SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
(Mark One)
| x | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
| | |
| For the fiscal year ended May 31, 2013 |
| | |
| o | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from _______________ to _______________
Commission File Number 000-54444
RED MOUNTAIN RESOURCES, INC.
(Exact Name of Registrant as Specified in Its Charter)
| Florida | | 27-1739487 |
| (State or Other Jurisdiction of Incorporation or Organization) | | (I.R.S. Employer Identification Number) |
2515 McKinney Avenue, Suite 900 Dallas, TX | | 75201 |
| (Address of Principal Executive Offices) | | (Zip Code) |
(214) 871-0400
(Registrant's Telephone Number, Including Area Code)
Securities registered pursuant to Section 12(b) of the Act: None
Securities registered pursuant to Section 12(g) of the Act:
Common Stock, par value $0.00001 per share
10.0% Series A Cumulative Redeemable Preferred Stock, par value $0.0001 per share
Warrants to purchase common stock
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No x
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Exchange Act. Yes o No x
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 past 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 x No o
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 during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No o
Indicate by check mark if disclosure of delinquent filers in response to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the 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. o
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 definition of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.
| Large accelerated filer o | | Accelerated filer o |
| | | |
| Non-accelerated filer x (Do not check if a smaller reporting company) | | Smaller reporting company o |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes o No x
As of November 30, 2012 (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 $0.90 per share on the OTCQB) held by non-affiliates of the registrant was approximately $71.4 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 September 12, 2013, there were 133,140,303 shares of common stock, $0.00001 par value per share, outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the registrant's proxy statement to be furnished to shareholders in connection with its 2013 Annual Meeting of Stockholders are incorporated by reference in Part III, Items 10-14 of this Annual Report on Form 10-K.
RED MOUNTAIN RESOURCES, INC.
FORM 10-K
TABLE OF CONTENTS
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 generate sufficient cash flow from operations, borrowings or other sources to enable us to fully develop and produce our oil and natural gas properties; |
| | | |
| | ● | declines or volatility in the prices we receive for our oil and natural gas; |
| | | |
| | ● | general economic conditions, whether internationally, nationally or in the regional and local market areas in which we do business; |
| | | |
| | ● | risks associated with drilling, including completion risks, cost overruns and the drilling of non-economic wells or dry holes; |
| | | |
| | ● | uncertainties associated with estimates of proved oil and natural gas reserves; |
| | | |
| | ● | the presence or recoverability of estimated oil and natural gas reserves and the actual future production rates and associated costs; |
| | | |
| | ● | risks and liabilities associated with acquired companies and properties; |
| | | |
| | ● | risks related to integration of acquired companies and properties; |
| | | |
| | ● | potential defects in title to our properties; |
| | | |
| | ● | cost and availability of drilling rigs, equipment, supplies, personnel and oilfield services; |
| | | |
| | ● | geological concentration of our reserves; |
| | | |
| | ● | environmental or other governmental regulations, including legislation of hydraulic fracture stimulation; |
| | | |
| | ● | our ability to secure firm transportation for oil and natural gas we produce and to sell the oil and natural gas at market prices; |
| | | |
| | ● | exploration and development risks; |
| | ● | management's ability to execute our plans to meet our goals; |
| | | |
| | ● | our ability to retain key members of our management team; |
| | | |
| | ● | weather conditions; |
| | | |
| | ● | actions or inactions of third-party operators of our properties; |
| | | |
| | ● | costs and liabilities associated with environmental, health and safety laws; |
| | | |
| | ● | our ability to find and retain highly skilled personnel; |
| | | |
| | ● | operating hazards attendant to the oil and natural gas business; |
| | | |
| | ● | competition in the oil and natural gas industry; and |
| | | |
| | ● | the other factors discussed under Item 1A. "Risk Factors" in this report. |
Forward-looking statements speak only as of the date hereof. All such forward-looking statements and any subsequent written and oral forward-looking statements attributable to us or any person acting on our behalf are expressly qualified in their entirety by the cautionary statements contained or referred to in this section and any other cautionary statements that may accompany such forward-looking statements. Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements.
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.
"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.
"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.
"proved undeveloped reserves" Reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required.
"PUD" Proved undeveloped reserves.
"PV-10" When used with respect to oil and natural gas reserves, PV-10 means the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development and abandonment costs, using prices and costs in effect at the determination date, before income taxes, and without giving effect to non-property-related expenses, discounted to a present value using an annual discount rate of 10% in accordance with the guidelines of the SEC.
"reasonable certainty" If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery, or EUR, with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.
"recompletion" The process of re-entering an existing wellbore that is either producing or not producing and completing new reservoirs in an attempt to establish or increase existing production.
"reserves" Estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible as of a given date by application of development prospects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and natural gas or related substances to market, and all permits and financing required to implement the project.
"reservoir" A porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers and is separate from other reservoirs.
"sand" A geological term for a formation beneath the surface of the Earth from which hydrocarbons are produced. Its make-up is sufficiently homogenous to differentiate it from other formations.
"shale" Fine-grained sedimentary rock composed mostly of consolidated clay or mud. Shale is the most frequently occurring sedimentary rock.
"spacing" The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres, e.g., 40-acre spacing, and is often established by regulatory agencies.
"standardized measure" The present value of estimated future cash inflows from proved oil and natural gas reserves, less future development, abandonment, production and income tax expenses, discounted at 10% per annum to reflect the timing of future cash flows and using the same pricing assumptions as were used to calculate PV-10. Standardized measure differs from PV-10 because standardized measure includes the effect of future income taxes.
"stratigraphic test well" A drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intention of being completed for hydrocarbon production.
"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.
Unless the context otherwise requires, all references to "Red Mountain," the "Company," "we," "our" and "us" refer to (i) Red Mountain Resources, Inc., (ii) Red Mountain's wholly owned subsidiaries, including Black Rock Capital, Inc. ("Black Rock") and RMR Operating, LLC ("RMR Operating"), and (iii) subsequent to January 28, 2013, Cross Border Resources, Inc. ("Cross Border"). Pro forma production and related data for 2013 reflects the acquisition of Cross Border as if it occurred on June 1, 2012. As of May 31, 2013, we owned 83% of the outstanding common stock of Cross Border. Acreage, reserves and production information presented subsequent to January 28, 2013 includes acreage, reserves and production represented by the 17% of Cross Border's common stock not owned by us.
Our Company
We are a Dallas-based growth-oriented energy company engaged in the acquisition, development and exploration of oil and natural gas properties in established basins with demonstrable prolific producing zones. Currently, we have established acreage positions and production in the Permian Basin of West Texas and Southeast New Mexico and the onshore Gulf Coast of Texas. Additionally, we have an established and growing acreage position in Kansas.
We plan to grow production and reserves by acquiring, exploring and developing an inventory of long-life, low risk drilling opportunities with attractive rates of return. Our focus is on opportunities in and around producing oil and natural gas properties where we can enhance production and reserves through application of newer drilling and completion techniques, infill drilling, targeting untapped but known productive hydrocarbon strata, and enhanced oil recovery applications.
As of May 31, 2013, we had proved reserves of approximately 3.5 MMBoe. For the fiscal year ended May 31, 2013, on a pro forma basis, we produced 172.2 MBbls of oil and 966.9 MMcf of natural gas, resulting in average net daily production of 913 Boe/d. In June 2013, we produced 981 Boe/d, of which 56% was oil.
As of May 31, 2013, we owned interests in 883,226 gross (305,845 net) mineral and lease acres in New Mexico, Texas and Kansas, of which 336,851 gross (31,011 net) acres are within the Permian Basin. We have successfully leased over 5,200 net acres in Kansas located on the Central Kansas Uplift, and we also owned interests in over 1,400 net acres located on the Villarreal, Frost Bank, Resendez, Peal Ranch and La Duquesa Prospects in the Gulf Coast of Texas.
History
Red Mountain was originally formed in January 2010 as Teaching Time, Inc. in order to design, develop, and market instructional products and services for the corporate, education, government, and healthcare e-learning industries. In March 2011, Teaching Time, Inc. determined to enter into oil and natural gas exploration, development and production and changed its name to Red Mountain Resources, Inc. to better reflect that plan. On March 22, 2011, we entered into a Plan of Reorganization and Share Exchange Agreement, as amended on June 17, 2011 and June 20, 2011 (the "Share Exchange Agreement"), with Black Rock Capital, LLC and The StoneStreet Group, Inc. ("StoneStreet"), the sole shareholder of Black Rock Capital, LLC. Alan W. Barksdale, our current president, chief executive officer and chairman of the board, was the president and the sole member of Black Rock Capital, LLC and the sole owner and the president of StoneStreet. On June 22, 2011, we completed a reverse merger pursuant to the Share Exchange Agreement in which we issued 27,000,000 shares of common stock to StoneStreet in exchange for 100% of the interests in Black Rock Capital, LLC. Concurrently with the closing, we retired 225,000,000 shares of common stock for no additional consideration. In connection with the reverse merger, the management of Black Rock Capital, LLC became our management.
While we were the legal acquirer in the reverse merger, Black Rock Capital, LLC was treated as the accounting acquirer and the transaction was treated as a recapitalization. As a result, at the closing, the historical financial statements of Black Rock became those of the Company. The description of our business presented below is that of our current business and all discussions of periods prior to the reverse merger describe the business of Black Rock.
Black Rock was originally formed on October 28, 2005 as an Arkansas limited liability company under the name "Black Rock Capital, LLC." From inception through May 2010, Black Rock had no operations. Effective June 1, 2010, Black Rock purchased two separate oil and natural gas fields out of the bankruptcy estate of MSB Energy, Inc. located in Zapata County and Duval County in the onshore Gulf Coast of Texas. Effective May 31, 2011, Black Rock acquired our current interests in the Madera Prospect. In June 2011, Black Rock Capital, LLC filed Articles of Conversion with the Secretary of State for the State of Arkansas to convert Black Rock Capital, LLC into a corporation. The conversion became effective July 1, 2011 and, accordingly, Black Rock Capital, LLC was converted to Black Rock Capital, Inc. As a result of the conversion, our 100% membership interest in Black Rock Capital, LLC became an interest in all of the outstanding common stock of Black Rock.
Recent Developments
Bamco Asset Purchase Agreement. On December 10, 2012, we entered into an Asset Purchase Agreement (the "Asset Purchase Agreement") with Bamco Gas, LLC ("Bamco"). Mr. Barksdale was the receiver for the receivership estate of Bamco. Pursuant to the Asset Purchase Agreement, we agreed to acquire working interests and claims and causes of action in or relating to certain oil and gas exploration projects in Duval, Johnson and Zapata Counties in Texas (the "Bamco Properties"). On December 10, 2012, pursuant to the Asset Purchase Agreement, we issued 2,375,000 shares of our common stock to the indenture trustee of certain debentures of Bamco, and we executed a waiver and release of a claim against the receivership estate of Bamco for a $2.7 million note receivable that we deemed uncollectible in 2011.
Acquisition of Cross Border. On January 28, 2013, pursuant to privately negotiated transactions, we acquired 5,091,210 shares of common stock of Cross Border from a limited number of stockholders in exchange for the issuance of 10,182,420 shares of our common stock, bringing our total ownership to approximately 78% of Cross Border's outstanding common stock (the "Acquisition"). Prior to the Acquisition, we owned 47% of Cross Border's outstanding common stock, and the investment was accounted for under the equity method of accounting. Subsequent to the Acquisition, we account for Cross Border as a consolidated subsidiary. As of May 31, 2013, we owned of record 14,327,767 shares of Cross Border common stock, representing 83% of Cross Border's outstanding common stock. In addition, as of May 31, 2013, we owned warrants to acquire an additional 2,502,831 shares of Cross Border common stock. The warrants have an exercise price of $2.25 per share and are exercisable until May 26, 2016.
As of May 31, 2013, Cross Border owned over 865,893 gross (293,843 net) mineral and lease acres in New Mexico and Texas, of which approximately 25,000 net acres were located in the Permian Basin. A significant majority of Cross Border's acreage consists of either owned mineral rights or leases held by production, allowing it to hold lease rental payments to under $5,000 annually.
Senior Credit Facility. On February 5, 2013, we entered into a Senior First Lien Secured Credit Agreement (as amended, the "Credit Agreement") with Cross Border, Black Rock and RMR Operating (collectively with the Company, the "Borrowers") and Independent Bank, as Lender (the "Lender").The Credit Agreement provides for an up to $100.0 million revolving credit facility (the "Credit Facility") with an initial commitment of $20.0 million and a maturity date of February 5, 2016.
Simultaneously with entering into the Credit Agreement, we borrowed $7.6 million under the Credit Facility and used a portion of the proceeds to repay outstanding indebtedness, and Cross Border borrowed $8.9 million and used a portion of the proceeds to repay in full its existing credit facility. As of May 31, 2013, the Borrowers had collectively borrowed $19.8 million and had availability of $0.2 million under the Credit Facility. On February 21, 2013, pursuant to the terms of the Credit Agreement, we entered into a hedge agreement with BP Energy Company, LP ("BP Energy") to hedge a portion of the future oil production of the Borrowers.
On July 19, 2013, we entered into an amendment to the Credit Agreement to permit the payment of cash dividends on our 10.0% Series A Cumulative Redeemable Preferred Stock (the "Series A Preferred Stock") so long as we are not otherwise in default under the Credit Agreement and payment of such cash dividends would not cause us to be in default under the Credit Agreement.
We were not in compliance with the current ratio covenant in the Credit Agreement as of May 31, 2013. We entered into an amendment and waiver to the Credit Agreement effective September 12, 2013, which waived the non-compliance at May 31, 2013. In addition, the amendment increased the borrowing base under the Credit Agreement from $20.0 million to $30.0 million.
Private Placements. On February 5, 2013, we closed a private placement for 7,058,823 shares of common stock at a purchase price of $0.85 per share, raising gross proceeds of $6.0 million, from certain of the initial investors in our company. We used the proceeds for drilling expenses, repayment of debt and general working capital. On May 3, 2013, we closed a private placement for 3,529,412 shares of common stock at a purchase price of $0.85 per share, raising gross proceeds of $3.0 million, from certain of the initial investors in our company. We used the proceeds for general working capital.
Madera 24 Federal 3H Well. During the three months ended February 28, 2013, we commenced drilling the Madera 24 Federal 3H well, which is located in the Madera prospect just to the west of the Madera 24 Federal 2H well. We are the operator of the well and own a 33% working interest. The well was spudded on February 6, 2013 and, on May 10, 2013, we finished drilling and completing the well. The initial production rate from the Madera 24 Federal 3H well was 1,491 Boe (81% oil). The well has a total measured depth of 13,570 feet, including a true vertical depth of 9,062 feet and a lateral length of 4,508 feet. At May 31, 2013, the well was still producing and permanent production facilities were under construction.
Reverse Stock Split. On April 22, 2013, our Board of Directors approved a reverse stock split. The Board authorized management to effectuate the reserve stock split in its discretion within a range of 1 for 5 to 1 for 10. We intend to consummate the reverse stock split during the first six months of fiscal 2014.
Change of Fiscal Year End. On July 17, 2013, we changed our fiscal year end from May 31 to June 30, effective June 30, 2013.
