Attached files
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
(Mark One)
| ☒ | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the fiscal year ended June 30, 2015
| ☐ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from ______________to ______________
Commission File Number 000-54444
RED MOUNTAIN RESOURCES, INC.
(Exact Name of Registrant as Specified in Its Charter)
| Texas | 27-1739487 |
| (State or Other Jurisdiction of Incorporation or Organization) | (I.R.S. Employer Identification Number) |
| 14282 Gillis Road Farmers Branch, TX |
75244 |
| (Address of Principal Executive Offices) | (Zip Code) |
(214) 871-0400
(Registrant’s Telephone Number, Including Area Code)
Securities registered pursuant to Section 12(b) of the Act: None
Securities registered pursuant to Section 12(g) of the Act:
Common Stock, par value $0.00001 per share
10.0% Series A Cumulative Redeemable Preferred Stock, par value $0.0001 per share
Warrants to purchase common stock
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☐ No ☒
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Exchange Act. Yes ☐ No ☒
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☐ No ☒
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ☒ No ☐
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ☒
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
| Large accelerated filer ☐ | Accelerated filer ☐ |
| Non-accelerated filer ☐ (Do not check if a smaller reporting company) | Smaller reporting company ☒ |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ☐ No ☒
As of December 31, 2014 (the last business day of the registrant’s most recently completed second fiscal quarter), the aggregate market value of the registrant’s common stock (based on a reported closing market price of $1.55 per share on the OTC Pink Marketplace) held by non-affiliates of the registrant was approximately $17.8 million. For purposes of this computation, all officers, directors and 10% beneficial owners of the registrant are deemed to be affiliates. Such determination should not be deemed to be an admission that such officers, directors or 10% beneficial owners are, in fact, affiliates of the registrant.
As of November 1, 2015, there were 14,857,488 shares of common stock, $0.00001 par value per share, outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
N/A
RED MOUNTAIN RESOURCES, INC.
FORM 10-K
TABLE OF CONTENTS
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Forward-Looking Statements
This Annual Report on Form 10-K contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). Statements that are not historical facts, including statements about our beliefs and expectations, are forward-looking statements. Forward-looking statements include statements preceded by, followed by or that include the words “may,” “could,” “would,” “should,” “believe,” “expect,” “anticipate,” “plan,” “estimate,” “target,” “project,” “intend,” “understand,” or similar expressions and the negative of such words and expressions, although not all forward-looking statements contain such words or expressions.
Forward-looking statements are only predictions and are not guarantees of performance. These statements generally relate to our plans, objectives and expectations for future operations and are based on management’s current beliefs and assumptions, which in turn are based on its experience and its perception of historical trends, current conditions and expected future developments as well as other factors it believes are appropriate under the circumstances. Although we believe that the plans, objectives and expectations reflected in or suggested by the forward-looking statements are reasonable, there can be no assurance that actual results will not differ materially from those expressed or implied in such forward-looking statements. Forward-looking statements also involve risks and uncertainties. Many of these risks and uncertainties are beyond our ability to control or predict and could cause results to differ materially from the results discussed in such forward-looking statements. Such risks and uncertainties include, but are not limited to, the following:
| ● | the substantial and continued decline in oil prices; | |
| ● | our ability to generate sufficient cash flow from operations, borrowings or other sources to enable us to fully develop and produce our oil and natural gas properties; | |
| ● | declines or volatility in the prices we receive for our oil and natural gas; | |
| ● | general economic conditions, whether internationally, nationally or in the regional and local market areas in which we do business; | |
| ● | risks associated with drilling, including completion risks, cost overruns and the drilling of non-economic wells or dry holes; | |
| ● | uncertainties associated with estimates of proved oil and natural gas reserves; | |
| ● | the presence or recoverability of estimated oil and natural gas reserves and the actual future production rates and associated costs; | |
| ● | risks and liabilities associated with acquired companies and properties; | |
| ● | risks related to integration of acquired companies and properties; | |
| ● | potential defects in title to our properties; | |
| ● | cost and availability of drilling rigs, equipment, supplies, personnel and oilfield services; | |
| ● | geological concentration of our reserves; | |
| ● | environmental or other governmental regulations, including legislation of hydraulic fracture stimulation; | |
| ● | our ability to secure firm transportation for oil and natural gas we produce and to sell the oil and natural gas at market prices; | |
| ● | exploration and development risks; | |
| ● | management’s ability to execute our plans to meet our goals; | |
| ● | our ability to retain key members of our management team; | |
| ● | weather conditions; | |
| ● | actions or inactions of third-party operators of our properties; | |
| ● | costs and liabilities associated with environmental, health and safety laws; | |
| ● | our ability to find and retain highly skilled personnel; | |
| ● | operating hazards attendant to the oil and natural gas business; | |
| ● | competition in the oil and natural gas industry; and | |
| ● | the other factors discussed under Item 1A. “Risk Factors” in this report. |
Forward-looking statements speak only as of the date hereof. All such forward-looking statements and any subsequent written and oral forward-looking statements attributable to us or any person acting on our behalf are expressly qualified in their entirety by the cautionary statements contained or referred to in this section and any other cautionary statements that may accompany such forward-looking statements. Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements.
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Glossary of Oil and Natural Gas Terms
The following are abbreviations and definitions of terms commonly used in the oil and natural gas industry and this Annual Report on Form 10-K.
“Bbl” One stock tank barrel or 42 U.S. gallons liquid volume of oil or other liquid hydrocarbons.
“Boe” One barrel of oil equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of oil and 42 gallons of NGLs to one Bbl of oil.
“Boe/d” Boe per day.
“Btu” A British thermal unit is a measurement of the heat generating capacity of natural gas. One Btu is the heat required to raise the temperature of a one-pound mass of pure liquid water one degree Fahrenheit at the temperature at which water has its greatest density (39 degrees Fahrenheit).
“completion” The process of treating a drilled well followed by the installation of permanent equipment for the production of oil or natural gas, or in the case of a dry well, the reporting of abandonment to the appropriate agency.
“condensate” A mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.
“developed acreage” The number of acres that are allocated or assignable to productive wells or wells capable of production.
“development costs” Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and natural gas. More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to:
| ● | gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, natural gas lines, and power lines, to the extent necessary in developing the proved reserves; | |
| ● | drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly; | |
| ● | acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems; and | |
| ● | provide improved recovery systems. |
“development well” A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.
“dry well” A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.
“exploration costs” Costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing oil and natural gas reserves, including costs of drilling exploratory wells and exploratory-type stratigraphic test wells.
“exploratory well” A well drilled for the purpose of discovering new reserves in unproven areas.
“field” An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.
“formation” A layer of rock which has distinct characteristics that differ from nearby rock.
“gross acres” The total acres in which a working interest is owned.
“Henry Hub” The pricing point for natural gas futures contracts traded on the NYMEX.
“horizontal well” A well that is drilled vertically to a certain depth and then drilled at a right angle within a specific interval.
“hydraulic fracturing” or “fracking” A process involving the injection of fluids, usually consisting mostly of water, but typically including small amounts of sand and other chemicals, 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.
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“lease operating expenses” The expenses, usually recurring, which pay for operating the wells and equipment on a producing lease.
“MBbl” One thousand barrels of oil or other liquid hydrocarbons.
“MBoe” One thousand barrels of oil equivalent.
“Mcf” One thousand cubic feet of natural gas.
“Mcf/d” One thousand cubic feet of natural gas per day.
“MMBoe” One million barrels of oil equivalent.
“MMBtu” One million British thermal units.
“MMcf” One million cubic feet of natural gas.
“natural gas” Natural gas and NGLs.
“net acres” The sum of the fractional working interests owned in gross acres.
“net revenue interest” An owner’s interest in the revenues of a well after deducting proceeds allocated to royalty and overriding interests.
“NGL” Natural gas liquid.
“NYMEX” The New York Mercantile Exchange.
“oil” Oil and condensate.
“overriding royalty interest” An interest in an oil and/or natural gas property entitling the owner to a share of oil and natural gas production free of costs of production.
“PDNP” Proved developed non-producing reserves.
“PDP” Proved developed producing reserves.
“play” A term applied to a portion of the exploration and production cycle following the identification by geologists and geophysicists of areas with potential natural gas and oil reserves.
“plugging and abandonment” Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another or to the surface. Regulations of many states require plugging of abandoned wells.
“producing well” A well found to be capable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well.
“production costs” Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. They become part of the cost of oil and natural gas produced. Examples of production costs (sometimes called lifting costs) are:
| ● | costs of labor to operate the wells and related equipment and facilities; | |
| ● | repairs and maintenance; | |
| ● | materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities; | |
| ● | property taxes and insurance applicable to proved properties and wells and related equipment and facilities; and | |
| ● | severance taxes. |
“productive well” A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.
“proved developed reserves” Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.
“proved properties” Properties with proved reserves.
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“proved reserves” 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—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. The area of the reservoir considered as proved includes (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or natural gas on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons, or LKH, as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty. Where direct observation from well penetrations has defined a highest known oil, or HKO, elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty. Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based, and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
“proved undeveloped reserves” Reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required.
“PUD” Proved undeveloped reserves.
“PV-10” When used with respect to oil and natural gas reserves, PV-10 means the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development and abandonment costs, using prices and costs in effect at the determination date, before income taxes, and without giving effect to non-property-related expenses, discounted to a present value using an annual discount rate of 10% in accordance with the guidelines of the SEC.
“reasonable certainty” If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery, or EUR, with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.
“recompletion” The process of re-entering an existing wellbore that is either producing or not producing and completing new reservoirs in an attempt to establish or increase existing production.
“reserves” Estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible as of a given date by application of development prospects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and natural gas or related substances to market, and all permits and financing required to implement the project.
“reservoir” A porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers and is separate from other reservoirs.
“sand” A geological term for a formation beneath the surface of the Earth from which hydrocarbons are produced. Its make-up is sufficiently homogenous to differentiate it from other formations.
“shale” Fine-grained sedimentary rock composed mostly of consolidated clay or mud. Shale is the most frequently occurring sedimentary rock.
“spacing” The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres, e.g., 40-acre spacing, and is often established by regulatory agencies.
“standardized measure” The present value of estimated future cash inflows from proved oil and natural gas reserves, less future development, abandonment, production and income tax expenses, discounted at 10% per annum to reflect the timing of future cash flows and using the same pricing assumptions as were used to calculate PV-10. Standardized measure differs from PV-10 because standardized measure includes the effect of future income taxes.
“stratigraphic test well” A drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intention of being completed for hydrocarbon production.
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“undeveloped acreage” Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.
“vertical well” An oil or natural gas wellbore that is drilled from the surface to the depth of interest without directional deviation.
“wellbore” The hole drilled by the bit that is equipped for oil or natural gas production on a completed well. Also called well or borehole.
“working interest” The right granted to the lessee of a property to explore for and to produce and own oil, natural gas, or other minerals. The working interest owners bear the exploitation, development, and operating costs on either a cash, penalty, or carried basis.
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Unless the context otherwise requires, all references to “Red Mountain,” the “Company,” “we,” “our” and “us” refer to (i) Red Mountain Resources, Inc., a Texas corporation (“Red Mountain”), (ii) Red Mountain’s wholly owned subsidiaries, including Black Rock Capital, Inc. (“Black Rock”) and RMR Operating, LLC (“RMR Operating”), and (iii) subsequent to January 28, 2013, Cross Border Resources, Inc. (“Cross Border”). As of June 30, 2015, we owned 83% of the outstanding common stock of Cross Border. Acreage, reserves and production information presented subsequent to January 28, 2013 includes acreage, reserves and production represented by the 17% of Cross Border’s common stock not owned by us.
Our Company
We are a Dallas-based company with oil and natural gas properties in the Permian Basin of West Texas and Southeast New Mexico, the onshore Gulf Coast of Texas and Kansas.
History
Red Mountain, a Texas corporation, was formed on January 23, 2014. On January 31, 2014, we changed our state of incorporation from the State of Florida to the State of Texas by merging Red Mountain Resources, Inc., a Florida corporation (“RMR FL”), with and into Red Mountain Resources, Inc., a Texas corporation. RMR FL 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, an entity wholly-owned by The StoneStreet Group, Inc. (“StoneStreet”). 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 2,700,000 shares of common stock to StoneStreet in exchange for 100% of the interests in Black Rock Capital, LLC. Concurrently with the closing, we retired 22,500,000 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.
On January 31, 2014, RMR FL effected a reverse stock split of RMR FL’s common stock, par value $0.00001 per share (“RMR FL Common Stock”), at an exchange ratio of 1-for-10 (the “Reverse Stock Split”), together with a proportional reduction in the number of authorized shares of RMR FL Common Stock from 500.0 million shares to 50.0 million shares. The par value of RMR FL Common Stock did not change as a result of the Reverse Stock Split. As of January 31, 2014, every ten shares of RMR FL Common Stock were combined into one share of RMR FL Common Stock, reducing the number of outstanding shares of RMR FL Common Stock from approximately 134.0 million to approximately 13.4 million. In addition, a proportionate adjustment was made to the per share exercise price and the number of shares issuable upon the exercise of all outstanding warrants to purchase shares of RMR FL Common Stock. All share and per share amounts and calculations in this report have been retroactively adjusted to reflect the effects of the Reverse Stock Split.
On January 31, 2014, RMR FL changed its state of incorporation from the State of Florida to the State of Texas by merging (the “Reincorporation”) with and into its wholly-owned subsidiary, Red Mountain, with Red Mountain continuing as the surviving corporation. As a result, as of January 31, 2014:
| (i) | RMR FL ceased to exist; |
| (ii) | shareholders of RMR FL automatically became shareholders of Red Mountain, without any action by such shareholders, and began to be governed by (a) the Texas Business Organizations Code, (b) Red Mountain’s Certificate of Formation, and (c) Red Mountain’s Bylaws; |
| (iii) | the name, business, management, fiscal year, accounting, location of the principal executive offices, assets and liabilities of RMR FL became the name, business, management, fiscal year, accounting, location of the principal executive offices, assets and liabilities of Red Mountain; and |
| (iv) | the directors and officers of RMR FL prior to the Reincorporation continued as the directors and officers of Red Mountain after the Reincorporation for an identical term of office. |
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On January 31, 2014, our common stock commenced trading on a split-adjusted basis. As a result of the Reincorporation, Red Mountain became the successor corporation to RMR FL under the Exchange Act and succeeded to RMR FL’s reporting obligations thereunder. Pursuant to Rule 12g-3 promulgated under the Exchange Act, the common stock, preferred stock and warrants of Red Mountain were deemed to be registered under Section 12(g) of the Exchange Act.
Recent Developments
On April 21, 2015, RMR Operating, Black Rock, RMR KS Holdings, LLC (“RMR KS”) and Cross Border (and together with RMR Operating, Black Rock and RMR KS, the “Operating Subsidiaries”) entered into a purchase and sale agreement (the “PSA”) with Black Shale Minerals, LLC (“Buyer”). Pursuant to the PSA, the Company, through the Operating Subsidiaries, sold, assigned, transferred and conveyed to Buyer, effective as of April 1, 2015, fifty percent (50%) of its right, title, and interest in and to certain oil and natural gas assets and properties (the “Assets”), including its oil and natural gas leasehold interests, wells, contracts, and oil and natural gas produced after April 1, 2015. The aggregate purchase price for the Assets under the PSA was $25.0 million, subject to certain adjustments, including post-closing adjustments for any title or environmental benefits or title or environmental defects resulting from Buyer’s title and environmental reviews.
Marketing and Customers
For the fiscal year ended June 30, 2015, approximately 49% of the Company’s revenues were attributable to sales to three customers, and approximately 21% of the Company’s revenues were received from one purchaser. For the fiscal year ended June 30, 2014, approximately 63% of the Company’s revenues were attributable to sales four customers, and approximately 18% of the Company’s revenues were received from one operator pursuant to a joint operating agreement. We believe that the loss of any of these customers 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 natural gas commercial general liability protection relating to all of our oil and natural gas operations (including environmental and pollution claims) with a total limit of coverage in the amount of $2.0 million (with no deductible) and excess liability protection with a total limit of $3.0 million (with a deductible of $10,000).
As is common in the oil and natural 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 June 30, 2015, we had 26 full-time employees. 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 will require hydraulic fracturing.
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Costs associated with hydraulic fracturing activities 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 2015, and we are not aware of any environmental issues or claims that will require material capital expenditures during fiscal 2016, other than the remediation plan for Cross Border’s Tom Tom and Tomahawk fields, 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.
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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 strict and joint and several liability for costs of investigation and removal and remediation of previously disposed wastes (including wastes disposed of or released by prior owners or operators) or property contamination (including groundwater contamination), for natural resource damages and the cost of certain health studies 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 U.S. Environmental Protection Agency (“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. Additionally, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. 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 and regulations promulgated thereunder regulate the generation, transportation, treatment, storage, disposal and cleanup of solid and hazardous waste. With federal approval, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent regulations. Although oil and natural gas waste generally is exempt from regulations as hazardous waste under RCRA, such wastes may constitute “solid wastes” that are subject to the less stringent requirements of non-hazardous waste provisions. Additionally, 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 or local governments will not adopt more stringent requirements for the handling of non-hazardous waste or categorize some non-hazardous waste as hazardous in the future. Indeed, legislation has been proposed from time to time in Congress to re-categorize certain oil and natural gas exploration, development and production wastes as “hazardous wastes.” 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.
Administrative, civil and criminal penalties can be imposed for failure to comply with waste handling requirements. We believe that we are in substantial compliance with applicable requirements related to waste handling, and that we hold all necessary and up-to-date permits, registrations and other authorizations to the extent that our operations require them under such laws and regulations. Although we do not believe the current costs of managing our wastes, as presently classified, to be significant, any legislative or regulatory reclassification of oil and natural gas exploration and production wastes could increase our costs to manage and dispose of such wastes.
Water Discharges. The Federal Water Pollution Control Act of 1972, as amended, also known as the Clean Water Act (the “CWA”), the Safe Drinking Water Act (“SDWA”), the Oil Pollution Act (the “OPA”) and analogous state laws and regulations promulgated thereunder impose restrictions and strict controls regarding the unauthorized discharge of pollutants, including produced waters and other gas and oil wastes, into navigable waters of the United States, as well as state waters. 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 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 CWA and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. The CWA 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. In addition, the EPA has developed pre-treatment standards for wastewater discharges produced by natural gas extraction from underground coalbed and shale formations. Hydraulic fracturing stimulation requires the use of a significant volume of water with some resulting flowback, as well as produced water. Costs may be associated with the treatment of wastewater or developing and implementing storm water pollution prevention plans, as well as for monitoring and sampling the storm water runoff from certain of our facilities. Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions.
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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 CWA 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 OPA is the primary federal law for oil spill liability. The OPA imposes 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 may include the owner or operator of an onshore facility. The OPA 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 and maintaining certain significant levels of financial assurance to cover potential environmental cleanup and restoration costs. Failure to comply with the OPA 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. We believe that compliance with applicable requirements under the OPA will not have a material and adverse effect on us.
Hydraulic fracturing is a practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations. The process involves the injection of water, sand and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. Although hydraulic fracturing has historically been regulated by state oil and gas commissions the EPA recently asserted federal regulatory authority over the process under the SDWA’s Underground Injection Control (“UIC”) Program. Under this assertion of authority, the EPA requires facilities to obtain permits to use diesel fuel in hydraulic fracturing operations, specifically in Class II wells, which are those wells injecting fluids associated with oil and natural gas production activities. The U.S. Energy Policy Act of 2005, which exempts hydraulic fracturing from regulation under the SDWA, prohibits the use of diesel fuel in the fracturing process without a UIC permit. On February 12, 2014, the EPA released an interpretive memorandum and technical recommendations for implementing the UIC Program for oil and natural gas hydraulic fracturing activities using diesel fuel. The guidance document describes how Class II regulations may be tailored to address the purported unique risks of diesel fuel injection during the hydraulic fracturing process. Although EPA has delegated UIC permitting authority to many states, it is encouraging those states to review and consider use of this permit guidance.
Air Emissions. Our operations are subject to federal regulations for the control of emissions from sources of air pollution under the Clean Air Act (“CAA”) and analogous state and local regulations. 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.
In August 2012, the EPA adopted rules that subject oil and natural gas production, processing, transmission, and storage operations to regulation under the New Source Performance Standards (“NSPS”) and National Emission Standards for Hazardous Air Pollutants (“NESHAP”) programs. The rule includes NSPS standards for completions of hydraulically fractured gas wells and establishes specific new requirements for emissions from compressors, controllers, dehydrators, storage vessels, natural gas processing plants and certain other equipment. The final rule seeks to achieve a 95% reduction in VOCs emitted by requiring the use of reduced emission completions or “green completions” on all hydraulically-fractured wells constructed or refractured after January 1, 2015. These rules may require a number of modifications to our operations. These standards, as well as any future laws and their implementing regulations, may require us to obtain pre-approval for the expansion or modification of existing facilities or the construction of new facilities expected to produce air emissions, impose stringent air permit requirements, or utilize specific equipment or technologies to control emissions. Our failure to comply with these requirements could subject us to monetary penalties, injunctions, conditions or restrictions on operations and, potentially, criminal enforcement actions.
We may be required to incur capital expenditures to insure compliance with these new regulations as they come into effect. Obtaining permits also has the potential to delay the development of oil and natural gas projects. We believe that we currently are in substantial compliance with all air emissions regulations and that we hold all necessary and valid construction and operating permits for our current operations.
