquired was $500,000.
On August 16, 2011, the Company acquired a 100% working interest with a 75% net revenue interest in the unproved oil and natural gas interests within the Martin Lease in Andrews County, Texas in exchange for 320,000 shares of the Company’s common stock. The fair value of the assets acquired and the shares issued was $320,000 based on the market approach and private placement value, respectively.
Red Mountain Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements 7. Oil and Natural Gas Properties and Other Property and Equipment Oil and natural gas properties The following table sets forth the capitalized costs under the successful efforts method for oil and natural gas properties:
At May 31, 2012, the capitalized costs of the Company’s oil and natural gas properties included $8.1 million relating to acquisition costs of proved properties which are being amortized by the unit-of-production method using total proved reserves and $17.0 million relating to exploratory well costs and additional development costs which are being amortized by the unit-of-production method using proved developed reserves.
During the fiscal year ended May 31, 2012, the Company incurred approximately $0.3 million in exploratory drilling costs, of which all amounts were included in exploration expense. The Company had no transfers of exploratory well costs to proved properties during the fiscal years ended May 31, 2012 and 2011.
The Company recorded a $0.1 million expense on its unproved oil and natural gas properties during the fiscal year ended May 31, 2012 attributable to expired leases on its Pawnee Prospect and the abandonment of its Bayou Darbonne Prospect. The expense is included in exploration expense in the Company’s Consolidated Statements of Operations.
Capitalized costs related to proved oil and natural gas properties, including wells and related equipment and facilities, are evaluated for impairment based on the Company’s analysis of undiscounted future net cash flows. If undiscounted future net cash flows are insufficient to recover the net capitalized costs related to proved properties, then the Company recognizes an impairment charge in income equal to the difference between the carrying value and the estimated fair value of the properties. Estimated fair values are determined using discounted cash flow models. The discounted cash flow models include management’s estimates of future oil and natural gas production, operating and development costs and discount rates. The Company recorded $1.0 million in impairment charges on its proved properties for the fiscal year ended May 31, 2012, primarily due to a decline in reserves and production associated with wells on its Pawnee Prospect, which was included in depreciation, depletion, amortization and impairment in the Company’s Consolidated Statements of Operations.
Uncertainties affect the recoverability of these costs as the recovery of the costs outlined above are dependent upon the Company obtaining and maintaining leases and achieving commercial production or sale.
Other property and equipment The historical cost of other property and equipment, presented on a gross basis with accumulated depreciation and amortization is summarized as follows:
Red Mountain Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements 8. Asset Retirement Obligations The following table presents the balance and activity of the Company’s ARO for the periods indicated:
9. Fair Value Measurements Fair value measurements are based upon inputs that market participants use in pricing an asset or liability, which are classified into two categories: observable inputs and unobservable inputs. Observable inputs represent market data obtained from independent sources, whereas unobservable inputs reflect a company’s own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. These two types of inputs are further prioritized into the following fair value input hierarchy:
• Level 1 - quoted prices for identical assets or liabilities in active markets.
• Level 2 - quoted prices for similar assets or liabilities in active markets; quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability (e.g. interest rates) and inputs derived principally from or corroborated by observable market data by correlation or other means.
• Level 3 - unobservable inputs for the asset or liability.
The fair value input hierarchy level to which an asset or liability measurement in its entirety falls is determined based on the lowest level input that is significant to the measurement in its entirety.
The following table summarizes the valuation of the Company’s financial assets and liabilities at May 31, 2012 and 2011:
Red Mountain Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements 9. Fair Value Measurements - (continued)
The following is a summary of changes to fair value measurements using Level 3 inputs during the fiscal year ended May 31, 2012:
The Company accounts for additions to AROs and oil and natural gas at fair value on a non-recurring basis. The following tables summarize the valuation of the Company’s assets and liabilities that were accounted for at fair value on a non-recurring basis as of May 31, 2012 and 2011.
The Company’s accounting policies for AROs are discussed in Note 3, and reconciliations of the Company’s AROs are provided in Note 8 for the periods presented. For purposes of fair value measurement,
Red Mountain Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements 9. Fair Value Measurements - (continued) the Company determined that additions to AROs should be classified as Level 3. The Company recorded additions to AROs of approximately $632,000 and $231,000 in fiscal years 2012 and 2011, respectively.
The Company’s accounting policies for oil and gas properties are discussed in Note 3. For purposes of fair value measurement, the Company determined that oil and natural gas properties should be classified as Level 3. The Company recorded impairment to its oil and natural gas properties of approximately $1.0 million in fiscal 2012 related to proved reserves associated with its Pawnee Prospect. Oil and natural gas properties are evaluated for potential impairment by field. Impairment on proved properties is recognized when the estimated undiscounted future net cash flows of an asset are less than its carrying value. If impairment occurs, the carrying value of the impaired asset is reduced to its estimated fair value, which is generally estimated using a discounted cash flow approach. If the results of an assessment indicate that the properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized.