Closing of Units Offerings. In August 2013, we closed public offerings of 476,687 Units (the "Units"), including 100,002 Units sold in cancellation of $2.3 million in debt, raising gross cash proceeds of $8.5 million. Each Unit consisted of one share of our Series A Preferred Stock and one warrant to purchase up to 25 shares of common stock. We intend to use the proceeds for general corporate purposes, including to fund a portion of our fiscal 2014 drilling and development expenditures and the payment of accrued interest and fees on indebtedness that was cancelled.
Closing of Common Stock Offering. In August 2013, we closed a public offering of 6,428,572 shares of common stock, raising gross cash proceeds of $4.5 million. We intend to use the proceeds for general corporate purposes, including to fund a portion of our fiscal 2014 drilling and development expenditures and the repayment of indebtedness.
Our Business Strategies
Key elements of our business strategy include:
Increase Reserves and Production Through Low-Risk Drilling Program. We intend to achieve reserves and production growth over the next few years through our drilling program, which will focus on low risk opportunities with attractive rates of return. In addition to our proved reserve base of 3.5 MMBoe at May 31, 2013, we believe we have significant upside potential to convert our current probable and possible reserves into proved reserves. We plan to drill and complete, workover or recomplete 55 gross wells (38.1 net) through fiscal 2014 to develop our current properties.
Maintain a Conventional Balance Sheet and Capital Structure. We take a conventional approach to our drilling program and seek to find and develop geologically defined conventional prospects. Similarly, we intend to maintain a conventional balance sheet minimizing our risk and allowing us to maintain strong credit metrics. Further, we plan to use derivatives to hedge against falling commodity prices to ensure adequate cash flows to meet our corporate and drilling objectives.
Pursue Growth through Acquisitions that Leverage Our Expertise. Our primary acquisition strategy is to identify and acquire geologically defined, undercapitalized plays with development potential. At the same time, we continually review opportunities to acquire producing properties, undeveloped acreage and drilling prospects. We focus particularly on opportunities where we believe our operational efficiency, reservoir management and geological expertise will enhance value and performance.
Retain Operational Control. We intend to retain a high degree of operational control over our interests, through a high average working interest or acting as the operator in areas of significant exploration and development activity. This strategy is intended to provide us with controlling interests in a multi-year inventory of drilling locations, positioning us for reserve and production growth through drilling. We plan to control the timing, level and allocation of our drilling capital expenditures and the technology and methods utilized in the planning, drilling and completion process on related targets. We believe this flexibility to opportunistically pursue development on properties provides us with a meaningful competitive advantage.
Mitigate Operational and Financial Risk. Our goal is to generate attractive rates of return on every dollar invested. Concurrently, our goal is to manage risk by spreading our capital dollars over a significant number of wells to mitigate capital, geologic and mechanical concentration risk to any one project. The combination may prevent us from aggressively and continuously drilling in any one area but the participation in more projects allows us to better manage our production growth, effectively procure services, and provides ample time necessary to evaluate results in order to attempt to improve future wells.
Our Competitive Strengths
We believe that the following competitive strengths will help us successfully execute our business strategies and create substantial value:
Large Acreage Position Consisting of Mineral Ownership and Leases Held by Production. As of May 31, 2013, we controlled 305,845 net acres, 98% of which was in Texas and New Mexico. Included in this acreage position were approximately 275,000 net mineral acres within Southwest New Mexico and the Permian Basin region of Southeast New Mexico. This net mineral acreage carries no drilling commitments or leasehold obligations. Furthermore, 93% of our leasehold acreage in the Permian Basin is currently held by existing production. The combination of perpetual mineral ownership and leases held by production provides us with ample time to exploit our drilling inventory in the Permian Basin.
Long-Life Reserves and Multi-Horizon Drilling Opportunities. One of the great attributes of the Permian Basin is that there are dozens of productive formations that lie deep into the Earth. Enhancements in drilling and completion technology have improved the economics of drilling and producing various hydrocarbon bearing strata that previously were uneconomic. We believe that much of our productive acreage has drilling opportunities into multiple hydrocarbon bearing zones that we have yet to evaluate which could provide substantial upside to our reserve base. Many of these zones are productive on nearby leases owned by other operators. Cash flow from our longer life reserve base combined with existing infrastructure should allow us to opportunistically test numerous potentially productive zones in the San Andres, Bone Spring, Brushy Canyon and other known horizons providing us with a multi-year drilling inventory.
Strong Management and Operations Team. Our team of managers, employees, consultants and directors combine to represent over 300 years of experience in the oil and natural gas industry as owners, investors, company builders, financiers, operators, geologists, service providers and petroleum engineers. In these various capacities, the Red Mountain team has participated in more than 10,000 wells in 20 states and 22 countries. We intend to utilize sophisticated geologic and 3-D seismic models to enhance the predictability and reproducibility of our operations. We also intend to utilize multi-zone, multi-stage hydraulic fracturing technology in completing wells to substantially increase near-term production, resulting in faster payback periods and higher rates of return and present values. Our team has applied these techniques to improve initial and ultimate production and returns for other organizations. We believe that the depth and breadth of our operations team coupled with a proven team in the areas of accounting, finance and capital markets, positions us well to take advantage of our large inventory of acreage and drilling opportunities.
Management with Meaningful Equity Ownership. As of September 13, 2013, our chairman of the board, chief executive officer and president, Alan Barksdale, owned 8.3% of our outstanding shares of common stock, and other members of our management and board of directors owned 1.1% of our outstanding shares of common stock. As a result of their equity investment in us, we believe our management's interests are highly aligned with our stockholders' interests in stock price appreciation and profitable growth.
Existing Infrastructure. All of our properties are located within established oil and natural gas producing areas or existing fields. We seek to enhance existing production in these properties by using our engineering and geological expertise. These areas also have a fully developed transportation infrastructure, which allows us to transport our oil and natural gas to market without long-term delay or significant investment.
Our Properties
Currently, our oil and natural gas properties are concentrated in the Permian Basin, the onshore Gulf Coast of Texas, Southwest New Mexico and Kansas. The Permian Basin covers an area approximately 250 miles wide and 300 miles long in West Texas and Southeast New Mexico. The Permian Basin is one of the most prolific onshore oil and natural gas producing regions in the United States. It is characterized by an extensive production history, mature infrastructure, long reserve life and hydrocarbon potential in multiple producing formations. Our primary operations in the onshore Gulf Coast are in conventional fields that produce primarily from the Wilcox formation in Zapata and Duval counties of Texas.
Permian Basin. As of May 31, 2013, we had interests in 336,851 gross (31,011 net) acres in the Permian Basin, including of the Madera Prospect, Pawnee Prospect, Cowden Lease, Shafter Lake Lease, Martin Lease, Jackson Bough C Prospect, East Ranch Prospect and West Ranch Prospect. We are the operator of each of these properties. These interests include the oil and natural gas interests of Cross Border in the Permian Basin, a large portion of which is non-operated acreage located in the heart of the Bone Spring play in central Lea and Eddy counties of New Mexico. Cross Border also has non-operated acreage in the Yeso and Abo trends along the Northwest Shelf and in areas targeting the Queen, Grayburg, and San Andres reservoirs. Cross Border also holds acreage in the Tom Tom area, where it is the operator.
In the aggregate, as of May 31, 2013, these properties had 209 gross (92.4 net) producing wells and, during the month of May 2013, had daily average net production of 636 Boe/d, 73% of which was oil. As of May 31, 2013, our Permian Basin properties had approximately 3,147 MBoe of proved reserves, of which 74% was oil. Of our proved reserves in the Permian Basin, 32% are from the Madera Prospect, 22% are from the Lusk Prospect and 17% are from the Tom Tom Prospect. During the fiscal year ended May 31, 2013, we derived approximately 79% of our revenue from the Permian Basin.
Onshore Gulf Coast. As of May 31, 2013, we had interests in 4,776 gross (1,405 net) acres in the onshore Gulf Coast of Texas, consisting of the Villarreal Prospect, Frost Bank Prospect, Peal Ranch Prospect, Resendez Prospect and La Duquesa Prospect. We are the operator of each of these properties, other than the Villarreal Prospect, which is operated by ConocoPhillips Company, and the Peal Ranch Prospect, which is operated by White Oak Energy.
In the aggregate, as of May 31, 2013, these properties had 39 gross (13.0 net) wells and, during the month of May 2013, had daily average net production of 244 Boe/d, substantially all of which was natural gas. As of May 31, 2013, our onshore Gulf Coast properties had approximately 401 MBoe of proved reserves, substantially all of which was natural gas. Of our proved reserves in the onshore Gulf Coast, 74% are from the Villarreal Prospect and 16% are from the Peal Ranch Prospect. During the fiscal year ended May 31, 2013, we derived approximately 21% of our revenue from the onshore Gulf Coast.
Southwest New Mexico. As of May 31, 2013, we owned 536,340 gross (268,170 net) mineral acres in Hidalgo, Grant, Sierra, and Socorro Counties, New Mexico. This mineral ownership carries no drilling commitments or leasehold obligations. As of May 31, 2013, this acreage had no proved reserves or production.
Kansas. As of May 31, 2013, we owned oil and natural gas interests in 5,215 gross and net acres in central Kansas. There are multiple target horizons in this prospect including the Arbuckle and the Lansing Kansas City formations. We own a 100% working interest and an average net revenue interest of 80%. RMR Operating is the operator. As of May 31, 2013, the Kansas acreage had no proved reserves or production.
For more detailed information on our properties, see "Item 2. Properties."
Planned Operations
During fiscal year 2014, we plan to spend approximately $39.5 million for drilling, completion, workovers, and recompletion on our properties including Madera, Tom Tom, Cowden and Shafter Lake and on properties in Cross Border's non-operated acreage. See "Management's Discussion and Analysis of Financial Condition and Results of Operations—Planned Operations."
Marketing and Customers
During the fiscal year ended May 31, 2013, we sold $5.6 million of oil to High Sierra Crude Oil & Marketing, LLC ("High Sierra"), representing 63% of our total revenues, and $2.0 million of oil to Phillips 66 Company, representing 22% of our total revenues . We sell our oil to High Sierra from our Good Chief State #1, Big Brave State #1 and Madera 24 Federal 2H and 3H wells pursuant to crude oil purchase contracts. The price of the oil delivered is based on the West Texas Intermediate price, subject to certain price adjustments. The purchase agreements continue until terminated by either party upon thirty days prior written notice. We believe that the loss of either customer would not have a material adverse effect on us because alternative purchasers are readily available.
Competition
The oil and natural gas industry is highly competitive and we compete with a substantial number of other companies that have greater resources than we do. The largest of these companies explore for, produce and market oil and natural gas, carry on refining operations and market the resultant products on a worldwide basis. The primary areas in which we encounter substantial competition are in our drilling and development operations, locating and acquiring prospective oil and natural gas properties and reserves and attracting and retaining highly skilled personnel. There is also competition between producers of oil and natural gas and other industries producing alternative energy and fuel. Furthermore, competitive conditions may be substantially affected by various forms of energy legislation and/or regulation considered from time to time by the United States government; however, it is not possible to predict the nature of any such legislation or regulation that may ultimately be adopted or its effects upon our future operations. Such laws and regulations may, however, substantially increase the costs of exploring for, developing or producing oil and natural gas and may prevent or delay the commencement or continuation of a given operation. The effect of these risks cannot be accurately predicted.
Insurance
We currently maintain oil and natural gas commercial general liability protection relating to all of our oil and natural gas operations (including environmental and pollution claims) with a total limit of coverage in the amount of $2.0 million (with no deductible) and excess liability protection with a total limit of $3.0 million (with a deductible of $10,000).
As is common in the oil and natural gas industry, we will not insure fully against all risks associated with our business either because such insurance is not available or because premium costs are considered prohibitive. In addition, pollution and environmental risks generally are not fully insurable. A loss not fully covered by insurance could have a material adverse effect on our business, financial condition and results of operations.
Legal Proceedings
On May 4, 2011, Clifton M. (Marty) Bloodworth filed a lawsuit in the State District Court of Midland County, Texas, against Doral West Corp. d/b/a Doral Energy Corp. and Everett Willard Gray II. Mr. Bloodworth alleges that Mr. Gray, as CEO of Cross Border, made false representations which induced Mr. Bloodworth to enter into an employment contract that was subsequently breached by Cross Border. The claims that Mr. Bloodworth has alleged are: breach of his employment agreement with Doral West Corp, common law fraud, civil conspiracy breach of fiduciary duty, and violation of the Texas Deceptive Trade Practices-Consumer Protection Act. Mr. Bloodworth is seeking damages of approximately $280,000. Mr. Gray and Cross Border deny that Mr. Bloodworth's claims have any merit.
Cross Border was previously party to an engagement letter, dated February 7, 2012 (the "Engagement Letter"), with KeyBanc Capital Markets Inc. ("KeyBanc") pursuant to which KeyBanc was to act as exclusive financial advisor to Cross Border's Board of Directors in connection with a possible "Transaction" (as defined in the Engagement Letter). The Engagement Letter was formally terminated by Cross Border on August 21, 2012. The Engagement Letter provided that KeyBanc would be entitled to a fee upon consummation of a Transaction within a certain period of time following termination of the Engagement Letter. On May 16, 2013, KeyBanc delivered an invoice to Cross Border in the amount of $751,334, representing amounts purportedly owed by Cross Border to KeyBanc as a result of the consummation of a purported Transaction that KeyBanc asserts had been consummated within the required time period and its out-of-pocket expenses in connection therewith. Cross Border disputes that any Transaction was consummated and that KeyBanc is entitled to any out-of-pocket expenses. The matter was originally filed 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. Cross Border intends to vigorously defend the action.
Employees
As of May 31, 2013, we had 27 full-time employees. We are not a party to any collective bargaining agreements and have not experienced any strikes or work stoppages. We believe our relationships with our employees are good.
Hydraulic Fracturing Policies and Procedures
We contract with third parties to conduct hydraulic fracturing as a means to maximize the productivity of our oil and natural gas wells in almost all of our wells. Hydraulic fracturing involves the injection of water, sand, gel and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. All of our proved non-producing and proved undeveloped reserves associated with future drilling, completion and recompletion projects will require hydraulic fracturing.
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 40% of the drilling and completion costs for our wells are associated with hydraulic fracturing activities. These costs are treated in the same way that all other costs of drilling and completing our wells are treated and are built into and funded through our normal capital expenditures budget. A change to any federal and state laws and regulations governing hydraulic fracturing could impact these costs and adversely affect our business and financial results. See "Risk Factors—Federal and state legislative and regulatory initiatives as well as governmental reviews relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays as well as adversely affect our level of production."
The protection of groundwater quality is important to us. Our policy and practice is to ensure our service providers follow all applicable guidelines and regulations in the areas where we have hydraulic fracturing operations. In addition, we send at least one of our own engineers or an experienced consultant to the well site to personally supervise each hydraulic fracture treatment.