Climate Change Legislation. In response to certain scientific studies suggesting that emissions of carbon dioxide, methane and other greenhouse gas (“GHG”) emissions 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.
In September 2009, the EPA issued a final rule requiring the reporting of GHG emissions from specified large GHG emission sources in the U.S., including NGLs fractionators and local natural gas/distribution companies. In November 2010, the EPA published a final rule expanding the GHG reporting rule to include onshore oil and natural gas production, processing, transmission, storage and distribution facilities. This rule requires reporting of GHG emissions from such facilities on an annual basis. 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.
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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 DOI, 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.
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In addition, some 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, Bureau of Safety and Environmental 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. The transportation of natural gas in interstate commerce by pipelines, and the sale for resale of natural gas in interstate commerce by pipelines or their affiliates and local distribution companies or their affiliates, are 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 (subject to anti-manipulation rules, which are discussed below), the United States 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 (so-called “first sales”) effective January 1, 1993.
FERC regulates interstate natural gas transportation rates, and terms and conditions of service, and this regulation 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 with Order No. 636 in 1992, FERC adopted mandatory open access policies including mandatory standards of conduct governing communications and information sharing between affiliated natural gas transportation and gas marketing employees. 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 a non-discriminatory, open access basis to others who buy and sell natural gas. Although the FERC’s open access orders do not directly regulate natural gas producers, they are intended to foster increased competition within all phases of the natural gas industry.
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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. 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.
FERC has jurisdiction under the NGA over some (but not all) sales for resale of physical gas. FERC has issued blanket certificates under the NGA that pre-authorize various sales for resale in interstate commerce. These blanket certificates preauthorize interstate sales for resale automatically, without the need to apply for the certificate, and without any conditions as to the price, purchaser, volume, term or other economic conditions of the sale. The blanket certificates also pre-authorize abandonment of the sale under the NGA upon expiration of the contract term or termination of the individualized sales arrangement. However, FERC retains NGA jurisdiction over all blanket certificate sales, meaning that FERC has the ability to add prospective terms and conditions to such certificates as future conditions warrant. FERC first exercised this authority in 2003, when in the wake of the market upheavals in California, FERC established a gas marketing “code of conduct” applicable to all blanket certificate sellers. The code of conduct for blanket certificate sellers includes price reporting provisions intended to address the problems that surfaced in gas markets concerning false transaction reports designed to manipulate price indices published by various publications. The code of conduct’s price reporting provision does not require any seller to report transactions to a publisher of natural gas price indices, but requires that any seller who chooses to do so must provide accurate information, not knowingly submit false or misleading information, or omit material information. Blanket certificate holders who violate the certificate conditions (including the code of conduct) are subject to potential suspension or revocation of the certificate. All blanket certificate sellers are subject to the regulatory risk associated with future FERC action to prescribe new conditions for transactions conducted under the certificate.
Pursuant to FERC 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. Order No. 704 has its genesis in the Energy Policy Act of 2005, which added section 23 of the NGA. Section 23 of the NGA, among other things, directs FERC “to facilitate price transparency in markets for the sale or transportation of physical natural gas in interstate commerce, having due regard for the public interest, the integrity of those markets, and the protection of consumers.” Order No. 704 requires market participants with reportable physical natural gas purchases or sales equal to or greater than 2.2 trillion British thermal units must comply with the reporting requirements. Reportable physical natural gas purchases include physical natural gas transactions that use an index or that contribute to or may contribute to the formation of a gas index.
The Energy Policy Act of 2005 amended the Natural Gas Act to give FERC authority to assess civil penalties to any person that violates the Natural Gas Act or any rule, regulation, restriction, condition, or order under the Act. Such penalties may be up to $1 million per day per violation. This significantly adds to the risk of FERC-regulated companies that violate the NGA or rules or orders thereunder as well as to non-regulated entities that directly or indirectly manipulate the purchase or sale of FERC-regulated natural gas or the purchase or sale of FERC-regulated transportation services. See “—Other Federal Laws and Regulations Affecting Our Industry—Energy Policy Act of 2005.”
Gathering services, which occur upstream of FERC jurisdictional gas 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 and 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.
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Risks Related to Our Business
We were not in compliance with our covenants under our Credit Agreement as of June 30, 2015. As a result, the Lender may exercise one or more of its remedies, including the right to accelerate the repayment of all outstanding borrowings.
As of June 30, 2015, we had $12.4 million of borrowings under our Credit Facility. This indebtedness is secured by substantially all of our assets and the assets of our subsidiaries. The Credit Agreement contains covenants which require us to maintain compliance with certain financial ratios, aging of accounts payable and agreements that hedge the price of oil. As of June 30, 2015, we were not in compliance with certain of these covenants and, as a result, the Lender can declare an event of default under the Credit Agreement. In the event of an event of default, the Lender has the right to accelerate repayment of all outstanding indebtedness and take actions to collect monies owed to it, including enforcing and foreclosing on its security interest on our assets and the assets of our subsidiaries. In addition, the Lender can restrict our access to additional borrowings under the Credit Facility. As of the date hereof, the Lender has not accelerated our repayment obligations or taken any of the other actions described above.
We are in discussions with the Lender regarding either a waiver of the non-compliance or an amendment to the Credit Agreement to cure the non-compliance. However, we cannot provide any assurance that these negotiations will be successful. Even if we successfully obtain a waiver or an amendment that cures the non-compliance, we can provide no assurance that we will not violate our covenants in the future.
If the Lender were to accelerate our repayment obligation under the Credit Facility, our assets may not be sufficient to fully repay the debt and we may not be able to obtain capital from other sources at favorable terms or at all. If additional funding is required, this funding may not be available on favorable terms, if at all, or without potentially very substantial dilution to our stockholders. If we do not raise the necessary funds, we may need to curtail or cease our operations, sell certain assets and/or file for bankruptcy, which would have a material adverse effect on our financial condition and results of operations.
We currently do not have sufficient funds to continue our operations beyond November 30, 2015, or sooner if the Lender accelerates the repayment of our obligations under the Credit Facility.
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 currently do not have sufficient funds to continue our operations beyond November 30, 2015, or sooner if the Lender accelerates our obligations under the Credit Agreement. If we are unable to finance our operations on acceptable terms or at all, we may be forced to sell assets or curtail or suspend our operations, 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:
| ● | the value of 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. |
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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.
Depressed oil and gas natural prices have significantly adversely affected our results of operations, financial condition and ability to meet our capital expenditure obligations.
Our revenue, profitability, access to capital and future rate of growth are substantially dependent on the prevailing prices of, and demand for, oil and natural gas. Oil prices have declined substantially since mid-2014 and have experienced significant volatility during 2015. The market price of Brent crude oil has decreased approximately 50% since June 2014 as a result of market uncertainties over the supply and demand of oil due to increased production in certain regions, decisions made by OPEC, the current state of the global economy and concerns over future global oil demand. Historically, oil and natural gas prices and markets have been volatile, and they are likely to continue to be volatile in the future.
Continued depressed oil prices or a further decrease in oil or natural gas prices will not only reduce revenues, but will also reduce the quantities of reserves that are commercially recoverable, make some wells uneconomical to drill or operate, reduce our ability to develop our properties, reduce our access to capital and may result in charges to earnings for impairment of the value of these assets.
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, and 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 natural gas 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. |
If oil and natural gas prices remain depressed or further decline, (i) our net cash flow attributable to current production will decline, (ii) our exploration and development activity may decline as some investments may become uneconomic and are either delayed or eliminated, and (iii) the value of proved developed producing reserves and proved undeveloped reserves could decline. It is impossible to predict future oil and natural gas price movements, and declines in oil and natural gas prices could have a material adverse effect on our liquidity and financial condition.
| 15 |
Our Credit Agreement contains various covenants that limit our management’s discretion in the operation of our business and can lead to an event of default that may adversely affect our business, financial condition and results of operations.
The operating and financial restrictions and covenants in our Senior First Lien Secured Credit Agreement (as amended, the “Credit Agreement”) with Cross Border, Black Rock and RMR Operating (collectively with the Company, the “Borrowers”) and Independent Bank, as Lender (the “Lender”), may adversely affect our ability to finance future operations or capital needs or to engage in other business activities. The Credit Agreement contains various covenants that restrict our ability to, among other things, incur liens, incur additional indebtedness, enter into mergers, sell assets, make investments and pay dividends.
The Credit Agreement also requires us to maintain specified financial ratios. We were not in compliance with one or more of the financial ratios in the Credit Agreement at June 30, 2015, which constitutes an event of default under the Credit Agreement.
Amounts outstanding under the revolving credit facility provided by the Credit Agreement (as amended, the “Credit Facility”) may be accelerated and become immediately due and payable upon specified events of default of Borrowers (as defined herein), including, among other things, a default in the payment of principal, interest or other amounts due under the Credit Facility, certain loan documents or hydrocarbon hedge agreements, a material inaccuracy of a representation or warranty, a breach of a covenant, a default with regard to certain loan documents which remains unremedied for a period of 30 days following notice, a default in the payment of other indebtedness of the Borrowers of $200,000 or more, bankruptcy or insolvency, certain changes in control, failure of the Lender’s security interest in any portion of the collateral with a value greater than $500,000, cessation of any security document to be in full force and effect, or Alan Barksdale ceasing to be Red Mountain’s Chief Executive Officer or Chairman of Cross Border and not being replaced with an officer acceptable to the Lender within 30 days.
If Lender accelerates our indebtedness under the Credit Facility, our business, financial condition and results of operations may be materially and adversely affected.
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.
Our producing properties are concentrated in the Permian Basin of Southeast New Mexico and West Texas, making us vulnerable to risks associated with operating in one major geographic area. In addition, we have a large amount of proved reserves attributable to a small number of producing horizons within this area.
Our producing properties are geographically concentrated in the Permian Basin of Southeast New Mexico and West Texas. At July 1, 2015, approximately 93% of our proved reserves were concentrated in this area. As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, processing or transportation capacity constraints, market limitations, water shortages or other drought related conditions or interruption of the processing or transportation of oil, natural gas or NGLs.
In addition to the geographic concentration of our producing properties described above, at July 1, 2015, approximately (i) 33.1% of our proved reserves were attributable to the Madera field, (ii) 15.6% of our proved reserves were attributable to the Lusk field and (iii) 16.3% of our proved reserves were attributable to the Turkey Track field. This concentration of assets within a small number of producing horizons exposes us to additional risks, such as changes in field-wide rules and regulations that could cause us to permanently or temporarily shut-in all of our wells within a field.
Approximately 46% of our total estimated proved reserves as of July 1, 2015 were classified as proved undeveloped and may not be ultimately developed or produced.
As of July 1, 2015, approximately 46% 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, 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.
Reserve estimates depend on many assumptions that may turn out to be inaccurate.
The calculation of reserves and estimating reserves are inherently imprecise. The accuracy of any reserve estimate is a function of the quality of available data, engineering interpretation and judgment and the assumptions used regarding the quantities of recoverable oil and natural gas and the future prices of oil and natural gas. Petroleum engineers consider many factors and make many assumptions in estimating reserves. Those factors and assumptions include, but are not limited to, the following: historical production from the area compared with production rates from similarly situated producing areas; the effects of governmental regulation; assumptions about future commodity prices, production and taxes; the availability of enhanced recovery techniques; and relationships with landowners, working interest partners, pipeline companies and others.
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Any material inaccuracies in our reserve estimates or underlying assumptions could materially affect the quantities and present values of our 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 of 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.
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.
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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.
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.
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 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 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.
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.
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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. From time to time, regulatory agencies have imposed price controls and limitations on production in order to conserve supplies of oil and natural gas. In addition, the production, handling, storage, transportation and disposal of oil and natural gas, byproducts thereof and other substances and materials produced or used in connection with oil and natural gas operations are subject to regulation under federal, state and local laws and regulations.
Currently, federal regulations provide that drilling fluids, produced waters and other wastes associated with the exploration, development or production of oil and natural gas are exempt from regulation as “hazardous waste.” From time to time, legislation has been proposed to eliminate or modify this exemption. Should the exemption be modified or eliminated, wastes associated with oil and natural gas exploration and production would be subject to more stringent regulation. On the federal level, operations on our properties may be subject to various federal statutes, including the Natural Gas Act, the Comprehensive Environmental Response, Compensation and Liability Act, the Solid Waste Disposal Act, as amended by the Resource Conservation and Recovery Act, the Clean Air Act, the National Environmental Policy Act, the Endangered Species Act, the Toxic Substances Control Act, the Federal Water Pollution Control Act and the Oil Pollution Act, as well as by regulations promulgated pursuant to these actions.
These regulations may subject us to increased operating costs and potential liability associated with the use and disposal of hazardous materials. These laws and regulations may have a material adverse effect on our financial condition and results of operations as there can be no assurance that we will not be required to make material expenditures in the future. Moreover, 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.
We may have difficulty managing growth in our business, which could adversely affect our financial condition and results of operations.
As a small 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, 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.
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. Local ordinances or other regulations may regulate or prohibit the performance of well drilling in general and hydraulic fracturing in particular. In addition, a number of federal agencies are analyzing, or have been requested to review, a variety of environmental issues associated with hydraulic fracturing. 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.
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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 June 30, 2105. 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 market price of our securities 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.
Our business may suffer if we lose key personnel.
We depend to a large extent on the services of our key personnel, including Alan Barksdale, our President and Chief Executive Officer, and Hilda Kouvelis, our Chief Accounting Officer. 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 an employment agreement with Ms. Kouvelis, 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 business is difficult to evaluate because we have a limited operating history.
Prior to June 2010, we had no material operations. After our June 2010 acquisition of oil and natural gas properties in Zapata County and Duval County in the onshore Gulf Coast of Texas, we began to recognize revenue from our operations. Accordingly, we have a very short financial operating history and a history of losses. As a result, there is only limited historical financial and operating information available upon which to base your evaluation of our performance.
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.
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We could suffer the loss of all or part of the expenses that we prepay to the operators of our properties.
We may be required prepay to the operators of our properties our contractual share of acreage, geophysical and geological costs and other up-front expenses, and drilling and completion costs, on a well-by-well basis. Once a prepayment is made, the operator is under no requirement to keep such funds segregated from funds received by other working interest owners. As a result of any prepayment, we would become a general unsecured creditor of the operator and, therefore, could suffer the loss of all or part of the amount prepaid in the event that an operator has financial difficulties, liens are placed against the operator’s assets or the operator files for bankruptcy.
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.
We could lose leases on certain of our properties unless production is established and maintained on units containing the acreage or the leases are extended.
Oil and natural gas leases generally must be drilled before the end of the lease term or the leaseholder will lose the lease and any capital invested therein. In addition, leases may also be lost due to legal issues relating to the ownership of leases. Any delays in drilling or legal issues causing us to lose leases on properties could have a material adverse effect on our results of operations and reserve growth. 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.
Our operations could be impacted by burdens and encumbrances on title to our properties.
Our leasehold acreage may be subject to existing oil and natural gas leases, liens for current taxes and other burdens, including other mineral encumbrances and restrictions customary in the oil and natural gas industry, that should not materially interfere with the use or otherwise affect the value of such properties. However, we cannot guarantee that we have or will have clear and unobstructed title to leases or other rights assigned to us. We also cannot guarantee that the mineral encumbrances and restrictions mentioned above will not materially interfere with the use of or affect the value of leasehold acreage. Any cloud on the title of the working interests, leases and other rights owned by us could have a material adverse effect on our operations.
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 have been particularly scrutinized. In particular, there is a growing trend of local and municipal initiatives to regulate drilling and completion activities. For example, a number of municipalities in Colorado have initiated bans or moratoriums on certain drilling and completion activities, including hydraulic fracturing. In addition, some municipalities have adopted temporary moratoriums on gas well permits while longer-term measures are considered. If we are unable to obtain the necessary permits for our operations or if we experience delays in obtaining permits, it could have a material adverse effect on our results of operations and profitability.
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.
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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.
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. Weather related risks include earthquakes, hurricanes and other adverse weather and environmental conditions. The occurrence of one or more of these events could result in a decrease in production of oil and natural gas. 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.
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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.
From time to time, legislative proposals are made 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, which could have a material adverse effect on our business, financial condition, operations and cash flows.
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.
For example, on February 11, 2013, the Bureau of Land Management accepted a remediation plan submitted by Cross Border for its Tom Tom and Tomahawk fields. Pursuant to the remediation plan, Cross Border expects to spend up to $2.1 million to correct environmental issues on these fields.
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, than the regulation of GHG emissions under the federal CAA, or state or regional regulatory programs.
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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.
Rules adopted or proposed by the EPA, as well as any future laws and their implementing regulations, may require us to obtain pre-approval for the expansion or modification of existing facilities or the construction of new facilities expected to produce air emissions, impose stringent air permit requirements, or utilize specific equipment or technologies to control emissions. Our failure to comply with these requirements could subject us to monetary penalties, injunctions, conditions or restrictions on operations and, potentially, criminal enforcement actions. 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.
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.
Various actual and potential 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.
Our operations and the oil and gas industry may be materially adversely impacted by domestic and foreign acts of terrorism and war.
Terrorist attacks and the threat of terrorist attacks, whether domestic or foreign, as well as the military or other actions taken in response to such actions, may cause instability in the global financial and energy markets. Terrorism, the wars in Iraq and Afghanistan, political instability in Northern Africa and the Middle East and other sustained military campaigns could adversely affect us and the market price of oil and natural gas in unpredictable ways, or the possibility that the infrastructure on which the operators developing mineral properties rely could be a direct target or an indirect casualty of an act of terror. Any of these conditions could have a material adverse effect on our operations.
Risks Related to Our Common Stock
We intend to deregister our securities under the Exchange Act. Deregistration will result in less disclosure about us and may negatively affect the liquidity and trading prices of our common stock.
On November 13, 2015, our Board of Directors voted to the voluntarily deregister our common stock, our 10.0% Series A Cumulative Redeemable Preferred Stock (the “Series A Preferred Stock”) and warrants under the Exchange Act and become a non-reporting company. In connection therewith, the Board of Directors approved the filing with the SEC of a Form 15 to voluntarily deregister our securities under Section 12(g) of the Exchange Act and suspend our reporting obligations under Section 15(d) of the Exchange Act. We expect to file the Form 15 on or about November 13, 2015. We expect that our obligations to file periodic reports, such as Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q and Current Reports on Form 8-K, will be suspended immediately upon the filing of the Form 15 with the SEC, and our proxy statement, Section 16 and other Section 12(g) reporting responsibilities will terminate effective 90 days after the filing of the Form 15. We are eligible to deregister under the Exchange Act because our common stock, Series A Preferred Stock and warrants are each held by fewer than 300 shareholders of record. Following deregistration, we do not expect to publish periodic financial information or furnish such information to its stockholders except as may be required by applicable laws. As a result of the foregoing factors, deregistration will result in less disclosure about us and may negatively affect the liquidity and trading prices of our common stock.
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The price of our common stock may fluctuate significantly, which could negatively affect us and holders of our common stock.
The trading price of our common stock may fluctuate significantly in response to a number of factors, many of which are beyond our control. For instance, if our financial results are below the expectations of securities analysts and investors, the market price of our common stock could decrease, perhaps significantly. Other factors that may affect the market price of our common stock include:
| ● | actual or anticipated fluctuations in our quarterly results of operations; | |
| ● | liquidity; | |
| ● | sales of common stock by our stockholders; | |
| ● | changes in oil and natural gas prices; | |
| ● | changes in our cash flow from operations or earnings estimates; | |
| ● | publication of research reports about us or the oil and natural gas exploration and production industry generally; | |
| ● | competition for, among other things, capital, acquisition of reserves, undeveloped land and skilled personnel; | |
| ● | increases in market interest rates which may increase our cost of capital; | |
| ● | changes in applicable laws or regulations, court rulings and enforcement and legal actions; | |
| ● | changes in market valuations of similar companies; | |
| ● | adverse market reaction to any indebtedness we incur in the future; | |
| ● | additions or departures of key management personnel; | |
| ● | actions by our stockholders; | |
| ● | commencement of or involvement in litigation; | |
| ● | news reports relating to trends, concerns, technological or competitive developments, regulatory changes and other related issues in our industry; | |
| ● | speculation in the press or investment community regarding our business; | |
| ● | political conditions in oil and natural gas producing regions; | |
| ● | general market and economic conditions; and | |
| ● | domestic and international economic, legal and regulatory factors unrelated to our performance. |
In addition, the U.S. securities markets have experienced significant price and volume fluctuations. These fluctuations often have been unrelated to the operating performance of companies in these markets. Our common stock is traded on the OTC Pink marketplace, 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.
Market fluctuations and broad market, economic and industry factors may negatively affect the price of our common stock, regardless of our operating performance. Any volatility or a significant decrease in the market price of our common stock could also negatively affect our ability to make acquisitions using common stock. Further, if we were to be the object of securities class action litigation as a result of volatility in our common stock price or for other reasons, it could result in substantial costs and diversion of our management’s attention and resources, which could negatively affect our financial results.
Offers or availability for sale of a substantial number of shares of our common stock by our shareholders may cause the market price of our common stock to decline.
