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 year ended December 31, 2013
OR
| ☐ | 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 000-52738
CROSS BORDER RESOURCES, INC.
(Exact Name of Registrant as Specified in Its Charter)
| Nevada | 98-0555508 |
| (State or Other Jurisdiction of Incorporation or Organization) | (I.R.S. Employer Identification No.) |
|
2515 McKinney Avenue, Suite 900 Dallas, TX |
75201 |
| (Address of Principal Executive Offices) | (Zip Code) |
(210) 226-6700
(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 $.001
(Title of class)
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 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 requirement for the past 90 days. Yes ☒ No ☐
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, 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. (Check one):
| 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 Exchange Act). Yes ☐ No ☒
As of June 28, 2013 (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 $0.35 per share on the OTCBB) held by non-affiliates of the registrant was approximately $1.1 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 April 14, 2014, there were 17,336,226 shares of common stock, $.001 par value per share, outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
None.
CROSS BORDER 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:
| · | our ability to raise additional capital to fund future capital expenditures; |
| · | 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; |
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| · | 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 natural gas liquids 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.
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“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 “fracing” 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.
“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 natural gas liquids.
“net acres” The sum of the fractional working interests owned in gross acres.
“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.
“PDP” Proved developed producing reserves.
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“PDNP” Proved developed non-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.
“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.
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“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.
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“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.
“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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| Item 1. | Business |
Our Company
We are an oil and gas exploration company. We currently own over 865,893 gross (approximately 293,843 net) mineral and lease acres in New Mexico. Approximately 25,000 of these net acres exist within the Permian Basin. A significant majority of our acreage consists of either owned mineral rights or leases held by production, allowing us to hold lease rental payments to under $5,000 annually. The majority of our acreage interests consists of non-operated working interests except for certain core San Andres properties which we operate.
Current development of our acreage is focused on our prospective Bone Spring acreage located in the heart of the 1st and 2nd Bone Spring play. This play encompasses approximately 4,390 square miles across both New Mexico and Texas. We currently own varying, non-operated working interests in both Eddy and Lea Counties, New Mexico, along with our working interest partners that include Cimarex, Apache, Oxy Permian, Occidental, Oxy USA and, Mewbourne; all having significant footprints within this play, and are adding to those footprints through lease and corporate acquisitions.
History
We were originally formed on October 25, 2005 under the name “Language Enterprises Corp.” We subsequently changed our name to Doral Energy Corp. On July 29, 2008, we acquired a working interest in 66 producing oil fields and approximately 186 wells (the “Eddy County Properties”) in and around Eddy County, New Mexico. As a result of our acquisition of the Eddy County Properties, we changed our business focus to the acquisition, exploration, operation and development of oil and gas projects, and we ceased being a “shell company.” On August 4, 2008, we filed our Form 8-K that included the information that would be required if we were filing a general form for registration of securities on Form 10 as a smaller reporting company.
Effective January 3, 2011, we completed the acquisition of Pure Energy Group, Inc. as contemplated pursuant to the Pure Merger Agreement among our company, Doral Sub, Pure L.P. and Pure Sub, a wholly owned subsidiary of Pure L.P. Pursuant to the provisions of the Pure Merger Agreement, all of Pure L.P.’s oil and gas assets and liabilities were transferred to Pure Sub. Pure Sub was then merged with and into Doral Sub, with Doral Sub continuing as the surviving corporation. Upon completion of the Pure Merger, the outstanding shares of Pure Sub were converted into an aggregate of 9,981,536 shares of our common stock. Since the Pure Merger, Pure L.P. has distributed all of its shares of our common stock to the partners of Pure L.P. so that Pure L.P. is no longer a shareholder of our company.
Effective January 4, 2011, following closing of the Pure Merger, Doral Sub was merged with and into our company, with our company continuing as the surviving corporation. Upon completing the merger of Doral Sub with and into our company, we changed our name to “Cross Border Resources, Inc.”
Our Strengths
Large Acreage Position Consisting of Mineral Ownership and Leasehold Held by Production. Our acreage consists of more than 290,000 net mineral acres within the Permian Basin region of New Mexico and Southwest New Mexico. The majority of our acreage is made up of mineral ownership which carries no drilling commitments or leasehold obligations. We own minerals in both the Permian Basin region and Southwest New Mexico. Cross Border’s producing leasehold acreage is located entirely within the active Permian Basin region and is currently held by existing production. The combination of perpetual mineral ownership and unexpired leasehold held by production uniquely positions us as a strong Permian Basin exploration and production company with continued growth potential.
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Existing Infrastructure. All of our producing Permian properties are located within established oil and natural gas producing areas or existing fields. We seek to enhance existing production in these properties by using engineering and geological expertise. These areas also have a fully developed transportation infrastructure, which allows us to transport our oil and natural gas to market without long-term delay or significant investment.
Our Properties
Currently, substantially all of our producing oil and natural gas properties are concentrated in the Permian Basin. 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.
Planned Operations
We plan to spend between $6 million and $8 million during fiscal 2014 to drill and complete wells, re-enter and complete wells, or improve infrastructure. Our main area of focus is the Tom Tom/Tomahawk Prospect, where we will continue work on the field alongside the execution of our remediation plan. For fiscal 2013, this included the re-entry of 11 gross wells (8.2 net), drilling of 3 gross wells (2.6 net), and the improvement of field infrastructure. We will also spend capital in several non-operated prospect areas. Currently, we are committed to participating in the drilling of 4 gross wells (0.5 net) in fiscal 2014.
Competition
The oil and natural gas industry is highly competitive and we compete with a substantial number of other companies that have greater resources than we do. The largest of these companies explore for, produce and market oil and natural gas, carry on refining operations and market the resultant products on a worldwide basis. The primary areas in which we encounter substantial competition are in our drilling and development operations, locating and acquiring prospective oil and natural gas properties and reserves and attracting and retaining highly skilled personnel. There is also competition between producers of oil and natural gas and other industries producing alternative energy and fuel. Furthermore, competitive conditions may be substantially affected by various forms of energy legislation and/or regulation considered from time to time by the United States government; however, it is not possible to predict the nature of any such legislation or regulation that may ultimately be adopted or its effects upon our future operations. Such laws and regulations may, however, substantially increase the costs of exploring for, developing or producing oil and natural gas and may prevent or delay the commencement or continuation of a given operation. The effect of these risks cannot be accurately predicted.
Insurance
We currently maintain oil and gas commercial general liability protection relating to all of our oil and gas operations (including environmental and pollution claims) with a total limit of coverage in the amount of $2,000,000 (with no deductible) and excess liability protection with a total limit of $3,000,000 (with a deductible of $10,000).
As is common in the oil and gas industry, we will not insure fully against all risks associated with our business either because such insurance is not available or because premium costs are considered prohibitive. In addition, pollution and environmental risks generally are not fully insurable. A loss not fully covered by insurance could have a material adverse effect on our business, financial condition and results of operations.
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Employees
As of December 31, 2013, we had no employees. We engage the services of our Interim President and our Chief Accounting Officer on a consulting or contract basis. We engage additional part-time consultants on an as-needed basis. We are not a party to any collective bargaining agreements and have not experienced any strikes or work stoppages.
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.
Although average drilling and completion costs for each area will vary, as will the cost of each well within a given area, on average approximately 50% of the drilling and completion costs for our wells are associated with hydraulic fracturing activities. These costs are treated in the same way that all other costs of drilling and completing our wells are treated and are built into and funded through our normal capital expenditures budget. A change to any federal and state laws and regulations governing hydraulic fracturing could impact these costs and adversely affect our business and financial results. See “Risk Factors — Federal and state legislative and regulatory initiatives as well as governmental reviews relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays as well as adversely affect our level of production.”
The protection of groundwater quality is important to us. Our policy and practice is to ensure our service providers follow all applicable guidelines and regulations in the areas where we have hydraulic fracturing operations. In addition, we send at least one of our own engineers or an experienced consultant to the well site to personally supervise each hydraulic fracture treatment.
We believe that the hydraulic fracturing operations on our properties are conducted in compliance with all state and federal regulations and in accordance with industry standard practices for groundwater protection. These protective measures include setting surface casing at a depth sufficient to protect fresh water zones as determined by applicable state regulatory agencies, and cementing the casing to create a permanent isolating barrier between the casing pipe and surrounding geological formations. The casing plus the cement are intended to prevent contact between the fracturing fluid and any aquifers during the hydraulic fracturing or other well operations. For recompletions of existing wells, the production casing is pressure tested prior to perforating the new completion interval. Injection rates and pressures are monitored at the surface during our hydraulic fracturing operations. Pressure is monitored on both the injection string and the immediate annulus to the injection string.
The vast majority of hydraulic fracturing treatments are made up of water and sand or other kinds of man-made propping agents. Our service providers track and report chemical additives that are used in the fracturing operation as required by the applicable governmental agencies.
Hydraulic fracturing requires the use of a significant amount of water. All produced water, including fracture stimulation water, is disposed of in a way that does not impact surface waters. All produced water is disposed of in permitted and regulated disposal facilities.
Environmental Matters and Regulation
Our exploration, development and production operations are subject to various federal, state and local laws and regulations governing health and safety, the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may, among other things: require the acquisition of permits to conduct exploration, drilling and production operations; govern the amounts and types of substances that may be released into the environment in connection with oil and natural gas drilling and production; restrict the way we handle or dispose of our wastes or of naturally occurring radioactive materials generated by our operations; cause us to incur significant capital expenditures to install pollution control or safety related equipment operating at our facilities; limit or prohibit construction or drilling activities in sensitive areas such as wetlands, wilderness areas or areas inhabited by endangered or threatened species; impose specific health and safety criteria addressing worker protection; require investigatory and remedial actions to mitigate pollution conditions caused by our operations or attributable to former operations; impose obligations to reclaim and abandon well sites and pits and impose substantial liabilities on us for pollution resulting from our operations. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations and the issuance of orders enjoining some or all of our operations in affected areas.
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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 were notified by the Bureau of Land Management (“BLM”) that environmental deficiencies existed on our Tom Tom Tomahawk field in Chaves and Roosevelt counties in New Mexico. We have submitted a plan to remediate such activities to the BLM and the plan was accepted. Before work can commence, we have to perform certain procedures such as sampling the soil. For the year ending December 31, 2012, we recorded a non-cash charge of $2,100,000 which was management’s best estimate of the costs to remediate the environmental deficiencies. This estimate could materially differ from actual expenditures. We cannot assure you that the passage of more stringent laws and regulations in the future will not have a further negative impact on our business, financial condition or results of operations.
The following is a summary of the more significant existing environmental, health and safety laws and regulations to which our business is subject and for which compliance may have a material adverse impact on our capital expenditures, financial condition or results of operations.
Comprehensive Environmental Response, Compensation and Liability Act
Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the “Superfund” law, and comparable state statutes impose joint and several liability for costs of investigation and remediation and for natural resource damages without regard to fault or legality of the original conduct, on certain classes of persons with respect to the release into the environment of substances designated under CERCLA as hazardous substances. These classes of persons, or so–called potentially responsible parties (“PRPs”) include the current and past owners or operators of a site where the release occurred and anyone who transported or disposed or arranged for the transport or disposal of a hazardous substance found at the site. CERCLA also authorizes the Environmental Protection Agency (the “EPA”) and, in some instances, third parties to take actions in response to threats to public health or the environment and to seek to recover from the PRPs the costs of such action. Many states have adopted comparable or more stringent state statutes.
Although CERCLA generally exempts “petroleum” from the definition of hazardous substance, in the course of our operations, we will generate, transport and dispose or arrange for the disposal of wastes that may fall within CERCLA’s definition of hazardous substances. Comparable state statutes may not contain a similar exemption for petroleum. We may also be the owner or operator of sites on which hazardous substances have been released.
Solid and Hazardous Waste Handling
The Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes regulate the generation, transportation, treatment, storage, disposal and cleanup of solid and hazardous waste. Although oil and natural gas waste generally is exempt from regulations as hazardous waste under RCRA, we will generate waste as a routine part of our operations that may be subject to RCRA and not all state and local laws contain a comparable exemption. Further, there is no guarantee that the EPA or individual states will not adopt more stringent requirements for the handling of non–hazardous waste or categorize some non–hazardous waste as hazardous in the future. Any such change could result in an increase in our costs to manage and dispose of waste, which could have a material adverse effect on our financial condition and results of operations.
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It is also possible that our oil and natural gas operations may require us to manage naturally occurring radioactive materials, or NORM. NORM is present in varying concentrations in sub-surface formations, including hydrocarbon reservoirs, and may become concentrated in scale, film and sludge in equipment that comes in contract with crude oil and natural gas production and processing streams. Some states have enacted regulations governing the handling, treatment, storage and disposal of NORM.
Clean Water Act
The Clean Water Act and analogous state laws impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of produced water and other oil and natural gas wastes, and fill materials into state waters and waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of certain permits issued by the EPA or an analogous state agency. Spill prevention, control and countermeasure (“SPCC”) requirements under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. In addition, the Clean Water Act and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. The Clean Water Act also prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by a permit issued by the United States Army Corps of Engineers. Federal and state regulatory agencies can impose administrative, civil and criminal penalties, as well as require remedial or mitigation measures, for non–compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations. In the event of an unauthorized discharge of wastes, we may be liable for penalties and costs of remediation.
The Oil Pollution Act of 1990 (“OPA 90”) and its regulations impose requirements on “responsible parties” related to the prevention of oil spills and liability for damages resulting from oil spills into or upon navigable waters, adjoining shorelines or in the exclusive economic zone of the United States. A “responsible party” under the OPA 90 may include the owner or operator of an onshore facility. The OPA 90 subjects responsible parties to strict, joint and several financial liability for removal costs and other damages, including natural resource damages, caused by an oil spill that is covered by the statute. It also imposes other requirements on responsible parties, such as the preparation of an oil spill contingency plan. Failure to comply with the OPA 90 may subject a responsible party to civil or criminal enforcement action. We may conduct operations on acreage located near, or that affects, navigable waters subject to the OPA 90. We believe that compliance with applicable requirements under the OPA 90 will not have a material and adverse effect on us.
Safe Drinking Water Act
The Safe Drinking Water Act (the “SDWA”) regulates, among other things, underground injection operations. Hydraulic fracturing continues to be under intense regulatory scrutiny both at the federal level and at the state level. In past legislative sessions, the United States Congress considered two companion bills that if passed would have imposed on our hydraulic fracturing operations significantly more stringent requirements. In addition to subjecting the injection of hydraulic fracturing to the SDWA regulatory and permitting requirements, the proposed legislation would require the disclosure of the chemicals within the hydraulic fluids, which could make it easier for our competition to copy our operations and for third parties opposing hydraulic fracturing to initiate legal proceedings based on allegations that specific chemicals used in the process could adversely affect ground water. If this or similar legislation is enacted, we could incur substantial compliance costs and the requirements could negatively impact our ability to conduct fracturing activities on our assets.
Many states have considered or adopted legislation or regulations requiring the disclosure of the chemicals used in hydraulic fracturing. Texas has adopted such a program, which is administered by the Railroad Commission of Texas. The Wyoming Oil and Gas Conservation Commission also passed a rule requiring disclosure of hydraulic fracturing fluid. In addition, a number of states in which we plan to conduct, are currently conducting, or may in the future conduct, hydraulic fracturing operations regulatory reviews hydraulic fracturing and new regulations from such reviews could restrict or limit our access to shale formations or could delay our operations or make them more costly.
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The BLM has proposed a comprehensive rule regulating hydraulic fracturing on federal and certain tribal lands. The rules impose disclosure requirements on the use of hydraulic fracturing chemicals. These proposed rules also require BLM approval prior to hydraulic fracturing. BLM also would require operators to meet other substantive requirements relating to well integrity and recordkeeping.
The EPA recently issued draft guidance under the SDWA, providing direction about how it will address the use of diesel in hydraulic fracturing activities. The draft guidance provides a definition of diesel fuels and discusses how the EPA’s Underground Injection Control rules will be applied to hydraulic fracturing. Further, in March 2010, the EPA announced that it would conduct a wide-ranging study on the effects of hydraulic fracturing on drinking water resources. Interim results of the study are expected in 2012, with final results expected in 2014. The agency also announced that one of its enforcement initiatives for 2011 to 2013 would be to focus on environmental compliance by the energy extraction sector. This additional regulatory scrutiny could make it difficult to perform hydraulic fracturing and increase our costs of compliance and doing business.
Air Emissions
Our operations are subject to federal, state and local regulations for the control of emissions from sources of air pollution under the Clean Air Act (“CAA”) and analogous state and local programs. Federal and state laws require new and modified sources of air pollutants to obtain permits prior to commencing construction and also impose various monitoring and reporting requirements. Major sources of air pollutants are subject to more stringent, federally imposed requirements including additional permits. Federal and state laws designed to control hazardous or toxic air pollutants may require installation of additional controls. Administrative enforcement actions for failure to comply strictly with air pollution regulations or permits are generally resolved by payment of monetary fines and correction of any identified deficiencies. Alternatively, regulatory agencies could bring lawsuits for civil penalties or require us to forego construction, modification or operation of certain air emission sources.
On April 17, 2012, the EPA signed final rules under the CAA regarding emissions from oil and natural gas operations. The EPA rule subjects oil and natural gas operations to regulation under the New Source Performance Standards (“NSPS”) and National Emissions Standards for Hazardous Air Pollutants (“NESHAPS”), programs under the CAA, and imposes new and amended requirements under both programs. The new rules, among other things, amend standards applicable to natural gas processing plants and would expand the NSPS to include all oil and natural gas operations, imposing requirements on those operations. The EPA also imposed NSPS standards for completions of hydraulically fractured natural gas wells, requiring the use of reduced emission completion techniques. The adopted rules allow in most circumstances, until January 1, 2015, facilities to combust natural gas that would escape during completion activities as an alternative to the reduced emission completion techniques. The NESHAPS proposal includes maximum achievable control technology standards for certain glycol dehydrators and storage vessels, and revises applicability provisions, alternative test protocols and the availability of the startup, shutdown and maintenance exemption. These new requirements may result in increased operating and compliance costs, increased regulatory burdens and delays in our operations. Compliance with such rules could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact our business.
Climate Change Legislation
In response to certain scientific studies suggesting that emissions of carbon dioxide, methane and other greenhouse gases (“GHGs”) are contributing to the warming of the Earth’s atmosphere and other climatic changes, the United States Congress has considered legislation to reduce such emissions. To date, the United States Congress has failed to enact a comprehensive GHG program. Some states, either individually or on a regional level, have considered or enacted legal measures to reduce GHG emissions. Although most of the state-level initiatives have to date focused on large sources of GHG emissions, it is possible that smaller sources of emissions could become subject to GHG emission limitations. The cost of complying with these programs could be significant.
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The EPA published finding that emissions of GHGs presented an endangerment to public health and the environment. These findings by the EPA allowed the agency to proceed through a rule-making process with the adoption and implementation of regulations that would restrict emissions of GHGs under existing provisions of the CAA. Consequently, the EPA adopted two sets of regulations that would require a reduction in emissions of GHGs from motor vehicles and could trigger permit review for GHG emissions from certain stationary sources. On June 3, 2010, the EPA published its final rule to address permitting of GHG emissions from stationary sources under the prevention of significant deterioration (“PSD”) and Title V permitting programs. The final rule tailors the PSD and Title V permitting programs to apply to qualifying stationary sources of GHG emissions in a multi-step process, beginning January 2, 2011, with the largest sources first subject to permitting. In addition, the EPA has adopted a rule requiring the reporting of GHG emissions from specified large GHG emission sources in the United States. On November 8, 2010, the EPA finalized its regulations to expand its final rule on GHG emissions reporting to include onshore and offshore oil and natural gas production facilities and onshore oil and natural gas processing, transmission, storage and distribution facilities. Reporting of GHG emissions from such facilities will be required on an annual basis beginning in 2012 for emissions occurring in 2011. While we believe that we will be able to substantially comply with such reporting requirements without any material adverse effect to our financial condition, since such reporting requirements with respect to GHG emissions are new in the oil and natural gas industry, there can be no assurance that our reports will initially be in substantial compliance or that such requirements will not develop into more stringent and costly obligations that may have a significant impact on our operating costs. The adoption and implementation of any regulations imposing reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations or could adversely affect demand for the oil and natural gas we produce. Any one of these climate change regulatory and legislative initiatives could have a material adverse effect on our business, financial condition and results of operations.
Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts and floods and other climatic events; if any such effects were to occur, they could have a material adverse effect on our business and results of operations.
OSHA and Other Laws and Regulations on Employee Health and Safety
To the extent not preempted by other applicable laws, we are subject to the requirements of the Occupational Safety and Health Act (“OSHA”) and comparable state statutes, where applicable. These laws and the implementing regulations strictly govern the protection of the health and safety of employees. The OSHA hazard communication standard, the EPA community right–to–know regulations under the Title III of CERCLA and similar state statutes, where applicable, require us to organize and maintain information about hazardous materials used or, as applicable, produced in our operations and that this information be provided to employees, state and local government authorities and, where applicable, citizens. OSHA may enforce workplace safety regulations through issuance of citations for violations of its standards, which include, but are not limited to, those regarding hazard communication, personal protective equipment, general environmental controls, and materials handling and storage. We believe that we are in substantial compliance with these requirements where applicable and with other applicable OSHA and comparable requirements.
National Environmental Policy Act
Oil and natural gas exploration and production activities on federal lands may be subject to the National Environmental Policy Act (“NEPA”) which requires federal agencies, including the U.S. Department of the Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an Environmental Assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. All of our current exploration and production activities, as well as proposed exploration and development plans, on federal lands require governmental permits that are subject to the requirements of NEPA. This process has the potential to delay or impose additional conditions upon the development of oil and natural gas projects.
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Endangered Species Act
TheEndangered Species Act, as amended (the “ESA”), and analogous state statutes restrict activities that may affect endangered and threatened species or their habitats. While some of our facilities may be located in areas that are designated as habitat for endangered or threatened species, we believe that we are in substantial compliance with the ESA. However, the designation of previously unidentified endangered or threatened species could cause us to incur additional costs or become subject to operating restrictions or bans in the affected areas.
Other Regulation of the Oil and Natural Gas Industry
The oil and natural gas industry is extensively regulated by numerous federal, state and local authorities. In particular, oil and natural gas production and related operations are, or have been, subject to price controls, taxes and numerous other laws and regulations. These laws and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability.
Failure to comply with applicable laws and regulations can result in substantial penalties and possibly cessation of drilling and production operations. The regulatory burden on the industry increases the cost of doing business and affects profitability. We believe that we are in substantial compliance with existing requirements and such compliance will not have a material adverse effect on our financial condition, cash flows or results of operations. Nevertheless, such laws and regulations are frequently amended or reinterpreted. Therefore, we are unable to predict the future costs or impact of compliance. Additional proposals and proceedings that affect the oil and natural gas industry are regularly considered by the United States Congress, the states, the Federal Energy Regulatory Commission (“FERC”) and the courts. We cannot predict when or whether any such proposals may become effective.
Drilling and Production
Our operations are subject to various types of regulation at the federal, state and local levels. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. The states and some counties and municipalities in which we operate also regulate one or more of the following:
| · | the location of wells; |
| · | the method of drilling and casing wells; |
| · | the surface use and restoration of properties upon which wells are drilled; and |
| · | the plugging and abandonment of wells. |
State laws, including Texas, regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploitation while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and natural gas we can produce from our wells or limit the number of wells or the locations at which we can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil and natural gas within its jurisdiction.