We believe that the hydraulic fracturing operations on our properties are conducted in compliance with all state and federal regulations and in accordance with industry standard practices for groundwater protection. These protective measures include setting surface casing at a depth sufficient to protect fresh water zones as determined by applicable state regulatory agencies, and cementing the casing to create a permanent isolating barrier between the casing pipe and surrounding geological formations. The casing plus the cement are intended to prevent contact between the fracturing fluid and any aquifers during the hydraulic fracturing or other well operations. For recompletions of existing wells, the production casing is pressure tested prior to perforating the new completion interval. Injection rates and pressures are monitored at the surface during our hydraulic fracturing operations. Pressure is monitored on both the injection string and the immediate annulus to the injection string.
The vast majority of hydraulic fracturing treatments are made up of water and sand or other kinds of man-made propping agents. Our service providers track and report chemical additives that are used in the fracturing operation as required by the applicable governmental agencies.
Hydraulic fracturing requires the use of a significant amount of water. All produced water, including fracture stimulation water, is disposed of in a way that does not impact surface waters. All produced water is disposed of in permitted and regulated disposal facilities.
Environmental Matters and Regulation
Our exploration, development and production operations are subject to various federal, state and local laws and regulations governing health and safety, the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may, among other things: require the acquisition of permits to conduct exploration, drilling and production operations; govern the amounts and types of substances that may be released into the environment in connection with oil and natural gas drilling and production; restrict the way we handle or dispose of our wastes or of naturally occurring radioactive materials generated by our operations; cause us to incur significant capital expenditures to install pollution control or safety related equipment operating at our facilities; limit or prohibit construction or drilling activities in sensitive areas such as wetlands, wilderness areas or areas inhabited by endangered or threatened species; impose specific health and safety criteria addressing worker protection; require investigatory and remedial actions to mitigate pollution conditions caused by our operations or attributable to former operations; impose obligations to reclaim and abandon well sites and pits and impose substantial liabilities on us for pollution resulting from our operations. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations and the issuance of orders enjoining some or all of our operations in affected areas.
Additionally, the United States Congress and federal and state agencies frequently revise environmental, health and safety laws and regulations, and their interpretations thereof, and any changes that result in more stringent and costly operational requirements or waste handling, disposal, cleanup and remediation requirements for the oil and natural gas industry could have a significant impact on our operating costs. The trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, and thus, any changes in environmental laws and regulations or new interpretations of enforcement policies that result in more stringent and costly waste handling, storage, transport, disposal or remediation requirements could have a material adverse effect on our financial condition and results of operations. We may be unable to pass on such increased compliance costs to our customers.
We believe that we are in substantial compliance with all existing environmental laws and regulations applicable to our current operations and that our continued compliance with existing requirements will not have a material adverse impact on our financial condition and results of operations. We have not incurred any material capital expenditures for remediation or pollution control activities during fiscal 2013, and we are not aware of any environmental issues or claims that will require material capital expenditures during fiscal 2014, other than the remediation plan for Cross Border's Tom Tom and Tomahawk fields, or that will otherwise have a material impact on our financial condition and results of operations in the future. However, we cannot assure you that the passage of more stringent laws and regulations in the future will not have a negative impact on our business, financial condition or results of operations.
The following is a summary of the more significant existing environmental, health and safety laws and regulations to which our business is subject and for which compliance may have a material adverse impact on our capital expenditures, financial condition or results of operations.
Comprehensive Environmental Response, Compensation and Liability Act. Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA"), also known as the "Superfund" law, and comparable state statutes impose strict and joint and several liability for costs of investigation and removal and remediation of previously disposed wastes (including wastes disposed of or released by prior owners or operators) or property contamination (including groundwater contamination), for natural resource damages and the cost of certain health studies without regard to fault or legality of the original conduct, on certain classes of persons with respect to the release into the environment of substances designated under CERCLA as hazardous substances. These classes of persons, or so-called potentially responsible parties ("PRPs") include the current and past owners or operators of a site where the release occurred and anyone who transported or disposed or arranged for the transport or disposal of a hazardous substance found at the site. CERCLA also authorizes the 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. Additionally, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. Many states have adopted comparable or more stringent state statutes.
Although CERCLA generally exempts "petroleum" from the definition of hazardous substance, in the course of our operations, we will generate, transport and dispose or arrange for the disposal of wastes that may fall within CERCLA's definition of hazardous substances. Comparable state statutes may not contain a similar exemption for petroleum. We may also be the owner or operator of sites on which hazardous substances have been released.
Solid and Hazardous Waste Handling. The Resource Conservation and Recovery Act ("RCRA") and comparable state statutes and regulations promulgated thereunder regulate the generation, transportation, treatment, storage, disposal and cleanup of solid and hazardous waste. With federal approval, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent regulations. Although oil and natural gas waste generally is exempt from regulations as hazardous waste under RCRA, such wastes may constitute "solid wastes" that are subject to the less stringent requirements of non-hazardous waste provisions. Additionally, we will generate waste as a routine part of our operations that may be subject to RCRA and not all state and local laws contain a comparable exemption. Further, there is no guarantee that the Environmental Protection Agency ("EPA") or individual states or local governments will not adopt more stringent requirements for the handling of non-hazardous waste or categorize some non-hazardous waste as hazardous in the future. Indeed, legislation has been proposed from time to time in Congress to re-categorize certain oil and natural gas exploration, development and production wastes as "hazardous wastes." Any such change could result in an increase in our costs to manage and dispose of waste, which could have a material adverse effect on our financial condition and results of operations.
It is also possible that our oil and natural gas operations may require us to manage naturally occurring radioactive materials, or NORM. NORM is present in varying concentrations in sub-surface formations, including hydrocarbon reservoirs, and may become concentrated in scale, film and sludge in equipment that comes in contract with crude oil and natural gas production and processing streams. Some states have enacted regulations governing the handling, treatment, storage and disposal of NORM.
Administrative, civil and criminal penalties can be imposed for failure to comply with waste handling requirements. We believe that we are in substantial compliance with applicable requirements related to waste handling, and that we hold all necessary and up-to-date permits, registrations and other authorizations to the extent that our operations require them under such laws and regulations. Although we do not believe the current costs of managing our wastes, as presently classified, to be significant, any legislative or regulatory reclassification of oil and natural gas exploration and production wastes could increase our costs to manage and dispose of such wastes.
Water Discharges. The Federal Water Pollution Control Act of 1972, as amended, also known as the Clean Water Act (the "CWA"), the Safe Drinking Water Act (the "SDWA"), the Oil Pollution Act (the "OPA") and analogous state laws and regulations promulgated thereunder impose restrictions and strict controls regarding the unauthorized discharge of pollutants, including produced waters and other gas and oil wastes, into navigable waters of the United States, as well as state waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of certain permits issued by the EPA or an analogous state agency. Spill prevention, control and countermeasure ("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. In addition, on October 20, 2011, the EPA announced a schedule to develop pre-treatment standards for wastewater discharges produced by natural gas extraction from underground coalbed and shale formations. The EPA stated that it will gather data, consult with stakeholders, including ongoing consultation with industry, and solicit public comment on a proposed rule for coalbed methane in 2013 and a proposed rule for shale gas in 2014. Costs may be associated with the treatment of wastewater or developing and implementing storm water pollution prevention plans, as well as for monitoring and sampling the storm water runoff from certain of our facilities. Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions.
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") is the primary federal law for oil spill liability. The OPA imposes requirements on "responsible parties" related to the prevention of oil spills and liability for damages resulting from oil spills into or upon navigable waters, adjoining shorelines or in the exclusive economic zone of the United States. A "responsible party" under the OPA may include the owner or operator of an onshore facility. The OPA subjects responsible parties to strict, joint and several financial liability for removal costs and other damages, including natural resource damages, caused by an oil spill that is covered by the statute. It also imposes other requirements on responsible parties, such as the preparation of an oil spill contingency plan and maintaining certain significant levels of financial assurance to cover potential environmental cleanup and restoration costs. Failure to comply with the OPA may subject a responsible party to civil or criminal enforcement action. We may conduct operations on acreage located near, or that affects, navigable waters subject to the OPA. We believe that compliance with applicable requirements under the OPA will not have a material and adverse effect on us.
Hydraulic fracturing is a practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations. The process involves the injection of water, sand and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. Although hydraulic fracturing has historically been regulated by state oil and gas commissions the EPA recently asserted federal regulatory authority over the process under the SDWA's Underground Injection Control ("UIC") Program. Under this assertion of authority, the EPA requires facilities to obtain permits to use diesel fuel in hydraulic fracturing operations, specifically in Class II wells, which are those wells injecting fluids associated with oil and natural gas production activities. The U.S. Energy Policy Act of 2005, which exempts hydraulic fracturing from regulation under the SDWA, prohibits the use of diesel fuel in the fracturing process without a UIC permit. On May 4, 2012, the EPA published a draft UIC Program permitting guidance for oil and natural gas hydraulic fracturing activities using diesel fuel. The guidance document is designed for use by EPA UIC permit writers, and describes how Class II regulations may be tailored to address the purported unique risks of diesel fuel injection during the hydraulic fracturing process. Although EPA has delegated UIC permitting authority to many states, it is encouraging those states to review and consider use of this permit guidance. The draft guidance document underwent an extended public comment process, which concluded on August 23, 2012. The EPA is presently evaluating the public comments and will likely issue a final guidance document at a later date. On November 3, 2011, the EPA released its Plan to Study the Potential Impacts of Hydraulic Fracturing on Drinking Water Resources. The study will include both analysis of existing data and investigative activities designed to generate future data. The EPA issued a progress report in December 2012, and expects to release a final report for public comment and peer review in 2014. In addition, legislation is pending in Congress to repeal the hydraulic fracturing exemption from the SDWA, provide for federal regulation of hydraulic fracturing, and require public disclosure of the chemicals used in the fracturing process, and such legislation could be introduced in the current session of Congress. 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.
Many states have adopted, and other states are considering adopting, legislation or regulations requiring the disclosure of the chemicals used in hydraulic fracturing or otherwise restrict hydraulic fracturing in certain circumstances. For example, pursuant to legislation adopted by the State of Texas in June 2011, beginning February 1, 2012, companies were required to disclose to the Railroad Commission of Texas (the "RRC") and the public the chemical components used in the hydraulic fracturing process, as well as the volume of water used. Furthermore, on May 23, 2013, the RRC issued the "well integrity rule," which updates the RRC's Rule 13 requirements for drilling, putting pipe down, and cementing wells. The rule also includes new testing and reporting requirements, such as (i) the requirement to submit to the RRC cementing reports after well completion or after cessation of drilling, whichever is later, and (ii) the imposition of additional testing on wells less than 1,000 feet below usable groundwater. The "well integrity rule" takes effect in January 2014. 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 regularly review 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. In addition to state law, local land use restrictions, such as city ordinances, may restrict or prohibit the performance of well drilling in general and/or hydraulic fracturing in particular.
Finally, with respect to our operations that occur on federally managed public lands, on May 16, 2013, the U.S. Department of Interior ("DOI") issued a proposed rule that seeks to require companies operating on federal and Indian lands to (i) publicly disclose the chemicals used in the hydraulic fracturing process, (ii) confirm their wells meet certain construction standards and (iii) establish site plans to manage flowback water. The revised proposed rule is presently subject to an extended 90-day public comment period, which ends on August 23, 2013.
Air Emissions. Our operations are subject to federal regulations for the control of emissions from sources of air pollution under the Clean Air Act ("CAA"), as amended, and analogous state and local regulations. Federal and state laws require new and modified sources of air pollutants to obtain permits prior to commencing construction and also impose various monitoring and reporting requirements. Major sources of air pollutants are subject to more stringent, federally imposed requirements including additional permits. Federal and state laws designed to control hazardous or toxic air pollutants may require installation of additional controls. Administrative enforcement actions for failure to comply strictly with air pollution regulations or permits are generally resolved by payment of monetary fines and correction of any identified deficiencies. Alternatively, regulatory agencies could bring lawsuits for civil penalties or require us to forego construction, modification or operation of certain air emission sources.
In August 2012, the EPA adopted rules that subject oil and natural gas production, processing, transmission, and storage operations to regulation under the New Source Performance Standards, or NSPS, and National Emission Standards for Hazardous Air Pollutants, or NESHAP, programs. The rule includes NSPS standards for completions of hydraulically fractured gas wells and establishes specific new requirements for emissions from compressors, controllers, dehydrators, storage vessels, natural gas processing plants and certain other equipment. The final rule became effective October 15, 2012; however, a number of the requirements did not take immediate effect. The final rule establishes a phase-in period to allow for the manufacture and distribution of required emissions reduction technology. During the first phase, ending December 31, 2014, owners and operators of gas wells must either flare their emissions or use emissions reduction technology called "green completions" technologies already deployed at wells. On or after January 1, 2015, all newly fractured gas wells will be required to use green completions. Controls for certain storage vessels and pneumatic controllers may phase-in over one year beginning on the date the final rule is published in the Federal Register, while certain compressors, dehydrators and other equipment must comply with the final rule immediately or up to three years and 60 days after publication of the final rule, depending on the construction date and/or nature of the unit. We continue to evaluate the EPA's final rule, as it may require changes to our operations, including the installation of new emissions control equipment. These standards, as well as any future laws and their implementing regulations, may require us to obtain pre-approval for the expansion or modification of existing facilities or the construction of new facilities expected to produce air emissions, impose stringent air permit requirements, or utilize specific equipment or technologies to control emissions. Our failure to comply with these requirements could subject us to monetary penalties, injunctions, conditions or restrictions on operations and, potentially, criminal enforcement actions.
We have incurred additional capital expenditures to insure compliance with these new regulations as they come into effect. We may also be required to incur additional capital expenditures in the next few years for air pollution control equipment in connection with maintaining or obtaining operating permits addressing other air emission related issues, which may have a material adverse effect on our operations. Obtaining permits also has the potential to delay the development of oil and natural gas projects. We believe that we currently are in substantial compliance with all air emissions regulations and that we hold all necessary and valid construction and operating permits for our current operations.
Climate Change Legislation. In response to certain scientific studies suggesting that emissions of carbon dioxide, methane and other greenhouse gases ("GHGs") are contributing to the warming of the Earth's atmosphere and other climatic changes, the United States Congress has considered legislation to reduce such emissions. To date, the United States Congress has failed to enact a comprehensive GHG program. Some states, either individually or on a regional level, have considered or enacted legal measures to reduce GHG emissions. Although most of the state-level initiatives have to date focused on large sources of GHG emissions, it is possible that smaller sources of emissions could become subject to GHG emission limitations. The cost of complying with these programs could be significant.