10. Debt As of the dates indicated, our debt consisted of the following:
Line of credit with First State Bank On June 18, 2010, Black Rock, Mr. Barksdale and Ernest Bartlett, the managing member of a shareholder of the Company, entered into a three year, $3.5 million line of credit with FSB. Loans borrowed under the line of credit accrue interest at the bank’s reference rate plus 275 basis points (6.0% at May 31, 2012) and are payable on demand, or if no demand is made, mature on June 18, 2013. The line of credit is secured by a lien against (i) the Company’s Villarreal, Frost Bank, Resendez and La Duquesa properties, (ii) 2,136,164 shares of Cross Border common stock owned by the Company and (iii) certain property owned by Mr. Bartlett. As co-signers, Mr. Barksdale and Mr. Bartlett are personally obligated for the repayment of borrowings under this line of credit.
Pursuant to the terms of the line of credit, until amounts outstanding under the line of credit are repaid, Black Rock may not, without the lender’s consent, among other things and subject to certain exceptions, (i) cease business or engage in any new line of business that is materially different from its current business; (ii) enter into any merger, consolidation, or acquisition of substantially all of the assets of another entity; (iii) materially change its legal structure, management, ownership or financial condition; (iv) effect a domestication, conversion or interest exchange; (v) incur indebtedness; or (vi) sell, lease, assign, transfer or dispose of substantially all of its assets.
Red Mountain Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements 10. Debt - (continued) The promissory note has substantially the same events of default as the June 29, 2011 promissory note discussed below under “- Replacement Note and Bamco Note Receivable.” In addition, an event of default includes the removal of Mr. Barksdale as president and chief executive officer of Black Rock.
On June 18, 2010, Black Rock, Mr. Barksdale and Mr. Bartlett borrowed $3.5 million and issued a $3.5 million promissory note to FSB under the line of credit. Pursuant to the promissory note, the loan is payable on demand, or if no demand is made, is due on June 18, 2013. Borrowings may be repaid at any time without penalty. If FSB declares a default under the loan, interest will accrue on the principal at a rate of 18% per annum. In addition, pursuant to the promissory note, First State Bank of Lonoke will lock box all funds from net production due to Black Rock. Funds received are first applied to accrued interest, and any remaining amount of funds is applied to the outstanding principal.
As of May 31, 2012, the Company had $1.8 million outstanding and $1.7 million remaining available for borrowing under the line of credit and was in compliance with all of the covenants under the line of credit described above. Because the promissory note has a subjective acceleration clause and a requirement to maintain a lock box arrangement it has been classified as a current liability.
Notes Payable Replacement Note and Bamco Note Receivable As a condition to the reverse merger pursuant to the Share Exchange Agreement with Black Rock and StoneStreet, FSB required Black Rock to assume and acquire a loan of $2.7 million from FSB (the “Bamco Note Receivable”) that had previously been issued by Bamco Gas, LLC (“Bamco”). Bamco is in receivership, and Mr. Barksdale is the receiver. As a result, the note payable from Bamco to FSB was cancelled, and Black Rock executed a new note to FSB (the “Replacement Note”), which became the only outstanding note due to FSB related to Bamco. Due to the uncertainty about collection or realizing the value of the Bamco Note Receivable, management deemed it necessary to fully impair the value of the Bamco Note Receivable, which was recorded as a loss on note receivable of $2.7 million in the Company’s Consolidated Statement of Operations for the fiscal year ended May 31, 2012. No interest income was recognized on the Bamco Note Receivable.
The Replacement Note accrues interest at a rate of 6% per annum. If FSB declares a default, interest will accrue on the principal at a rate of 18% per annum. The Replacement Note is payable on demand, or if no demand is made, must be paid on June 29, 2014. In addition, the Company must make a principal payment of $540,000 on June 29, 2013. The note may be prepaid at any time without penalty.
The Replacement Note is secured by (i) a pledge of all of the common stock of Black Rock; (ii) 2,000,000 shares of common stock of the Company held by StoneStreet and (iii) a lien against the Company’s Villarreal, Frost Bank, Resendez and La Duquesa properties. As co-signers, Mr. Barksdale and Mr. Bartlett are personally obligated for the repayment of borrowings under this Replacement Note.
Pursuant to the terms of a commercial loan agreement related to the Replacement Note, until amounts outstanding under the loan are repaid, Black Rock may not, without the lender’s consent, among other things and subject to certain exceptions, (i) cease business or engage in any new line of business that is materially different from its current business; (ii) enter into any merger, consolidation, or acquisition of substantially all of the assets of another entity; (iii) materially change its legal structure, management, ownership or financial condition; (iv) effect a domestication, conversion or interest exchange; (v) incur indebtedness; or (vi) sell, lease, assign, transfer or dispose of substantially all of its assets.
An event of default includes, among other events, the following occurrences by any of Black Rock, Mr. Barksdale or Mr. Bartlett: (i) failure to make payment when due; (ii) insolvency or bankruptcy of the Company, any co-signer, endorser, surety or guarantor; (iii) the death or declaration of incompetency of any co-signer or majority owner or partner; (iv) merger; (v) dissolution; (vi) reorganization; (vii) name change;
Red Mountain Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements 10. Debt - (continued) (viii) failure to perform any condition or keep any promise or covenant under the loan agreement; (ix) default of any other agreements with FSB; (x) a misrepresentation in any verbal or written statement or financial information; (xi) failure to satisfy or appeal a judgment; (xii) use of the property securing the loan in a manner or for a purpose that threatens confiscation by a legal authority; (xiii) a transfer of all or substantially all of Black Rock or the co-signer’s property; (xiv) a determination by FSB that the value of its security has declined or is impaired; (xv) a material change in business, ownership, management or financial condition; or (xvi) FSB’s determination in good faith that its prospect for payment are impaired for any reason.
In addition, pursuant to the Replacement Note, First State Bank of Lonoke will lock box all funds from net production due to Black Rock. Funds received are first applied to accrued interest, and any remaining amount of funds is applied to the outstanding principal.
As of May 31, 2012, the Company had $2.3 million outstanding under the Replacement Note and was in compliance with all of the covenants under the Replacement Note described above. Because the Replacement Note has a subjective acceleration clause and a requirement to maintain a lock box arrangement it has been classified as a current liability.
Senior secured promissory note The Company issued a senior secured promissory note dated November 16, 2011 payable to the Lenders in an aggregate principal amount of $4.0 million. The senior secured promissory note accrues interest at a rate of 12% per annum, is payable monthly and matures on the earlier of November 16, 2012 or the date the senior secured promissory note is terminated, whether by its terms, by prepayment or by acceleration. Upon an event of default, interest will accrue on all outstanding principal and interest at a rate of 18% above the per annum rate otherwise applicable.
All of the Company’s obligations are guaranteed, jointly and severally, by Black Rock and RMR Operating, LLC, wholly owned subsidiaries of the Company. The promissory note is the Company’s senior obligation and is secured by (i) second priority real property liens against its Villarreal, Frost Bank, Resendez and La Duquesa properties, (ii) a first priority real property lien against all of its then existing properties, and (iii) a stock pledge agreement with the Lenders, dated November 30, 2011, with respect to a second lien on 2,136,164 shares of Cross Border common stock owned by the Company.
The promissory note contains customary non-financial covenants governing the conduct of the Company’s business and the maintenance of its properties.
Under the terms of the senior secured promissory note, for so long as the promissory note is outstanding, the Company is prohibited from incurring any future indebtedness secured by all or any portion of the collateral without the prior written consent of Lenders.
An event of default under the senior secured promissory note includes, among other things, (i) failure to make payments when due; (ii) any representation or warranty proves false; (iii) failure to comply with any covenant; (iv) violation of any provision of the note; (v) bankruptcy or insolvency; (vi) the Lenders determine in their sole and absolute discretion that the promissory note or related documents shall, for any reason, fail or cease to create a valid and perfected lien on or security interest in any or all of the collateral or the collateral shall be compromised, encumbered, cancelled, expired, terminated or otherwise rescinded; (vii) the Lenders determine in their sole but reasonable discretion that the Company is unable in the ordinary course of business to pay its debts as they are due or its debts exceed the fair market value of all of its assets and property; or (viii) a default under any of the Company’s material agreements.
As of May 31, 2012, the Company had $4.0 million outstanding under the senior secured promissory note and was in compliance with all of the covenants under the senior secured promissory note described above.
Red Mountain Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements 10. Debt - (continued) Unsecured promissory notes Black Rock issued an unsecured promissory note dated March 4, 2011 to Capital Growth Investment Trust, a shareholder of the Company, in the principal amount of $90,000. The promissory note accrued interest at 3.25% per annum and, in May 2011, Black Rock repaid the promissory note in full.
Black Rock issued an unsecured promissory note dated March 4, 2011, as amended September 28, 2011, to Robert Hersov, an unaffiliated lender, in the principal amount of $150,000. The proceeds from the promissory note were used to fund Black Rock's acquisition of the Madera assets located in New Mexico. The promissory note, as amended, accrued interest at 3.25% per annum and matured on November 30, 2011.
The Company issued an unsecured promissory note to Robert Hersov in February 2011, as amended in September 2011, and to Fiordaliso Investments Limited and Capital Growth Investment Trust in March and April 2011, in an aggregate principal amount of $212,500. Fiordaliso Investments Limited and Capital Growth Investment Trust were shareholders of the Company and Robert Hersov was an unaffiliated lender. The proceeds from the promissory note were used to fund working capital. The promissory notes, as amended, accrued interest at 10.0% per annum and matured on November 30, 2011.
The Company issued an unsecured promissory note dated May 24, 2011, as amended in September 2011, to each of Michael J. Garnick, Bel-Cal Properties and William F. Miller, III, each an unaffiliated lender, in an aggregate principal amount of $2,450,000. These promissory notes, as amended, accrued interest at 10% per annum and matured on November 30, 2011. The proceeds from the promissory notes were used to purchase a portion of the Cross Border units and shares. In July and August 2011, Black Rock repaid a portion of the amounts owed under the promissory notes held by Mr. Garnick, Bel-Cal Properties and Mr. Miller. On October 25, 2011, Mr. Garnick entered into a new 10% convertible note providing for the remaining $200,000 owed to him to be due on April 15, 2013 and cancelled the old promissory note. As a condition for issuing the promissory notes, on November 16, 2011, the Company issued an aggregate of 600,000 shares of its common stock to Mr. Garnick, Bel-Cal Properties and Mr. Miller. On the date of issuance, the common stock was valued at $600,000 consistent with the private placement value, which was recorded as a debt issuance cost. The Company believes that $1.00 per share represented the fair value per share of the Company’s common stock on the date of issuance.
On November 30, 2011, the Company repaid in full all the remaining principal and interest related to the promissory notes payable to Mr. Hersov, Fiordaliso Investments Limited, Capital Growth Investment Trust, Bel-Cal Properties and Mr. Miller, and the convertible note issued to Mr. Garnick, which amounted to $1.4 million.
Secured promissory note On June 15, 2010, the Company issued a $200,060 secured promissory note to FSB. The promissory note accrued interest at 6.0% per annum and was due June 15, 2011. The note was secured by a first security lien against the Company’s Frost Bank Prospect. In addition to a security interest in the Frost Bank Prospect, the principal member of the Company and another individual who is a related party personally guaranteed the note. In addition, the related party provided a mortgage in favor of FSB on certain property owned by the related party as additional collateral. As of May 31, 2011, the Company had $10,000 outstanding under the promissory note. The remaining balance was repaid in full subsequent to May 31, 2011.
Notes payable - related party On April 29, 2011, Black Rock Capital, LLC issued a $4.9 million non-interest bearing secured commercial promissory note to the Company. The promissory note, as amended, was due June 22, 2011. On May 24, 2011, Black Rock Capital, LLC issued a $850,000 non-interest bearing commercial promissory note to the Company, due June 15, 2011. As of May 31, 2011, the Company had $5.8 million outstanding under these promissory notes. In connection with the reverse merger between Black Rock Capital, LLC and the Company in June 2011, the Company eliminated the outstanding notes payable.
Red Mountain Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements 10. Debt - (continued) Convertible notes payable On November 25, 2011, the Company issued convertible promissory notes to each of Hohenplan Privatstiftung, Personalversorge der Autogrill Schweiz AG and SST Advisors, Inc. in an aggregate principal amount of $2.75 million. The convertible promissory notes are due and payable on November 25, 2013 and bear interest at a rate of 10% per annum. Prior to repayment, the holders of the convertible promissory notes have the option of converting all or any portion of the unpaid balance of the convertible promissory notes (including accrued and unpaid interest) into shares of the Company’s common stock at a conversion price equal to $1.00 per share, subject to standard anti-dilution provisions. The value of the beneficial conversion feature of the three convertible promissory notes was $1.2 million as of May 31, 2012 based on the difference between the conversion price and the Company’s closing price per common share. The beneficial conversion feature has been recorded as a discount to the convertible notes payable and to additional paid-in-capital and will be amortized to interest expense over the life of the convertible promissory notes. The Company amortized $410,868 to interest expense during the fiscal year ended May 31, 2012.
The following is a schedule by year of future principal payments required under the notes and line of credit described above as of May 31, 2012:
11. Earnings Per Share The Company reports basic earnings per common share, which excludes the effect of potentially dilutive securities, and diluted earnings per common share, which includes the effect of all potentially dilutive securities unless their impact is anti-dilutive. The following are reconciliations of the numerators and denominators of basic and diluted earnings per share:
(1) Warrants to purchase approximately 1,617,590 shares of the Company’s common stock and 45,297 shares payable for director compensation were excluded from this calculation because they were anti-dilutive during the fiscal year ended May 31, 2012.
Red Mountain Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements 11. Earnings Per Share - (continued)
12. Equity As of May 31, 2012, the Company was authorized to issue (i) 500,000,000 shares of common stock, par value $0.00001 per share, of which 86,932,000 shares were issued and 85,100,000 shares were outstanding, and (ii) 100,000,000 shares of preferred stock, par value $0.0001 per share, none of which was outstanding.
On March 22, 2011, the Company entered into the Share Exchange Agreement with Black Rock Capital, LLC and StoneStreet, the sole shareholder of Black Rock Capital, LLC. Alan W. Barksdale, the Company’s current president, chief executive officer and chairman of the board, was the president and the sole member of Black Rock Capital, LLC and the sole owner and the president of StoneStreet. On June 22, 2011, pursuant to the Share Exchange Agreement, the Company issued 27,000,000 shares of common stock to StoneStreet in exchange for 100% of the interests in Black Rock Capital, LLC. Concurrently with the closing, the Company retired 225,000,000 shares of common stock for no additional consideration.
On June 22, 2011, Mr. Barksdale and StoneStreet entered into a lock-up agreement with the Company with respect to 18,000,000 shares of common stock then held by StoneStreet. On September 12, 2011, StoneStreet assigned 7,000,000 shares subject to the lock-up agreement to several third parties after receiving the consent from the Company to release it from the lockup restrictions with respect to such shares. In connection with the assignment, the transferees agreed to have 100,000 shares of common stock cancelled in exchange for the Company releasing the shares from the lockup restrictions.
Beginning in March 2011, the Company commenced a private placement of its shares of common stock at an offering price of $1.00 per share, which terminated in November 2011. Through November 2011, the Company sold 16,206,000 shares of its common stock raising gross proceeds of $16.2 million, of which 10,136,000 shares of common stock were issued and $10.0 million was received subsequent to closing of the reverse merger with Black Rock in June 2011. Randell K. Ford participated in the private placement, purchasing 750,000 shares of common stock. Mr. Ford became a director of the Company in November 2011. Offering expenses for the private placement during the fiscal year ended May 31, 2012 totaled $3.7 million, consisting of $738,302 paid in cash and the issuance of 313,125 shares of the Company’s common stock and warrants to purchase 892,500 shares of common stock for commissions paid to brokers that participated in the transaction. The warrants are exercisable until April 30, 2014 and have an exercise price of $1.20 per share. On the date of issuance, the shares of common stock were valued at $171,250 and the warrants were valued at $555,504. Management determined the fair value of the shares consistent with the private placement value. Management determined the fair value of the warrants based upon the Black-Scholes option model with a volatility based on the historical closing price of common stock of industry peers, remaining term until April 30, 2014 and the closing price of the Company’s common stock on the OTCBB on the date of issuance. The range for volatility and remaining term was 83% to 94% and 2.3 to 2.7 years, respectively.