The ability of our shareholders to sell shares of our common stock in the public market, or upon the expiration of any statutory holding period under Rule 144 of the Securities Act of 1933, as amended (the “Securities Act”), could create a circumstance commonly referred to as an “overhang,” which could cause the market price of our common stock to fall. The existence of an overhang, whether or not sales have occurred or are occurring, could make it more difficult for us to raise additional financing through future sales of equity or equity-related securities at a time and price that we deem reasonable or appropriate. Sales of a substantial number of shares of our common stock, or the perception that sales could occur, could adversely affect the market price of our common stock.
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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 on our common stock 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 on our common stock 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 on our common stock in the future. As a result, any gain holders of our common stock will realize will result solely from the appreciation of such common stock.
As of November 1, 2015, we had 254,463 shares of Series A Preferred Stock outstanding, and our certificate of formation permit us to issue additional preferred stock, which could diminish the rights of holders of our common stock and restrict a takeover attempt that you may favor.
As of November 1, 2015, we had 254,463 shares of Series A Preferred Stock outstanding, and our certificate of formation authorizes the issuance of additional shares of preferred stock in one or more series on terms that may be determined at the time of issuance by our board of directors. The Series A Preferred Stock and any additional 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 Pink marketplace 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 OTC Pink marketplace, 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, may 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 common stock price has been affected substantially by a relatively modest volume of transactions and could be again so affected. If our common stock price falls, our stockholders may not be able to sell their shares when desired or at desirable prices.
Risks Related to Our Series A Preferred Stock
The Series A Preferred Stock does not have an established trading market, which may negatively affect its market value and the ability to transfer or sell shares.
The Series A Preferred Stock does not have an established trading market, which may limit the ability of holders of Series A Preferred Stock to sell shares. An active trading market for the shares may not develop or, even if it develops, may not last, in which case the trading price of the shares could be adversely affected and the ability to transfer shares will be limited. The market value of the Series A Preferred Stock could be adversely affected by various factors. The trading price of the Series A Preferred Stock may depend on many factors, including, without limitation:
| ● | market liquidity; | |
| ● | prevailing interest rates; | |
| ● | the market for similar securities; | |
| ● | general economic conditions; |
| ● | the sale of additional shares of Series A Preferred Stock; | |
| ● | our financial condition, performance and prospects; and | |
| ● | our issuance of additional preferred equity or debt securities. | |
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For example, higher market interest rates could cause the market price of the Series A Preferred Stock to decrease. The foregoing factors, among others, may affect the trading price of the Series A Preferred Stock, as well as limit the trading market and restrict ability of investors in the Series A Preferred Stock to transfer their shares.
We are currently prevented from paying cash dividends on the Series A Preferred Stock.
Although dividends on the Series A Preferred Stock are cumulative and arrearages will accrue until paid, holders of shares of Series A Preferred Stock will only receive cash dividends on the Series A Preferred Stock when, as and if declared by our board of directors, and if we have funds legally available for the payment of dividends under Texas law and such payment is not restricted or prohibited by law or the terms of any of our agreements, including the documents governing our indebtedness. Pursuant to the terms of our Credit Agreement, we may pay cash dividends on the Series A Preferred Stock so long as we are not otherwise in default under the Credit Agreement and payment of such cash dividends would not cause us to be in default under the Credit Agreement. Because the Company is currently in default under the Credit Facility, it cannot pay dividends on the Series A Preferred Stock. Future debt, contractual covenants or arrangements that we may enter into in the future may also restrict or prevent future dividend payments.
The payment of any future dividends will be determined by our board of directors in light of conditions then existing, including earnings, financial condition, capital requirements, restrictions or prohibitions in current or future agreements, business conditions and other factors affecting us as a whole. Accordingly, there is no guarantee that we will be able to pay any dividends on the Series A Preferred Stock.
The Series A Preferred Stock has not been rated and our payment obligations with respect to the shares of Series A Preferred Stock will be effectively subordinated to all of our existing and future debt.
The Series A Preferred Stock has not been rated by any nationally recognized statistical rating organization. In addition, with respect to dividend rights and rights upon our liquidation, winding-up or dissolution, the Series A Preferred Stock will be subordinated to all of our existing and future debt and all future capital stock designated as senior to the Series A Preferred Stock.
We may incur additional indebtedness in the future to finance acquisitions or the development of properties, and the terms of the Series A Preferred Stock do not require us to obtain the approval of the holders of the Series A Preferred Stock prior to incurring additional indebtedness. As a result, our existing and future indebtedness may be subject to restrictive covenants or other provisions that may prevent or otherwise limit our ability to make dividend or liquidation payments on the Series A Preferred Stock. Upon our liquidation, our obligations to our creditors would rank senior to the Series A Preferred Stock and would be required to be paid before any payments could be made to holders of the Series A Preferred Stock.
Holders of Series A Preferred Stock have extremely limited voting rights.
Except as expressly stated in our certificate of formation governing the Series A Preferred Stock, holders of Series A Preferred Stock do not have any relative, participating, optional or other special voting rights and powers and their approval is not required for the taking of any corporate action. For example, the approval of holders of Series A Preferred Stock is not required to elect members to our board of directors (except for a limited right to elect two directors upon a dividend default, or one director upon a listing default), or for any merger or consolidation in which we are involved or sale of all or substantially all of our assets, except to the extent that such transaction materially adversely changes the express powers, preferences, rights or privileges of the holders of Series A Preferred Stock. None of the provisions relating to the Series A Preferred Stock contains any provisions affording the holders of the Series A Preferred Stock protection in the event of a highly leveraged or other transaction, including a merger or the sale, lease or conveyance of all or substantially all of our assets or business, that might adversely affect the holders of the Series A Preferred Stock, so long as the terms and rights of the holders of Series A Preferred Stock are not materially and adversely changed.
The issuance in future offerings of preferred stock may adversely affect the value of the Series A Preferred Stock.
Our certificate of formation currently authorizes the issuance of up to 100,000,000 shares of preferred stock in one or more series on terms that may be determined at the time of issuance by our board of directors, including up to 1,200,000 shares of Series A Preferred Stock. We may offer for sale additional shares of Series A Preferred Stock in the future. Accordingly, we may issue additional shares of Series A Preferred Stock and/or stock that ranks on parity with the Series A Preferred Stock (“Parity Stock”) or, with the consent of the holders of the Series A Preferred Stock, stock that ranks senior to the Series A Preferred Stock (“Senior Stock”). The issuance of Series A Preferred Stock, Parity Stock or Senior Stock would dilute the interests of the holders of Series A Preferred Stock, and any issuance of Senior Stock could affect our ability to pay dividends on, redeem or pay the liquidation preference on the Series A Preferred Stock.
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Holders of the Series A Preferred Stock may be unable to use the dividends-received deduction and may not be eligible for the preferential tax rates applicable to “qualified dividend income.”
We may not have sufficient current or accumulated earnings and profits during future fiscal years for the distributions on the Series A Preferred Stock (or our common stock should we determine to pay distributions on it) to qualify as dividends for U.S. federal income tax purposes. If the distributions fail to qualify as dividends, U.S. holders that are corporations would be unable to use the dividends-received deduction and may not be eligible for the preferential tax rates applicable to “qualified dividend income.” If any distributions on the Series A Preferred Stock with respect to any fiscal year are not eligible for the dividends-received deduction or preferential tax rates applicable to “qualified dividend income” because of insufficient current or accumulated earnings and profits, it is possible that a U.S holder that is a corporation could recognize capital gain income upon receipt of a distribution or upon disposition of shares of Series A Preferred Stock. Because of the way corporations are taxed on capital gain income, such capital gains, absent offsetting capital losses, would be effectively taxed to a corporate owner of our preferred stock (or common stock) at then current ordinary income tax rates.
The Series A Preferred Stock is not convertible.
The Series A Preferred Stock accrues dividends at a fixed rate and is not convertible into shares of our common stock. Accordingly, the market value of the Series A Preferred Stock may depend on dividend and interest rates for other preferred stock, debt securities and other investment alternatives, and our actual and perceived ability to pay dividends on, and in the event of dissolution satisfy the liquidation preference with respect to, the Series A Preferred Stock. Moreover, the mandatory redemption of Series A Preferred Stock on July 15, 2018 or upon a “change of control,” or our optional right to redeem the Series A Preferred Stock on or after July 15, 2014, could impose a ceiling on its value.
We may not be able to comply with the financial covenant for the Series A Preferred Stock.
We are required to have an asset coverage ratio of 2.0 or greater as of the date of any issuance of additional debt (excluding borrowings under the Credit Facility or any revolving credit facility in replacement thereof) Series A Preferred Stock, Senior Stock or Parity Stock (the “Financial Covenant”). If we fail to comply with the Financial Covenant, the dividend rate will be increased to 12.0%. Future debt arrangements that we enter into in the future may inhibit our ability to comply with the Financial Covenant, as well as also restrict or limit our ability to make future dividend payments.
We may not be able to comply with the listing covenant for the Series A Preferred Stock, and listing on a national securities exchange does not guarantee a market for the Series A Preferred Stock.
Our certificate of formation requires us to list the Series A Preferred Stock on a National Exchange prior to April 30, 2014. Because we are currently in default pursuant to this listing requirement, the dividend rate specified was increased by one-half percent on May 1, 2014 and shall be increased by one-half percent per quarter, up to a rate not to exceed 12.0%, until such listing occurs at which time the Dividend Rate shall revert to the rate of 10.0%.
Additionally, once the Series A Preferred Stock is listed on a national securities exchange, we are required to maintain the listing of the Series A Preferred Stock on such exchange. In the event we fail to maintain such listing for 180 consecutive days, then, until such failure is cured, (i) the dividend rate will increase, and (ii) the holders of Series A Preferred Stock have the right to elect one director to our board of directors. A national securities exchange could delist the Series A Preferred Stock, which may result in a listing default.
Item 1B. Unresolved Staff Comments
Not applicable.
Our Properties
Currently, our oil and natural gas properties are concentrated in the Permian Basin, the onshore Gulf Coast of Texas, Southwest New Mexico and Kansas. 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.
Permian Basin
The following description of our properties in the Permian Basin is presented as of June 30, 2015.
Madera Prospect. The Madera Prospect consists of 2,545 gross (566 net) acres in Lea County, New Mexico. RMR Operating is the operator of the Madera Prospect.
Tom Tom Area. We own oil and natural gas interests in approximately 8,300 gross (3,100 net) acres in the Tom Tom and Tomahawk fields in Chaves and Roosevelt Counties, New Mexico through our ownership of Cross Border. Cross Border is the operator of these leases. The target formation in the area is the San Andres reservoir, which is productive across the trend with the Cato field to the west and the Chaveroo field to the east.
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Turkey Track Area. We own interests in 4,059 gross acres (351 net) in the Turkey Track Area in Eddy County, New Mexico through Cross Border. The primary targets in the Turkey Track Prospect are the 1st and 2nd Bone Spring reservoirs. The operator of the Turkey Track Prospect is Mewbourne Oil Company.
Lusk Area. We own interests in 1,921 gross acres (278 net) in the Lusk Area in Lea County, New Mexico through Cross Border. The primary targets in the Lusk Prospect are the 2nd Bone Spring and Delaware reservoirs. We operate one vertical well (0.2 net) that is producing from the Delaware reservoir. The other operators in the Lusk Prospect are Occidental Petroleum Corporation, Apache Corp., Cimarex Energy Co., and Concho Resources Inc.
Cowden Lease. We own oil and natural gas interests in 760 gross (370 net) acres plus 48 acres of surface property in the Cowden Lease in Ector County, Texas. 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 Grayburg and San Andres formations.
Shafter Lake Lease. We own oil and natural gas interests in 322 gross (94 net) acres within the Shafter Lake San Andres field in Andrews County, Texas. The Shafter Lake Lease is horizontally severed at 4,520 feet and is held by production. 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.
Pawnee Prospect. We own oil and natural gas interests in 720 gross (360 net) acres in the Pawnee Prospect in Lea County, New Mexico. This acreage targets the Tansill, Yates and Delaware formations. RMR Operating is the operator of the Pawnee Prospect.
Other Non-Operated. Cross Border owns non-operated, oil and natural gas interests in 321,067 gross (9,725 net) acres in Chaves, Eddy, Lea and Roosevelt Counties, New Mexico of the Permian Basin. Current development of this acreage is focused on prospective Bone Spring acreage located in the heart of the 1st and 2nd Bone Spring play, which encompasses approximately 4,390 square miles across both New Mexico and Texas. Other non-operated development targets include the Queen, Grayburg, San Andres, Yeso, and Abo reservoirs. Our operating partners, which include Apache Corp., Mewbourne Oil Company, Concho Resources Inc., COG Operating LLC, LRE Operating, LLC, XTO Energy Inc., Cimarex Energy Co., and Occidental Petroleum Corporation, have significant footprints within these plays.
Onshore Gulf Coast
The following is a description of our properties in the onshore Gulf Coast as of June 30, 2015.
Villarreal Prospect. The Villarreal Prospect covers 1,099 gross (77 net) acres in Zapata County, Texas. ConocoPhillips Company is the operator of this prospect.
Frost Bank and Peal Ranch Prospects. The Frost Bank and Peal Ranch Prospects cover 2,926 gross (439 net) acres in Duval County, Texas. RMR Operating is the operator of the Frost Bank Prospect. The Peal Ranch Prospect is operated by White Oak Operating Company LLC.
Kansas
As of June 30, 2015, we owned oil and natural gas interests in 7,449 gross (3,725 net) acres in central Kansas.
New Mexico Non-Permian Minerals
Cross Border owns 536,526 gross (134,097 net) mineral acres in Hidalgo, Grant, Sierra, Socorro, and De Baca Counties, New Mexico. This mineral ownership carries no drilling commitments or leasehold obligations.
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 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.
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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 the properties of the Company, Black Rock, RMR Operating and Cross Border are pledged as collateral under the Credit Agreement.
Summary of Oil and Natural Gas Reserves
Proved Reserves
The following table sets forth our estimated proved reserves.
| As of July 1, 2015 | ||||||||||||||||
| Reserves | ||||||||||||||||
| Estimated proved reserve data (1)(2) | Oil (MBbls) |
Natural Gas (MMcf) |
Natural Gas Liquids (MBbls) |
Total (MBoe) | ||||||||||||
| Proved developed producing reserves | 525 | 2,351 | 98 | 1,015 | ||||||||||||
| Proved developed non-producing reserves | 81 | 121 | 1 | 102 | ||||||||||||
| Proved undeveloped reserves | 763 | 956 | 38 | 960 | ||||||||||||
| Total proved reserves | 1,369 | 3,428 | 137 | 2,077 | ||||||||||||
| (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 July 2014 through June 2015. For oil and NGL volumes, the average NYMEX spot price is $71.68 per Bbl. For natural gas volumes, the average Henry Hub spot price is $3.39 per MMBtu. Prices are adjusted for basis differentials, hydrocarbon quality, and transportation, processing, and gathering fees resulting in an oil price of $63.87 per barrel, natural gas liquids price of $23.80 per barrel, and natural gas price of $3.66 per Mcf. The adjusted oil, NGL and natural gas prices are held constant throughout the lives of the properties. |
| (2) | Proved reserves include 100% of the reserve quantities attributable to Cross Border. |
The following table sets forth our estimated PV-10 and standardized measure of discounted net cash flows as of July 1, 2015.
| (in thousands) | As of July 1, 2015 | |||
| PV-10 (1) | $ | 26,453 | ||
| Standardized measure | $ | 26,453 | ||
| (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: |
| (in thousands) | As of July 1, 2015 | |||
| PV-10 | $ | 26,453 | ||
| Future income taxes | — | |||
| Discount of future income taxes at 10% per annum | — | |||
| Standardized measure | $ | 26,453 | ||
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 July 1, 2015, our estimated proved reserves were 2.1 MMBoe, consisting of 66% oil, which is a decrease of 49% compared to our proved reserves of 4.1 MMBoe at June 30, 2014. The decrease during fiscal 2015 was attributable to 2.0 MMBoe of divested reserves and 0.3 MMBoe of production, partially offset by 0.2 MMBoe added through field extensions and another 0.1 MMBoe of upward revisions.
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Proved Undeveloped Reserves
At July 1, 2015, our estimated proved undeveloped reserves were 1.0 MMBoe, consisting of 79% oil, as compared to 2.0 MMBoe at June 30, 2014, consisting of 76% oil. During fiscal 2015, we added estimated proved undeveloped reserves of 0.2 MMBoe through field extensions. This addition was offset by 0.5 MMBoe of divested reserves, 0.1 MMBoe of proved undeveloped reserves converted to proved developed producing reserves, and 0.6 MMBoe of revisions. During the fiscal year ended June 30, 2015, we spent $2.2 million relating to the development of our proved undeveloped reserves. As of July 1, 2015, estimated future development costs relating to the development of our proved undeveloped reserves was $16.8 million. All of our currently identified proved undeveloped reserves are scheduled to be drilled by October 31, 2018.
Qualifications of Technical Persons and Internal Controls Over Reserves Estimation Process
Our July 1, 2015 reserve report was prepared by Cawley, Gillespie & Associates, Inc. (“CG&A”), independent petroleum engineers. CG&A estimated 100% of our proved reserves 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.
The technical persons responsible for preparing the reserves estimates presented herein meet the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the SPE Standards.
The principal person at CG&A who prepared the reserve report is Mr. Zane Meekins. Mr. Meekins has been a practicing consulting petroleum engineer at CG&A since 1989. Mr. Meekins is a Registered Professional Engineer in the State of Texas (License No. 71055) and has over 28 years of practical experience in petroleum engineering, with over 26 years of experience in the estimation and evaluation of reserves. He graduated from Texas A&M University in 1987 with a Bachelor of Science degree in Petroleum Engineering. Mr. Meekins meets or exceeds the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the SPE Standards. He is proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserve definitions and guidelines.
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 CG&A. We review with them our properties and discuss methods and assumptions used in their preparation of our reserves estimates. While we have no formal committee specifically designated to review reserves reporting and the reserves estimation process, a copy of the reserve report is reviewed with representatives of CG&A and our internal technical staff before we disseminate any of the information. Additionally, our senior management reviews and approves the reserve report 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 15 – 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, CG&A employs 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.
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Summary of Oil and Natural Gas Properties
Production, Price and Cost History
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 June 30, 2015 and 2014 and May 31, 2013.
| Fiscal Year Ended, | ||||||||||||
| June 30, 2015 |
June 30, 2014 |
May 31, 2013 (1) | ||||||||||
| Net Production sold | ||||||||||||
| Oil (Bbl) | 155,604 | 185,522 | 83,143 | |||||||||
| Natural gas (Mcf) | 682,706 | 882,606 | 645,609 | |||||||||
| Natural gas liquids (Bbl) | 32,193 | 27,208 | 7,427 | |||||||||
| Total (Boe) | 301,581 | 359,901 | 198,172 | |||||||||
| Average sales prices | ||||||||||||
| Oil ($/Bbl) | $ | 62.31 | $ | 93.47 | $ | 81.26 | ||||||
| Natural gas ($/Mcf) | 3.15 | 4.68 | 3.40 | |||||||||
| Natural gas liquids ($/Bbl) | 23.91 | 32.78 | 29.62 | |||||||||
| Total average price ($/Boe) | $ | 41.83 | $ | 62.51 | $ | 46.28 | ||||||
| Average production costs ($/Boe)(2) | $ | 11.70 | $ | 8.96 | $ | 8.93 | ||||||
| (1) | The results for the fiscal year ended May 31, 2013 only include results and estimated production from Cross Border since February 1, 2013. |
| (2) | Calculated based on production cost, not including production taxes. |
The following table provides a summary of our net production sold for oil and gas fields containing 15% or more of our total proved reserves as of June 30, 2015:
| Fiscal Year Ended, | ||||||||||||
| June 30, 2015 |
June 30, 2014 |
May 31, 2013 (1) | ||||||||||
| Madera | ||||||||||||
| Oil (Bbl) | 41,514 | 53,273 | 33,266 | |||||||||
| Natural gas (Mcf) | 95,374 | 180,815 | 51,151 | |||||||||
| Natural gas liquids (Bbl) | 17,801 | 14,531 | 4,357 | |||||||||
| Total (Boe) | 75,211 | 97,940 | 46,148 | |||||||||
| Lusk | ||||||||||||
| Oil (Bbl) | 37,591 | 64,208 | 27,180 | |||||||||
| Natural gas (Mcf) | 46,050 | 107,855 | 38,425 | |||||||||
| Natural gas liquids (Bbl) | 10,660 | 10,358 | 1,226 | |||||||||
| Total (Boe) | 55,926 | 92,542 | 34,810 | |||||||||
| Turkey Track | ||||||||||||
| Oil (Bbl) | 30,992 | 30,218 | 8,948 | |||||||||
| Natural gas (Mcf) | 115,160 | 87,829 | 23,389 | |||||||||
| Natural gas liquids (Bbl) | 1,472 | 1,877 | 543 | |||||||||
| Total (Boe) | 51,657 | 46,733 | 13,389 | |||||||||
| (1) | The results for the fiscal year ended May 31, 2013 only include production from Cross Border since February 1, 2013. |
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Developed and Undeveloped Acreage
The following table presents our total gross and net developed and undeveloped acreage by region as of June 30, 2015:
| Developed Acres | Undeveloped Acres | |||||||||||||||
| Gross (1) | Net (2) | Gross (1) | Net (2) | |||||||||||||
| Permian Basin (3) | 10,997 | 2,634 | 323,054 | 11,749 | ||||||||||||
| Onshore Gulf Coast | 4,456 | 645 | — | — | ||||||||||||
| New Mexico Non-Permian (4) | — | — | 536,526 | 134,097 | ||||||||||||
| Kansas | — | — | 7,449 | 3,725 | ||||||||||||
| Total | 15,453 | 3,279 | 867,029 | 149,571 | ||||||||||||
| (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. |
| (3) | Undeveloped acreage includes mineral ownership. |
| (4) | Reflects mineral ownership. |
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 leasehold acreage scheduled to expire in the next five fiscal years.
| Undeveloped Leasehold Acres |
% of Total Undeveloped Leasehold Acres | |||||||||||||
| As of June 30, | Gross (1) | Net (2) | Net (2) | |||||||||||
| 2016 | 5,552 | 2,776 | 2 | % | ||||||||||
| 2017 | 1,897 | 948 | 1 | % | ||||||||||
| 2018 | — | — | — | |||||||||||
| 2019 | — | — | — | |||||||||||
| 2020 | — | — | — | |||||||||||
| (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 June 30, 2015. Cross Border owns royalty interests in 22 gross wells (average of 0.003), which have been excluded from these well counts.
| Oil Wells | Natural Gas Wells | |||||||||||||||
| Gross (1) | Net (2) | Gross (1) | Net (2) | |||||||||||||
| Permian Basin | 172 | 36.5 | 40 | 3.2 | ||||||||||||
| Onshore Gulf Coast | — | — | 34 | 5.4 | ||||||||||||
| Total | 172 | 36.5 | 74 | 8.6 | ||||||||||||
| (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
At June 30, 2015, we had one well (0.02 net) in progress.