The EPA published finding that emissions of GHGs presented an endangerment to public health and the environment. These findings by the EPA allowed the agency to proceed through a rule-making process with the adoption and implementation of regulations that would restrict emissions of GHGs under existing provisions of the CAA. Consequently, the EPA adopted two sets of regulations that would require a reduction in emissions of GHGs from motor vehicles and could trigger permit review for GHG emissions from certain stationary sources. The EPA adopted the stationary source rule (or the "tailoring rule") in May 2010, and it also became effective January 2011, although it remains the subject of several pending lawsuits filed by industry groups. The tailoring rule establishes new GHG emissions thresholds that determine when stationary sources must obtain permits under the Prevention of Significant Deterioration, or PSD, and Title V programs of the Clean Air Act. The permitting requirements of the PSD program apply only to newly constructed or modified major sources. Obtaining a PSD permit requires a source to install best available control technology, or BACT, for those regulated pollutants that are emitted in certain quantities. Phase I of the tailoring rule, which became effective on January 2, 2011, requires projects already triggering PSD permitting that are also increasing GHG emissions by more than 75,000 tons per year to comply with BACT rules for their GHG emissions. Phase II of the tailoring rule, which became effective on July 1, 2011, requires preconstruction permits using BACT for new projects that emit 100,000 tons of GHG emissions per year or existing facilities that make major modifications increasing GHG emissions by more than 75,000 tons per year. Phase III of the tailoring rule, which is expected to go into effect in 2013, will seek to streamline the permitting process and permanently exclude smaller sources from the permitting process. Finally, in October 2009, the EPA issued a final rule requiring the reporting of GHG emissions from specified large GHG emission sources in the U.S., including natural gas liquids fractionators and local natural gas/distribution companies, beginning in 2011 for emissions occurring in 2010. In November 2010, the EPA published a final rule expanding the GHG reporting rule to include onshore oil and natural gas production, processing, transmission, storage and distribution facilities. This rule requires reporting of GHG emissions from such facilities on an annual basis, with reporting beginning in 2012 for emissions occurring in 2011. On March 27, 2012, the EPA issued a proposed rule establishing carbon pollution standards for new fossil-fuel-fired electric utility generating units. The proposed rule underwent an extended public comment process, which concluded on June 25, 2012. The EPA is presently evaluating the public comments and is expected to issue a final rule at a later date. The EPA plans to implement GHG emissions standards for refineries at a later date. The adoption and implementation of any regulations imposing reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations or could adversely affect demand for the oil and natural gas we produce. Any one of these climate change regulatory and legislative initiatives could have a material adverse effect on our business, financial condition and results of operations.
Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth's atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts and floods and other climatic events; if any such effects were to occur, they could have a material adverse effect on our business and results of operations.
OSHA and Other Laws and Regulations on Employee Health and Safety. To the extent not preempted by other applicable laws, we are subject to the requirements of the Occupational Safety and Health Act ("OSHA") and comparable state statutes, where applicable. These laws and the implementing regulations strictly govern the protection of the health and safety of employees. The OSHA hazard communication standard, the EPA community right-to-know regulations under the Title III of CERCLA and similar state statutes, where applicable, require us to organize and maintain information about hazardous materials used or, as applicable, produced in our operations and that this information be provided to employees, state and local government authorities and, where applicable, citizens. OSHA may enforce workplace safety regulations through issuance of citations for violations of its standards, which include, but are not limited to, those regarding hazard communication, personal protective equipment, general environmental controls, and materials handling and storage. We believe that we are in substantial compliance with these requirements where applicable and with other applicable OSHA and comparable requirements.
National Environmental Policy Act. Oil and natural gas exploration and production activities on federal lands may be subject to the National Environmental Policy Act ("NEPA") which requires federal agencies, including the U.S. Department of the Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an Environmental Assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. All of our current exploration and production activities, as well as proposed exploration and development plans, on federal lands require governmental permits that are subject to the requirements of NEPA. This process has the potential to delay or impose additional conditions upon the development of oil and natural gas projects.
Endangered Species Act. The Endangered Species Act, as amended (the "ESA"), and analogous state statutes restrict activities that may affect endangered and threatened species or their habitats. While some of our facilities may be located in areas that are designated as habitat for endangered or threatened species, we believe that we are in substantial compliance with the ESA. However, the designation of previously unidentified endangered or threatened species could cause us to incur additional costs or become subject to operating restrictions or bans in the affected areas.
Other Regulation of the Oil and Natural Gas Industry
The oil and natural gas industry is extensively regulated by numerous federal, state and local authorities. In particular, oil and natural gas production and related operations are, or have been, subject to price controls, taxes and numerous other laws and regulations. These laws and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability.
Failure to comply with applicable laws and regulations can result in substantial penalties and possibly cessation of drilling and production operations. The regulatory burden on the industry increases the cost of doing business and affects profitability. We believe that we are in substantial compliance with existing requirements and such compliance will not have a material adverse effect on our financial condition, cash flows or results of operations. Nevertheless, such laws and regulations are frequently amended or reinterpreted. Therefore, we are unable to predict the future costs or impact of compliance. Additional proposals and proceedings that affect the oil and natural gas industry are regularly considered by the United States Congress, the states, the Federal Energy Regulatory Commission ("FERC") and the courts. We cannot predict when or whether any such proposals may become effective.
Drilling and Production. Our operations are subject to various types of regulation at the federal, state and local levels. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. The states and some counties and municipalities in which we operate also regulate one or more of the following:
| | ● | the location of wells; |
| | | |
| | ● | the method of drilling and casing wells; |
| | | |
| | ● | the surface use and restoration of properties upon which wells are drilled; and |
| | | |
| | ● | the plugging and abandonment of wells. |
State laws, including Texas, regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploitation while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and natural gas we can produce from our wells or limit the number of wells or the locations at which we can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil and natural gas within its jurisdiction.
In addition, 11 states have enacted surface damage statutes ("SDAs"). These laws are designed to compensate for damage caused by mineral development. Most SDAs contain entry notification and negotiation requirements to facilitate contact between operators and surface owners and users. Most also contain bonding requirements and specific expenses for exploration and producing activities. Costs and delays associated with SDAs could impair operational effectiveness and increase development costs.
We do not control the availability of transportation and processing facilities used in the marketing of our production. For example, we may have to shut-in a productive natural gas well because of a lack of available natural gas gathering or transportation facilities.
If we conduct operations on federal, state or Indian oil and natural gas leases, these operations must comply with numerous regulatory restrictions, including various non-discrimination statutes, royalty and related valuation requirements, and certain of these operations must be conducted pursuant to certain on-site security regulations and other appropriate permits issued by the United States Department of the Interior Bureau of Land Management (the "BLM"), 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. The transportation of natural gas in interstate commerce by pipelines, and the sale for resale of natural gas in interstate commerce by pipelines or their affiliates and local distribution companies or their affiliates, are regulated by the FERC under the Natural Gas Act of 1938 (the "NGA"), the Natural Gas Policy Act of 1978 (the "NGPA"), and regulations issued under those statutes. In the past, the federal government has regulated the prices at which natural gas could be sold. While sales by producers of natural gas can currently be made at market prices (subject to anti-manipulation rules, which are discussed below), the United States Congress could reenact price controls in the future. Deregulation of wellhead natural gas sales began with the enactment of the NGPA and culminated in adoption of the Natural Gas Wellhead Decontrol Act which removed all price controls affecting wellhead sales of natural gas (so-called "first sales") effective January 1, 1993.
FERC regulates interstate natural gas transportation rates, and terms and conditions of service, and this regulation affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas. Since 1985, the FERC has endeavored to make natural gas transportation more accessible to natural gas buyers and sellers on an open and non-discriminatory basis. The FERC has stated that open access policies are necessary to improve the competitive structure of the interstate natural gas pipeline industry and to create a regulatory framework that will put natural gas sellers into more direct contractual relations with natural gas buyers by, among other things, unbundling the sale of natural gas from the sale of transportation and storage services. Beginning with Order No. 636 in 1992, FERC adopted mandatory open access policies including mandatory standards of conduct governing communications and information sharing between affiliated natural gas transportation and gas marketing employees. As a result, the interstate pipelines' traditional role of providing the sale and transportation of natural gas as a single service has been eliminated and replaced by a structure under which pipelines provide transportation and storage service on a non-discriminatory, open access basis to others who buy and sell natural gas. Although the FERC's open access orders do not directly regulate natural gas producers, they are intended to foster increased competition within all phases of the natural gas industry.
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.
FERC has jurisdiction under the NGA over some (but not all) sales for resale of physical gas. FERC has issued blanket certificates under the NGA that pre-authorize various sales for resale in interstate commerce. These blanket certificates preauthorize interstate sales for resale automatically, without the need to apply for the certificate, and without any conditions as to the price, purchaser, volume, term or other economic conditions of the sale. The blanket certificates also pre-authorize abandonment of the sale under the NGA upon expiration of the contract term or termination of the individualized sales arrangement. However, FERC retains NGA jurisdiction over all blanket certificate sales, meaning that FERC has the ability to add prospective terms and conditions to such certificates as future conditions warrant. FERC first exercised this authority in 2003, when in the wake of the market upheavals in California, FERC established a gas marketing "code of conduct" applicable to all blanket certificate sellers. The code of conduct for blanket certificate sellers includes price reporting provisions intended to address the problems that surfaced in gas markets concerning false transaction reports designed to manipulate price indices published by various publications. The code of conduct's price reporting provision does not require any seller to report transactions to a publisher of natural gas price indices, but requires that any seller who chooses to do so must provide accurate information, not knowingly submit false or misleading information, or omit material information. Blanket certificate holders who violate the certificate conditions (including the code of conduct) are subject to potential suspension or revocation of the certificate. All blanket certificate sellers are subject to the regulatory risk associated with future FERC action to prescribe new conditions for transactions conducted under the certificate.
Pursuant to FERC Order No. 704, some of our operations may be required to annually report to the FERC on May 1 of each year for the previous calendar year. Order No. 704 has its genesis in the Energy Policy Act of 2005, which added section 23 of the Natural Gas Act (NGA). Section 23 of the NGA, among other things, directs FERC "to facilitate price transparency in markets for the sale or transportation of physical natural gas in interstate commerce, having due regard for the public interest, the integrity of those markets, and the protection of consumers." Order No. 704 requires market participants with reportable physical natural gas purchases or sales equal to or greater than 2.2 trillion British Thermal Units must comply with the reporting requirements. Reportable physical natural gas purchases include physical natural gas transactions that use an index or that contribute to or may contribute to the formation of a gas index.
The Energy Policy Act of 2005 amended the Natural Gas Act to give FERC authority to assess civil penalties to any person that violates the Natural Gas Act or any rule, regulation, restriction, condition, or order under the Act. Such penalties may be up to $1 million per day per violation. This significantly adds to the risk of FERC-regulated companies that violate the NGA or rules or orders thereunder as well as to non-regulated entities that directly or indirectly manipulate the purchase or sale of FERC-regulated natural gas or the purchase or sale of FERC-regulated transportation services. See "—Other Federal Laws and Regulations Affecting Our Industry—Energy Policy Act of 2005."
Gathering services, which occur upstream of FERC jurisdictional gas transmission services, are regulated by the states. In addition, intrastate natural gas transportation and facilities are also subject to regulation by state regulatory agencies, and certain transportation services provided by intrastate pipelines are also regulated by the FERC. The basis for regulation of intrastate natural gas transportation and gathering and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline and gathering pipeline rates and services varies from state to state. Insofar as such regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable basis, we believe that the regulation of similarly situated intrastate natural gas transportation in any states in which we operate and ship natural gas on an intrastate basis will not affect our operations in any way that is of material difference from those of our competitors. Like the regulation of interstate transportation rates, the regulation of intrastate transportation rates affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas.
State Natural Gas Regulation. Various states, including Texas, regulate the drilling for, and the production, gathering and sale of, natural gas, including imposing severance taxes and requirements for obtaining drilling permits. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of natural gas resources. States may regulate rates of production and may establish maximum daily production allowables from natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but there can be no assurance that they will not do so in the future. The effect of these regulations may be to limit the amounts of natural gas that may be produced from our wells and to limit the number of wells or locations we can drill.
Other Federal Laws and Regulations Affecting Our Industry
Energy Policy Act of 2005. On August 8, 2005, President Bush signed into law the Energy Policy Act of 2005 (the "EPAct 2005"). The EPAct 2005 is a comprehensive compilation of tax incentives, authorized appropriations for grants and guaranteed loans, and significant changes to the statutory policy that affects all segments of the energy industry. Among other matters, the EPAct 2005 amends the NGA to add an anti-manipulation provision which makes it unlawful for any entity to engage in prohibited behavior to be prescribed by the FERC, and furthermore provides the FERC with additional civil penalty authority. The EPAct 2005 provides the FERC with the power to assess civil penalties of up to $1.0 million per day for violations of the NGA and increases the FERC's civil penalty authority under the NGPA from $5,000 per violation per day to $1.0 million per violation per day. On January 19, 2006, the FERC issued Order No. 670, a rule that implements the anti-manipulation provision of the EPAct 2005 and makes it unlawful for any entity, directly or indirectly, in connection with the purchase or sale of natural gas subject to the jurisdiction of the FERC, or the purchase or sale of transportation services subject to the jurisdiction of the FERC: (1) to use or employ any device, scheme or artifice to defraud; (2) to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or (3) to engage in any act, practice, or course of business that operates as a fraud or deceit upon any person. The anti-manipulation rules and enhanced civil penalty authority reflect an expansion of the FERC's NGA enforcement authority. Should we fail to comply with all applicable FERC administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines.
Executive Officers of the Registrant
| | | | |
| Alan W. Barksdale | | 36 | | President, Chief Executive Officer and Director |
| Michael R. Uffman | | 37 | | Chief Financial Officer |
| Hilda D. Kouvelis | | 50 | | Chief Accounting Officer and Executive Vice President |
| Tommy W. Folsom | | 59 | | Executive Vice President and Director of Exploration and Production of RMR Operating, LLC |
Alan W. Barksdale has been our President, Chief Executive Officer and a director since June 2011 and served as our Interim Acting Chief Financial Officer from June 2011 to August 2011. Mr. Barksdale has also served as President of Black Rock Capital, Inc., our wholly owned subsidiary, since its inception. Mr. Barksdale has also been the owner and president of The StoneStreet Group, Inc. and president and manager of StoneStreet Operating Company, LLC ("StoneStreet Operating"), advisory and management services and merchant banking firms, since 2008. Mr. Barksdale has also been the president of AWB Enterprises, Inc., a holding company that owns a percentage of StoneStreet, since November 2011. From January 2004 to April 2010, Mr. Barksdale served as a director in the Capital Markets Group of Crews & Associates, an investment banking firm. From August 2003 to October 2003, Mr. Barksdale served as an investment banker at Stephens Inc., an investment banking firm. From 2002 to 2003, Mr. Barksdale was an investment banker at Crews & Associates. Mr. Barksdale has served as the non-executive chairman of the board for Cross Border Resources, Inc., an oil and gas exploration company, since May 2012. We believe that Mr. Barksdale's experience in operating, managing, financing and investing in more than 100 wells in Louisiana, Mexico and Texas, combined with his over ten years of capital markets experience and contacts and relationships, provides our Board of Directors with 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.