In addition, 11 states have enacted surface damage statutes (“SDAs”). These laws are designed to compensate for damage caused by mineral development. Most SDAs contain entry notification and negotiation requirements to facilitate contact between operators and surface owners and users. Most also contain bonding requirements and specific expenses for exploration and producing activities. Costs and delays associated with SDAs could impair operational effectiveness and increase development costs.
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We do not control the availability of transportation and processing facilities used in the marketing of our production. For example, we may have to shut-in a productive natural gas well because of a lack of available natural gas gathering or transportation facilities.
If we conduct operations on federal, state or Indian oil and natural gas leases, these operations must comply with numerous regulatory restrictions, including various non-discrimination statutes, royalty and related valuation requirements, and certain of these operations must be conducted pursuant to certain on-site security regulations and other appropriate permits issued by the Bureau of Land Management, the Bureau of Ocean Energy Management, Regulation and Enforcement or other appropriate federal or state agencies.
Transportation of Oil
Sales of oil are not currently regulated and are made at negotiated prices. Nevertheless, the United States Congress could reenact price controls in the future.
Our sales of oil are affected by the availability, terms and cost of transportation. The transportation of oil in common carrier pipelines is also subject to rate and access regulation. The FERC regulates interstate oil pipeline transportation rates under the Interstate Commerce Act. In general, interstate oil pipeline rates must be cost-based, although settlement rates agreed to by all shippers are permitted and market based rates may be permitted in certain circumstances. Effective January 1, 1995, the FERC implemented regulations establishing an indexing system (based on inflation) for transportation rates for oil that allowed for an annual increase or decrease in the cost of transporting oil to the purchaser, effective July 1 of each year. The FERC reviews the indexing methodology every five years. In its latest order on the methodology, issued in December 2010, the FERC concluded that an index level of the Producer Price Index for Finished Goods plus 2.65 percent should be established for the five-year period commencing July 1, 2011.
Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any way that is of material difference from those of our competitors who are similarly situated.
Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all similarly situated shippers requesting service on the same terms and under the same rates. When shipper nominations exceed full capacity, access is governed by prorationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our similarly situated competitors.
Transportation and Sales of Natural Gas
Historically, the transportation and sale for resale of natural gas in interstate commerce has been regulated by the FERC under the Natural Gas Act of 1938 (the “NGA”), the Natural Gas Policy Act of 1978 (the “NGPA”), and regulations issued under those statutes. In the past, the federal government has regulated the prices at which natural gas could be sold. While sales by producers of natural gas can currently be made at market prices, the United State Congress could reenact price controls in the future. Deregulation of wellhead natural gas sales began with the enactment of the NGPA and culminated in adoption of the Natural Gas Wellhead Decontrol Act which removed all price controls affecting wellhead sales of natural gas effective January 1, 1993.
FERC regulates interstate natural gas transportation rates, and terms and conditions of service, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas. Since 1985, the FERC has endeavored to make natural gas transportation more accessible to natural gas buyers and sellers on an open and non-discriminatory basis. The FERC has stated that open access policies are necessary to improve the competitive structure of the interstate natural gas pipeline industry and to create a regulatory framework that will put natural gas sellers into more direct contractual relations with natural gas buyers by, among other things, unbundling the sale of natural gas from the sale of transportation and storage services. Beginning in 1992, the FERC issued a series of orders, beginning with Order No. 636, to implement its open access policies. As a result, the interstate pipelines’ traditional role of providing the sale and transportation of natural gas as a single service has been eliminated and replaced by a structure under which pipelines provide transportation and storage service on an open access basis to others who buy and sell natural gas. Although the FERC’s orders do not directly regulate natural gas producers, they are intended to foster increased competition within all phases of the natural gas industry.
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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 (the “CFTC”). See “—Other Federal Laws and Regulations Affecting Our Industry—Energy Policy Act of 2005.” Should we violate the anti-market manipulation laws and regulations, we could also be subject to related third party damage claims by, among others, sellers, royalty owners and taxing authorities. In addition, pursuant to Order No. 704, some of our operations may be required to annually report to the FERC on May 1 of each year for the previous calendar year. Currently, Order No. 704 requires certain natural gas market participants to report information regarding their reporting of transactions to price index publishers and their blanket sales certificate status, as well as certain information regarding their wholesale, physical natural gas transactions for the previous calendar year depending on the volume of natural gas transacted. See “—Other Federal Laws and Regulations Affecting Our Industry—FERC Market Transparency Rules.”
Gathering services, which occur upstream of jurisdictional transmission services, are regulated by the states. In addition, intrastate natural gas transportation and facilities are also subject to regulation by state regulatory agencies, and certain transportation services provided by intrastate pipelines are also regulated by the FERC. The basis for regulation of intrastate natural gas transportation and gathering the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline and gathering pipeline rates and services varies from state to state. Insofar as such regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable basis, we believe that the regulation of similarly situated intrastate natural gas transportation in any states in which we operate and ship natural gas on an intrastate basis will not affect our operations in any way that is of material difference from those of our competitors. Like the regulation of interstate transportation rates, the regulation of intrastate transportation rates affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas.
State Natural Gas Regulation
Various states, including Texas, regulate the drilling for, and the production, gathering and sale of, natural gas, including imposing severance taxes and requirements for obtaining drilling permits. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of natural gas resources. States may regulate rates of production and may establish maximum daily production allowables from natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but there can be no assurance that they will not do so in the future. The effect of these regulations may be to limit the amounts of natural gas that may be produced from our wells and to limit the number of wells or locations we can drill.
Other Federal Laws and Regulations Affecting Our Industry
Energy Policy Act of 2005
On August 8, 2005, President Bush signed into law the Energy Policy Act of 2005 (the “EPAct 2005”). The EPAct 2005 is a comprehensive compilation of tax incentives, authorized appropriations for grants and guaranteed loans, and significant changes to the statutory policy that affects all segments of the energy industry. Among other matters, the EPAct 2005 amends the NGA to add an anti-manipulation provision which makes it unlawful for any entity to engage in prohibited behavior to be prescribed by the FERC, and furthermore provides the FERC with additional civil penalty authority. The EPAct 2005 provides the FERC with the power to assess civil penalties of up to $1.0 million per day for violations of the NGA and increases the FERC’s civil penalty authority under the NGPA from $5,000 per violation per day to $1.0 million per violation per day. On January 19, 2006, the FERC issued Order No. 670, a rule that implements the anti-manipulation provision of the EPAct 2005 and makes it unlawful for any entity, directly or indirectly, in connection with the purchase or sale of natural gas subject to the jurisdiction of the FERC, or the purchase or sale of transportation services subject to the jurisdiction of the FERC: (1) to use or employ any device, scheme or artifice to defraud; (2) to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or (3) to engage in any act, practice, or course of business that operates as a fraud or deceit upon any person. The anti-manipulation rules and enhanced civil penalty authority reflect an expansion of the FERC’s NGA enforcement authority. Should we fail to comply with all applicable FERC administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines.
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FERC Market Transparency Rules
On April 19, 2007, the FERC issued a final rule on the annual natural gas transaction reporting requirements, as amended by subsequent orders on rehearing, or Order No. 704. Under Order No. 704, wholesale buyers and sellers of more than 2.2 million MMBtu of physical natural gas in the previous calendar year, including interstate and intrastate natural gas pipelines, natural gas gatherers, natural gas processors, natural gas marketers and natural gas producers are required to report, on May 1 of each year, aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to or may contribute to the formation of price indices. It is the responsibility of the reporting entity to determine which individual transactions should be reported based on the guidance of Order No. 704. Order No. 704 also requires market participants to indicate whether they report prices to any index publishers and, if so, whether their reporting complies with the FERC’s policy statement on price reporting. In 2011, a federal appellate court determined that FERC does not have legal authority to impose reporting requirements on wholly-intrastate pipelines.
Additional proposals and proceedings that might affect the natural gas industry are pending before the United State Congress, the FERC and the courts. We cannot predict the ultimate impact of these or the above regulatory changes to our natural gas operations. We do not believe that we would be affected by any such action materially differently than similarly situated competitors.
| Item 1A. | Risk Factors |
Risks Related to Our Business
We may not have sufficient capital to operate our business as presently contemplated.
The oil and natural gas industry is capital intensive. We make and expect to continue to make significant capital expenditures in our business for the exploration, development, production and acquisition of oil and natural gas reserves. Improvement in commodity prices may result in an increase in our actual capital expenditures.
We plan to spend between $6 million and $8 million during fiscal 2014 to drill and complete wells, re-enter and complete wells, or improve infrastructure. Our main area of focus is the Tom Tom/Tomahawk Prospect, where we will continue work on the field alongside the execution of our remediation plan. For fiscal 2013, this included the re-entry of 11 gross wells (8.2 net), drilling of 3 gross wells (2.6 net), and the improvement of field infrastructure. We will also spend capital in several non-operated prospect areas. Currently, we are committed to participating in the drilling of 4 gross wells (0.5 net) in fiscal 2014. We expect to finance these activities with cashflow generated from operations and availability under our line of credit with Independent Bank.
Our cash flows from operations and access to capital are subject to a number of variables, including:
| · | our proved reserves; |
| · | the level of oil and natural gas we are able to produce from existing wells; |
| · | the prices at which our oil and natural gas are sold; |
| · | our ability to acquire, locate and produce new reserves; and |
| · | the ability of our banks to lend. |
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Debt financing could lead to:
| · | a substantial portion of operating cash flow being dedicated to the payment of principal and interest; |
| · | us being more vulnerable to competitive pressures and economic downturns; and |
| · | restrictions on our operations, including our ability to pay dividends. |
If sufficient capital resources are not available, we might be forced to cease operations entirely, curtail developmental and exploratory drilling and other activities or be forced to sell some assets on an untimely or unfavorable basis, which would have a material adverse effect on our business, financial condition and results of operations.
Our outstanding debt contains covenants restricting certain actions we may take.
Our credit agreement with Independent Bank contains various restricting certain actions we may take, including, but not limited to, incurring additional indebtedness, entering into any merger, selling any of our assets, making certain investments and paying dividends. The credit agreement also contains various financial covenants requiring us to maintain a certain ratio of debt compared to EBITDAX (as defined in the credit agreement). These restrictions and covenants may adversely effect our operations.
We may have difficulty managing growth in our business, which could adversely affect our financial condition and results of operations.
Growth in accordance with our business plan, if achieved, could place a significant strain on our financial, technical, operational and management resources. As we expand our activities and increase the number of projects we are evaluating or in which we participate, there will be additional demands on our financial, technical, operational and management resources. The failure to continue to upgrade our technical, administrative, operating and financial control systems or the occurrences of unexpected expansion difficulties, including the failure to recruit and retain experienced managers, geologists, engineers and other professionals in the oil and natural gas industry, could have a material adverse effect on our business, financial condition and results of operations and our ability to timely execute our business plan.
A substantial or extended decline in oil and natural gas prices may adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments.
The price we receive for our oil and natural gas will heavily influence our revenue, profitability, access to capital and future rate of growth. Oil and natural gas are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil and natural gas have been volatile. These markets will likely continue to be volatile in the future. The prices we receive for our production depend on numerous factors beyond our control. These factors include the following:
| · | worldwide and regional economic conditions impacting the global supply and demand for oil and natural gas; |
| · | the price and quantity of imports of foreign oil and natural gas; |
| · | the actions of the Organization of Petroleum Exporting Countries, or OPEC, and other state-controlled oil companies relating to oil and natural gas price and production control; |
| · | political conditions in or affecting other oil-producing and natural gas-producing countries, including the current conflicts in the Middle East and conditions in South America and Russia; |
| · | the level of global oil and natural gas inventories; |
| · | localized supply and demand fundamentals; |
| · | the availability of refining capacity; |
| · | price and availability of transportation and pipeline systems with adequate capacity; |
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| · | weather conditions and natural disasters; |
| · | governmental regulations; |
| · | speculation as to the future price of oil and the speculative trading of oil and natural gas futures contracts; |
| · | price and availability of competitors’ supplies of oil and natural gas; |
| · | energy conservation and environmental measures; |
| · | technological advances affecting energy consumption; |
| · | the price and availability of alternative fuels and energy sources; and |
| · | domestic and international drilling activity. |
Declines in oil and natural gas prices may materially adversely affect our financial condition, liquidity, and ability to finance planned capital expenditures and results of operations and may reduce the amount of oil and natural gas that we can produce economically. This could have a material adverse effect on our liquidity and financial condition.
Properties that we acquire may not produce as projected, and we may be unable to accurately predict reserve potential, identify liabilities associated with the properties or obtain protection from sellers against such liabilities.
We may 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 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 the majority of the properties in which we have an interest. As a result, we have limited ability to exercise influence over, and control the risks associated with, the operation of these properties. The success and timing of our drilling and development activities on those properties depend upon a number of factors outside of our control, including:
| · | the timing and amount of capital expenditures; |
| · | the operators’ expertise and financial resources; |
| · | the approval of other participants in drilling wells; and |
| · | the selection of suitable technology. |
As a result of any of the above or an operator’s failure to act in ways that are in our best interest, our allocated production revenues and results of operations could be adversely affected.
Drilling for and producing oil and natural gas are speculative activities and involve numerous risks and substantial and uncertain costs that could adversely affect us.
Our future financial condition and results of operations will depend on the success of our acquisition, exploitation, development and production activities. Our oil and natural gas exploration and production activities are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially productive oil or natural gas reservoirs. Our decisions to acquire, explore, develop or otherwise exploit drilling locations or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. In addition, our cost of drilling, completing and operating wells is often uncertain before drilling commences. Overruns in budgeted expenditures are common risks that can make a particular project uneconomical. Further, many factors may curtail, delay or cancel our scheduled drilling projects, including the following:
| · | shortages of or delays in obtaining equipment and qualified personnel; |
| · | facility or equipment malfunctions; |
| · | unexpected operational events; |
| · | pressure or irregularities in geological formations; |
| · | adverse weather conditions, such as flooding; |
| · | reductions in oil and natural gas prices; |
| · | delays imposed by or resulting from compliance with regulatory requirements; |
| · | proximity to and capacity of transportation facilities; |
| · | title problems; |
| · | limitations in the market for oil and natural gas; and |
| · | costs and availability of drilling rigs, equipment, supplies, personnel and oilfield services. |
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Even if drilled, our completed wells may not produce reserves of oil or natural gas that are commercially productive or that meet our earlier estimates of economically recoverable reserves. A productive well may become uneconomic if water or other deleterious substances are encountered, which impair or prevent the production of oil and/or natural gas from the well. Our overall drilling success rate or our drilling success rate for activity within a particular project area may decline. Unsuccessful drilling activities could result in a significant decline in our production and revenues and materially harm our operations and financial condition by reducing our available cash and resources.
Reserve estimates depend on many assumptions that may turn out to be inaccurate.
Any material inaccuracies in our reserve estimates or underlying assumptions could materially affect the quantities and present values of our reserves. This Annual Report on Form 10-K contains estimates of our proved oil and natural gas reserves and PV-10 and standardized measure of our proved oil and natural gas reserves. The process of estimating oil and natural gas reserves is complex. It requires interpretations of available technical data and various assumptions, including assumptions relating to economic factors. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities of reserves and amount of PV-10 and standardized measure that we may report. The process of preparing these estimates requires the projection of production rates and timing of development expenditures and analysis of available geological, geophysical, production and engineering data, and the extent, quality and reliability of this data can vary. The process also requires economic assumptions relating to matters such as oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds.
Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves most likely will vary from our estimates. Any significant variance could materially affect the estimated quantities of reserves and amount of PV-10 and standardized measure that we may report. In addition, we may adjust estimates of proved reserves and amount of PV-10 and standardized measure to reflect production history, results of exploration and development, prevailing oil and natural gas prices and other factors, many of which are beyond our control. Moreover, there can be no assurance that our reserves will ultimately be produced or that our proved undeveloped reserves will be developed within the periods anticipated. Any significant variance in the assumptions could materially affect the estimated quantity our reserves and amount of PV-10 and standardized measure.
Investors should not assume that the PV-10 of our proved reserves is the current market value of our estimated oil and natural gas reserves. PV-10 is based on prices and costs in effect on the date of the estimate. Actual future prices, costs, and the volume of produced reserves may differ materially from those used in the PV-10 estimate.
Approximately 43% of our total estimated proved reserves as of December 31, 2013 were classified as proved undeveloped and may not be ultimately developed or produced.
As of December 31, 2013, approximately 43% of our total estimated proved reserves were undeveloped. Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations. The future drilling of proved undeveloped reserves is highly dependent upon our ability to fund our capital expenditures, which we estimate will be approximately $6.0 million to $8.0 million for 2014. We cannot be sure that these estimated costs are accurate, and we may be unable to obtain sufficient capital. Further, our drilling efforts may be delayed or unsuccessful, and actual reserves may prove to be less than current reserve estimates, which could have a material adverse effect on our financial condition, future cash flows and results of operations.
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If we are unable to find purchasers of our natural gas, it could harm our profitability.
There generally are only a limited number of natural gas transmission companies with existing pipelines in the vicinity of a natural gas well or wells. In the event that producing natural gas properties are not subject to purchase contracts or that any such contracts terminate and other parties do not purchase our natural gas production, there is no assurance that we will be able to enter into purchase contracts with any transmission companies or other purchasers of natural gas and there can be no assurance regarding the price which such purchasers would be willing to pay for such natural gas. There presently exists an oversupply of natural gas in the marketplace, the extent and duration of which is not known. Such oversupply may result in reductions of purchases by principal natural gas pipeline purchasers.
If oil and natural gas prices decrease, we may be required to take write-downs of the carrying values of our oil and natural gas properties.
We will review our proved oil and natural gas properties for impairment whenever events or changes in circumstances indicate that a decline in the recoverability of their carrying value may have occurred. Based on specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write down the carrying value of our oil and natural gas properties, which may result in a decrease in the amount of future permitted indebtedness available. A write-down constitutes a non-cash charge to earnings. We may incur impairment charges in the future, which could have a material adverse effect on our results of operations for the periods in which such charges are taken.
Unless we replace oil and natural gas reserves, our production and cash flows will decline.
Our future success will depend on our ability to find, develop or acquire additional reserves that are commercially productive. If we are unable to replace reserves through drilling or acquisitions, our level of production and cash flows will be adversely affected. In general, production from oil and natural gas properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. Our total proved reserves decline as reserves are produced unless we conduct other successful exploration and development activities or acquire properties containing proved reserves, or both. Our ability to make the necessary capital investment to maintain or expand our asset base of oil and natural gas reserves would be impaired to the extent cash flow from operations is reduced and external sources of capital become limited or unavailable. We may not be successful in exploring for, developing or acquiring additional reserves. We also may not be successful in raising funds to acquire, explore or develop additional reserves.
Prospects that we decide to drill may not yield oil or natural gas in commercially viable quantities.
Prospects that we decide to drill that do not yield oil or natural gas in commercially productive quantities will adversely affect our financial condition and results of operations. Our prospects are in various stages of evaluation, and may range from a prospect which is ready to drill to a prospect that will require substantial additional seismic data processing and interpretation and other technical analysis. There is no way to predict in advance of drilling and testing whether any particular prospect will yield oil or natural gas in sufficient quantities to recover drilling or completion costs or to be commercially productive. The use of seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in commercial quantities. We cannot assure you that the analogies we draw from available data from other wells, more fully explored prospects or producing fields will be applicable to our drilling prospects.
Market conditions or transportation impediments may hinder access to oil and natural gas markets or delay production.
Market conditions, the unavailability of satisfactory oil and natural gas transportation or the remote location of our drilling operations may restrict our access to oil and natural gas markets or delay production. The availability of a ready market for oil and natural gas production depends on a number of factors, including the demand for and supply of oil and natural gas, the proximity of reserves to pipelines or trucking and terminal facilities and the availability of trucks and other transportation equipment. We may be required to shut-in wells or delay initial production for lack of a viable market or because of inadequacy or unavailability of pipeline or gathering system capacity. When that occurs, we will be unable to realize revenue from those wells until the production can be tied to a gathering system. This can result in considerable delays from the initial discovery of a reservoir to the actual production of the oil and natural gas and realization of revenues.
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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 has been particularly scrutinized. New York, for example, recently issued a moratorium currently in effect on the issuance of permits for inland drilling and completion activities. Subject to an Executive Order issued by Governor Paterson on December 13, 2010, the New York Department of Environmental Conservation will not issue permits for drilling and completion activities until it completes a final environmental impact study following public comment. Texas is not currently considering such a measure. In addition, on May 17, 2012, the Governor of Vermont signed a bill banning hydraulic fracturing in the state of Vermont. To date, Vermont is the first and only state to ban hydraulic fracturing. If we are unable to obtain the necessary permits for our operations, it could have a material adverse effect on our results of operations and profitability.
Our operations are subject to hazards inherent in the oil and natural gas industry.
We implement hydraulic fracturing in our operations, a process involving the injection of fluids—usually consisting mostly of water but typically including small amounts of several chemical additives—as well as sand in order to create fractures extending from the wellbore through the rock formation to enable oil or natural gas to move more easily through the rock pores to a production well. Risks inherent to our industry include the potential for significant losses associated with damage to the environment. Equipment design or operational failures, or vehicle operator error can result in explosions and discharges of toxic gases, chemicals and hazardous substances, and, in rare cases, uncontrollable flows of natural gas or well fluids into environmental media, as well as personal injury, loss of life, long-term suspension or cessation of operations and interruption of our business and/or the business or livelihood of third parties, damage to geologic formations, environmental media and natural resources, equipment and/or facilities and property. In addition, we use and generate hazardous substances and wastes in our operations and may become subject to claims relating to the release of such substances into the environment. In addition, some of our current properties are, or have been, used for industrial purposes, which could contain currently unknown contamination that could expose us to governmental requirements or claims relating to environmental remediation, personal injury and/or property damage. These conditions could expose us to liability for personal injury, wrongful death, property damage, loss of oil and natural gas production, pollution and other environmental damages and, in an extreme case, could materially impair our profitability, competitive position or viability. Depending on the frequency and severity of such liabilities or losses, it is possible that our operating costs, insurability and relationships with employees and regulators could be materially impaired.
Our business and operations may be adversely affected by regulations affecting the oil and natural gas industry.
Our business and operations are subject to and impacted by a wide array of federal, state, and local laws and regulations on the exploration for and development, production, and marketing of oil and natural gas, the operation of oil and natural gas wells, taxation, and environmental and safety matters. Many laws and regulations require drilling permits and govern the spacing of wells, rates of production, prevention of waste and other matters. The technical requirements of these laws and regulations are becoming increasingly stringent, complex and costly to implement. The high cost of compliance with applicable regulations may cause us to limit or discontinue our operation and development activities.
Changes in regulations and laws relating to the oil and natural gas industry could result in our operations being disrupted or curtailed by government authorities. For example, oil and natural gas exploration and production may become less cost effective and decline as a result of increasingly stringent environmental requirements (including land use policies responsive to environmental concerns and delays or difficulties in obtaining environmental permits). A decline in exploration and production, in turn could have a material adverse effect on our business, financial condition, results of operations and cash flows.
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The unavailability or high cost of drilling rigs, equipment, supplies, personnel and oilfield services could adversely affect our ability to execute exploration plans on a timely basis and within budget.
We are highly dependent upon third-party services. The cost of oilfield services typically fluctuates based on demand for those services. There is no assurance that we will be able to contract for such services on a timely basis or that the cost of such services will remain at a satisfactory or affordable level. Shortages or the high cost of drilling rigs, equipment, supplies or personnel could delay or adversely affect our exploration operations, which could have a material adverse effect on our business, financial condition or results of operations.
Production of oil and natural gas could be materially and adversely affected by natural disasters or severe or unseasonable weather.
Production of oil and natural gas could be materially and adversely affected by natural disasters or severe weather. Repercussions of natural disasters or severe weather conditions may include:
| · | evacuation of personnel and curtailment of operations; |
| · | damage to drilling rigs or other facilities, resulting in suspension of operations; |
| · | inability to deliver materials to worksites; and |
| · | damage to pipelines and other transportation facilities. |
In addition, our hydraulic fracturing operations require significant quantities of water. Texas recently has experienced drought conditions. Any diminished access to water for use in hydraulic fracturing, whether due to usage restrictions or drought or other weather conditions, could curtail our operations or otherwise result in delays in operations or increased costs.
Operating hazards, natural disasters or other interruptions of our operations could result in potential liabilities, which may not be fully covered by our insurance.
The oil and natural gas business generally, and our operations specifically, are subject to certain operating hazards such as:
| · | accidents resulting in serious bodily injury and the loss of life or property; |
| · | liabilities from accidents or damage by our equipment; |
| · | well blowouts; |
| · | cratering (catastrophic failure); |
| · | explosions; |
| · | uncontrollable flows of oil, natural gas or well fluids; |
| · | abnormally pressurized formations; |
| · | fires; |
| · | reservoir damage; |
| · | oil spills; |
| · | pollution and other damage to the environment; and |
| · | releases of toxic gas. |
In addition, our operations are susceptible to damage from natural disasters such as flooding or tornados, which involve increased risks of personal injury, property damage and marketing interruptions. The occurrence of one of these operating hazards may result in injury, loss of life, suspension of operations, environmental damage and remediation and/or governmental investigations and penalties. The payment of any of these liabilities could reduce, or even eliminate, the funds available for exploration and development, or could result in a loss of our properties. In addition, pollution and environmental risks generally are not fully insurable. If a significant accident or other event occurs and is not fully covered by insurance, it could materially adversely affect our financial condition, results of operations and cash flows.
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Our insurance might be inadequate to cover our liabilities. Insurance costs are expected to continue to increase over the next few years, and we may decrease coverage and retain more risk to mitigate future cost increases. If we incur substantial liability, and the damages are not covered by insurance or are in excess of policy limits, then our business, results of operations and financial condition may be materially adversely affected.
We may not be able to keep pace with technological developments in our industry.
The oil and natural gas industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. As others use or develop new technologies, we may be placed at a competitive disadvantage or competitive pressures may force us to implement those new technologies at substantial costs. In addition, other oil and natural gas companies may have greater financial, technical and personnel resources that allow them to enjoy technological advantages and may in the future allow them to implement new technologies before we can. We may not be able to respond to these competitive pressures and implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use now or in the future were to become obsolete or if we are unable to use the most advanced commercially available technology, our business, financial condition and results of operations could be materially adversely affected.
Competition in the oil and natural gas industry is intense, and many of our competitors have resources that are greater than ours.
We operate in a highly competitive environment for developing and acquiring properties, marketing oil and natural gas and securing equipment and trained personnel. As a relatively small oil and natural gas company, many of our competitors, major and large independent oil and natural gas companies, possess and employ financial, technical and personnel resources substantially greater than ours. Those companies may be able to develop and acquire more prospects and productive properties than our financial or personnel resources permit. Our ability to acquire additional prospects and discover reserves in the future will depend on our ability to evaluate and select suitable properties and execute our exploration and development activities in a highly competitive environment. Also, there is substantial competition for capital available for investment in the oil and natural gas industry. Larger competitors may be better able to withstand sustained periods of unsuccessful drilling and absorb the burden of changes in laws and regulations more easily than we can, which would adversely affect our competitive position. We may not be able to compete successfully in the future in developing reserves, acquiring prospective oil and natural gas properties and reserves, attracting and retaining highly skilled personnel and raising additional capital.
We may be unable to diversify our operations to avoid any downturn in the oil and natural gas industry.
Because of our limited financial resources, it is unlikely that we will be able to diversify our operations the way companies with greater financial resources are able to do. Our inability to diversify our activities will subject us to economic fluctuations within the oil and natural gas industry and therefore increase the risks associated with our operations as limited to one industry.
Certain federal income tax deductions currently available with respect to oil and natural gas exploration and development may be eliminated as a result of future legislation.
President Obama’s proposed Fiscal Year 2015 Budget includes proposed legislation that would, if enacted into law, make significant changes to United States tax laws, including the elimination or postponement of certain key United States federal income tax incentives currently available to oil and natural gas exploration and production companies. These changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and natural gas properties, (ii) the elimination of the current deduction for intangible drilling and development costs, (iii) the elimination of the deduction for certain domestic production activities and (iv) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could become effective. The passage of any legislation as a result of these proposals or any other similar changes in United States federal income tax laws could eliminate certain tax deductions that are currently available with respect to oil and natural gas exploration and development.
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Federal and state legislative and regulatory initiatives as well as governmental reviews relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays as well as adversely affect our level of production.
Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons from tight formations. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The process is typically regulated by state oil and gas commissions. However, the EPA has asserted federal regulatory authority over certain hydraulic fracturing practices. Also, legislation has been introduced, but not enacted, in Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process. Certain states, including Texas, and municipalities have adopted, or are considering adopting, regulations that have imposed, or that could impose, more stringent permitting, disclosure, disposal and well construction requirements on hydraulic fracturing operations. For example, in December 2011, the Railroad Commission of Texas finalized regulations requiring public disclosure of all the chemicals in fluids used in the hydraulic fracturing process. Local ordinances or other regulations may regulate or prohibit the performance of well drilling in general and hydraulic fracturing in particular. If new laws or regulations that significantly restrict or regulate hydraulic fracturing are adopted, such legal requirements could cause project delays and make it more difficult or costly for us to perform fracturing to stimulate production from a formation. These delays or additional costs could adversely affect the determination of whether a well is commercially viable. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that we are ultimately able to produce in commercial quantities.
In addition, a number of federal agencies are analyzing, or have been requested to review, a variety of environmental issues associated with hydraulic fracturing. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices, and a committee of the United States House of Representatives has conducted an investigation of hydraulic fracturing practices. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with final results expected to be available by 2014. Moreover, the EPA announced on October 20, 2011 that it is also launching a study regarding wastewater resulting from hydraulic fracturing activities and currently plans to propose standards by 2014 that such wastewater must meet before being transported to a treatment plant. On August 16, 2012, the EPA published final rules under the CAA that, among other things, imposed NSPS standards for completions of hydraulically fractured natural gas wells, requiring the use of reduced emission completion techniques.
In addition, the U.S. Department of Energy is conducting an investigation into hydraulic fracturing practices the agency could recommend to better protect the environment from drilling using hydraulic fracturing completion methods. Also, the U.S. Department of the Interior is considering disclosure requirements or other mandates for hydraulic fracturing on federal lands. Additionally, certain members of Congress have called upon the U.S. Government Accountability Office to investigate how hydraulic fracturing might adversely affect water resources; the Securities and Exchange Commission (“SEC”) to investigate the natural gas industry and any possible misleading of investors or the public regarding the economic feasibility of pursuing natural gas deposits in shales by means of hydraulic fracturing; and the U.S. Energy Information Administration to provide a better understanding of that agency’s estimates regarding natural gas reserves, including reserves from shale formations, as well as uncertainties associated with those estimates. These ongoing or proposed studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory mechanisms.
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Our business exposes us to liability and extensive regulation on environmental matters, which could result in substantial expenditures.
Our operations are subject to numerous U.S. federal, state and local laws and regulations relating to the protection of the environment, including those governing the discharge of materials into the water and air, the generation, management and disposal of hazardous substances and wastes and the clean-up of contaminated sites. We could incur material costs, including clean-up costs, fines and civil and criminal sanctions, injunctive relief and third-party claims for property damage and personal injury as a result of violations of, or liabilities under, environmental laws and regulations. Such laws and regulations not only expose us to liability for our own activities, but may also expose us to liability for the conduct of others or for actions by us that were in compliance with all applicable laws at the time those actions were taken. In addition, we could incur substantial expenditures complying with environmental laws and regulations, including future environmental laws and regulations which may be more stringent, for example, the regulation of GHG emissions under the federal CAA, or state or regional regulatory programs. Regulation of GHG emissions by the EPA, or various states in the United States in areas in which we conduct business, could have an adverse effect on our operations and demand for our oil and natural gas production. Moreover, the EPA has shown a general increased scrutiny on the oil and gas industry through its GHG, CAA and SDWA regulations.
On August 16, 2012, the EPA published final rules under the CAA regarding emissions from oil and natural gas operations. The EPA rule subjects oil and natural gas operations to regulation under the NSPS and NESHAPS, programs under the CAA, and imposes new and amended requirements under both programs. The new rules, among other things, amend standards applicable to natural gas processing plants and would expand the NSPS to include all oil and natural gas operations, imposing requirements on those operations. The EPA also imposed NSPS standards for completions of hydraulically fractured natural gas wells, requiring the use of reduced emission completion techniques. The adopted rules allow facilities, in most circumstances until January 1, 2015, to combust natural gas that would escape during completion activities as an alternative to the reduced emission completion techniques. The NESHAPS rules includes MACT standards for certain glycol dehydrators and storage vessels, and revises applicability provisions, alternative test protocols and the availability of the startup, shutdown and maintenance exemption. These new requirements may result in increased operating and compliance costs, increased regulatory burdens and delays in our operations.
Additionally, we were by the BLM that environmental deficiencies existed on our Tom Tom Tomahawk field in Chaves and Roosevelt counties in New Mexico. We submitted a plan to remediate such activities to the BLM and the plan was accepted. For the year ended December 31, 2012, we recorded a non-cash charge of $2,100,000 which was management’s best estimate of the costs to remediate the environmental deficiencies. If this occurs on any of our other properties, it could have a material adverse effect on our financial condition and results of operations.
The EPA’s implementation of climate change regulations could result in increased operating costs and reduced demand for our oil and natural gas production.
Although federal legislation regarding the control of emissions of GHGs, for the present, appears unlikely, the EPA has been implementing regulatory measures under existing CAA authority and some of those regulations may affect our operations. GHGs are certain gases, including carbon dioxide, a product of the combustion of natural gas, and methane, a primary component of natural gas, that may be contributing to the warming of the Earth’s atmosphere, resulting in climatic changes. These GHG regulations could require us to incur increased operating costs and could have an adverse effect on demand for our oil and natural gas production.
On June 3, 2010, the EPA published its so-called GHG tailoring rule that will phase in federal prevention of significant deterioration permit requirements for new sources and modifications, and Title V operating permits for all sources, that have the potential to emit specific quantities of GHGs. Those permitting provisions, should they become applicable to our operations, could require controls or other measures to reduce GHG emissions from new or modified sources, and we could incur additional costs to satisfy those requirements. On November 30, 2010, the EPA published a rule establishing GHG reporting requirements for sources in the petroleum and natural gas industry, requiring those sources to monitor, maintain records on, and annually report their GHG emissions, with the first annual report for 2011 being due in September 2012. Although this rule does not limit the amount of GHGs that can be emitted, it requires us to incur costs to monitor, record keep and report GHG emissions associated with our operations.
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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 December 31, 2013 relating primarily to the fact that we have a limited number of internal and external staff and therefore are not able to implement proper segregation of duties and review procedures. Failure to have effective internal controls could lead to a misstatement of our financial statements. If, as a result of deficiencies in our internal controls, we cannot provide reliable financial statements, our business decision process may be adversely affected, our business and operating results could be harmed, investors could lose confidence in our reported financial information, the price of our common shares could decrease and our ability to obtain additional financing, or additional financing on favorable terms, could be adversely affected. In addition, failure to maintain effective internal control over financial reporting could result in investigations or sanctions by regulatory authorities.
We intend to take further action to remediate the material weaknesses and improve the effectiveness of our internal control over financial reporting. However, we can give no assurances that the measures we may take will remediate the material weaknesses identified or that any additional material weaknesses will not arise in the future due to our failure to implement and maintain adequate internal control over financial reporting. In addition, even if we are successful in strengthening our controls and procedures, those controls and procedures may not be adequate to prevent or identify irregularities or ensure the fair presentation of our financial statements included in our periodic reports filed with the SEC.
Our officers and directors are engaged in other business activities and conflicts of interest may arise in their daily activities which may not be resolved in our favor.
Certain conflicts of interest may exist between us and our officers and directors. Our officers and directors have other business interests to which they devote their attention, and we expect they will continue to do so. As a result, conflicts of interest or potential conflicts of interest may arise from time to time that can be resolved only through the officers or directors exercising such judgment as is consistent with fiduciary duties to their other business interests and to us. These conflicts of interest may not be resolved in our favor.
Compliance with changing regulation of corporate governance and public disclosure will result in additional expenses and pose challenges for our management.
Changing laws, regulations and standards relating to corporate governance and public disclosure, including the Dodd-Frank Act and the rules and regulations promulgated thereunder, the Sarbanes-Oxley Act and SEC regulations, have created uncertainty for public companies and significantly increased the costs and risks associated with accessing the U.S. public markets. Our management team will need to devote significant time and financial resources to comply with both existing and evolving standards for public companies, which will lead to increased general and administrative expenses and a diversion of management time and attention from revenue generating activities to compliance activities.
Risks Related to Our Common Stock
We may raise additional capital in the future through issuances of securities and such additional funding may be dilutive to shareholders or impose operational restrictions.
We may raise additional capital in the future to help fund our operations through sales of shares of our common stock or securities convertible into shares of our common stock, as well as issuances of debt. Such additional financing may be dilutive to our shareholders, and debt financing, if available, may involve restrictive covenants which may limit our operating flexibility, including the ability to pay dividends. If additional capital is raised through the issuances of shares of our common stock or securities convertible into shares of our common stock, the percentage ownership of existing shareholders will be reduced. These shareholders may experience additional dilution in net book value per share and any additional equity securities may have rights, preferences and privileges senior to those of the holders of our common stock.
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We do not intend to pay dividends in the future.
We have not paid dividends on our common stock and do not intend to pay dividends in the foreseeable future. The payment of cash dividends in the future will be dependent on our revenues and earnings, if any, capital requirements and general financial condition and will be entirely within the discretion of our board of directors at such time. It is the present intention of our board of directors to retain earnings, if any, to fund our future growth, and there is no assurance we will ever pay dividends in the future. As a result, any gain you will realize on our securities will result solely from the appreciation of such securities.
Because we are quoted on the OTC Bulletin Board instead of an exchange or national quotation system, our investors may have more difficulty selling their stock or may experience negative volatility in the market price of our stock.
Our common stock is traded on the OTCBB, which is subject to greater volatility than a national exchange or quotation system. This volatility may be caused by a variety of factors, including the lack of readily available price quotations, the absence of consistent administrative supervision of bid and ask quotations, lower trading volume, and market conditions. Investors in our common stock may experience high fluctuations in the market price and volume of the trading market for our securities. These fluctuations, when they occur, have a negative effect on the market price for our common stock. Accordingly, our stockholders may not be able to realize a fair price from their shares when they determine to sell them or may have to hold them for a substantial period of time until the market for our common stock improves.
Trading in our common stock has been limited, and our stock price could potentially be subject to substantial fluctuations.
Trading in our common stock has been limited. Historically, our stock price has been affected substantially by a relatively modest volume of transactions and could be again so affected. If our stock price falls, our stockholders may not be able to sell their stock when desired or at desirable prices.
The value of our common stock might be affected by matters not related to our own operating performance.
The value of our common stock may be affected by matters that are not related to our operating performance and which are outside of our control. These matters include the following:
| · | general domestic and worldwide economic conditions; |
| · | industry conditions, including fluctuations in the price of oil and natural gas; |
| · | governmental regulation of the oil and natural gas industry, including environmental regulation and regulation of fracture stimulation activities; |
| · | liabilities inherent in oil and natural gas operations; |
| · | geological, technical, drilling and processing problems; |
| · | unanticipated operating events which can reduce production or cause production to be shut in or delayed; |
| · | failure to obtain industry partner and other third party consents and approvals, when required; |
| · | stock market volatility and market valuations; |
| · | competition for, among other things, capital, acquisition of reserves, undeveloped land and skilled personnel; |
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| · | political conditions in oil and natural gas producing regions; |
| · | revenue and operating results failing to meet expectations in any particular period; |
| · | investor perception of the oil and natural gas industry; |
| · | limited trading volume of our common stock; |
| · | announcements relating to our business or the business of our competitors; |
| · | the sale of assets; |
| · | our liquidity; and |
| · | our ability to raise additional funds. |
In the past, companies that have experienced volatility in the trading price of their common stock have been the subject of securities class action litigation. We might become involved in securities class action litigation in the future. Such litigation often results in substantial costs and diversion of management’s attention and resources and could have a material adverse effect on our business, financial condition and results of operation.
Our common stock is subject to penny stock regulation.
Our shares are subject to the provisions of Section 15(g) and Rule 15g-9 of the Exchange Act, commonly referred to as the “penny stock” rule, which set forth certain requirements for transactions in penny stocks. The SEC generally defines penny stock to be any equity security that has a market price less than $5.00 per share, subject to certain exceptions. Rule 3a51-1 provides that any equity security is considered to be penny stock unless that security is: registered and traded on a national securities exchange meeting specified criteria set by the SEC; authorized for quotation on the NASDAQ Stock Market; issued by a registered investment company; excluded from the definition on the basis of price (at least $5.00 per share) or the registrant’s net tangible assets; or exempted from the definition by the SEC. Since our shares are deemed to be “penny stock”, trading in the shares will be subject to additional sales practice requirements on broker-dealers who sell penny stock to persons other than established customers and accredited investors.
FINRA Sales Practice requirements may also limit a stockholder’s ability to buy and sell our stock.
In addition to the “penny stock” rules described above, the Financial Industry Regulatory Authority (“FINRA”) has adopted rules that require that in recommending an investment to a customer, a broker-dealer must have reasonable grounds for believing that the investment is suitable for that customer. Prior to recommending speculative low priced securities to their non-institutional customers, broker-dealers must make reasonable efforts to obtain information about the customer’s financial status, tax status, investment objectives and other information. Under interpretations of these rules, FINRA believes that there is a high probability that speculative low priced securities will not be suitable for at least some customers. FINRA requirements make it more difficult for broker-dealers to recommend that their customers buy our common stock, which may limit your ability to buy and sell our stock and have an adverse effect on the market for our shares.
| Item 1B. | Unresolved Staff Comments |
Not applicable.
| Item 2. | Properties |
Our producing oil and natural gas properties are located in the Permian Basin of Southeastern New Mexico, in Chaves, Eddy, Lea, and Roosevelt counties. We also have significant undeveloped acreage in Chaves, De Baca, Eddy, Grant, Hidalgo, Lea, Sierra, Socorro, and Roosevelt counties.
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Title to Properties
As is customary in the oil and natural gas industry, we generally conduct a preliminary title examination prior to the acquisition of properties or leasehold interests. Prior to commencement of operations on such acreage, a thorough title examination will usually be conducted and any significant defects will be remedied before proceeding with operations. We believe the title to our leasehold properties is good, defensible and customary with practices in the oil and natural gas industry, subject to such exceptions that we believe do not materially detract from the use of such properties. With respect to our properties of which we are not the record owner, we rely instead on contracts with the owner or operator of the property or assignment of leases, pursuant to which, among other things, we generally have the right to have our interest placed on record.
Our properties are generally subject to royalty, overriding royalty and other interests customary in the industry, liens incident to agreements, current taxes and other burdens, minor encumbrances, easements and restrictions. We do not believe any of these burdens will materially interfere with our use of these properties. Substantially all of our material properties are pledged as collateral under our line of credit with Independent Bank.
Summary of Oil and Natural Gas Reserves
Proved Reserves
The following table sets forth our estimated net proved reserves as of December 31, 2013.
| Reserves | |||||||||||||
| Estimated Proved Reserves Data: (1) | Oil / Condensate (MBbls) |
Natural Gas (MMcf) |
Natural Gas Liquids (MBbls) |
Total (MBoe) |
|||||||||
| Proved developed reserves | 804 | 1,853 | 60 | 1,173 | |||||||||
| Proved undeveloped reserves | 726 | 920 | 0 | 879 | |||||||||
| Total proved reserves | 1,530 | 2,773 | 60 | 2,052 | |||||||||
| (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 January 2013 through December 2013. For oil volumes, the average NYMEX posted price of $96.78 per Bbl is adjusted for quality, transportation fees and a regional price differential. For natural gas volumes, the average Henry Hub spot price of $3.67 per Mmbtu is adjusted for energy content, transportation fees and a regional price differential. The adjusted volume-weighted average product prices over the life of the properties are $89.63 per barrel of oil, $28.66 per barrel of NGL, and $5.30 per Mcf of gas. | |
The following table sets forth our estimated PV-10 and standardized measure of discounted net cash flows as of December 31, 2013.
| (in thousands) | As of December 31, 2013 |
|||
| PV-10 (1) | $ | 48,997 | ||
| Standardized measure | $ | 36,281 | ||
| (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:1 | |
| (in thousands) | ||||
| PV-10 | $ | 48,997 | ||
| Future income taxes | (20,243 | ) | ||
| Discount of future income taxes at 10% per annum | 7,527 | |||
| Standardized measure | $ | 36,281 | ||
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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 December 31, 2013, our estimated proved reserves were 2,052 MBoe, an increase of 32.1% compared to 1,554MBoe at December 31, 2012. During fiscal 2013, we added estimated proved reserves of 507 MBoe through field extensions. Revisions to previous estimates increased increased reserves by 162 MBoe. These increases in reserves were offset by production of 170 MBoe. The revisions to previous estimates were primarily due to the revised production curves as a result of additional production history and detailed analysis and updated development plans at Tom Tom.
Proved Undeveloped Reserves
Our proved undeveloped reserves at December 31, 2013 were 879MBoe, consisting of 726MBbl of oil, 0MBbl of NGLs, and 929MMcf of natural gas. During 2013, we converted 135 MBoe of proved undeveloped reserves to proved developed producing reserves, primarily due to the completion of development wells in the Lusk and Turkey Track prospects in the 2nd Bone Springs formation. As of December 31, 2013, estimated future development costs relating to the development of our proved undeveloped reserves was $17.4 million. All of our currently identified proved undeveloped reserves are scheduled to be drilled by December 31, 2016.
Qualifications of Technical Persons and Internal Controls Over Reserves Estimation Process
Our reserve reports were 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 23 years of practical experience in petroleum engineering, with over 20 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.
As indicated elsewhere in this report, we have no full-time employees and instead rely on the availability of internal staff of Red Mountain, the majority holder of our common stock, to assist us in working 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 year-end 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 CG&A reserve report and any internally estimated significant changes to our proved reserves on an annual basis.
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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 13—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, Neal 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.
Summary of Oil and Natural Gas Properties and Projects
Production, Price and Cost History
The following table presents net production sold, average sales prices and production costs and expenses for the years ended December 31, 2013 and 2012.
| Year ended December 31, | ||||||||
| 2013 | 2012 | |||||||
| Revenue | ||||||||
| Oil and natural gas sales | $ | 13,125,960 | $ | 14,781,497 | ||||
| Net production sold | ||||||||
| Oil (Bbl) | 122,666 | 149,600 | ||||||
| Natural gas (Mcf) | 282,864 | 285,885 | ||||||
| Natural gas liquids(Bbl) | 9,223 | 12,287 | ||||||
| Total (Boe) | 179,033 | 209,535 | ||||||
| Average sales prices | ||||||||
| Oil ($/Bbl) | $ | 93.17 | $ | 87.95 | ||||
| Natural gas ($/Mcf | 4.56 | 4.47 | ||||||
| Natural gas liquids ($/Bbl | 28.11 | 28.13 | ||||||
| Total average price ($/Boe) | $ | 73.32 | $ | 70.54 | ||||
| Costs and expenses (per Boe) | ||||||||
| Production taxes | $ | 6.96 | $ | 5.59 | ||||
| Lease operating expenses | 12.85 | 10.89 | ||||||
| Natural gas transportation and marketing expenses | 0.44 | 0.69 | ||||||
| Environmental cleanup | — | 10.02 | ||||||
| Impairment | — | 12.57 | ||||||
| Depreciation, depletion, and amortization | 27.60 | 27.07 | ||||||
| Accretion of discount on asset retirement obligation | 0.83 | 0.45 | ||||||
| General and administrative expense | 6.02 | 13.61 | ||||||
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Developed and Undeveloped Acreage
The following table presents our total gross and net developed and undeveloped acreage as of December 31, 2013:
| Developed Acres | Undeveloped Acres | |||||
| Gross (1) | Net (2) | Gross (1) | Net (2) | |||
| 9,277 | 3,834 | 856,616 | 290,009 | |||
| (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. | |
Our developed leasehold 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. Additionally, we have significant undeveloped acreage which consists of mineral rights and, accordingly, does not expire.
Productive Wells
The following table presents the total gross and net productive wells by oil or natural gas completion as of December 31, 2013. We own royalty interests in 16 gross wells (average of 0.43%), which have been excluded from these well counts:
| Oil Wells | Natural Gas Wells | |||||
| Gross(1) | Net(2) | Gross(1) | Net(2) | |||
| 142 | 53.6 | 40 | 4.4 | |||
| (1) | “Gross” means the total number of wells in which we have a working interest. | |
| (2) | “Net” means the sum of the fractional working interests that we own in gross wells. | |
Drilling Activity
The following table summarizes the number of net productive and dry development wells and net productive and dry exploratory wells we drilled during the periods indicated and refers to the number of wells completed during the period, regardless of when drilling was initiated. At December 31, 2013, we had no wells being drilled or awaiting completion.
| Development Wells | Exploratory Wells | ||||||||||||
| Year Ended December 31, | Productive | Dry | Productive | Dry | |||||||||
| 2013 | 1.88 | — | — | — | |||||||||
| 2012 | 1.91 | — | 0.13 | — | |||||||||
| 2011 | 0.36 | — | 1.17 | — | |||||||||
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| Item 3. | Legal Proceedings |
The information under the heading “ Litigation” contained in Note 9, “Commitments and contingencies,” of our Financial Statements included in Part II, Item 8 of this Form 10-K is incorporated herein by reference.
| 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 OTCBB under the symbol “XBOR.” 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.
| High | Low | |||||||
| Fiscal Year 2013: | ||||||||
| Fourth Quarter | $ | 0.60 | $ | 0.27 | ||||
| Third Quarter | $ | 0.69 | $ | 0.30 | ||||
| Second Quarter | $ | 0.67 | $ | 0.35 | ||||
| First Quarter | $ | 0.90 | $ | 0.63 | ||||
| Fiscal Year 2012: | ||||||||
| Fourth Quarter | $ | 1.25 | $ | 0.86 | ||||
| Third Quarter | $ | 1.62 | $ | 1.10 | ||||
| Second Quarter | $ | 1.99 | $ | 1.50 | ||||
| First Quarter | $ | 2.70 | $ | 1.55 | ||||
Holders
As of March 1, 2014, there were approximately 40 holdersof our common stock, including nominee holders such as bank and brokerage firms who hold shares for beneficial owners.
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. However, our credit agreement with Independent Bank restricts our ability to pay dividends. Accordingly, it is the present intention of the Board of Directors to retain all earnings, if any, for use in the business operations and, accordingly, the Board does not anticipate declaring any dividends in the foreseeable future. The payment of dividends in the future, if any, will be contingent upon restrictions contained in our credit agreement, our revenues and earnings, if any, capital requirements and our general financial condition.
Sales of Unregistered Securities
We have not made any sales of unregistered securities during the year ended December 31, 2013 that was not disclosed previously in a Quarterly Report on Form 10-Q or in a Current Report on Form 8-K.
| Item 6. | Selected Financial Data |
Not applicable.
| Item 7. | Management’s Discussion and Analysis of Financial Condition and Results of Operations |
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and the related notes to those statements included elsewhere in this Annual Report on Form 10-K. In addition to historical financial information, the following discussion and analysis contains forward-looking statements that involve risks, uncertainties and assumptions. Our results and the timing of selected events may differ materially from those anticipated in these forward-looking statements as a result of many factors, including those discussed under “Risk Factors” and elsewhere in this Annual Report on Form 10-K.
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Company
We are an oil and gas exploration company. We currently own over 865,893 gross (approximately 293,843 net) mineral and lease acres in New Mexico and Texas. Approximately 25,000 of these net acres exist within the Permian Basin. A significant majority of our acreage consists of either owned mineral rights or leases held by production, allowing us to hold lease rental payments to under $5,000 annually. The majority of our acreage interests consists of non-operated working interests except for certain core San Andres properties which we operate.
Current development of our acreage is focused on our prospective Bone Spring acreage located in the heart of the 1st and 2nd Bone Spring play. This play encompasses approximately 4,390 square miles across both New Mexico and Texas. We currently own varying, non-operated working interests in both Eddy and Lea Counties, New Mexico, along with our working interest partners that include Cimarex, Apache, Oxy Permian, Occidental, Oxy USA and, Mewbourne; all having significant footprints within this play, and are adding to those footprints through lease and corporate acquisitions.
History
We were originally formed on October 25, 2005 under the name “Language Enterprises Corp.” We subsequently changed our name to Doral Energy Corp. On July 29, 2008, we acquired a working interest in 66 producing oil fields and approximately 186 wells (the “Eddy County Properties”) in and around Eddy County, New Mexico. As a result of our acquisition of the Eddy County Properties, we changed our business focus to the acquisition, exploration, operation and development of oil and gas projects, and we ceased being a “shell company.” On August 4, 2008, we filed our Form 8-K that included the information that would be required if we were filing a general form for registration of securities on Form 10 as a smaller reporting company.
Effective January 3, 2011, we completed the acquisition of Pure Energy Group, Inc. as contemplated pursuant to the Pure Merger Agreement among our company, Doral Sub, Pure L.P. and Pure Sub, a wholly owned subsidiary of Pure L.P. Pursuant to the provisions of the Pure Merger Agreement, all of Pure L.P.’s oil and gas assets and liabilities were transferred to Pure Sub. Pure Sub was then merged with and into Doral Sub, with Doral Sub continuing as the surviving corporation. Upon completion of the Pure Merger, the outstanding shares of Pure Sub were converted into an aggregate of 9,981,536 shares of our common stock. Since the Pure Merger, Pure L.P. has distributed all of its shares of our common stock to the partners of Pure L.P. so that Pure L.P. is no longer a shareholder of our company.
Effective January 4, 2011, following closing of the Pure Merger, Doral Sub was merged with and into our company, with our company continuing as the surviving corporation. Upon completing the merger of Doral Sub with and into our company, we changed our name to “Cross Border Resources, Inc.”
Significant Fiscal 2013 Operations
During 2013, development of our acreage was focused on prospective Bone Spring acreage located in the heart of the play. We currently own varying, non-operated working interests in both Eddy and Lea Counties, New Mexico, along with our working interest partners that include Cimarex, Apache, Oxy Permian, and Mewbourne, all having significant footprints within this play, and are adding to those footprints through lease and corporate acquisitions. We completed 6 gross (0.9 net) horizontal 2nd Bone Spring wells in 2013.
Besides those properties, most of our development was targeting the Glorieta-Yeso reservoirs on the NW Shelf of New Mexico. In total we completed 4 horizontal wells (0.2 net) and 11 vertical wells (0.7 net) in these reservoirs, along with working interest partners Concho, Lime Rock, and Oxy USA. We also completed 1 vertical well (0.1 net) in the Queen-Grayburg-San Andres.
In addition to this development, in 2013, we began work in the Tom Tom/Tomahawk area, where we operate with working interest ranging from 37% to 100%. Several workovers have been performed in the field, and a detailed geologic study was performed and used to update plans for further development in 2014.
Average production in 2013 was 490 Boepd, down from 574 Boepd in 2012. The decrease was due to the slower pace of development on non-operated properties in 2013, which resulted in few high impact wells to offset the natural decline in production.
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Planned Operations
We plan to spend between $6 million and $8 million during fiscal 2014 to drill and complete wells, re-enter and complete wells, or improve infrastructure. Our main area of focus is the Tom Tom/Tomahawk Prospect. For fiscal 2013, this included the re-entry of 11 gross wells (8.2 net), drilling of 3 gross wells (2.6 net), and the improvement of field infrastructure. We will also spend capital in several non-operated prospect areas. Currently, we are committed to participating in the drilling of 14 gross wells (0.5 net) in fiscal 2014.
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 in this Annual Report on Form 10-K. We have identified below policies that are of particular importance to the portrayal of our financial position and results of operations and which require the application of significant judgment by management. These estimates are based on historical experience, information received from third parties, and on various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates under different assumptions or conditions.
We believe the following critical accounting policies affect the significant judgments and estimates used in the preparation of our consolidated financial statements.
Oil and Gas Properties
We follow the successful efforts method of accounting for our oil and natural gas producing activities. 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 December 31, 2013 or 2012. 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 December 31, 2013, 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 advanceof the work commencing. This right to call for cash advances is typically found in the operating agreement that joint interest owners in a property adopt. We record these advance payments in prepaid and other current assets in its property account and release this account when the actual expenditure is later billed to it by the operator.
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On the sale of an entire interest in an unproved property for cash or cash equivalents, gain or loss on the sale is recognized, taking into consideration the amount of any recorded impairment if the property had been assessed individually. If a partial interest in an unproved property is sold, the amount received is treated as a reduction of the cost of the interest retained.
Impairment of Long-Lived Assets
We evaluate our long-lived assets for potential impairment in their carrying values whenever events or changes in circumstances indicate such impairment may have occurred. Oil and natural gas properties are evaluated for potential impairment by field. Other properties are evaluated for impairment on a specific asset basis or in groups of similar assets, as applicable. An impairment on proved properties is recognized when the estimated undiscounted future net cash flows of an asset are less than its carrying value. If an impairment occurs, the carrying value of the impaired asset is reduced to its estimated fair value, which is generally estimated using a discounted cash flow approach. If the results of an assessment indicate that the properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized.
Unproved oil and natural gas properties do not have producing properties. As reserves are proved through the successful completion of exploratory wells, the cost is transferred to proved properties. The cost of the remaining unproved basis is periodically evaluated by management to assess whether the value of a property has diminished. To do this assessment, management considers estimated potential reserves and future net revenues from an independent expert, our history in exploring the area, our future drilling plans per our capital drilling program prepared by our reservoir engineers and operations management and other factors associated with the area. Impairment is taken on the unproved property cost if it is determined that the costs are not likely to be recoverable. The valuation is subjective and requires management to make estimates and assumptions which, with the passage of time, may prove to be materially different from actual results.
In the second quarter of 2012, the Company determined to sell its Wolfberry assets located in Texas. As a result of that decision, management conducted an impairment evaluation of those assets which resulted in a non cash impairment charge of approximately $1,776,000.
Additionally, during the fourth quarter of 2012, management conducted an impairment evaluation of its proved and unproved oil and natural gas properties. As a result of the evaluation, management recorded a non cash impairment charge of approximately $857,945, primarily related to a decline in the value of proved reserves. There were no impairment charges in the year ended December 31, 2013.
Recent Accounting Pronouncements
In May 2011, the FASB issued an accounting pronouncement related to fair value measurement (FASB ASC Topic 820), which amends current guidance to achieve common fair value measurement and disclosure requirements in U.S. GAAP and International Financial Reporting Standards. The amendments generally represent clarification of FASB ASC Topic 820, but also include instances where a particular principle or requirement for measuring fair value or disclosing information about fair value measurements has changed. This pronouncement is effective for fiscal years, and interim periods within those years, beginning after December 15, 2011. We adopted this pronouncement for our fiscal year beginning January 1, 2012 and the adoption of this pronouncement did not have a material effect on our financial statements.
In December 2011, the Financial Accounting Standards Board (“FASB”) issued new standards that require an entity to disclose information about offsetting and related arrangements to enable users of its financial statements to understand the effect of those arrangements on its financial position. The new standards are effective for annual periods beginning on or after January 1, 2013. We adopted this pronouncement for our fiscal year beginning January 1, 2013 and the adoption of this pronouncement did not have a material effect on our financial statements.
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Results of Operations
Year Ended December 31, 2013 Compared to Year Ended December 31, 2012
The following table presents net production sold, average sales prices and production costs and expenses for the years ended December 31, 2013 and 2012.
| Year ended December 31, | ||||||||
| 2013 | 2012 | |||||||
| Revenue | ||||||||
| Oil and natural gas sales | $ | 13,125,960 | $ | 14,781,497 | ||||
| Net production sold | ||||||||
| Oil (Bbl) | 122,666 | 149,600 | ||||||
| Natural gas (Mcf) | 282,864 | 285,885 | ||||||
| Natural gas liquids(Bbl) | 9,223 | 12,287 | ||||||
| Total (Boe) | 179,033 | 209,535 | ||||||
| Average sales prices | ||||||||
| Oil ($/Bbl) | $ | 93.17 | $ | 87.95 | ||||
| Natural gas ($/Mcf | 4.56 | 4.47 | ||||||
| Natural gas liquids ($/Bbl | 28.11 | 28.13 | ||||||
| Total average price ($/Boe) | $ | 73.32 | $ | 70.54 | ||||
| Costs and expenses (per Boe) | ||||||||
| Production taxes | $ | 6.96 | $ | 5.59 | ||||
| Lease operating expenses | 12.85 | 10.89 | ||||||
| Natural gas transportation and marketing expenses | 0.44 | 0.69 | ||||||
| Environmental cleanup | 0.00 | 10.02 | ||||||
| Impairment | 0.00 | 12.57 | ||||||
| Depreciation, depletion, and amortization | 27.60 | 27.07 | ||||||
| Accretion of discount on asset retirement obligation | 0.83 | 0.45 | ||||||
| General and administrative expense | 6.02 | 13.61 | ||||||
(1) Boe/d is calculated based on actual calendar days during the period.
Revenues and Production
Oil and Natural Gas Production.During the year ended December 31, 2013, we had total production sold of 179,033Boe, compared to total production sold of 209,535Boe during the year ended December 31, 2012. The decrease in total production sold was attributable to the natural declines in existing wells. For the year ended December 31, 2013, 68.5% of our production soldwas oil, 26.3% was natural gas, and 5.2% was natural gas liquids, compared to 71.4% oil, 22.7% was natural gas, and 5.9% was natural gas liquidsfor the year ended December 31, 2012.
Oil and Natural Gas Sales.During the year ended December 31, 2013, we had oil and natural gas sales of $13.1 million, as compared to $14.8 million during the year ended December 31, 2012. The decrease in oil and natural gas sales was primarily attributable to the natural declines in existing wells.
Costs and Expenses
Operating Costs. During the year ended December 31, 2013, we incurred operating costs of $2.3 million, as compared to $2.3 million during the year ended December 31, 2012.
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Environmental Cleanup. For the year ended December 31, 2012 we incurred a $2.1 million non-cash charge related to required environmental remediation activities on our Tom Tom / Tomahawk field. There were no such charges in the year ended December 31, 2013.
Impairment. For the year ended December 31, 2012, impairment expense was $2.6 million. There were no impairment charges for the year ended December 31, 2013.
Production Taxes. Production taxes were $1.2 million for the year ended December 31, 2013, as compared to $1.2 million for the year ended December 31, 2012.
Depreciation, Depletion, and Amortization. For the year ended December 31, 2013, depreciation, depletion, and amortization expense was $4.9 million, as compared to $5.7 million for the year ended December 31, 2012. The decrease in depreciation, depletion, and amortization was primarily attributable to lower sales production and a lower rate of depletion in 2013 due to overall higher reserve volumes.
General and Administrative Expense. General and administrative expense was $1 million for the year ended December 31, 2013 as compared to $2.9 million for the year ended December 31, 2012. This reduction is primarily attributable to a decrease in personnel related expenditures of $0.3 million and a decrease in professional fees of $0.4 million. Further, for the period ended December 31, 2012, we incurred approximately $0.9 million in change in control costs while no such expenditures were incurred during the period ended December 31, 2013.
Other Expense.Other expense was $0.1 million for the year ended December 31, 2013 as compared to $0.2 milion for the year ended December 31, 2012. The decrease in other expenses is attributable to an increase in loss on derivatives contracts of approximately $0.9 million offset by a $0.9 million gain on settlement of debt, and an increase in interest expense of approximately $0.1 million.
Liquidity and Capital Resources
General
Our primary sources of liquidity are cash flow from operations and borrowings under our line of credit. Our ability to fund planned capital expenditures and to make acquisitions depends upon our future operating performance, availability of borrowings under our line of credit and availability of equity and debt financing, which is affected by prevailing economic conditions in our industry and financial, business and other factors, some of which are beyond our control. Our cash flow from operations is mainly influenced by the prices we receive for our oil and natural gas production and the quantity of oil and natural gas we produce. Prices for oil and natural gas are affected by national and international economic and political conditions, national and global supply and demand for hydrocarbons, seasonal weather influences and other factors beyond our control.
Capital Expenditures
Most of our capital expenditures are for the exploration, development, and production of oil and natural gas reserves. For 2013, we had capital expenditures of approximately $9.2 million for the development of oil and natural gas properties. We anticipate capital expenditures of between $6.0 million and $8.0 million for 2014. See “—Planned Operations” for more information about our planned capital expenditures.
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Liquidity
At December 31, 2013, we had $0.7 million in cash and cash equivalents and $12.2 million outstanding under our credit facility with Independent Bank. At December 31, 2013, we had $15.2 million of availability under the credit facility. At December 31, 2013, we had a working capital deficit of $0.4 million as compared to a working capital deficit of $3.3 million December 31, 2012.
On February 5, 2013, we entered into a Senior First Lien Secured Credit Agreement with Independent Bank. Our initial draw on the line of credit was $8.9 million which was primarily used to pay off the Texas Capital Bank line of credit principal and accrued interest. On February 28, 2013, we drew another $2.0 million on the line of credit and utilized those funds to pay for capital expenditures associated with our drilling activity.
In February 2013, we settled our creditors liability for $633,975 in cash and by arranging for our largest shareholder, Red Mountain Resources, Inc., to issue the creditors an aggregate of 745,854 shares of its common stock. Further, the holder of the subordinated unsecured debt elected to convert the entire principal and accrued interest balance of the notes into 611,630 shares of our common stock.
Cash Flows
Net cash provided by operating activities was $6.9 million for the year ended December 31, 2013, compared to net cash provided by operating activities of $7.0 million for the year ended December 31, 2012.
Net cash used in investing activities decreased to $9.3 million for the year ended December 31, 2013 from $10.0 million for the year ended December 31, 2012 due to a decrease in capital expenditures for the continued development of our oil and natural gas properties of approximately $3.0 million, offset by the receipt of approximately $2.3 million as proceeds from the sale of some of our oil and natural gas properties which were sold effective August 1, 2012.
During the year ended December 31, 2013, net cash provided by financing activities was $2.8 million, as compared to $2.8 million during the year ended December 31, 2012. Net cash provided by financing activities during the year ended December 31, 2012 was primarily comprised of $12.2 million drawn under our credit facility, offset by repayments of our line of credit of $8.75 million, and repayments to creditors of $0.7 million.
Indebtedness
Notes Payable- Green Shoe
In connection with the merger, the Company, as the accounting acquirer, assumed an unsecured loan from Green Shoe Investments Ltd. (“Green Shoe”) in the principal amount of $487,000 at an interest rate of 5.0%
On April 26, 2011, the Company entered into a Loan Agreement with Green Shoe, and the Company executed and delivered a Promissory Note to Green Shoe in connection therewith. The amount of the Promissory Note and the loan from Green Shoe (the “Green Shoe Loan”) was $550,936 and the purpose of the Green Shoe Loan was to consolidate and extend all of the loans owed by the Company and its predecessors to Green Shoe including without limitation the following: (i) loan dated May 9, 2008 in the principal amount of $100,000, (ii) loan dated May 23, 2008 in the principal amount of $150,000, (iii) loan dated July 18, 2008 in the principal amount of $50,000, (iv) loan dated February 24, 2009 in the principal amount of $100,000, and (v) loan dated April 29, 2009 in the principal amount of $87,000 plus accrued interest of $63,936. The Green Shoe Loan is unsecured.
Beginning March 31, 2011 (the effective date of the Promissory Note), the amounts owed under the Promissory Note began to accrue interest at a rate of 9.99%, and the Promissory Note provided that no payments of principal or interest were due until the maturity date of September 30, 2012. The Company is obligated to pay all accrued interest and make a principal payment equal to one-third of the principal owed upon the closing of an equity offering resulting in a specified amount of net proceeds to the Company. In addition, Green Shoe was granted the right to convert the principal and interest owed into shares of common stock of the Company at a conversion price of $4.00 per share. The principal balance of the note as of September 30, 2012 was $367,309.
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The debt and associated accrued interest were not repaid at maturity on September 30, 2012. On October 22, 2012, the Company received notice from the lender’s counsel that it would be considered in default on the note beginning November 1, 2012 if the note and accrued interest were not paid in full. From November 1, 2012, the note began to accrue interest at the default rate of 18%. On November 30, 2012, Jackson Street Investors, LLC purchased the note from Green Shoe Investments. Subsequently, on December 12, 2012, Red Mountain Resources, Inc. purchased the note from Jackson Street Investors, LLC. As of December 31, 2012, the note had a principal balance of $367,309 and an accrued interest balance of $62,924.
On February 28, 2013, the Company’s Board of Directors approved a resolution to modify the terms of the note so that the conversion price was reduced from $4.00 to $1.50 per share. On February 28, 2013, Red Mountain Resources, Inc. converted the principal balance of $367,309 and accrued interest balance of $73,611 into 293,947 shares of the Company’s common stock.
Notes Payable- Little Bay
In connection with the merger, the Company, as the accounting acquirer, assumed an unsecured loan from Little Bay Consulting SA (“Little Bay”) in the principal amount of $520,000 at an interest rate of 5%.
On April 26, 2011, the Company entered into a Loan Agreement with Little Bay, and the Company executed and delivered a Promissory Note to Little Bay in connection therewith. The amount of the Promissory Note and the loan from Little Bay (the “Little Bay Loan”) was $595,423 and the purpose of the Little Bay Loan was to consolidate and extend all of the loans owed by the Company and its predecessors to Little Bay including without limitation the following: (i) loan dated March 7, 2008 in the original principal amount of $220,000, (ii) loan dated July 18, 2008 in the original principal amount of $100,000, and (iii) loan dated October 3, 2008 in the principal amount of $200,000 plus accrued interest of $75,423. The Little Bay Loan is unsecured.
Beginning March 31, 2011 (the effective date of the Promissory Note), the amounts owed under the Promissory Note began to accrue interest at a rate of 9.99%, and the Promissory Note provided that no payments of principal or interest were due until the maturity date of September 30, 2012. The Company is obligated to pay all accrued interest and make a principal payment equal to one-third of the principal owed upon the closing of an equity offering resulting in a specified amount of net proceeds to the Company. In addition, Little Bay was granted the right to convert the principal and interest owed into shares of common stock of the Company at a conversion price of $4.00 per share. The principal balance of the note as of September 30, 2012 is $396,969.