Red Mountain Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements 12. Equity - (continued) In connection with the private placement, on July 20, 2011 and September 12, 2011, the Company granted three investors each the right to purchase an additional $3.0 million worth of shares of the Company’s common stock. If exercised, the shares would be sold to the investor at a price equal to the lesser of (i) $1.10 per share or (ii) the average closing price of the Company’s common stock during the period from five days prior to the investor exercising its right to purchase the shares and ending five days after such exercise. The Company accounts for the warrants as a derivative liability since the final exercise price is contingent upon market prices. Changes in fair value are recorded as unrealized gain on warrant liability in the Company’s Consolidated Statements of Operations. The Company recorded $2.2 million of issuance costs representing the grant date fair value. Management determined the fair value of the warrants using a probability weighted Black-Scholes option model with a volatility based on the historical closing price of common stock of industry peers and the closing price of the Company’s common stock on the OTCBB on the date of issuance. The range for volatility and remaining term was 93% to 94% and 0.3 to 0.45, respectively.
On December 21, 2011, one investor exercised its right and purchased an aggregate of 2,727,272 shares of common stock at $1.10 per share raising gross proceeds of $3.0 million. We incurred cash and non-cash offering costs and broker commissions of $300,000 and $245,729, respectively. During February, March, and April of 2012, the other two investors (and their assignees) exercised a portion of their rights and purchased 4,310,818 shares of common stock at $1.10 per share raising gross proceeds of $4.7 million. At May 31, 2012, 136,364 of those shares had not yet been issued and 1,143,725 warrants expired unexercised. In connection with the exercises by the remaining investors (and their assignees) of their rights, the Company issued warrants to purchase an aggregate of 425,090 shares of common stock as a portion of commissions paid to the brokers that participated in the initial private placement. The warrants are exercisable until April 30, 2014 and have an exercise price of $1.20 per share. Management determined the fair value based on the same methodology as the warrants issued to investors discussed above. The volatility and remaining term was 77% and two years, respectively.
In November 2011, the Company issued 200,000 shares of its common stock to a broker as payment for a fee related to obtaining the $4.0 million loan from the Lenders. On the date of issuance, the common stock was valued at $318,000 based on the closing price of the Company’s common stock on the OTCBB on the date of issuance.
On December 30, 2011, the Company entered into a consulting agreement with St. Bernard Financial Services, Inc. In connection with the agreement the Company paid the consultants $100,000 in cash and issued them 100,000 shares of common stock. On the date of issuance, the shares of common stock were valued at $152,000 based on the closing price of the Company’s common stock on the OTCBB on the date of issuance.
During the fiscal year ended May 31, 2012, the Company issued an aggregate of 4,803,957 shares of common stock and paid an aggregate of $287,532 in cash to certain shareholders of Cross Border as consideration for the purchase of an aggregate of 2,701,261 shares of Cross Border’s common stock, including 218,535 shares of Cross Border’s common stock purchased from Mr. Ford on August 12, 2011, in exchange for the issuance of 273,169 shares of the Company’s common stock. The aggregate value of the common stock issued during the fiscal year ended May 31, 2012 was $4.8 million, including the common stock issued to Mr. Ford which was valued at $346,925. Management determined the fair value based on the closing price of the Company’s common stock on the OTCBB on the date of issuance.
Red Mountain Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements 13. Income Taxes Income tax expense differs from the statutory amounts as follows:
Deferred taxes are provided for the temporary differences between the financial reporting bases and the tax bases of our assets and liabilities. The temporary differences that give rise to deferred tax assets were as follows:
At May 31, 2012, the Company had approximately $18.3 million of pre-tax net operating loss carryforwards (“NOLs”). These carryforwards begin to expire in 2030.
The Company continually assesses both positive and negative evidence to determine whether it is more likely than not that deferred tax assets can be realized prior to their expiration. Management monitors Company-specific, oil and natural gas industry and worldwide economic factors and assesses the likelihood that the Company's NOLs and other deferred tax attributes in the United States, state, and local tax jurisdictions will be utilized prior to their expiration. The Company establishes a valuation allowance to reduce any deferred tax asset for which it is determined that it is more likely than not that some portion of the deferred tax asset will not be realized. At May 31, 2012, the Company had a valuation allowance of $3.8 million related to its deferred tax assets.
As of May 31, 2012, the Company had no unrecognized tax benefits. Black Rock Capital, LLC’s tax returns for the years ended December 31, 2010, 2009, and 2008 and stub period ended June 30, 2011, and Red Mountain Resources, Inc.’s tax returns for the fiscal year ended May 31, 2012, stub period ended May 31, 2011, and the fiscal years ended January 31, 2011 and January 31, 2010, are open to examination by the major taxing jurisdictions to which the Company is subject.
Red Mountain Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements 14. Commitments and Contingencies Litigation The Company may from time to time be involved in various claims, lawsuits, and disputes with third parties, or breach of contract incidental to the operations of its business. The Company is not currently involved in any litigation that it believes could have a materially adverse effect on its financial conditions or results of operations.
Environmental issues The Company is engaged in oil and natural gas exploration and production and may become subject to certain liabilities as they relate to environmental clean up of well sites or other environmental restoration procedures as they relate to the drilling of oil and natural gas wells and the operation thereof. In connection with the Company’s acquisition of existing or previously drilled well bores, the Company may not be aware of what environmental safeguards were taken at the time such wells were drilled or during such time the wells were operated. Should it be determined that a liability exists with respect to any environmental clean up or restoration, the Company would be responsible for curing such a violation. No claim has been made, nor is the Company aware of any liability that exists, as it relates to any environmental clean up, restoration or the violation of any rules or regulations relating thereto.
Leases As of May 31, 2012, the Company rented various office spaces in Dallas, Texas; Midland, Texas; and Lafayette, Louisiana and rented corporate housing in Richardson, Texas under non-cancelable lease agreements. In the aggregate, these leases cover approximately 16,884 square feet at a cost of approximately $27,000 per month and have remaining lease terms ranging from 3 months to 52 months. The following is a schedule by year of future minimum rental payments required under these lease arrangements as of May 31, 2012:
Rent expense under the Company’s lease arrangements amounted to $201,771 and $2,400 for the fiscal years ended May 31, 2012 and 2011, respectively.
15. Related Party Transactions On September 15, 2011, the Company borrowed $100,000, interest free, from StoneStreet Operating Company, LLC (“StoneStreet Operating”) for working capital purposes, and the loan was repaid in full on September 26, 2011. On October 19, 2011, the Company borrowed an additional $180,000, interest free, from StoneStreet Operating for working capital purposes, and the loan was repaid in full on October 26, 2011. Mr. Barksdale is the president and manager of StoneStreet Operating.
Mr. Barksdale is the receiver for Bamco. Bamco primarily owns oil and gas leasehold interests in various properties, including partial interests in the Frost Bank, La Duquesa and Resendez leases. The Company has proposed acquiring Bamco’s assets in exchange for issuing 2,375,000 shares of the Company’s common stock to Bamco’s receivership estate. The proposed asset acquisition is subject to confirmation by the court presiding over Bamco’s receivership. The Company expects the court to confirm the plan of acquisition during the second quarter of fiscal 2013.
Red Mountain Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements 15. Related Party Transactions - (continued) StoneStreet Operating served as the operator for the Frost Bank, Resendez and La Duquesa properties from June 1, 2011 to December 31, 2011. Mr. Barksdale is the president and manager of StoneStreet Operating. For the fiscal year ended May 31, 2012, StoneStreet Operating paid the Company $146,166 of oil and natural gas revenues attributable to the properties, and the Company paid StoneStreet Operating $14,550 for acting as operator of the properties.
During the fiscal year ended May 31, 2012, the Company also paid StoneStreet Operating approximately $90,796 as reimbursement for operating and corporate expenses incurred by StoneStreet Operating on behalf of the Company and $20,260 as payment for condensate proceeds that were payable to StoneStreet Operating. At May 31, 2012, $11,629 was payable to StoneStreet Operating for reimbursement of expenses.
On January 28, 2011, Black Rock funded a $25,000 one year certificate of deposit in order for StoneStreet Operating to secure an additional letter of credit for the benefit of the Railroad Commission of Texas. Subsequent to funding, Black Rock assigned the certificate of deposit to StoneStreet Operating. The certificate of deposit was liquidated on November 2, 2011 and the proceeds of $25,141 were returned to Black Rock.
The Company entered into an arrangement with R.K. Ford and Associates and Cabal Energy relating to the operations of the Good Chief State #1 and Big Brave State #1 wells, and a contract for drilling services with Western Drilling on the Company’s Madera 24-2H well. Each of these entities are owned or partially owned by Randell K. Ford, a director of the Company. During the fiscal year ended May 31, 2012, the Company paid an aggregate of $5.0 million to these entities for engineering, drilling and completion services. In addition, the Company is a party to a lease agreement with R.K. Ford and Associates, pursuant to which the Company leases office space in Midland, Texas. During the fiscal year ended May 31, 2012, the Company paid $25,200 to R.K. Ford and Associates pursuant to the lease agreement.
The Company is a party to a consulting agreement with Enerstar Resources O&G, LLC. This entity is partially owned by Tommy Folsom, Executive Vice President and Director of Exploration and Production for RMR Operating, LLC and formerly the Executive Vice President and Director of Exploration and Production for the Company. During the fiscal year ended May 31, 2012, the Company paid an aggregate of $5,745 to this entity.
16. Subsequent Events Swan Purchase and Sale Agreement On May 9, 2012, the Company entered into a Purchase and Sale Agreement to acquire all of the ownership interests in Swan PC, LP (“Swan”) for approximately $235.0 million, subject to certain adjustments. Swan owns 49,179 gross (47,096 net) acres of oil and natural gas leaseholds located in Jack, Palo Pinto, Clay, Wise and Parker Counties, Texas. On June 30, 2012, the Company terminated the Purchase and Sale Agreement pursuant to its right to terminate the Purchase and Sale Agreement at any time and for any reason. No material early termination penalties were incurred by the Company in connection with the termination of the Purchase and Sale Agreement.
Cross Border Purchase and Sale Agreements On June 13, 2012, the Company entered into a stock purchase and sale agreement pursuant to which the Company acquired an aggregate of 1,000,000 shares of common stock of Cross Border in exchange for the issuance of 2,000,000 shares of the Company’s common stock. On August 10, 2012, the Company entered into a stock purchase and sale agreement pursuant to which the Company acquired an aggregate of 384,040 shares of common stock of Cross Border in exchange for the issuance of an aggregate of 768,080 shares of the Company’s common stock. On August 28, 2012, the Company entered into stock purchase and sale agreements pursuant to which the Company acquired an aggregate of 1,185,301 shares of common stock of
Red Mountain Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements 16. Subsequent Events - (continued) Cross Border in exchange for the issuance of an aggregate of 2,370,602 shares of the Company’s common stock. As of August 28, 2012, the Company owned approximately 45.9% of the outstanding shares of common stock of Cross Border.
Hunter Drilling Asset Purchase Agreement On July 19, 2012, the Company and its wholly-owned subsidiary, Hunter Drilling, LLC, entered into an Asset Purchase Agreement (the “Purchase Agreement”) with First Security Bank, as Trustee for the Holders of the Senior Series 2009A Debentures and the Series 2009B Debentures, O&G Leasing, LLC (“O&G”) and Performance Drilling Company, LLC (“Performance Drilling”) for the purchase and sale of all of the assets of O&G and Performance Drilling in a pending bankruptcy proceeding. The assets include five oil and natural gas drilling rigs and related parts and equipment. The Purchase Agreement is subject to the Bankruptcy Court’s confirmation of a Plan of Reorganization filed by First Security Bank over a competing Plan of Reorganization filed by the debtors and the entry of orders of the Bankruptcy Court approving the Purchase Agreement and the sale of the assets.
Pursuant to the terms of the Purchase Agreement, Hunter Drilling and the Company agreed (i) to pay $450,000 in cash at closing and (ii) to pay an additional $500,000 for the payment of certain administrative expenses, professional fees, cure amounts and other allowed claims if the amount of cash in the bankruptcy estate is insufficient to pay these claims. On July 19, 2012, Hunter Drilling paid $250,000 into an escrow account as an earnest money deposit, which will be applied toward the cash consideration.
In addition to the cash purchase price, the Company agreed to issue 1,509,307 shares of its common stock to the holders of Senior Series 2009A Debentures (the “2009A Debentures”) at an agreed price of $1.50 per share, for the payment of accrued and unpaid interest on the 2009A Debentures, subject to adjustment in certain limited circumstances. Hunter Drilling also agreed to issue Senior Secured Convertible Debentures with a term of approximately eight years that accrue interest at a rate of 6% per annum (the “Senior Secured Debentures”) to the holders of 2009A Debentures in the aggregate principal amount of $25,955,000 (the aggregate principal amount of debt held by such holders), subject to adjustment for (A) those 2009A Debentures that have been acquired by the Company in exchange for issuing shares of its common stock (the “Exchanged Senior Debentures”) and (B) those 2009A Debentures that are redeemed with cash provided by Hunter Drilling at Closing. Hunter Drilling agreed to either acquire $2,345,000 in principal amount of 2009A Debentures prior to Closing or to tender cash to acquire 2009A Debentures in a principal amount equal to the difference between the $2,345,000 and the principal amount of Exchanged Senior Debentures. Principal and interest on the Senior Secured Debentures will be paid quarterly based on an approximately eight year amortization schedule. The Senior Secured Debentures shall be secured by a first priority lien on the Purchased Assets, subject to certain exceptions. The Senior Secured Debentures are subject to conversion after the Closing, in whole or in part at the option of the holders, into shares of the Company’s common stock at a conversion price of $2.00 per share of common stock until the first anniversary of the Closing, with an increase in the conversion price of $0.50 per share on each subsequent anniversary of Closing until maturity, each subject to adjustment in certain limited circumstances. The Senior Secured Debentures can be prepaid without premium or penalty, subject to prior notice. In addition, Hunter Drilling is required to conduct a dutch auction on an annual basis that uses all excess cash of Hunter Drilling to purchase Senior Secured Debentures.
As part of the purchase price, the Company agreed to issue 697,110 shares of its common stock to the holders of the Series 2009B Debentures (the “2009B Debentures”) of the Debtors at an agreed price of $1.50 per share, for the payment of accrued and unpaid interest on the 2009B Debentures, subject to adjustment in certain limited circumstances. In addition, Hunter Drilling agreed to issue junior secured debentures with a term of approximately nine years that accrue interest at a rate of 6% per annum (the “Junior Secured Debentures”) to the holders of the 2009B Debentures in the aggregate principal amount of $7.6 million (the aggregate principal amount of debt held by such holders), subject to adjustment for (i) those 2009B Debentures that have been acquired by the Company in exchange for issuing shares of its common stock (the
Red Mountain Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements 16. Subsequent Events - (continued) “Exchanged Junior Debentures”) and (ii) those 2009B Debentures that are redeemed with cash provided by Hunter Drilling at the closing of the transaction. Hunter Drilling agreed to acquire either $1.0 million in principal amount of the Exchanged Junior Debentures prior to the closing of the transaction or to tender cash to acquire 2009B Debentures in a principal amount equal to the difference between the $1.0 million and the principal amount of the Exchanged Junior Debentures.
In August 2012, the Company acquired an aggregate of $425,000 of 2009B Debentures and the rights to pre-petition interest from four holders in exchange for the issuance of an aggregate of 399,109 shares of the Company’s common stock.
Convertible promissory note On July 30, 2012, the Company issued a convertible promissory note (the “Note”) in the principal amount of $1,000,000 to Hohenplan Privatstiftung (the “Holder”). The Note accrues interest at a fixed rate of 10% per annum. The entire principal amount of the Note together with accrued but unpaid interest is due on July 30, 2013, subject to a 12-month extension at the Holder’s option. The Holder has the option of converting all or a portion of the principal amount of the Note, plus accrued but unpaid interest, into shares of the Company’s common stock. Subject to adjustment upon certain events, the conversion price is equal to the lower of (a) $1.50 and (b) the lowest price at which the Company’s common stock is sold in an equity financing for cash after the date of the Note and prior to the maturity date. The Company has granted the Holder piggyback registration rights and agreed to include the resale of any shares of common stock that may be received upon conversion of the Note in a future registration statement filed by the Company, other than a registration statement (i) filed in connection with any employee stock option or other benefit plan, (ii) for an exchange offer or offering of securities solely to the Company’s existing shareholders, (iii) for an offering of debt that is convertible into equity securities of the Company or (iv) for a dividend reinvestment plan.
17. Supplemental Information Relating to Oil And Natural Gas Producing Activities (Unaudited) Costs incurred in oil and natural gas property acquisition, exploration and development Set forth below is certain information regarding the costs incurred for oil and natural gas property acquisition, development and exploration activities:
(1) For the fiscal years ended May 31, 2012 and 2011, development costs included $0.6 million and $0.2 million, respectively, in non-cash asset retirement obligations.
Red Mountain Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements 17. Supplemental Information Relating to Oil And Natural Gas Producing Activities (Unaudited) - (continued) Results of operations for oil and natural gas producing activities Set forth below is certain information regarding the results of operations for oil and natural gas producing activities:
Proved reserves Forrest A. Garb & Associates, Inc., independent petroleum engineers, estimated 100% of the proved reserve information for the Company’s onshore Gulf Coast properties as of May 31, 2012 and 2011. Lee Engineering, independent petroleum engineers, estimated 100% of the proved reserve information for the Company’s Permian Basin properties as of May 31, 2012 and 2011. Each estimate of proved reserves and related valuations were also prepared in accordance with then-current provisions of ASC 932, Extractive Activities.
Estimates of proved reserves are inherently imprecise and are continually subject to revision based on production history, results of additional exploration and development, price changes and other factors. All of the Company’s estimated oil and natural gas reserves are attributable to properties within the United States. A summary of the Company’s changes in quantities of proved oil and natural gas reserves for the fiscal years ended May 31, 2012 and 2011 are as follows:
Red Mountain Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements 17. Supplemental Information Relating to Oil And Natural Gas Producing Activities (Unaudited) - (continued) At May 31, 2012, the Company’s estimated proved reserves were 2,082 MBoe, a decrease of 19.5% compared to 2,586 MBoe at May 31, 2011. During fiscal 2012, the Company added estimated proved reserves of 338 MBoe through acquisitions, which were offset by production of 176 MBoe and downward revisions in previous estimates of 666 MBoe. The downward revisions were primarily comprised of 453 MBoe due to the removal of two proved undeveloped locations from the reserve report because the Company determined those wells would not be drilled based upon current gas prices and 151 MBoe due to lower production than expected from two new wells.
Standardized measure of discounted future net cash flows relating to proved reserves Future cash inflows were computed by applying the average of the closing price on the first day of each month for the 12-month period prior to May 31, 2012 to estimated future production. Future production and development costs are computed by estimating the expenditures to be incurred in developing and producing the proved oil and natural gas reserves at year end, based on year-end costs and assuming continuation of existing economic conditions.
Future income tax expenses are calculated by applying appropriate year-end tax rates to future pre-tax net cash flows relating to proved oil and natural gas reserves, less the tax basis of properties involved.
Future income tax expenses give effect to permanent differences, tax credits and loss carryforwards relating to the proved oil and natural gas reserves. Future net cash flows are discounted at a rate of 10% annually to derive the standardized measure of discounted future net cash flows. This calculation procedure does not necessarily result in an estimate of the fair market value of the Company’s oil and natural gas properties.
The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves were as follows:
Red Mountain Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements 17. Supplemental Information Relating to Oil And Natural Gas Producing Activities (Unaudited) - (continued) Changes in standardized measure of discounted future net cash flows The changes in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves are as follows:
SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
RED MOUNTAIN RESOURCES, INC.
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.
EXHIBIT INDEX
* Filed herewith.
** As provided in Rule 406T of Regulation S-T, this information shall not be deemed “filed” for purposes of Section 11 and 12 of the Securities Act of 1933 and Section 18 of the Securities Exchange Act of 1934 or otherwise subject to liability under those sections.
 Indicates a compensation contract or arrangement with management.