Michael R. Uffman has served as our Chief Financial Officer since November 2012. His extensive investment banking background includes years of experience advising companies on equity and debt capital markets, investor relations, and assisting in the acquisition and divestiture of assets, all in the exploration and production space. Throughout his career, Mr. Uffman has assisted clients raise more than $5 billion in the energy space. From January 2012 until December 2012, Mr. Uffman served as a Managing Director of Global Hunter Securities, LLC, a full service, natural resource focused investment banking firm. From July 2010 to December 2011, Mr. Uffman served as Director of Oil and Gas Business Development for Louisiana Economic Development, which is responsible for strengthening Louisiana's business environment and creating a more vibrant economy in the state. From May 2007 to June 2010, Mr. Uffman served as Director of Energy Investment Banking for Dahlman Rose & Company, a research-driven investment bank focused internationally on the commodity supply chain. From 2002 to 2007, Mr. Uffman served as Vice President of Energy Investment Banking at Capital One Southcoast, Inc., an energy investment banking boutique. From 2000 to 2002, Mr. Uffman served in External Audit at KPMG, LLP.
Hilda D. Kouvelis has served as our Chief Accounting Officer since February 2012 and was appointed Executive Vice President in July 2012. Ms. Kouvelis has more than 25 years of industry accounting and finance experience. From January 2005 until June 2011, she was employed with TransAtlantic Petroleum Ltd., an international oil and natural gas company engaged in the acquisition, exploration, development and production of oil and natural gas, serving as its Chief Financial Officer from January 2007 until April 2011 and as its Vice President from May 2007 to April 2011. She also served as its controller from January 2005 to January 2007. Prior to joining TransAtlantic Petroleum, Ms. Kouvelis served as Controller for Ascent Energy, Inc. from 2001 to 2004 and as Financial Controller for the international operations at the headquarters of PetroFina, S.A. in Brussels, Belgium from 1998 through 2000.
Tommy W. Folsom has been Executive Vice President and Director of Exploration and Production of RMR Operating, LLC, our wholly owned subsidiary, since August 2012 and served as our Executive Vice President and Director of Exploration and Production from September 2011 to August 2012. Mr. Folsom is the founder of Enerstar Resources O & G, LLC ("Enerstar"), an oil company involved in the drilling, re-completion, re-entry and acquisition of properties and leases in the United States, and has served as its President since its formation in 1994. From 1996 to August 2011, Mr. Folsom served as the Operations Manager of Murchison Oil and Gas, Inc., a privately-held independent oil and gas company engaged in the acquisition, development and production of oil and gas resources in the United States.
Risks Related to Our Business
Our Credit Agreement contains various covenants that limit our management's discretion in the operation of our business and can lead to an event of default that may adversely affect our business, financial condition and results of operations.
The operating and financial restrictions and covenants in our Credit Agreement may adversely affect our ability to finance future operations or capital needs or to engage in other business activities. The Credit Agreement contains various covenants that restrict our ability to, among other things, incur liens, incur additional indebtedness, enter into mergers, sell assets, make investments and pay dividends.
The Credit Agreement also requires us to maintain specified financial ratios. We were not in compliance with one or more of the financial ratios in the Credit Agreement at February 28, 2013 and May 31, 2013. In each case, the Lender waived the non-compliance, but the Lender may not waive future defaults. In addition, various risks, uncertainties and events beyond our control could affect our ability to comply with the covenants and financial ratios required by the Credit Agreement and could result in an event of default under the Credit Agreement.
Amounts outstanding under the Credit Facility may be accelerated and become immediately due and payable upon specified events of default of Borrowers, including, among other things, a default in the payment of principal, interest or other amounts due under the Credit Facility, certain loan documents or hydrocarbon hedge agreements, a material inaccuracy of a representation or warranty, a default with regard to certain loan documents which remains unremedied for a period of 30 days following notice, a default in the payment of other indebtedness of the Borrowers of $200,000 or more, bankruptcy or insolvency, certain changes in control, failure of the Lender's security interest in any portion of the collateral with a value greater than $500,000, cessation of any security document to be in full force and effect, or Alan Barksdale ceasing to be Red Mountain's Chief Executive Officer or Chairman of Cross Border and not being replaced with an officer acceptable to the Lender within 30 days.
In the event of a default and acceleration of indebtedness under the Credit Facility, our business, financial condition and results of operations may be materially and adversely affected.
We will need to raise additional capital to fully fund our planned exploration and development activities for fiscal 2014.
We plan to spend approximately $39.5 million during fiscal 2014 to drill and complete wells or re-enter and complete wells, most of which will be spent in the Permian Basin. As of September 13, 2013, we do not have sufficient funds for our planned fiscal 2014 exploration and development activities and will need to raise between $5.0 million and $10.0 million to fully fund our fiscal 2014 development plan. If we are unable to raise these additional funds, we may be forced to curtail or suspend our planned exploration and development activities.
Our business is difficult to evaluate because we have a limited operating history.
Prior to June 2010, we had no material operations. After our June 2010 acquisition of oil and natural gas properties in Zapata County and Duval County in the onshore Gulf Coast of Texas, we began to recognize revenue from our operations. Accordingly, we have a very short financial operating history and incurred a net loss attributable to Red Mountain Resources of $12.2 million during the fiscal year ended May 31, 2013. As a result, there is only limited historical financial and operating information available upon which to base your evaluation of our performance.
We may have difficulty managing growth in our business, which could adversely affect our financial condition and results of operations.
As a recently-formed company, growth in accordance with our business plan, if achieved, could place a significant strain on our financial, technical, operational and management resources. As we expand our activities, increase the number of projects we are evaluating or in which we participate and integrate Cross Border, 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.
Our producing properties are concentrated in the Permian Basin of Southeast New Mexico and West Texas, making us vulnerable to risks associated with operating in one major geographic area. In addition, we have a large amount of proved reserves attributable to a small number of producing horizons within this area.
Our producing properties are geographically concentrated in the Permian Basin of Southeast New Mexico and West Texas. At May 31, 2013, approximately 89% of our proved reserves were concentrated in this area. Additionally, for the fiscal year ended May 31, 2013, we derived 79% of our revenues from this area. As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, processing or transportation capacity constraints, market limitations, water shortages or other drought related conditions or interruption of the processing or transportation of oil, natural gas or natural gas liquids.
In addition to the geographic concentration of our producing properties described above, at May 31, 2013, approximately (i) 27% of our proved reserves were attributable to the Brushy Canyon formation in the Madera Prospect, (ii) 15% of our proved reserves were attributable to the San Andres formation in the Tom Tom Prospect and (iii) 15% of our proved reserves were attributable to the Bone Spring formation in the Lusk Prospect. This concentration of assets within a small number of producing horizons exposes us to additional risks, such as changes in field-wide rules and regulations that could cause us to permanently or temporarily shut-in all of our wells within a field.
A substantial or extended decline in oil and natural gas prices may adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments.
The price we receive for our oil and natural gas will heavily influence our revenue, profitability, access to capital and future rate of growth. Oil and natural gas are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil and natural gas have been volatile. These markets will likely continue to be volatile in the future. The prices we receive for our production depend on numerous factors beyond our control. These factors include the following:
| | ● | worldwide and regional economic conditions impacting the global supply and demand for oil and natural gas; |
| | | |
| | ● | the price and quantity of imports of foreign oil and natural gas; |
| | | |
| | ● | the actions of the Organization of Petroleum Exporting Countries, or OPEC, and other state-controlled oil companies relating to oil and natural gas price and production control; |
| | | |
| | ● | political conditions in or affecting other oil-producing and natural gas-producing countries, including the current conflicts in the Middle East and conditions in South America and Russia; |
| | | |
| | ● | the level of global oil and natural gas inventories; |
| | | |
| | ● | localized supply and demand fundamentals; |
| | | |
| | ● | the availability of refining capacity; |
| | | |
| | ● | price and availability of transportation and pipeline systems with adequate capacity; |
| | ● | weather conditions and natural disasters; |
| | | |
| | ● | governmental regulations; |
| | | |
| | ● | speculation as to the future price of oil and natural gas and the speculative trading of oil and natural gas futures contracts; |
| | | |
| | ● | price and availability of competitors' supplies of oil and natural gas; |
| | | |
| | ● | energy conservation and environmental measures; |
| | | |
| | ● | technological advances affecting energy consumption; |
| | | |
| | ● | the price and availability of alternative fuels and energy sources; and |
| | | |
| | ● | domestic and international drilling activity. |
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. There can be no assurance that the prices of oil and natural gas will increase in the future. If oil and natural gas prices decline, (i) our net cash flow attributable to current production will decline, (ii) our exploration and development activity may decline as some investments may become uneconomic and are either delayed or eliminated, and (iii) the value of proved developed producing reserves and proved undeveloped reserves could decline. It is impossible to predict future oil and natural gas price movements, and declines in oil and natural gas prices could have a material adverse effect on our liquidity and financial condition.
Properties that we acquire may not produce as projected, and we may be unable to accurately predict reserve potential, identify liabilities associated with the properties or obtain protection from sellers against such liabilities.
As part of our growth strategy, we intend to acquire additional interests in oil and natural gas properties. Any future acquisitions will require an assessment of recoverable reserves, title, future oil and natural gas prices, operating costs, potential environmental hazards and liabilities, potential tax and Employee Retirement Income Security Act liabilities, and other liabilities and other similar factors. Generally, it is not feasible for us to review in detail every individual property involved in an acquisition, and our review efforts are normally focused on the higher-valued properties. Even a detailed review of properties and records may not reveal existing or potential problems, nor will it permit us to become sufficiently familiar with the properties to assess fully their deficiencies and capabilities. We do not inspect every well that we acquire. Potential problems, such as deficiencies in the mechanical integrity of equipment or environmental conditions that may require significant remedial expenditures, are not necessarily observable even when we inspect a well. Any unidentified problems could result in material liabilities and costs that negatively impact our financial condition and results of operations.
Even if we are able to identify problems with an acquisition, the seller may be unwilling or unable to provide effective contractual protection or indemnity against all or part of these problems. Even if a seller agrees to provide indemnity, the indemnity may not be fully enforceable and may be limited by floors and caps on such indemnity. In addition, we may acquire oil and natural gas properties that contain commercially productive reserves which are less than predicted. Any of these factors could have a material adverse effect on our results of operations and reserve growth.
Our failure to successfully identify, complete and integrate future acquisitions of properties or businesses could reduce our earnings and slow our growth.
There is intense competition for acquisition opportunities in our industry. Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions. Our ability to complete acquisitions is dependent upon, among other things, our ability to obtain debt and equity financing and, in some cases, regulatory approvals. Further, these acquisitions may be in geographic regions in which we do not currently operate, which could result in unforeseen operating difficulties and difficulties in coordinating geographically dispersed operations, personnel and facilities. In addition, if we enter into new geographic markets, we may be subject to additional and unfamiliar legal and regulatory requirements. Compliance with regulatory requirements may impose substantial additional obligations on us and our management, cause us to expend additional time and resources in compliance activities and increase our exposure to penalties or fines for non-compliance with such additional legal requirements. Completed acquisitions could require us to invest further in operational, financial and management information systems and to attract, retain, motivate and effectively manage additional employees. The inability to effectively manage the integration of acquisitions could reduce our focus on subsequent acquisitions and current operations, which, in turn, could negatively impact our earnings and growth. Our financial position and results of operations may fluctuate significantly from period to period, based on whether or not significant acquisitions are completed in particular periods.
We cannot control the development of the properties we do not operate, which may adversely affect our production, revenues and results of operations.
We do not operate all of the properties in which we have an interest. As a result, we have limited ability to exercise influence over, and control the risks associated with, the operation of these properties. The success and timing of our drilling and development activities on those properties depend upon a number of factors outside of our control, including:
| | ● | the timing and amount of capital expenditures; |
| | | |
| | ● | the operators' expertise and financial resources; |
| | | |
| | ● | the approval of other participants in drilling wells; and |
| | | |
| | ● | the selection of suitable technology. |
As a result of any of the above or an operator's failure to act in ways that are in our best interest, our allocated production revenues and results of operations could be adversely affected.
We could suffer the loss of all or part of the expenses that we prepay to the operators of our properties.
We may be required prepay to the operators of our properties our contractual share of acreage, geophysical and geological costs and other up-front expenses, and drilling and completion costs, on a well-by-well basis. Once a prepayment is made, the operator is under no requirement to keep such funds segregated from funds received by other working interest owners. As a result of any prepayment, we would become a general unsecured creditor of the operator and, therefore, could suffer the loss of all or part of the amount prepaid in the event that an operator has financial difficulties, liens are placed against the operator's assets or the operator files for bankruptcy.
Drilling for and producing oil and natural gas are speculative activities and involve numerous risks and substantial and uncertain costs that could adversely affect us.
Our future financial condition and results of operations will depend on the success of our acquisition, exploitation, development and production activities. Our oil and natural gas exploration and production activities are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially productive oil or natural gas reservoirs. Our decisions to acquire, explore, develop or otherwise exploit drilling locations or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. In addition, our cost of drilling, completing and operating wells is often uncertain before drilling commences. Overruns in budgeted expenditures are common risks that can make a particular project uneconomical. Further, many factors may curtail, delay or cancel our scheduled drilling projects, including the following:
| | ● | shortages of or delays in obtaining equipment and qualified personnel; |
| | | |
| | ● | facility or equipment malfunctions; |
| | | |
| | ● | unexpected operational events; |
| | | |
| | ● | pressure or irregularities in geological formations; |
| | | |
| | ● | adverse weather conditions, such as flooding; |
| | | |
| | ● | reductions in oil and natural gas prices; |
| | | |
| | ● | delays imposed by or resulting from compliance with regulatory requirements; |
| | | |
| | ● | proximity to and capacity of transportation facilities; |
| | | |
| | ● | title problems; |
| | | |
| | ● | limitations in the market for oil and natural gas; and |
| | | |
| | ● | costs and availability of drilling rigs, equipment, supplies, personnel and oilfield services. |
Even if drilled, our completed wells may not produce reserves of oil or natural gas that are commercially productive or that meet our earlier estimates of economically recoverable reserves. A productive well may become uneconomic if water or other deleterious substances are encountered, which impair or prevent the production of oil and/or natural gas from the well. Our overall drilling success rate or our drilling success rate for activity within a particular project area may decline. Unsuccessful drilling activities could result in a significant decline in our production and revenues and materially harm our operations and financial condition by reducing our available cash and resources.
Reserve estimates depend on many assumptions that may turn out to be inaccurate.
The calculation of reserves and estimating reserves are inherently imprecise. The accuracy of any reserve estimate is a function of the quality of available data, engineering interpretation and judgment and the assumptions used regarding the quantities of recoverable oil and natural gas and the future prices of oil and natural gas. Petroleum engineers consider many factors and make many assumptions in estimating reserves. Those factors and assumptions include, but are not limited to, the following: historical production from the area compared with production rates from similarly situated producing areas; the effects of governmental regulation; assumptions about future commodity prices, production and taxes; the availability of enhanced recovery techniques; and relationships with landowners, working interest partners, pipeline companies and others.
Any material inaccuracies in our reserve estimates or underlying assumptions could materially affect the quantities and present values of our reserves. The process of estimating oil and natural gas reserves is complex. It requires interpretations of available technical data and various assumptions, including assumptions relating to economic factors. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities of reserves and amount of PV-10 and standardized measure that we may report. The process of preparing these estimates requires the projection of production rates and timing of development expenditures and analysis of available geological, geophysical, production and engineering data, and the extent, quality and reliability of this data can vary. The process also requires economic assumptions relating to matters such as oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds.
Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves most likely will vary from our estimates. Any significant variance could materially affect the estimated quantities of reserves and amount of PV-10 and standardized measure that we may report. In addition, we may adjust estimates of proved reserves and amount of PV-10 and standardized measure to reflect production history, results of exploration and development, prevailing oil and natural gas prices and other factors, many of which are beyond our control. Moreover, there can be no assurance that our reserves will ultimately be produced or that our proved undeveloped reserves will be developed within the periods anticipated. Any significant variance in the assumptions could materially affect the estimated quantity of our reserves and amount of PV-10 and standardized measure.
Investors should not assume that the PV-10 of our proved reserves is the current market value of our estimated oil and natural gas reserves. PV-10 is based on prices and costs in effect on the date of the estimate. Actual future prices, costs, and the volume of produced reserves may differ materially from those used in the PV-10 estimate.
Approximately 46% of our total estimated proved reserves as of May 31, 2013 were classified as proved undeveloped and may not be ultimately developed or produced.
As of May 31, 2013, approximately 46% of our total estimated proved reserves were undeveloped. Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations. The future drilling of proved undeveloped reserves is highly dependent upon our ability to fund our capital expenditures, which we estimate will be approximately $39.5 million for fiscal 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.
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.
We could lose leases on certain of our properties unless production is established and maintained on units containing the acreage or the leases are extended.
Oil and natural gas leases generally must be drilled before the end of the lease term or the leaseholder will lose the lease and any capital invested therein. In addition, leases may also be lost due to legal issues relating to the ownership of leases. Any delays in drilling or legal issues causing us to lose leases on properties could have a material adverse effect on our results of operations and reserve growth.
At May 31, 2013, of our total undeveloped leasehold acreage, 24.4% is currently not held by production and will expire during fiscal 2015 or fiscal 2016 unless production in paying quantities is established and maintained on units containing these leases during their primary terms or we obtain extensions of the leases. If our leases expire, we will lose our right to develop the related properties.
Our drilling plans for these areas are subject to change based upon various factors, including factors that are beyond our control. Such factors include drilling results, oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, gathering system and pipeline transportation constraints, and regulatory approvals.
Our operations could be impacted by burdens and encumbrances on title to our properties.
Our leasehold acreage may be subject to existing oil and natural gas leases, liens for current taxes and other burdens, including other mineral encumbrances and restrictions customary in the oil and natural gas industry, that should not materially interfere with the use or otherwise affect the value of such properties. However, we cannot guarantee that we have or will have clear and unobstructed title to leases or other rights assigned to us. We also cannot guarantee that the mineral encumbrances and restrictions mentioned above will not materially interfere with the use of or affect the value of leasehold acreage. Any cloud on the title of the working interests, leases and other rights owned by us could have a material adverse effect on our operations.
Prospects that we decide to drill may not yield oil or natural gas in commercially viable quantities.
Prospects that we decide to drill that do not yield oil or natural gas in commercially productive quantities will adversely affect our financial condition and results of operations. Our prospects are in various stages of evaluation, and may range from a prospect which is ready to drill to a prospect that will require substantial additional seismic data processing and interpretation and other technical analysis. There is no way to predict in advance of drilling and testing whether any particular prospect will yield oil or natural gas in sufficient quantities to recover drilling or completion costs or to be commercially productive. The use of seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in commercial quantities. We cannot assure you that the analogies we draw from available data from other wells, more fully explored prospects or producing fields will be applicable to our drilling prospects.
Market conditions or transportation impediments may hinder access to oil and natural gas markets or delay production.
Market conditions, the unavailability of satisfactory oil and natural gas transportation or the remote location of our drilling operations may restrict our access to oil and natural gas markets or delay production. The availability of a ready market for oil and natural gas production depends on a number of factors, including the demand for and supply of oil and natural gas, the proximity of reserves to pipelines or trucking and terminal facilities and the availability of trucks and other transportation equipment. We may be required to shut-in wells or delay initial production for lack of a viable market or because of inadequacy or unavailability of pipeline or gathering system capacity. When that occurs, we will be unable to realize revenue from those wells until the production can be tied to a gathering system. This can result in considerable delays from the initial discovery of a reservoir to the actual production of the oil and natural gas and realization of revenues.
Delays in obtaining permits by us for our operations could impact our business.
We are required to obtain permits from one or more governmental agencies in order to perform drilling and completion activities, including hydraulic fracturing. Such permits are typically required by state agencies, but can also be required by federal and local governmental agencies. As with all governmental permitting processes, there is a degree of uncertainty as to whether a permit will be granted, the time it will take for a permit to be issued, and the conditions which may be imposed in connection with the granting of the permit. Hydraulic fracturing activities, which we estimate will represent approximately 40% of our forecasted development costs for fiscal 2014, 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. To our knowledge, 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 could contain currently unknown contamination that could expose us to governmental requirements or claims relating to environmental remediation, personal injury and/or property damage. These conditions could expose us to liability for personal injury, wrongful death, property damage, loss of oil and natural gas production, pollution and other environmental damages and could materially impair our profitability, competitive position or viability. Depending on the frequency and severity of such liabilities or losses, it is possible that our operating costs, insurability and relationships with employees and regulators could be materially impaired.
Our business and operations may be adversely affected by regulations affecting the oil and natural gas industry.
Our business and operations are subject to and impacted by a wide array of federal, state, and local laws and regulations on the exploration for and development, production, and marketing of oil and natural gas, the operation of oil and natural gas wells, taxation, and environmental and safety matters. Many laws and regulations require drilling permits and govern the spacing of wells, rates of production, prevention of waste and other matters. From time to time, regulatory agencies have imposed price controls and limitations on production in order to conserve supplies of oil and natural gas. In addition, the production, handling, storage, transportation and disposal of oil and natural gas, byproducts thereof and other substances and materials produced or used in connection with oil and natural gas operations are subject to regulation under federal, state and local laws and regulations.
Currently, federal regulations provide that drilling fluids, produced waters and other wastes associated with the exploration, development or production of oil and natural gas are exempt from regulation as "hazardous waste." From time to time, legislation has been proposed to eliminate or modify this exemption. Should the exemption be modified or eliminated, wastes associated with oil and natural gas exploration and production would be subject to more stringent regulation. On the federal level, operations on our properties may be subject to various federal statutes, including the Natural Gas Act, the Comprehensive Environmental Response, Compensation and Liability Act, the Solid Waste Disposal Act, as amended by the Resource Conservation and Recovery Act, the Clean Air Act, the Federal Water Pollution Control Act and the Oil Pollution Act, as well as by regulations promulgated pursuant to these actions.
These regulations may subject us to increased operating costs and potential liability associated with the use and disposal of hazardous materials. These laws and regulations may have a material adverse effect on our financial condition and results of operations as there can be no assurance that we will not be required to make material expenditures in the future. Moreover, the technical requirements of these laws and regulations are becoming increasingly stringent, complex and costly to implement. The high cost of compliance with applicable regulations may cause us to limit or discontinue our operation and development activities.
Changes in regulations and laws relating to the oil and natural gas industry could result in our operations being disrupted or curtailed by government authorities. For example, oil and natural gas exploration and production may become less cost effective and decline as a result of increasingly stringent environmental requirements (including land use policies responsive to environmental concerns and delays or difficulties in obtaining environmental permits). A decline in exploration and production, in turn could have a material adverse effect on our business, financial condition, results of operations and cash flows.
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. Weather related risks include earthquakes, hurricanes and other adverse weather and environmental conditions. The occurrence of one or more of these events could result in a decrease in production of oil and natural gas. Repercussions of natural disasters or severe weather conditions may include:
| | ● | evacuation of personnel and curtailment of operations; |
| | | |
| | ● | damage to drilling rigs or other facilities, resulting in suspension of operations; |
| | | |
| | ● | inability to deliver materials to worksites; and |
| | | |
| | ● | damage to pipelines and other transportation facilities. |
In addition, our hydraulic fracturing operations require significant quantities of water. Texas recently has experienced drought conditions. Any diminished access to water for use in hydraulic fracturing, whether due to usage restrictions or drought or other weather conditions, could curtail our operations or otherwise result in delays in operations or increased costs.
Operating hazards, natural disasters or other interruptions of our operations could result in potential liabilities, which may not be fully covered by our insurance.
The oil and natural gas business generally, and our operations specifically, are subject to certain operating hazards such as:
| | ● | accidents resulting in serious bodily injury and the loss of life or property; |
| | | |
| | ● | liabilities from accidents or damage by our equipment; |
| | | |
| | ● | well blowouts; |
| | | |
| | ● | cratering (catastrophic failure); |
| | | |
| | ● | explosions; |
| | | |
| | ● | uncontrollable flows of oil, natural gas or well fluids; |
| | | |
| | ● | abnormally pressurized formations; |
| | | |
| | ● | fires; |
| | | |
| | ● | reservoir damage; |
| | | |
| | ● | oil spills; |
| | | |
| | ● | pollution and other damage to the environment; and |
| | | |
| | ● | releases of toxic gas. |
In addition, our operations are susceptible to damage from natural disasters such as flooding or tornados, which involve increased risks of personal injury, property damage and marketing interruptions. The occurrence of one of these operating hazards may result in injury, loss of life, suspension of operations, environmental damage and remediation and/or governmental investigations and penalties. The payment of any of these liabilities could reduce, or even eliminate, the funds available for exploration and development, or could result in a loss of our properties. In addition, pollution and environmental risks generally are not fully insurable. If a significant accident or other event occurs and is not fully covered by insurance, it could materially adversely affect our financial condition, results of operations and cash flows.
Our insurance might be inadequate to cover our liabilities. Insurance costs are expected to continue to increase over the next few years, and we may decrease coverage and retain more risk to mitigate future cost increases. If we incur substantial liability, and the damages are not covered by insurance or are in excess of policy limits, then our business, results of operations and financial condition may be materially adversely affected.
We may not be able to keep pace with technological developments in our industry.
The oil and natural gas industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. As others use or develop new technologies, we may be placed at a competitive disadvantage or competitive pressures may force us to implement those new technologies at substantial costs. In addition, other oil and natural gas companies may have greater financial, technical and personnel resources that allow them to enjoy technological advantages and may in the future allow them to implement new technologies before we can. We may not be able to respond to these competitive pressures and implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use now or in the future were to become obsolete or if we are unable to use the most advanced commercially available technology, our business, financial condition and results of operations could be materially adversely affected.
Competition in the oil and natural gas industry is intense, and many of our competitors have resources that are greater than ours.
We operate in a highly competitive environment for developing and acquiring properties, marketing oil and natural gas and securing equipment and trained personnel. As a relatively small oil and natural gas company, many of our competitors, major and large independent oil and natural gas companies, possess and employ financial, technical and personnel resources substantially greater than ours. Those companies may be able to develop and acquire more prospects and productive properties than our financial or personnel resources permit. Our ability to acquire additional prospects and discover reserves in the future will depend on our ability to evaluate and select suitable properties and execute our exploration and development activities in a highly competitive environment. Also, there is substantial competition for capital available for investment in the oil and natural gas industry. Larger competitors may be better able to withstand sustained periods of unsuccessful drilling and absorb the burden of changes in laws and regulations more easily than we can, which would adversely affect our competitive position. We may not be able to compete successfully in the future in developing reserves, acquiring prospective oil and natural gas properties and reserves, attracting and retaining highly skilled personnel and raising additional capital.
We may be unable to diversify our operations to avoid any downturn in the oil and natural gas industry.
Because of our limited financial resources, it is unlikely that we will be able to diversify our operations the way companies with greater financial resources are able to do. Our inability to diversify our activities will subject us to economic fluctuations within the oil and natural gas industry and therefore increase the risks associated with our operations as limited to one industry.
Certain federal income tax deductions currently available with respect to oil and natural gas exploration and development may be eliminated as a result of future legislation.
President Obama's proposed Fiscal Year 2014 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, which could have a material adverse effect on our business, financial condition, operations and cash flows.
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. On November 3, 2011, the EPA released its Plan to Study the Potential Impacts of Hydraulic Fracturing on Drinking Water Resources. The study will include both analysis of existing data and investigative activities designed to generate future data. The EPA issued a progress report in December 2012, and expects to release a final report for public comment and peer review in 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 for completions of hydraulically fractured natural gas wells, requiring the use of reduced emission completion techniques.
Our business exposes us to liability and extensive regulation on environmental matters, which could result in substantial expenditures.
Our operations are subject to numerous U.S. federal, state and local laws and regulations relating to the protection of the environment, including those governing the discharge of materials into the water and air, the generation, management and disposal of hazardous substances and wastes and the clean-up of contaminated sites. We could incur material costs, including clean-up costs, fines and civil and criminal sanctions, injunctive relief and third-party claims for property damage and personal injury as a result of violations of, or liabilities under, environmental laws and regulations. Such laws and regulations not only expose us to liability for our own activities, but may also expose us to liability for the conduct of others or for actions by us that were in compliance with all applicable laws at the time those actions were taken.
For example, on February 11, 2013, the BLM accepted a remediation plan submitted by Cross Border for its Tom Tom and Tomahawk fields. Pursuant to the remediation plan, Cross Border expects to spend $2.1 million during fiscal 2014 and 2015 to correct environmental issues on these fields.
In addition, we could incur substantial expenditures complying with environmental laws and regulations, including future environmental laws and regulations which may be more stringent, for example, than the regulation of GHG emissions under the federal CAA, or state or regional regulatory programs. 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.
In August 2012, the EPA adopted rules that subject oil and natural gas production, processing, transmission, and storage operations to regulation under the New Source Performance Standards, or NSPS, and National Emission Standards for Hazardous Air Pollutants, or NESHAP, programs. The rule includes NSPS standards for completions of hydraulically fractured gas wells and establishes specific new requirements for emissions from compressors, controllers, dehydrators, storage vessels, natural gas processing plants and certain other equipment. The final rule became effective October 15, 2012; however, a number of the requirements did not take immediate effect. The final rule establishes a phase-in period to allow for the manufacture and distribution of required emissions reduction technology. During the first phase, ending December 31, 2014, owners and operators of gas wells must either flare their emissions or use emissions reduction technology called "green completions" technologies already deployed at wells. On or after January 1, 2015, all newly fractured gas wells will be required to use green completions. Controls for certain storage vessels and pneumatic controllers may phase-in over one year beginning on the date the final rule is published in the Federal Register, while certain compressors, dehydrators and other equipment must comply with the final rule immediately or up to three years and 60 days after publication of the final rule, depending on the construction date and/or nature of the unit. We continue to evaluate the EPA's final rule, as it may require changes to our operations, including the installation of new emissions control equipment. These standards, as well as any future laws and their implementing regulations, may require us to obtain pre-approval for the expansion or modification of existing facilities or the construction of new facilities expected to produce air emissions, impose stringent air permit requirements, or utilize specific equipment or technologies to control emissions. Our failure to comply with these requirements could subject us to monetary penalties, injunctions, conditions or restrictions on operations and, potentially, criminal enforcement actions. These new requirements may result in increased operating and compliance costs, increased regulatory burdens and delays in our operations.
The EPA's implementation of climate change regulations could result in increased operating costs and reduced demand for our oil and natural gas production.