The debt and associated accrued interest were not repaid at maturity on September 30, 2012. On October 22, 2012, the Company received notice from the lender’s counsel that it would be considered in default on the note beginning November 1, 2012 if the note and accrued interest were not paid in full. From November 1, 2012, the note began to accrue interest at the default rate of 18%. On November 30, 2012, Jackson Street Investors, LLC purchased the note from Little Bay Consulting, S.A. Subsequently, on December 12, 2012, Red Mountain Resources, Inc. purchased the note from Jackson Street Investors, LLC. As of December 31, 2012, the note had a principal balance of $396,969 and an accrued interest balance of $68,005.
On February 28, 2013, the Company’s Board of Directors approved a resolution to modify the terms of the note so that the conversion price was reduced from $4.00 to $1.50 per share. On February 28, 2013, Red Mountain Resources, Inc. converted the principal balance of $396,969 and accrued interest balance of $79,555 into 317,683 shares of the Company’s common stock.
Line of Credit – Texas Capital Bank
As of December 31, 2011, the borrowing base on the Texas Capital Bank (“TCB”) line of credit was $4,500,000. Effective March 1, 2012, the borrowing base was increased to $9,500,000. The interest rate was calculated at the greater of the adjusted base rate or 4%. The line of credit was collateralized by producing wells and was to mature on January 14, 2014. As the result of the sale of certain interests in oil and gas properties, effective August 1, 2012, the borrowing base was reduced by $750,000 and that amount was repaid to TCB out of the sale proceeds.
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As of December 31, 2013 and December 31, 2012, the outstanding balance on the TCB line of credit was $0 and $8,750,000, respectively.
Credit Facility
On February 5, 2013, the Company entered into the Credit Agreement with Red Mountain Resources, Inc., Black Rock Capital, Inc. and RMR Operating, LLC (the Company, Red Mountain Resources, Inc., Black Rock Capital, Inc. and RMR Operating, LLC, jointly and severally, the “Borrowers”) and Independent Bank, as Lender. The Credit Agreement provides for an up to $100.0 million revolving credit facility (as amended, the “Credit Facility”) with an initial commitment of $20.0 million and 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. Effective September 12, 2013, the borrowing base was increased to $30.0 million from $20.0 million. As of December 31, 2013, the borrowing base and commitment were $30.0 million. As of December 31, 2013, the Company had $12.2 million outstanding under the Credit Facility and had availability of $12.6 million.
On, January 21, 2014, March 13, 2014, and March 20, 2014 the Red Mountain Resources, Inc., a co-borrower under the Credit Facility, withdrew $5.0 million, $1.0 million, and $3.0 million, respectively, under the Credit Facility with Independent Bank. As of April 14, 2014, the Company had availability of $6.2 million under the Credit Facility.
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. As of December 31, 2013, the interest rate was 4%. 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.
The Credit Agreement also contains financial covenants, measured as of the last day of each fiscal quarter of the Company. As of December 31, 2013, the Company was in compliance with these covenants.
Pursuant to the Credit Agreement, at least one of the Borrowers is required to have acceptable hedge agreements in place at all times effectively hedging at least 50% of the oil volumes of the Borrowers. Pursuant to the terms of the Credit Agreement, the Company has hedge agreements with BP Energy hedging a portion of the future oil production of the Borrowers.
Contractual Obligations
The following table presents a summary of our contractual obligations at December 31, 2013:
| Payments Due By Period | ||||||||||||||||||||
| (in thousands) | Less than one year |
One to three years |
Three to five years |
More than five years |
Total | |||||||||||||||
| Line of credit | $ | — | $ | 12,200,000 | $ | — | $ | — | $ | 12,200,000 | ||||||||||
| Environmental cleanup | 1,400,000 | 687,973 | — | — | 2,087,973 | |||||||||||||||
| Asset retirement obligations | 561,708 | 1,476,304 | 191,197 | 1,285,689 | 3,514,898 | |||||||||||||||
| Total | $ | 1,961,708 | $ | 14,364,277 | $ | 191,197 | $ | 1,285,689 | $ | 17,802,871 | ||||||||||
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Off-Balance Sheet Arrangements
As of December 31, 2013, we did not have any off-balance sheet arrangements as defined by Regulation S-K.
| Item 7A. | Quantitative and Qualitative Disclosures About Market Risk |
Not applicable.
| 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 May 31, 2012 and, based on that evaluation, and as a result of the material weaknesses described below, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were not effective at the reasonable assurance level.
Management’s Report on Internal Control Over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act. Internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of our financial statements for external purposes in accordance with GAAP. Internal control over financial reporting includes policies and procedures that: (i) pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of our assets; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of our financial statements in accordance with GAAP, and that our receipts and expenditures are being made only in accordance with the authorizations of our management and board of directors and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on our financial statements.
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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 December 31, 2013 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 December 31, 2013 because of the identification of the material weaknesses identified below.
A material weakness (as defined in Rule 12b-2 under the Exchange Act) is a deficiency, or combination of deficiencies, in internal control over financial reporting such that there is a reasonable possibility that a material misstatement in our annual or interim financial statements will not be prevented or detected on a timely basis. During the course of our assessment, management identified the following material weaknesses:
| • | lack of accounting expertise to appropriately apply GAAP for complex or non-recurring transactions; and |
| • | lack of sufficient accounting personnel to properly design and implement internal control over financial reporting. |
This Annual Report on Form 10-K does not include an attestation report of our independent registered public accounting firm regarding internal control over financial reporting as such report is not required for non-accelerated filers.
Management’s Plan for Remediation of Our Material Weaknesses
Management will continue to review and assess our system of internal control over financial reporting as well as the new members of our accounting staff and their increased levels of accounting expertise. During this review and assessment, we will continue to implement enhancements to our system of internal controls where appropriate. Finally, we will continue to evaluate the employees and contractors involved in the preparation of our financial statements, the need to engage outside consultants with accounting and tax expertise to assist us in accounting for complex transactions and the hiring of additional accounting staff as necessary to timely prepare our financial statements. Management currently believes it will be able to remedy the material weaknesses described above over the next 12 months.
Changes in Internal Control Over Financial Reporting
There have been no changes in our internal control over financial reporting that occurred during our last fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
| Item 9B. | Other Information |
None.
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| Item 10. | Directors, Executive Officers and Corporate Governance |
Directors and Executive Officers
Our current directors and executive officers are as follows:
|
Name |
Age |
Position | ||
| Alan W. Barksdale | 37 | Chairman of the Board of Directors | ||
| Earl M. Sebring | 64 | Interim President | ||
| Kenneth S. Lamb | 38 | Chief Accounting Officer, Secretary, and Treasurer | ||
| Richard F. LaRoche Jr. | 59 | Director | ||
| Paul N. Vassilakos | 36 | Director | ||
| John W. Hawkins | 62 | Director |
Alan W. Barksdale has been Chairman of the Board of Directors since May 2012. Mr. Barksdale has been the Chief Executive Officer and Chairman of the Board of Directors of Red Mountain Resources, Inc. since June 2011, its President since July 2012, and served as its Interim Acting Chief Financial Officer from June 2011 to August 2011. Mr. Barksdale has also been the owner and president of StoneStreet and president and manager of StoneStreet Group, advisory and management services and merchant banking firms, since 2008. Mr. Barksdale has also been the president of AWB Enterprises, Inc., a holding company, since November 2011. From January 2004 to April 2010, Mr. Barksdale served as a director in the Capital Markets Group of Crews & Associates, an investment banking firm. From August 2003 to October 2003, Mr. Barksdale served as an investment banker at Stephens Inc., an investment banking firm. From 2002 to 2003, Mr. Barksdale was an investment banker at Crews & Associates. Mr. Barksdale’s experience in operating, managing, financing and investing in more than 100 wells in Louisiana, New Mexico and Texas, combined with his over ten years of capital markets experience and contacts and relationships, provides our Board of Directors with invaluable management and operational direction.
In 2004, the National Association of Securities Dealers, Inc. (“NASD”) alleged that Mr. Barksdale solicited an attorney to make contributions to officials of an issuer with which Stephens Inc. was engaging in municipal securities business when Mr. Barksdale was employed as an investment banker of Stephens Inc. Without admitting or denying the allegations, Mr. Barksdale entered into an acceptance, waiver and consent decree that provided for a 30-day suspension from associating with any NASD member and a $5,000 fine.
Earl M. Sebringhas been our Interim President since June 2012. Mr. Sebring is an exploration geologist with 35 years of experience. Since August 2000, Mr. Sebring has been the owner and President of Sebring Exploration Texas, Inc., an independent exploration company. In 1982, Mr. Sebring became an exploration geologist for Wagner and Brown, eventually becoming Exploration Manager. As Exploration Manager, Mr. Sebring was responsible for handling all foreign and domestic exploration and production efforts. This included directing exploration efforts, staffing those efforts as required, and securing outside industry funding. Mr. Sebring began his career at City Service Oil Company in 1976 where his responsibilities included ascertaining petroleum commercial prospectivity in frontier basins around the world through the use of core, log, geochemical, and out crop data. Mr. Sebring has been involved in drilling, managing, consulting or investing in locations such as the Permian Basin, Gulf Coast, Oklahoma, Southern France, Southern United Kingdom, Argentina, Columbia, Kodiak Shelf of Alaska, Philippines, Southern Australia, Louisiana, New Mexico, Oklahoma and Athabasca Tar Sands. Mr. Sebring graduated from the University of Texas in 1976, where he received a Bachelor's Degree in Geology.
Kenneth S. Lamb has been our Chief Accounting Officer, Secretary, and Treasurer since August 2012. Mr. Lamb has significant experience in corporate accounting, financial reporting, and corporate governance. From December 2008 until May 2011, he was employed by Transatlantic Petroleum, Ltd., an international oil and gas company engaged in the acquisition, exploration, development, and production of crude oil and natural gas, serving as its Director of Internal Audit from December 2008 to July 2010 and its Manager of Financial Reporting and Internal Controls from August 2010 to May 2011. From July 2007 until November 2008, Mr. Lamb was employed with the Brink's Company, a company providing security-related services for banks, retailers and other commercial and governmental customers, as Internal Audit Supervisor where he managed financial audits in numerous different countries. Mr. Lamb began his career with PricewaterhouseCoopers in 2000 and worked for KPMG from 2005 to 2006. He received a B.B.A. in Accounting and a B.A. in History from Sam Houston State University and is a licensed Certified Public Accountant.
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Richard F. LaRoche Jrwas appointed as a director of the Company effective January 3, 2011, upon closing of the Pure Merger. Mr. LaRoche served 27 years with National HealthCare Corporation (“NHC”) as Secretary and General Counsel and 14 years as Senior Vice President, retiring from these positions in May 2002. He has served as a Board member of NHC since 2002. Mr. LaRoche serves as a director of Lodge Manufacturing Company (privately held). He also served on the boards of National Health Investors, Inc. from 1991 through 2008, National Health Realty, Inc. from 1998 through 2007 and Trinsic, Inc. from 2004 through 2006. Mr. LaRoche continues to serve on NHC’s Board of Directors and on that Board’s Audit Committee, Nominating and Corporate Governance Committee and Compensation Committee.
He has a law degree from Vanderbilt University (1970) and an A.B. degree from Dartmouth College (1967).
Mr. LaRoche brings significant experience to this Board. He has served as both an independent board member to a large publicly-held company and acted as general counsel to that company. The Company sought a director who could provide leadership as the Company developed its policies and procedures, and Mr. LaRoche has provided that direction and leadership. Mr. LaRoche’s legal and board experience were the primary factors considered in connection with his election to the Board.
Paul N. Vassilakos has been a director since May 2012. 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. Since November 2013, Mr. Vassilakos has been the Chief Executive Officer of Cullen Agricultural Holding Corp. (“CAH”) and served as its assistant treasurer from October 2009 to November 2013. CAH is a development stage company which was formed in connection with the business combination between Triplecrown Acquisition Corp. and Cullen Agricultural Technologies, Inc. in October 2009. In July 2007, Mr. Vassilakos founded Petrina Advisors, Inc., a privately held advisory firm providing investment banking services, and has served as its president since its formation. Mr. Vassilakos also founded and, since December 2006, serves as the vice president of Petrina Properties Ltd., a privately held real estate holding company. From February 2002 through June 2007, Mr. Vassilakos served as vice president of Elmsford Furniture Corp., a privately held furniture retailer in the New York area. Mr. Vassilakos brings extensive public company and capital markets experience, as well as his professional contacts and experience, to our Board of Directors.
John W. Hawkinswas appointed as a director of the Company effective January 3, 2011, effective upon closing of the Pure Merger. Mr. Hawkins has over 30 years experience in management and accounting for NYSE listed companies. He previously served as interim CFO of Pure L.P. and Aztec Energy Partners. In 2002, he retired as VP-Treasurer of Dillard Department Stores after 28 years of service. As VP-Treasurer of Dillard’s, he managed the treasury department, assisted with the annual audits, managed payroll department, tax department, accounts payable department, worker’s compensation and general liability department, and the employee benefits department. He was one of the 401(k) and pension plan administrators. He was heavily involved in the acquisition of 16 companies totaling approximately $2.5 billion in revenue. Mr. Hawkins received a BBA with a major in accounting from Midwestern University. Mr. Hawkins qualifies as an audit committee financial expert. In addition, his experience with publicly traded companies and his historical knowledge of the Pure operations and assets prior to the Pure merger were significant factors that led to his election to the Board. Mr. Hawkins has served on the board of directors of the Self Insurance Institute of America, Ronald McDonald House of Little Rock, Texas,Self Insured Association, and as chairman of the advisory board of Certergy Inc.
Audit Committee
The primary functions of the Audit Committee are to assist the Board of Directors of the Company in fulfilling its oversight responsibilities with respect to: (i) the Company’s systems of internal controls regarding finance, accounting, legal compliance and ethical behavior; (ii) the Company’s auditing, accounting and financial reporting processes generally; (iii) the Company’s financial statements and other financial information provided by the Company to its stockholders, the public and others; (iv) the Company’s compliance with legal and regulatory requirements; and (v) the performance of the Company’s corporate audit department and independent auditors. Consistent with these functions, the Committee will encourage continuous improvement of, and foster adherence to, the Company’s policies, procedures and practices at all levels.
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The members of the Audit Committee are not full-time employees of the Company and may or may not be accountants or auditors by profession or experts in the fields of accounting or auditing and, in any event, do not serve in such capacity. Consequently, it is not the duty of the Committee to conduct audits or to determine that the Company’s financial statements and disclosures are complete and accurate and are in accordance with generally accepted accounting principles and applicable rules and regulations.
The members of the Audit Committee are John W. Hawkins, Paul N. Vassilakos and Richard F. LaRoche, Jr. John W. Hawkins serves as chair of the Audit Committee and the Board has determined that he qualifies as an audit committee financial expert. Mr. Hawkins is independent as such term as defined by both NASDAQ Marketplace Rule 5605 and SEC Rule 10A-3(b)(1). The Audit Committee meets at least four times per year (on a quarterly basis). As part of its job to foster open communications, the Audit Committee does meet in separate executive sessions without management and the Company’s independent auditors to discuss any matters that the Audit Committee believes should be discussed privately.
The charter of the Audit Committee is available on the Investor Relations section of the Company’s website (www.xbres.com) by clicking “Investor Relations” and then “Corporate Governance.”
Nominating and Corporate Governance Committee
The purpose of the Nominating and Corporate Governance Committee is to provide assistance to the Board of Directors in identifying and recommending candidates qualified to serve as directors of the Company, to review the composition of the Board of Directors, to develop, review and recommend governance policies and principles for the Company and to review periodically the performance of the Board of Directors.
The Nominating and Corporate Governance Committee considers candidates for Board membership suggested by its members and other Board members as well as management and stockholders. The Nominating and Corporate Governance Committee among many factors, considers qualities of high personal and professional ethics, values and integrity It also examines the skills, diversity, backgrounds and experience with business and other organizations of director nominees. Also, the Nominating and Corporate Governance Committee looks for candidates with the ability and willingness to commit adequate time to, as well as a commitment to representing the long-term interests of Cross Border.
The members of the Nominating and Corporate Governance Committee are John W. Hawkins, Paul N. Vassilakos, and Richard F. LaRoche, Jr. Mr. LaRoche serves as chair of the Nominating and Corporate Governance Committee. The Nominating and Corporate Governance Committee meets at least annually.
The charter of the Nominating and Corporate Governance Committee is available on the Investor Relations section of the Company’s website (www.xbres.com) by clicking “Investor Relations” and then “Corporate Governance.”
The Nominating and Corporate Governance Committee has adopted the following procedures by which security holders may recommend nominees to the Company’s board of directors(as well as presenting shareholder proposals for consideration by the shareholders at the next annual meeting):
The Nominating and Corporate Governance Committee will consider all nominees and shareholder proposals presented to it in writing provided that such nominees and proposals are received by the Committee no later than the first day of the fourth quarter (October 1) of the Company’s fiscal year for consideration for nomination by the Nominating and Corporate Governance Committee at the following annual shareholders’ meeting to be held in or around May of the following year. Written requests should be sent to the Company’s address to the attention of the Chair of the Nominating and Corporate Governance Committee.
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Compensation Committee
The purpose of the Compensation Committee of the Board of Directors is to discharge the responsibilities of the Board relating to compensation of the Company’s executive officers and to review and approve senior officers’ compensation.
Under the Charter of the Compensation Committee, the Compensation Committee is required to meet at least annually and more frequently as necessary or appropriate. Special meetings of the Committee may be called on two hours notice by the Chairman of the Board or the Committee Chairman. A majority of the Committee constitutes a quorum and the Committee may act only on the affirmative vote of a majority of the members present at the meeting.
The members of the Compensation Committee are John W. Hawkins, Paul N. Vassilakos, and Richard F. LaRoche, Jr. Mr. Vassilakos serves as chair of the Compensation Committee.
The charter of the Compensation Committee is available on the Investor Relations section of the Company’s website (www.xbres.com) by clicking “Investor Relations” and then “Corporate Governance.”
Code of Ethics
In connection with the Pure Merger, we adopted a Code of Business Conduct and Ethics applicable to all of our employees and directors, including our principal executive officer and principal financial officer, which is a “code of ethics” as defined by applicable rules of the SEC. A copy of the Company’s Code of Ethics can be found on the Company’s website, under the Investor Relations- Corporate Governance tabs (http://xbres.investorroom.com/corp-governance).
If we make any amendments to our Code of Ethics other than technical, administrative, or other non-substantive amendments, or grant any waivers, including implicit waivers, from a provision of our Code of Ethics to our principal executive officer and principal financial officer, or certain other finance executives, we will disclose the nature of the amendment or waiver, its effective date and to whom it applies in a Current Report on Form 8-K filed with the SEC.
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16(a) of the Exchange Act (“Section 16(a)”) requires our executive officers and directors, and persons who beneficially own more than 10% of our equity securities, to file reports of ownership and changes in ownership with the SEC. Based solely on our review of Forms 3, 4 and 5 furnished to us as required under the rules of the Exchange Act, we have no knowledge of any failure to report on a timely basis any transaction required to be disclosed under Section 16(a).
| Item 11. | Executive Compensation |
The following table sets forth information concerning compensation of our Named Executive Officers for the years ended December 31, 2012 and 2013. The Named Executive Officers are: our Interim President and our Chief Accounting Officer, Secretary, and Treasurer.
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Summary Compensation Table
| Name and Principal Position |
Year Ended | Salary ($) |
Bonus ($) |
Stock Awards ($) |
All Other Compensation ($) |
Total ($) |
|||||||||||||
| Earl M. Sebring | December 31, 2013 | 200,000 | — | — | — | 200,000 | |||||||||||||
| Interim President | December 31, 2012 | 125,000 | — | — | — | 125,000 | |||||||||||||
| Kenneth S. Lamb (1) | December 31, 2013 | — | — | — | 20,000 | 20,000 | |||||||||||||
| Chief Accounting Officer, Secretary, and Treasurer | December 31, 2012 | — | — | — | 57,695 | 57,695 | |||||||||||||
| (1) | Mr. Lamb is an employee of Red Mountain Resources, the Company’s largest shareholder, and receives no direct remuneration from the Company. The Company reimburses Red Mountain Resources for a portion of Mr. Lamb’s salary, upon request. In 2013, the Company reimbursed $20,000 while in 2012 the Company reimbursed $57,695 to Red Mountain Resources. Such amounts are reported as all other compensation in the table above. | |
Employment Agreements
Nature of Services Provided by Earl Sebring and Kenneth Lamb
Neither Mr. Sebring nor Mr. Lamb are employees of the Company. Their services as officers of the Company can be terminated at any time by the Board of Directors. The Company pays Mr. Sebring $16,667 per month for his services as Interim President. The Company reimburses Red Mountain Resources, Inc. (the Company’s largest shareholder) for Mr. Lamb’s services as Chief Accounting Officer, Secretary, and Treasurer, upon request from Red Mountain Resources. Mr. Lamb is an employee of Red Mountain Resources, Inc., and serves as Red Mountain Resources, Inc.’s Controller.
Indemnification Agreements
The Company has indemnificatieon agreements with each of its directors and officers. These agreements, among other things, require the Company to indemnify each director and officer to the fullest extent permitted by applicable law, against any and all expenses of a proceeding, in the event that such person was, is or becomes a party to or witness or other participant in such proceeding by reason of such person’s service as a member of the Company’s board of directors or as an officer.
Director Compensation
Our Board of Directors approved a compensation program for non-employee directors, as follows:
| · | Each non-employee director receives an annual cash fee of $8,000; |
| · | Each non-employee director receives a cash fee of $500 for each telephonic meeting of the Board and committee that such director participates in; |
| · | Each non-employee director receives a cash fee of $1,500 for each in person meeting of the Board and committee that such director participates in; and |
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| · | Each non-employee director receives a cash fee of $500 for each in person meeting held with management that such director participates in. |
All directors are reimbursed for their costs incurred in attending meetings of the Board of Directors or of the committees on which they serve. Members of our Board of Directors are appointed to hold office until the next annual meeting of our stockholders or until his or her successor is elected and qualified, or until he or she resigns or is removed in accordance with the provisions of the Nevada Revised Statutes.
Director Compensation Table
The table below reflects compensation paid to non-employee directors for the year endedDecember 31, 2013.
| Name | Fees Earned or Paid in Cash ($) | |
| Alan W. Barksdale | 10,500 | |
| Paul N. Vassilakos | 10,500 | |
| John W. Hawkins | 12,000 | |
| Richard F. LaRoche Jr | 11,500 | |
| Randell K. Ford | 10,500 |
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 April 15, 2014 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.
| Name and Address of Beneficial Owner (1) | Amount of Beneficial Ownership (2) | Percentage of Outstanding Common Stock (2) |
|||||
| Alan W. Barksdale | — | — | |||||
| Richard F. LaRoche, Jr. | 838,331 | (3) | 4.8 | % | |||
| John W. Hawkins | — | — | * | ||||
| Paul N. Vassilakos | — | — | |||||
| Earl M. Sebring | — | — | |||||
| Kenneth S. Lamb | — | — | |||||
| All executive officers and directors as a group (6 persons) | 848,331 | 4.8 | % | ||||
| Red Mountain Resources, Inc. and Subsidiaries | 16,830,598 | (4) | 84.8 | % | |||
| 2515 McKinney Ave, Suite 900 | |||||||
| Dallas, TX 75201 | |||||||
| * | Less than one percent. | |
| (1) | Unless noted otherwise, the address for the above individuals is 2515 McKinney Ave., Suite 900, Dallas, Texas 75201. Unless noted otherwise, each of the above persons has sole voting and investment power with respect to all shares of common stock beneficially owned by them. |
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| (2) | Based on 17,336,226 shares of common stock issued and outstanding on December 31, 2013.
|
| (3) | Mr. LaRoche is deemed the beneficial owner of 838,331 Shares, or 4.8% of the Issuer’s outstanding common stock, which ownership includes: (i) 94,984 Shares held by LaRoche Family, L.P., of which Mr. LaRoche is a general partner; (ii) 485,013 Shares held by LaRoche Enterprises, L.P., of which Mr. LaRoche is a general partner; (iii) 100,000 Shares held by Bushy Forest L.P.; of which Mr. LaRoche is a general partner; (iv) warrants to purchase 133,334 Shares held by LaRoche Enterprises, L.P, of which Mr. LaRoche is general partner; and (v) stock options to purchase 25,000 Shares held by Mr. LaRoche. As general partner of LaRoche Family, L.P., LaRoche Enterprises, L.P. and Bushy Forest, L.P., Mr. LaRoche has sole power to vote and to dispose of the Shares; accordingly, he is deemed to have beneficial ownership over such shares. However, Mr. LaRoche disclaims beneficial ownership of Shares held by the limited partnerships except to the extent of his pecuniary interest therein.
|
| (4) | Based on Amendment No. 14 to Schedule 13D filed on May 6, 2013, each of Red Mountain Resources, Inc. and Alan Barksdale is deemed to be the beneficial owner of 16,830,598 shares of the Issuer’s Common Stock, or approximately 84.8% of the Issuer’s outstanding Common Stock. This represents 14,327,767 shares of Common Stock held by Red MountainResolurces, Inc. This also includes: (i) warrants to purchase 366,667 shares of Common Stock held by Red Mountain Resources, Inc. and (ii) warrants to purchase 2,136,164 shares of Common Stock of the Issuer held by Black Rock Capital, Inc., all of which are immediately exercisable. Barksdale is the Chief Executive Officer of Red Mountain Resources, Inc. and an officer of Black Rock Capital, Inc. As such, Alan Barksdale has the authority to vote the shares of Common Stock on behalf of Red Mountain Resources, Inc. and Black Rock Capital, Inc.Black Rock Capital, Inc. is deemed to be the beneficial owner of 2,136,164 shares of the Issuer’s Common Stock, or approximately 11.0% of the Issuer’s outstanding Common Stock. This represents immediately exercisable warrants to purchase 2,136,134 shares of Common Stock held by Black Rock Capital, Inc. |
Equity Compensation Plans
Effective April 29, 2009, our Board of Directors adopted our 2009 Stock Incentive Plan (the “2009 Plan”). The purpose of the 2009 Plan is to enhance our long-term stockholder value by offering opportunities to our directors, officers, employees and eligible consultants (“Participants”) to acquire and maintain stock ownership in us in order to give these persons the opportunity to participate in our growth and success, and to encourage them to remain in our service.
The 2009 Plan allows us to grant awards to our officers, directors and employees. In addition, we may grant awards to individuals who act as consultants to us, so long as those consultants do not provide services connected to the offer or sale of our securities in capital raising transactions and do not directly or indirectly promote or maintain a market for our securities.
On adoption, a total of 8,500,000 shares of our common stock were available for issuance under the 2009 Plan. Effective July 28, 2010, we amended and restated our 2009 Plan to increase the total number of shares authorized for issuance under the 2009 Plan to 14,500,000 shares. However, under the terms of the 2009 Plan, at any time after August 1, 2010, the authorized number of shares available under the 2009 Plan may be increased by our Board of Directors, provided that the total number of shares issuable under the 2009 Plan cannot exceed 15% of the total number of shares of common stock outstanding.
Awards may be granted in the form of options to purchase shares of our common stock (“Option Awards”) or in the form of shares of our common stock (“Stock Awards”). Option Awards granted under the 2009 Plan may be made in the form of incentive stock options and non-qualified stock options. Incentive stock options granted under the 2009 Plan are those intended to qualify as “incentive stock options” as defined under Section 422 of the Internal Revenue Code. However, in order to qualify as “incentive stock options” under Section 422 of the Internal Revenue Code, the 2009 Plan must be approved by our stockholders within 12 months of its adoption. The 2009 Plan has not been approved by our stockholders and there is no assurance that the 2009 Plan will be approved by our stockholders. Non-qualified stock options granted under the 2009 Plan are Option Awards that do not qualify as incentive stock options under Section 422 of the Internal Revenue Code. Stock Awards may be made subject to such terms, conditions and restrictions as the plan administrator may, in its sole discretion, decide, including transfer restrictions and vesting provisions. On May 26, 2009, we filed a Registration Statement on Form S-8 (Registration Number 333-159480) under the Securities Act of 1933, as amended (the “Securities Act”), to register 8,500,000 shares of our common stock available for issuance under the 2009 Plan.
| 56 |
On August 10, 2010, we filed a Registration Statement on Form S-8 (Registration Number 333-168724) under the Securities Act to register an additional 6,000,000 shares of our common stock available for issuance under the 2009 Plan as amended and restated. The total registered shares available for issuance under the 2009 Plan was reduced to 263,636 shares by the 1-for-55 reverse split effective December 27, 2010. The 2009 Plan expressly provides that the number of shares may be increased to the number of shares issued under the 2009 Plan provided that it does not exceed 15% of the outstanding shares. The total number of shares underlying currently outstanding options issued under the Plan is 87,500.
The following table sets forth certain information concerning all equity compensation plans previously approved by stockholders and all previous equity compensation plans not previously approved by stockholders, as of the most recently completed fiscal year.
| 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 Issuance Under Equity Compensation Plans (Excluding Securities Reflected in column (a)) (c) | |||||||||
| Equity compensation plans approved by security holders | — | — | — | |||||||||
| Equity compensation plans not approved by security holders | 87,500 | $ | 4.80 | 2,357,792 | ||||||||
| Total | 87,500 | $ | 4.80 | 2,357,792 | ||||||||
| (1) | The total number of securities available for issuance under the plan cannot exceed 15% of the total number of shares of common stock outstanding. Therefore, as of April 1, 2013, the number of securities remaining available is 15% of 16,301,946 (2,445,292) less outstanding options (87,500). | |
| Item 13. | Certain Relationships and Related Transactions, and Director Independence |
Certain Relationships and Related Transactions
The Company paid $163,000 for consulting fees in the year ended December 31, 2011, respectively to BDR Consulting, Inc. (BDR), a member of CCJ/BDR Investments, L.L.C., who owned a combined 64.108% limited partnership interest in the Pure Gas Partners, L.P. The president of BDR also served on the Board of Directors and was the Chief Executive Officer of Pure Energy Group, Inc.
| 57 |
On April 11, 2012, the Company advanced its then Chief Executive Officer, E. Willard Gray, II, $119,575 related to the change in control provisions in Mr. Gray's employment agreement. At June 30, 2012, $42,070 remained outstanding (shown as Accounts receivable - related party on the Balance Sheet), which was deducted from the second change of control payment to him from the Company in July 2012.
During the year ended December 31, 2012, Red Mountain Resources, Inc. incurred approximately $628,274 for general and administrative expenses and operating costs that will be reimbursed by the Company for accounting services and attendance of certain of the Company’s directors and officers at the Company’s annual meeting of stockholders and for costs associated with workovers on three of the Company’s salt water disposal wells, of which $215,495 remained unpaid at December 31, 2012. The expenditures pertaining to the operating costs were incurred pursuant to a technical services agreement between the Company and Red Mountain Resources, Inc.
The Company paid $720 and $91,633 for consulting fees and expense reimbursements for the years ended December 31, 2012 and 2011, respectively to Sebring Exploration Texas, Inc., an entity owned by Earl M. Sebring, the Company’s Interim President.
Independence of Directors
The standards relied upon the Board in determining whether a director is “independent” are those set forth in the rules of the NYSE MKT LLC (formerly, NYSE Amex). The NYSE MKT LLC generally defines “independent directors” as a person other than an executive officer or employee of a company, who does not have a relationship with the company that would interfere with the director’s exercise of independent judgment in carrying out the responsibilities of a director. Consistent with these standards, our Board of Directors has affirmatively determined that Messrs. Hawkins,LaRoche, and Vassilakos are our independent directors.
| Item 14. | Principal Accountant Fees And Services |
Aggregate fees for professional services provided to us by Darilek, Butler & Associates, PLLC, our principal accountant for the years endedDecember 31, 2013and 2012 were as follows:
| Year endedDecember 31, | |||||||
| 2013 | 2012 | ||||||
| Audit Fees(a) | $ | 205,100 | $ | 103,100 | |||
| Audit-Related Fees(b) | 84,000 | 8,475 | |||||
| Tax Fees(c) | — | 11,487 | |||||
| All Other Fees | — | — | |||||
| Total | $ | 289,100 | $ | 123,062 | |||
| (a) | Audit services billed consisted of the audits of our annual financial statementsand reviews of our quarterly condensed financial statements. | |
| (b) | Audit-related fees includes professional services in connection with procedures related to various other audit and special reports. | |
| (c) | Tax fees include tax compliance and tax planning. | |
Audit Committee Approval
The Company’s board of directors 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 the Company’s board of directors approves the engagement letter with respect to audit, tax and review services. Other fees are subject to pre-approval by the audit committee. The audit, audit-related fees and tax fees paid to Darilek Butler & Associates, PLLC with respect to 2013 and 2012 were pre-approved by the audit committee.
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| 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 | |
| Balance Sheets as of December 31, 2013 and 2012 | ||
| Statements of Operations for the Years Ended December 31, 2013 and 2012 | ||
| Statements of Stockholders’ Equity for the Years Ended December 31, 2013 and 2012 | ||
| Statements of Cash Flows for the Years Ended December 31, 2013 and 2012 | ||
| Notes to Financial Statements | ||
| 2. | Exhibits required to be filed by Item 601 of Regulation S-K | |
| The exhibits required to be filed by this Item 15 are set forth in the Exhibit Index accompanying this report. | ||
| 59 |
Cross Border Resources, Inc.
| December 31, | December 31, | |||||||
| 2013 | 2012 | |||||||
| ASSETS | ||||||||
| Current Assets | ||||||||
| Cash and Cash Equivalents | $ | 726,239 | $ | 241,561 | ||||
| Accounts Receivable – Oil and Natural Gas Sales | 2,086,239 | 3,194,725 | ||||||
| Accounts Receivable – Related Party | 24,630 | — | ||||||
| Prepaid Expenses & Other Current Assets | 87,443 | 465,223 | ||||||
| Derivative Asset - Current Portion | — | 235,825 | ||||||
| Current Tax Asset | 19,600 | 21,737 | ||||||
| Total Current Assets | 2,944,151 | 4,159,071 | ||||||
| Oil and Gas Properties | 56,561,040 | 48,248,378 | ||||||
| Less: Accumulated Depletion, Amortization, and Impairment | (20,941,867) | (16,018,892 | ) | |||||
| Net Oil and Gas Properties | 35,619,173 | 32,229,486 | ||||||
| Other Assets | ||||||||
| Other Property and Equipment, net of Accumulated Depreciation of $95,828 and $77,190 in 2013 and 2012, respectively | 34,641 | 53,280 | ||||||
| Restricted Cash | 206,087 | — | ||||||
| Deferred financing costs, net of accumulated amortization of $19,242 and $113,581 in 2013 and 2012, respectively | 91,242 | 101,045 | ||||||
| Derivative Asset, net of Current Portion | — | 54,963 | ||||||
| Other Assets | 54,324 | 54,324 | ||||||
| Total Other Assets | 386,294 | 263,612 | ||||||
| TOTAL ASSETS | $ | 38,949,618 | $ | 36,652,169 | ||||
The accompanying notes are an integral part of these financial statements.
| F-1 |
| December 31, | December 31, | |||||||
| 2013 | 2012 | |||||||
| LIABILITIES AND STOCKHOLDERS’ EQUITY | ||||||||
| Current Liabilities | ||||||||
| Accounts Payable - Trade | $ | 1,268,257 | $ | 4,226,547 | ||||
| Accounts Payable – Related Party | — | 215,495 | ||||||
| Interest Payable | — | 130,929 | ||||||
| Accrued Expenses & Other Payables | 63,101 | 61,065 | ||||||
| Notes Payable Related Party - Current | — | 764,278 | ||||||
| Creditors Payable - Current Portion | — | 758,167 | ||||||
| Derivative Liability | 38,109 | — | ||||||
| Environmental Liability – Current Portion | 1,400,000 | 860,000 | ||||||
| Asset Retirement Obligation – Current Portion | 562,000 | 452,013 | ||||||
| Deferred Tax Liability | 19,600 | 21,737 | ||||||
| Total Current Liabilities | 3,351,067 | 7,490,231 | ||||||
| Non-Current Liabilities | ||||||||
| Asset Retirement Obligations | 2,952,898 | 2,865,345 | ||||||
| Deferred Income Tax Liability | — | — | ||||||
| Environmental Liability, Net of Current Portion | 687,973 | 1,240,000 | ||||||
| Line of Credit | 12,200,000 | 8,750,000 | ||||||
| Creditors Payable, Net of Current Portion | — | 594,616 | ||||||
| Total Non-Current Liabilities | 15,840,871 | 13,449,961 | ||||||
| Total Liabilities | 19,191,938 | 20,940,192 | ||||||
| Commitments & Contingencies (Note 9) | ||||||||
| Stockholders’ Equity | ||||||||
| Common Stock ($0.001 par value; 99,000,000 shares authorized and 17,336,226 issued and outstanding as of December 31, 2013 and 16,301,946 as of December 31, 2012) | 17,336 | 16,302 | ||||||
| Additional Paid in Capital | 33,462,473 | 32,770,540 | ||||||
| Accumulated Deficit | (13,722,129 | ) | (17,074,865 | ) | ||||
| Total Stockholders’ Equity | 19,757,680 | 15,711,977 | ||||||
| TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY | $ | 38,949,618 | $ | 36,652,169 | ||||
The accompanying notes are an integral part of these financial statements.
| F-2 |
Cross Border Resources, Inc.
| Twelve Months Ended December 31, | |||||||
| 2013 | 2012 | ||||||
| Revenues | |||||||
| Oil and gas sales | $ | 13,125,960 | $ | 14,781,497 | |||
| Expenses: | |||||||
| Operating costs | 2,300,899 | 2,281,443 | |||||
| Environmental cleanup | — | 2,100,000 | |||||
| Natural gas marketing and transportation expenses | 78,211 | 143,672 | |||||
| Production taxes | 1,246,153 | 1,171,474 | |||||
| Depreciation and depletion | 4,941,614 | 5,671,202 | |||||
| Impairment of oil & gas properties | — | 2,633,742 | |||||
| Loss on sale of oil and gas properties | — | — | |||||
| Accretion expense | 148,364 | 94,556 | |||||
| General and administrative | 1,007,065 | 2,851,003 | |||||
| Total expense | 9,722,306 | 16,947,092 | |||||
| Gain (loss) from operations | 3,403,654 | (2,165,595 | ) | ||||
| Other income (expense): | |||||||
| Gain (loss) on derivatives | (269,769 | ) | 575,086 | ||||
| Gain on settlement of debt | 858,429 | — | |||||
| Bond issuance amortization | — | (218,631) | |||||
| Interest expense | (639,578 | ) | (547,066 | ) | |||
| Miscellaneous other income (expense) | — | (3,089) | |||||
| Total other income (expense) | (50,918 | ) | (193,700) | ||||
| Income (loss) before income taxes | 3,352,736 | (2,359,295) | |||||
| Current tax benefit | (— | ) | (—) | ||||
| Deferred tax expense | — | — | |||||
| Income tax expense | — | (—) | |||||
| Net income (loss) | $ | 3,352,736 | $ | (2,359,295) | |||
| Net income (loss) per share: | |||||||
| Basic | $ | 0.20 | $ | (0.15) | |||
| Diluted | $ | 0.16 | $ | (0.15) | |||
| Weighted average shares outstanding: | |||||||
| Basic | 17,169,041 | 16,173,316 | |||||
| Diluted | 20,856,541 | 16,173,316 | |||||
The accompanying notes are an integral part of these financial statements.
| F-3 |
Cross Border Resources, Inc.
| Twelve Months Ended December 31, | ||||||||
| 2013 | 2012 | |||||||
| CASH FLOWS FROM OPERATING ACTIVITIES | ||||||||
| Net income | $ | 3,352,736 | $ | (2,359,295 | ) | |||
| Adjustments to reconcile net income (loss) to cash used by operating activities: | ||||||||
| Depreciation, depletion, and impairment | 4,941,614 | 8,304,944 | ||||||
| Gain on Settlement of Creditors Liability | (350,800 | ) | — | |||||
| Gain on Conversion of Notes | (485,416 | ) | — | |||||
| Settlement of environmental liability | (12,027 | ) | — | |||||
| Accretion of asset retirement obligations | 148,364 | 94,556 | ||||||
| (Gain) loss on disposition of assets | — | |||||||
| Amortization of and deferred financing costs | 9,803 | 218,631 | ||||||
| Change in derivative instruments | 328,897 | (375,782 | ) | |||||
| Changes in operating assets and liabilities: | ||||||||
| Accounts receivable | 1,083,856 | (2,010,181 | ) | |||||
| Prepaid expenses and other current assets | 375,666 | 1,343,721 | ||||||
| Accounts payable | (2,245,392 | ) | 112,713 | |||||
| Accounts payable – related party | — | — | ||||||
| Restricted Cash | (206,087 | ) | — | |||||
| Accrued expenses | 7,527 | (413,746 | ) | |||||
| Derivative asset/liability | — | — | ||||||
| Deferred income tax | — | — | ||||||
| Environmental liability | — | 2,100,000 | ||||||
| Deferred revenue | — | (32,479 | ) | |||||
| Interest payable | — | 18,270 | ||||||
| NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES | 6,948,741 | 7,001,352 | ||||||
| CASH FLOWS USED IN INVESTING ACTIVITIES | ||||||||
| Capital expenditures - oil and gas properties | (9,253,152 | ) | (12,233,698 | ) | ||||
| Proceeds from disposal of oil and gas properties | — | 2,250,000 | ||||||
| Capital expenditures - other assets | — | — | ||||||
| NET CASH USED IN INVESTING ACTIVITIES | (9,253,152 | ) | (9,983,698 | ) | ||||
| CASH FLOWS FROM FINANCING ACTIVITIES | ||||||||
| Proceeds from issuance of common stock, net of expenses | — | — | ||||||
| Borrowings on line of credit | 12,200,000 | 7,119,000 | ||||||
| Payments on line of credit | (8,750,000 | ) | (750,000 | ) | ||||
| Deferred financing costs | — | (36,299 | ) | |||||
| Repayments of bonds | — | (3,395,000 | ) | |||||
| Repayments to creditors | (660,911 | ) | (186,761 | ) | ||||
| NET CASH PROVIDED BY FINANCING ACTIVITIES | 2,789,089 | 2,750,940 | ||||||
| NET DECREASE IN CASH AND CASH EQUIVALENTS | 484,678 | (231,406 | ) | |||||
| Cash and cash equivalents, beginning of period | 241,561 | 472,967 | ||||||
| Cash and cash equivalents, end of period | $ | 726,239 | $ | 241,561 | ||||
| Supplemental disclosures of cash flow information: | ||||||||
| Interest paid | $ | 518,756 | $ | 269,501 | ||||
| Income taxes paid | $ | — | $ | — | ||||
| Issuance of common stock to settle liabilities | $ | (692,967 | ) | $ | — | |||
| Additions of ARO | $ | 51,290 | $ | 383,481 | ||||
The accompanying notes are an integral part of these financial statements.
| F-4 |
Cross Border Resources, Inc.
Statements of Equity
For the years ended December 31, 2013 and 2012
Common Stock | ||||||||||||||||||||
Shares | Amount | Additional Paid-in Capital | Accumulated Deficit | Total | ||||||||||||||||
| Balance at December 31, 2011 | 16,151,946 | 16,152 | 32,617,690 | $ | (14,715,570 | ) | $ | 17,918,272 | ||||||||||||
| Issuance of shares to settle change of control liability with former CEO | 150,000 | 150 | 152,850 | — | 153,000 | |||||||||||||||
| Net loss attributable to shareholders | — | — | — | (2,359,295 | ) | (2,359,295 | ) | |||||||||||||
| Balance at December 31, 2012 | 16,301,946 | 16,302 | 32,770,540 | (17,074,865 | ) | 15,711,977 | ||||||||||||||
| Issuance of shares to Red Mountain Resources, Inc. upon conversion of unsecured liabilities | 611,630 | 612 | 409,180 | — | 409,792 | |||||||||||||||
| Issuance of shares to settle creditors payable claims | 422,650 | 422 | 282,753 | — | 283,176 | |||||||||||||||
| Net income attributable to shareholders | — | — | — | 3,352,736 | 3,352,736 | |||||||||||||||
| Balance at December 31, 2013 | 17,336,226 | 17,336 | 33,462,473 | (13,722,129 | ) | 19,757,681 | ||||||||||||||
| F-5 |
Cross Border Resources, Inc.
1. Organization
Nature of Operations
The Company is an independent natural gas and oil company engaged in the exploration, development, exploitation, and acquisition of natural gas and oil reserves in North America. The Company’s primary area of focus is the State of New Mexico, particularly southeastern New Mexico. The Company has two wholly-owned subsidiaries, which are inactive: Doral West Corporation and Pure Energy Operating, Inc, and accordingly are not consolidated in these financial statements.
2. Summary of Significant Accounting Policies
Reclassification
Certain amounts have been reclassified to conform to the current period presentation. The amounts reclassified did not have an effect on the Company’s results of operations or stockholders’ equity.
Cash and cash equivalents
The Company considers all highly liquid debt instruments purchased with an original maturity of three months or less to be cash equivalents. At times, the amount of cash and cash equivalents on deposit in financial institutions exceeds federally insured limits. The Company monitors the soundness of the financial institutions and believes the Company’s risk is negligible.
Concentrations of Credit Risk
All of our receivables are due from crude oil and natural gas purchasers. The Company sold approximately 78% of our crude oil and natural gas production to 5 customers during the year ended December 31, 2013. The Company believes that there are potential alternative purchasers and that it may be necessary to establish relationships with new purchasers. However, there can be no assurance that the Company can establish such relationships and that those relationships will result in an increased number of purchasers. Although the Company is exposed to credit risk, the Company believes that all of its purchasers are credit worthy. The Company had no bad debt for the years ended December 31, 2013 and 2012.
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 December 31, 2013 and December 31, 2012.
Oil and natural gas properties
The Company follows the successful efforts method of accounting for its oil and natural gas producing activities. 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 December 31, 2012 or December 31, 2013. 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 December 31, 2013, 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-6 |
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 and release this account when the actual expenditure is later billed to it by the operator.
On the sale of an entire interest in an unproved property for cash or cash equivalents, gain or loss on the sale is recognized, taking into consideration the amount of any recorded impairment if the property had been assessed individually. If a partial interest in an unproved property is sold, the amount received is treated as a reduction of the cost of the interest retained.
Impairment of long-lived assets
The Company evaluates its long-lived assets for potential impairment in their carrying values whenever events or changes in circumstances indicate such impairment may have occurred. Oil and natural gas properties are evaluated for potential impairment by field. Other properties are evaluated for impairment on a specific asset basis or in groups of similar assets, as applicable. An impairment on proved properties is recognized when the estimated undiscounted future net cash flows of an asset are less than its carrying value. If an impairment occurs, the carrying value of the impaired asset is reduced to its estimated fair value, which is generally estimated using a discounted cash flow approach. If the results of an assessment indicate that the properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized.
Unproved oil and natural gas properties do not have producing properties. As reserves are proved through the successful completion of exploratory wells, the cost is transferred to proved properties. The cost of the remaining unproved basis is periodically evaluated by management to assess whether the value of a property has diminished. To do this assessment, management considers estimated potential reserves and future net revenues from an independent expert, the Company’s history in exploring the area, the Company’s future drilling plans per its capital drilling program prepared by the Company’s reservoir engineers and operations management and other factors associated with the area. Impairment is taken on the unproved property cost if it is determined that the costs are not likely to be recoverable. The valuation is subjective and requires management to make estimates and assumptions which, with the passage of time, may prove to be materially different from actual results.
Revenue and accounts receivable
The Company recognizes revenue for its production when the quantities are delivered to, or collected by, the purchaser. Prices for such production are generally defined in sales contracts and are readily determinable based on certain publicly available indices. All transportation costs are included in lease operating expense.
Accounts receivable—oil and natural gas sales consist of uncollateralized accrued revenues due under normal trade terms, generally requiring payment within 30 to 60 days of production. Accounts receivable—other consist of amounts owed from interest owners of the Company’s operated wells. No interest is charged on past-due balances. Payments made on all accounts receivable are applied to the earliest unpaid items. The Company reviews accounts receivable periodically and reduces the carrying amount by a valuation allowance that reflects its best estimate of the amount that may not be collectible. There was no reserve for bad debts as of December 31, 2013 or December 31, 2012.
| F-7 |
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 and New Mexico. When tax returns are filed, it is highly certain that some positions taken would be sustained upon examination by the taxing authorities, while others are subject to uncertainty about the merits of the position taken or the amount of the position that would be ultimately sustained. The benefit of a tax position is recognized in the financial statements in the period during which, based on all available evidence, management believes it is more likely than not that the position will be sustained upon examination, including the resolution of appeals or litigation processes, if any. Tax positions taken are not offset or aggregated with other positions. Tax positions that meet the more-likely-than-not recognition threshold are measured as the largest amount of tax benefit that is more than 50% likely of being realized upon settlement with the applicable taxing authority. The portion of the benefits associated with tax positions taken that exceeds the amount measured as described above is reflected as a liability for unrecognized tax benefits in the accompanying balance sheet along with any associated interest and penalties that would be payable to the taxing authorities upon examination. Interest and penalties associated with unrecognized tax benefits are classified as additional income taxes in the Company’s Consolidated Statements of Operations. The Company accrues interest and penalties, if any, related to unrecognized tax benefits as a component of income tax expense.
Deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to the differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using the tax rate in effect for the year in 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.
Share-based compensation
The Company measures and records compensation expense for all share-based payment awards to employees and outside directors based on estimated grant date fair values. The Company recognizes compensation costs for awards granted over the requisite service period based on the grant date fair value.
| F-8 |
Business combinations
We follow ASC 805, Business Combinations (“ASC 805”), and ASC 810-10-65, Consolidation (“ASC 810-10-65”). ASC 805 requires most identifiable assets, liabilities, non-controlling interests, and goodwill acquired in a business combination to be recorded at “fair value.” The statement applies to all business combinations, including combinations among mutual entities and combinations by contract alone. Under ASC 805, all business combinations will be accounted for by applying the acquisition method. Accordingly, transaction costs related to acquisitions are to be recorded as a reduction of earnings in the period they are incurred and costs related to issuing debt or equity securities that are related to the transaction will continue to be recognized in accordance with other applicable rules under U.S. GAAP. ASC 810-10-65 requires non-controlling interests to be treated as a separate component of equity, not as a liability or other item outside of permanent equity. The statement applies to the accounting for non-controlling interests and transactions with non-controlling interest holders in consolidated financial statements.
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.
Recently issued accounting pronouncements
In May 2011, the FASB issued an accounting pronouncement related to fair value measurement (FASB ASC Topic 820), which amends current guidance to achieve common fair value measurement and disclosure requirements in U.S. GAAP and International Financial Reporting Standards. The amendments generally represent clarification of FASB ASC Topic 820, but also include instances where a particular principle or requirement for measuring fair value or disclosing information about fair value measurements has changed. This pronouncement is effective for fiscal years, and interim periods within those years, beginning after December 15, 2011. We adopted this pronouncement for our fiscal year beginning January 1, 2012 and the adoption of this pronouncement did not have a material effect on our consolidated financial statements.
In December 2011, the Financial Accounting Standards Board (“FASB”) issued new standards that require an entity to disclose information about offsetting and related arrangements to enable users of its financial statements to understand the effect of those arrangements on its financial position. The new standards are effective for annual periods beginning on or after January 1, 2013. We are currently evaluating the provisions of the new standards and assessing the impact, if any, it may have on our financial position and results of operations.
| F-9 |
3 – Asset retirement obligations
The following is a description of the changes to the Company’s asset retirement obligations for the periods ended December 31, 2013 and December 31, 2012:
| December 31, | December 31, | |||||||
| 2013 | 2012 | |||||||
| Asset retirement obligations at beginning of year | $ | 3,317,358 | $ | 1,186,260 | ||||
| Disposal of assets | — | (88,650 | ) | |||||
| Settlement of liabilities | (1,284 | ) | (55,915 | ) | ||||
| Revision of previous estimates | — | 1,797,626 | ||||||
| Accretion expense | 148,364 | 94,556 | ||||||
| Additions | 51,290 | 383,481 | ||||||
| Asset retirement obligations at end of period | $ | 3,515,728 | $ | 3,317,358 | ||||
| Less: current portion | 562,000 | 452,013 | ||||||
| Long-term portion | $ | 2,952,898 | $ | 2,865,345 | ||||
4 – 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:
| December 31, | December 31, | ||||||
| 2013 | 2012 | ||||||
| Oil and natural gas properties | $ | 56,561,040 | $ | 48,248,378 | |||
| Less accumulated depletion and impairment | (20,941,867 | ) | (16,018,892 | ) | |||
| Net oil and natural gas properties capitalized costs | $ | 35,619,173 | $ | 32,229,486 | |||
Capitalized costs related to proved oil and natural gas properties, including wells and related equipment and facilities, are evaluated for impairment based on the Company’s analysis of undiscounted future net cash flows. If undiscounted future net cash flows are insufficient to recover the net capitalized costs related to proved properties, then the Company recognizes an impairment charge in income equal to the difference between carrying value and the estimated fair value of the properties. Estimated fair values are determined using discounted cash flow models. The discounted cash flow models include management’s estimates of future oil and natural gas production, operating and development costs, and discount rates.
Uncertainties affect the recoverability of these costs as the recovery of the costs outlined above are dependent upon the Company obtaining and maintaining leases and achieving commercial production or sale.
Other property and equipment
The historical cost of other property and equipment, presented on a gross basis with accumulated depreciation is summarized as follows:
| December 31, | December 31, | ||||||
| 2013 | 2012 | ||||||
| Other property and equipment | $ | 130,470 | $ | 130,470 | |||
| Less accumulated depreciation | (95,828 | ) | (77,190 | ) | |||
| Net property and equipment | $ | 34,641 | $ | 53,280 | |||
| F-10 |
5 – Stockholders’ equity and earnings per share
2011 Equity Financing
On May 26, 2011, the Company closed a private offering exempt from registration under the Securities Act of 1933 pursuant to Rule 506 of Regulation D promulgated thereunder. In the offering, the Company issued an aggregate of 3,600,000 units. Each unit was sold at $1.50 and was comprised of one share of common stock and one five-year warrant to purchase a share of common stock at an exercise price of $2.25 per share. The warrants became exercisable on November 26, 2011. The Company agreed to use the net proceeds from the sale of the units for general business and working capital purposes and not to use such proceeds for the redemption of any common stock or common stock equivalents.
The investors in the offering (“Selling Stockholders”) received registration rights. The Company agreed to file a registration statement covering the resale of the common stock issued and the common stock underlying the warrants issued to the Selling Stockholders within sixty days after the closing date. If the registration statement was not declared effective by the SEC within the time periods defined within the agreement, then the Company would have made pro rata cash payments to each Selling Stockholder as liquidated damages in an amount equal to 1.0% of the aggregate amount invested by such Selling Stockholder for each 30-day period or pro rata for any portion thereof following the date by which such Registration Statement should have been effective. If at the time of exercise of the warrants there is no effective registration statement covering the resale of the shares underlying the warrant, then the Selling Stockholders have the right at such time to exercise warrants in full or in part on a cashless basis. The Company filed an S-1 registration statement registering the shares on July 25, 2011, which was declared effective on August 5, 2011.
In addition to registration rights, the Selling Stockholders were offered a right of first refusal to participate in future offerings of common stock if the principal purpose of which was to raise capital. This right of first refusal terminated upon the one-year anniversary of the closing date.
Warrants
In connection with the equity offering closed on May 26, 2011, the Company issued warrants to purchase an aggregate of 3,125,000 shares of the Company’s common stock at a per share price of $2.25 (the "$2.25 Warrants"). The Company also issued warrants to purchase 3,600,000 shares of the Company’s common stock at a per share price of $5.00. The $2.25 Warrants became exercisable in November 2011 and expire in November 2015. On the date of issuance, the warrants were valued at $898,384. Management determined the fair value of the warrants based upon the Black-Scholes option model with a volatility based on the historical closing price of common stock of industry peers and the closing price of the Company’s common stock on the OTCBB on the date of issuance. The volatility and remaining term was 50% and 1.92 years, respectively. The Company does not expect the immediate exercise of these warrants as the exercise price exceeds the average closing market price for the Company's common stock. Furthermore, no assurances can be made that any of the warrants will ever be exercised for cash or at all.
Issuance of Shares to Former Executive
On November 7, 2012, the Company issued 150,000 shares of its common stock to Everett Willard Gray II, in full satisfaction of any remaining amounts owed to Mr. Gray by the Company pursuant to Mr. Gray’s employment agreement with the Company, dated as of January 31, 2011 and amended as of March 6, 2012 and April 20, 2012 (as amended, the “Employment Agreement”). Mr. Gray resigned as the Company’s Chairman and Chief Executive Officer effective May 31, 2012 in connection with the transactions described in the Company’s Current Report on Form 8-K filed on April 24, 2012. The Employment Agreement provided for him to receive severance payments of $478,298, payable in installments, of which $239,149 remained to be paid, which was satisfied by the issuance of the 150,000 shares.
| F-11 |
Stock Options
In 2011, the Company issued options to purchase 85,000 shares of its common stock at $4.80 to its directors. For the years ended December 31 2013 and December 31, 2012, there was no stock based compensation.
Stock option activity summary is presented in the table below:
| Weighted- | |||||||||
| average | |||||||||
| Weighted- | Remaining | ||||||||
| average | Contractual | ||||||||
| Number of | Exercise | Term | |||||||
| Shares | Price | (years) | |||||||
| Outstanding and exercisable at December 31, 2011 | 87,500 | $ | 4.80 | 5.08 | |||||
| Granted | — | — | — | ||||||
| Cancelled | — | — | — | ||||||
| Exercised | — | — | — | ||||||
| Forfeited | — | — | — | ||||||
| Expired | — | — | — | ||||||
| Outstanding and exercisable at December 31, 2012 | 87,500 | 4.80 | 4.08 | ||||||
| Granted | — | — | — | ||||||
| Cancelled | — | — | — | ||||||
| Exercised | — | — | — | ||||||
| Forfeited | — | — | — | ||||||
| Expired | — | — | — | ||||||
| Outstanding and exercisable at December 31, 2013 | 87,500 | $ | 4.80 | 3.08 |
There is no intrinsic value in the outstanding options since the option price is in excess of the market price of the Company's common stock.
The fair value of the options granted during 2011 was estimated at the date of grant using the Black-Scholes option-pricing model with the following assumptions:
| Closing market price of stock on grant date | $ | 3.11 | |
| Risk-free interest rate | 2.43 | % | |
| Dividend yield | 0.00 | % | |
| Volatility factor | 50 | % | |
| Expected life | 2.5 years |
The Company elected to use the “simplified” method to calculate the estimated life of options granted to employees. The use of the “simplified” method has been extended until such time when the Company has sufficient information to make more refined estimates on the estimated life of our options. The expected stock price volatility was calculated by averaging the historical volatility of the Company’s common stock over a term equal to the expected life of the options.
Issuance of Common Shares to Settle Creditors Payable
As described in Note 8, the Company entered into settlement agreements with two of the creditors payable arising out of the 2002 bankruptcy. The Company paid the creditors $633,975 in cash and the Company’s largest shareholder, Red Mountain Resources, Inc. (“Red Mountain”), issued approximately 750,000 shares of its common stock to the creditors in settlement of the claims. In return for Red Mountain issuing its shares to the creditors payable, the Company issued Red Mountain 422,650 shares of its common stock.
Conversion of Notes Payable
On February 28, 2013, Red Mountain, the holder of the Green Shoe and Little Bay notes, elected to convert the outstanding notes and accrued interest into common shares. The board of directors of the Company had previously resolved to change the conversion feature from $4.00 per common share to $1.50 per common share. As a result, the Company issued 611,630 common shares to Red Mountain.
| F-12 |
6 – Related party transactions
During the year ended December 31, 2012, Red Mountain incurred approximately $628,274 for general and administrative expenses and operating costs that will be reimbursed by the Company for accounting services and attendance of certain of the Company’s directors and officers at the Company’s annual meeting of stockholders and for costs associated with workovers on three of the Company’s salt water disposal wells, of which $215,495 remained unpaid at December 31, 2012. The expenditures pertaining to the operating costs were incurred pursuant to a technical services agreement between the Company and Red Mountain.
During the year ended December 31, 2013, Red Mountain incurred approximately $3,000,000 of such expenditures, all of which was repaid at December 31, 2013.
7 – Long term debt
Notes Payable Green Shoe Investments – Related Party
In connection with the January 2011 merger, the Company, as the accounting acquirer, assumed an unsecured loan from Green Shoe Investments Ltd. (“Green Shoe”) in the principal amount of $487,000 at an interest rate of 5.0%
On April 26, 2011, the Company entered into a Loan Agreement with Green Shoe, and the Company executed and delivered a Promissory Note to Green Shoe in connection therewith. The amount of the Promissory Note and the loan from Green Shoe (the “Green Shoe Loan”) was $550,936 and the purpose of the Green Shoe Loan was to consolidate and extend all of the loans owed by the Company and its predecessors to Green Shoe including without limitation the following: (i) loan dated May 9, 2008 in the principal amount of $100,000, (ii) loan dated May 23, 2008 in the principal amount of $150,000, (iii) loan dated July 18, 2008 in the principal amount of $50,000, (iv) loan dated February 24, 2009 in the principal amount of $100,000, and (v) loan dated April 29, 2009 in the principal amount of $87,000 plus accrued interest of $63,936. The Green Shoe Loan was unsecured.
Beginning March 31, 2011 (the effective date of the Promissory Note), the amounts owed under the Promissory Note began to accrue interest at a rate of 9.99%, and the Promissory Note provided that no payments of principal or interest were due until the maturity date of September 30, 2012. The Company is obligated to pay all accrued interest and make a principal payment equal to one-third of the principal owed upon the closing of an equity offering resulting in a specified amount of net proceeds to the Company. In addition, Green Shoe was granted the right to convert the principal and interest owed into shares of common stock of the Company at a conversion price of $4.00 per share. The principal balance of the note as of September 30, 2012 was $367,309.
The debt and associated accrued interest were not repaid at maturity on September 30, 2012. On October 22, 2012, the Company received notice from the lender’s counsel that it would be considered in default on the note beginning November 1, 2012 if the note and accrued interest were not paid in full. From November 1, 2012, the note began to accrue interest at the default rate of 18%. On November 30, 2012, Jackson Street Investors, LLC purchased the note from Green Shoe Investments. Subsequently, on December 12, 2012, Red Mountain purchased the note from Jackson Street Investors, LLC. As of December 31, 2012, the note had a principal balance of $367,309 and an accrued interest balance of $62,924.
On February 28, 2013, the Company’s Board of Directors approved a resolution to modify the terms of the note so that the conversion price was reduced from $4.00 to $1.50 per share. On February 28, 2013, Red Mountain converted the principal balance of $367,309 and accrued interest balance of $73,611 into 293,947 shares of the Company’s common stock.
| F-13 |
Notes Payable Little Bay Consulting – Related Party
In connection with the January 2011 merger, the Company, as the accounting acquirer, assumed an unsecured loan from Little Bay Consulting SA (“Little Bay”) in the principal amount of $520,000 at an interest rate of 5%.
On April 26, 2011, the Company entered into a Loan Agreement with Little Bay, and the Company executed and delivered a Promissory Note to Little Bay in connection therewith. The amount of the Promissory Note and the loan from Little Bay (the “Little Bay Loan”) was $595,423 and the purpose of the Little Bay Loan was to consolidate and extend all of the loans owed by the Company and its predecessors to Little Bay including without limitation the following: (i) loan dated March 7, 2008 in the original principal amount of $220,000, (ii) loan dated July 18, 2008 in the original principal amount of $100,000, and (iii) loan dated October 3, 2008 in the principal amount of $200,000 plus accrued interest of $75,423. The Little Bay Loan was unsecured.
Beginning March 31, 2011 (the effective date of the Promissory Note), the amounts owed under the Promissory Note began to accrue interest at a rate of 9.99%, and the Promissory Note provided that no payments of principal or interest were due until the maturity date of September 30, 2012. The Company is obligated to pay all accrued interest and make a principal payment equal to one-third of the principal owed upon the closing of an equity offering resulting in a specified amount of net proceeds to the Company. In addition, Little Bay was granted the right to convert the principal and interest owed into shares of common stock of the Company at a conversion price of $4.00 per share. The principal balance of the note as of September 30, 2012 is $396,969.
The debt and associated accrued interest were not repaid at maturity on September 30, 2012. On October 22, 2012, the Company received notice from the lender’s counsel that it would be considered in default on the note beginning November 1, 2012 if the note and accrued interest were not paid in full. From November 1, 2012, the note began to accrue interest at the default rate of 18%. On November 30, 2012, Jackson Street Investors, LLC purchased the note from Little Bay Consulting, S.A. Subsequently, on December 12, 2012, Red Mountain purchased the note from Jackson Street Investors, LLC. As of December 31, 2012, the note had a principal balance of $396,969 and an accrued interest balance of $68,005.
On February 28, 2013, the Company’s Board of Directors approved a resolution to modify the terms of the note so that the conversion price was reduced from $4.00 to $1.50 per share. On February 28, 2013, Red Mountain converted the principal balance of $396,969 and accrued interest balance of $79,555 into 317,683 shares of the Company’s common stock.
Line of Credit – Texas Capital Bank
As of December 31, 2011, the borrowing base on the Texas Capital Bank (“TCB”) line of credit was $4,500,000. Effective March 1, 2012, the borrowing base was increased to $9,500,000. The interest rate was calculated at the greater of the adjusted base rate or 4%. The line of credit was collateralized by producing wells and was to mature on January 14, 2014. As the result of the sale of certain interests in oil and gas properties, effective August 1, 2012, the borrowing base was reduced by $750,000 and that amount was repaid to TCB out of the sale proceeds.
As of December 31, 2013 and December 31, 2012, the outstanding balance on the TCB line of credit was $0 and $8,750,000, respectively.
Credit Facility
On February 5, 2013, the Company entered into the Credit Agreement with Red Mountain, Black Rock Capital, Inc. and RMR Operating, LLC (the Company, Red Mountain, Black Rock Capital, Inc. and RMR Operating, LLC, jointly and severally, the “Borrowers”) and Independent Bank, as Lender. The Credit Agreement provides for an up to $100.0 million revolving credit facility (as amended, the “Credit Facility”) with an initial commitment of $20.0 million and 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. Effective September 12, 2013, the borrowing base was increased to $30.0 million from $20.0 million. As of December 31, 2013, the borrowing base and commitment were $30.0 million. As of December 31, 2013, the Company had $12.2 million outstanding under the Credit Facility and had availability of $15.2 million.
| F-14 |
On, January 21, 2014, March 13, 2014 and March 20, 2014, Red Mountain, withdrew $5.0 million, $1.0 million, and $3.0 million, respectively, under the Credit Facility with Independent Bank. As of April 15, 2014, the Company had availability of $6.2 million under the Credit Facility.
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. As of December 31, 2013, the interest rate was 4%. 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.
The Credit Agreement also contains financial covenants, measured as of the last day of each fiscal quarter of the Company. As of December 31, 2013, the Company was in compliance with these covenants.
Pursuant to the Credit Agreement, at least one of the Borrowers is required to have acceptable hedge agreements in place at all times effectively hedging at least 50% of the oil volumes of the Borrowers. Pursuant to the terms of the Credit Agreement, the Company has hedge agreements with BP Energy hedging a portion of the future oil production of the Borrowers.
8 – Creditors payable
In 2002, the prior owner of Pure Sub filed a petition for reorganization with the United States Bankruptcy Court. According to the plan of reorganization, three creditors were to receive a combined amount of approximately $3,000,000 for their claims out of future net revenues of Pure Sub (defined as revenues from producing wells net of lease operating expenses and other direct costs).
On February 28, 2013, the Company entered into settlement agreements with two of the creditors. Under the agreement, one creditor with a balance of $608,727 as of December 31, 2012 was paid $304,363 in cash and the Company arranged for Red Mountain to issue the creditor 358,075 shares of Red Mountain’s common stock. The other creditor with a balance of $659,224 as of December 31, 2012 was paid $329,612 and the Company arranged for Red Mountain to issue the creditor 387,779 shares of Red Mountain’s common stock.
9 – 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 the Company, made false representations which induced Mr. Bloodworth to enter into an employment contract that was subsequently breached by the Company. The claims that Mr. Bloodworth has alleged are: breach of his employment agreement with Doral, 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 the Company deny that Mr. Bloodworth’s claims have any merit.
| F-15 |
The Company 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 the Company’s Board of Directors in connection with a possible "Transaction" (as defined in the Engagement Letter). The Engagement Letter was formally terminated by the Company 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 the Company in the amount of $751,334, representing amounts purportedly owed by the Company to KeyBanc as a result of the consummation of a purported Transaction KeyBanc asserts had been consummated within the required time period and its out-of-pocket expenses in connection therewith. The Company disputes that any Transaction was consummated and that KeyBanc is entitled to any out-of-pocket expenses. The matter was originally filed by the Company in the 44th-B 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 where Key Banc filed a counter claim against the Company. The Company and Key Banc have each filed motions for summary judgement, requesting the Court to rule in their respective Favors. The Company intends to vigorously defend the action.
Environmental Contingencies
The Company is subject to federal and state laws and regulations relating to the protection of the environment. Environmental risk is inherent to 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 December 31, 2013, the Company had $2,087,973 in environmental liabilities related to its operated Tom Tom Tomahawk field located in Chaves and Roosevelt counties in New Mexico. In February 2013, the Bureau of Land Management (“BLM”) accepted the Company’s remediation plan for the Tom Tom and Tomahawk fields. The Company 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. The Company expects to incur these expenditures over a eighteen month period beginning in January 2014.
10 – Price risk management activities
ASC 815-25 (formerly SFAS No. 133 “Accounting for Derivative Instruments and Hedging Activities”) requires that all derivative instruments be recorded on the balance sheet at their fair value. Changes in the fair value of each derivative are recorded each period in current earnings or other comprehensive income, depending on whether the derivative is designated as part of a hedge transaction and, if it is, the type of hedge transaction. When choosing to designate a derivative as a hedge, management formally documents the hedging relationship and its risk-management objective and strategy for undertaking the hedge, the hedging instrument, the item, the nature of the risk being hedged, how the hedging instrument’s effectiveness in offsetting the hedged risk will be assessed, and a description of the method of measuring effectiveness. This process includes linking all derivatives that are designated as cash-flow hedges to specific cash flows associated with assets and liabilities on the balance sheet or to specific forecasted transactions. Based on the above, management has determined the swaps noted below do not qualify for hedge accounting treatment.
At December 31, 2013, the Company had a net derivative liability of $38,109, as compared to a net derivative asset of $290,788 at December 31, 2012. The change in net derivative asset/liability is recorded as non-cash mark-to-market income or loss. Mark-to-market losses of $283,831 were recorded in the twelve months ended December 31, 2013 as compared to mark-to-market income of $330,716 during the twelve months ended December 31, 2012. Net realized hedge settlement gain for the twelve months ended December 31, 2013 was $14,062 as compared to $244,370 for the twelve months ended December 31, 2012. The combination of these two components of derivative expense/income is reflected in "Other Income (Expense)" on the Statements of Operations as "Gain (loss) on derivatives."
| F-16 |
As of December 31, 2013, the Company had crude oil swaps in place relating to a total of 3,000 Bbls per month, as follows:
|
Price |
Volumes |
Fair Value of Outstanding Derivative Contracts (1) as of |
|||||||||||||||
| Transaction | Per | Per | December 31, | December | |||||||||||||
| Date | Type (2) | Beginning | Ending | Unit | Month | 2013 | 31, 2012 | ||||||||||
| March 2011 | Swap | 04/01/2011 | 02/28/2013 | $104.55 | 1,000 | $ | — | $ | 41,019 | ||||||||
| November 2011 | Swap | 12/01/2011 | 11/30/2014 | $93.50 | 2,000 | (62,730) | 44,942 | ||||||||||
| February 2012 | Swap | 03/01/2012 | 02/28/2014 | $106.50 | 1,000 | 24,621 | 204,827 | ||||||||||
| $ | (38,109) | $ | 290,788 | ||||||||||||||
| (1) The fair value of the Company's outstanding transactions is presented on the balance sheet by counterparty. Currently all of our derivatives are with the same counterparty. The balance is shown as current or long-term based on our estimate of the amounts that will be due in the relevant time periods at currently predicted price levels. Amounts in parentheses indicate liabilities. |
|
(2) These crude oil hedges were entered into on a per barrel delivered price basis, using the NYMEX - West Texas Intermediate Index, with settlement for each calendar month occurring following the expiration date, as determined by the contracts. |
11 – 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 tables summarize the valuation of the Company’s financial assets and liabilities at December 31, 2013 and December 31, 2012:
| Fair Value Measurements at Reporting Date Using | ||||||||||||||||||||
| 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 December 31, 2013 | |||||||||||||||||
| Assets: | ||||||||||||||||||||
| Commodities derivatives | $ | — | $ | 3,504 | $ | — | $ | 3,504 | ||||||||||||
| Total | $ | — | $ | 3,504 | $ | — | $ | 3,504 | ||||||||||||
| Liabilities | ||||||||||||||||||||
| Environmental liability | $ | — | $ | — | $ | (2,086,833 | ) | $ | (2,086,833 | ) | ||||||||||
| Asset retirement obligations (non-recurring) | $ | — | $ | — | $ | (3,514,898 | ) | $ | (3,514,898 | ) | ||||||||||
| Commodities Derivative | $ | — | $ | (38,109 | ) | $ | — | $ | (38,109 | |||||||||||
| Total | $ | — | $ | (38,109 | ) | $ | (5,601,731 | ) | $ | (5,639,840 | ) | |||||||||
| F-17 |
| Fair Value Measurements at Reporting Date Using | ||||||||||||||
|
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 December 31, 2012 | |||||||||||
| Assets: | ||||||||||||||
| Commodities derivatives | $ | — | $ | 290,788 | $ | — | $ | 290,788 | ||||||
| Total | $ | — | $ | 290,788 | $ | — | $ | 290,788 | ||||||
| Liabilities: | ||||||||||||||
| Environmental liability | $ | — | $ | — | $ | (2,100,000 | ) | $ | (2,100,000 | ) | ||||
| Asset retirement obligations (non-recurring) | — | — | (3,317,358 | ) | (3,317,358 | ) | ||||||||
| Total | $ | — | $ | — | $ | (5,417,358 | ) | $ | (5,417,358 | ) | ||||
The following is a summary of changes to fair value measurements using Level 3 inputs during the 12 months ended December 31, 2013:
| Environmental Liability | ||||
| Balance, December 31, 2012 | $ | 2,100,000 | ||
| Acquisitions | — | |||
| Settlement of liabilities | 11,657 | |||
| Revisions of previous estimates | — | |||
| Balance, December 31, 2013 | $ | 2,087,973 | ||
12 – Income taxes
Total income tax expense (benefit) differed from the amounts computed by applying the U.S. Federal statutory tax rates to pre-tax income:
| Year Ended December 31, | ||||||||
| (in thousands) | 2013 | 2012 | ||||||
| Income taxes at U.S. statutory rate | 1,140 | (802 | ) | |||||
| State taxes, net of federal impact | 88 | (63 | ) | |||||
| Change in valuation allowance | (1,229 | ) | 864 | |||||
| Permanent differences | 1 | 1 | ||||||
| Other differences | 0 | 0 | ||||||
| Total | 0 | 0 | ||||||
Deferred tax assets/(liabilities) consist of the following:
| Year Ended December 31, | ||||||||
| (in thousands) | 2013 | 2012 | ||||||
| Derivatives | (34 | ) | 105 | |||||
| Valuation allowance | (5,972 | ) | (7,200 | ) | ||||
| Difference in depreciation and capitalization methods-natural gas properties, | (3,444 | ) | (379 | ) | ||||
| Accrued expenses | 765 | 769 | ||||||
| Net operating losses | 8,685 | 6,705 | ||||||
| Total | 0 | 0 | ||||||
| F-18 |
Deferred tax assets and liabilities are the result of temporary differences between the financial statement carrying values and tax bases of assets and liabilities. The Company’s net deferred tax assets and liabilities are recorded as a long-term liability of $0 at December 31, 2013 and 2012, respectively.
As of December 31, 2013, the Company had net operating loss carryfowards (“NOLs”) of approximately $23.7 million which will begin to expire, if unused, in 2026.
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 December 31, 2013, and 2012 the Company had a valuation allowance of $6.0 million and $7.2 million, respectively, related to its deferred tax assets.
The company recognizes the financial statement effects of tax positions when it is more likely than not, based on the technical merits, that the position will be sustained upon examination by a taxing authority. Recognized tax positions are initially and subsequently measured as the largest amount of tax benefit that is more likely than not of being realized upon ultimate settlement with a taxing authority. We have not taken a tax position that, if challenged, would have a material effect on the financial statements or the effective tax rate for the periods ended December 31, 2013 and December 31, 2012. There were no interest and penalties related to unrecognized tax positions for the periods ended December 31, 2013 and December 31, 2012. The tax years subject to examination by tax jurisdictions in the United States are 2009 through 2012.
13 - 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 gas property acquisition, development and exploration activities:
| Year Ended December 31, | ||||||||
| 2013 | 2012 | |||||||
| Property acquisition costs: | ||||||||
| Unproved properties | $ | — | $ | — | ||||
| Proved properties | — | — | ||||||
| Exploration costs | — | — | ||||||
| Development costs (1) | 8,312,662 | 13,261,812 | ||||||
| Total costs incurred | $ | 8,312,662 | $ | 13,261,812 | ||||
| (1) | For the years ended December 31, 2013 and 2012, development costs included $51,290 and $383,481, respectively, in non-cash, asset retirement obligations. |
| F-19 |
Results of operations for oil and natural gas producing activities
Set forth below is certain information regarding the results of operations for oil and gas producing activities:
| Year Ended December 31, | ||||||||
| 2013 | 2012 | |||||||
| Revenues | $ | 13,125,960 | $ | 14,781,497 | ||||
| Production costs | 2,300,899 | 2,281,443 | ||||||
| Impairment | — | 2,663,742 | ||||||
| Depletion | 4,941,614 | 5,671,202 | ||||||
| Income tax expense | — | — | ||||||
| Accretion expense | 148,364 | 94,556 | ||||||
| Gain on sale of properties | — | — | ||||||
| Environmental cleanup | — | 2,100,000 | ||||||
| Natural gas marketing | 78,211 | 143,672 | ||||||
| Production taxes | 1,246,153 | 1,171,471 | ||||||
| Results of operations | $ | 4,410,719 | $ | 685,408 | ||||
Proved reserves
Cawley, Gillespie and Associates, Inc, independent petroleum engineers estimated 100% of the proved reserve information for the Company properties as of December 31, 2013.
Joe C. Neal & Associates, Inc., independent petroleum engineers estimated 100% of the proved reserve information for the Company properties as of December 31, 2012. Each year’s estimate of proved reserves and related valuations were also prepared in accordance with then-current provisions of ASC 932, Extractive Activities.
Estimates of proved reserves are inherently imprecise and are continually subject to revision based on production history, results of additional exploration and development, price changes and other factors. All of the Company’s estimated oil and natural gas reserves are attributable to properties within the United States. A summary of the Company’s changes in quantities of proved oil and natural gas reserves for the years ended December 31, 2013 and 2012 are as follows:
| Oil (MBbls) | Natural Gas (MMcf) | Total (MBoe) | ||||||||||
| December 31, 2011 | 1,708 | 2,385 | 2,106 | |||||||||
| Acquisitions | (144 | ) | (143 | ) | (168 | ) | ||||||
| Extensions and discoveries | 16 | 265 | 210 | |||||||||
| Revisions in previous estimates | (308 | ) | (518 | ) | (394 | ) | ||||||
| Production | (151 | ) | (294 | ) | (200 | ) | ||||||
| December 31, 2012 | 1,271 | 1,695 | 1,554 | |||||||||
| Acquisitions | — | — | — | |||||||||
| Extensions and discoveries | 371 | 817 | 507 | |||||||||
| Revisions of previous estimates | 11 | 906 | 161 | |||||||||
| Production | (123 | ) | (283 | ) | (170 | ) | ||||||
| December 31, 2013 | 1,530 | 3,135 | 2,052 | |||||||||
| Proved Developed Reserves | ||||||||||||
| December 31, 2012 | 804 | 1,336 | 1,027 | |||||||||
| December 31, 2013 | 804 | 2,215 | 1,173 | |||||||||
| Proved Undeveloped Reserves | ||||||||||||
| December 31, 2012 | 467 | 359 | 527 | |||||||||
| December 31, 2013 | 726 | 920 | 879 | |||||||||
| F-20 |
Standardized measure of discounted future net cash flows relating to proved reserves
Future cash inflows were computed by applying the average on the closing price on the first day of each month for the 12-month period prior to December 31, 2013 to estimated future production. Future production and development costs are computed by estimating the expenditures to be incurred in developing and producing the proved oil and natural gas reserves at year end, based on year-end costs and assuming continuation of existing economic conditions.
Future income tax expenses are calculated by applying appropriate year-end tax rates to future pre-tax net cash flows relating to proved oil and natural gas reserves, less the tax basis of properties involved.
Future income tax expenses give effect to permanent differences, tax credits and loss carryforwards relating to the proved oil and natural gas reserves. Future net cash flows are discounted at a rate of 10% annually to derive the standardized measure of discounted future net cash flows. This calculation procedure does not necessarily result in an estimate of the fair market value of the Company’s oil and natural gas properties.
The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves are as follows:
| Year Ended December 31, | ||||||||
| 2013 | 2012 | |||||||
| Future cash inflows | $ | 153,544,250 | $ | 120,208,031 | ||||
| Future production costs | (41,381,543 ) | (47,186,808 | ) | |||||
| Future development costs | (18,821,422) | (22,620,478 | ) | |||||
| Future income tax expense | (20,243,102) | (12,218,429 | ) | |||||
| Future net cash flows | 73,098,179 | 38,182,316 | ||||||
| 10% annual discount for estimated timing of cash flows | (36,817,148) | (19,542,639 | ) | |||||
| Standardized measure of discounted future net cash flows | $ | 36,281,031 | $ | 18,639,677 | ||||
| F-21 |
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:
| Year Ended December 31, | ||||||||
| 2013 | 2012 | |||||||
| Balance, beginning of period | $ | 28,147,572 | $ | 44,862,000 | ||||
| Net change in sales and transfer prices and in production (lifting) costs related to future production | 9,374,986 | (18,916,722 | ) | |||||
| Changes in estimated future development costs | 4,042,730 | 11,934,249 | ||||||
| Sales and transfers of oil and natural gas produced during the period | (10,825,061) | (11,227,504 | ) | |||||
| Net change due to extensions and discoveries | 12,107,955 | (3,726,923 | ) | |||||
| Net change due to revisions in quantity estimates | 3,883,464 | 6,992,767 | ||||||
| Previously estimated development costs incurred during the period | (8,312,662) | (16,602,246 | ) | |||||
| Accretion of discount | 2,747,142 | 4,486,195 465,035 | ||||||
| Other | (672,750) | 9,880,721 | ||||||
| Net change in income taxes | (4,212,345) | — | ||||||
| Balance, end of period | $ | 36,281,031 | $ | 28,147,572 | ||||
| F-22 |
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
| Dated: APRIL 15, 2014 | ||||
| RED MOUNTAIN RESOURCES, INC. | ||||
| By: | /s/ Earl M. Sebring | |||
| Earl M. Sebring | ||||
| Interim President | ||||
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 | Chairman of the Board of Directors | APRIL 15, 2014 | ||
| Alan W. Barksdale | ||||
| /s/ Earl M. Sebring | Interim President | APRIL 15, 2014 | ||
| Earl M. Sebring | (Principal Executive Officer) | |||
| /s/ Kenneth S. Lamb | Chief Accounting Officer, Secretary, and Treasurer | APRIL 15, 2014 | ||
| Kenneth S. Lamb | (Principal Financial and Accounting Officer) | |||
| /s/ Paul N. Vassilakos | Director | APRIL 15, 2014 | ||
| Paul N. Vassilakos | ||||
| /s/ Richard F. LaRoche, Jr. | Director | APRIL 15, 2014 | ||
| Richard F. LaRoche, Jr. | ||||
| /s/ John W. Hawkins | Director | APRIL 15, 2014 | ||
| John W. Hawkins |
| 60 |
EXHIBIT INDEX
| Exhibit No. | Name of Exhibit | |
| 2.1 | Agreement and Plan of Merger entered into on December 2, 2010 among Doral Energy Corp., Doral Acquisition Corp., Pure Gas Partners II, L.P. and Pure Energy Group, Inc. (14) | |
| 2.2 | Agreement and Plan of Merger entered into on December 24, 2010 between Doral Acquisition Corp. (as subsidiary merging entity) and Doral Energy Corp. (as parent surviving entity) with the surviving entity changing its name to Cross Border Resources, Inc. (16) | |
| 3.1 | Articles of Incorporation. (1) | |
| 3.2 | Certificate of Change Pursuant to NRS 78.209 increasing the authorized capital of common stock to 2,500,000,000 shares, par value $0.001 per share (25-for-1 Stock Split). (3) | |
| 3.3 | Articles of Merger between Language Enterprises Corp. (as surviving entity) and Doral Energy Corp. (as merging entity). (4) | |
| 3.4 | Certificate of Change Pursuant to NRS 78.209 decreasing the authorized capital of common stock to 400,000,000 shares, par value $0.001 per share (1-for-6.25 Reverse Split). (5) | |
| 3.5 | Certificate of Change Pursuant to NRS 78.209 increasing the authorized capital of common stock to 2,000,000,000 shares, par value $0.001 per share (5-for-1 Stock Split). (6) | |
| 3.6 | Certificate of Change Pursuant to NRS 78.209 decreasing the authorized capital of common stock to 36,363,637 shares, par value $0.001 per share (1-for-55 Stock Split). (15) | |
| 3.7 | Certificate of Merger between Doral Acquisition Corp. (as merging entity) and Doral Energy Corp. (as surviving entity). (16) | |
| 3.8 | Articles of Merger between Doral Acquisition Corp. (as merging entity) and Doral Energy Corp. (as surviving entity). (16) | |
| 3.9 | Amended and Restated Bylaws as amended by Amendments No. 1 and No. 2. (*) | |
| 4.1 | Trust Indenture of Pure Energy Group, Inc. and Pure Gas Partners II, L.P. assumed by the Company. (16) | |
| 4.2 | Form of Common Stock Warrant. (23) | |
| 10.1 | Loan and Cancellation of Convertible Note Agreement between Doral Energy Corp. and Edward Ajootian dated March 3, 2010. (7) | |
| 10.2 | Debt Settlement Agreement with War Chest Multi-Strategy Fund, LLC dated March 8, 2010. (7) | |
| 10.3 | Amendment Agreement dated March 12, 2010 to Debt Settlement Agreement with War Chest Multi- Strategy Fund, LLC. (7) | |
| 10.4 | Release and Settlement Agreement between Doral Energy Corp. and Macquarie Bank Limited dated March 8, 2010. (7) | |
| 10.5 | Purchase and Sale Agreement dated April 30, 2010 between Doral Energy Corp. and Alamo Resources LLC. (8) | |
| 10.6 | Purchase and Sale Agreement dated June 14, 2010 between Doral Energy Corp., John R. Stearns and John R. Stearns Jr. (9) | |
| 10.7 | Amended and Restated 2009 Stock Incentive Plan. (10) | |
| 10.8 | Debt Settlement Agreement dated September 16, 2010 between the Company and War Chest Multi- Strategy Fund, LLC. (11) | |
| 10.9 | Debt Settlement Agreement dated September 16, 2010 between the Company and Barclay Lyons, LLC. (11) | |
| 10.10† | Separation Agreement dated June 15, 2010 between Doral Energy Corp. and H. Patrick Seale. (12) | |
| 10.11† | Debt Settlement Agreement dated November 24, 2010 between the Company and WS Oil & Gas Limited. (13) | |
| 10.12 | Amended and Restated Credit Agreement between Cross Border Resources, Inc. and Texas Capital Bank, N.A. dated January 31, 2011. (18) | |
| 10.13† | Employment Agreement with Everett Willard “Will” Gray II. (19) | |
| 10.14† | Nonqualified Stock Option Award Agreement with Everett Willard “Will” Gray II. (19) | |
| 10.15† | Employment Agreement with Lawrence J. Risley. (19) | |
| 10.16† | Nonqualified Stock Option Award Agreement with Lawrence J. Risley. (19) |
| 61 |
| 10.17† | Employment Agreement with P. Mark Stark. (19) | |
| 10.18† | Nonqualified Stock Option Award Agreement with P. Mark Stark. (19) | |
| 10.19† | Consulting Agreement with BDR, Inc. (19) | |
| 10.20† | Nonqualified Stock Option Award Agreement with BDR, Inc. (19) | |
| 10.21 | Loan Agreement by and between Green Shoe Investments Ltd. and the Company. (20) | |
| 10.22 | Promissory Note to Green Shoe Investments Ltd. (20) | |
| 10.23 | Loan Agreement by and between Little Bay Consulting SA and the Company. (20) | |
| 10.24 | Promissory Note to Little Bay Consulting SA. (20) | |
| 10.25† | Separation Agreement and Release with BDR, Inc. (22) | |
| 10.26 | Consent Waiver and First Amendment to Amended and Restated Credit Agreement with Texas Capital Bank, N.A. (25) | |
| 10.27† | First Amendment to Employment Agreement with Everett Willard “Will” Gray II. (25) | |
| 10.28† | First Amendment to Employment Agreement with Lawrence J. Risley. (25) | |
| 10.29† | Letter Agreement with Nancy S. Stephenson. (25) | |
| 10.30 | Letter Agreement with American Standard Energy Corp. (21) | |
| 14.1 | Code of Business Conduct and Ethics. (*) | |
| 21.1 | List of Subsidiaries. (23) | |
| 23.1 | Consent of Darilek, Butler & Associates PLLC. (*) | |
| 23.2 | Consent of Joe C. Neal & Associates, Inc. (*) | |
| 24.1 | Power of Attorney (included in signature block to this Annual Report on Form 10-K). | |
| 31.1 | Certification of Principal Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. (*) | |
| 31.2 | Certification of Principal Accounting Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. (*) | |
| 32.1 | Certification of Principal Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. (*) | |
| 32.2 | Certification of Principal Accounting Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. (*) | |
| 99.1* | Evaluation of Oil and Gas Reserves of Cross Border Resources, Inc., Effective Date: January 1, 2012. (*) | |
| 99.2* | Evaluation of Oil and Gas Reserves of Pure Energy Group, Inc., Effective Date: December 31, 2010. (*) | |
| (1) | Filed as an exhibit to our Registration Statement on Form SB-2 filed on September 11, 2006. | |
| (2) | Filed as an exhibit to our Annual Report on Form 10-KSB for the year ended July 31, 2007 filed on October 30, 2007. | |
| (3) | Filed as an exhibit to our Current Report on Form 8-K filed on January 9, 2008. | |
| (4) | Filed as an exhibit to our Current Report on Form 8-K filed on April 28, 2008. | |
| (5) | Filed as an exhibit to our Current Report on Form 8-K filed on January 29, 2009. | |
| (6) | Filed as an exhibit to our Current Report on Form 8-K filed on September 14, 2009. | |
| (7) | Filed as an exhibit to our Quarterly Report on Form 10-Q filed on March 22, 2010. | |
| (8) | Filed as an exhibit to our Current Report on Form 8-K filed on May 6, 2010. | |
| (9) | Filed as an exhibit to our Current Report on Form 8-K filed on June 18, 2010. | |
| (10) | Filed as an exhibit to our Current Report on Form 8-K filed on July 30, 2010. | |
| (11) | Filed as an exhibit to our Current Report on Form 8-K filed on October 1, 2010. | |
| (12) | Filed as an exhibit to our Annual Report on Form 10-K filed on November 15, 2010. | |
| (13) | Filed as an exhibit to our Current Report on Form 8-K filed on December 1, 2010. | |
| (14) | Filed as an exhibit to our Current Report on Form 8-K filed on December 6, 2010. | |
| (15) | Filed as an exhibit to our Current Report on Form 8-K filed on December 29, 2010. | |
| (16) | Filed as an exhibit to our Current Report on Form 8-K filed on January 7, 2011. | |
| (17) | Filed as an exhibit to our Current Report on Form 8-K filed on January 19, 2011. | |
| (18) | Filed as an exhibit to our Current Report on Form 8-K filed on February 8, 2011. | |
| (19) | Filed as an exhibit to our Current Report on Form 8-K filed on March 25, 2011. | |
| (20) | Filed as an exhibit to our Current Report on Form 8-K filed on April 28, 2011. | |
| (21) | Filed as an exhibit to our Current Report on Form 8-K filed on November 23, 2011. |
| 62 |
| (22) | Filed as an exhibit to our Current Report on Form 8-K filed on June 3, 2011. | |
| (23) | Filed as an exhibit to our Registration Statement on Form S-1/A on August 2, 2011. | |
| (24) | Filed as an exhibit to our Current Report on Form 8-K filed on November 16, 2011. | |
| (25) | Filed as an exhibit to our Current Report on Form 8-K filed on March 6, 2012. | |
| 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. |
| ** | As provided in Rule 406T of Regulation S-T, this information shall not be deemed “filed” for purposes of Section 11 and 12 of the Securities Act of 1933 and Section 18 of the Securities Exchange Act of 1934 or otherwise subject to liability under those sections. |
| † | Indicates a compensation contract or arrangement with management. |
| 63 |