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.
| Development Wells | Exploratory Wells | |||||||||||||||||
| Fiscal Year Ended, | Productive | Dry | Productive | Dry | ||||||||||||||
| June 30, 2015 | 1.01 | — | 1.00 | 4.00 | ||||||||||||||
| June 30, 2014 | 1.95 | — | — | — | ||||||||||||||
| May 31, 2013 | 1.56 | — | 2.96 | — | ||||||||||||||
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Bloodworth Litgation
On May 4, 2011, Clifton M. (Marty) Bloodworth filed a lawsuit in the State District Court of Midland County, Texas, against Doral West Corp. d/b/a Doral Energy Corp. and Everett Willard Gray II. Mr. Bloodworth alleges that Mr. Gray, as CEO of Cross Border, made false representations which induced Mr. Bloodworth to enter into an employment contract that was subsequently breached by Cross Border. The claims that Mr. Bloodworth has alleged are: breach of his employment agreement with Doral West Corp, common law fraud, civil conspiracy breach of fiduciary duty, and violation of the Texas Deceptive Trade Practices-Consumer Protection Act. Mr. Bloodworth is seeking damages of approximately $280,000. Mr. Gray and Cross Border deny that Mr. Bloodworth’s claims have any merit.
SEC Subpoena
On August 27, 2014, the Company received a subpoena from the Securities and Exchange Commission (the “SEC”). The subpoena seeks the production of various documents and information by the Company during the period January 1, 2011 through the date of production. The accompanying letter from the SEC states that the subpoena “should not be construed as an indication by the Commission or its staff that any violation of law has occurred, nor as a reflection upon any person, entity or security.” The Company provided responsive materials to the SEC in the first calendar quarter of 2015. The Company is unable to predict the duration, scope or result of the SEC’s investigation. The Company intends to cooperate fully with the SEC.
Arbitration Claim
On August 27, 2015, the Company received a demand for arbitration with the Dallas, Texas office of the American Arbitration Association (“AAA”) that was filed by a former RMR employee, Tommy Folsom. The arbitration demand asserts claims for breach of contract and defamation and identifies the total claim amount as $100,000 and further seeks unspecified attorney’s fees, interest, arbitration costs, and punitive/exemplary damages. The Company disputes the allegations in the arbitration proceedings made by Mr. Folsom. The parties are engaged in settlement negotiations.
Item 4. Mine Safety Disclosures
Not applicable.
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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 OTC Pink marketplace 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. 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.
| Price Range | ||||||||
| High | Low | |||||||
| Fiscal Year 2015: | ||||||||
| Fourth Quarter | $ | 0.80 | $ | 0.40 | ||||
| Third Quarter | $ | 1.55 | $ | 0.60 | ||||
| Second Quarter | $ | 4.25 | $ | 1.22 | ||||
| First Quarter | $ | 5.70 | $ | 3.27 | ||||
| Fiscal Year 2014: | ||||||||
| Fourth Quarter | $ | 5.30 | $ | 3.50 | ||||
| Third Quarter | $ | 5.80 | $ | 4.12 | ||||
| Second Quarter | $ | 6.50 | $ | 4.00 | ||||
| First Quarter (includes the one month ended June 30, 2013) | $ | 8.20 | $ | 4.80 | ||||
Holders
As of November 1, 2015, we had 14,857,488 shares of common stock outstanding, and our outstanding shares of common stock were held by approximately 81 stockholder accounts of record. This number does not include beneficial owners holding shares in “street” or “nominee” name.
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 our board of directors to retain all earnings for use in the business operations and, accordingly, our board of directors does not anticipate declaring any dividends on our common stock in the foreseeable future.
Item 6. Selected Financial Data
Not required for a smaller reporting company.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Overview
We are a Dallas-based company with oil and natural gas properties in the Permian Basin of West Texas and Southeast New Mexico, the onshore Gulf Coast of Texas and Kansas.
In light of the Company's limited activities, the Company has determined that it is advisable to terminate the registration of its securities under the Exchange Act. The Company anticipates filing a Form 15 with the SEC to effect the deregistration on or about November 13, 2015. After careful consideration, the Board of Directors decided to deregister based on its belief that the savings the Company will achieve as a result of deregistration, particularly on costs related to the preparation and filing of SEC reports and compliance with Sarbanes-Oxley obligations, will benefit shareholders, and such benefits will outweigh any advantages of continuing as an SEC reporting company. Upon the filing of the Form 15, the Company's obligation to file periodic and current reports with the SEC, including Forms 10-K, 10-Q, and 8-K, will be suspended.
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 — Summary of Significant Accounting Policies” to our consolidated financial statements included elsewhere 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.
Debentures - Held to Maturity
Our investments in non-performing debentures were initially recorded at cost which we believe was fair value. Management estimated cash flows expected to be collected considering the contractual terms of the loans, the nature and estimated fair value of collateral, and other factors it deemed appropriate. The estimated fair value of the loans at acquisition was significantly less than the contractual amounts due under the terms of the loan agreements.
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Since, at the acquisition date, we expected to collect less than the contractual amounts due under the terms of the loans based, at least in part, on the assessment of the credit quality of the borrower, the loans are accounted for in accordance with Accounting Standards Codification (“ASC”) Topic 310-30, Loans and Debt Securities Acquired with Deteriorated Credit Quality (“ASC 310-30”). The difference between the contractually required payments on the loans as of the acquisition date and the total cash flows expected to be collected, or non-accretable difference, is not recognized.
Debentures are classified as non-accrual when management is unable to reasonably estimate the timing or amount of cash flows expected to be collected from the debentures or has serious doubts about further collectability of principal or interest. As of June 30, 2015 and 2014, all of our debentures were on non-accrual status since the borrower remains under the supervision of the bankruptcy court.
We periodically re-evaluate cash flows expected to be collected for each debenture based upon all available information as of the measurement date. Subsequent increases in cash flows expected to be collected are recognized prospectively through an adjustment to the debenture’s yield over its remaining life, which may result in a reclassification from non-accretable difference to accretable yield. Subsequent decreases in cash flows expected to be collected are evaluated to determine whether a provision for loan loss should be established. If decreases in expected cash flows result in a decrease in the estimated fair value of the debenture below its amortized cost, the debenture is deemed to be impaired and we will record a provision for impairment to write the debenture down to its estimated fair value.
Our investments in non-performing debentures are classified as held to maturity because we have the intent and ability to hold them until maturity.
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 July 1, 2015 or 2014 or June 1, 2013. 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 June 30, 2015, 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 a property account and release this account when the actual expenditure is later billed to us 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.
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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.
Noncontrolling Interests
Subsequent to January 28, 2013, we account for the noncontrolling interest in Cross Border in accordance with ASC Topic 810, Consolidation (“ASC 810”). ASC 810 establishes accounting and reporting standards for ownership interests in subsidiaries held by parties other than the parent, the amount of consolidated net income attributable to the parent and to the noncontrolling interest, changes in a parent’s ownership interest and the valuation of retained noncontrolling equity investments when a subsidiary is deconsolidated. ASC 810 also establishes reporting requirements that provide sufficient disclosures that clearly identify and distinguish between the interest of the parent and the interests of the noncontrolling owner. In addition, this guidance provides for increases and decreases in our controlling financial interests in consolidated subsidiaries to be reported in equity similar to treasury stock transactions.
Recent Accounting Pronouncements
In May 2014, the FASB issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers (“ASU 2014-09”), which supersedes nearly all existing revenue recognition guidance under U.S. GAAP. The core principle of ASU 2014-09 is to recognize revenues when promised goods or services are transferred to customers in an amount that reflects the consideration to which an entity expects to be entitled for those goods or services. ASU 2014-09 defines a five step process to achieve this core principle and, in doing so, more judgment and estimates may be required within the revenue recognition process than are required under existing U.S. GAAP. The standard is effective for annual periods beginning after December 15, 2016, and interim periods therein, using either of the following transition methods: (i) a full retrospective approach reflecting the application of the standard in each prior reporting period with the option to elect certain practical expedients, or (ii) a retrospective approach with the cumulative effect of initially adopting ASU 2014-09 recognized at the date of adoption (which includes additional footnote disclosures). The Company is currently evaluating the impact of the adoption of ASU 2014-09 on its consolidated financial statements and have not yet determined the method by which it will adopt the standard in 2017.
Results of Operations
Fiscal Year Ended June 30, 2015 Compared to Fiscal Year Ended June 30, 2014
Revenues
Oil and Natural Gas Sales. During the fiscal year ended June 30, 2015, we had oil and natural gas sales of $12.7 million, as compared to $22.5 million during the fiscal year ended June 30, 2014. The decrease in oil and natural gas sales was primarily attributable to lower commodity prices, depletion and the sale of assets during fiscal 2015.
Costs and Expenses
Exploration Expense. Exploration expense was $1.6 million for the fiscal year ended June 30, 2015, as compared to $1.2 million for the fiscal year ended June 30, 2014. The increase was primarily attributable to seismic costs and dry hole expense.
Production Taxes. Production taxes were $1.0 million for the fiscal year ended June 30, 2015, as compared to $2.1 million for the fiscal year ended June 30, 2014. The decrease was primarily attributable to lower commodity prices, depletion and the sale of assets.
Lease Operating Expenses. During the fiscal year ended June 30, 2015, we incurred lease operating expenses of $3.5 million, as compared to $3.2 million during the fiscal year ended June 30, 2014. The increase in lease operating expenses was attributable to costs related to new Madera wells and additional workover expense, partially offset by the sale of assets.
Natural Gas Transportation and Marketing Expenses. For the fiscal year ended June 30, 2015, natural gas transportation and marketing expenses remained flat at $0.2 million, as compared to the fiscal year ended June 30, 2014.
Depreciation, Depletion, Amortization and Impairment. For the fiscal year ended June 30, 2015, depreciation, depletion, amortization and impairment was $36.5 million, as compared to $9.7 million for the fiscal year ended June 30, 2014. The increase in depreciation, depletion, amortization and impairment was attributable to the impairment of our oil and gas assets resulting from significantly lower oil and gas prices.
General and Administrative Expense. General and administrative expense was $6.9 million for the fiscal year ended June 30, 2015, as compared to $8.6 million for the fiscal year ended June 30, 2014. The decrease in general and administrative expense was due primarily to lower personnel costs, professional fees and litigation expense.
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Other Expense. Other expense was $5.9 million for the fiscal year ended June 30, 2015, as compared to other expense of $6.2 million for the fiscal year ended June 30, 2014. The decrease in other expense was primarily attributable to lower interest expense and loss on extinguishment of preferred stock partially offset by increased impairment of debentures.
Liquidity and Capital Resources
General
Our primary source of liquidity for fiscal 2015 was borrowings under our Credit Facility. Due to the significant decline in oil prices since 2014, we have had limited access to capital to execute our capital development plan. We are currently evaluating future options and strategic plans.
Liquidity
At June 30, 2015, we had $1.0 million in cash and cash equivalents and $17.6 million of total indebtedness, consisting of $12.4 million under the Credit Facility and $5.2 million of Series A Preferred Stock, net of a discount of $1.2 million. At June 30, 2015, we had a working capital deficit of $14.4 million compared to a working capital deficit of $2.4 million at June 30, 2014.
Cash Flows
Net cash used in operating activities was $3.5 million for the fiscal year ended June 30, 2015, compared to $2.9 million for the fiscal year ended June 30, 2014. The increase in net cash used in operating activities was primarily due to decreased sales volumes resulting from the divestiture of oil and gas assets and significantly lower oil and gas prices.
Net cash provided by investing activities was $17.2 million for the fiscal year ended June 30, 2015, compared to net cash used in investing activities of $17.2 million for the fiscal year ended June 30, 2014 due to divestiture of oil and gas assets partially offset by capital expenditures for investment in oil and gas properties.
Net cash used in financing activities was $14.4 million for the fiscal year ended June 30, 2015, as compared to net cash provided by financing activities of $15.5 million for the fiscal year ended June 30, 2014. Net cash used in financing activities for the fiscal year ended June 30, 2015 was primarily comprised of $15.4 million of payments under the Senior Credit Facility, partially offset by a $1.0 million draw under the Senior Credit Facility.
Indebtedness
Credit Facility. The Credit Agreement with the Borrowers and the Lender provides for the Credit Facility with a maturity date of February 5, 2016. The borrowing base under the Credit Facility is determined at the discretion of the Lender based on, among other things, the Lender’s estimated value of the proved reserves attributable to the Borrowers’ oil and natural gas properties that have been mortgaged to the Lender, and is subject to regular redeterminations on September 30 and March 31 of each year, and interim redeterminations described in the Credit Agreement and potentially monthly commitment reductions, in each case which may reduce the amount of the borrowing base. As of June 30, 2015, the borrowing base and commitment were $12.4 million. The commitment is subject to monthly commitment reductions of $125,000 starting July 1, 2015.
A portion of the Credit Facility, in an aggregate amount not to exceed $2.0 million, may be used to issue letters of credit for the account of Borrowers. The Borrowers may be required to prepay the Credit Facility in the event of a borrowing base deficiency as a result of over-advances, sales of oil and gas properties or terminations of hedging transactions.
Amounts outstanding under the Credit Facility bear interest at a rate per annum equal to the greater of (x) the U.S. prime rate as published in The Wall Street Journal’s “Money Rates” table in effect from time to time and (y) 4.0%. Interest is payable monthly in arrears on the last day of each calendar month. Borrowings under the Credit Facility are secured by first priority liens on substantially all the property of each of the Borrowers and are unconditionally guaranteed by Doral West Corp. and Pure Energy Operating, Inc., each a subsidiary of Cross Border.
Under the Credit Agreement, the Borrowers are required to pay fees consisting of (i) an unused facility fee equal to 0.5% multiplied by the average daily unused commitment amount, payable quarterly in arrears until the commitment is terminated; (ii) a fronting fee payable on the date of issuance of each letter of credit and annually thereafter or on the date of any increase or extension thereof, equal to the greater of (a) 2.0% per annum multiplied by the face amount of such letter of credit or (b) $1,000; and (iii) an origination fee (x) of $200,000, and (y) payable on any date the commitment is increased, an additional facility fee equal to 1.0% multiplied by any increase of the commitment above the highest previously determined or redetermined commitment.
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The Credit Agreement contains negative covenants that may limit the Borrowers’ ability to, among other things, incur liens, incur additional indebtedness, enter into mergers, sell assets, make investments and pay dividends. The Credit Agreement permits the payment of cash dividends on our Series A Preferred Stock so long as we are not otherwise in default under the Credit Agreement and payment of such cash dividends would not cause us to be in default under the Credit Agreement.
The Credit Agreement also contains financial covenants, measured as of the last day of each fiscal quarter of Red Mountain, requiring the Borrowers to maintain a ratio of (i) the Borrowers’ and their consolidated subsidiaries’ consolidated current assets (inclusive of the unfunded commitment amount under the Credit Agreement) to consolidated current liabilities (exclusive of the current portion of long-term debt under the Credit Agreement) of at least 1.00 to 1.00; (ii) the Borrowers’ and their subsidiaries’ consolidated “Funded Debt” to consolidated EBITDAX (for the four fiscal quarter period then ended) of less than 3.50 to 1.00; and (iii) the Borrowers’ and their subsidiaries’ consolidated EBITDAX less paid and accrued dividends on the Series A Preferred Stock to interest expenses (each for the four fiscal quarter period then ended) of at least 3.00 to 1.00. Funded Debt is defined in the Credit Agreement as the sum of all debt for borrowed money, whether as a direct or reimbursement obligor, but excludes shares of Series A Preferred Stock. EBITDAX is defined in the Credit Agreement as (a) consolidated net income plus (b) (i) interest expense, (ii) income taxes, (iii) depreciation, (iv) depletion and amortization expenses, (v) dry hole and exploration expenses, (vi) non-cash losses or charges on any hedge agreements resulting from derivative accounting, (vii) extraordinary or non-recurring losses, (viii) expenses that could be capitalized under GAAP but by election of Borrowers are being expensed for such period under GAAP, (ix) costs associated with intangible drilling costs, (x) other non-cash charges, (xi) one-time expenses associated with transactions associated with (b)(i) through (iv), minus (c)(i) non-cash income on any hedge agreements resulting from FASB Statement 133, (ii) extraordinary or non-recurring income, and (iii) other non-cash income.
Amounts outstanding under the Credit Facility may be accelerated and become immediately due and payable upon specified events of default of Borrowers, including, among other things, a default in the payment of principal, interest or other amounts due under the Credit Facility, certain loan documents or hydrocarbon hedge agreements, a material inaccuracy of a representation or warranty, a breach of a covenant, a default with regard to certain loan documents which remains unremedied for a period of 30 days following notice, a default in the payment of other indebtedness of the Borrowers of $200,000 or more, bankruptcy or insolvency, certain changes in control, failure of the Lender’s security interest in any portion of the collateral with a value greater than $500,000, cessation of any security document to be in full force and effect, or Alan Barksdale ceasing to be Red Mountain’s Chief Executive Officer or Chairman of Cross Border and not being replaced with an officer acceptable to the Lender within 30 days.
Pursuant to the Credit Agreement, at least one of the Borrowers is required to have acceptable hydrocarbon hedge agreements in place at all times effectively hedging at least 50% of the oil volumes of the Borrowers, derived from the most recent third party engineering report received by Lender covering a period of not less than eighteen (18) consecutive months.
As of June 30, 2015, the Borrowers had collectively borrowed $12.4 million and had no availability under the Credit Facility. The Company was not in compliance with all of the financial covenants under the Credit Facility described above at June 30, 2015. As a result, the Lender has the right to accelerate all amounts outstanding under the Credit Facility upon notice to the Borrowers. As a result, we have included a "going concern" note in our consolidated financial statements. The Company has recorded the full amount of its outstanding borrowings under the Credit Facility as a current liability on its Consolidated Balance Sheet as of June 30, 2015 because the facility matures in February 2016.
Series A Preferred Stock. As of June 30, 2015, we had 254,463 shares of Series A Preferred Stock outstanding. The Series A Preferred Stock is mandatorily redeemable and is not convertible into shares of our common stock. We classify the Series A Preferred Stock as a long-term liability, and we record dividends paid or accrued as interest expense in our condensed consolidated statements of operations. Because we are in default under the Credit Facility, as described above, we cannot pay dividends on the Series A Preferred Stock.
In August 2013, we closed offerings issuing 476,687 Units. Each Unit consisted of one share of Series A Preferred Stock and one warrant to purchase up to 2.5 shares of common stock. The warrants are exercisable until the earlier of August 2016 or (ii) the first trading day that is at least 30 days after the date that we have provided notice to the holders of the warrants by filing a Current Report on Form 8-K stating that the common stock has (A) achieved a 20 trading day volume weighted average price of $15.00 per share or more and (B) traded, in the aggregate, 300,000 shares or more over the same 20 consecutive trading days for which the 20 trading day volume weighted average price was calculated; provided, that clause (ii) shall only be applicable so long as a warrant is exercisable for shares of common stock. The warrants have an exercise price of $10.00 per share. The warrants issued with the Series A Preferred Stock were valued at $2.4 million. The value of the warrants is treated as a discount to the Series A Preferred Stock and will be accreted over the life of the mandatorily redeemable preferred stock. Management determined the fair value 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 our common stock on the OTCBB on the date of issuance. The volatility and remaining term was approximately 55% and three years, respectively.
The Series A Preferred Stock is mandatorily redeemable on July 15, 2018 at $25.00 per share, plus accrued and unpaid dividends to the redemption date, for a total redeemable value of $6.4 million.
Off-Balance Sheet Arrangements
As of June 30, 2015, we did not have any off-balance sheet arrangements as defined by Regulation S-K.
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Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Not required for a smaller reporting company.
Item 8. Financial Statements and Supplementary Data
Our consolidated financial statements required by this item are included in this report beginning on page F-1 and are incorporated herein by reference.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Not applicable.
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 June 30, 2015 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 June 30, 2015 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 June 30, 2015 because of the identification of the material weaknesses identified below.
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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 appropriate accounting personnel to properly design and implement internal control procedures over financial reporting. | |
| ● | Lack of sufficient review of accounting schedules to properly prevent and detect errors. |
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
On November 13, 2015, our Board of Directors voted to voluntarily deregister our securities under the Exchange Act and become a non-reporting company. In connection therewith, the Board of Directors approved the filing with the SEC of a Form 15 to voluntarily deregister our securities under Section 12(g) of the Exchange Act and suspend our reporting obligations under Section 15(d) of the Exchange Act. We expect to file the Form 15 on or about November 13, 2015. We expect that our obligations to file periodic reports, such as Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q and Current Reports on Form 8-K, will be suspended immediately upon the filing of the Form 15 with the SEC, and our proxy statement, Section 16 and other Section 12(g) reporting responsibilities will terminate effective 90 days after the filing of the Form 15. To the extent the Company does not complete the deregistration process as anticipated, management will assess its plans for remediation of the material weaknesses described above.
Changes in Internal Control Over Financial Reporting
Due to a reduction in staffing, there have been 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. Additionally, the Company anticipates a further reduction in staff that is reasonably likely to materially affect our internal control over financial reporting.
None.
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Item 10. Directors, Executive Officers and Corporate Governance
The following sets forth information about the Company’s current directors and executive officers:
| Name | Age | Position | ||
| Alan W. Barksdale | 38 | President, Chief Executive Officer and Chairman of the Board of Directors | ||
| Hilda D. Kouvelis | 52 | Chief Accounting Officer and Executive Vice President | ||
| David M. Heikkinen | 44 | Director | ||
| Richard Y. Roberts | 64 | Director | ||
| Paul N. Vassilakos | 39 | Director | ||
| Frank Yates, Jr. | 59 | Director |
Alan W. Barksdale has been our President, Chief Executive Officer and Chairman of the Board since June 2011 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 Capital, Inc., our wholly owned subsidiary (“Black Rock”), since May 2010. Mr. Barksdale has also been the owner and president of StoneStreet Group, Inc. (“StoneStreet”) and president and manager of StoneStreet Operating Company, LLC (“StoneStreet Operating”), since 2008. Mr. Barksdale has also been the president of AWB Enterprises, Inc., a holding company that owns a percentage of StoneStreet Operating, 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 Resources, Inc. (“Cross Border”), an oil and gas exploration company and majority owned subsidiary of the Company, since May 2012. We believe that Mr. Barksdale’s experience in operating, managing, financing and investing in more than 200 wells in Kansas, Louisiana, New Mexico and Texas, combined with his over ten years of capital markets experience and contacts and relationships, provides our Board with management and operational direction.
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. Prior to joining TransAtlantic Petroleum, Ms. Kouvelis served as Controller for Ascent Energy, Inc. from 2001 to 2004 and as Financial Controller for the international operations at the headquarters of PetroFina, S.A. in Brussels, Belgium from 1998 through 2000.
David M. Heikkinen has been a director since April 2013. Mr. Heikkinen has served as the Chief Executive Officer of Heikkinen Energy Advisors, LLC, an institutional equity research and investment advisory firm, since he founded it in July 2012. From December 2005 to February 2012, Mr. Heikkinen served as Head of Exploration and Production Research for Tudor, Pickering, Holt & Co., an integrated energy investment and merchant bank, providing advice and services to institutional and corporate clients. From February 2000 to December 2005, Mr. Heikkinen served as the Exploration and Production Analyst for Capital One Southcoast, Inc., an energy investment banking boutique. From January 1994 to February 2000, Mr. Heikkinen held various engineering roles with Shell Offshore Inc. and Shell International Exploration and Production. In addition, Mr. Heikkinen has served as a director of Taos Resources, a Houston-based oil and gas exploration and production company within the past five years. We believe our Board benefits from Mr. Heikkinen’s extensive capital markets experience in the oil and gas industry.
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 Long Island Iced Tea Corp. (“LTEA”), and was a director of Cullen Agricultural Holding Corp. (“CAH”) prior to its merger with LTEA. He was a director of Nyfix, Inc. from September 2005 to December 2009 and 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 with necessary insight into the requirements and needs of an emerging public company.
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Paul N. Vassilakos has been a director since October 2011. Mr. Vassilakos also previously served as our interim 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 CAH since October 2009 and the Chief Executive Officer and a director of CAH since November 2013 and has continued in these roles with LTEA after its merger with CAH. 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.
Frank Yates, Jr. has been a director since June 2014. Mr. Yates has been Manager of Yates Industries, LLC, a single member investment company, since 1999 and has served as Chairman of the Board of Taos Resources, a Houston-based oil and gas exploration and production company, since June 2013. From 1992 to 2007, he served as Vice President and, in 2007 and 2008, as President of Yates Petroleum Corporation, an independent oil and gas exploration and production company producing over 50,000 barrels of oil equivalent per day. From 1986 to September 2009, he served as President of MYCO Industries, Inc., associated with Yates Petroleum Corp in the oil and gas industry.
Board Committees
On July 21, 2014, the Board established an audit committee, compensation committee and nominating and corporate governance committee. The written charter for each committee and our code of conduct and ethics are posted and available on our website at www.redmountainresources.com. Shareholders may request copies of these corporate governance documents, free of charge, by writing to our Corporate Secretary at 14282 Gillis Road, Farmers Branch, Texas 75244.
Audit Committee Functions
The audit committee is responsible for overseeing the accounting and financial reporting processes of the Company and the audits of our financial statements. The audit committee is also directly responsible for the appointment, compensation, retention and oversight of the work of our independent auditors, including the resolution of disagreements between management and the auditors regarding financial reporting. Additionally, the audit committee approves all related-party transactions that are required to be disclosed pursuant to Item 404 of Regulation S-K. The audit committee currently consists of Mr. Heikkinen, who acts as chair, Mr. Vassilakos and Mr. Yates. All members of the audit committee have been determined to be financially literate and to meet the appropriate NASDAQ and SEC standards for independence. The Board has determined that each of Messrs. Heikkinen and Vassilakos is an “audit committee financial expert” in accordance with SEC rules.
Compensation Committee Functions
The compensation committee is responsible for, among other things, annually reviewing and recommending to the Board the salaries and other compensation of our executive officers, including our Chief Executive Officer. The compensation committee is also responsible for reviewing and recommending to the Board the compensation of our non-employee directors and overseeing regulatory compliance with respect to compensation matters. The compensation committee also produces annual reports on executive compensation for inclusion in our proxy statement. The compensation committee currently consists of Mr. Roberts, who acts as chair, and Mr. Heikkinen. All members of the compensation committee have been determined to meet the appropriate NASDAQ standards for independence.
Nominating and Corporate Governance Committee Functions
The nominating and corporate governance committee is responsible for, among other things, evaluating and recommending to the Board qualified nominees for election as directors and qualified directors for committee membership, as well as developing and recommending to the Board corporate governance principles applicable to the Company. The nominating and corporate governance committee currently consists of Mr. Vassilakos, who acts as chair, and Mr. Roberts. All members of the nominating and corporate governance committee have been determined to meet the appropriate NASDAQ standards for independence.
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The nominating and corporate governance committee identifies individuals qualified to become members of the Board and recommend candidates to the Board to fill new or vacant positions. Except as may be required by rules promulgated by NASDAQ or the SEC, there are currently no specific, minimum qualifications that must be met by each candidate for the Board, nor are there specific qualities or skills that are necessary for one or more of the members of the Board to possess. In recommending candidates, the nominating and corporate governance committee considers such factors as it deems appropriate, including possible conflicts of interest.
Board and Committee Meetings
Our Board met 8 times during the fiscal year ended June 30, 2015. During fiscal 2015, each director attended 75% or more of the aggregate number of meetings held by our Board. The Board’s independent directors did not meet separately from the Board meetings that were held during fiscal 2015.
We do not have a formal policy respecting attendance by our Board at annual meetings of the shareholders. However, we attempt to schedule our annual meetings so that all of our directors can attend and encourage them to do so. All of the then-current members of our Board attended the Company’s 2014 Annual Meeting of Shareholders.
Board Leadership Structure and Role in Risk Oversight
Mr. Barksdale serves both as our Chief Executive Officer and Chairman of the Board. At this time, our Board believes that the Company is best served by having one person serve as both chief executive officer and the chairman because this structure provides unified leadership and direction. Given Mr. Barksdale’s extensive experience in operating, managing, financing and investing in oil and natural gas wells and his capital markets experience, Mr. Barksdale is uniquely situated to provide day-to-day operational guidance, as well as broader strategic and management direction for the Company. His knowledge of the Company’s daily operations as Chief Executive Officer ensures that key business issues are brought to our Board’s attention and prioritized as appropriate for the Company’s success. Our Board has not appointed a lead independent director.
Our Board’s role in the risk oversight process includes receiving regular reports from senior management on areas of material risk, including operational, financial, legal and regulatory and strategic and reputational risks. In connection with its review of the operations of our business and corporate functions, our Board considers and addresses the primary risks associated with those functions. Our Board regularly engages in discussions of the most significant risks that we are facing and how we manage these risks.
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 Securities Exchange Act of 1934 (the “Exchange Act”) 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 and representations to us from our executive officers and directors, we have no knowledge of any failure to report on a timely basis any transaction required to be disclosed under Section 16(a) during fiscal 2015.
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Item 11. Executive Compensation
FISCAL 2015 AND 2014 SUMMARY COMPENSATION TABLE
The following table sets forth information concerning the compensation of our named executive officers for the fiscal years ended June 30, 2015 and 2014. For fiscal 2015, our named executive officers consist of: (i) our President and Chief Executive Officer, and (ii) our Chief Accounting Officer and Executive Vice President. We do not have any other executive officers.
| Name and Principal Position | Period Ended | Salary ($) | Bonus ($) | Option Awards ($) | All Other Compensation ($) | Total ($) | ||||||||||||||||
| Alan Barksdale (1) | June 30, 2015 | 300,000 | — | — | 21,000 | (2)(3) | 321,000 | |||||||||||||||
| President and Chief Executive Officer | June 30, 2014 | 300,000 | — | — | 30,000 | (2)(3) | 330,000 | |||||||||||||||
| Hilda D. Kouvelis (4) | June 30, 2015 | 200,000 | — | — | — | 200,000 | ||||||||||||||||
| Chief Accounting Officer and Executive Vice President | June 30, 2014 | 200,000 | 20,000 | — | — | 220,000 | ||||||||||||||||
| (1) | Mr. Barksdale has served as Chief Executive Officer since June 22, 2011 and as President since July 25, 2012. |
| (2) | Includes $3,000 for fiscal 2015 and $12,000 for fiscal 2014 received from Cross Border, a subsidiary of the Company, for services as a director of Cross Border. |
| (3) | Includes vehicle allowance. |
| (4) | Ms. Kouvelis has served as our Chief Accounting Officer and Executive Vice President since February 7, 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. The performance bonus is payable in cash, shares of our common stock, or a combination thereof as determined by the Board. Ms. Kouvelis is also entitled to receive an initial stock option grant in an amount to be determined by the Board with a value of not less than $42,500. As of November 1, 2015, neither the performance objectives and parameters nor the size of the initial stock option grant had been determined. 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 expired on January 31, 2015 and was not renewed.
“Cause” in Ms. Kouvelis’ employment agreement 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, 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 agreement is defined as a material reduction in the executive’s salary or benefits or duties, authority or responsibilities (and the Company’s failure to cure such circumstances within no less than 10 days of the Company receiving written notice from the executive of the obligation to do so), the relocation of the executive’s work location to a location more than 50 miles from the executive’s current location, or the failure of a successor to assume and perform under the agreement.
Long-Term Incentive Plan
The Red Mountain Resources, Inc. 2012 Long-Term 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. As of June 30, 2015, no awards had been issued under the Incentive Plan, and there were 820,000 shares of common stock available for issuance under the Incentive Plan.
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Potential Payments Upon Termination or Change of Control
As of June 30, 2015, neither of our named executive officers were entitled to any potential payments upon termination or a change of control.
Director Compensation
The following is a summary of our director compensation program for the fiscal year ended June 30, 2015. For the first fiscal quarter ended September 20, 2014, each director received a cash fee of $8,750. Subsequently, the compensation committee determined to cease payments of cash fees to our non-employee directors. In addition, each non-employee director annually earned $76,250 to be paid in shares of our common stock at a price equal to the last sales price of our common stock on the OTC Pink marketplace on the date of issuance. The stock grant is earned annually on June 30th of each year (or the next business day if June 30th is not a business day) and pro-rated for partial service in any given year. The term of office for each director is one year, or until his or her successor is elected at our annual shareholders meeting and qualified.
DIRECTOR COMPENSATION TABLE
The table below reflects compensation paid to non-employee directors for the fiscal year ended June 30, 2015. Mr. Barksdale serves as a director and our President and Chief Executive Officer. As such, information about his compensation is listed in the Fiscal 2015 and 2014 Summary Compensation Table above. Mr. Barksdale did not receive any additional compensation for his service as a director.
| Name | Fees Earned or Paid in Cash ($) | Stock Awards ($)(1)(2) | Total ($) | |||||||||
| David M. Heikkinen | 8,750 | 76,250 | 85,000 | |||||||||
| Richard Y. Roberts | 8,750 | 76,250 | 85,000 | |||||||||
| Paul N. Vassilakos | 8,750 | 76,250 | 85,000 | |||||||||
| Frank Yates, Jr. | 8,750 | 76,250 | 85,000 | |||||||||
| (1) | Consists of shares of common stock earned by the directors on June 30, 2015 pursuant to our director compensation program. These stock awards have not been issued as of November 1, 2015. |
| (2) | The amounts shown were not actually paid to the directors. Rather, as required by the rules of the SEC, the amounts represent the aggregate grant date fair value of the shares of common stock awarded to each of them in fiscal 2015. These values were determined in accordance with Financial Accounting Standards Board Accounting Standards Codification Topic 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. 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 November 1, 2015 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.
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| Name and Address of Beneficial Owner (1) | Amount of Beneficial Ownership (2)(3) | Percentage of Outstanding Common Stock (2)(3) | ||||||
| Alan W. Barksdale | 1,102,239 | (4)(5) | 7.5 | % | ||||
| Hilda D. Kouvelis | — | — | ||||||
| David M. Heikkinen | — | — | ||||||
| Richard Y. Roberts | 2,045 | * | ||||||
| Paul N. Vassilakos | 7,045 | * | ||||||
| Frank Yates, Jr. | — | — | ||||||
| All executive officers and directors as a group (6 persons) | 1,111,329 | 7.5 | % | |||||
| StoneStreet Group, Inc. | 1,101,250 | (4)(5) | 7.4 | % | ||||
| 14282 Gillis Rd. | ||||||||
| Farmers Branch, Texas 75244 | ||||||||
| Sophia Company Inc. | 2,224,863 | (6)(7) | 14.8 | % | ||||
| Sterling House, 16 Wesley Street | ||||||||
| Hamilton, HM 11 Bermuda | ||||||||
| Blue Jays Stiftung | 2,224,863 | (6)(7) | 14.8 | % | ||||
| Landstrasse 99 | ||||||||
| Postfach 532 | ||||||||
| FL-9494 Schaan | ||||||||
| Liechtenstein | ||||||||
| * | Less than one percent. |
| (1) | Unless noted otherwise, the address for the above individuals is 14282 Gillis Rd., Farmers Branch, Texas 75244. |
| (2) | Beneficial ownership as reported in the above table has been determined in accordance with Rule 13d-3 under the Exchange Act. Unless otherwise specified, beneficial ownership information is based on the most recent Forms 3, 4 and 5 and Schedule 13D and 13G filings with the SEC and reports made directly to the Company. The number of shares shown as beneficially owned includes shares of common stock that may be acquired upon exercise of warrants within 60 days after November 1, 2015. Except as indicated by footnote, and subject to community property laws where applicable, the persons named in the table above have sole voting and investment power with respect to all shares of common stock shown as beneficially owned by them. |
| (3) | The percentages indicated are based on 14,857,488 shares of common stock outstanding on November 1, 2015. Shares of common stock that may be acquired upon exercise of warrants within 60 days after November 1, 2015 are deemed outstanding for computing the percentage of the person or entity holding such warrants but are not outstanding for computing the percentage of any other person or entity. |
| (4) | Includes 1,101,250 shares of common stock owned directly 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 the shares beneficially owned by StoneStreet. Also includes 989 shares of common stock owned directly by AWB Enterprises, Inc. Alan Barksdale is the sole shareholder of AWB Enterprises, Inc. and may be deemed to beneficially own the shares beneficially owned by AWB Enterprises, Inc. |
| (5) | Includes 500 warrants exercisable for 1,250 shares of our common stock. |
| (6) | Based on information contained in the Schedule 13G filed with the SEC on October 24, 2014 by Sophia Company Inc. and Blue Jays Stiftung, which indicates that (i) Sophia Company Inc. has sole voting and dispositive power over 2,224,863 shares of our common stock, and (ii) Blue Jays Stiftung has shared voting and dispositive power over 2,224,863 shares of our common stock. |
| (7) | Includes 88,889 warrants exercisable for 222,222 shares of our common stock. |
Equity Compensation Plans
The following table sets forth the number of shares of common stock available for future issuance under the Incentive Plan at June 30, 2015. No awards had been issued under the Incentive Plan as of June 30, 2015.
| 47 |
| Plan Category | Number of Securities to Be Issued Upon Exercise of Outstanding Options, Warrants and Rights (a) | Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights (b) | Number of Securities Remaining Available for Future Issuable Under Equity Compensation Plans (Excluding Securities Reflected in Column (a))(c) | |||||||
| Equity compensation plans approved by security holders | — | — | 820,000 | |||||||
| Equity compensation plans not approved by security holders | — | — | — | |||||||
| Total | — | — | 820,000 | |||||||
Item 13. Certain Relationships and Related Transactions, and Director Independence
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 Inc. on our Madera 24-2H well. At the time, each of these entities were owned or partially owned by Randell K. Ford, our then-current director. Mr. Ford passed away on December 14, 2013. During the fiscal years ended June 30, 2015 and 2014, the Company paid an aggregate of $0 and $2.9 million, respectively, to these entities for engineering, drilling and completion services.
In addition, the Company was a party to a lease agreement with R.K. Ford and Associates, pursuant to which the Company leased office space in Midland, Texas. During the fiscal year ended June 30, 2014, the Company paid $2,100 to R.K. Ford and Associates pursuant to the lease agreement. The lease agreement expired in July 2013.
The Company entered into a master service agreement with Integrity Well Services LLC (“Integrity”) pursuant to which Integrity provides well services to us. This entity is partially owned by Tommy Folsom, formerly the Executive Vice President and Director of Exploration and Production for RMR Operating, LLC, our subsidiary, and formerly the Executive Vice President and Director of Exploration and Production for us. During fiscal years ended June 30, 2015 and 2014, the Company paid approximately $0 and $313,000, respectively, to Integrity pursuant to the master service agreement.
Enerstar, a company owned by Mr. Folsom, owns an overriding royalty interest in our Madera Prospect. During the fiscal years ended June 30, 2015 and 2014, the Company paid royalties of approximately $11,900 and $15,000, respectively, to Enerstar.
Director Independence
The standards relied upon by the Board in determining whether a director is “independent” are those set forth in the rules of the NASDAQ Capital Market. The corporate governance rules of the NASDAQ Capital Market require that a majority of the Board consist of directors who are “independent” of us. The Board has determined each of Messrs. Heikkinen, Roberts, Vassilakos and Yates qualify as “independent” under the NASDAQ standards for determining independence under the corporate governance rules of the NASDAQ Capital Market.
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 years ended June 30, 2015 and 2014 were as follows:
| Fiscal Year Ended | ||||||||
| June 30, 2015 | June 30, 2014 | |||||||
| Audit Fees (1) | $ | 171,131 | $ | 569,635 | ||||
| Audit-Related Fees (2) | — | — | ||||||
| Tax Fees (3) | 11,623 | 90,123 | ||||||
| All Other Fees | — | — | ||||||
| Total | $ | 182,754 | $ | 659,758 | ||||
| (1) | Audit services billed consisted of the audits of our annual consolidated financial statements and reviews of our quarterly condensed consolidated financial statements. |
| (2) | Audit-related fees principally include costs incurred related to audit-related work regarding proposed acquisitions. |
| (3) | Tax fees include tax compliance and tax planning. |
Audit Committee Approval
Our Board has adopted a procedure for pre-approval of all fees charged by its independent registered public accounting firm. Under the procedure, the audit committee of our Board approves the engagement letter with respect to auditing services and internal control-related services. Other fees are subject to pre-approval by the audit committee.
| 48 |
Item 15. Exhibits and Financial Statement Schedules
| (a) | The following documents are filed as part of this Annual Report on Form 10-K: | |
| 1. | Report of Independent Registered Public Accounting Firm | |
Consolidated Balance Sheets as of June 30, 2015 and 2014
Consolidated Statements of Operations for the Fiscal Years Ended June 30, 2015 and 2014
Consolidated Statements of Cash Flows for the Fiscal Years Ended June 30, 2015 and 2014
Consolidated Statements of Stockholders’ Equity for the Fiscal Years Ended June 30, 2015 and 2014
Notes to Consolidated 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.
| 49 |
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
| Page | ||
| Report of Independent Registered Public Accounting Firm | F-1 | |
| Consolidated Balance Sheets as of June 30, 2015 and 2014 | F-2 | |
| Consolidated Statements of Operations for the Fiscal Years Ended June 30, 2015 and 2014 | F-3 | |
| Consolidated Statements of Cash Flows for the Fiscal Years Ended June 30, 2015 and 2014 | F-4 | |
| Consolidated Statements of Stockholders’ Equity for the Fiscal Years Ended June 30, 2015 and 2014 | F-5 | |
| Notes to Consolidated Financial Statements | F-6 |
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 sheets of Red Mountain Resources, Inc. (“the Company”) and subsidiaries as of June 30, 2015 and 2014, and the related consolidated statements of operations, stockholders’ and members’ equity, and cash flows for each of the years then ended. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Red Mountain Resources, Inc. and subsidiaries as of June 30, 2015 and 2014 and the consolidated results of their operations and their cash flows for each of the years then ended in conformity with U.S. generally accepted accounting principles.
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 financial statements, the Company has suffered recurring losses from operations and has a working capital deficit of $14.4 million. The Company is currently in default on their Credit Facility. This raises substantial doubt about the Company's ability to continue as a going concern. Management's plans in regard to these matters also are described in Note 2. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.
/s/ Hein & Associates LLP
Dallas, Texas
November 13, 2015
F-1
Red Mountain Resources, Inc. and Subsidiaries
Consolidated Balance Sheets
(in thousands)
| ASSETS | June 30, 2015 | June 30, 2014 | ||||||
| Current Assets: | ||||||||
| Cash and cash equivalents | $ | 943 | $ | 1,682 | ||||
| Accounts receivable – oil and natural gas sales | 1,436 | 3,186 | ||||||
| Accounts receivable – joint interest | 949 | 1,645 | ||||||
| Prepaid expenses and other current assets | 670 | 527 | ||||||
| Commodities derivative asset – current | 190 | 37 | ||||||
| Deferred tax asset – current | — | 368 | ||||||
| Total current assets | 4,188 | 7,445 | ||||||
| Long-Term Investments: | ||||||||
| Debentures – held to maturity | 773 | 4,820 | ||||||
| Oil and Natural Gas Properties, Successful Efforts Method: | ||||||||
| Proved properties | 44,483 | 82,362 | ||||||
| Unproved properties | 11,458 | 19,109 | ||||||
| Other property and equipment | 1,112 | 1,196 | ||||||
| Less accumulated depreciation, depletion, amortization and impairment | (30,031 | ) | (19,497 | ) | ||||
| Oil and natural gas properties, net | 27,022 | 83,170 | ||||||
| Other Assets: | ||||||||
| Restricted cash, long-term | 874 | 493 | ||||||
| Debt issuance costs | 632 | 1,101 | ||||||
| Security deposit and other assets | 62 | 197 | ||||||
| Total Assets | $ | 33,551 | $ | 97,226 | ||||
| LIABILITIES AND STOCKHOLDERS’ EQUITY | ||||||||
| Current Liabilities: | ||||||||
| Accounts payable | $ | 1,041 | $ | 3,536 | ||||
| Revenues payable | 920 | 1,673 | ||||||
| Accrued expenses | 1,552 | 2,035 | ||||||
| Line of credit, current | 12,400 | — | ||||||
| Commodities derivative liability | — | 121 | ||||||
| Dividend payable | 581 | 179 | ||||||
| Asset retirement obligation – current | — | 214 | ||||||
| Environmental remediation liability – current | 2,057 | 2,067 | ||||||
| Total current liabilities | 18,551 | 9,825 | ||||||
| Long-Term Liabilities: | ||||||||
| Mandatorily redeemable preferred stock, net of discount of $1,173 and $1,561 | 5,189 | 4,801 | ||||||
| Stock issuance liability | 50 | — | ||||||
| Line of credit, net of current portion | — | 26,800 | ||||||
| Deferred tax liability – long-term | — | 409 | ||||||
| Asset retirement obligation, net of current portion | 2,931 | 5,531 | ||||||
| Total long-term liabilities | 8,170 | 37,541 | ||||||
| Total Liabilities | 26,721 | 47,366 | ||||||
| Commitments and Contingencies (Note 12) | ||||||||
| Stockholders’ Equity: | ||||||||
| Common stock, $0.00001 par value; 50,000 shares authorized; 14,857 shares issued and outstanding as of June 30, 2015 and June 30, 2014 | 1 | 1 | ||||||
| Noncontrolling interest | 3,217 | 6,076 | ||||||
| Additional paid-in capital | 78,105 | 78,105 | ||||||
| Accumulated deficit | (74,493 | ) | (34,322 | ) | ||||
| Total stockholders’ equity | 6,830 | 49,860 | ||||||
| Total Liabilities and Stockholders’ Equity | $ | 33,551 | $ | 97,226 | ||||
The accompanying notes are an integral part of these consolidated financial statements.
F-2
Red Mountain Resources, Inc. and Subsidiaries
Consolidated Statements of Operations
(in thousands, except per share amounts)
| Fiscal Year Ended | ||||||||
| June 30, 2015 | June 30, 2014 | |||||||
| Revenue: | ||||||||
| Oil and natural gas sales | $ | 12,738 | $ | 22,498 | ||||
| Operating Expenses: | ||||||||
| Exploration expense | 1,569 | 1,193 | ||||||
| Production taxes | 1,011 | 2,116 | ||||||
| Lease operating expenses | 3,529 | 3,224 | ||||||
| Natural gas transportation
and marketing expenses | 195 | 183 | ||||||
| Depreciation, depletion,
amortization and impairment | 36,538 | 9,694 | ||||||
| Accretion of discount on asset retirement obligation | 131 | 267 | ||||||
| General and administrative expense | 6,935 | 8,584 | ||||||
| Total operating expenses | 49,908 | 25,261 | ||||||
| Loss from Operations | (37,170 | ) | (2,763 | ) | ||||
| Other Income (Expense): | ||||||||
| Loss on extinguishment of mandatorily redeemable preferred stock | — | (2,281 | ) | |||||
| Interest expense | (2,606 | ) | (3,363 | ) | ||||
| Impairment of debentures | (3,787 | ) | — | |||||
| Gain (loss) on derivatives | 574 | (544 | ) | |||||
| Loss on sale of assets | (85 | ) | — | |||||
| Total Other Expense | (5,904 | ) | (6,188 | ) | ||||
| Loss Before Income Taxes | (43,074 | ) | (8,951 | ) | ||||
| Income tax provision | 44 | (44 | ) | |||||
| Net loss | (43,030 | ) | (8,995 | ) | ||||
| Net income/(loss) attributable to noncontrolling interest | (2,860 | ) | 513 | |||||
| Net loss attributable to Red Mountain Resources, Inc. | $ | (40,170 | ) | $ | (9,508 | ) | ||
| Basic and diluted loss per common share | $ | (2.70 | ) | $ | (0.70 | ) | ||
| Basic and diluted weighted average common shares outstanding | 14,857 | 13,626 | ||||||
The accompanying notes are an integral part of these consolidated financial statements.
F-3
Red Mountain Resources, Inc. and Subsidiaries
Consolidated Statements of Cash Flows
(in thousands)
| Fiscal Year Ended | ||||||||
| June 30, 2015 | June 30, 2014 | |||||||
| Cash Flow From Operating Activities: | ||||||||
| Net loss | $ | (43,030 | ) | $ | (8,995 | ) | ||
| Adjustments to reconcile net loss to net cash used in operating activities: | ||||||||
| Depreciation, depletion, amortization and impairment | 36,538 | 9,694 | ||||||
| Issuance of stock for consulting services | — | 194 | ||||||
| Dividend declared for preferred shares | 402 | 179 | ||||||
| Loss on extinguishment of mandatorily redeemable preferred stock | — | 2,281 | ||||||
| Deferred income tax expense | (41 | ) | 44 | |||||
| Accretion of discount on asset retirement obligation | 131 | 267 | ||||||
| Amortization of debt issuance costs | 857 | 1,449 | ||||||
| Change in fair value of commodity derivatives | (274 | ) | 216 | |||||
| Impairment on debentures | 3,787 | — | ||||||
| Change in working capital: | ||||||||
| Accounts receivable—oil
and natural gas sales |
1,750 | 1,487 | ||||||
| Accounts receivable—joint interest | 697 | 21 | ||||||
| Prepaid expenses and other current assets | (8 | ) | 467 | |||||
| Accounts payable | (3,517 | ) | (5,268 | ) | ||||
| Accrued expenses | (438 | ) | 858 | |||||
| Restricted cash | (381 | ) | 41 | |||||
| Net cash used in operating activities | (3,527 | ) | (2,853 | ) | ||||
| Cash Flow From Investing Activities: | ||||||||
| Additions to oil and natural gas properties | (8,120 | ) | (17,033 | ) | ||||
| Interest received on debentures | 260 | — | ||||||
| Divestiture of oil and natural gas properties | 25,000 | — | ||||||
| Other property and equipment | 84 | (136 | ) | |||||
| Settlement of asset retirement obligations | (36 | ) | (2 | ) | ||||
| Net cash provided by (used in) investing activities | 17,188 | (17,171 | ) | |||||
| Cash Flow From Financing Activities: | ||||||||
| Proceeds from issuance of common shares, net of issuance costs | — | 3,606 | ||||||
| Draws on line of credit | 1,000 | 12,000 | ||||||
| Payments under line of credit | (15,400 | ) | (5,000 | ) | ||||
| Payments on notes payable | — | (2,000 | ) | |||||
| Issuance costs of notes payable | — | (157 | ) | |||||
| Issuance of preferred stock, net of expenses | — | 7,095 | ||||||
| Net cash provided by (used in) financing activities | (14,400 | ) | 15,544 | |||||
| Net change in cash and equivalents | (739 | ) | 1,226 | |||||
| Cash at beginning of period | 1,682 | 456 | ||||||
| Cash at end of period | $ | 943 | $ | 1,682 | ||||
| Supplemental Disclosure of Cash Flow Information | ||||||||
| Cash paid during the period for interest | $ | 1,187 | $ | 2,274 | ||||
| Non-Cash Transactions | ||||||||
| Change in asset retirement obligation estimate | $ | — | $ | 385 | ||||
| Issuance of shares for debentures | $ | — | $ | 541 | ||||
| Issuance of warrants with preferred stock | $ | — | $ | 2,395 | ||||
| Settlement of mandatorily redeemable preferred stock with common stock | $ | — | $ | 5,833 | ||||
The accompanying notes are an integral part of these consolidated financial statements.
F-4
Red Mountain Resources, Inc. and Subsidiaries
Consolidated Statements of Stockholders’ Equity
(in thousands)
| Common Stock | Additional | Accumulated | Noncontrolling | |||||||||||||||||||||
| Shares | Amount | Paid-in Capital | Deficit | Interest | Total | |||||||||||||||||||
Balance at June 30, 2013 |
12,692 | $ | 1.269 | $ | 65,536 | $ | (24,814 | ) | $ | 5,563 | $ | 46,286 | ||||||||||||
| Issuance of shares, net of offering costs of $895 | 643 | 0.064 | 3,606 | — | — | 3,606 | ||||||||||||||||||
Issuance of warrants with preferred stock | — | — | 2,395 | — | — | 2,395 | ||||||||||||||||||
Issuance of shares for debentures | 87 | 0.009 | 541 | — | — | 541 | ||||||||||||||||||
Issuance of shares for services | 47 | 0.005 | 194 | — | — | 194 | ||||||||||||||||||
Issuance of shares in exchange for preferred stock | 1,388 | 0.14 | 5,833 | — | — | 5,833 | ||||||||||||||||||
Net income (loss) | — | — | — | (9,508 | ) | 513 | (8,995 | ) | ||||||||||||||||
| Balance at June 30, 2014 | 14,857 | 1.487 | 78,105 | (34,322 | ) | 6,076 | 49,860 | |||||||||||||||||
| Net loss | — | — | — | (40,170 | ) | (2,860 | ) | (43,030 | ) | |||||||||||||||
| Balance at June 30, 2015 | 14,857 | $ | 1.487 | $ | 78,105 | $ | (74,492 | ) | $ | 3,216 | $ | 6,830 | ||||||||||||
The accompanying notes are an integral part of these consolidated financial statements.
F-5
Red Mountain Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
1. Organization
Red Mountain Resources, Inc. is a Texas corporation formed on January 23, 2014. On January 31, 2014, the Company changed its state of incorporation from the State of Florida to the State of Texas by merging Red Mountain Resources, Inc., a Florida corporation (“RMR FL”), with and into Red Mountain Resources, Inc., a Texas corporation. 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 Dallas-based company with oil and natural gas properties in the Permian Basin of West Texas and Southeast New Mexico, the onshore Gulf Coast of Texas and Kansas.
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 $43.0 million during the fiscal year ended June 30, 2015. At June 30, 2015, the outstanding principal amount of the Company’s debt was $17.6 million, net of an aggregate discount of $1.2 million, and the Company had a working capital deficit of $14.4 million. Of the outstanding debt, $12.4 million is outstanding under the Company’s Credit Facility (as defined below). Of the $14.4 million working capital deficit at June 30, 2015, $12.4 million relates to the outstanding borrowings under the Company’s Credit Facility that are classified as a short-term liability on its Consolidated Balance Sheets as of June 30, 2015. The Company is currently in default under the Credit Facility, and the lender has the right to accelerate all amounts outstanding under the Credit Facility upon notice to the borrowers. The Company is in discussions with the lender regarding either a waiver of the non-compliance or an amendment to the credit agreement to cure the non-compliance. While the Company anticipates obtaining a waiver from the lender, it cannot provide any assurance that these negotiations will be successful. 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 at all, its business, financial condition and results of operations may be materially and adversely affected.
As a result of 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 amount and classification 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 and majority-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 debentures carrying value, accrued liability, derivatives, environmental remediation liability and asset retirement obligations. Changes in facts and circumstances may result in revised estimates and actual results may differ from these estimates.
Noncontrolling interests
Subsequent to January 28, 2013, the Company accounts for the noncontrolling interest in Cross Border Resources, Inc. (“Cross Border”) in accordance with ASC Topic 810, Consolidation (“ASC 810”). ASC 810 establishes accounting and reporting standards for ownership interests in subsidiaries held by parties other than the parent, the amount of consolidated net income attributable to the parent and to the noncontrolling interest, changes in a parent’s ownership interest and the valuation of retained noncontrolling equity investments when a subsidiary is deconsolidated. ASC 810 also establishes reporting requirements that provide sufficient disclosures that clearly identify and distinguish between the interest of the parent and the interests of the noncontrolling owner. In addition, this guidance provides for increases and decreases in the Company’s controlling financial interests in consolidated subsidiaries to be reported in equity similar to treasury stock transactions.
F-6
Debentures - held to maturity
The Company’s investments in non-performing debentures were initially recorded at cost which the Company believes was fair value. Management estimated cash flows expected to be collected considering the contractual terms of the loans, the nature and estimated fair value of collateral, and other factors it deemed appropriate. The estimated fair value of the loans at acquisition was significantly less than the contractual amounts due under the terms of the loan agreements.
Since, at the acquisition date, the Company expected to collect less than the contractual amounts due under the terms of the loans based, at least in part, on the assessment of the credit quality of the borrower, the loans are accounted for in accordance with ASC Topic 310-30, Loans and Debt Securities Acquired with Deteriorated Credit Quality (“ASC 310-30”). The difference between the contractually required payments on the loans as of the acquisition date and the total cash flows expected to be collected, or non-accretable difference, totaled $6.6 million and $2.1 million, plus accrued interest in arrears as of June 30, 2015 and June 30, 2014, respectively.
Debentures are classified as non-accrual when management is unable to reasonably estimate the timing or amount of cash flows expected to be collected from the debentures or has serious doubts about further collectability of principal or interest. As of June 30, 2015 and 2014, all of the Company’s debentures were on non-accrual status since the borrower remains under the supervision of the bankruptcy court.
The Company periodically re-evaluates cash flows expected to be collected for each debenture based upon all available information as of the measurement date. Subsequent increases in cash flows expected to be collected are recognized prospectively through an adjustment to the debenture’s yield over its remaining life, which may result in a reclassification from non-accretable difference to accretable yield. Subsequent decreases in cash flows expected to be collected are evaluated to determine whether a provision for loan loss should be established. If decreases in expected cash flows result in a decrease in the estimated fair value of the debenture below its amortized cost, the debenture is deemed to be impaired and the Company will record a provision for impairment to write the debenture down to its estimated fair value.
Due to the continuing decline of crude oil and natural gas prices which began approximately June 2014, and subsequent downturn in the related oilfield services sector, the Company reevaluated the value of the debentures. As a result, during the fiscal year ended June 30, 2015 the Company recorded an impairment on debentures of approximately $3.8 million while no such impairment was recorded during the fiscal year ended June 30, 2014.
The Company’s investments in non-performing debentures are classified as held to maturity because the Company has the intent and ability to hold them until maturity.
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 long-term based on the terms of the agreement. Restricted cash at June 30, 2015 and June 30, 2014 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 June 30, 2015 and June 30, 2014.
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 June 30, 2015 and June 30, 2014. Geological and 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 June 30, 2015, 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.
F-7
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 or the estimated actual proceeds from the sale of assets. 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. During fiscal years ended June 30, 2015 and June 30, 2014, the Company recognized impairments on its proved properties of $14.5 million and $0.3 million, respectively.
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. During fiscal years ended June 30, 2015 and June 30, 2014, the Company recognized impairments on its unproved properties of $16.5 million and $0.2 million, respectively.
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 — joint interest 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. No valuation allowance was recognized as of June 30, 2015 and June 30, 2014.
F-8
Dependence on major customers
For the fiscal year ended June 30, 2015, approximately 49% of the Company’s revenues were attributable to sales to three customers, and approximately 21% of the Company’s revenues were received from one operator pursuant to a joint operating agreement. For the fiscal year ended June 30, 2014, approximately 63% of the Company’s revenues were attributable to sales four customers, and approximately 18% of the Company’s revenues were received from one operator pursuant to a joint operating agreement. Although the Company is exposed to a concentration of credit risk, the Company believes that all of its purchasers are creditworthy. The Company had no bad debt for the fiscal years ended June 30, 2015 and June 30, 2014.
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 Consolidated Balance Sheets 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 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.
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.
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.
Derivative financial instruments
All derivative instruments are recorded on the Company’s Consolidated Balance Sheets at fair value. Historically, the Company has not designated its derivative instruments as cash-flow hedges. Although the Company has not designated its derivative instruments as cash-flow hedges, it uses those instruments to reduce its exposure to fluctuations in commodity prices related to its oil and natural gas production. Unrealized gains and losses, at fair value, are included on the Company’s Consolidated Balance Sheets as current or non-current assets or liabilities based on the anticipated timing of cash settlements under the related contracts. Changes in the fair value of the Company’s commodity derivative contracts and realized gains and losses are recorded in earnings as they occur and included in other income (expense) on the Company’s Consolidated Statements of Operations.
F-9
Recent accounting pronouncements
In May 2014, the FASB issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers (“ASU 2014-09”), which supersedes nearly all existing revenue recognition guidance under U.S. GAAP. The core principle of ASU 2014-09 is to recognize revenues when promised goods or services are transferred to customers in an amount that reflects the consideration to which an entity expects to be entitled for those goods or services. ASU 2014-09 defines a five step process to achieve this core principle and, in doing so, more judgment and estimates may be required within the revenue recognition process than are required under existing U.S. GAAP. The standard is effective for annual periods beginning after December 15, 2016, and interim periods therein, using either of the following transition methods: (i) a full retrospective approach reflecting the application of the standard in each prior reporting period with the option to elect certain practical expedients, or (ii) a retrospective approach with the cumulative effect of initially adopting ASU 2014-09 recognized at the date of adoption (which includes additional footnote disclosures). The Company is currently evaluating the impact of the adoption of ASU 2014-09 on its consolidated financial statements and has not yet determined the method by which it will adopt the standard in 2017.
4. 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:
| (in thousands) | June 30, 2015 | June 30, 2014 | ||||||
| Oil and natural gas properties: | ||||||||
| Proved | $ | 44,483 | $ | 82,362 | ||||
| Unproved | 11,458 | 19,109 | ||||||
| Total oil and natural gas properties | 55,941 | 101,471 | ||||||
| Less accumulated depletion and impairment | (29,390 | ) | (19,138 | ) | ||||
| Net oil and natural gas properties capitalized costs | $ | 26,551 | $ | 82,333 | ||||
During the fiscal years ended June 30, 2015 and June 30, 2014, the Company incurred approximately $1.6 million and $1.2 million, respectively, in exploration 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 June 30, 2015 and June 30, 2014.
The Company recorded $0.2 million of impairment related to its unproved oil and gas properties during the fiscal year ended June 30, 2014 related to expiring acreage. The expense is included in exploration expense in the Company’s Consolidated Statements of Operations.
On April 21, 2015, the Company entered into a purchase and sale agreement in which it sold, assigned, and transferred and conveyed to the buyer fifty percent of its right, title, and interest in and to certain oil and natural gas assets and properties, including its oil and natural gas leasehold interests, wells, contracts, and oil and natural gas produced after April 1, 2015. The aggregate purchase price for the assets was $25.0 million. This purchase price was used to establish the fair value of all of the Company’s assets. As a result of the sale, the Company recognized an impairment expense of approximately $31.0 million on its oil and gas assets for the fiscal year ended June 30, 2015.
The Company recorded $0.3 million in impairment charges on its proved properties for the fiscal year ended June 30, 2014, primarily due to a decline in reserves and production associated with wells on its Pawnee and Walnut Creek Prospects, which was included in depreciation, depletion, amortization and impairment in the Company’s Consolidated Statements of Operations.
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:
| (in thousands) | June 30, 2015 | June 30, 2014 | ||||||
| Other property and equipment | $ | 1,112 | $ | 1,196 | ||||
| Less accumulated depreciation and amortization | (641 | ) | (359 | ) | ||||
| Net property and equipment | $ | 471 | $ | 837 | ||||
F-10
5. Asset Retirement Obligations
The following table presents the balance and activity of the Company’s ARO for the periods indicated:
| Fiscal Year Ended | ||||||||
| (in thousands) | June 30, 2015 | June 30, 2014 | ||||||
| Asset retirement obligations at beginning of period | $ | 5,745 | $ | 5,020 | ||||
| Liabilities incurred | — | 75 | ||||||
| Liabilities settled | (2 | ) | (2 | ) | ||||
| Assets sold | (2,943 | ) | — | |||||
| Accretion expense | 131 | 267 | ||||||
| Revisions in estimated liabilities | — | 385 | ||||||
| Asset retirement obligations at end of period | $ | 2,931 | $ | 5,745 | ||||
| Less: current portion | — | 214 | ||||||
| Long-term portion | $ | 2,931 | $ | 5,531 | ||||
During the fiscal year ended June 30, 2014 the Company recorded an upward revision to previous estimates for its ARO primarily due to changes in the estimated future cash outlays.
6. Derivatives
At June 30, 2015, the Company had the following commodity derivatives positions outstanding:
| Commodity and Time Period | Contract Type | Volume Transacted | Contract Price | |||||
| Crude Oil | ||||||||
| July 1, 2015—December 31, 2015 | Put | 5,500-6,600 Bbls/month | $ | 50.00 | /Bbl | |||
| January 1, 2016—June 30, 2016 | Put | 5,000-5,500 Bbls/month | $ | 58.00 | /Bbl | |||
The following table summarizes the fair value of the Company’s open commodity derivatives as of June 30, 2015 and June 30, 2014 (in thousands):
| Balance Sheet Location | ||||||||||
| June 30, | June 30, | |||||||||
| 2015 | 2014 | |||||||||
| Derivatives not designated as hedging instruments | ||||||||||
| Commodity derivatives | Commodities derivative asset | $ | 190 | $ | 37 | |||||
| Commodity derivatives | Commodities derivative liability | $ | — | $ | (121 | ) | ||||
The following table summarizes the change in the fair value of the Company’s commodity derivatives (in thousands):
| Statement of Operations Location | Fiscal Year Ended | |||||||||
| June
30, 2015 | June
30, 2014 | |||||||||
| Derivatives not designated as hedging instruments | ||||||||||
| Commodity derivatives | Gain (loss) on derivatives | $ | 574 | $ | (544 | ) | ||||
Unrealized gains and losses, at fair value, are included on the Company’s Consolidated Balance Sheets as current or non-current assets or liabilities based on the anticipated timing of cash settlements under the related contracts. Changes in the fair value of the Company’s commodity derivatives contracts are recorded in earnings as they occur and included in other income (expense) on the Company’s Consolidated Statements of Operations. The Company estimates the fair values of swap contracts based on the present value of the difference in exchange-quoted forward price curves and contractual settlement prices multiplied by notional quantities. The Company internally valued the option contracts using industry-standard option pricing models and observable market inputs. The Company uses its internal valuations to determine the fair values of the contracts that are reflected on its Consolidated Balance Sheets. Realized gains and losses are also included in other income (expense) on its Consolidated Statements of Operations.
F-11
The Company is exposed to credit losses in the event of nonperformance by the counterparties on its commodity derivatives positions and has considered the exposure in its internal valuations. However, the Company does not anticipate nonperformance by the counterparties over the term of the commodity derivatives positions.
In connection with the closing of the Senior First Lien Secured Credit Agreement (as amended, the “Credit Agreement”) with Cross Border, Black Rock Capital, Inc. (“Black Rock”) and RMR Operating, LLC (collectively with the Company, the “Borrowers”) and Independent Bank, as Lender (the “Lender”), the Company was required to enter into hedging agreements effectively hedging at least 50% of the oil volumes of the Company and its subsidiaries. At the same time, the Company entered into a Novation Agreement with BP Energy Company that transferred Cross Border’s then-existing swap agreements to the Company. Pursuant to an Inter-Borrower Agreement among the Borrowers, the Company allocates these swap agreements back to Cross Border and may allocate future hedging agreements related to Cross Border’s production to Cross Border.
7. 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 June 30, 2015 and June 30, 2014:
| Fair Value Measurements at Reporting Date Using | ||||||||||||||||
| (in thousands) | Quoted
Prices in Active Markets for Identical Assets or Liabilities (Level 1) | Significant
or Other Observable Inputs (Level 2) | Significant
Unobservable Inputs (Level 3) | Fair Value at June 30, 2015 | ||||||||||||
| Assets: | ||||||||||||||||
| Commodities derivatives | $ | — | $ | 190 | $ | — | $ | 190 | ||||||||
| Debentures | — | — | 773 | 773 | ||||||||||||
| Oil and gas properties | — | — | 26,551 | 26,551 | ||||||||||||
| Total | $ | — | $ | 190 | $ | 27,324 | $ | 27,514 | ||||||||
| Liabilities: | ||||||||||||||||
| Asset retirement obligations (non-recurring) | $ | — | $ | — | $ | (2,931 | ) | $ | (2,931 | ) | ||||||
| Environmental remediation liability | — | — | (2,057 | ) | (2,057 | ) | ||||||||||
| Total | $ | — | $ | — | $ | (4,988 | ) | $ | (4,988 | ) | ||||||
| Fair Value Measurements at Reporting Date Using | ||||||||||||||||
| (in thousands) | Quoted
Prices in Active Markets for Identical Assets or Liabilities (Level 1) | Significant
or Other Observable Inputs (Level 2) | Significant
Unobservable Inputs (Level 3) | Fair Value at June 30, 2014 | ||||||||||||
| Assets: | ||||||||||||||||
| Commodities derivatives | $ | — | $ | 37 | $ | — | $ | 37 | ||||||||
| Oil and gas properties impairment (nonrecurring) | — | — | (487 | ) | (487 | ) | ||||||||||
| Total | $ | — | $ | 37 | $ | (487 | ) | $ | (450 | ) | ||||||
| Liabilities: | ||||||||||||||||
| Asset retirement obligations (non-recurring) | $ | — | $ | — | $ | (5,745 | ) | $ | (5,745 | ) | ||||||
| Commodities derivative liability | — | (121 | ) | — | (121 | ) | ||||||||||
| Environmental remediation liability | — | — | (2,067 | ) | (2,067 | ) | ||||||||||
| Total | $ | — | $ | (121 | ) | $ | (7,812 | ) | $ | (7,933 | ) | |||||
F-12
The following is a summary of changes to fair value measurements using Level 3 inputs during the year ended June 30, 2015:
| (in thousands) | Environmental Liability | |||
| Balance, June 30, 2014 | $ | (2,067 | ) | |
| Settlement of liabilities | 10 | |||
| Balance, June 30, 2015 | $ | (2,057 | ) | |
8. Debt
As of the dates indicated, the Company’s debt consisted of the following:
| (in thousands) | June 30, 2015 | June 30, 2014 | ||||||
| Credit Facility | $ | 12,400 | $ | 26,800 | ||||
| Mandatorily redeemable preferred stock, net of discount of $1,173 and $1,561, respectively | 5,189 | 4,801 | ||||||
| Total debt | 17,589 | 31,601 | ||||||
| Less: short-term portion | 12,400 | — | ||||||
| Long-term debt | $ | 5,189 | $ | 31,601 | ||||
Credit Facility
On February 5, 2013, the Borrowers entered into the Credit Agreement with the Lender. The Credit Agreement provides for a credit facility (as amended, the “Credit Facility”) with a maturity date of February 5, 2016. The borrowing base under the Credit Facility is determined at the discretion of the Lender based on, among other things, the Lender’s estimated value of the proved reserves attributable to the Borrowers’ oil and natural gas properties that have been mortgaged to the Lender, and is subject to regular redeterminations on September 30 and March 31 of each year, and interim redeterminations described in the Credit Agreement and potentially monthly commitment reductions, in each case which may reduce the amount of the borrowing base. As of June 30, 2015, the borrowing base and commitment were $12.4 million. The commitment is subject to monthly commitment reductions of $125,000 starting July 1, 2015.
A portion of the Credit Facility, in an aggregate amount not to exceed $2.0 million, may be used to issue letters of credit for the account of Borrowers. The Borrowers may be required to prepay the Credit Facility in the event of a borrowing base deficiency as a result of over-advances, sales of oil and gas properties or terminations of hedging transactions.
Amounts outstanding under the Credit Facility bear interest at a rate per annum equal to the greater of (x) the U.S. prime rate as published in The Wall Street Journal’s “Money Rates” table in effect from time to time and (y) 4.0% (4.0% at June 30, 2015). Interest is payable monthly in arrears on the last day of each calendar month. Borrowings under the Credit Facility are secured by first priority liens on substantially all the property of each of the Borrowers and are unconditionally guaranteed by Doral West Corp. and Pure Energy Operating, Inc., each a subsidiary of Cross Border.
Under the Credit Agreement, the Borrowers are required to pay fees consisting of (i) an unused facility fee equal to 0.5% multiplied by the average daily unused commitment amount, payable quarterly in arrears until the commitment is terminated; (ii) a fronting fee payable on the date of issuance of each letter of credit and annually thereafter or on the date of any increase or extension thereof, equal to the greater of (a) 2.0% per annum multiplied by the face amount of such letter of credit or (b) $1,000; and (iii) an origination fee (x) of $200,000, and (y) payable on any date the commitment is increased, an additional facility fee equal to 1.0% multiplied by any increase of the commitment above the highest previously determined or redetermined commitment.
The Credit Agreement contains negative covenants that may limit the Borrowers’ ability to, among other things, incur liens, incur additional indebtedness, enter into mergers, sell assets, make investments and pay dividends. The Credit Agreement permits the payment of cash dividends on the Company’s 10.0% Series A Convertible Redeemable Preferred Stock (the “Series A Preferred Stock”) so long as the Company is not otherwise in default under the Credit Agreement and payment of such cash dividends would not cause the Company to be in default under the Credit Agreement.
F-13
The Credit Agreement also contains financial covenants, measured as of the last day of each fiscal quarter of Red Mountain, requiring the Borrowers to maintain a ratio of (i) the Borrowers’ and their consolidated subsidiaries’ consolidated current assets (inclusive of the unfunded commitment amount under the Credit Agreement) to consolidated current liabilities (exclusive of the current portion of long-term debt under the Credit Agreement) of at least 1.00 to 1.00; (ii) the Borrowers’ and their subsidiaries’ consolidated “Funded Debt” to consolidated EBITDAX (for the four fiscal quarter period then ended) of less than 3.50 to 1.00; and (iii) the Borrowers’ and their subsidiaries’ consolidated EBITDAX less paid and accrued dividends on the Series A Preferred Stock to interest expenses (each for the four fiscal quarter period then ended) of at least 3.00 to 1.00. Funded Debt is defined in the Credit Agreement as the sum of all debt for borrowed money, whether as a direct or reimbursement obligor, but excludes shares of Series A Preferred Stock. EBITDAX is defined in the Credit Agreement as (a) consolidated net income plus (b) (i) interest expense, (ii) income taxes, (iii) depreciation, (iv) depletion and amortization expenses, (v) dry hole and exploration expenses, (vi) non-cash losses or charges on any hedge agreements resulting from derivative accounting, (vii) extraordinary or non-recurring losses, (viii) expenses that could be capitalized under GAAP but by election of Borrowers are being expensed for such period under GAAP, (ix) costs associated with intangible drilling costs, (x) other non-cash charges, (xi) one-time expenses associated with transactions associated with (b)(i) through (iv), minus (c)(i) non-cash income on any hedge agreements resulting from FASB Statement 133, (ii) extraordinary or non-recurring income, and (iii) other non-cash income.
Amounts outstanding under the Credit Facility may be accelerated and become immediately due and payable upon specified events of default of Borrowers, including, among other things, a default in the payment of principal, interest or other amounts due under the Credit Facility, certain loan documents or hydrocarbon hedge agreements, failure to perform or observe covenants under the Credit Facility, a material inaccuracy of a representation or warranty, a default with regard to certain loan documents which remains unremedied for a period of 30 days following notice, a default in the payment of other indebtedness of the Borrowers of $200,000 or more, bankruptcy or insolvency, certain changes in control, failure of the Lender’s security interest in any portion of the collateral with a value greater than $500,000, cessation of any security document to be in full force and effect, or Alan Barksdale ceasing to be Red Mountain’s Chief Executive Officer or Chairman of Cross Border and not being replaced with an officer acceptable to the Lender within 30 days.
Pursuant to the Credit Agreement, at least one of the Borrowers is required to have acceptable hydrocarbon hedge agreements in place at all times effectively hedging at least 50% of the oil volumes of the Borrowers, derived from the most recent third party engineering report received by Lender covering a period of not less than eighteen (18) consecutive months.
As of June 30, 2015, the Borrowers had collectively borrowed $12.4 million and had no availability under the Credit Facility. The Company was not in compliance with all of the financial covenants under the Credit Facility described above at June 30, 2015. As a result, the Lender has the right to accelerate all amounts outstanding under the Credit Facility upon notice to the Borrowers. The Company has recorded the full amount of its outstanding borrowings under the Credit Facility as a current liability on its Consolidated Balance Sheet as of June 30, 2015 because the facility matures in February 2016.
Mandatorily Redeemable Preferred Stock
The Company’s Series A Preferred Stock is mandatorily redeemable and is not convertible into shares of the Company’s common stock. The Company classifies the Series A Preferred Stock as a long-term liability, and the Company records dividends paid or accrued as interest expense in the Company’s Condensed Consolidated Statement of Operations. Because the Company is in default under the Credit Facility, as described above, it cannot pay dividends on the Series A Preferred Stock.
In August 2013, the Company closed offerings of 476,687 Units (the “Units”), including 100,002 Units sold in cancellation of $2.3 million in debt under convertible notes payable to Hohenplan Privatstiftung and SST Advisors, Inc., raising net proceeds of $7.1 million. Each Unit consisted of one share of Series A Preferred Stock and one warrant to purchase up to 2.5 shares of common stock at a price of $22.50 per Unit. The warrants are exercisable until the earlier of (i) August 2016 or (ii) the first trading day that is at least 30 days after the date that the Company has provided notice to the holders of the warrants by filing a Current Report on Form 8-K stating that the common stock has (A) achieved a 20 trading day volume weighted average price of $15.00 per share or more and (B) traded, in the aggregate, 300,000 shares or more over the same 20 consecutive trading days for which the 20 trading day volume weighted average price was calculated; provided, that clause (ii) shall only be applicable so long as a warrant is exercisable for shares of common stock. The warrants have an exercise price of $10.00 per share. The warrants issued with the Series A Preferred Stock were valued at $2.4 million. The value of the warrants is treated as a discount to the Series A Preferred Stock and will be accreted over the life of the mandatorily redeemable preferred stock. Management determined the fair value 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 volatility and remaining term was approximately 55% and three years, respectively.
F-14
As of June 30, 2015, we had 254,463 shares of Series A Preferred Stock outstanding. The Series A Preferred Stock is mandatorily redeemable on July 15, 2018 at $25.00 per share, plus accrued and unpaid dividends to the redemption date, for a total redeemable value of $11.9 million at the time of issuance. The difference between the $11.9 million redeemable value and the $10.8 million of gross proceeds and canceled debt is treated as a discount and will be accreted over the life of the Series A Preferred Stock.
For the fiscal year ended June 30, 2015, the Company recognized total interest expense of $1.1 million related to the Series A Preferred Stock, which includes accretion of discount and amortization of issuance costs of $0.4 million for the fiscal year ended June 30, 2015.
The following is a schedule by year of future principal payments required under the Credit Facility and the redemption of the Series A Preferred Stock described above as of June 30, 2015:
| (in thousands) | ||||||
| Fiscal Years Ending June 30, | ||||||
| 2016 | $ | 12,400 | ||||
| 2017 | — | |||||
| 2018 | — | |||||
| 2019 | 6,362 | |||||
| 2020 | — | |||||
| Total | 18,762 | |||||
| Discount | (1,173 | ) | ||||
| Total, net value | $ | 17,589 | ||||
9. 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 for the fiscal years ending:
| (dollars in thousands, except per share amounts) | ||||||||
| June 30, 2015 | June 30, 2014 | |||||||
| Net loss (numerator): | ||||||||
| Net loss attributable to Red Mountain Resources, Inc.—basic | $ | (40,170 | ) | $ | (9,508 | ) | ||
| Weighted average shares (denominator): | ||||||||
| Weighted average shares—basic | 14,857 | 13,626 | ||||||
| Weighted average shares—diluted (1) | 14,857 | 13,626 | ||||||
| Loss per share: | ||||||||
| Basic | $ | (2.70 | ) | $ | (0.70 | ) | ||
| Diluted | $ | (2.70 | ) | $ | (0.70 | ) | ||
| (1) | Approximately 1,653,559 and 1,349,051 shares of common stock underlying warrants to purchase shares of the Company’s common stock were excluded from this calculation because they were anti-dilutive during the periods ended June 30, 2015 and 2014, respectively. |
10. Equity
During fiscal year 2014, the Company entered into a Debenture Purchase Agreement with a holder of 2009A Debentures and 2009B Debentures for the purchase of an aggregate of $1.1 million principal amount of 2009A Debentures and 2009B Debentures, plus accrued and unpaid interest, in exchange for the issuance of 0.9 million shares of common stock of the Company.
F-15
11. Income Taxes
Income tax expense differs from the statutory amounts as follows for the following fiscal years ending:
| (dollars in thousands) | June 30, 2015 | June 30, 2014 | ||||||
| Income taxes at U.S. statutory rate | $ | (14,687 | ) | $ | (3,044 | ) | ||
| Deferred state income tax expense | (1,729 | ) | (184 | ) | ||||
| Change in tax status | — | (311 | ) | |||||
| Permanent differences | 148 | 1,217 | ||||||
| Change in valuation allowance | 16,224 | 2,366 | ||||||
| Total tax expense (benefit) | $ | (44 | ) | $ | 44 | |||
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 and liabilities were as follows:
| (dollars in thousands) | June 30, 2015 | June 30, 2014 | ||||||
| Deferred tax assets and liabilities: | ||||||||
| Net operating loss carryforwards | $ | 25,666 | $ | 19,879 | ||||
| Oil and natural gas properties | 1,051 | (9,367 | ) | |||||
| Derivatives | — | 32 | ||||||
| Capitalized transaction costs | 539 | 528 | ||||||
| Environmental liabilities | — | 788 | ||||||
| Other | — | — | ||||||
| Gross deferred tax assets | 27,256 | 11,860 | ||||||
| Valuation allowance | (27,256 | ) | (11,901 | ) | ||||
| Net deferred taxes | $ | — | $ | (41 | ) | |||
At June 30, 2015, the Company had approximately $67.6 million of pre-tax net operating loss carryforwards (“NOLs”). These carryforwards begin to expire in 2030. Due to the change in control of Cross Border on January 28, 2013, the Company’s ability to utilize the NOLs of Cross Border will be subject to limitations under applicable tax laws.
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 June 30, 2014, the Company had a valuation allowance of $11.9 million related to its deferred tax assets.
As of June 30, 2015, the Company had no unrecognized tax benefits. Black Rock Capital, LLC’s tax returns for the years ended December 31, 2011 – 2009 and stub period ended June 30, 2011, the Company’s tax returns for the fiscal years ended May 31, 2014, 2013 and 2012, stub period ended May 31, 2011, and the fiscal years ended January 31, 2011 and 2010, and Cross Border’s tax returns for the years ended December 31, 2013 – 2009, are open to examination by the major taxing jurisdictions to which the Company is subject.
12. Commitments and Contingencies
Litigation
On May 4, 2011, Clifton M. (Marty) Bloodworth filed a lawsuit in the State District Court of Midland County, Texas, against Doral West Corp. d/b/a Doral Energy Corp. and Everett Willard Gray II. Mr. Bloodworth alleges that Mr. Gray, as CEO of Cross Border, made false representations which induced Mr. Bloodworth to enter into an employment contract that was subsequently breached by Cross Border. The claims that Mr. Bloodworth has alleged are: breach of his employment agreement with Doral West Corp, common law fraud, civil conspiracy breach of fiduciary duty, and violation of the Texas Deceptive Trade Practices-Consumer Protection Act. Mr. Bloodworth is seeking damages of approximately $280,000. Mr. Gray and Cross Border deny that Mr. Bloodworth’s claims have any merit.
F-16
Cross Border was previously party to an engagement letter, dated February 7, 2012 (the “Engagement Letter”) with KeyBanc Capital Markets Inc. (“KeyBanc”) pursuant to which KeyBanc was to act as exclusive financial advisor to Cross Border’s board of directors in connection with a possible “Transaction” (as defined in the Engagement Letter). The Engagement Letter was formally terminated by Cross Border on August 21, 2012. The Engagement Letter provided that KeyBanc would be entitled to a fee upon consummation of a Transaction within a certain period of time following termination of the Engagement Letter. On May 16, 2013, KeyBanc delivered an invoice to Cross Border representing a fee and out-of-pocket expenses purportedly owed by Cross Border to KeyBanc as a result of the consummation of a purported Transaction that KeyBanc asserts had been consummated within the required time period. Cross Border disputed that any Transaction was consummated and that KeyBanc was entitled to any fees or out-of-pocket expenses. Cross Border filed a complaint seeking (i) a declaration that it was not liable to KeyBanc for any amounts in connection with the Engagement Letter, (ii) attorneys’ fees, and (iii) costs of suit. KeyBanc filed a counterclaim seeking (i) compensatory damages, (ii) interest, (iii) expenses and court costs, and (iv) reasonable and necessary attorneys’ fees. The matter was originally filed in the 44th Judicial District Court for the State of Texas, Dallas County but was subsequently removed to the United States District Court for the Northern District of Texas, Dallas Division. On August 26, 2014, Cross Border entered into a settlement agreement with KeyBanc, settling a lawsuit between the parties. In connection with the settlement, Cross Border agreed to pay KeyBanc $900,000 in three equal installments of $300,000 each on or before August 28, 2014, October 31, 2014 and December 31, 2014, and the parties agreed to mutual releases of liability related to the Engagement Letter.
In addition to the foregoing, in the ordinary course of business, the Company is periodically a party to various litigation matters that it does not believe will have a material adverse effect on its results of operations or financial condition.
Environmental issues
The Company is subject to federal and state laws and regulations relating to the protection of the environment. Environmental risk is inherent in all oil and natural gas operations, and the Company could be subject to environmental cleanup and enforcement actions. The Company manages this environmental risk through appropriate environmental policies and practices to minimize the impact to the Company.
As of June 30, 2015, the Company had approximately $2.1 million in environmental remediation liabilities related to Cross Border’s operated Tom Tom and Tomahawk fields located in Chaves and Roosevelt counties in New Mexico. In February 2013, the Bureau of Land Management (“BLM”) accepted Cross Border’s remediation plan for the Tom Tom and Tomahawk fields. Cross Border is working in conjunction with the BLM to initiate remediation on a site-by-site basis. This is management’s best estimate of the costs of remediation and restoration with respect to these environmental matters, although the ultimate cost could differ materially. Inherent uncertainties exist in these estimates due to unknown conditions, changing governmental regulation, and legal standards regarding liability, and emerging remediation technologies for handling site remediation and restoration. Cross Border has incurred approximately $43,000 in costs, in total, and expects to incur the remaining expenditures during the Company’s fiscal year ending June 30, 2016.
Leases
As of June 30, 2015, the Company rented various office spaces in Dallas, Texas and Midland, Texas under non-cancelable lease agreements. In the aggregate, these leases cover approximately 10,509 square feet at a cost of approximately $21,000 per month and have remaining lease terms between 5 and 15 months. The following is a schedule by year of future minimum rental payments required under lease arrangements in excess of one year as of June 30, 2015:
| (in thousands) | ||||||
| Fiscal Years Ending June 30, | ||||||
| 2016 | $ | 181 | ||||
| 2017 | 45 | |||||
| 2018 | — | |||||
| 2019 | — | |||||
| 2020 | — | |||||
| Total | $ | 226 | ||||
Rent expense under the Company’s lease arrangements amounted to approximately $0.2 million and $0.3 million for the fiscal years ended June 30, 2015 and 2014, respectively.
13. Related Party Transactions
Enerstar Resources O&G, LLC (“Enerstar”), a company owned by Tommy Folsom, the former Executive Vice President and Director of Exploration and Production for RMR Operating, LLC, a subsidiary of the Company, and formerly the Executive Vice President and Director of Exploration and Production for the Company, owns an overriding royalty interest in the Company’s Madera Prospect. During the fiscal years ended June 30, 2015 and 2014, the Company paid royalties of approximately $11,900 and $15,000, respectively, to Enerstar.
F-17
14. Subsequent Events
Fifth Amendment to the Credit Agreement
Effective June 30, 2015, the Borrowers entered into an amendment and waiver (the “Fifth Amendment”) to the Credit Agreement with the Lender. Pursuant to the Fifth Amendment, the borrowing base was set at $12.4 million, and the initial monthly commitment reduction was set at $125,000 beginning on July 1, 2015. In addition, the Lender waived any default, event of default or right to exercise any remedy as a result of the failure by the Borrowers to be in compliance with (i) the requirements of Section 6.18 of the Credit Agreement with respect to the permitted ratio of consolidated current assets to consolidated current liabilities of Borrowers for the fiscal quarter ended December 31, 2014; and (ii) the requirements of Section 6.21 of the Credit Agreement with respect to the trade payables or other accounts payable of Borrowers that may be past due for more than 90 days for the fiscal quarter ended December 31, 2014 and the fiscal quarter ended March 31, 2015.
Lease and Lease Amendment
On July 31, 2015, the Company entered into an amendment and consent to assignment of lease pursuant to which the Company assigned its lease for its office space in Dallas, Texas, to a new tenant, effective as of November 1, 2015. The Company and the new tenant will be jointly and severally liable under the lease through October 1, 2016. In addition, the Company entered into a lease agreement for approximately 4100 square feet of new office space, for approximately $2700 per month and a term of three years beginning on September 1, 2015.
Unwinding of Hedge Agreements
On August 19, 2015, the Company unwound a portion of its commodity derivative positions for net proceeds of $18,600.
Arbitration Claim
On August 27, 2015, the Company received a demand for arbitration with the Dallas, Texas office of the American Arbitration Association (“AAA”) that was filed by a former RMR employee, Tommy Folsom. The arbitration demand asserts claims for breach of contract and defamation and identifies the total claim amount as $100,000 and further seeks unspecified attorney’s fees, interest, arbitration costs, and punitive/exemplary damages. The Company disputes the allegations in the arbitration proceedings made by Mr. Folsom. The parties are engaged in settlement negotiations.
Deregistration
On November 13, 2015, the Company's Board of Directors voted to voluntarily deregister the Company's common stock, Series A Preferred Stock and warrants under the Exchange Act and become a non-reporting company. In connection therewith, the Board of Directors approved the filing with the SEC of a Form 15 to voluntarily deregister the Company's securities under Section 12(g) of the Exchange Act and suspend its reporting obligations under Section 15(d) of the Exchange Act. The Company expects to file the Form 15 on or about November 13, 2015. The Company expects that its obligations to file periodic reports, such as Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q and Current Reports on Form 8-K, will be suspended immediately upon the filing of the Form 15 with the SEC, and its proxy statement, Section 16 and other Section 12(g) reporting responsibilities will terminate effective 90 days after the filing of the Form 15. The Company is eligible to deregister under the Exchange Act because its common stock, Series A Preferred Stock and warrants are each held by fewer than 300 shareholders of record.
15. 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:
| (in thousands) | June 30, 2015 | June 30, 2014 | ||||||
| Property acquisition costs: | ||||||||
| Unproved properties | $ | — | $ | — | ||||
| Proved properties | — | — | ||||||
| Exploration costs | 1,569 | 1,193 | ||||||
| Development costs (1) | 8,392 | 17,101 | ||||||
| Total costs incurred | $ | 9,961 | $ | 18,294 | ||||
| (1) | For the fiscal years ended June 30, 2015 and 2014, development costs included $0 and $0.5 million, respectively, in non-cash asset retirement obligations. |
F-18
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:
| (in thousands) | June 30, 2015 | June 30, 2014 | ||||||
| Revenues | $ | 12,738 | $ | 22,498 | ||||
| Production costs | (4,540 | ) | (5,340 | ) | ||||
| Exploration expense | (1,569 | ) | (1,193 | ) | ||||
| Impairment | (31,021 | ) | (487 | ) | ||||
| Depletion | (5,517 | ) | (9,020 | ) | ||||
| Income tax expense | — | — | ||||||
| Results of operations | $ | (29,909 | ) | $ | 6,458 | |||
Proved reserves
Cawley, Gillespie & Associates, Inc., independent petroleum engineers, estimated 100% of the Company’s proved reserve information as of July 1, 2015. The estimate of proved reserves and related valuations were prepared in accordance with the 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. The following table is a summary of the Company’s changes in quantities of proved oil and natural gas reserves for the fiscal years ended June 30, 2014 and 2015:
| Oil (MBbls) | Natural Gas (MMcf) | NGL (MBbls) | Total (MBoe) | |||||||||||||
| June 30, 2013 | 2,320 | 6,173 | 198 | 3,547 | ||||||||||||
| Extensions and discoveries | 656 | 1,398 | 55 | 944 | ||||||||||||
| Revisions in previous estimates | (67 | ) | 365 | 32 | (26 | ) | ||||||||||
| Production | (204 | ) | (987 | ) | (29 | ) | (398 | ) | ||||||||
| June 30, 2014 | 2,705 | 6,949 | 256 | 4,119 | ||||||||||||
| Extensions and discoveries | 118 | 173 | 11 | 159 | ||||||||||||
| Revisions in previous estimates | 45 | 322 | 36 | 135 | ||||||||||||
| Sales of assets | (1,344 | ) | (3,333 | ) | (134 | ) | (2,033 | ) | ||||||||
| Production | (155 | ) | (683 | ) | (32 | ) | (302 | ) | ||||||||
| June 30, 2015 | 1,369 | 3,428 | 137 | 2,078 | ||||||||||||
| Proved Developed Reserves | ||||||||||||||||
| June 30, 2014 | 1,171 | 4,688 | 142 | 2,094 | ||||||||||||
| June 30, 2015 | 606 | 2,472 | 99 | 1,117 | ||||||||||||
| Proved Undeveloped Reserves | ||||||||||||||||
| June 30, 2014 | 1,534 | 2,261 | 114 | 2,025 | ||||||||||||
| June 30, 2015 | 763 | 956 | 38 | 960 | ||||||||||||
At June 30, 2015, the Company’s estimated proved reserves were 2.1 MMBoe, a decrease of 50% compared to 4.1 MMBoe at June 30, 2014. The decrease during fiscal 2015 was attributable to 2.0 MMBoe of divested reserves and 0.3 MMBoe of production, partially offset by 0.2 MMBoe added through field extensions and another 0.1 MMBoe of upward revisions.
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 June 30, 2015 to estimated future production. For oil and natural gas liquid volumes, the average NYMEX spot price is $71.68 per Bbl. For natural gas volumes, the average Henry Hub spot price is $3.39 per MMBtu. Prices are adjusted for basis differentials, hydrocarbon quality, and transportation, processing, and gathering fees resulting in an oil price of $63.87 per barrel, natural gas liquids price of $23.80 per barrel, and natural gas price of $3.66 per Mcf. The adjusted oil, natural gas liquids and natural gas prices are held constant throughout the lives of the properties. 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.
F-19
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:
| (in thousands) | June 30, 2015 | June 30, 2014 | ||||||
| Future cash inflows | $ | 103,236 | $ | 294,350 | ||||
| Future production costs | (30,578 | ) | (76,574 | ) | ||||
| Future development costs | (17,489 | ) | (42,357 | ) | ||||
| Future income tax expense | — | (23,306 | ) | |||||
| Future net cash flows | 55,169 | 152,113 | ||||||
| 10% annual discount for estimated timing of cash flows | (28,716 | ) | (73,113 | ) | ||||
| Standardized measure of discounted future net cash flows | $ | 26,453 | $ | 79,000 | ||||
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:
| (in thousands) | June 30, 2015 | June 30, 2014 | ||||||
| Balance, beginning of period | $ | 79,000 | $ | 57,136 | ||||
| Net change in sales and transfer prices and in production (lifting) costs related to future production | (29,343 | ) | 8,407 | |||||
| Changes in estimated future development costs | (15,619 | ) | 18,870 | |||||
| Sales and transfers of oil and natural gas produced during the period | (8,003 | ) | (17,879 | ) | ||||
| Sale of reserves | (25,891 | ) | — | |||||
| Net change due to extensions and discoveries | 2,018 | 21,859 | ||||||
| Net change due to purchase of minerals in place | — | — | ||||||
| Net change due to revisions in quantity estimates | 1,715 | 601 | ||||||
| Previously estimated development costs incurred during the period | (8,392 | ) | (16,755 | ) | ||||
| Accretion of discount | 17,869 | 6,763 | ||||||
| Other | 22 | (110 | ) | |||||
| Net change in income taxes | 13,077 | 108 | ||||||
| Balance, end of period | $ | 26,453 | $ | 79,000 | ||||
F-20
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.
| Dated: November 13, 2015 | By: | /s/ Alan W. Barksdale |
| Alan W. Barksdale | ||
| Chief Executive Officer | ||
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
| Signature | Title | Date | ||
| /s/ Alan W. Barksdale | President, Chief Executive Officer | November 13, 2015 | ||
| Alan W. Barksdale | and Director (Principal Executive Officer) | |||
| /s/ Hilda D. Kouvelis | Chief Accounting Officer | November 13, 2015 | ||
| Hilda D. Kouvelis | (Principal
Financial and Accounting Officer) |
|||
| /s/ David M. Heikkinen | Director | November 13, 2015 | ||
| David M. Heikkinen | ||||
| /s/ Richard Y. Roberts | Director | November 13, 2015 | ||
| Richard Y. Roberts | ||||
| /s/ Paul N. Vassilakos | Director | November 13, 2015 | ||
| Paul N. Vassilakos | ||||
| /s/ Frank Yates, Jr. | Director | November 13, 2015 | ||
| Frank Yates, Jr. |
| 50 |
EXHIBIT INDEX
| Exhibit No. | Name of Exhibit | |
| 2.1 | Plan of Reorganization and Share Exchange Agreement, dated March 22, 2011, by and between Black Rock Capital, LLC and Red Mountain Resources, Inc. (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K, filed on March 31, 2011). | |
| 2.2 | Amendment to Plan of Reorganization and Share Exchange Agreement, dated June 17, 2011, by and among Red Mountain Resources Inc., Black Rock Capital, LLC and Black Rock Capital Shareholders (incorporated by reference to Exhibit 10.4 to the Company’s Current Report on Form 8-K, filed on June 23, 2011). | |
| 2.3 | Amendment to Plan of Reorganization and Share Exchange Agreement, dated June 20, 2011, by and among Red Mountain Resources Inc., Black Rock Capital, LLC and Black Rock Capital Shareholders (incorporated by reference to Exhibit 10.5 to the Company’s Current Report on Form 8-K, filed on June 23, 2011). | |
| 2.4 | Asset Purchase Agreement, dated July 19, 2012, by and among Hunter Drilling, LLC, First Security Bank, as Trustee for the Holders of the Senior Series 2009A Debentures and the Series 2009B Debentures, Red Mountain Resources, Inc., O&G Leasing, LLC and Performance Drilling Company, LLC (incorporated by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K filed on July 25, 2012). | |
| 2.5 | Agreement and Plan of Merger, dated January 29, 2014, by and between Red Mountain Resources, Inc., a Florida corporation, and Red Mountain Resources, Inc., a Texas corporation (incorporated by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K filed on February 4, 2014). | |
| 3.1 | Certificate of Formation of Red Mountain Resources, Inc. (incorporated by reference to Exhibit 3.2 to the Company’s Current Report on Form 8-K filed on February 4, 2014). | |
| 3.2 | Certificate of Correction to the Certificate of Formation of Red Mountain Resources, Inc. (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on August 11, 2014). | |
| 3.3 | Bylaws of Red Mountain Resources, Inc. (incorporated by reference to Exhibit 3.3 to the Company’s Current Report on Form 8-K filed on February 4, 2014). | |
| 4.1 | Form of Common Stock Certificate of Red Mountain Resources, Inc. (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed on February 4, 2014). | |
| 4.2 | Form of 10.0% Series A Cumulative Redeemable Preferred Stock Certificate of Red Mountain Resources, Inc. (incorporated by reference to Exhibit 4.2 to the Company’s Current Report on Form 8-K filed on February 4, 2014). | |
| 4.3 | Form of Warrant Certificate of Red Mountain Resources, Inc. (incorporated by reference to Exhibit 4.3 to the Company’s Current Report on Form 8-K filed on February 4, 2014). | |
| 4.4 | Form of Warrant Agreement between the Company and Broadridge Corporate Issuer Solutions, Inc. (incorporated by reference to Exhibit 4.4 to the Company’s Registration Statement on Form 8-A filed on July 24, 2013). | |
| 4.5 | Amendment No. 1 to Warrant Agreement, effective as of January 31, 2014, between Broadridge Corporate Issuer Solutions, Inc. and Red Mountain Resources, Inc. (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on February 4, 2014). | |
| 10.1 | Cross Border Resources, Inc. Common Stock Warrant (incorporated by reference to Exhibit 10.1 to the Company’s Annual Report on Form 10-K filed on September 13, 2012). | |
| 10.2† | Employment Agreement, dated February 7, 2012, by and between Red Mountain Resources, Inc. and Hilda D. Kouvelis (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K, filed on February 8, 2012). | |
| 10.3† | Form of Indemnification Agreement between Red Mountain Resources, Inc. and its officers and directors (incorporated by reference to Exhibit 10.16 to the Company’s Annual Report on Form 10-K filed on September 13, 2012). | |
| 10.4† | Amendment to Employment Agreement, dated July 27, 2012, by and between Red Mountain Resources, Inc. and Hilda Kouvelis (incorporated by reference to Exhibit 10.19 to the Company’s Annual Report on Form 10-K filed on September 13, 2012). |
| 51 |
| Exhibit No. | Name of Exhibit | |
| 10.5† | Red Mountain Resources, Inc. 2012 Long-Term Incentive Plan (incorporated by reference to Annex A to the Company’s Definitive Proxy Statement on Schedule 14A filed on September 26, 2012). | |
| 10.6 | Senior First Lien Secured Credit Agreement, dated February 5, 2013, among the Company, Cross Border Resources, Inc., Black Rock Capital, Inc. and RMR Operating, LLC, as borrowers, and Independent Bank, as lender (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K, filed on February 11, 2013). | |
| 10.7 | Inter-Borrower Agreement, dated February 5, 2013, among the Company, Cross Border Resources, Inc., Black Rock Capital, Inc. and RMR Operating, LLC (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K, filed on February 11, 2013). | |
| 10.8 | Amendment and Waiver, dated May 2, 2013, among Red Mountain Resources, Inc., Cross Border Resources, Inc., Black Rock Capital, Inc. and RMR Operating, LLC and Independent Bank to that certain Senior First Lien Secured Credit Agreement (incorporated by reference to Exhibit 10.12 to the Company’s Annual Report on Form 10-K, filed on September 13, 2013). | |
| 10.9 | Amendment and Consent, dated July 19, 2013, to that certain Senior First Lien Secured Credit Agreement, dated February 5, 2013, among the Company, Cross Border Resources, Inc., Black Rock Capital, Inc. and RMR Operating, LLC, as borrowers, and Independent Bank, as lender (incorporated by reference to Exhibit 10.12 to the Company’s Quarterly Report on Form 10-Q, filed on November 18, 2013). | |
| 10.10 | Amendment and Waiver, effective as of September 12, 2013, by and among Independent Bank, as lender, and the Company, Cross Border Resources, Inc., Black Rock Capital, Inc. and RMR Operating, LLC, as borrowers (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on September 17, 2013). | |
| 10.11 | Fourth Amendment to Senior First Lien Secured Credit Agreement, effective as of April 21, 2015, by and among Independent Bank, as Lender, and Red Mountain Resources, Inc., Cross Border Resources, Inc., Black Rock Capital, Inc. and RMR Operating, LLC, as Borrowers (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on April 27, 2015). | |
| 10.12* | Fifth Amendment to Senior First Lien Secured Credit Agreement, effective as of June 30, 2015, by and among Independent Bank, as Lender, and Red Mountain Resources, Inc., Cross Border Resources, Inc., Black Rock Capital, Inc. and RMR Operating, LLC, as Borrowers. | |
| 10.13† | Form of Incentive Stock Option Agreement (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on May 6, 2013). | |
| 10.14† | Form of Nonqualified Stock Option Agreement (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on May 6, 2013). | |
| 21.1* | Subsidiaries of the Company. | |
| 23.1* | Consent of Cawley, Gillespie & Associates, Inc. | |
| 31.1* | Certification by Principal Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | |
| 31.2* | Certification by Principal Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | |
| 32.1** | Certification by Principal Executive Officer and Principal Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. | |
| 99.1* | Report of Cawley, Gillespie & Associates, Inc., dated as of August 18, 2015. | |
| 101.INS* | XBRL Instance Document | |
| 101.SCH* | XBRL Taxonomy Extension Schema Document | |
| 101.CAL* | XBRL Taxonomy Extension Calculation Linkbase Document | |
| 101.DEF* | XBRL Taxonomy Extension Definition Linkbase Document | |
| 101.LAB* | XBRL Taxonomy Extension Label Linkbase Document | |
| 101.PRE* | XBRL Taxonomy Extension Presentation Linkbase Document |
* Filed herewith.
** Furnished herewith.
† Indicates a compensation contract or arrangement with management.
52