Although federal legislation regarding the control of emissions of GHGs, for the present, appears unlikely, the EPA has been implementing regulatory measures under existing CAA authority and some of those regulations may affect our operations. GHGs are certain gases, including carbon dioxide, a product of the combustion of natural gas, and methane, a primary component of natural gas, that may be contributing to the warming of the Earth's atmosphere, resulting in climatic changes. These GHG regulations could require us to incur increased operating costs and could have an adverse effect on demand for our oil and natural gas production.
On June 3, 2010, the EPA published its so-called GHG tailoring rule that will phase in federal prevention of significant deterioration permit requirements for new sources and modifications, and Title V operating permits for all sources, that have the potential to emit specific quantities of GHGs. Those permitting provisions, should they become applicable to our operations, could require controls or other measures to reduce GHG emissions from new or modified sources, and we could incur additional costs to satisfy those requirements. In October 2009, the EPA issued a final rule requiring the reporting of GHG emissions from specified large GHG emission sources in the U.S., including natural gas liquids fractionators and local natural gas/distribution companies, beginning in 2011 for emissions occurring in 2010. In November 2010, the EPA published a final rule expanding the GHG reporting rule to include onshore oil and natural gas production, processing, transmission, storage and distribution facilities. This rule requires reporting of GHG emissions from such facilities on an annual basis, with reporting beginning in 2012 for emissions occurring in 2011. Finally, on March 27, 2012, the EPA issued a proposed rule establishing carbon pollution standards for new fossil-fuel-fired electric utility generating units. The proposed rule underwent an extended public comment process, which concluded on June 25, 2012. The EPA is presently evaluating the public comments and is expected to issue a final rule at a later date. The EPA plans to implement GHG emissions standards for refineries at a later date.
We have identified material weaknesses in our internal control over financial reporting. These material weaknesses, if not corrected, could affect the reliability of our financial statements and have other adverse consequences.
Under Section 404 of the Sarbanes-Oxley Act of 2002, we are required to furnish a report by our management on internal control over financial reporting. This report must contain, among other matters, an assessment of the effectiveness of our internal control over financial reporting, including a statement as to whether or not our internal control over financial reporting is effective. This assessment must include disclosure of any material weaknesses in our internal control over financial reporting identified by our management.
We have identified material weaknesses in our internal control over financial reporting as of May 31, 2013 relating primarily to the (i) lack of sufficient accounting expertise to appropriately apply GAAP for complex or non-recurring transactions; (ii) lack of appropriate accounting personnel to properly design and implement internal control procedures over financial reporting; (iii) lack of sufficient review of accounting schedules to properly prevent and detect errors associated with accrued revenue and oil and natural gas sales; and (iv) lack of segregation of duties surrounding the cash disbursements process of a significant subsidiary. Failure to have effective internal controls could lead to a misstatement of our financial statements. If, as a result of deficiencies in our internal controls, we cannot provide reliable financial statements, our business decision process may be adversely affected, our business and operating results could be harmed, investors could lose confidence in our reported financial information, the market price of our securities could decrease and our ability to obtain additional financing, or additional financing on favorable terms, could be adversely affected. In addition, failure to maintain effective internal control over financial reporting could result in investigations or sanctions by regulatory authorities.
We intend to take further action to remediate the material weaknesses and improve the effectiveness of our internal control over financial reporting. However, we can give no assurances that the measures we may take will remediate the material weaknesses identified or that any additional material weaknesses will not arise in the future due to our failure to implement and maintain adequate internal control over financial reporting. In addition, even if we are successful in strengthening our controls and procedures, those controls and procedures may not be adequate to prevent or identify irregularities or ensure the fair presentation of our financial statements included in our periodic reports filed with the SEC.
Our business may suffer if we lose key personnel.
We depend to a large extent on the services of our officers, including Alan Barksdale, our President and Chief Executive Officer, Michael Uffman, our Chief Financial Officer, Hilda Kouvelis, our Chief Accounting Officer, and Tommy Folsom, Executive Vice President and Director of Exploration and Production for RMR Operating. These individuals have extensive experience and expertise in evaluating and analyzing producing oil and natural gas properties and drilling prospects, maximizing production from oil and natural gas properties and developing and executing financing strategies. Although we have employment agreements with Ms. Kouvelis and Mr. Folsom, we do not currently have an employment agreement with Messrs. Barksdale or Uffman and they are free to terminate their employment with us at any time and compete with us immediately thereafter. The loss of any of these individuals could have a material adverse effect on our operations. We do not maintain key-man life insurance with respect to any management personnel. Our success will be dependent on our ability to continue to retain and utilize skilled technical personnel.
Our officers and directors are engaged in other business activities and conflicts of interest may arise in their daily activities which may not be resolved in our favor.
Various actual and potential conflicts of interest may exist between us and our officers and directors. Our officers and directors have other business interests to which they devote their attention, and we expect they will continue to do so, although our officers will devote the majority of their business time to our affairs. As a result, conflicts of interest or potential conflicts of interest may arise from time to time that can be resolved only through the officers or directors exercising such judgment as is consistent with fiduciary duties to their other business interests and to us. These conflicts of interest may not be resolved in our favor.
Compliance with changing regulation of corporate governance and public disclosure will result in additional expenses and pose challenges for our management.
Changing laws, regulations and standards relating to corporate governance and public disclosure, including the Dodd-Frank Act and the rules and regulations promulgated thereunder, the Sarbanes-Oxley Act and SEC regulations, have created uncertainty for public companies and significantly increased the costs and risks associated with accessing the U.S. public markets. Our management team will need to devote significant time and financial resources to comply with both existing and evolving standards for public companies, which will lead to increased general and administrative expenses and a diversion of management time and attention from revenue generating activities to compliance activities.
Our operations and the oil and gas industry may be materially adversely impacted by domestic and foreign acts of terrorism and war.
Terrorist attacks and the threat of terrorist attacks, whether domestic or foreign, as well as the military or other actions taken in response to such actions, may cause instability in the global financial and energy markets. Terrorism, the wars in Iraq and Afghanistan, political instability in Northern Africa and the Middle East and other sustained military campaigns could adversely affect us and the market price of oil and natural gas in unpredictable ways, or the possibility that the infrastructure on which the operators developing mineral properties rely could be a direct target or an indirect casualty of an act of terror. Any of these conditions could have a material adverse effect on our operations.
Risks Related to Our Common Stock
The price of our common stock may fluctuate significantly, which could negatively affect us and holders of our common stock.
The trading price of our common stock may fluctuate significantly in response to a number of factors, many of which are beyond our control. For instance, if our financial results are below the expectations of securities analysts and investors, the market price of our common stock could decrease, perhaps significantly. Other factors that may affect the market price of our common stock include:
| | ● | actual or anticipated fluctuations in our quarterly results of operations; |
| | | |
| | ● | liquidity; |
| | | |
| | ● | sales of common stock by our stockholders; |
| | | |
| | ● | changes in oil and natural gas prices; |
| | | |
| | ● | changes in our cash flow from operations or earnings estimates; |
| | | |
| | ● | publication of research reports about us or the oil and natural gas exploration and production industry generally; |
| | | |
| | ● | competition for, among other things, capital, acquisition of reserves, undeveloped land and skilled personnel; |
| | | |
| | ● | increases in market interest rates which may increase our cost of capital; |
| | | |
| | ● | changes in applicable laws or regulations, court rulings and enforcement and legal actions; |
| | | |
| | ● | changes in market valuations of similar companies; |
| | | |
| | ● | adverse market reaction to any indebtedness we incur in the future; |
| | | |
| | ● | additions or departures of key management personnel; |
| | | |
| | ● | actions by our stockholders; |
| | | |
| | ● | commencement of or involvement in litigation; |
| | | |
| | ● | news reports relating to trends, concerns, technological or competitive developments, regulatory changes and other related issues in our industry; |
| | | |
| | ● | speculation in the press or investment community regarding our business; |
| | | |
| | ● | political conditions in oil and natural gas producing regions; |
| | | |
| | ● | general market and economic conditions; and |
| | | |
| | ● | domestic and international economic, legal and regulatory factors unrelated to our performance. |
In addition, the U.S. securities markets have experienced significant price and volume fluctuations. These fluctuations often have been unrelated to the operating performance of companies in these markets. Our common stock is traded on the OTCQB, which is subject to greater volatility than a national exchange or quotation system. This volatility may be caused by a variety of factors, including the lack of readily available price quotations, the absence of consistent administrative supervision of bid and ask quotations, lower trading volume, and market conditions.
Market fluctuations and broad market, economic and industry factors may negatively affect the price of our common stock, regardless of our operating performance. Any volatility or a significant decrease in the market price of our common stock could also negatively affect our ability to make acquisitions using common stock. Further, if we were to be the object of securities class action litigation as a result of volatility in our common stock price or for other reasons, it could result in substantial costs and diversion of our management's attention and resources, which could negatively affect our financial results.
Offers or availability for sale of a substantial number of shares of our common stock by our shareholders may cause the market price of our common stock to decline.
On May 3, 2013, we filed a resale shelf registration statement on a Form S-3 covering 15,438,805 shares of common stock with the SEC. The ability of our shareholders to sell shares of our common stock in the public market, or upon the expiration of any statutory holding period under Rule 144 of the Securities Act of 1933, as amended (the "Securities Act"), could create a circumstance commonly referred to as an "overhang," which could cause the market price of our common stock to fall. The existence of an overhang, whether or not sales have occurred or are occurring, could make it more difficult for us to raise additional financing through future sales of equity or equity-related securities at a time and price that we deem reasonable or appropriate. Additionally, we filed a universal shelf registration statement on Form S-3 on January 17, 2013, registering the possible issuance of $150.0 million of common stock, preferred stock, warrants and debt securities. Sales of a substantial number of shares of our common stock, or the perception that sales could occur, could adversely affect the market price of our common stock. In addition, these sales may be dilutive to existing shareholders.
We may raise additional capital in the future through issuances of securities and such additional funding may be dilutive to shareholders or impose operational restrictions.
We may raise additional capital in the future to help fund our operations through sales of shares of our common stock or securities convertible into shares of our common stock, as well as issuances of debt. Such additional financing may be dilutive to our shareholders, and debt financing, if available, may involve restrictive covenants which may limit our operating flexibility, including the ability to pay dividends. If additional capital is raised through the issuances of shares of our common stock or securities convertible into shares of our common stock, the percentage ownership of existing shareholders will be reduced. These shareholders may experience additional dilution in net book value per share and any additional equity securities may have rights, preferences and privileges senior to those of the holders of our common stock.
We do not intend to pay dividends on our common stock in the future.
We have not paid dividends on our common stock and do not intend to pay dividends in the foreseeable future. The payment of cash dividends on our common stock in the future will be dependent on our revenues and earnings, if any, capital requirements and general financial condition and will be entirely within the discretion of our board of directors at such time. It is the present intention of our board of directors to retain earnings, if any, to fund our future growth, and there is no assurance we will ever pay dividends on our common stock in the future. As a result, any gain holders of our common stock will realize will result solely from the appreciation of such common stock.
As of August 31, 2013, we had 476,687 shares of Series A Preferred Stock outstanding, and our articles of incorporation permit us to issue additional preferred stock, which could diminish the rights of holders of our common stock and restrict a takeover attempt that you may favor.
As of August 31, 2013, we had 476,687 shares of Series A Preferred Stock outstanding, and our articles of incorporation, as amended, authorizes the issuance of additional shares of preferred stock in one or more series on terms that may be determined at the time of issuance by our Board of Directors. The Series A Preferred Stock and any additional preferred stock may be issued on terms that are unfavorable to the holders of our common stock, including the grant of superior voting rights, the grant of preferences in favor of preferred shareholders in the payment of dividends and upon our liquidation and the designation of conversion rights that entitle holders of our preferred stock to convert their shares into our common stock on terms that are dilutive to holders of our common stock. The issuance of preferred stock in future offerings may make a takeover or change in control of us more difficult.
Because we are quoted on the OTC 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 OTCQB, which is subject to greater volatility than a national exchange or quotation system. This volatility may be caused by a variety of factors, including the lack of readily available price quotations, the absence of consistent administrative supervision of bid and ask quotations, lower trading volume, and market conditions. Investors in our common stock may experience high fluctuations in the market price and volume of the trading market for our securities. These fluctuations, when they occur, may have a negative effect on the market price for our common stock. Accordingly, our stockholders may not be able to realize a fair price from their shares when they determine to sell them or may have to hold them for a substantial period of time until the market for our common stock improves.
Trading in our common stock has been limited, and our stock price could potentially be subject to substantial fluctuations.
Trading in our common stock has been limited. Historically, our common stock price has been affected substantially by a relatively modest volume of transactions and could be again so affected. If our common stock price falls, our stockholders may not be able to sell their shares when desired or at desirable prices.
Our common stock is subject to penny stock regulation.
Our common stock is 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 common 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 the ability of the holders of our common stock to buy and sell their shares and have an adverse effect on the market for our common stock.
Risks Related to Our Series A Preferred Stock
The Series A Preferred Stock does not have an established trading market, which may negatively affect its market value and the ability to transfer or sell shares.
The Series A Preferred Stock does not have an established trading market, which may limit the ability of holders of Series A Preferred Stock to sell shares. We intend to apply to list the Series A Preferred Stock on a national securities exchange prior to April 30, 2014. An active trading market for the shares may not develop or, even if it develops, may not last, in which case the trading price of the shares could be adversely affected and the ability to transfer shares will be limited.
The market value of the Series A Preferred Stock could be adversely affected by various factors.
The trading price of the Series A Preferred Stock may depend on many factors, including, without limitation:
● market liquidity;
● prevailing interest rates;
● the market for similar securities;
● general economic conditions;
● the sale of additional shares of Series A Preferred Stock;
● our financial condition, performance and prospects; and
● our issuance of additional preferred equity or debt securities.
For example, higher market interest rates could cause the market price of the Series A Preferred Stock to decrease. The foregoing factors, among others, may affect the trading price of the Series A Preferred Stock, as well as limit the trading market and restrict ability of investors in the Series A Preferred Stock to transfer their shares.
We could be prevented from paying cash dividends on the Series A Preferred Stock.
Although dividends on the Series A Preferred Stock are cumulative and arrearages will accrue until paid, holders of shares of Series A Preferred Stock will only receive cash dividends on the Series A Preferred Stock when, as and if declared by our Board of Directors, and if we have funds legally available for the payment of dividends under Florida law and such payment is not restricted or prohibited by law or the terms of any of our agreements, including the documents governing our indebtedness. Pursuant to the terms of our Credit Agreement, we may pay cash dividends on the Series A Preferred Stock so long as we are not otherwise in default under the Credit Agreement and payment of such cash dividends would not cause us to be in default under the Credit Agreement. Future debt, contractual covenants or arrangements that we may enter into in the future may also restrict or prevent future dividend payments.
The payment of any future dividends will be determined by our Board of Directors in light of conditions then existing, including earnings, financial condition, capital requirements, restrictions or prohibitions in current or future agreements, business conditions and other factors affecting us as a whole. Accordingly, there is no guarantee that we will be able to pay any dividends on the Series A Preferred Stock.
The Series A Preferred Stock has not been rated and our payment obligations with respect to the shares of Series A Preferred Stock will be effectively subordinated to all of our existing and future debt.
The Series A Preferred Stock has not been rated by any nationally recognized statistical rating organization. In addition, with respect to dividend rights and rights upon our liquidation, winding-up or dissolution, the Series A Preferred Stock will be subordinated to all of our existing and future debt and all future capital stock designated as senior to the Series A Preferred Stock. As of September 12, 2013, our total outstanding indebtedness was approximately $16.3 million.
We may incur additional indebtedness in the future to finance acquisitions or the development of properties, and the terms of the Series A Preferred Stock do not require us to obtain the approval of the holders of the Series A Preferred Stock prior to incurring additional indebtedness. As a result, our existing and future indebtedness may be subject to restrictive covenants or other provisions that may prevent or otherwise limit our ability to make dividend or liquidation payments on the Series A Preferred Stock. Upon our liquidation, our obligations to our creditors would rank senior to the Series A Preferred Stock and would be required to be paid before any payments could be made to holders of the Series A Preferred Stock.
Holders of Series A Preferred Stock have extremely limited voting rights.
Except as expressly stated in the amendment to our articles of incorporation governing the Series A Preferred Stock, holders of Series A Preferred Stock do not have any relative, participating, optional or other special voting rights and powers and their approval is not required for the taking of any corporate action. For example, the approval of holders of Series A Preferred Stock is not required to elect members to our Board of Directors (except for a limited right to elect two directors upon a dividend default, or one director upon a listing default), or for any merger or consolidation in which we are involved or sale of all or substantially all of our assets, except to the extent that such transaction materially adversely changes the express powers, preferences, rights or privileges of the holders of Series A Preferred Stock. None of the provisions relating to the Series A Preferred Stock contains any provisions affording the holders of the Series A Preferred Stock protection in the event of a highly leveraged or other transaction, including a merger or the sale, lease or conveyance of all or substantially all of our assets or business, that might adversely affect the holders of the Series A Preferred Stock, so long as the terms and rights of the holders of Series A Preferred Stock are not materially and adversely changed.
The issuance in future offerings of preferred stock may adversely affect the value of the Series A Preferred Stock.
Our articles of incorporation, as amended, currently authorizes the issuance of up to 100,000,000 shares of preferred stock in one or more series on terms that may be determined at the time of issuance by our Board of Directors, including up to 1,200,000 shares of Series A Preferred Stock. We may offer for sale additional shares of Series A Preferred Stock in the future. Accordingly, we may issue additional shares of Series A Preferred Stock and/or stock that ranks on parity with the Series A Preferred Stock ("Parity Stock") or, with the consent of the holders of the Series A Preferred Stock, stock that ranks senior to the Series A Preferred Stock ("Senior Stock"). The issuance of Series A Preferred Stock, Parity Stock or Senior Stock would dilute the interests of the holders of Series A Preferred Stock, and any issuance of Senior Stock could affect our ability to pay dividends on, redeem or pay the liquidation preference on the Series A Preferred Stock.
Holders of the Series A Preferred Stock may be unable to use the dividends-received deduction and may not be eligible for the preferential tax rates applicable to "qualified dividend income."
We may not have sufficient current or accumulated earnings and profits during future fiscal years for the distributions on the Series A Preferred Stock (or our common stock should we determine to pay distributions on it) to qualify as dividends for U.S. federal income tax purposes. If the distributions fail to qualify as dividends, U.S. holders that are corporations would be unable to use the dividends-received deduction and may not be eligible for the preferential tax rates applicable to "qualified dividend income." If any distributions on the Series A Preferred Stock with respect to any fiscal year are not eligible for the dividends-received deduction or preferential tax rates applicable to "qualified dividend income" because of insufficient current or accumulated earnings and profits, it is possible that a U.S holder that is a corporation could recognize capital gain income upon receipt of a distribution or upon disposition of shares of Series A Preferred Stock. Because of the way corporations are taxed on capital gain income, such capital gains, absent offsetting capital losses, would be effectively taxed to a corporate owner of our preferred stock (or common stock) at then current ordinary income tax rates.
The Series A Preferred Stock is not convertible.
The Series A Preferred Stock accrues dividends at a fixed rate and is not convertible into shares of our common stock. Accordingly, the market value of the Series A Preferred Stock may depend on dividend and interest rates for other preferred stock, debt securities and other investment alternatives, and our actual and perceived ability to pay dividends on, and in the event of dissolution satisfy the liquidation preference with respect to, the Series A Preferred Stock. Moreover, the mandatory redemption of Series A Preferred Stock on July 15, 2018 or upon a "change of control," or our optional right to redeem the Series A Preferred Stock on or after July 15, 2014, could impose a ceiling on its value.
We may not be able to comply with the financial covenant for the Series A Preferred Stock.
We are required to have an asset coverage ratio of 2.0 or greater as of the date of any issuance of additional debt (excluding borrowings under the Credit Facility or any revolving credit facility in replacement thereof) Series A Preferred Stock, Senior Stock or Parity Stock (the "Financial Covenant"). If we fail to comply with the Financial Covenant, the dividend rate will be increased to 12.0%. Future debt arrangements that we enter into in the future may inhibit our ability to comply with the Financial Covenant, as well as also restrict or limit our ability to make future dividend payments.
We may not be able to comply with the listing covenant for the Series A Preferred Stock, and listing on a national securities exchange does not guarantee a market for the Series A Preferred Stock.
We intend to apply to list the shares of the Series A Preferred Stock on a national securities exchange prior to April 30, 2014, as required by the terms of the Series A Preferred Stock. A national securities exchange may decline our application to be listed on such exchange. Further, our identification of certain material weaknesses in our internal control over financial reporting may make it more difficult to qualify for listing on a national securities exchange.
In the event we fail to list the Series A Preferred Stock on a national securities exchange prior to April 30, 2014, the dividend rate specified shall be increased by one-half percent per calendar quarter, up to a rate not to exceed 12.0%, until such listing occurs. Even if a national securities exchange approves the Series A Preferred Stock for listing, an active trading market for the Series A Preferred Stock may not develop or, if it does develop, may not last, in which case the market price of the Series A Preferred Stock could be materially and adversely affected.
Additionally, once the Series A Preferred Stock is listed on a national securities exchange, we are required to maintain the listing of the Series A Preferred Stock on such exchange. In the event we fail to maintain such listing for 180 consecutive days, then, until such failure is cured, (i) the dividend rate will increase, and (ii) the holders of Series A Preferred Stock have the right to elect one director to our Board of Directors. A national securities exchange could delist the Series A Preferred Stock, which may result in a listing default.
Not applicable.
Currently, our oil and natural gas properties are concentrated in the Permian Basin, the onshore Gulf Coast of Texas, Southwest New Mexico and Kansas. The Permian Basin covers an area approximately 250 miles wide and 300 miles long in West Texas and Southeast New Mexico. The Permian Basin is one of the most prolific onshore oil and natural gas producing regions in the United States. It is characterized by an extensive production history, mature infrastructure, long reserve life and hydrocarbon potential in multiple producing formations. Our primary operations in the onshore Gulf Coast are in conventional fields that produce primarily from the Wilcox formation in Zapata and Duval Counties of Texas.
The following map shows the location of our core properties as of May 31, 2013.
The following description of our properties in the Permian Basin is presented as of May 31, 2013.
We drilled and completed our first horizontal well, the Madera 24 Federal 2H, on the Madera Prospect in January 2012. The well was drilled to a vertical depth of 9,028 feet and a lateral length of 4,620 feet in the Brushy Canyon reservoir and initially produced at a rate of 1,043 Boe/d, comprised of 86% oil. As of May 31, 2013, the Madera 24 Federal 2H well has produced over 111 MBoe, of which 77% was oil. A portion of the other working interest owners elected not to participate in the drilling and completion of the Madera 24 Federal 2H well. As a result, we increased our ownership to an 80.1% working interest (60.1% net revenue interest). Our ownership will revert to a 23.3% working interest (17.5% net revenue interest) when we recover an amount equal to 300% of the costs to drill and complete the well plus operating costs through that date.
We commenced drilling our second horizontal well in the Madera Prospect, the Madera 24 Federal 3H, on February 6, 2013. This well is located just to the west of the Madera 24 Federal 2H well. We are the operator of the well and own a 33% working interest and 25% net revenue interest. At May 31, 2013, we had finished drilling and completing the well. The initial production rate from the Madera 24 Federal 3H well was 1,491 Boe/d, of which 81% was oil. The well has a total measured depth of 13,570 feet, including a true vertical depth of 9,062 feet and a lateral length of 4,508 feet. At May 31, 2013, the well was still producing and permanent production facilities were under construction. The Madera Prospect contains an additional 4 proved undeveloped locations (1.7 net) that target the Brushy Canyon reservoir.
As of May 31, 2013, the Madera Prospect had estimated proved reserves of 1,015 MBoe, of which 690 MBoe were proved undeveloped, and had net daily average production for the month of May 2013 of 76 Boe/d, of which 66% was oil. Production from the Madera 24 Federal 2H well was shut in during May 2013 for the completion of the Madera 24 Federal 3H well.
On February 11, 2013, the BLM accepted a remediation plan submitted by Cross Border for its Tom Tom and Tomahawk fields. Pursuant to the remediation plan, Cross Border expects to spend $2.1 million during fiscal 2014 and 2015 to correct environmental issues on these fields.
We commenced a 10-well workover program in May 2013 to re-enter existing wells, clean out the wellbores, open unperforated pay, and increase pump efficiency. We have identified 12 wells (7.2 net) with proved developed non-producing reserves. Additionally, there are 14 proved undeveloped locations (10.6 net) that target the San Andres formation.
The following is a description of our properties in the onshore Gulf Coast as of May 31, 2013.
Cross Border owns 536,340 gross (268,170 net) mineral acres in Hidalgo, Grant, Sierra, and Socorro Counties, New Mexico. This mineral ownership carries no drilling commitments or leasehold obligations. As of May 31, 2013, this acreage had no proved reserves or production.
As of May 31, 2013, we owned oil and natural gas interests in 5,215 gross and net acres in central Kansas. There are multiple target horizons in this prospect including the Arbuckle and the Lansing-Kansas City and Viola formations. We own a 100% working interest and an average net revenue interest of 80%. RMR Operating is the operator. As of May 31, 2013, the Kansas acreage had no proved reserves or production.
As is customary in the oil and natural gas industry, we generally conduct a preliminary title examination prior to the acquisition of properties or leasehold interests. Prior to commencement of operations on such acreage, a thorough title examination will usually be conducted and any significant defects will be remedied before proceeding with operations. We believe the title to our properties is good, defensible and customary with practices in the oil and natural gas industry, subject to such exceptions that we believe do not materially detract from the use of such properties. With respect to our properties of which we are not the record owner, we rely instead on contracts with the owner or operator of the property or assignment of leases, pursuant to which, among other things, we generally have the right to have our interest placed on record.
Our properties are generally subject to royalty, overriding royalty and other interests customary in the industry, liens incident to agreements, current taxes and other burdens, minor encumbrances, easements and restrictions. We do not believe any of these burdens will materially interfere with our use of these properties. Substantially all of the properties of the Company, Black Rock, RMR Operating and Cross Border are pledged as collateral under the Credit Agreement with Independent Bank.
The following table sets forth our estimated proved reserves as of May 31, 2013.
The following table sets forth our estimated PV-10 and standardized measure of discounted net cash flows as of May 31, 2013.
Estimates of proved developed and undeveloped reserves are inherently imprecise and are continually subject to revision based on production history, results of additional exploration and development, price changes and other factors. See “—Qualifications of Technical Persons and Internal Controls Over Reserves Estimation Process.”
At May 31, 2013, our estimated proved reserves were 3.5 MMBoe, consisting of 65% oil, which is an increase of 70% compared to our proved reserves of 2.1 MMBoe at May 31, 2012. During fiscal 2013, we added estimated proved reserves of 2.5 MMBoe through our acquisitions, including the acquisition of Cross Border, which were partially offset by production of 0.2 MMBoe and downward revisions in previous estimates of 0.8 MMBoe. The downward revisions were primarily comprised of 0.2 MMBoe due to a revision to the proved undeveloped reserves at Cowden and 0.5 MMBoe due to a revision to the proved developed behind the pipe reserves at Frost Bank and Peal Ranch.
At May 31, 2013, our estimated proved undeveloped reserves were 1.6 MMBoe, consisting of 79% oil, as compared to 1.2 MMBoe at May 31, 2012, consisting of 70% oil. During fiscal 2013, we added estimated proved undeveloped reserves of 1.0 MMBoe through the acquisition of Cross Border. We converted 0.3 MMBoe of proved undeveloped reserves to proved developed producing reserves, due to the completion of a well on the Madera Prospect, a well on the Villarreal Prospect and several wells on the Cross Border non-operated acreage. As of May 31, 2013, estimated future development costs relating to the development of our proved undeveloped reserves was $35.4 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.
We have an internal staff of geoscience professionals who work closely with our independent petroleum engineers to ensure the integrity, accuracy and timeliness of data furnished to them in their reserves estimation process. Our technical team consults regularly with representatives of CG&A. We review with them our properties and discuss methods and assumptions used in their preparation of our fiscal year-end reserves estimates. While we have no formal committee specifically designated to review reserves reporting and the reserves estimation process, a copy of the reserve report is reviewed with representatives of CG&A and our internal technical staff before we disseminate any of the information. Additionally, our senior management reviews and approves the reserve report and any internally estimated significant changes to our proved reserves on an annual basis.
Estimates of oil and natural gas reserves are projections based on a process involving an independent third party engineering firm’s collection of all required geologic, geophysical, engineering and economic data, and such firm’s complete external preparation of all required estimates and are forward-looking in nature. These reports rely upon various assumptions, including assumptions required by the SEC, such as constant oil and natural gas prices, operating expenses and future capital costs. The process also requires assumptions relating to availability of funds and timing of capital expenditures for development of our proved undeveloped reserves. These reports should not be construed as the current market value of our reserves. The process of estimating oil and natural gas reserves is also dependent on geological, engineering and economic data for each reservoir. Because of the uncertainties inherent in the interpretation of this data, we cannot be certain that the reserves will ultimately be realized. Our actual results could differ materially. See “Note 18 – Supplemental Information Relating to Oil and Natural Gas Producing Activities (Unaudited)” to our audited consolidated financial statements for additional information regarding our oil and natural gas reserves.
Under SEC rules, proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil and/or natural gas actually recovered will equal or exceed the estimate. To achieve reasonable certainty, CG&A employs technologies consistent with the standards established by the Society of Petroleum Engineers. The technologies and economic data used in the estimation of our proved reserves include, but are not limited to, well logs, geologic maps and available downhole and production data, seismic data and well test data.
The following table sets forth summary information regarding our oil and natural gas sales, net production sold, average sales prices and production costs and expenses for the fiscal years ended May 31, 2013 and 2012. The results for the fiscal year ended May 31, 2013 only include results and net production sold from Cross Border since February 1, 2013.
The following table presents our total gross and net developed and undeveloped acreage by region as of May 31, 2013:
