Red Mountain Resources (RDMP) 424B5 Prospectus supplement for primary offering

Filed Pursuant to Rule 424(b)(5)
Registration No. 333-186076

The information in this preliminary prospectus supplement and the accompanying prospectus is not complete and may be changed. A registration statement relating to these securities has been declared effective by the Securities and Exchange Commission. This preliminary prospectus supplement and the accompanying prospectus are not an offer to sell these securities, and we are not soliciting an offer to buy these securities in any jurisdiction where the offer or sale is not permitted.

Subject to Completion, dated August 12, 2014

PRELIMINARY PROSPECTUS SUPPLEMENT

(To Prospectus dated February 1, 2013)

Red Mountain Resources, Inc.

Shares of 10.0% Series A Cumulative Redeemable Preferred Stock

(Liquidation Preference $25.00 Per Share)

We are offering                  shares of our 10% Series A Cumulative Redeemable Preferred Stock, par value $0.0001 per share (“Series A Preferred Stock”).

Holders of the Series A Preferred Stock will be entitled to cumulative dividends (whether or not declared) in the amount of $2.50 per share each year, which is equivalent to 10.0% of the $25.00 liquidation preference per share. The dividend rate may increase in certain circumstances. Dividends on the Series A Preferred Stock will be paid quarterly in arrears on the 15th day of January, April, July and October of each year (provided that if any dividend payment date is not a business day, then the dividend which would otherwise have been payable on that dividend payment date may be paid on the next succeeding business day) when, as and if declared by our board of directors, beginning on October 15, 2014.

The Series A Preferred Stock is subject to a mandatory redemption by the Company on July 15, 2018, for $25.00 per share, plus accrued and unpaid dividends to the redemption date. The Series A Preferred Stock is currently redeemable, in whole or in part, at our option, at specified redemption amounts as set forth in this prospectus supplement. If at any time a “Change of Control,” as defined in this prospectus supplement, occurs, we will be required to redeem the Series A Preferred Stock. The Series A Preferred Stock will not be subject to any sinking fund and will not be convertible into any of our other securities.

Investors in the Series A Preferred Stock generally will have no voting rights, but will have limited voting rights under certain circumstances including, without limitation, if we fail to pay dividends for six or more quarters.

There is no established trading market for the Series A Preferred Stock. Subject to issuance of the offered shares, we have applied to list the Series A Preferred Stock on the NASDAQ Capital Market concurrently with the consummation of this offering under the trading symbol “RMRAP”.

Northland Capital Markets and Euro Pacific Capital are acting as our underwriters in the public offering on a firm commitment basis.

Investing in our securities involves a high degree of risk. You should carefully consider the risks relating to an investment in the Series A Preferred Stock and each of the other risk factors described under “Risk Factors” beginning on page S-21 of this prospectus supplement, on page 3 of the accompanying prospectus and in our reports filed with the Securities and Exchange Commission, which are incorporated by reference herein, before you make an investment in our securities.

	Per Share	Total
Public offering price	$	$
Underwriting discounts and commissions (1)	$	$
Proceeds to us, before expenses	$	$

(1) In addition to the underwriting discount, we have also agreed to grant the underwriters an option for a period of 45 days to purchase an additional                  shares of our Series A Preferred Stock, and agreed to pay up to $200,000 of the expenses of the underwriters, including legal fees in connection with this offering. If the underwriters exercise the option in full, the total underwriting discounts payable by us will be $         and total proceeds to us before expenses will be $        . Please see “Underwriting” on pageS-104 for more information regarding our arrangements with the underwriters.

NEITHER THE SECURITIES AND EXCHANGE COMMISSION NOR ANY STATE SECURITIES COMMISSION HAS APPROVED OR DISAPPROVED OF THESE SECURITIES OR DETERMINED IF THIS PROSPECTUS SUPPLEMENT OR ACCOMPANYING PROSPECTUS IS TRUTHFUL OR COMPLETE. ANY REPRESENTATION TO THE CONTRARY IS A CRIMINAL OFFENSE.

We expect the Series A Preferred Stock will be ready for delivery in book-entry form through The Depository Trust Company on or about                     , 2014.

Northland Capital Markets   Euro Pacific Capital

The date of this prospectus supplement is                     , 2014.

Company Overview

Summary of Combined Properties of Red

Mountain and Cross Border

FY 2014 Q4 Net Production¹: Approximately 1,200 Boe/d – 56% oil

Proved Reserves²: 3.6 MMBoe

52% Proved Developed

¹  Average daily net production for the three months ended June 30, 2014. Includes net production sold represented by the 17% of Cross Border’s common stock not owned by us.

²  As of January 1, 2014. Includes reserves represented by the 17% of Cross Border’s common stock not owned by us.

96% of Net Acreage Either Owned Mineral Rights or Leases Held by Production as of June 30, 20141
Prospect	Gross Acres		Net Acres
Developed Permian		10,757		5,028
Undeveloped Permian2		325,574		25,898
New Mexico Non-Permian Minerals3		536,526		268,193
Developed Onshore Gulf Coast		4,776		1,405
Kansas		9,868		9,868
TOTAL		887,501		310,392

¹ Includes acreage represented by the 17% of Cross Border’s common stock not owned by us.

²  Includes mineral ownership.

³  Reflects mineral ownership.

PROSPECTUS SUPPLEMENT

ABOUT THIS PROSPECTUS SUPPLEMENT	S-1
NON-GAAP FINANCIAL MEASURES	S-1
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS	S-2
PROSPECTUS SUPPLEMENT SUMMARY	S-4
THE OFFERING	S-9
SUMMARY HISTORICAL FINANCIAL INFORMATION	S-16
SUMMARY RESERVES AND HISTORICAL OPERATING DATA	S-20
RISK FACTORS	S-21
USE OF PROCEEDS	S-40
RATIO OF EARNINGS TO FIXED CHARGES	S-41
CAPITALIZATION	S-42
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	S-43
BUSINESS	S-57
PROPERTIES	S-72
MANAGEMENT	S-82
DESCRIPTION OF THE SERIES A PREFERRED STOCK	S-86
MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES	S-95
UNDERWRITING	S-104
LEGAL MATTERS	S-108
EXPERTS	S-108
INDEPENDENT PETROLEUM ENGINEERS	S-108
WHERE YOU CAN FIND MORE INFORMATION	S-108
INCORPORATION OF CERTAIN INFORMATION BY REFERENCE	S-109
GLOSSARY OF OIL AND NATURAL GAS TERMS	S-111
PROSPECTUS
ABOUT THIS PROSPECTUS	1
RED MOUNTAIN RESOURCES, INC.	2
RISK FACTORS	3
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS	4
RATIO OF EARNINGS TO FIXED CHARGES	6
USE OF PROCEEDS	6
DESCRIPTION OF CAPITAL STOCK	7
DESCRIPTION OF WARRANTS	10
DESCRIPTION OF DEBT SECURITIES	11
PLAN OF DISTRIBUTION	22
LEGAL MATTERS	25
EXPERTS	25
INDEPENDENT PETROLEUM ENGINEERS	25
MATERIAL CHANGES	25
INCORPORATION OF CERTAIN INFORMATION BY REFERENCE	26
WHERE YOU CAN FIND MORE INFORMATION	28

ABOUT THIS PROSPECTUS SUPPLEMENT

This document is in two parts. The first part consists of this prospectus supplement, which describes the specific terms of this offering. The second part consists of the accompanying prospectus, which gives more general information about securities that we may offer from time to time, some of which may not be applicable to the Series A Preferred Stock offered by this prospectus supplement and the accompanying prospectus.

Before you invest in the Series A Preferred Stock, you should read the registration statement of which this prospectus supplement and the accompanying prospectus form a part. You should also read the exhibits to that registration statement, as well as this prospectus supplement, the accompanying prospectus, and the documents incorporated by reference into this prospectus supplement and the accompanying prospectus. The documents incorporated by reference are described in this prospectus supplement and the accompanying prospectus under “Incorporation of Certain Information by Reference.”

If the information set forth in this prospectus supplement varies in any way from the information set forth in the accompanying prospectus, you should rely on the information contained in this prospectus supplement. If the information set forth in this prospectus supplement varies in any way from the information set forth in a document that we have incorporated by reference into this prospectus supplement, you should rely on the information in the more recent document.

You should rely only on the information contained or incorporated by reference in this prospectus supplement and the accompanying prospectus. We have not, and the underwriters have not, authorized any other person to provide you with different information. We are not, and the underwriters are not, making an offer to sell these securities in any jurisdiction where the offer or sale is not permitted. You should assume that the information appearing in this prospectus supplement, the accompanying prospectus, and the documents incorporated by reference is accurate only as of their respective dates. Our business, financial condition, results of operations and prospects may have changed since those dates.

NON-GAAP FINANCIAL MEASURES

Adjusted EBITDAX is a non-GAAP financial measure that represents earnings before interest, income tax expense, exploration expense, depletion, depreciation, amortization and impairment expense, accretion of discount on asset retirement obligations, gains and losses on commodity derivatives and significant non-recurring expenses. Adjusted EBITDAX is a supplemental financial measure that is not required by, or presented in accordance with, U.S. generally accepted accounting principles (“GAAP”). It is not a measurement of our financial performance under GAAP and should not be considered as an alternative to net income (loss), operating income or any other performance measures derived in accordance with GAAP or as an alternative to cash flows from operating activities as a measure of our liquidity. Our measurement of Adjusted EBITDAX may not be comparable to similarly titled measures of other companies, and is not identical to similar measures used in our various agreements, including our $100.0 million revolving credit facility with Independent Bank as lender (the “Credit Facility”).

We present Adjusted EBITDAX because we believe that such information is used by certain investors as a measure of a company’s historical ability to fund capital expenditures and working capital requirements on a consistent basis without regard to depreciation, depletion and amortization and impairment of oil and natural gas properties and exploration expenses, which can vary significantly from period to period. In addition, our management uses Adjusted EBITDAX as a financial measure to evaluate our operating performance. Our presentation of Adjusted EBITDAX should not be construed as an inference that our future results will be unaffected by unusual or nonrecurring items.

Adjusted EBITDAX has limitations as an analytical tool, and you should not consider it in isolation, or as a substitute for analysis of our operating results or cash flows as reported under GAAP. Some of these limitations are:

• it does not reflect our cash expenditures, or future requirements, for capital expenditures or contractual commitments;

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• it does not reflect changes in, or cash requirements for, our working capital needs;

• it does not reflect the significant interest expense, or the cash requirements necessary to service interest or principal payments, on our debt;

• although depreciation is a non-cash charge, the assets being depreciated will often have to be replaced in the future, and Adjusted EBITDAX does not reflect any cash requirements for such replacements;

• it is not adjusted for all non-cash income or expense items that are reflected in our statements of cash flows; and

• other companies in our industry may calculate these measures differently than we do, limiting their usefulness as comparative measures.

Because of these limitations, Adjusted EBITDAX should not be considered as a measure of discretionary cash available to us to invest in the growth of our business or to provide for dividends on the Series A Preferred Stock. We compensate for these limitations by relying primarily on our GAAP results and using Adjusted EBITDAX only for supplemental purposes. Please see our consolidated financial statements incorporated by reference in this prospectus supplement.

For a description of how Adjusted EBITDAX is calculated from our net income (loss) and a reconciliation of our Adjusted EBITDAX to net income (loss), see “Summary—Summary Historical Financial Information” in this prospectus supplement.

PV-10 is a non-GAAP financial measure as defined by the SEC. The closest GAAP measure to PV-10 is the standardized measure of discounted net cash flows. The standardized measure differs from PV-10 because standardized measure includes the effect of future income taxes. We believe that the presentation of PV-10 is relevant and useful to our investors as supplemental disclosure to the standardized measure, or after-tax amount, because it presents the discounted future net cash flows attributable to our proved reserves before taking into account future corporate income taxes and our current tax structure. PV-10 is not a measure of financial or operating performance under GAAP. PV-10 should not be considered as an alternative to the standardized measure as defined under GAAP. For a description of how PV-10 is calculated from our standardized measure and a reconciliation of our PV-10 to our standardized measure, see “Properties—Summary of Oil and Natural Gas Reserves” in this prospectus supplement.

Total cash interest expense is a non-GAAP financial measure that represents total interest expense, which includes dividends on Series A Preferred Stock, less accretion of discount on preferred stock and debt issuance costs. Management believes that cash interest expense is useful for analyzing the cash flow needs and debt service requirements of the Company. However, cash interest expense is not intended to be used as an alternative to any measure of our financial condition in accordance with GAAP.

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

This prospectus supplement 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,

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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 “Risk Factors” in this prospectus supplement.

Forward-looking statements speak only as of the date hereof. All such forward-looking statements and any subsequent written and oral forward-looking statements attributable to us or any person acting on our behalf are expressly qualified in their entirety by the cautionary statements contained or referred to in this section and any other cautionary statements that may accompany such forward-looking statements. Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements.

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PROSPECTUS SUPPLEMENT SUMMARY

This summary provides a brief overview of information contained elsewhere in, or incorporated by reference into, this prospectus supplement and the accompanying prospectus. Because it is abbreviated, this summary does not contain all of the information that you should consider before investing in our Series A Preferred Stock. You should carefully read this entire prospectus supplement and the accompanying prospectus before making an investment decision, including the information presented under the headings “Risk Factors” and “Cautionary Statement Regarding Forward-Looking Statements” in this prospectus supplement and the financial statements and other information incorporated by reference into this prospectus supplement and the accompanying prospectus.

In this prospectus supplement, all references to the “Company,” “we,” “our” and “us” refer to (i) Red Mountain Resources, Inc., a Texas corporation (“Red Mountain”), (ii) Red Mountain’s wholly owned subsidiaries, including Black Rock Capital, Inc. (“Black Rock”) and RMR Operating, LLC (“RMR Operating”), and (iii) subsequent to January 28, 2013, Cross Border Resources, Inc. (“Cross Border”). As of June 30, 2014, 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.

Overview

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 June 30, 2014, we owned interests in 887,501 gross (310,392 net) mineral and lease acres in New Mexico, Texas and Kansas, of which 336,331 gross (30,926 net) acres are within the Permian Basin. We have successfully leased 9,868 net acres in Kansas located on the Central Kansas Uplift, and we also owned interests in over 1,405 net acres located on the Villarreal, Frost Bank, Resendez, Peal Ranch and La Duquesa Prospects in the onshore Gulf Coast of Texas.

On January 28, 2013, we closed the acquisition of 5,091,210 shares of common stock of Cross Border, bringing our total ownership to approximately 78% of the outstanding Cross Border common stock. Prior to the consolidation, we owned 47% of Cross Border’s outstanding common stock, and the investment was accounted for under the equity method of accounting. Subsequent to this transaction, we account for Cross Border as a consolidated subsidiary. As of June 30, 2014, we owned of record 14,327,767 shares of Cross Border common stock, representing 83% of Cross Border’s outstanding common stock.

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Permian Basin

As of January 1, 2014, approximately 90% of our proved reserves were concentrated in the Permian Basin. The Permian Basin covers an area approximately 250 miles wide and 300 miles long in West Texas and Southeast New Mexico. The Permian Basin is one of the most prolific onshore oil and natural gas producing regions in the United States. It is characterized by an extensive production history, mature infrastructure, long reserve life and hydrocarbon potential in multiple producing formations, including the Bone Spring, Wolfcamp, Abo, Yeso, San Andres and Delaware horizons.

2015 Capital Development Program

The following table presents the project name, location, operator, wellbore orientation and targeted primary formation for our properties with active and planned development as of June 30, 2014. During fiscal year 2015, we plan to spend between $40.0 million and $50.0 million to develop our properties, including Cross Border’s non-operated acreage. Of this amount, we expect to spend between $35.0 million and $45.0 million on the operated properties listed in the table below and between $5.0 million and $7.0 million on the non-operated properties listed in the table below. Our planned fiscal 2015 development program is subject to change. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Planned Development Program.”

Operated Projects	Location	Operator(s)	Wellbore Orientation	Target Primary Formation
Madera	Lea, NM	RMR Operating	Horizontal	Brushy Canyon
Tom Tom	Chaves and Roosevelt, NM	Cross Border	Vertical	San Andres
Cowden	Ector, TX	RMR Operating	Vertical	Grayburg, San Andres
Shafter Lake	Andrews, TX	RMR Operating	Vertical	San Andres
Jack Matthews	Pecos, TX	RMR Operating	Vertical	Devonian
Kansas	Rush, KS	RMR Operating	Vertical	Arbuckle, Lansing Kansas City
Non-Operated Projects	Location	Operator(s)	Wellbore Orientation	Target Primary Formation
Turkey Track	Eddy, NM	Mewbourne Oil Co.	Horizontal	1st/2nd  Bone Spring
Perla Verde	Lea, NM	XTO Energy Inc.	Horizontal	3rd Bone Spring
Red Lakes	Eddy, NM	Apache Corp.	Vertical	Glorieta, Yeso

Operational Update

Net production for the quarter ended June 30, 2014 was approximately 109.2 MBoe, which equates to approximately 1,200 Boe/d based on actual calendar days during the period.

Madera Prospect (Lea County, New Mexico). We own 2,545 gross (1,132 net) acres in the Madera Prospect. We have seven producing wells, one disposal well, and one well awaiting completion in this area. The Madera 25 Federal Com 2H well, which is awaiting completion, has been on hold pending resolution of a casing problem. We have resolved the casing issue, and we expect to complete the well with a 20 stage fracture stimulation in September 2014. We own an approximately 30% working interest and 23% net revenue interest in this well. The well is a long-lateral length well, consisting of a total measured depth of approximately 16,000 feet, and targets the Brushy Canyon reservoir. In addition to the Madera 25 Federal Com 2H well, we have eight gross (3.4 net) additional Brushy Canyon drilling locations, which includes six gross (2.9 net) long-lateral length well locations, each with a total measured depth of approximately 16,000 feet, and two gross (0.5 net) lateral wells, each with a total measured depth of approximately 14,000 feet.

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We are currently evaluating the additional potential in the Bone Spring, Upper Wolfcamp, and Middle Wolfcamp zones in the Madera Prospect. The three objectives provide 36 potential gross drilling locations (15.1 net), which include 24 gross (12.1 net) long lateral wells and 12 gross (3.0 net) single section lateral wells.

Tom Tom Area (Chaves and Roosevelt Counties, New Mexico). We own 8,300 gross (6,200 net) acres in the Tom Tom Area. We have developed a workover program to reenter, add pay, and retreat existing wells in the area. There are 28 gross wells (21.6 net) that we have identified with additional behind pipe pay, and an additional 21 gross wells (17.3 net) on which we expect to perform new acid and fracture stimulations. We commenced this workover program in June 2014.

The first workover was on the Strange Federal 1 well in which we own a 100% working interest and an approximately 75% net revenue interest. We added perforations and treated the well with acid. Its production increased by approximately 5 Bbl/d after the initial work. Subsequently, in August 2014, we fracture stimulated the well and are awaiting flow back results.

Kansas (Rush County, Kansas). We lease 9,868 gross and net acres in Rush County, Kansas. We recently acquired and processed seismic data over this acreage. Our primary targets in this area include the Arbuckle, Basal Penn, Reagan, and Lansing-Kansas City formations. Our initial plans include a seven well drilling program. The first of these wells, the Besperat #1, was spudded on August 1st and drilled to a depth of 3,850 feet. The well did not encounter commercial hydrocarbons and will be considered for conversion to a disposal well upon completion of the initial phase of the drilling program. The total dry hole cost was approximately $100,000. We moved the rig to the Koriel #1 drilling location where the Arbuckle formation is the primary target with additional potential in the Lansing-Kansas City formation and expect to spud the well in August 2014.

Turkey Track Prospect (Eddy County, New Mexico). We own a non-operated interest in the Turkey Track Prospect. The operator of this acreage, Mewbourne Oil Company, is actively drilling horizontal 1st and 2nd Bone Spring wells. The most recent completion, the Zircon 2 B1EH State 2H, is the first well targeting the 1st Bone Spring. The well was completed in July 2014 and achieved a maximum 24-hour production rate of 632 Boe/d (of which 87% was oil) and a 10-day average production rate of 549 Boe/d (of which 81% was oil). We own an approximately 13% working interest and 9% net revenue interest in this well.

On July 20, 2014, the operator spuded the Bradley 31 B2DA Federal Com 1H well, which is currently being drilled. This well targets the 2nd Bone Spring. We own an approximately 7% working interest and 5% net revenue interest in this well. Including this well, we have 11 gross locations (1.1 net) remaining targeting the 2nd Bone Spring and 12 gross locations (0.9 net) targeting the 1st Bone Spring.

Perla Verde Area (Lea County, New Mexico). We own non-operated interests in the Perla Verde Area. We recently approved drilling four gross wells (0.2 net). These wells, the Perla Verde 31 State Com 1H, 2H, 3H and 4H wells, will be operated by XTO Energy, Inc. We own working interests ranging from 4.7% to 6.3% and net revenue interests ranging from 3.5% to 4.7% in these wells.

Red Lakes Area (Eddy County, New Mexico). We own a non-operated interest in the Red Lakes Area. In June 2014, LRE Operating completed two vertical wells targeting the Yeso formation, the Southern Union 30G State 3 well and the Horseshoe State 3 well. We own an approximately 14% working interest and 12% net revenue interest in the Southern Union 30G State 3 well and an approximately 13% working interest and 9% net revenue interest in the Horseshoe State 3 well. Early production rates from the wells were 137 Boe/d (of which 88% was oil) and 140 Boe/d (of which 86% was oil), respectively.

We recently approved the drilling of four additional gross wells (0.9 net) in the Red Lakes Area. These wells, the T Rex 31 State 1, 2, 3, and 4 wells, will be operated by Apache Corp. We own an approximately 22% working interest and 16% net revenue interest in each of these wells.

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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 3.6 MMBoe at January 1, 2014, 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 93 gross wells (66.8 net) through fiscal 2015 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 LeasesHeld by Production. As of June 30, 2014, we controlled 310,392 net acres, 97% of which was in Texas and New Mexico. Included in this acreage position were approximately 290,000 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 net 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

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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. 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 wellsto substantially increase near-term production, resulting in faster payback periods and higher rates of return andpresent 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 July 15, 2014, our chairman of the board, chief executive officer and president, Alan Barksdale, beneficially owned 7.5% of our outstanding shares of common stock. As a result of his equity investment in us, we believe our management’s interests are highly aligned with our shareholders’ 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.

Corporate Information

Our principal executive office is located at 2515 McKinney Avenue, Suite 900, Dallas, Texas 75201. Our telephone number is (214) 871-0400. Our website address is www.redmountainresources.com. Information contained on or accessible through our website is not incorporated by reference into, or otherwise a part of, this prospectus supplement or the accompanying prospectus.

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THE OFFERING

The following is a brief summary of certain terms of the Series A Preferred Stock and this offering. For a more complete description of the terms of the Series A Preferred Stock, see “Description of the Series A Preferred Stock” beginning on page S-86 of this prospectus supplement.

Issuer Red Mountain Resources, Inc.

Securities offered by us                 shares of 10.0% Series A Cumulative Redeemable Preferred Stock, which are a further issuance of, form a single series with and have the same terms as, our outstanding Series A Preferred Stock.

Firm commitment Our underwriters are purchasing the shares of Series A Preferred Stock from us on a firm commitment basis for sale to the public at the offering price.

Dividends Holders of shares of the Series A Preferred Stock are entitled to receive, when, as and if declared by our board of directors, out of funds legally available for the payment of dividends under Texas law, cumulative cash dividends at the “Dividend Rate,” which rate shall be 10.0% of the $25.00 per share liquidation preference per year (equivalent to $2.50 per year per share) unless increased as described below.

In the event of a Dividend Default, Financial Covenant Default or Listing Default (each as defined below), the Dividend Rate on the Series A Preferred Stock may increase as more fully described below.

Dividends on the Series A Preferred Stock shall accrue daily and be cumulative from, and including, July 1, 2014, the first day of the most recent quarterly dividend period. The next scheduled dividend will be payable on October 15, 2014 in the amount of approximately $0.65 per share, which will be paid to the persons who are the holders of record of the Series A Preferred Stock at the close of business on the corresponding record date, which will be September 30, 2014.

Dividends on the Series A Preferred Stock are payable quarterly in arrears on January 15, April 15, July 15 and October 15 of each year following the applicable quarterly period (a “dividend payment date”). If any date on which dividends are first payable is not a business day, then the dividend is paid on the next succeeding business day, and no interest or additional dividends or other sums accrue as a result of any such delay.

A “dividend period” is the period commencing on the first day of each of January, April, July and October and ending on the day preceding the first day of the next succeeding dividend period, provided that any dividend period during which shares of Series A Preferred Stock shall be redeemed shall end on the day prior to the date of redemption.

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Dividends on the Series A Preferred Stock will accrue regardless of whether:

• the terms of any of our agreements, including any documents governing our indebtedness, at any time prohibit the declaration, payment or setting apart for payment, or provide that any such actions would constitute a breach or default;

• we have earnings or profits;

• there are funds legally available for the payment of such dividends; or

• such dividends are declared by our board of directors.

Any dividend payment made on the Series A Preferred Stock shall first be credited against the earliest accumulated but unpaid dividend due with respect to those shares.

The record date for each dividend payment date shall be the last day of the applicable dividend period.

Dividend Default Whenever dividends on any shares of Series A Preferred Stock are in arrears for six or more full quarterly dividend periods, whether or not consecutive (such event, a “Dividend Default”), (i) the holders of the Series A Preferred Stock will have the right to elect two directors in addition to those directors then serving on such board, voting separately as a class with holders of all other series of Parity Stock (as defined under “—Ranking” below) upon which like voting rights have been conferred and are exercisable and (ii) the Dividend Rate shall be increased to 12.0% (the “Default Rate”).

The Default Rate shall remain in effect until we have paid accrued but unpaid dividends on the Series A Preferred Stock and timely paid the accrued dividends for the two subsequent quarterly dividend payment periods, at which time the Dividend Rate shall revert to the rate of 10.0%, and the term of office of all directors so elected will terminate with the termination of such voting rights. The foregoing provisions will not be applicable unless there is again a Dividend Default.

Financial Covenant Default We are required to have an Asset Coverage Ratio (as defined below) of 2-to-1 or greater as of the date of any issuance of additional debt (excluding any borrowings under our 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 (such event, a “Financial Covenant Default”), the Dividend Rate will be increased to the Default Rate. The Default Rate shall remain in effect until our Asset Coverage Ratio on two consecutive quarterly balance sheets (not including the balance sheet for the quarter in which the Financial Covenant Default occurs) is 2-to-1 or greater, upon which the Dividend Rate shall revert to the rate of 10.0% effective as of the day after the second balance sheet date, and shall remain at 10.0% until a subsequent Financial Default occurs.

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“Asset Coverage Ratio” means the ratio, determined on a consolidated basis, without duplication, in accordance with generally accepted accounting principles, of (a) total assets less goodwill, intellectual property and other intangible assets but excluding intangible drilling costs, divided by (b) the sum of total debt plus the aggregate liquidation preference of Series A Preferred Stock, Senior Stock and Parity Stock then outstanding, less cash, cash equivalents and marketable securities. The Asset Coverage Ratio shall be calculated based on our balance sheet for the most recent fiscal period then ended that has been filed with the Securities and Exchange Commission (“SEC”) on a pro forma basis after giving effect to (i) the issuance of such additional debt (excluding any borrowings under the Credit Facility or any revolving credit facility in replacement thereof), Series A Preferred Stock, Senior Stock or Parity Stock and (ii) the application of the proceeds from the issuance of such additional debt (excluding any borrowings under the Credit Facility or any revolving credit facility in replacement thereof), Series A Preferred Stock, Senior Stock or Parity Stock. Notwithstanding the classification of the Series A Preferred Stock on our balance sheet, the Series A Preferred Stock shall not be deemed debt for purposes of the Asset Coverage Ratio.

Listing Default Our certificate of formation requires us to list the Series A Preferred Stock on a National Exchange prior to April 30, 2014. Because we are currently in default pursuant to this listing requirement, the Dividend Rate specified was increased by one-half percent on May 1, 2014 and shall be increased by one-half percent per quarter, up to a rate not to exceed the Default Rate, until such listing occurs at which time the Dividend Rate shall revert to the rate of 10.0% until a subsequent Listing Default occurs. We have applied to list the Series A Preferred Stock on the NASDAQ Capital Market concurrently with the consummation of this offering, at which time the Dividend Rate will revert to 10.0%.

Once the Series A Preferred Stock is listed a National Exchange, in the event we fail to maintain such listing for 180 consecutive days (such event, a “Listing Default”), then, until such failure is cured, (i) the Dividend Rate will increase to the Default Rate, and (ii) the holders of Series A Preferred Stock have the right to elect one director in addition to those directors then serving on such Board, voting separately as a class with holders of all other series of Parity Stock (as defined under “—Ranking” below) upon which like voting rights have been conferred and are exercisable. Once the Listing Default has been cured, the Dividend Rate will revert to the rate of 10.0% and the term of office of the director so elected will terminate with the termination of such voting rights until a subsequent Listing Default occurs.

“National Exchange” includes the New York Stock Exchange, or the NYSE, the NYSE MKT LLC, or the NYSE MKT, or NASDAQ Stock Market, or NASDAQ, or an exchange or quotation system that is a

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successor to the NYSE, NYSE MKT or NASDAQ or any comparable national securities exchange or national securities market.

Mandatory redemption The Series A Preferred Stock is subject to a mandatory redemption by the Company on July 15, 2018, for $25.00 per share, plus accrued and unpaid dividends.

Optional redemption The Series A Preferred Stock is currently redeemable, in whole or in part, at our option, at any time or from time to time, for cash at the redemption prices (expressed as percentages of the liquidation preference) set forth in the following table, plus accrued and unpaid dividends, if any, if redeemed during the twelve month period commencing on the dates set forth below:

Redemption Dates	Redemption Prices (expressed as percentage of liquidation preference)
July 15, 2014	105%
July 15, 2015	103%
July 15, 2016 and thereafter	100%

If we elect to redeem any shares of Series A Preferred Stock as described in this paragraph, we may use any available cash legally available under Texas law to pay the redemption price, and we will not be required to pay the redemption price only out of the proceeds from the issuance of other equity securities or any other specific source.

Redemption upon a Change of Control Upon the occurrence of a “Change of Control” (as defined below), we will be required to redeem the Series A Preferred Stock within 120 days after the first date on which such Change of Control occurred, for cash at a redemption price of $25.00 per share, plus any accrued and unpaid dividends.

A “Change of Control” is deemed to occur when, after the original issuance of the Series A Preferred Stock, the following has occurred and is continuing: (i) the acquisition by any person, including any syndicate or group deemed to be a “person” under Section 13(d)(3) of the Exchange Act, of beneficial ownership, directly or indirectly, through a purchase, merger or other acquisition transaction or series of purchases, mergers or other acquisition transactions of shares of our company entitling that person to exercise more than 50% of the total voting power of all shares of our company entitled to vote generally in elections of directors (except that such person will be deemed to have beneficial ownership of all securities that such person has the right to acquire, whether such right is currently exercisable or is exercisable only upon the occurrence of a subsequent condition) and (ii) following the closing of any transaction referred to in (i) above, neither we, if we are the surviving entity, nor the acquiring or surviving entity, if we are not the surviving entity, has a class of

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common securities (or American Depositary Receipts representing such securities) listed on a National Exchange; provided, that a merger effected to change our jurisdiction of incorporation shall not be deemed a Change of Control.

Ranking The Series A Preferred Stock ranks: (i) senior to all of our common stock and any other equity securities that we may issue in the future, the terms of which specifically provide that such equity securities rank junior to the Series A Preferred Stock, in each case with respect to payment of dividends and amounts upon liquidation, dissolution or winding up, which we refer to as “Junior Stock;” (ii) equal to any shares of equity securities that we may issue in the future, the terms of which specifically provide that such equity securities rank on par with such Series A Preferred Stock, in each case with respect to payment of dividends and amounts upon liquidation, dissolution or winding up, which we refer to as “Parity Stock;” (iii) junior to all other equity securities we issue, the terms of which specifically provide that such equity securities rank senior to the Series A Preferred Stock, in each case with respect to payment of dividends and amounts upon liquidation, dissolution or winding up (any such issuance would require the affirmative vote of the holders of at least two-thirds of the outstanding shares of Series A Preferred Stock), which we refer to as “Senior Stock;” and (iv) junior to all of our existing and future indebtedness.

As of July 15, 2014, we had outstanding indebtedness, excluding the Series A Preferred Stock, of $26.8 million, all of which was secured indebtedness.

Liquidation preferences If we liquidate, dissolve or wind up our operations, the holders of the Series A Preferred Stock will have the right to receive out of our assets legally available for distribution to shareholders an amount of cash equal to $25.00 per share, plus all accrued and unpaid dividends (whether or not declared) to and including the date of payment, before any payments are made to the holders of Junior Stock. The rights of the holders of the Series A Preferred Stock to receive the liquidation preference will be subject to the proportionate rights of holders of each other future series or class of Parity Stock and subordinate to the rights of Senior Stock. Please see the Section entitled “Description of the Series A Preferred Stock—Liquidation Preference.”

Voting rights Except to the extent required under Texas law, holders of the Series A Preferred Stock will generally have no voting rights. However, in the event of a (i) Dividend Default, or (ii) Listing Default, the holders of the Series A Preferred Stock, voting separately as a class with holders of all other series of Parity Stock upon which like voting rights have been conferred and are exercisable, will have the right to elect two directors, in the case of a Dividend Default, or one director, in the case of a Listing Default, to serve on our board of directors in addition to those directors then serving on our board. In no event will

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holders of the Series A Preferred Stock be entitled to elect more than two directors under the above default provisions, regardless of whether there is both a Dividend Default and a Listing Default.

Additionally, subject to certain exceptions, the affirmative consent of holders of at least two-thirds of the then-outstanding Series A Preferred Stock will be required for (i) amendments to our certificate of formation or bylaws that would affect materially and adversely the rights of holders of the Series A Preferred Stock, (ii) a statutory share exchange that affects the Series A Preferred Stock, or a merger or consolidation with another entity, unless the shares of Series A Preferred Stock would remain outstanding with no material or adverse changes to their terms or are substituted or exchanged for preferred equity of the surviving company having substantially similar rights, preferences and terms (except for changes that do not materially and adversely affect the Series A Preferred Stock), or (iii) the authorization, reclassification, creation, issuance, or increase in the authorized amount of, shares of any class or any security convertible or exchangeable for Senior Stock.

Material U.S. federal income tax consequences The material U.S. federal income tax consequences of purchasing, owning and disposing of Series A Preferred Stock are described in “Material U.S. Federal Income Tax Consequences.” Due to our history of losses for U.S. federal income tax purposes, you should consult your tax advisor with respect to the U.S. federal income tax consequences of owning the Series A Preferred Stock in light of your own particular situation and with respect to any tax consequences arising under the laws of any state, local, foreign or other taxing jurisdiction.

Listing; Market for Series A Preferred Stock There is currently no public market for the Series A Preferred Stock. We have applied to list the Series A Preferred Stock on the NASDAQ Capital Market concurrently with the consummation of this offering. If approved for listing, we expect that trading on the NASDAQ Capital Market will commence within 30 days after the date of issuance of the Series A Preferred Stock. The underwriters have advised us that they intend to make a market in the Series A Preferred Stock, but they are not obligated to do so and may discontinue market making at any time without notice. We cannot assure you that a market for the Series A Preferred Stock will develop prior to commencement of trading on the NASDAQ Capital Market or, if developed, will be maintained or will provide you with adequate liquidity.

Book-entry The Series A Preferred Stock will be issued and maintained in book-entry form registered in the name of the nominee of The Depository Trust Company, except under limited circumstances.

No exchange or conversion rights; No sinking fund The Series A Preferred Stock are not convertible into, or exchangeable for, any of our other property or securities. The Series A Preferred Stock is not subject to the operation of any purchase, retirement, or sinking fund.

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No Preemptive rights Holders of the Series A Preferred Stock will have no preemptive right to acquire shares of any class or series of our capital stock.

Use of proceeds We intend to use the net proceeds from this offering to fund a portion of our fiscal 2015 development program. See “Use of Proceeds.”

Risk factors Investing in the Series A Preferred Stock involves risk. You should carefully read and consider the information beginning on page S-21 of this prospectus supplement and page 3 of the accompanying prospectus set forth under the headings “Risk Factors” and all other information set forth in this prospectus supplement, the accompanying prospectus and the documents incorporated herein by reference before deciding to invest in the Series A Preferred Stock.

Settlement Delivery of the shares of Series A Preferred Stock will be made against payment therefor starting on or about                     , 2014.

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SUMMARY HISTORICAL FINANCIAL INFORMATION

The following summary historical financial information should be read together with our most recent Annual Report on Form 10-K for the fiscal year ended May 31, 2013 and Quarterly Report on Form 10-Q for the three months ended March 31, 2014, each of which is incorporated by reference in this prospectus supplement and accompanying prospectus. The summary historical consolidated statement of operations and cash flow data below for the fiscal years ended May 31, 2011, 2012 and 2013 and the nine months ended February 28, 2013 and March 31, 2014, and the summary historical balance sheet data as of May 31, 2012 and 2013 and March 31, 2014 have been derived from our historical consolidated financial statements that are incorporated by reference in this prospectus supplement and accompanying prospectus.

Our unaudited historical consolidated financial statements are prepared on the same basis as our audited consolidated financial statements and, in the opinion of management, all adjustments, consisting only of normal recurring adjustments, considered necessary for a fair presentation have been included. Historical results are not necessarily indicative of results to be expected in the future, and operating results for the nine months ended March 31, 2014 are not necessarily indicative of results that may be expected for the full year or future periods.

Prior to June 30, 2013, Red Mountain’s fiscal year ended on May 31. On July 17, 2013, our board of directors approved a change in our fiscal year end from May 31 to June 30, effective as of June 30, 2013.

	Fiscal Year Ended May 31,								Nine Months Ended						Three Months Ended March 31, 2014
(in thousands)	2011		2012			2013			February 28, 2013			March 31, 2014
STATEMENT OF OPERATIONS DATA:
Revenue:
Oil and natural gas sales	$	3,712	$	6,325		$	8,982		$	4,917		$	15,511		$	5,270
Operating Expenses:
Exploration expense		—		265			849			53			943			515
Production taxes		161		403			536			180			1,564			386
Lease operating expenses		165		943			1,769			966			2,088			633
Natural gas transportation and marketing expenses		236		170			104			77			117			43
Depletion, depreciation, amortization and impairment		717		5,149			4,515			3,193			6,712			2,460
Environmental remediation liability		—		—			—			—			—			—
Accretion of discount on asset retirement obligations		9		44			150			74			199			64
General and administrative expense		293		6,165			7,822			6,205			5,852			1,993
Total operating expense		1,581		13,139			15,745			10,748			17,475			6,094
Income (Loss) from Operations		2,131		(6,814	)		(6,763	)		(5,831	)		(1,964	)		(824	)

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	Fiscal Year Ended May 31,									Nine Months Ended						Three Months Ended March 31, 2014
(in thousands)	2011			2012			2013			February 28, 2013			March 31, 2014
STATEMENT OF OPERATIONS DATA:
Other Income (Expense):
Interest and other income		—			1			—			29			—			—
Bond issuance amortization		—			—			—			—			—			—
Change in fair value of derivative liability		—			—			496			182			—			—
Change in fair value of warrant liability		—			(763	)		—			—			—			—
Unrealized gain (loss) on investment in Cross Border Resources, Inc. warrants		899			282			(1,304	)		(1,304	)		—			—
Equity in earnings (losses) of Cross Border Resources, Inc.		—			(316	)		(332	)		(332	)		—			—
Gain on consolidation of Cross Border Resources, Inc.		—			—			682			736			—			—
Interest expense		(228	)		(2,097	)		(2,989	)		(2,310	)		(2,717	)		(902	)
Unrealized (loss) gain on commodity derivatives		—			—			—			177			(272	)		(41	)
Realized (loss) gain on derivatives		—			—			49			17			(74	)		(23	)
Impairment on debentures		—			—			(503	)		(503	)		—			—
Impairment on note receivable		—			(2,725	)		(856	)		(856	)		—			—
Total Other Income (Expense)		671			(5,618	)		(4,757	)		(4,164	)		(3,063	)		(966	)
Income (Loss) Before Income Taxes		2,802			(12,432	)		(11,520	)		(9,995	)		(5,027	)		(1,790	)
Income tax provision		—			—			—			—			—			—
Net Income (Loss)		2,802			(12,432	)		(11,520	)		(9,995	)		(5,027	)		(1,790	)
Net income attributable to noncontrolling interest		—			—			682			344			437			194
Net income (loss) attributable to Red Mountain Resources, Inc.	$	2,802		$	(12,432	)	$	(12,202	)	$	(10,339	)	$	(5,464	)	$	(1,984	)
Basic and diluted net income (loss) per common share	$	1.04		$	(1.69	)	$	(1.20	)	$	(1.10	)	$	(0.41	)	$	(0.15	)
Basic and diluted weighted average common shares outstanding		2,700			7,378			10,133			9,380			13,237			13,422

	As of May 31,				As of March 31, 2014
(in thousands)	2012		2013
BALANCE SHEET DATA:
Cash and cash equivalents	$	168	$	1,112	$	1,233
Oil and natural gas properties, net		23,680		75,132		84,992
Total assets		35,052		89,230		98,819
Line of credit		1,787		—		23,800
Total liabilities		14,732		42,273		51,018
Stockholders’ equity		20,320		46,957		47,801

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	Fiscal Year Ended May 31,									Nine Months Ended
(in thousands)	2011			2012			2013			February 28, 2013			March 31, 2014
CASH FLOW DATA:
Net cash provided by (used in) operating activities	$	1,716		$	(1,194	)	$	(10,213	)	$	(5,036	)	$	4,516
Net cash used in investing activities		(3,604	)		(18,267	)		(609	)		(178	)		(16,412	)
Net cash provided by financing activities		2,009			19,508			11,766			7,826			12,673

	Three Months Ended March 31, 2014
OTHER FINANCIAL DATA:
Adjusted EBITDAX (in thousands) (1)	$	2,478
Interest coverage ratio (2)		4.4x
Pro forma interest coverage ratio (2)		3.0x

(1) Adjusted EBITDAX is a non-GAAP financial measure that represents earnings before interest, income tax expense, exploration expense, depletion, depreciation, amortization and impairment expense, accretion of discount on asset retirement obligations, gains and losses on commodity derivatives and significant non-recurring expenses. We present Adjusted EBITDAX because we believe that such information is used by certain investors as a measure of company’s historical ability to fund capital expenditures and working capital requirements on a consistent basis without regard to depreciation, depletion and amortization and impairment of oil and natural gas properties and exploration expenses, which can vary significantly from period to period. In addition, our management uses Adjusted EBITDAX as a financial measure to evaluate our operating performance. Adjusted EBITDAX is not a measure of financial performance under GAAP, and it should not be considered as an alternative to net income (loss), operating income or any other performance measures derived in accordance with GAAP or as an alternative to cash flows from operating activities as a measure of our liquidity. The following table reconciles net loss to Adjusted EBITDAX for the period presented:

(in thousands)	Three Months Ended March 31, 2014
Net loss	$	(1,790	)
Adjustments:
Interest and other, net		902
Exploration expense		515
Depletion, depreciation, amortization and impairment		2,460
Accretion of discount on asset retirement obligation		64
Realized loss on commodity derivatives		23
Unrealized loss on commodity derivatives		41
Significant non-recurring expenses		263
Adjusted EBITDAX	$	2,478

(2) Interest coverage ratio represents the amount determined by dividing Adjusted EBITDAX by total cash interest expense. Pro forma interest coverage ratio represents the amount determined by dividing Adjusted EBITDAX by pro forma total cash interest expense. Total cash interest expense is a non-GAAP financial measure that represents total interest expense, which includes dividends on Series A Preferred Stock, less accretion of discount on preferred stock and amortization of debt issuance costs. Pro forma total cash interest expense reflects total cash interest expense, as adjusted to give effect to additional borrowings of $3.0 million under the Credit Facility subsequent to March 31, 2014 and the sale of 400,000 shares of Series A Preferred Stock in this offering, not including temporary repayment of amounts outstanding under the Credit Facility, as set forth under “Use of Proceeds.”

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Management believes that cash interest expense is useful for analyzing the cash flow needs and debt service requirements of the Company. However, cash interest expense is not intended to be used as an alternative to any measure of our financial condition in accordance with GAAP. The following table reconciles interest expense to total cash interest expense and pro forma total cash interest expense for the period presented:

(in thousands)	Three Months Ended March 31, 2014
Interest expense	$	902
Adjustments:
Accretion of discount on preferred stock		(181	)
Amortization of debt issuance costs		(164	)
Total cash interest expense		557
Proforma interest adjustment		276
Pro forma total cash interest expense	$	833

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SUMMARY RESERVES AND

HISTORICAL OPERATING DATA

The following tables present summary data with respect to our estimated proved reserves and historical production volumes and average prices as of and for the dates indicated.

Reserve estimates are inherently imprecise and remain subject to revisions based on production history, results of additional exploration and development drilling, results of secondary and tertiary recovery applications, prevailing oil and natural gas prices and other factors. You should read the notes following the table below and our consolidated financial statements and related notes incorporated by reference in this prospectus supplement in conjunction with the following reserve estimates.

Estimated Quantities of Proved Reserves

	As of January 1, 2014
	Reserves
Estimated proved reserve data (1)(2)	Oil (MBbls)		Natural Gas (MMcf)		Natural Gas Liquids (MBbls)		Total (MBoe)
Proved developed producing reserves		854		4,153		105		1,651
Proved developed non-producing reserves		148		309		—		200
Proved undeveloped reserves		1,335		1,811		84		1,721
Total proved reserves		2,337		6,273		189		3,572

(1) Prices used are based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the period January 2013 through December 2013. For oil volumes, the average NYMEX spot price is $96.78 per Bbl. For natural gas volumes, the average Henry Hub spot price is $3.67 per MMBtu. Each of the oil price of $88.93 per barrel, the natural gas liquids (“NGL”) price of $29.61 per barrel, and the natural gas price of $4.41 per Mcf is adjusted for basis differentials, hydrocarbon quality, and transportation, processing, and gathering fees. The adjusted oil, NGL and natural gas prices are held constant throughout the lives of the properties.

(2) Proved reserves include 100% of the reserve quantities attributable to Cross Border.

Production and Price History

	Fiscal Year Ended May 31,						Nine Months Ended,
	2011		2012		2013(1)		February 28, 2013 (1)		March 31, 2014
Net Production sold
Oil (Bbl)		—		37,004		83,143		43,754		123,624
Natural gas (Mcf)		900,332		795,659		645,609		432,810		650,334
Natural gas liquids (Bbl)		1,177		5,438		7,427		4,622		21,167
Total (Boe)		151,233		175,052		198,172		120,511		253,180
Total (Boe/d) (2)		414		480		543		441		924
Average sales prices
Oil ($/Bbl)	$	—	$	93.97	$	81.26	$	79.23	$	95.45
Natural gas ($/Mcf)		4.12		3.58		3.40		2.77		4.64
Natural gas liquids ($/Bbl)		40.28		46.45		29.62		31.19		27.82
Total average price ($/Boe)	$	24.54	$	36.13	$	45.32	$	42.43	$	60.84

(1) The results for the fiscal year ended May 31, 2013 and the nine months ended February 28, 2013 only include results and estimated net production sold from Cross Border since February 1, 2013.

(2) Boe/d is calculated based on actual calendar days during the period.

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RISK FACTORS

Investing in our Series A Preferred Stock involves a high degree of risk. In addition to the other information contained in this prospectus supplement and accompanying prospectus and in documents that we incorporate by reference, you should carefully review and consider the risks discussed below, and the other risk factors contained or incorporated by reference in this prospectus supplement before making a decision about investing in our securities. Investors are encouraged to consult with their own financial, legal and business advisors before making any decision regarding an investment. The risks and uncertainties discussed below, and the other risk factors contained or incorporated by reference in this prospectus supplement, are not the only ones facing us. Additional risks and uncertainties not presently known to us, or that we currently see as immaterial, may also harm our business. If any of these risks occur, our business, financial condition and operating results could be harmed, the market value of the Series A Preferred Stock could decline and you could lose part or all of your investment.

If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, actual outcomes may vary materially from those contained in any forward-looking statement included or incorporated by reference in this prospectus supplement. See “Cautionary Statement Regarding Forward-Looking Statements.”

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, Independent Bank (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 (as defined herein), including, among other things, a default in the payment of principal, interest or other amounts due under the Credit Facility, certain loan documents or hydrocarbon hedge agreements, a material inaccuracy of a representation or warranty, a 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.

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Prospects that we decide to drill may not yield oil or natural gas in commercially viable quantities.

Prospects that we decide to drill that do not yield oil or natural gas in commercially productive quantities will adversely affect our financial condition and results of operations. Our prospects are in various stages of evaluation, and may range from a prospect which is ready to drill to a prospect that will require substantial additional seismic data processing and interpretation and other technical analysis. There is no way to predict in advance of drilling and testing whether any particular prospect will yield oil or natural gas in sufficient quantities to recover drilling or completion costs or to be commercially productive. The use of seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in commercial quantities. We cannot assure you that the analogies we draw from available data from other wells, more fully explored prospects or producing fields will be applicable to our drilling prospects.

Our producing properties are concentrated in the Permian Basin of Southeast New Mexico and West Texas, making us vulnerable to risks associated with operating in one major geographic area. In addition, we have a large amount of proved reserves attributable to a small number of producing horizons within this area.

Our producing properties are geographically concentrated in the Permian Basin of Southeast New Mexico and West Texas. At January 1, 2014, approximately 90% of our proved reserves were concentrated in this area. Additionally, for the nine months ended March 31, 2014, we derived 90% 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 NGLs.

In addition to the geographic concentration of our producing properties described above, at January 1, 2014, approximately (i) 27% of our proved reserves were attributable to the Madera Prospect, (ii) 13% of our proved reserves were attributable to the Tom Tom Prospect. (iii) 19% of our proved reserves were attributable to the Lusk Prospect and (iv) 15% of our proved reserves were attributable to the Turkey Track 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.

Approximately 48% of our total estimated proved reserves as of January 1, 2014 were classified as proved undeveloped and may not be ultimately developed or produced.

As of January 1, 2014, approximately 48% 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 between $40.0 million and $50.0 million for fiscal 2015. 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.

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

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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 thePV-10 estimate.

Drilling for and producing oil and natural gas are speculative activities and involve numerous risks and substantial and uncertain costs that could adversely affect us.

Our future financial condition and results of operations will depend on the success of our acquisition, exploitation, development and production activities. Our oil and natural gas exploration and production activities are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially productive oil or natural gas reservoirs. Our decisions to acquire, explore, develop or otherwise exploit drilling locations or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. In addition, our cost of drilling, completing and operating wells is often uncertain before drilling commences. Overruns in budgeted expenditures are common risks that can make a particular project uneconomical. Further, many factors may curtail, delay or cancel our scheduled drilling projects, including the following:

• shortages of or delays in obtaining equipment and qualified personnel;

• facility or equipment malfunctions;

• unexpected operational events;

• pressure or irregularities in geological formations;

• adverse weather conditions, such as flooding;

• reductions in oil and natural gas prices;

• delays imposed by or resulting from compliance with regulatory requirements;

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• 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.

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.

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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.

We cannot control the development of the properties we do not operate, which may adversely affect our production, revenues and results of operations.

We do not operate all of the properties in which we have an interest. As a result, we have limited ability to exercise influence over, and control the risks associated with, the operation of these properties. The success and timing of our drilling and development activities on those properties depend upon a number of factors outside of our control, including:

• the timing and amount of capital expenditures;

• the operators’ expertise and financial resources;

• the approval of other participants in drilling wells; and

• the selection of suitable technology.

As a result of any of the above or an operator’s failure to act in ways that are in our best interest, our allocated production revenues and results of operations could be adversely affected.

If oil and natural gas prices decrease, we may be required to take write-downs of the carrying values of our oil and natural gas properties.

We will review our proved oil and natural gas properties for impairment whenever events or changes in circumstances indicate that a decline in the recoverability of their carrying value may have occurred. Based on specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write down the carrying value of our oil and natural gas properties, which may result in a decrease in the amount of future permitted indebtedness available. A write-down constitutes a non-cash charge to earnings. We may incur impairment charges in the future, which could have a material adverse effect on our results of operations for the periods in which such charges are taken.

Unless we replace oil and natural gas reserves, our production and cash flows will decline.

Our future success will depend on our ability to find, develop or acquire additional reserves that are commercially productive. If we are unable to replace reserves through drilling or acquisitions, our level of production and cash flows will be adversely affected. In general, production from oil and natural gas properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. Our total proved reserves decline as reserves are produced unless we conduct other successful exploration and development activities or acquire properties containing proved reserves, or both. Our ability to make the necessary capital investment to maintain or expand our asset base of oil and natural gas reserves would be impaired to the extent cash flow from operations is reduced and external sources of capital become limited or unavailable. We may not be successful in exploring for, developing or acquiring additional reserves. We also may not be successful in raising funds to acquire, explore or develop additional reserves.

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Our operations are subject to hazards inherent in the oil and natural gas industry.

We implement hydraulic fracturing in our operations, a process involving the injection of fluids—usually consisting mostly of water but typically including small amounts of several chemical additives—as well as sand in order to create fractures extending from the wellbore through the rock formation to enable oil or natural gas to move more easily through the rock pores to a production well. Risks inherent to our industry include the potential for significant losses associated with damage to the environment. Equipment design or operational failures, or vehicle operator error can result in explosions and discharges of toxic gases, chemicals and hazardous substances, and, in rare cases, uncontrollable flows of natural gas or well fluids into environmental media, as well as personal injury, loss of life, long-term suspension or cessation of operations and interruption of our business and/or the business or livelihood of third parties, damage to geologic formations, environmental media and natural resources, equipment and/or facilities and property. In addition, we use and generate hazardous substances and wastes in our operations and may become subject to claims relating to the release of such substances into the environment. In addition, some of our current properties could contain currently unknown contamination that could expose us to governmental requirements or claims relating to environmental remediation, personal injury and/or property damage. These conditions could expose us to liability for personal injury, wrongful death, property damage, loss of oil and natural gas production, pollution and other environmental damages and could materially impair our profitability, competitive position or viability. Depending on the frequency and severity of such liabilities or losses, it is possible that our operating costs, insurability and relationships with employees and regulators could be materially impaired.

The unavailability or high cost of drilling rigs, equipment, supplies, personnel and oilfield services could adversely affect our ability to execute exploration plans on a timely basis and within budget.

We are highly dependent upon third-party services. The cost of oilfield services typically fluctuates based on demand for those services. There is no assurance that we will be able to contract for such services on a timely basis or that the cost of such services will remain at a satisfactory or affordable level. Shortages or the high cost of drilling rigs, equipment, supplies or personnel could delay or adversely affect our exploration operations, which could have a material adverse effect on our business, financial condition or results of operations.

Our business and operations may be adversely affected by regulations affecting the oil and natural gas industry.

Our business and operations are subject to and impacted by a wide array of federal, state, and local laws and regulations on the exploration for and development, production, and marketing of oil and natural gas, the operation of oil and natural gas wells, taxation, and environmental and safety matters. Many laws and regulations require drilling permits and govern the spacing of wells, rates of production, prevention of waste and other matters. From time to time, regulatory agencies have imposed price controls and limitations on production in order to conserve supplies of oil and natural gas. In addition, the production, handling, storage, transportation and disposal of oil and natural gas, byproducts thereof and other substances and materials produced or used in connection with oil and natural gas operations are subject to regulation under federal, state and local laws and regulations.

Currently, federal regulations provide that drilling fluids, produced waters and other wastes associated with the exploration, development or production of oil and natural gas are exempt from regulation as “hazardous waste.” From time to time, legislation has been proposed to eliminate or modify this exemption. Should the exemption be modified or eliminated, wastes associated with oil and natural gas exploration and production would be subject to more stringent regulation. On the federal level, operations on our properties may be subject to various federal statutes, including the Natural Gas Act, the Comprehensive Environmental Response, Compensation and Liability Act, the Solid Waste Disposal Act, as amended by the Resource Conservation and Recovery Act, the Clean Air Act, the National Environmental Policy Act, the Endangered Species Act, the Toxic Substances Control Act, the Federal Water Pollution Control Act and the Oil Pollution Act, as well as by regulations promulgated pursuant to these actions.

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These regulations may subject us to increased operating costs and potential liability associated with the use and disposal of hazardous materials. These laws and regulations may have a material adverse effect on our financial condition and results of operations as there can be no assurance that we will not be required to make material expenditures in the future. Moreover, the technical requirements of these laws and regulations are becoming increasingly stringent, complex and costly to implement. The high cost of compliance with applicable regulations may cause us to limit or discontinue our operation and development activities.

Changes in regulations and laws relating to the oil and natural gas industry could result in our operations being disrupted or curtailed by government authorities. For example, oil and natural gas exploration and production may become less cost effective and decline as a result of increasingly stringent environmental requirements (including land use policies responsive to environmental concerns and delays or difficulties in obtaining environmental permits). A decline in exploration and production, in turn could have a material adverse effect on our business, financial condition, results of operations and cash flows.

We may have difficulty managing growth in our business, which could adversely affect our financial condition and results of operations.

As a small company, growth in accordance with our business plan, including our fiscal 2015 development plan, if achieved, could place a significant strain on our financial, technical, operational and management resources. As we expand our activities, increase the number of projects we are evaluating or in which we participate, there will be additional demands on our financial, technical, operational and management resources. The failure to continue to upgrade our technical, administrative, operating and financial control systems or the occurrences of unexpected expansion difficulties, including the failure to recruit and retain experienced managers, geologists, engineers and other professionals in the oil and natural gas industry, could have a material adverse effect on our business, financial condition and results of operations and our ability to timely execute our business plan.

Federal and state legislative and regulatory initiatives as well as governmental reviews relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays as well as adversely affect our level of production.

Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons from tight formations. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The process is typically regulated by state oil and gas commissions. However, the U.S. Environmental Protection Agency (“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 June 2011, the State of Texas adopted regulations requiring public disclosure of all the chemicals in fluids used in the hydraulic fracturing process. Also, in May 2013, the Railroad Commission of Texas adopted new requirements for well construction and integrity testing. 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. On May 19, 2014, the EPA issued an advance notice of proposed rulemaking pursuant to the Toxic Substances Control Act, requesting comments on the information

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that should be reported or disclosed for hydraulic fracturing chemical substances and mixtures and the mechanism for obtaining this information. 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. The EPA is also updating chloride water quality criteria for the protection of aquatic life under the Clean Water Act, which criteria are used by states for establishing acceptable discharge limits. Moreover, the EPA announced in October 2011 that it was 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 Clean Air Act (“CAA”) that, among other things, imposed New Source Performance Standards (“NSPS”) for completions of hydraulically fractured natural gas wells, requiring the use of reduced emission completion techniques.

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 key personnel, including Alan Barksdale, our President and Chief Executive Officer, Hilda Kouvelis, our Chief Accounting Officer, and Tommy Folsom, Executive Vice President and Director of Exploration and Production for RMR Operating. These individuals have extensive experience and expertise in evaluating and analyzing producing oil and natural gas properties and drilling prospects, maximizing production from oil and natural gas properties and developing and executing financing strategies. Although we have employment agreements with Ms. Kouvelis and Mr. Folsom, we do not currently

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have an employment agreement with Mr. Barksdale and he is free to terminate his employment with us at any time and compete with us immediately thereafter. The loss of any of these individuals could have a material adverse effect on our operations. We do not maintain key-man life insurance with respect to any management personnel. Our success will be dependent on our ability to continue to retain and utilize skilled technical personnel.

Our business is difficult to evaluate because we have a limited operating history.

Prior to June 2010, we had no material operations. After our June 2010 acquisition of oil and natural gas properties in Zapata County and Duval County in the onshore Gulf Coast of Texas, we began to recognize revenue from our operations. Accordingly, we have a very short financial operating history and 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.

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

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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 could suffer the loss of all or part of the expenses that we prepay to the operators of our properties.

We may be required prepay to the operators of our properties our contractual share of acreage, geophysical and geological costs and other up-front expenses, and drilling and completion costs, on a well-by-well basis. Once a prepayment is made, the operator is under no requirement to keep such funds segregated from funds received by other working interest owners. As a result of any prepayment, we would become a general unsecured creditor of the operator and, therefore, could suffer the loss of all or part of the amount prepaid in the event that an operator has financial difficulties, liens are placed against the operator’s assets or the operator files for bankruptcy.

If we are unable to find purchasers of our natural gas, it could harm our profitability.

There generally are only a limited number of natural gas transmission companies with existing pipelines in the vicinity of a natural gas well or wells. In the event that producing natural gas properties are not subject to purchase contracts or that any such contracts terminate and other parties do not purchase our natural gas production, there is no assurance that we will be able to enter into purchase contracts with any transmission companies or other purchasers of natural gas and there can be no assurance regarding the price which such purchasers would be willing to pay for such natural gas. There presently exists an oversupply of natural gas in the marketplace, the extent and duration of which is not known. Such oversupply may result in reductions of purchases by principal natural gas pipeline purchasers.

We could lose leases on certain of our properties unless production is established and maintained on units containing the acreage or the leases are extended.

Oil and natural gas leases generally must be drilled before the end of the lease term or the leaseholder will lose the lease and any capital invested therein. In addition, leases may also be lost due to legal issues relating to the ownership of leases. Any delays in drilling or legal issues causing us to lose leases on properties could have a material adverse effect on our results of operations and reserve growth.

At June 30, 2014, of our total undeveloped leasehold acreage, 31.0% 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.

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Delays in obtaining permits by us for our operations could impact our business.

We are required to obtain permits from one or more governmental agencies in order to perform drilling and completion activities, including hydraulic fracturing. Such permits are typically required by state agencies, but can also be required by federal and local governmental agencies. As with all governmental permitting processes, there is a degree of uncertainty as to whether a permit will be granted, the time it will take for a permit to be issued, and the conditions which may be imposed in connection with the granting of the permit. Hydraulic fracturing activities, which we estimate will represent approximately 80% of our forecasted development costs for fiscal 2015, has been particularly scrutinized. In particular, there is a growing trend of local and municipal initiatives to regulate drilling and completion activities. For example, a number of municipalities in Colorado have initiated bans or moratoriums on certain drilling and completion activities, including hydraulic fracturing. In addition, some municipalities (including Denton, Texas) have adopted temporary moratoriums on gas well permits while longer-term measures are considered. In New York, numerous municipalities have enacted bans or moratoriums on hydraulic fracturing. Furthermore, on June 30, 2014, the New York State Court of Appeals, the highest court in the state, held that municipalities can effectively “zone out” oil and gas operations by passing zoning ordinances that ban oil and gas production activities, including hydraulic fracturing, within municipal boundaries. State governments have also taken actions to regulate hydraulic fracturing activities. New York, for example, has had a moratorium in place since 2008 prohibiting the issuance of oil and gas well permits for hydraulic fracturing. In addition, on May 16, 2012, the Governor of Vermont signed a bill banning hydraulic fracturing in the state of Vermont. To our knowledge, Texas is not currently considering such a measure. If we are unable to obtain the necessary permits for our operations or if we experience delays in obtaining permits, it could have a material adverse effect on our results of operations and profitability.

Market conditions or transportation impediments may hinder access to oil and natural gas markets or delay production.

Market conditions, the unavailability of satisfactory oil and natural gas transportation or the remote location of our drilling operations may restrict our access to oil and natural gas markets or delay production. The availability of a ready market for oil and natural gas production depends on a number of factors, including the demand for and supply of oil and natural gas, the proximity of reserves to pipelines or trucking and terminal facilities and the availability of trucks and other transportation equipment. We may be required to shut-in wells or delay initial production for lack of a viable market or because of inadequacy or unavailability of pipeline or gathering system capacity. When that occurs, we will be unable to realize revenue from those wells until the production can be tied to a gathering system. This can result in considerable delays from the initial discovery of a reservoir to the actual production of the oil and natural gas and realization of revenues.

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;

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• reservoir damage;

• oil spills;

• pollution and other damage to the environment; and

• releases of toxic gas.

In addition, our operations are susceptible to damage from natural disasters such as flooding or tornados, which involve increased risks of personal injury, property damage and marketing interruptions. The occurrence of one of these operating hazards may result in injury, loss of life, suspension of operations, environmental damage and remediation and/or governmental investigations and penalties. The payment of any of these liabilities could reduce, or even eliminate, the funds available for exploration and development, or could result in a loss of our properties. In addition, pollution and environmental risks generally are not fully insurable. If a significant accident or other event occurs and is not fully covered by insurance, it could materially adversely affect our financial condition, results of operations and cash flows.

Our insurance might be inadequate to cover our liabilities. Insurance costs are expected to continue to increase over the next few years, and we may decrease coverage and retain more risk to mitigate future cost increases. If we incur substantial liability, and the damages are not covered by insurance or are in excess of policy limits, then our business, results of operations and financial condition may be materially adversely affected.

Production of oil and natural gas could be materially and adversely affected by natural disasters or severe or unseasonable weather.

Production of oil and natural gas could be materially and adversely affected by natural disasters or severe weather. Weather related risks include earthquakes, hurricanes and other adverse weather and environmental conditions. The occurrence of one or more of these events could result in a decrease in production of oil and natural gas. Repercussions of natural disasters or severe weather conditions may include:

• evacuation of personnel and curtailment of operations;

• damage to drilling rigs or other facilities, resulting in suspension of operations;

• inability to deliver materials to worksites; and

• damage to pipelines and other transportation facilities.

In addition, our hydraulic fracturing operations require significant quantities of water. Texas recently has experienced drought conditions. Any diminished access to water for use in hydraulic fracturing, whether due to usage restrictions or drought or other weather conditions, could curtail our operations or otherwise result in delays in operations or increased costs.

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.

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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.

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.

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For example, on February 11, 2013, the DOI Bureau of Land Management (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 up to $2.1 million during our fiscal 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 greenhouse gases (“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 Safe Drinking Water Act (“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 seeks to achieve a 95% reduction in volatile organic compounds (“VOCs”) emitted by requiring the use of reduced emission completions or “green completions” on all hydraulically-fractured wells constructed or refractured after January 1, 2015. These rules may require a number of modifications to our operations, including the installation of new equipment to control emissions from our wells by January 1, 2015. The EPA received numerous requests for reconsideration of these rules from both industry and the environmental community, and court challenges to the rules were also filed. The EPA intends to issue revised rules responsive to some of these requests. On September 23, 2013, the EPA finalized the portion of the rule addressing VOC emissions from storage tanks, including a phase-in period and an alternative emissions limit for older tanks. On July 1, 2014, the EPA announced proposed amendments and clarifications to the NSPS standards. 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.

In May 2010, the EPA adopted its so-called GHG tailoring rule to 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. On June 23, 2014, the Supreme Court held that stationary sources of GHGs could not become subject to prevention of significant deterioration or Title V permitting merely by reason of their GHG emissions. The Court also ruled that the EPA may require installation of best available control technology for GHG emissions at sources otherwise subject to the PSD and Title V

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programs. The EPA has announced that it is currently evaluating the decision and awaiting further action by the courts, and that it will provide relevant guidance on GHG permitting requirements. Those permitting requirements, 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 September 2009, the EPA also issued a final rule requiring the reporting of GHG emissions from specified large GHG emission sources in the U.S., including NGLs fractionators and local natural gas/distribution companies, 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. In addition, in September 2013, the EPA issued a proposed rule that, if finalized, would set NSPS standards for GHG emissions at new fossil-fuel fired power plants. Finally, on June 2, 2014, the EPA issued the so-called Clean Power Plan proposed rules, which propose state-specific rate-based goals to reduce GHG emissions from existing fossil-fuel fired power plants.

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.

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Risks Related to This Offering

The Series A Preferred Stock does not have an established trading market, which may negatively affect its market value and your ability to transfer or sell your shares.

The Series A Preferred Stock does not have an established trading market. The trading market for investors seeking liquidity may be limited. We have filed an application to list the Series A Preferred Stock on the NASDAQ Capital Market concurrently with the closing of this offering. However, we cannot assure you that the Series A Preferred Stock will be approved for listing on the NASDAQ Capital Market. Even if so approved, trading of the Series A Preferred Stock on the NASDAQ Capital Market is not expected to begin until some time during the period ending 30 days after the date of issuance of the Series A Preferred Stock, and, in any event, an active trading market for the shares may not develop or, even if it develops, may not last. Certain of the underwriters have advised us that they intend to make a market in the Series A Preferred Stock, but are not obligated to do so and may discontinue market making at any time without notice. The liquidity of any market for the Series A Preferred Stock that may develop will depend on a number of factors, including prevailing interest rates, our financial condition and operating results, the number of holders of the Series A Preferred Stock, the market for similar securities and the interest of securities dealers in making a market in the Series A Preferred Stock. As a result, the trading price of the shares could be adversely affected and your ability to transfer your shares of Series A Preferred Stock 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 your ability to transfer your 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, you will only receive cash dividends on the Series A Preferred Stock when, as and if declared by our board of directors, and if we have funds legally available for the payment of dividends under Texas law and such payment is not restricted or prohibited by law or the terms of any of our agreements, including the documents governing our indebtedness. On July 19, 2013, we entered into an amendment to our Credit Agreement to permit the payment of 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

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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 June 30, 2014, our total outstanding indebtedness, excluding the Series A Preferred Stock, was approximately $26.8 million, and we had approximately $3.2 million in unused borrowing capacity under the Credit Facility. We may incur additional indebtedness in the future to finance acquisitions or the development of properties, and the terms of the Series A Preferred Stock do not require us to obtain the approval of the holders of the Series A Preferred Stock prior to incurring additional indebtedness. As a result, our existing and future indebtedness may be subject to restrictive covenants or other provisions that may prevent or otherwise limit our ability to make dividend or liquidation payments on the Series A Preferred Stock. Upon our liquidation, our obligations to our creditors would rank senior to the Series A Preferred Stock and would be required to be paid before any payments could be made to holders of the Series A Preferred Stock.

Holders of Series A Preferred Stock have extremely limited voting rights.

Except as expressly stated in our certificate of formation, as a holder of Series A Preferred Stock, you will not have any relative, participating, optional or other special voting rights and powers and your approval will not be required for the taking of any corporate action. For example, your approval would not be 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, as described in “Description of the Series A Preferred Stock—Voting Rights”), 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. See “Description of the Series A Preferred Stock—Voting Rights.”

The issuance in future offerings of preferred stock may adversely affect the value of the Series A Preferred Stock.

Our certificate of formation currently authorizes the issuance of up to 100,000,000 shares of preferred stock in one or more series on terms that may be determined at the time of issuance by the our board of directors, including up to 1,200,000 shares of Series A Preferred Stock, of which 254,463 shares are currently outstanding. Upon the completion of the offering described in this prospectus supplement, we may increase the number of authorized shares of Series A Preferred Stock and offer for sale additional shares of Series A Preferred Stock in the future without your consent. Accordingly, we may issue additional shares of Series A Preferred Stock and/or Parity Stock or, with the consent of the holders of the Series A Preferred Stock, Senior Stock. The issuance of Series A Preferred Stock, Parity Stock or Senior Stock would dilute the interests of the holders of Series A Preferred Stock, and any issuance of Senior Stock could affect our ability to pay dividends on, redeem or pay the liquidation preference on the Series A Preferred Stock.

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Holders of the Series A Preferred Stock may be unable to use the dividends-received deduction and may not be eligible for the preferential tax rates applicable to “qualified dividend income.”

We may not have sufficient current or accumulated earnings and profits during future fiscal years for the distributions on the Series A Preferred Stock (or our common stock should we determine to pay distributions on it) to qualify as dividends for U.S. federal income tax purposes. If the distributions fail to qualify as dividends, U.S. holders that are corporations would be unable to use the dividends-received deduction and may not be eligible for the preferential tax rates applicable to “qualified dividend income.” If any distributions on the Series A Preferred Stock with respect to any fiscal year are not eligible for the dividends-received deduction or preferential tax rates applicable to “qualified dividend income” because of insufficient current or accumulated earnings and profits, it is possible that a U.S. holder that is a corporation could recognize capital gain income upon receipt of a distribution or upon disposition of shares of Series A Preferred Stock. Because of the way corporations are taxed on capital gain income, such capital gains, absent offsetting capital losses, would be effectively taxed to a corporate owner of our preferred stock (or common stock) at then current ordinary income tax rates. For additional information concerning these matters, see “Material U.S. Federal Income Tax Consequences—Corporate Dividends Received Deduction.”

The Series A Preferred Stock is not convertible, is currently redeemable at our option at specified redemption prices and is mandatorily redeemable in certain circumstances.

The Series A Preferred Stock accrues dividends at a fixed rate and is not convertible into 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.

In addition, we currently have the option to redeem the Series A Preferred Stock, in whole or in part, at our option, at any time or from time to time, for cash at the redemption prices (expressed as percentages of the liquidation preference) set forth in the following table, plus accrued and unpaid dividends, if any, if redeemed during the twelve month period commencing on the dates set forth below:

Redemption Dates	Redemption Prices (expressed as  percentage of liquidation preference)
July 15, 2014	105%
July 15, 2015	103%
July 15, 2016 and thereafter	100%

Moreover, the Series A Preferred Stock is subject to a mandatory redemption on July 15, 2018 or upon a “Change of Control.” These redemption provisions could also impose a ceiling on the value of the Series A Preferred Stock.

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. If we fail to comply with the Financial Covenant, the Dividend Rate will be increased to the Default Rate. 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.

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We may not be able to comply with the Listing Covenant for the Series A Preferred Stock, and listing on a National Exchange does not guarantee a market for the Series A Preferred Stock.

Our certificate of formation requires us to list the Series A Preferred Stock on a National Exchange prior to April 30, 2014. Because we are currently in default pursuant to this listing requirement, the Dividend Rate specified was increased by one-half percent on May 1, 2014 and shall be increased by one-half percent per quarter, up to a rate not to exceed the Default Rate, until such listing occurs at which time the Dividend Rate shall revert to the rate of 10.0% until a subsequent Listing Default occurs.

We have applied to list the shares of the Series A Preferred Stock on the NASDAQ Capital Market concurrently with the consummation of this offering, at which time the Dividend Rate will revert to 10.0%. The NASDAQ may decline our application to be listed on such exchange. Further, our identification of certain material weaknesses in our internal control over financial reporting included in our Annual Report on Form 10-K for the fiscal year ended May 31, 2013 may make it more difficult to qualify for listing on the NASDAQ Capital Market. Even if the NASDAQ 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 the NASDAQ Capital Market, 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, as described under “Description of the Series A Preferred Stock—Voting Rights.” The NASDAQ could delist the Series A Preferred Stock, which may result in a Listing Default.

The foregoing may limit your ability to transfer your shares and could adversely affect the trading price of shares of the Series A Preferred Stock. See “—The Series A Preferred Stock does not have an established trading market, which may negatively affect its market value and your ability to transfer or sell your shares.”

We may use the net proceeds from this offering in ways with which you may not agree.

While we currently intend to use the proceeds from this offering to fund a portion of our fiscal 2015 development program, we have considerable discretion in the application of the proceeds. You will not have the opportunity, as part of your investment decision, to assess whether the proceeds are being used in a manner agreeable to you. You must rely on our judgment regarding the application of the net proceeds of this offering. The net proceeds may be used for corporate purposes that do not immediately improve our profitability or increase the price of our shares.

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USE OF PROCEEDS

We intend to use the net proceeds from this offering to fund a portion of our fiscal 2015 development program. Proceeds to be used for drilling and development will be used to repay amounts outstanding under our Credit Facility until the expected drilling and development expenses are incurred. Amounts repaid under our Credit Facility may be reborrowed.

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RATIO OF EARNINGS TO FIXED CHARGES

	Fiscal Year Ended May 31,											Nine Months Ended March 31, 2014
	2010			2011		2012			2013
Ratio of earnings to fixed charges (1)(2)		(3	)		13.3x		(4	)		(4	)		(4	)

(1) For purposes of calculating the ratio of earnings to combined fixed charges and preferred stock dividends, “earnings” represents income (loss) before income taxes and before adjustment for income or loss from equity investees plus fixed charges. “Fixed charges” includes interest expense, capitalized interest and the portion of rental expense that management believes is representative of the interest component of rental expense.

(2) Represents ratio of earnings to combined fixed charges and preferred stock dividends. “Preferred stock dividends” consist of the amount of pre-tax earnings required to pay dividends on the outstanding Series A Preferred Stock. Preferred stock was outstanding only during the nine months ended March 31, 2014. Because no preferred stock was outstanding for the fiscal year ended May 31, 2013 and prior periods, no historical ratios of earnings to combined fixed charges and preferred stock dividends are presented for these periods.

(3) The Company commenced operations on June 1, 2010 with the purchase of two separate oil and natural gas fields. As a result, no ratio is presented for the fiscal year ended May 31, 2010 or prior periods.

(4) For these periods, earnings were insufficient to cover fixed charges. The amount of the coverage deficiencies were $12.4 million and $11.5 million for the fiscal years ended May 31, 2012 and 2013, respectively, and $5.0 million for the nine months ended March 31, 2014.

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CAPITALIZATION

The following table presents a summary of our cash and cash equivalents and capitalization as of March 31, 2014:

• on an actual basis;

• on an as adjusted basis, after giving effect to (i) additional borrowings of $3.0 million under the Credit Facility subsequent to March 31, 2014; and (ii) the exchange of 222,224 outstanding shares of our Series A Preferred Stock for the issuance of 1,388,898 shares of common stock effective as of April 1, 2014; and

• on a further adjusted basis, after giving effect to the issuance of             shares of Series A Preferred Stock offered to the public by this prospectus supplement and the accompanying prospectus, assuming net proceeds of $         million, after deducting underwriting discounts and commissions and other offering expenses payable by us.

You should read the following table in conjunction with our historical consolidated financial statements and the related notes thereto incorporated by reference into this prospectus supplement.

	March 31, 2014
(in thousands)	Actual			As Adjusted			As Further Adjusted
Cash and cash equivalents	$	1,233		$	1,233		$
Debt
Credit Facility (1)	$	23,800		$	26,800		$
Series A Preferred Stock, net of discount (2)		8,812			4,704
Stockholders’ equity
Common stock		1			1
Noncontrolling interest		6,001			6,001
Additional paid-in-capital		72,077			77,910
Accumulated deficit		(30,278	)		(30,278	)
Total stockholders’ equity		47,801			53,634
Total capitalization	$	80,413		$	85,138		$

(1) Proceeds to be used for drilling and development will be used to repay amounts outstanding under our Credit Facility until the expected drilling and development expenses are incurred. Amounts repaid under our Credit Facility may be reborrowed.

(2) The amounts shown actual, as adjusted and as further adjusted are net of an original issue discount of $3.1 million, $1.7 million and $         million, respectively.

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and the related notes to those statements incorporated by reference in this prospectus supplement. In addition to historical financial information, the following discussion and analysis contains forward-looking statements that involve risks, uncertainties and assumptions. Our results and the timing of selected events may differ materially from those anticipated in these forward-looking statements as a result of many factors, including those discussed under “Risk Factors” and elsewhere in this prospectus supplement.

Overview

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 June 30, 2014, we owned interests in 887,501 gross (310,392 net) mineral and lease acres in New Mexico, Texas and Kansas, of which 336,331 gross (30,926 net) acres are within the Permian Basin. We have successfully leased 9,868 net acres in Kansas located on the Central Kansas Uplift, and we also owned interests in over 1,405 net acres located on the Villarreal, Frost Bank, Resendez, Peal Ranch and La Duquesa Prospects in the onshore Gulf Coast of Texas.

On January 28, 2013, we closed the acquisition of 5,091,210 shares of common stock of Cross Border, bringing our total ownership to approximately 78% of the outstanding Cross Border common stock. Prior to the consolidation, we owned 47% of Cross Border’s outstanding common stock, and the investment was accounted for under the equity method of accounting. Subsequent to this transaction, we account for Cross Border as a consolidated subsidiary. As of June 30, 2014, we owned of record 14,327,767 shares of Cross Border common stock, representing 83% of Cross Border’s outstanding common stock.

History

Red Mountain, a Texas corporation, was formed on January 23, 2014. On January 31, 2014, we changed our state of incorporation from the State of Florida to the State of Texas by merging RMR FL with and into Red Mountain Resources, Inc., a Texas corporation. RMR FL was originally formed in January 2010 as Teaching Time, Inc. in order to design, develop, and market instructional products and services for the corporate, education, government, and healthcare e-learning industries. In March 2011, Teaching Time, Inc. determined to enter into oil and natural gas exploration, development and production and changed its name to Red Mountain Resources, Inc. to better reflect that plan. On March 22, 2011, we entered into the Plan of Reorganization and Share Exchange Agreement (the “Share Exchange Agreement”) with Black Rock Capital, LLC, an entity wholly-owned by StoneStreet Group, Inc. (“StoneStreet”). Alan W. Barksdale, our current president, chief executive officer and chairman of the board, was the president and the sole member of Black Rock Capital, LLC and 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 2,700,000 shares of common stock to StoneStreet in exchange

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for 100% of the interests in Black Rock Capital, LLC. Concurrently with the closing, we retired 22,500,000 shares of common stock for no additional consideration. In connection with the reverse merger, the management of Black Rock Capital, LLC became our management.

While we were the legal acquirer in the reverse merger, Black Rock Capital, LLC was treated as the accounting acquirer and the transaction was treated as a recapitalization. As a result, at the closing, the historical financial statements of Black Rock became those of the Company.

From inception through May 2010, Black Rock had no operations. Effective June 1, 2010, Black Rock purchased two separate oil and natural gas fields out of the bankruptcy estate of MSB Energy, Inc. located in Zapata County and Duval County in the onshore Gulf Coast of Texas. Effective May 31, 2011, Black Rock acquired our current interests in the Madera Prospect. Effective July 1, 2011, Black Rock Capital, LLC was converted to Black Rock Capital, Inc., and our 100% membership interest in Black Rock Capital, LLC became an interest in all of the outstanding common stock of Black Rock.

Planned Development Program

For fiscal year 2015, we plan to spend between $40.0 million and $50.0 million for continued drilling, completion, workovers and recompletions on our properties, including Cross Border’s non-operated acreage. The following sets forth our planned fiscal 2015 development program (dollars in millions):

Target	Gross Wells		Net Wells		Cost		Percentage of Total Program
Operated Properties:
Madera (Brushy Canyon)		6.0		2.0	$	12.6		26	%
Tom Tom (San Andres)		57.0		45.3		22.3		45
Cowden (Grayburg, San Andres)		2.0		2.0		1.0		2
Shafter Lake (San Andres)		1.0		0.4		0.2		1
East and West Ranch (Devonian)		2.0		2.0		4.0		8
Kansas (Arbuckle, Lansing Kansas City)		14.0		14.0		5.6		11
Non-Operated Properties:
Turkey Track (1st/2nd Bone Spring)		3.0		0.3		1.4		3
Perla Verde (3rd Bone Spring)		4.0		0.2		1.5		3
Red Lakes (Glorieta,Yeso)		4.0		0.9		0.8		2
Total		93.0		67.1	$	49.4		100	%

After giving effect to the completion of this offering and assuming successful and timely implementation of our current and planned development program, we expect cash on hand, borrowings under our Credit Facility and cash flow from operations will be sufficient to fund our fiscal 2015 development program. If not, we will either curtail our development program or seek other funding sources. Our planned fiscal 2015 development program is subject to change.

Critical Accounting Policies and Estimates

Our discussion and analysis of our financial condition and results of operations is based upon our consolidated financial statements, which have been prepared in accordance with GAAP. The preparation of these consolidated financial statements requires management to make estimates and judgments that affect the reported amounts of assets, liabilities, revenue and expenses, and related disclosures. Our significant accounting policies are described in “Note 3—Significant Accounting Policies” to our consolidated financial statements included our Annual Report on Form 10-K incorporated by reference in this prospectus supplement. We have identified below

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policies that are of particular importance to the portrayal of our financial position and results of operations and which require the application of significant judgment by management. These estimates are based on historical experience, information received from third parties, and on various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates under different assumptions or conditions.

We believe the following critical accounting policies affect the significant judgments and estimates used in the preparation of our consolidated financial statements.

Oil and Gas Properties

Effective June 1, 2011, we follow the successful efforts method of accounting for our oil and natural gas producing activities. The change in accounting principle has been applied retroactively to prior periods. Costs to acquire mineral interests in oil and natural gas properties and to drill and equip development wells and related asset retirement costs are capitalized. Costs to drill exploratory wells are capitalized pending determination of whether the wells have proved reserves. If we determine that the wells do not have proved reserves, the costs are charged to expense. There were no exploratory wells capitalized pending determination of whether the wells have proved reserves at May 31, 2013 or 2012. Geological and geophysical costs, including seismic studies and costs of carrying and retaining unproved properties, are charged to expense as incurred. We capitalize interest on expenditures for significant exploration and development projects that last more than six months while activities are in progress to bring the assets to their intended use. Through May 31, 2013, we had capitalized no interest costs because our exploration and development projects generally lasted less than six months. Costs incurred to maintain wells and related equipment are charged to expense as incurred.

On the sale or retirement of a complete unit of a proved property, the cost and related accumulated depreciation, depletion and amortization are eliminated from the property accounts, and the resultant gain or loss is recognized. On the retirement or sale of a partial unit of proved property, the cost is charged to accumulated depreciation, depletion and amortization, with a resulting gain or loss recognized in income.

Capitalized amounts attributable to proved oil and natural gas properties are depleted by the unit-of-production method over proved reserves using the unit conversion ratio of six Mcf of natural gas to one Boe. The ratio of six Mcf of natural gas to one Boe is based on energy equivalency, rather than price equivalency. Given current price differentials, the price for a Boe for natural gas differs significantly from the price for a barrel of oil.

It is common for operators of oil and natural gas properties to request that joint interest owners pay for large expenditures, typically for drilling new wells, in advance of the work commencing. This right to call for cash advances is typically found in the operating agreement that joint interest owners in a property adopt. We record these advance payments in prepaid and other current assets in a property account and release this account when the actual expenditure is later billed to us by the operator.

On the sale of an entire interest in an unproved property for cash or cash equivalents, gain or loss on the sale is recognized, taking into consideration the amount of any recorded impairment if the property had been assessed individually. If a partial interest in an unproved property is sold, the amount received is treated as a reduction of the cost of the interest retained.

Impairment of Long-Lived Assets

We evaluate our long-lived assets for potential impairment in their carrying values whenever events or changes in circumstances indicate such impairment may have occurred. Oil and natural gas properties are evaluated for potential impairment by field. Other properties are evaluated for impairment on a specific asset basis or in groups of similar assets, as applicable. An impairment on proved properties is recognized when the estimated undiscounted future net cash flows of an asset are less than its carrying value. If an impairment occurs,

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the carrying value of the impaired asset is reduced to its estimated fair value, which is generally estimated using a discounted cash flow approach. If the results of an assessment indicate that the properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized.

Unproved oil and natural gas properties do not have producing properties. As reserves are proved through the successful completion of exploratory wells, the cost is transferred to proved properties. The cost of the remaining unproved basis is periodically evaluated by management to assess whether the value of a property has diminished. To do this assessment, management considers estimated potential reserves and future net revenues from an independent expert, our history in exploring the area, our future drilling plans per our capital drilling program prepared by our reservoir engineers and operations management and other factors associated with the area. Impairment is taken on the unproved property cost if it is determined that the costs are not likely to be recoverable. The valuation is subjective and requires management to make estimates and assumptions which, with the passage of time, may prove to be materially different from actual results.

Business Combinations

We account for business combinations under the acquisition method of accounting in accordance with Accounting Standards Codification (“ASC”) Topic 805,Business Combinations. The acquisition method requires that assets acquired and liabilities assumed including contingencies be recorded at their fair values as of the acquisition date. We have finalized the determination of the fair values of the assets acquired and liabilities assumed for Cross Border.

Noncontrolling Interests

We account for the noncontrolling interest in Cross Border in accordance with ASC Topic 810,Consolidation(“ASC 810”). ASC 810 establishes accounting and reporting standards for ownership interests in subsidiaries held by parties other than the parent, the amount of consolidated net income attributable to the parent and to the noncontrolling interest, changes in a parent’s ownership interest and the valuation of retained noncontrolling equity investments when a subsidiary is deconsolidated. ASC 810 also establishes reporting requirements that provide sufficient disclosures that clearly identify and distinguish between the interest of the parent and the interests of the noncontrolling owner. In addition, this guidance provides for increases and decreases in our controlling financial interests in consolidated subsidiaries to be reported in equity similar to treasury stock transactions.

Recent Accounting Pronouncements

In December 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2011-11, Disclosures about Offsetting Assets and Liabilities (“ASU 2011-11”), as updated by ASU 2013-01, Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities. ASU 2011-11 requires entities to disclose both gross information and net information about instruments and transactions eligible for offset in the statement of financial position and instruments and transactions subject to an agreement similar to a master netting arrangement. The purpose of ASU 2011-11 is to facilitate comparison between entities that prepare their financial statements on a GAAP basis and entities that prepare their financial statements on the basis of International Financial Reporting Standards. ASU 2011-11 applies to derivatives, sale and repurchase agreements and reverse sale and repurchase agreements and securities borrowing and lending arrangements. ASU 2011-11 is effective for annual reporting periods beginning on or after January 1, 2013 and interim periods within those annual periods. We do not expect the adoption of this amendment to have a material impact on our consolidated financial statements.

Transition Period

On July 17, 2013, our board of directors approved a change in our fiscal year end from May 31 to June 30, effective as of June 30, 2013. In the following “Results of Operations,” we compare the results of the nine

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months ended March 31, 2014 with the previously reported nine months ended February 28, 2013. Financial information for the nine months ended March 31, 2013 has not been included for the following reasons: (i) the nine months ended February 28, 2013 provide a meaningful comparison for the nine months ended March 31, 2014; (ii) there are no significant factors, seasonal or other, that would impact the comparability of information if the results for the nine months ended March 31, 2013 were presented in lieu of results for the nine months ended February 28, 2013; and (iii) it was not practicable or cost justified to prepare this information.

Results of Operations

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, 2011, 2012 and 2013 and the nine months ended February 28, 2013 and March 31, 2014.

	Fiscal Year Ended,						Nine Months Ended,
	May 31, 2011		May 31, 2012		May 31, 2013 (1)		February 28, 2013 (1)		March 31, 2014
Revenue
Oil and natural gas sales (in thousands)	$	3,712	$	6,325	$	8,982	$	4,917	$	15,511
Net Production sold
Oil (Bbl)		—		37,004		83,143		43,754		123,624
Natural gas (Mcf)		900,332		795,659		645,609		432,810		650,334
Natural gas liquids (Bbl)		1,177		5,438		7,427		4,622		21,167
Total (Boe)		151,233		175,052		198,172		120,511		253,180
Total (Boe/d) (2)		414		480		543		441		924
Average sales prices
Oil ($/Bbl)	$	—	$	93.97	$	81.26	$	79.23	$	95.45
Natural gas ($/Mcf)		4.12		3.58		3.40		2.77		4.64
Natural gas liquids ($/Bbl)		40.28		46.45		29.62		31.19		27.82
Total average price ($/Boe)	$	24.54	$	36.13	$	45.32	$	42.43	$	60.84
Costs and expenses (per Boe)
Exploration expense	$	—	$	1.51	$	4.28	$	0.43	$	3.73
Production taxes		1.06		2.31		2.70		1.49		6.18
Lease operating expenses		1.09		5.39		8.93		8.01		8.25
Natural gas transportation and marketing expenses		1.56		0.97		0.52		0.63		0.46
Depreciation, depletion, amortization and impairment		4.74		29.42		23.11		26.49		26.51
Accretion of discount on asset retirement obligation		0.06		0.24		0.76		0.62		0.79
General and administrative expense		1.88		35.22		39.47		51.49		23.11

(1) The results for the fiscal year ended May 31, 2013 and the nine months ended February 28, 2013 only include results and estimated production from Cross Border since February 1, 2013.

(2) Boe/d is calculated based on actual calendar days during the period.

Nine Months Ended March 31, 2014 Compared to Nine Months Ended February 28, 2013

Revenues and Production

Oil and Natural Gas Production.During the nine months ended March 31, 2014, we had net production sold of 253,180 Boe, compared to net production sold of 120,511 Boe during the nine months ended February 28,

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2013. The 110% increase in net production sold was primarily attributable to the consolidation of Cross Border and to new wells coming online during the past year. For the nine months ended March 31, 2014, 48.8% of our production was oil, 42.8% was natural gas, and 8.4% was NGLs, compared to 36.3% oil, 59.9% natural gas, and 3.8% NGLs for the nine months ended February 28, 2013.

Oil and Natural Gas Sales.During the nine months ended March 31, 2014, we had oil and natural gas sales of $15.5 million, as compared to $4.9 million during the nine months ended February 28, 2013. The 215% increase in oil and natural gas sales was primarily attributable to a 110% increase in production and a 43% increase in the average realized price per Boe.

Costs and Expenses

Exploration Expense. Exploration expense was $0.9 million for the nine months ended March 31, 2014, as compared to $53,000 for the nine months ended February 28, 2013. The increase in exploration expense was attributable to seismic surveys and geological and geophysical activities performed during the nine months ended March 31, 2014.

Production Taxes. Production taxes were $1.6 million for the nine months ended March 31, 2014, as compared to $0.2 million for the nine months ended February 28, 2013. The increase in production taxes was attributable to increased oil and natural gas sales, primarily as a result of the consolidation of Cross Border and to new wells coming online during the past year.

Lease Operating Expenses. During the nine months ended March 31, 2014, we incurred lease operating expenses of $2.1 million, as compared to $1.0 million during the nine months ended February 28, 2013. The increase in lease operating expenses was attributable to the consolidation of Cross Border and increased production from the completed producing wells on our Madera property.

Natural Gas Transportation and Marketing Expenses. For the nine months ended March 31, 2014, natural gas transportation and marketing expenses were $0.1 million, as compared to $0.1 million for the nine months ended February 28, 2013.

Depreciation, Depletion, Amortization and Impairment. For the nine months ended March 31, 2014, depreciation, depletion, amortization and impairment was $6.7 million, as compared to $3.2 million for the nine months ended February 28, 2013. The increase in depreciation, depletion, amortization and impairment was attributable to the consolidation of Cross Border, the depletion of the additional producing wells on our Madera property and the upward revision of asset retirement obligations in December 2012, partially offset by no impairment for the nine months ended March 31, 2014.

General and Administrative Expense. General and administrative expense was $5.9 million for the nine months ended March 31, 2014, as compared to $6.2 million for the nine months ended February 28, 2013. The decrease in general and administrative expense was due primarily to a decrease in professional fees, partially offset by higher personnel costs related to increased headcount.

Other Expense. Other expense was $3.1 million for the nine months ended March 31, 2014, as compared to other expense of $4.2 million for the nine months ended February 28, 2013. The decrease in other expense was primarily attributable to a $1.3 million unrealized loss on investment in Cross Border warrants, a $0.9 million impairment on a note receivable, a $0.5 million unrealized loss on debentures, partially offset by a $0.7 million gain on the consolidation of Cross Border during the nine months ended February 28, 2013, none of which were also recorded during the nine months ended March 31, 2014. In addition, we incurred $0.4 million of increased interest expense during the nine months ended March 31, 2014.

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Fiscal Year Ended May 31, 2013 Compared to Fiscal Year Ended May 31, 2012

Revenues and Production

Oil and Natural Gas Production. During the fiscal year ended May 31, 2013, we had net production sold of 198,172 Boe, compared to net production sold of 175,052 Boe during the fiscal year ended May 31, 2012. The increase in net production sold was primarily attributable to the consolidation of Cross Border, partially offset by production declines in the onshore Gulf Coast and our Madera 24 Federal 2H well being shut in for approximately 100 non-consecutive days during fiscal 2013. For the fiscal year ended May 31, 2013, 42.0% of our net production sold was oil, 54.3% was natural gas and 3.7% was NGLs, compared to 21.1% oil, 75.8% natural gas and 3.1% NGLs for the fiscal year ended May 31, 2012.

Oil and Natural Gas Sales. During the fiscal year ended May 31, 2013, we had oil and natural gas sales of $9.0 million, as compared to $6.3 million during the fiscal year ended May 31, 2012. The increase in oil and natural gas sales was primarily attributable to us producing approximately 46,000 additional barrels of oil in fiscal 2013, partially offset by a 14% decrease in the price received per barrel of oil.

Costs and Expenses

Exploration Expense. Exploration expense was $0.8 million for the fiscal year ended May 31, 2013, as compared to $0.3 million for the fiscal year ended May 31, 2012. Exploration expense increased due to a $0.4 million impairment of an unproved property in the fiscal year ended May 31, 2013.

Production Taxes. Production taxes were $0.5 million for the fiscal year ended May 31, 2013, as compared to $0.4 million for the fiscal year ended May 31, 2012.

Lease Operating Expenses. During the fiscal year ended May 31, 2013, we incurred lease operating expenses of $1.8 million, as compared to $0.9 million during the fiscal year ended May 31, 2012. The increase in lease operating expenses was partially attributable to the consolidation of Cross Border, which incurred $0.4 million of lease operating expense from the consolidation date through May 31, 2013. In addition, we incurred higher operating costs on our existing wells, such as salt water disposal costs.

Natural Gas Transportation and Marketing Expenses. For the fiscal year ended May 31, 2013, natural gas transportation and marketing expenses were $0.1 million, as compared to $0.2 million for the fiscal year ended May 31, 2012.

Depreciation, Depletion, Amortization and Impairment. For the fiscal year ended May 31, 2013, depreciation, depletion, amortization and impairment was $4.5 million, as compared to $5.1 million for the fiscal year ended May 31, 2012. The decrease in depreciation, depletion, amortization and impairment was primarily attributable to a $1.0 million impairment of our Pawnee Prospect in the fiscal year ended May 31, 2012 that did not recur in the fiscal year ended May 31, 2013.

General and Administrative Expense. General and administrative expense was $7.8 million for the fiscal year ended May 31, 2013, as compared to $6.2 million for the fiscal year ended May 31, 2012. The increase in general and administrative expense for the fiscal year ended May 31, 2013 was partially attributable to the consolidation of Cross Border, which incurred $0.3 million in general and administrative expenditures from the consolidation date through May 31, 2013. In addition, we incurred an additional $0.6 million in personnel related expenditures due to increased headcount.

Other Expense. Other expense was $4.8 million for the fiscal year ended May 31, 2013, as compared to $5.6 million for the fiscal year ended May 31, 2012. The decrease in other expense was primarily attributable to a $0.5 million gain on the change in the fair value of derivatives, an unrealized loss of $1.3 million on our investment in

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Cross Border warrants, a $1.0 million increase in interest expense, a $0.7 million gain on the consolidation of Cross Border and a $0.5 million impairment of debentures for the fiscal year ended May 31, 2013. Also contributing to the decline in other expenses was a $1.9 million decline in impairment on notes receivable.

Fiscal Year Ended May 31, 2012 Compared to Fiscal Year Ended May 31, 2011

Revenues and Production

Oil and Natural Gas Production. During the fiscal year ended May 31, 2012, we had net production sold of 175,052 Boe, compared to net production sold of 151,233 Boe during the fiscal year ended May 31, 2011. The increase in net production sold was primarily attributable to completion of the Madera 24 Federal 2H well on the Madera Prospect, partially offset by lower natural gas production. For the fiscal year ended May 31, 2012, 21.1% of our net production sold was oil, 75.8% was natural gas and 3.1% was NGLs, compared to 99.2% natural gas and 0.8% NGLs for the fiscal year ended May 31, 2011. For fiscal 2011, we had no oil production.

Oil and Natural Gas Sales. During the fiscal year ended May 31, 2012, we had oil and natural gas sales of $6.3 million, as compared to $3.7 million during the fiscal year ended May 31, 2011. The increase in oil and natural gas sales was primarily attributable to 46.1 MBoe of net production sold from the Madera Prospect partially offset by lower natural gas production and lower average prices for natural gas sales.

Costs and Expenses

Exploration Expense. Exploration expense was $0.3 million for the fiscal year ended May 31, 2012, as compared to no exploration expense for the fiscal year ended May 31, 2011. Exploration expense increased due to $0.1 million of expired leases and $0.2 million of other well data and evaluation costs.

Production Taxes. Production taxes were $0.4 million for the fiscal year ended May 31, 2012, as compared to $0.2 million for the fiscal year ended May 31, 2011. The increase in production taxes was attributable to increased production from the Madera and Pawnee Prospects and the Cowden Lease.

Lease Operating Expenses. During the fiscal year ended May 31, 2012, we incurred lease operating expenses of $0.9 million, as compared to $0.2 million during the fiscal year ended May 31, 2011. The increase in lease operating expenses was attributable to our acquisition of the Madera and Pawnee Prospects and the Cowden Lease.

Natural Gas Transportation and Marketing Expenses. For the fiscal year ended May 31, 2012, natural gas transportation and marketing expenses were $0.2 million, as compared to $0.2 million for the fiscal year ended May 31, 2011.

Depreciation, Depletion, Amortization and Impairment. For the fiscal year ended May 31, 2012, depreciation, depletion, amortization and impairment was $5.1 million, as compared to $0.7 million for the fiscal year ended May 31, 2011. The increase in depreciation, depletion, amortization and impairment was attributable to increased production, oil and natural gas property additions, and $1.0 million of impairment on the Pawnee Prospect primarily due to a decline in the reserves and production associated with our Pawnee wells.

General and Administrative Expense. General and administrative expense was $6.2 million for the fiscal year ended May 31, 2012, as compared to $0.3 million for the fiscal year ended May 31, 2011. The increase in general and administrative expense for the fiscal year ended May 31, 2012 was due primarily to $2.9 million of acquisition-related due diligence and transaction costs as well as expenditures related to the reverse merger and creation of company infrastructure. We incurred $3.3 million of personnel, office and public company expenses as compared to $0.3 million for the year ended May 31, 2011.

Other Expense. Other expense was $5.6 million for the fiscal year ended May 31, 2012, as compared to other income of $0.7 million for the fiscal year ended May 31, 2011. The increase in other expense was primarily

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attributable to increased interest expense due to $6.7 million aggregate principal amount of promissory notes and $2.75 million aggregate principal amount of convertible promissory notes issued during fiscal 2012, a $2.7 million loss on note receivable due to the uncertainty of collection of the note receivable and a $0.8 million change in fair value of warrant liability due to an increase in the price of our common stock at the time of exercise of certain warrants.

Liquidity and Capital Resources

General

Our primary sources of liquidity for the nine months ended March 31, 2014 were cash flow from operations, borrowings under our Credit Facility and proceeds from the sale of equity securities. Our primary sources of liquidity for fiscal 2013 were borrowings under our Credit Facility and a loan agreement and proceeds from the sale of common stock. Our ability to fund planned capital expenditures and to make acquisitions depends upon our future operating performance, availability of borrowings under our Credit Facility and availability of equity and debt financing, which is affected by prevailing economic conditions in our industry and financial, business and other factors, some of which are beyond our control. Our cash flow from operations is mainly influenced by the prices we receive for our oil and natural gas production and the quantity of oil and natural gas we produce. Prices for oil and natural gas are affected by national and international economic and political conditions, national and global supply and demand for hydrocarbons, seasonal weather influences and other factors beyond our control.

Capital Expenditures

Most of our capital expenditures are for the exploration, development, production and acquisition of oil and natural gas reserves. We anticipate cash capital expenditures of between $40.0 million and $50.0 million for fiscal year 2015. See “—Planned Development Program” for more information about our planned capital expenditures. After giving effect to the completion of this offering and assuming successful and timely implementation of our current and planned development program, we expect cash on hand, borrowings under our Credit Facility and cash flow from operations will be sufficient to fund our fiscal 2015 development program. If not, we will either curtail our development program or seek other funding sources. Our planned fiscal 2015 development program is subject to change.

Liquidity

At March 31, 2014, we had $1.2 million in cash and cash equivalents and $32.6 million of total indebtedness, consisting of $23.8 million under the Credit Facility and $8.8 million of Series A Preferred Stock, net of a discount of $3.1 million. At March 31, 2014, we had a working capital deficit of $5.4 million compared to a working capital deficit of $24.3 million at February 28, 2013.

Upon completion of this offering, we expect to have sufficient cash on hand, cash flow from operations and available borrowings under our Credit Facility to fund our operations for the next 12 months.

Financings

On November 22, 2013, we paid in full the $1.5 million convertible promissory note, plus accrued and unpaid interest, to Personalversorge der Autogrill Schweiz AG, and the note was terminated.

On April 22, 2014, we borrowed $3.0 million under the Credit Facility. As of July 15, 2014, we had $26.8 million outstanding under the Credit Facility and had availability of $3.2 million.

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Series A Preferred Stock Exchange

We agreed to exchange 222,224 outstanding shares of our Series A Preferred Stock for the issuance of 1,388,898 shares of common stock effective as of April 1, 2014. After the exchange, we had 254,463 shares of Series A Preferred Stock outstanding with an aggregate redemption amount of $6.4 million.

Cash Flows

Net cash provided by operating activities was $4.5 million for the nine months ended March 31, 2014, compared to net cash used in operating activities of $5.0 million for the nine months ended February 28, 2013. The increase in net cash provided by operating activities was primarily due to a $5.0 million lower net loss, $3.5 million of higher depreciation, depletion, amortization, and impairment, and changes in working capital. Net cash used in operating activities was $10.2 million for the fiscal year ended May 31, 2013, compared to net cash used in operating activities of $1.2 million for the fiscal year ended May 31, 2012. The increase in net cash used in operating activities was primarily due to changes in working capital and changes resulting from the consolidation of Cross Border.

Net cash used in investing activities increased to $16.4 million for the nine months ended March 31, 2014 from $0.2 million for the nine months ended February 28, 2013 due to increased drilling activity during the nine months ended March 31, 2014. Net cash used in investing activities was $0.6 million for the fiscal year ended May 31, 2013 compared to $18.2 million for the fiscal year ended May 31, 2012 due to a reduction in investment in oil and gas properties.

Net cash provided by financing activities was $12.7 million for the nine months ended March 31, 2014, as compared to $7.8 million for the nine months ended February 28, 2013. Net cash provided by financing activities for the nine months ended March 31, 2014 was primarily comprised of proceeds from the sale of common stock and units, consisting of Series A Preferred Stock and warrants, partially offset by $7.0 million of payments on the Credit Facility and convertible notes payable and $9.0 million of borrowings under the Credit Facility. Net cash provided by financing activities was $11.8 million for the fiscal year ended May 31, 2013, as compared to $19.5 million for the fiscal year ended May 31, 2012. Net cash provided by financing activities for the fiscal year ended May 31, 2013 was primarily comprised of borrowings of $12.5 million under our Credit Facility and $10.7 million from notes payable and proceeds from our private placement of common stock, partially offset by $11.5 million of repayments on promissory notes and a Cross Border credit facility.

Indebtedness

Credit Facility. The Senior First Lien Secured Credit Agreement (as amended, the “Credit Agreement”) with Cross Border, Black Rock and RMR Operating (Red Mountain, Cross Border, Black Rock and RMR Operating, jointly and severally, the “Borrowers”) and Independent Bank, as Lender, provides for an up to $100.0 million Credit Facility with a maturity date of February 5, 2016. The borrowing base under the Credit Facility is determined at the discretion of the Lender based on, among other things, the Lender’s estimated value of the proved reserves attributable to the Borrowers’ oil and natural gas properties that have been mortgaged to the Lender, and is subject to regular redeterminations on September 30 and March 31 of each year, and interim redeterminations described in the Credit Agreement and potentially monthly commitment reductions, in each case which may reduce the amount of the borrowing base. As of March 31, 2014, the borrowing base was $30.0 million.

A portion of the Credit Facility, in an aggregate amount not to exceed $2.0 million, may be used to issue letters of credit for the account of Borrowers. The Borrowers may be required to prepay the Credit Facility in the event of a borrowing base deficiency as a result of over-advances, sales of oil and gas properties or terminations of hedging transactions.

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Amounts outstanding under the Credit Facility bear interest at a rate per annum equal to the greater of (x) the U.S. prime rate as published in The Wall Street Journal’s “Money Rates” table in effect from time to time and (y) 4.0%. Interest is payable monthly in arrears on the last day of each calendar month. Borrowings under the Credit Facility are secured by first priority liens on substantially all the property of each of the Borrowers and are unconditionally guaranteed by Doral West Corp. and Pure Energy Operating, Inc., each a subsidiary of Cross Border.

Under the Credit Agreement, the Borrowers are required to pay fees consisting of (i) an unused facility fee equal to 0.5% multiplied by the average daily unused commitment amount, payable quarterly in arrears until the commitment is terminated; (ii) a fronting fee payable on the date of issuance of each letter of credit and annually thereafter or on the date of any increase or extension thereof, equal to the greater of (a) 2.0% per annum multiplied by the face amount of such letter of credit or (b) $1,000; and (iii) an origination fee (x) of $200,000, and (y) payable on any date the commitment is increased, an additional facility fee equal to 1.0% multiplied by any increase of the commitment above the highest previously determined or redetermined commitment.

The Credit Agreement contains negative covenants that may limit the Borrowers’ ability to, among other things, incur liens, incur additional indebtedness, enter into mergers, sell assets, make investments and pay dividends. The Credit Agreement permits the payment of cash dividends on our Series A Preferred Stock so long as we are not otherwise in default under the Credit Agreement and payment of such cash dividends would not cause us to be in default under the Credit Agreement.

The Credit Agreement also contains financial covenants, measured as of the last day of each fiscal quarter of Red Mountain, requiring the Borrowers to maintain a ratio of (i) the Borrowers’ and their consolidated subsidiaries’ consolidated current assets (inclusive of the unfunded commitment amount under the Credit Agreement) to consolidated current liabilities (exclusive of the current portion of long-term debt under the Credit Agreement) of at least 1.00 to 1.00; (ii) the Borrowers’ and their subsidiaries’ consolidated “Funded Debt” to consolidated EBITDAX (for the four fiscal quarter period then ended) of less than 3.50 to 1.00; and (iii) the Borrowers’ and their subsidiaries’ consolidated EBITDAX less paid and accrued dividends on the Series A Preferred Stock to interest expenses (each for the four fiscal quarter period then ended) of at least 3.00 to 1.00. Funded Debt is defined in the Credit Agreement as the sum of all debt for borrowed money, whether as a direct or reimbursement obligor, but excludes shares of Series A Preferred Stock. EBITDAX is defined in the Credit Agreement as (a) consolidated net income plus (b) (i) interest expense, (ii) income taxes, (iii) depreciation, (iv) depletion and amortization expenses, (v) dry hole and exploration expenses, (vi) non-cash losses or charges on any hedge agreements resulting from derivative accounting, (vii) extraordinary or non-recurring losses, (viii) expenses that could be capitalized under GAAP but by election of Borrowers are being expensed for such period under GAAP, (ix) costs associated with intangible drilling costs, (x) other non-cash charges, (xi) one-time expenses associated with transactions associated with (b)(i) through (iv), minus (c)(i) non-cash income on any hedge agreements resulting from FASB Statement 133, (ii) extraordinary or non-recurring income, and (iii) other non-cash income.

Amounts outstanding under the Credit Facility may be accelerated and become immediately due and payable upon specified events of default of Borrowers, including, among other things, a default in the payment of principal, interest or other amounts due under the Credit Facility, certain loan documents or hydrocarbon hedge agreements, a material inaccuracy of a representation or warranty, a default with regard to certain loan documents which remains unremedied for a period of 30 days following notice, a default in the payment of other indebtedness of the Borrowers of $200,000 or more, bankruptcy or insolvency, certain changes in control, failure of the Lender’s security interest in any portion of the collateral with a value greater than $500,000, cessation of any security document to be in full force and effect, or Alan Barksdale ceasing to be Red Mountain’s Chief Executive Officer or Chairman of Cross Border and not being replaced with an officer acceptable to the Lender within 30 days.

Pursuant to the Credit Agreement, at least one of the Borrowers is required to have acceptable hedge agreements in place at all times effectively hedging at least 50% of the oil volumes of the Borrowers. Pursuant to

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the terms of the Credit Agreement, Red Mountain has hedge agreements with various counterparties hedging a portion of the future oil production of the Borrowers.

As of March 31, 2014, the Borrowers had collectively borrowed $23.8 million and had availability of $6.2 million under the Credit Facility. Subsequent to March 31, 2014, the Borrowers borrowed an additional $3.0 million on the Credit Facility, bringing the balance to $26.8 million and leaving $3.2 million of availability as of July 15, 2014.

Series A Preferred Stock. As of March 31, 2014, we had 476,687 shares of Series A Preferred Stock outstanding. The Series A Preferred Stock is mandatorily redeemable and is not convertible into shares of our common stock. We classify the Series A Preferred Stock as a long-term liability, and we record dividends paid or accrued as interest expense in our condensed consolidated statements of operations.

In August 2013, we closed offerings of 476,687 Units (the “Units”), including 100,002 Units sold in cancellation of $2.3 million in debt, raising net proceeds of $7.1 million. Each Unit consisted of one share of Series A Preferred Stock and one warrant to purchase up to 2.5 shares of common stock. The warrants are exercisable until the earlier of August 2016 or (ii) the first trading day that is at least 30 days after the date that we have provided notice to the holders of the warrants by filing a Current Report on Form 8-K stating that the common stock has (A) achieved a 20 trading day volume weighted average price of $15.00 per share or more and (B) traded, in the aggregate, 300,000 shares or more over the same 20 consecutive trading days for which the 20 trading day volume weighted average price was calculated; provided, that clause (ii) shall only be applicable so long as a warrant is exercisable for shares of common stock. The warrants have an exercise price of $10.00 per share. The warrants issued with the Series A Preferred Stock were valued at $2.4 million. The value of the warrants is treated as a discount to the Series A Preferred Stock and will be accreted over the life of the mandatorily redeemable preferred stock. Management determined the fair value using a probability weighted Black-Scholes option model with a volatility based on the historical closing price of common stock of industry peers and the closing price of our common stock on the OTCBB on the date of issuance. The volatility and remaining term was approximately 55% and three years, respectively.

The Series A Preferred Stock is mandatorily redeemable on July 15, 2018 at $25.00 per share, plus accrued and unpaid dividends to the redemption date, for a total redeemable value of $11.9 million. The difference between the $11.9 million redeemable value and the $10.8 million of gross proceeds and canceled debt is treated as a discount and will be accreted over the life of the Series A Preferred Stock.

For the nine months ended March 31, 2014, we recognized total interest expense of $1.5 million related to the Series A Preferred Stock, which includes accretion of discount and issuance cost of $0.7 million for the nine months ended March 31, 2014.

We agreed to exchange 222,224 outstanding shares of our Series A Preferred Stock for the issuance of 1,388,898 shares of common stock effective as of April 1, 2014. After the exchange, we had 254,463 shares of Series A Preferred Stock outstanding with an aggregate redemption amount of $6.4 million.

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Contractual Obligations

The following table presents our contractual obligations at March 31, 2014, on an as adjusted basis to give effect to the (i) exchange of 222,224 outstanding shares of Series A Preferred Stock for the issuance of 1,388,898 shares of common stock effective as of April 1, 2014, (ii) additional borrowings of $3.0 million under the Credit Facility subsequent to March 31, 2014, and (iii) sale of 400,000 shares of Series A Preferred Stock in this offering, not including temporary repayment of amounts outstanding under the Credit Facility as set forth under “Use of Proceeds” (in thousands):

	Payments Due by Period
	Total		Less than 1 Year		1 – 3 Years		3 – 5 Years		More than 5 Years
Credit Facility	$	25,670	$	952	$	24,718	$	—	$	—
Series A Preferred Stock		23,383		1,636		3,272		18,475		—
Environmental remediation liability		2,077		286		1,791		—		—
Asset retirement obligations		5,275		686		1,617		101		2,871
Lease obligations		495		70		425		—		—
Total	$	56,900	$	3,630	$	31,823	$	18,576	$	2,871

Off-Balance Sheet Arrangements

As of March 31, 2014, we did not have any off-balance sheet arrangements as defined byRegulation S-K.

Quantitative and Qualitative Disclosures About Market Risk

Commodity Price Risk

Our major market risk exposure is the price we receive for our oil and natural gas production. Realized pricing is primarily driven by the prevailing price for oil and spot market prices for natural gas. Prices for oil and natural gas production are volatile and sometimes experience large fluctuations as a result of relatively small changes in supplies, weather conditions, economic conditions and government actions.

Pursuant to the Credit Agreement, at least one of the Borrowers is required to have acceptable hedge agreements in place at all times effectively hedging at least 50% of the oil volumes of the Borrowers. We have entered into derivative contracts, including costless collars, swaps, and puts, which hedge the price of oil for a portion of our expected production through January 2015.

The derivative contracts economically hedge against the variability in cash flows associated with the forecasted sale of our future oil production. While the use of the hedging arrangements will limit the downside risk of adverse price movements, it may also limit future gains from favorable movements.

The costless collars provide us with a lower limit “floor” price and an upper limit “ceiling” price on the hedged volumes. The floor price represents the lowest price we will receive for the hedged volumes while the ceiling price represents the highest price we will receive for the hedged volumes. The costless collars are settled monthly.

The swaps provide us with a fixed settlement price for our hedged volumes. The swaps are settled monthly.

The puts provide a fixed floor price on a notional amount of sales volumes while allowing full price appreciation if the relevant index price closes above the floor price.

We have elected not to designate our derivative financial instruments as hedges for accounting purposes, and accordingly, we record such contracts at fair value and recognize changes in such fair value in current

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earnings as they occur. Our commodity derivative contracts are carried at their fair value in earnings as they occur. We recognize unrealized and realized gains and losses related to these contracts on a mark-to-market basis in our condensed consolidated statements of operations under the captions “Unrealized gain (loss) on commodity derivatives” and “Realized gain (loss) on commodity derivatives,” respectively. Each derivative contract is evaluated separately to determine its own fair value. During the nine months ended March 31, 2014, we recorded an unrealized (loss) on commodity derivative contracts of $(272,000), and a realized (loss) on commodity derivative contracts of $(74,000).

The following table summarizes our outstanding derivatives contracts with respect to future oil production as of July 31, 2014:

Commodity and Time Period	Contract Type	Volume Transacted	Contract Price
Crude Oil
August 1, 2014—August 31, 2014 Collar—Minimum	Option	1,437 Bbls/month	$	80.00/Bbl
August 1, 2014—August 31, 2014 Collar—Maximum	Option	1,437 Bbls/month	$	100.50/Bbl
August 1, 2014—November 30, 2014	Swap	2,000 Bbls/month	$	93.50/Bbl
August 1, 2014—January 31, 2015	Put	4,061-8,330 Bbls/month	$	95.00/Bbl
August 1, 2014—October 31, 2014	Put	1,979-2,574 Bbls/month	$	100.00/Bbl

The fair values of our commodity derivatives are largely determined by estimates of the forward curves of the relevant price indices. As of July 31, 2014, a 10% increase or decrease in underlying commodity prices would neither reduce nor increase the fair value of these derivatives by a material amount.

Interest Rate Risk

The Credit Facility exposes us to interest risk associated with interest rate fluctuations on outstanding borrowings. At June 30, 2014, we had $26.8 million in outstanding borrowings under the Credit Facility. We incur interest on borrowings under the Credit Facility at a rate per annum equal to the greater of (x) the U.S. prime rate as published in The Wall Street Journal’s “Money Rates” table in effect from time to time and (y) 4.0% (which interest rate was 4.0% at June 30, 2014). A hypothetical 10% change in the interest rates we pay on our borrowings under the Credit Facility as of March 31, 2014 would result in an increase or decrease in our interest costs of approximately $107,000 per year.

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BUSINESS

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 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 June 30, 2014, we owned interests in 887,501 gross (310,392 net) mineral and lease acres in New Mexico, Texas and Kansas, of which 336,331 gross (30,926 net) acres are within the Permian Basin. We have successfully leased 9,868 net acres in Kansas located on the Central Kansas Uplift, and we also owned interests in over 1,405 net acres located on the Villarreal, Frost Bank, Resendez, Peal Ranch and La Duquesa Prospects in the onshore Gulf Coast of Texas.

On January 28, 2013, we closed the acquisition of 5,091,210 shares of common stock of Cross Border, bringing our total ownership to approximately 78% of the outstanding Cross Border common stock. Prior to the consolidation, we owned 47% of Cross Border’s outstanding common stock, and the investment was accounted for under the equity method of accounting. Subsequent to this transaction, we account for Cross Border as a consolidated subsidiary. As of June 30, 2014, we owned of record 14,327,767 shares of Cross Border common stock, representing 83% of Cross Border’s outstanding common stock.

History

Red Mountain, a Texas corporation, was formed on January 23, 2014. On January 31, 2014, we changed our state of incorporation from the State of Florida to the State of Texas by merging RMR FL with and into Red Mountain Resources, Inc., a Texas corporation. RMR FL was originally formed in January 2010 as Teaching Time, Inc. in order to design, develop, and market instructional products and services for the corporate, education, government, and healthcare e-learning industries. In March 2011, Teaching Time, Inc. determined to enter into oil and natural gas exploration, development and production and changed its name to Red Mountain Resources, Inc. to better reflect that plan. On March 22, 2011, we entered into the Share Exchange Agreement with Black Rock Capital, LLC, an entity wholly-owned by StoneStreet. Alan W. Barksdale, our current president, chief executive officer and chairman of the board, was the president and the sole member of Black Rock Capital, LLC and sole owner and the president of StoneStreet. On June 22, 2011, we completed a reverse merger pursuant to the Share Exchange Agreement in which we issued 2,700,000 shares of common stock to StoneStreet in exchange for 100% of the interests in Black Rock Capital, LLC. Concurrently with the closing, we retired 22,500,000 shares of common stock for no additional consideration. In connection with the reverse merger, the management of Black Rock Capital, LLC became our management.

While we were the legal acquirer in the reverse merger, Black Rock Capital, LLC was treated as the accounting acquirer and the transaction was treated as a recapitalization. As a result, at the closing, the historical financial statements of Black Rock became those of the Company. The description of our business presented below is that of our current business and all discussions of periods prior to the reverse merger describe the business of Black Rock.

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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

Reverse Stock Split and Authorized Share Reduction. On January 31, 2014, Red Mountain Resources, Inc., a Florida corporation (“RMR FL”), effected a reverse stock split of RMR FL’s common stock, par value $0.00001 per share (“RMR FL Common Stock”), at an exchange ratio of 1-for-10 (the “Reverse Stock Split”), together with a proportional reduction in the number of authorized shares of RMR FL Common Stock from 500.0 million shares to 50.0 million shares. The par value of RMR FL Common Stock did not change as a result of the Reverse Stock Split. As of January 31, 2014, every ten shares of RMR FL Common Stock were combined into one share of RMR FL Common Stock, reducing the number of outstanding shares of RMR FL Common Stock from approximately 134.0 million to approximately 13.4 million. In addition, a proportionate adjustment was made to the per share exercise price and the number of shares issuable upon the exercise of all outstanding warrants to purchase shares of RMR FL Common Stock. All share and per share amounts and calculations in this prospectus supplement have been retroactively adjusted to reflect the effects of the Reverse Stock Split.

Change of State of Incorporation. On January 31, 2014, RMR FL changed its state of incorporation from the State of Florida to the State of Texas by merging (the “Reincorporation”) with and into its wholly-owned subsidiary, Red Mountain, with Red Mountain continuing as the surviving corporation. As a result, as of January 31, 2014:

(i) RMR FL ceased to exist;

(ii) shareholders of RMR FL automatically became shareholders of Red Mountain, without any action by such shareholders, and began to be governed by (a) the Texas Business Organizations Code, (b) Red Mountain’s Certificate of Formation, and (c) Red Mountain’s Bylaws;

(iii) the name, business, management, fiscal year, accounting, location of the principal executive offices, assets and liabilities of RMR FL became the name, business, management, fiscal year, accounting, location of the principal executive offices, assets and liabilities of Red Mountain; and

(iv) the directors and officers of RMR FL prior to the Reincorporation continued as the directors and officers of Red Mountain after the Reincorporation for an identical term of office.

On January 31, 2014, our common stock commenced trading on a split-adjusted basis. As a result of the Reincorporation, Red Mountain became the successor corporation to RMR FL under the Exchange Act and succeeded to RMR FL’s reporting obligations thereunder. Pursuant to Rule 12g-3 promulgated under the Exchange Act, the common stock, preferred stock and warrants of Red Mountain were deemed to be registered under Section 12(g) of the Exchange Act.

Series A Preferred Stock Exchange.We agreed to exchange 222,224 outstanding shares of our Series A Preferred Stock for the issuance of 1,388,898 shares of common stock effective as of April 1, 2014. After the exchange, we had 254,463 shares of Series A Preferred Stock outstanding with an aggregate redemption amount of $6.4 million.

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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 June 30, 2014, we had interests in 336,331 gross (30,926 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 June 30, 2014, these properties had 220 gross (94.2 net) producing wells and, during the three months ended June 30, 2014, had daily average net production of 1,057 Boe/d, 64% of which was oil. As of January 1, 2014, our Permian Basin properties had approximately 3,214 MBoe of proved reserves, of which 73% was oil. Of our proved reserves in the Permian Basin, 31% are from the Madera Prospect, 21% are from the Lusk Prospect, 20% are from the Tom Tom Prospect and 14% are from the Turkey Track Prospect. During the nine months ended March 31, 2014, we derived approximately 90% of our revenue from the Permian Basin.

Onshore Gulf Coast. As of June 30, 2014, 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 June 30, 2014, these properties had 37 gross (12.8 net) producing wells and, during the three months ended June 30, 2014, had daily average net production of 168 Boe/d, substantially all of which was natural gas. As of January 1, 2014, our onshore Gulf Coast properties had approximately 359 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 17% are from the Peal Ranch Prospect. During the nine months ended March 31, 2014, we derived approximately 9% of our revenue from the onshore Gulf Coast.

New Mexico Non-Permian Minerals. As of June 30, 2014, we owned 536,526 gross (268,193 net) mineral acres in DeBaca, Hidalgo, Grant, Sierra, and Socorro Counties, New Mexico. This mineral ownership carries no drilling commitments or leasehold obligations. As of January 1, 2014, this acreage had no proved reserves or production.

Kansas. As of June 30, 2014, we owned oil and natural gas interests in 9,868 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 January 1, 2014, the Kansas acreage had no proved reserves or production.

For more detailed information on our properties, see “Properties.”

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Planned Development Program

During fiscal year 2015, we plan to spend between $40.0 million and $50.0 million for drilling, completion, workovers, and recompletion on our properties, including Cross Border’s non-operated acreage. Our planned fiscal 2015 development program is subject to change. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Planned Development Program.”

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

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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 a fee and out-of-pocket expenses purportedly owed by Cross Border to KeyBanc as a result of the consummation of a purported Transaction that KeyBanc asserts had been consummated within the required time period. Cross Border disputes that any Transaction was consummated and that KeyBanc is entitled to any fees or out-of-pocket expenses. Cross Border filed a complaint seeking (i) a declaration that it is not liable to KeyBanc for any amounts in connection with the Engagement Letter, (ii) attorneys’ fees, and (iii) costs of suit. KeyBanc filed a counterclaim seeking (i) at least $750,000 in compensatory damages, (ii) interest, (iii) expenses and court costs, and (iv) reasonable and necessary attorneys’ fees. The matter was originally filed in the 44th Judicial District Court for the State of Texas, Dallas County but was subsequently removed to the United States District Court for the Northern District of Texas, Dallas Division. Cross Border and KeyBanc filed motions for summary judgment. On August 4, 2014, the court granted in part and denied in part KeyBanc’s motion for summary judgment, narrowing the unresolved issue for trial to whether or not Red Mountain’s acquisitions of Cross Border common stock were a “series of related transactions” within the meaning of the Engagement Letter. The matter could go to trial as early as September 2014. Cross Border intends to vigorously defend the action.

Employees

As of June 30, 2014, we had 33 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.

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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 2014, and we are not aware of any environmental issues or claims that will require material capital expenditures during fiscal 2015, other than

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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 EPA and, in some instances, third parties to take actions in response to threats to public health or the environment and to seek to recover from the PRPs the costs of such action. Additionally, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. Many states have adopted comparable or more stringent state statutes.

Although CERCLA generally exempts “petroleum” from the definition of hazardous substance, in the course of our operations, we will generate, transport and dispose or arrange for the disposal of wastes that may fall within CERCLA’s definition of hazardous substances. Comparable state statutes may not contain a similar exemption for petroleum. We may also be the owner or operator of sites on which hazardous substances have been released.

Solid and Hazardous Waste Handling. The Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes and regulations promulgated thereunder regulate the generation, transportation, treatment, storage, disposal and cleanup of solid and hazardous waste. With federal approval, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent regulations. Although oil and natural gas waste generally is exempt from regulations as hazardous waste under RCRA, such wastes may constitute “solid wastes” that are subject to the less stringent requirements of non-hazardous waste provisions. Additionally, we will generate waste as a routine part of our operations that may be subject to RCRA and not all state and local laws contain a comparable exemption. Further, there is no guarantee that the EPA or individual states or local governments will not adopt more stringent requirements for the handling of non-hazardous waste or categorize some non-hazardous waste as hazardous in the future. Indeed, legislation has been proposed from time to time in Congress to re-categorize certain oil and natural gas exploration, development and production wastes as “hazardous wastes.” Any such change could result in an increase in our costs to manage and dispose of waste, which could have a material adverse effect on our financial condition and results of operations.

It is also possible that our oil and natural gas operations may require us to manage naturally occurring radioactive materials, or NORM. NORM is present in varying concentrations in sub-surface formations, including hydrocarbon reservoirs, and may become concentrated in scale, film and sludge in equipment that comes in contract with crude oil and natural gas production and processing streams. Some states have enacted regulations governing the handling, treatment, storage and disposal of NORM.

Administrative, civil and criminal penalties can be imposed for failure to comply with waste handling requirements. We believe that we are in substantial compliance with applicable requirements related to waste

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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 SDWA, the Oil Pollution Act (the “OPA”) and analogous state laws and regulations promulgated thereunder impose restrictions and strict controls regarding the unauthorized discharge of pollutants, including produced waters and other gas and oil wastes, into navigable waters of the United States, as well as state waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of certain permits issued by the EPA or an analogous state agency. Spill prevention, control and countermeasure requirements under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. In addition, the CWA and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. The CWA also prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by a permit issued by the United States Army Corps of Engineers. In addition, in October 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. Hydraulic fracturing stimulation requires the use of a significant volume of water with some resulting flowback, as well as produced water. The EPA asserts that this water may contain radioactive materials and other pollutants and, therefore, may deteriorate drinking water quality if not properly treated before discharge. While the EPA has revised the scope of its rulemaking to exclude discharges associated with coalbed methane extraction, it is continuing to develop pre-treatment standards for wastewater discharges produced by natural gas extraction from shale formations, and a proposed rule is scheduled for publication 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 CWA and analogous state laws and regulations. In the event of an unauthorized discharge of wastes, we may be liable for penalties and costs of remediation. The OPA is the primary federal law for oil spill liability. The OPA imposes requirements on “responsible parties” related to the prevention of oil spills and liability for damages resulting from oil spills into or upon navigable waters, adjoining shorelines or in the exclusive economic zone of the United States. A “responsible party” under the OPA may include the owner or operator of an onshore facility. The OPA subjects responsible parties to strict, joint and several financial liability for removal costs and other damages, including natural resource damages, caused by an oil spill that is covered by the statute. It also imposes other requirements on responsible parties, such as the preparation of an oil spill contingency plan and maintaining certain significant levels of financial assurance to cover potential environmental cleanup and restoration costs. Failure to comply with the OPA may subject a responsible party to civil or criminal enforcement action. We may conduct operations on acreage located near, or that affects, navigable waters subject to the OPA. We believe that compliance with applicable requirements under the OPA will not have a material and adverse effect on us.

Hydraulic fracturing is a practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations. The process involves the injection of water, sand and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. Although hydraulic fracturing has historically been regulated by state oil and gas commissions the EPA recently asserted federal regulatory authority over the process under the SDWA’s Underground Injection Control (“UIC”) Program. Under this assertion of authority, the EPA requires facilities to obtain permits to use diesel fuel in hydraulic fracturing

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operations, specifically in Class II wells, which are those wells injecting fluids associated with oil and natural gas production activities. The U.S. Energy Policy Act of 2005, which exempts hydraulic fracturing from regulation under the SDWA, prohibits the use of diesel fuel in the fracturing process without a UIC permit. On February 12, 2014, the EPA released an interpretive memorandum and technical recommendations for implementing the UIC Program for oil and natural gas hydraulic fracturing activities using diesel fuel. The guidance document describes how Class II regulations may be tailored to address the purported unique risks of diesel fuel injection during the hydraulic fracturing process. Although EPA has delegated UIC permitting authority to many states, it is encouraging those states to review and consider use of this permit guidance.

The EPA is also evaluating a variety of environmental issues associated with hydraulic fracturing. 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. The EPA is also updating chloride water quality criteria for the protection of aquatic life under the Clean Water Act, which criteria are used by states for establishing acceptable discharge limits. In addition, on May 19, 2014, the EPA issued an advance notice of proposed rulemaking pursuant to the Toxic Substances Control Act, requesting comments on the information that should be reported or disclosed for hydraulic fracturing chemical substances and mixtures and the mechanism for obtaining this information. 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 2014 to 2016 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” took effect in January 2014. In September 2010, 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 DOI plans to issue a final rule in 2014.

Air Emissions. Our operations are subject to federal regulations for the control of emissions from sources of air pollution under the CAA and analogous state and local regulations. Federal and state laws require new and modified sources of air pollutants to obtain permits prior to commencing construction and also impose various monitoring and reporting requirements. Major sources of air pollutants are subject to more stringent, federally

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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 seeks to achieve a 95% reduction in VOCs emitted by requiring the use of reduced emission completions or “green completions” on all hydraulically-fractured wells constructed or refractured after January 1, 2015. These rules may require a number of modifications to our operations, including the installation of new equipment to control emissions from our wells by January 1, 2015. The EPA received numerous requests for reconsideration of these rules from both industry and the environmental community, and court challenges to the rules were also filed. The EPA intends to issue revised rules that are likely responsive to some of these requests. On September 23, 2013, the EPA finalized the portion of the rule addressing VOC emissions from storage tanks, including a phase-in period and an alternative emissions limit for older tanks. On July 1, 2014, the EPA announced proposed amendments and clarifications to the NSPS standards. 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 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. The tailoring rule established 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. On June 23, 2014, the Supreme Court held that the tailoring rule exceeded EPA’s authority under the CAA. The Court ruled that stationary

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sources could not become subject to PSD or Title V permitting merely by reason of their GHG emissions. The Court further ruled that the EPA may require installation of best available control technology for GHG emissions at sources otherwise subject to the PSD or Title V programs. The EPA has announced that it is currently evaluating the decision and awaiting further action by the courts, and that it will provide relevant guidance on GHG permitting requirements. The Court’s ruling does not affect the EPA’s exercise of authority under different sections of the CAA.

In September 2009, the EPA issued a final rule requiring the reporting of GHG emissions from specified large GHG emission sources in the U.S., including NGLs fractionators and local natural gas/distribution companies, 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. In addition, the EPA has continued to adopt GHG regulations of other industries, such as a September 2013 proposed GHG rule that, if finalized, would set NSPS standards for new fossil-fuel fired power plants. Finally, on June 2, 2014, the EPA issued the so-called Clean Power Plan proposed rules, which propose state-specific rate-based goals to reduce GHG emissions from existing fossil-fuel fired power plants. 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 DOI, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an Environmental Assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. All of our current exploration and production activities, as well as proposed exploration and development plans, on federal lands require governmental permits that are subject to the requirements of NEPA. This process has the potential to delay or impose additional conditions upon the development of oil and natural gas projects.

Endangered Species Act. The Endangered Species Act, as amended (the “ESA”), and analogous state statutes restrict activities that may affect endangered and threatened species or their habitats. While some of our

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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, at least 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.

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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 BLM, the Bureau of Ocean Energy Management, Bureau of Safety and Environmental Enforcement, or other appropriate federal or state agencies.

Transportation of Oil. Sales of oil are not currently regulated and are made at negotiated prices. Nevertheless, the United States Congress could reenact price controls in the future. 

Our sales of oil are affected by the availability, terms and cost of transportation. The transportation of oil in common carrier pipelines is also subject to rate and access regulation. The FERC regulates interstate oil pipeline transportation rates under the Interstate Commerce Act. In general, interstate oil pipeline rates must be cost-based, although settlement rates agreed to by all shippers are permitted and market based rates may be permitted in certain circumstances. Effective January 1, 1995, the FERC implemented regulations establishing an indexing system (based on inflation) for transportation rates for oil that allowed for an annual increase or decrease in the cost of transporting oil to the purchaser, effective July 1 of each year. The FERC reviews the indexing methodology every five years. In its latest order on the methodology, issued in December 2010, the FERC concluded that an index level of the Producer Price Index for Finished Goods plus 2.65 percent should be established for the five-year period commencing July 1, 2011.

Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any way that is of material difference from those of our competitors who are similarly situated.

Further, interstate and intrastate common carrier oil pipelines must provide service on a non- discriminatory basis. Under this open access standard, common carriers must offer service to all similarly situated shippers requesting service on the same terms and under the same rates. When shipper nominations exceed full capacity, access is governed by prorationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our similarly situated competitors.

Transportation and Sales of Natural Gas. The transportation of natural gas in interstate commerce by pipelines, and the sale for resale of natural gas in interstate commerce by pipelines or their affiliates and local distribution companies or their affiliates, are regulated by the FERC under the Natural Gas Act of 1938 (the “NGA”), the Natural Gas Policy Act of 1978 (the “NGPA”), and regulations issued under those statutes. In the past, the federal government has regulated the prices at which natural gas could be sold. While sales by producers of natural gas can currently be made at market prices (subject to anti-manipulation rules, which are discussed below), the United States Congress could reenact price controls in the future. Deregulation of wellhead natural gas sales began with the enactment of the NGPA and culminated in adoption of the Natural Gas Wellhead Decontrol Act which removed all price controls affecting wellhead sales of natural gas (so-called “first sales”) effective January 1, 1993.

FERC regulates interstate natural gas transportation rates, and terms and conditions of service, and this regulation affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas. Since 1985, the FERC has endeavored to make natural gas transportation more accessible to natural gas buyers and sellers on an open and non-discriminatory basis. The FERC has stated that open access policies are necessary to improve the competitive structure of the interstate natural gas pipeline industry and to create a regulatory framework that will put natural gas sellers into more direct contractual relations with natural gas buyers by, among other things, unbundling the sale of natural gas from the sale of transportation and storage services. Beginning with Order No. 636 in 1992, FERC adopted mandatory open access policies including

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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. See “—Other Federal Laws and Regulations Affecting Our Industry—Energy Policy Act of 2005.” Should we violate the anti-market manipulation laws and regulations, we could also be subject to related third party damage claims by, among others, sellers, royalty owners and taxing authorities.

FERC has jurisdiction under the NGA over some (but not all) sales for resale of physical gas. FERC has issued blanket certificates under the NGA that pre-authorize various sales for resale in interstate commerce. These blanket certificates preauthorize interstate sales for resale automatically, without the need to apply for the certificate, and without any conditions as to the price, purchaser, volume, term or other economic conditions of the sale. The blanket certificates also pre-authorize abandonment of the sale under the NGA upon expiration of the contract term or termination of the individualized sales arrangement. However, FERC retains NGA jurisdiction over all blanket certificate sales, meaning that FERC has the ability to add prospective terms and conditions to such certificates as future conditions warrant. FERC first exercised this authority in 2003, when in the wake of the market upheavals in California, FERC established a gas marketing “code of conduct” applicable to all blanket certificate sellers. The code of conduct for blanket certificate sellers includes price reporting provisions intended to address the problems that surfaced in gas markets concerning false transaction reports designed to manipulate price indices published by various publications. The code of conduct’s price reporting provision does not require any seller to report transactions to a publisher of natural gas price indices, but requires that any seller who chooses to do so must provide accurate information, not knowingly submit false or misleading information, or omit material information. Blanket certificate holders who violate the certificate conditions (including the code of conduct) are subject to potential suspension or revocation of the certificate. All blanket certificate sellers are subject to the regulatory risk associated with future FERC action to prescribe new conditions for transactions conducted under the certificate.

Pursuant to FERC Order No. 704, some of our operations may be required to annually report to the FERC on May 1 of each year for the previous calendar year. Order No. 704 has its genesis in the Energy Policy Act of 2005, which added section 23 of the NGA. Section 23 of the NGA, among other things, directs FERC “to facilitate price transparency in markets for the sale or transportation of physical natural gas in interstate commerce, having due regard for the public interest, the integrity of those markets, and the protection of consumers.” Order No. 704 requires market participants with reportable physical natural gas purchases or sales equal to or greater than 2.2 trillion British thermal units must comply with the reporting requirements. Reportable physical natural gas purchases include physical natural gas transactions that use an index or that contribute to or may contribute to the formation of a gas index.

The Energy Policy Act of 2005 amended the Natural Gas Act to give FERC authority to assess civil penalties to any person that violates the Natural Gas Act or any rule, regulation, restriction, condition, or order under the Act. Such penalties may be up to $1 million per day per violation. This significantly adds to the risk of FERC-regulated companies that violate the NGA or rules or orders thereunder as well as to non-regulated entities that directly or indirectly manipulate the purchase or sale of FERC-regulated natural gas or the purchase or sale of FERC-regulated transportation services. See “—Other Federal Laws and Regulations Affecting Our Industry—Energy Policy Act of 2005.”

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Gathering services, which occur upstream of FERC jurisdictional gas transmission services, are regulated by the states. In addition, intrastate natural gas transportation and facilities are also subject to regulation by state regulatory agencies, and certain transportation services provided by intrastate pipelines are also regulated by the FERC. The basis for regulation of intrastate natural gas transportation and gathering and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline and gathering pipeline rates and services varies from state to state. Insofar as such regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable basis, we believe that the regulation of similarly situated intrastate natural gas transportation in any states in which we operate and ship natural gas on an intrastate basis will not affect our operations in any way that is of material difference from those of our competitors. Like the regulation of interstate transportation rates, the regulation of intrastate transportation rates affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas.

State Natural Gas Regulation. Various states, including Texas, regulate the drilling for, and the production, gathering and sale of, natural gas, including imposing severance taxes and requirements for obtaining drilling permits. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of natural gas resources. States may regulate rates of production and may establish maximum daily production allowables from natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but there can be no assurance that they will not do so in the future. The effect of these regulations may be to limit the amounts of natural gas that may be produced from our wells and to limit the number of wells or locations we can drill.

Other Federal Laws and Regulations Affecting Our Industry

Energy Policy Act of 2005. On August 8, 2005, President Bush signed into law the Energy Policy Act of 2005 (the “EPAct 2005”). The EPAct 2005 is a comprehensive compilation of tax incentives, authorized appropriations for grants and guaranteed loans, and significant changes to the statutory policy that affects all segments of the energy industry. Among other matters, the EPAct 2005 amends the NGA to add an anti-manipulation provision which makes it unlawful for any entity to engage in prohibited behavior to be prescribed by the FERC, and furthermore provides the FERC with additional civil penalty authority. The EPAct 2005 provides the FERC with the power to assess civil penalties of up to $1.0 million per day for violations of the NGA and increases the FERC’s civil penalty authority under the NGPA from $5,000 per violation per day to $1.0 million per violation per day. On January 19, 2006, the FERC issued Order No. 670, a rule that implements the anti-manipulation provision of the EPAct 2005 and makes it unlawful for any entity, directly or indirectly, in connection with the purchase or sale of natural gas subject to the jurisdiction of the FERC, or the purchase or sale of transportation services subject to the jurisdiction of the FERC: (1) to use or employ any device, scheme or artifice to defraud; (2) to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or (3) to engage in any act, practice, or course of business that operates as a fraud or deceit upon any person. The anti-manipulation rules and enhanced civil penalty authority reflect an expansion of the FERC’s NGA enforcement authority. Should we fail to comply with all applicable FERC administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines.

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PROPERTIES

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.

The following map shows the locations of our core properties as of June 30, 2014.

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Summary of Geographic Areas of Operations

The following table sets forth summary estimated reserve information attributable to our principal geographic areas of operations as of January 1, 2014. The following table includes reserves represented by the 17% of Cross Border not owned by us.

	PDP						PDNP						PUD						Total
	Oil (MBbls)		Natural Gas (MMcf)		Natural Gas Liquids (MBbls)		Oil (MBbls)		Natural Gas (MMcf)		Natural Gas Liquids (MBbls)		Oil (MBbls)		Natural Gas (MMcf)		Natural Gas Liquids (MBbls)		Oil (MBbls)		Natural Gas (MMcf)		Natural Gas Liquids (MBbls)
Permian Basin		851		2,131		105		148		195		—		1,335		1,811		84		2,334		4,137		189
Onshore Gulf Coast		3		2,021		—		—		114		—		—		—		—		3		2,135		—
Total		854		4,153		105		148		309		—		1,335		1,811		84		2,337		6,273		189

Permian Basin

The following description of our properties in the Permian Basin is presented as of June 30, 2014, except where indicated.

Madera Prospect.The Madera Prospect consists of 2,545 gross (1,132 net) acres in Lea County, New Mexico. Our interests in the Madera Prospect include 7 gross (4.1 net) producing wells with an average working interest of 58.4% and an average net revenue interest of 44.4%. RMR Operating is the operator of the Madera Prospect.

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 June 30, 2014, the Madera 24 Federal 2H well has produced over 169 MBoe, of which 70% 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 81.5% working interest (60.6% 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 32.5% working interest and 24.3% net revenue interest. 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. Our third horizontal Brushy Canyon well at the Madera Prospect, Madera 19 Federal 4H, was completed in March 2014 and had an initial production rate of 740 Boe/d, of which 86% was oil. The well was drilled to a measured depth of 15,843 feet, including a lateral length of 6,813 feet. We are the operator of the well and have an approximately 84% working interest and 63% net revenue interest. Another long lateral length well, the Madera 25 Federal 2H, in which we have an approximately 30% working interest and 23% net revenue interest, was drilled to measured depth of 15,827 feet, and is awaiting completion. The Madera Prospect contains an additional 5 proved undeveloped well locations (2.5 net) that target the Brushy Canyon reservoir.

As of January 1, 2014, the Madera Prospect had estimated proved reserves of 982 MBoe, of which 698 MBoe were proved undeveloped, and had net daily average production for the three months ended June 30, 2014 of 494 Boe/d, of which 61% was oil.

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Pawnee Prospect. We own oil and natural gas interests in 1,255 gross and net acres in the Pawnee Prospect in Lea County, New Mexico. The six gross and net producing wells have an average working interest of 100% and an average net revenue interest of 75%. This acreage targets the Tansill, Yates and Delaware formations. RMR Operating is the operator of the Pawnee Prospect. We drilled two wells on the Pawnee Prospect during fiscal 2012. We completed the Big Brave State #1 well in January 2012 and the Good Chief State #1 well in December 2011, with initial production rates of 52 Boe/d and 28 Boe/d, respectively, consisting of substantially all oil production. Both wells are marginal producers, and we are considering converting the wells to salt water disposal wells. As of January 1, 2014, the Pawnee Prospect had estimated proved reserves of 3 MBoe and had net daily average production sold for the three months ended June 30, 2014 of 4 Boe/d, all of which was oil production.

Cowden Lease. We own oil and natural gas interests in 760 gross (740 net) acres plus 48 acres of surface property in the Cowden Lease in Ector County, Texas. There are 19 gross (18.0 net) producing wells on the Cowden Lease with an average working interest of 94.7% and an average net revenue interest of 72.7%. The Cowden Lease is held by production. RMR Operating is the operator of the Cowden Lease. The Cowden Lease is located between the Harper and Donnelly San Andres fields on the Central Basin Platform and produces from the Grayburg and San Andres formations. It has three gross and net proved undeveloped drilling locations. As of January 1, 2014, the Cowden Lease had estimated proved reserves of 109 MBoe, of which 78 MBoe were proved undeveloped, and had net daily average production sold for the three months ended June 30, 2014 of 12 Boe/d, all of which was oil production.

Shafter Lake Lease. We own oil and natural gas interests in 322 gross (187 net) acres within the Shafter Lake San Andres field in Andrews County, Texas. The Shafter Lake Lease is horizontally severed at 4,520 feet and is held by production. We own all rights from the surface of the land to approximately 4,520 feet below the surface of the land. RMR Operating is the operator of the Shafter Lake Lease. There are three proved undeveloped locations on these leases (1.7 net wells) which target the Grayburg and San Andres formations. We hold a 58.1% working interest and a 39.7% net revenue interest in this acreage. As of January 1, 2014, our Shafter Lake Lease had estimated proved reserves of 66 MBoe, all of which were proved undeveloped, and no production.

Martin Lease. We own oil and natural gas interests in 337 gross (337 net) acres in Andrews County, Texas. The Martin Lease is horizontally severed at 5,000 feet and is held by production. We own the deep rights from 5,000 feet below the surface of the land. The target horizons on the Martin Lease are the Clearfork, Grayburg and San Andres formations. We own a 100% working interest and a 75% net revenue interest. As of January 1, 2014, our Martin Lease had no proved reserves or production. In the event we elect to perform operations on this property, RMR Operating will be the operator.

East Ranch and West Ranch Prospects. We own oil and natural gas interests in 1,425 gross and net acres in Pecos County, Texas. There are multiple target horizons in this prospect. We own a 100% working interest and an 80% net revenue interest, and RMR Operating is the operator. As of January 1, 2014, neither the East Ranch nor West Ranch Prospect had proved reserves or production.

Jackson Bough C Prospect. We own oil and natural gas interests in 320 gross (200 net) acres in Lea County, New Mexico. There are multiple target horizons in this prospect. We own a 100% working interest and an 80% net revenue interest, and RMR Operating is the operator. As of January 1, 2014, the Jackson Bough C Prospect had no proved reserves or production.

Tom Tom Area.Cross Border owns oil and natural gas interests in approximately 8,300 gross (6,200 net) acres in the Tom Tom and Tomahawk fields in Chaves and Roosevelt Counties, New Mexico. Cross Border is the operator of these leases. The target formation in the area is the San Andres reservoir, which is productive across the trend with the Cato field to the west and the Chaveroo field to the east. There are 66 gross wells (52.3 net) in the acreage, with an average working interest of 79% and an average net revenue interest of 66%. As of January 1, 2014, the Tom Tom area had estimated proved reserves of 462 MBoe, of which 91 MBoe were

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proved developed non-producing and 302 MBoe were proved undeveloped. The area had net daily average production sold for the three months ended June 30, 2014 of 20 Boe/d, all of which was oil production.

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 up to $2.1 million during our fiscal 2015 to correct environmental issues on these fields.

We commenced a 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 (8.4 net) with proved developed non-producing reserves. Additionally, there are 12 proved undeveloped locations (10.3 net) that target the San Andres formation. The second round of workovers was commenced in April 2014. We plan to reenter most of our existing Tom Tom wellbores by the end of fiscal 2015.

Non-Operated. Cross Border owns non-operated, oil and natural gas interests in 321,253 gross (19,473 net) acres in Chaves, DeBaca, Eddy, Lea and Roosevelt Counties, New Mexico of the Permian Basin. Current development of this acreage is focused on prospective Bone Spring acreage located in the heart of the 1st and 2nd Bone Spring play, which encompasses approximately 4,390 square miles across both New Mexico and Texas. Other non-operated development targets include the Queen, Grayburg, San Andres, Yeso, and Abo reservoirs. Our operating partners, which include Apache Corp., Mewbourne Oil Company, Concho Resources Inc., COG Operating LLC, LRE Operating, LLC, XTO Energy Inc., Cimarex Energy Co., and Occidental Petroleum Corporation, have significant footprints within these plays. As of January 1, 2014, this non-operated acreage had estimated proved reserves of 1,590 MBoe and had net daily average production sold for the three months ended June 30, 2014 of 527 Boe/d, 65% of which was oil.

Cross Border’s non-operated acreage includes two key producing areas: the Lusk Prospect and the Turkey Track Prospect. The Lusk Prospect consists of 18 gross (4.9 net) producing wells in Lea County, New Mexico, with an average working interest of 27% and an average net revenue interest of 21%, The primary targets in the Lusk Prospect are the 2^nd Bone Spring and Delaware reservoirs. The operators in the Lusk Prospect are Occidental Petroleum Corporation, Apache Corp., Cimarex Energy Co., and Concho Resources Inc. As of January 1, 2014, the Lusk Prospect had estimated proved reserves of 681 MBoe, of which 146 MBoe were proved undeveloped, and net daily average production sold for the three months ended June 30, 2014 of 239 Boe/d, of which 69% was oil.

The Turkey Track Prospect consists of 19 gross (2.2 net) producing wells in Eddy County, New Mexico, with an average working interest of 11.7% and an average net revenue interest of 9.4%. The primary targets in the Turkey Track Prospect are the 1^st and 2^nd Bone Spring reservoirs. The operator of the Turkey Track Prospect is Mewbourne Oil Company. As of January 1, 2014, the Turkey Track Prospect had estimated proved reserves of 519 MBoe, of which 291 MBoe were proved undeveloped, and net daily average production sold for the three months ended June 30, 2014 of 164 Boe/d, of which 64% was oil.

Onshore Gulf Coast

The following is a description of our properties in the onshore Gulf Coast as of June 30, 2014, except where indicated.

Villarreal Prospect. The Villarreal Prospect covers 1,099 gross (154 net) acres in Zapata County, Texas. We own an average working interest of 14.1% and an average net revenue interest of 10.6% in this acreage. We have 13 gross (1.8 net) wells on the prospect producing from the Wilcox formation. In August 2012, ConocoPhillips Company, the operator, drilled and completed the Villarreal #2 well, which had an initial production rate of 2,567 Mcf/d (428 Boe/d). As of January 1, 2014, the Villarreal Prospect had estimated proved reserves of 267 MBoe and had net daily average production sold for the three months ended June 30, 2014 of 134 Boe/d, substantially all of which was natural gas.

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Frost Bank Prospect. The Frost Bank Prospect covers 998 gross (521 net) acres in Duval County, Texas. We own an average working interest of 55.8% and an average net revenue interest of 41.9% in this acreage. There are five gross (2.8 net) wells on the Frost Bank Prospect producing from the Wilcox formation. RMR Operating is the operator of the Frost Bank Prospect. As of January 1, 2014, the Frost Bank Prospect had estimated proved reserves of 22 MBoe, of which 19 MBoe were proved developed non-producing, and had net daily average production sold for the three months ended June 30, 2014 of 3 Boe/d, all of which was natural gas.

Peal Ranch Prospect. We own oil and natural gas interests in 1,888 gross (354 net) acres in the Peal Ranch Prospect in Duval County, Texas. We own an average working interest of 22.7% and an average net revenue interest of 16.6% in this acreage. There are 12 gross (2.7 net) wells producing from the Wilcox formation. These wells share common gas processing facilities with the Frost Bank wells. The Peal Ranch Prospect is operated by White Oak Operating Company LLC. As of January 1, 2014, the Peal Ranch Prospect had proved reserves of 59 MBoe, all of which were proved developed producing. The prospect had net daily average production sold for the three months ended June 30, 2014 of 24 Boe/d, 93% of which was natural gas.

Resendez and La Duquesa Prospect. The Resendez and La Duquesa Prospect covers 240 gross acres (143 net) in Zapata County, Texas. There are four gross (3.2 net) wells on the acreage, two of which are producing from the Wilcox formation and two of which are shut-in. We own a 96.9% working interest and a 71.2% net revenue interest in the Resendez wells and a 81.3% working interest and a 61.0% net revenue interest in the La Duquesa well. RMR Operating is the operator of these wells. As of January 1, 2014, the Resendez and La Duquesa Prospect had no estimated proved reserves and had net daily average production sold for the three months ended June 30, 2014 of 6 Boe/d, all of which was natural gas.

New Mexico Non-Permian Minerals

Cross Border owns 536,526 gross (268,193 net) mineral acres in Hidalgo, Grant, Sierra, and Socorro Counties, New Mexico. This mineral ownership carries no drilling commitments or leasehold obligations. As of January 1, 2014, this acreage had no proved reserves or production.

Kansas

As of June 30, 2014, we owned oil and natural gas interests in 9,868 gross and net acres in central Kansas. There are multiple target horizons in this prospect including the Arbuckle and Lansing Kansas City. We own a 100% working interest and an average net revenue interest of 80%. RMR Operating is the operator. As of January 1, 2014, the Kansas acreage had no proved reserves or production.

Title to Properties

As is customary in the oil and natural gas industry, we generally conduct a preliminary title examination prior to the acquisition of properties or leasehold interests. Prior to commencement of operations on such acreage, a thorough title examination will usually be conducted and any significant defects will be remedied before proceeding with operations. We believe the title to our properties is good, defensible and customary with practices in the oil and natural gas industry, subject to such exceptions that we believe do not materially detract from the use of such properties. With respect to our properties of which we are not the record owner, we rely instead on contracts with the owner or operator of the property or assignment of leases, pursuant to which, among other things, we generally have the right to have our interest placed on record.

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.

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Summary of Oil and Natural Gas Reserves

Proved Reserves

The following table sets forth our estimated proved reserves.

	As of January 1, 2014
	Reserves
Estimated proved reserve data (1)(2)	Oil (MBbls)		Natural Gas (MMcf)		Natural Gas Liquids (MBbls)		Total (MBoe)
Proved developed producing reserves		854		4,153		105		1,651
Proved developed non-producing reserves		148		309		—		200
Proved undeveloped reserves		1,335		1,811		84		1,721
Total proved reserves		2,337		6,273		189		3,572

(1) Prices used are based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the period January 2013 through December 2013. For oil volumes, the average NYMEX spot price is $96.78 per Bbl. For natural gas volumes, the average Henry Hub spot price is $3.67 per MMBtu. Each of the oil price of $88.93 per barrel, the NGL price of $29.61 per barrel, and the natural gas price of $4.41 per Mcf is adjusted for basis differentials, hydrocarbon quality, and transportation, processing, and gathering fees. The adjusted oil, NGL and natural gas prices are held constant throughout the lives of the properties.

(2) Proved reserves include 100% of the reserve quantities attributable to Cross Border.

The following table sets forth our estimated PV-10 and standardized measure of discounted net cash flows as of January 1, 2014.

(in thousands)	As of January 1, 2014
PV-10 (1)	$	73,317
Standardized measure	$	62,425

(1) PV-10 is a non-GAAP financial measure as defined by the SEC. The closest GAAP measure to PV-10 is the standardized measure of discounted net cash flows. The standardized measure differs from PV-10 because standardized measure includes the effect of future income taxes. We believe that the presentation of PV-10 is relevant and useful to our investors as supplemental disclosure to the standardized measure, or after-tax amount, because it presents the discounted future net cash flows attributable to our proved reserves before taking into account future corporate income taxes and our current tax structure. The following table provides a reconciliation of our PV-10 to our standardized measure:

(in thousands)	As of January 1, 2014
PV-10	$	73,317
Future income taxes		28,406
Discount of future income taxes at 10% per annum		17,514
Standardized measure	$	62,425

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

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estimated proved reserves of 2.5 MMBoe through our acquisitions and the consolidation 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 January 1, 2014, our estimated proved reserves were 3.6 MMBoe, consisting of 65% oil.

Proved Undeveloped Reserves

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 consolidation 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. At January 1, 2014, our estimated proved undeveloped reserves were 1.7 MMBoe, consisting of 78% oil.

Qualifications of Technical Persons and Internal Controls Over Reserves Estimation Process

Our January 1, 2014 reserve report was prepared by Cawley, Gillespie & Associates, Inc. (“CG&A”), independent petroleum engineers. CG&A estimated 100% of our proved reserves in accordance with petroleum engineering and evaluation principles set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserve Information promulgated by the Society of Petroleum Engineers (“SPE Standards”) and definitions and guidelines established by the SEC.

The technical persons responsible for preparing the reserves estimates presented herein meet the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the SPE Standards.

The principal person at CG&A who prepared the reserve report is Mr. Zane Meekins. Mr. Meekins has been a practicing consulting petroleum engineer at CG&A since 1989. Mr. Meekins is a Registered Professional Engineer in the State of Texas (License No. 71055) and has over 27 years of practical experience in petroleum engineering, with over 25 years of experience in the estimation and evaluation of reserves. He graduated from Texas A&M University in 1987 with a Bachelor of Science degree in Petroleum Engineering. Mr. Meekins meets or exceeds the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the SPE Standards. He is proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserve definitions and guidelines.

We have an internal staff of geoscience professionals who work closely with our independent petroleum engineers to ensure the integrity, accuracy and timeliness of data furnished to them in their reserves estimation process. Our technical team consults regularly with representatives of CG&A. We review with them our properties and discuss methods and assumptions used in their preparation of our reserves estimates. While we have no formal committee specifically designated to review reserves reporting and the reserves estimation process, a copy of the reserve report is reviewed with representatives of CG&A and our internal technical staff before we disseminate any of the information. Additionally, our senior management reviews and approves the reserve report and any internally estimated significant changes to our proved reserves on an annual basis.

Estimates of oil and natural gas reserves are projections based on a process involving an independent third party engineering firm’s collection of all required geologic, geophysical, engineering and economic data, and such firm’s complete external preparation of all required estimates and are forward-looking in nature. These

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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.

Summary of Oil and Natural Gas Properties and Projects

Production, Price and Cost History

The following table sets forth summary information regarding our oil and natural gas sales, net production sold, average sales prices and production costs and expenses for the fiscal years ended May 31, 2013, 2012 and 2011.

	Fiscal Year Ended,
(dollars in thousands, except per unit prices)	May 31, 2013 (1)		May 31, 2012		May 31, 2011
Net Production sold
Oil (Bbl)		83,143		37,004		—
Natural gas (Mcf)		645,609		795,659		900,332
Natural gas liquids (Bbl)		7,427		5,438		1,177
Total (Boe)		198,172		175,052		151,233
Total (Boe/d) (2)		543		480		414
Average sales prices
Oil ($/Bbl)	$	81.26	$	93.97	$	—
Natural gas ($/Mcf)		3.40		3.58		4.12
Natural gas liquids ($/Bbl)		29.62		46.45		40.28
Total average price ($/Boe)	$	45.32	$	36.13	$	24.54
Costs and expenses (per Boe)
Exploration expense	$	4.28	$	1.51	$	—
Production taxes		2.70		2.31		1.06
Lease operating expenses		8.93		5.39		1.09
Natural gas transportation and marketing expenses		0.52		0.97		1.56
Depreciation, depletion, amortization and impairment		23.11		29.42		4.74
Accretion of discount on asset retirement obligation		0.76		0.24		0.06
General and administrative expense		39.47		35.22		1.88

(1) The results for the fiscal year ended May 31, 2013 only include results and estimated production from Cross Border since February 1, 2013.

(2) Boe/d is calculated based on actual calendar days during the period.

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The following table provides a summary of our net production sold for oil and gas fields containing 15% or more of our total proved reserves as of January 1, 2014:

	Fiscal Year Ended,
	May 31, 2013		May 31, 2012		May 31, 2011
Madera Prospect
Oil (Bbl)		33,266		32,424		—
Natural gas (Mcf)		51,151		88,499		—
Natural gas liquids (Bbl)		4,357		4,484		—
Total (Boe)		46,148		51,657		—
Total (Boe/d)		126		141		—
Lusk Prospect
Oil (Bbl)		27,180		—		—
Natural gas (Mcf)		38,425		—		—
Natural gas liquids (Bbl)		1,226		—		—
Total (Boe)		34,810		—		—
Total (Boe/d)		95		—		—

Developed and Undeveloped Acreage

The following table presents our total gross and net developed and undeveloped acreage by region as of June 30, 2014:

	Developed Acres				Undeveloped Acres
	Gross (1)		Net (2)		Gross (1)		Net (2)
Permian Basin (3)		10,757		5,028		325,574		25,898
Onshore Gulf Coast		4,776		1,405		—		—
New Mexico Non-Permian (4)		—		—		536,526		268,193
Kansas		—		—		9,868		9,868
Total		15,533		6,433		871,968		303,959

(1) “Gross” means the total number of acres in which we have a working interest.

(2) “Net” means the sum of the fractional working interests that we own in gross acres.

(3) Undeveloped acreage includes mineral ownership.

(4) Reflects mineral ownership.

The primary terms of our oil and natural gas leases expire at various dates. Much of our developed acreage is held by production, which means that these leases are active as long as we produce oil or natural gas from the acreage or comply with certain lease terms. Upon ceasing production, these leases will expire. The following table summarizes by year our gross and net undeveloped leasehold acreage scheduled to expire in the next five years.

	Undeveloped Leasehold Acres				% of Total Undeveloped Leasehold Acres
As of June 30,	Gross (1)		Net (2)		Net (2)
2015		8,768		8,648		24.0	%
2016		2,513		2,513		7.0	%
2017		332		332		0.9	%
2018		—		—		—
2019		—		—		—

(1) “Gross” means the total number of acres in which we have a working interest.

(2) “Net” means the sum of the fractional working interests that we own in gross acres.

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Productive Wells

The following table presents the total gross and net productive wells by area and by oil or natural gas completion as of June 30, 2014. Cross Border owns royalty interests in 16 gross wells (average of 0.43 net), which have been excluded from these well counts.

	Oil Wells				Natural Gas Wells
	Gross (1)		Net (2)		Gross (1)		Net (2)
Permian Basin		179		88.2		41		6.0
Onshore Gulf Coast		—		—		37		12.8
Total		179		88.2		78		18.8

(1) “Gross” means the total number of wells in which we have a working interest.

(2) “Net” means the sum of the fractional working interests that we own in gross wells.

Drilling Activity

At June 30, 2014, we had two gross wells (0.43 net) awaiting completion, one in the Madera Prospect and one in the Turkey Track Prospect.

The following table summarizes the number of net productive and dry development wells and net productive and dry exploratory wells we drilled during the periods indicated and refers to the number of wells completed during the period, regardless of when drilling was initiated.

	Development Wells				Exploratory Wells
Fiscal Year Ended,	Productive		Dry		Productive		Dry
June 30, 2014		1.95		—		—		—
May 31, 2013		1.56		—		—		—
May 31, 2012		—		—		2.96		—

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MANAGEMENT

Directors and Executive Officers

The following sets forth information about the Company’s directors and executive officers:

Name	Age		Position
Alan W. Barksdale		36	President, Chief Executive Officer and Director
Hilda D. Kouvelis		51	Chief Accounting Officer and Executive Vice President
David M. Heikkinen		43	Director
Richard Y. Roberts		63	Director
Paul N. Vassilakos		37	Director
Frank Yates Jr.		58	Director

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 since its inception. Mr. Barksdale has also been the owner and president of StoneStreet 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 since May 2012. We believe that Mr. Barksdale’s experience in operating, managing, financing and investing in more than 100 wells in Louisiana, New Mexico and Texas, combined with his over ten years of capital markets experience and contacts and relationships, provides our board of directors with 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 at Stephens Inc. Without admitting or denying the allegations, Mr. Barksdale entered into an acceptance, waiver and consent decree that provided for a 30-day suspension from associating with any NASD member and a $5,000 fine.

Hilda D. Kouvelis has served as our Chief Accounting Officer since February 2012 and was appointed Executive Vice President in July 2012. Ms. Kouvelis has more than 25 years of industry accounting and finance experience. From January 2005 until June 2011, she was employed with TransAtlantic Petroleum Ltd., an international oil and natural gas company engaged in the acquisition, exploration, development and production of oil and natural gas, serving as its Chief Financial Officer from January 2007 until April 2011 and as its Vice President from May 2007 to April 2011. She also served as its controller from January 2005 to January 2007. Prior to joining TransAtlantic Petroleum, Ms. Kouvelis served as Controller for Ascent Energy, Inc. from 2001 to 2004 and as Financial Controller for the international operations at the headquarters of PetroFina, S.A. in Brussels, Belgium from 1998 through 2000.

David M. Heikkinen has been a director since April 2013. Mr. Heikkinen has served as the Chief Executive Officer of Heikkinen Energy Advisors, LLC, an institutional equity research and investment advisory firm, since he founded it in July 2012. From December 2005 to February 2012, Mr. Heikkinen served as Head of Exploration and Production Research for Tudor, Pickering, Holt & Co., an integrated energy investment and merchant bank, providing advice and services to institutional and corporate clients. From February 2000 to December 2005, Mr. Heikkinen served as the Exploration and Production Analyst for Capital One Southcoast, Inc., an energy investment banking boutique. From January 1994 to February 2000, Mr. Heikkinen held various engineering roles with Shell Offshore Inc. and Shell International Exploration and Production. In addition,

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Mr. Heikkinen has served as a director of Taos Resources, a Houston based oil and gas exploration and production company, since July 2013. We believe our board of directors benefits from Mr. Heikkinen’s extensive capital markets experience in the oil and gas industry.

Richard Y. Robertshas been a director since October 2011. Mr. Roberts co-founded a regulatory and legislative consulting firm, Roberts, Raheb & Gradler LLC, in March 2006. He was a partner with Thelen Reid & Priest LLP, a national law firm, from January 1997 to March 2006. From August 1995 to January 1997, Mr. Roberts was a consultant at Princeton Venture Research, Inc., a private consulting firm. From 1990 to 1995, Mr. Roberts was a commissioner of the SEC. Mr. Roberts is currently a director of Cullen Agricultural Holding Corp. (“CAH”). CAH is a development stage agricultural company which was formed in connection with the business combination between Triplecrown Acquisition Corp. and Cullen Agricultural Technologies, Inc. in October 2009. He was a director of Nyfix, Inc. from September 2005 to December 2009 and Triplecrown Acquisition Corp. from June 2007 to October 2009. Mr. Roberts’ experience at the SEC, and his experience as a director of other public companies, as well as his professional contacts and relationships, provides our board of directors with necessary insight into the requirements and needs of an emerging public company.

Paul N. Vassilakos has been a director since October 2011. Mr. Vassilakos also previously served as our interim President and Chief Executive Officer from February 2011 to March 2011. From November 2011 through February 2012, Mr. Vassilakos served as Chief Executive Officer, Chief Financial Officer and director of Soton Holdings Group, Inc., a publicly held company now known as Rio Bravo Oil, Inc. Mr. Vassilakos has been the assistant treasurer of CAH since October 2009 and the Chief Executive Officer and a director of CAH since November 2013. In July 2007, Mr. Vassilakos founded Petrina Advisors, Inc., a privately held advisory firm providing investment banking services, and has served as its president since its formation. Mr. Vassilakos also founded and, since December 2006, serves as the vice president of Petrina Properties Ltd., a privately held real estate holding company. From February 2002 through June 2007, Mr. Vassilakos served as vice president of Elmsford Furniture Corp., a privately held furniture retailer in the New York area. Mr. Vassilakos has also served on the board of directors of Cross Border since May 2012. Mr. Vassilakos brings extensive public company and capital markets experience, as well as his professional contacts and experience, to our board of directors.

Frank Yates Jr. has been a director since June 2014. Mr. Yates has been Manager of Yates Industries, LLC, a single member investment company, since 1999 and has served as Chairman of the Board of Taos Resources, a Houston based oil and gas exploration and production company, since June 2013. From 1992 to 2007, he served as Vice President and, in 2007 and 2008, as President of Yates Petroleum Corporation, an independent oil and gas exploration and production company producing over 50,000 barrels of oil equivalent per day. From 1986 to September 2009, he served as President of MYCO Industries, Inc., associated with Yates Petroleum Corp in the oil and gas industry.

Director Independence

The corporate governance rules of the NASDAQ Capital Market require that a majority of the board of directors consist of directors who are “independent” of us. The board of directors has determined each of Messrs. Heikkinen, Roberts, Vassilakos and Yates qualify as “independent” under the NASDAQ standards for determining independence under the corporate governance rules of the NASDAQ Capital Market.

Board Committees

On July 21, 2014, the board of directors established an audit committee, compensation committee and nominating and corporate governance committee. The written charter for each committee and our code of conduct and ethics are posted and available on our website at www.redmountainresources.com. Stockholders may request copies of these corporate governance documents, free of charge, by writing to our Corporate Secretary at 2515 McKinney Avenue, Suite 900, Dallas, Texas 75201.

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Previously, we did not have separate standing audit, nominating or compensation committees. Our board of directors performed the functions of our audit, nominating and compensation committees.

Audit Committee Functions

The audit committee is responsible for overseeing the accounting and financial reporting processes of the Company and the audits of our financial statements. The audit committee is also directly responsible for the appointment, compensation, retention and oversight of the work of our independent auditors, including the resolution of disagreements between management and the auditors regarding financial reporting. Additionally, the audit committee approves all related-party transactions that are required to be disclosed pursuant to Item 404 of Regulation S-K. The audit committee currently consists of Mr. Heikkinen, who acts as chair, Mr. Vassilakos and Mr. Yates. All members of the audit committee have been determined to be financially literate and to meet the appropriate NASDAQ and SEC standards for independence. The board of directors has determined that each of Messrs. Heikkinen and Vassilakos is an “audit committee financial expert” in accordance with SEC rules.

Compensation Committee Functions

The compensation committee is responsible for, among other things, annually reviewing and recommending to the board of directors the salaries and other compensation of our executive officers, including our Chief Executive Officer. The compensation committee is also responsible for reviewing and recommending to the board of directors the compensation of our non-employee directors and overseeing regulatory compliance with respect to compensation matters. The compensation committee also produces annual reports on executive compensation for inclusion in our proxy statement. The compensation committee currently consists of Mr. Roberts, who acts as chair, and Mr. Heikkinen. All members of the compensation committee have been determined to meet the appropriate NASDAQ standards for independence.

Nominating and Corporate Governance Committee Functions

The nominating and corporate governance committee is responsible for, among other things, evaluating and recommending to the board of directors qualified nominees for election as directors and qualified directors for committee membership, as well as developing and recommending to the board of directors corporate governance principles applicable to the Company. The nominating and corporate governance committee currently consists of Mr. Vassilakos, who acts as chair, and Mr. Roberts. All members of the nominating and corporate governance committee have been determined to meet the appropriate NASDAQ standards for independence.

The nominating and corporate governance committee identifies individuals qualified to become members of the board of directors and recommend candidates to the board of directors to fill new or vacant positions. Except as may be required by rules promulgated by NASDAQ or the SEC, there are currently no specific, minimum qualifications that must be met by each candidate for the board of directors, nor are there specific qualities or skills that are necessary for one or more of the members of the board of directors to possess. In recommending candidates, the nominating and corporate governance committee considers such factors as it deems appropriate, including possible conflicts of interest.

Board and Committee Meetings

Our board of directors met 7 times during the fiscal year ended June 30, 2014. During fiscal 2014, each director attended 75% or more of the aggregate number of meetings held by our board of directors, except Mr. Yates who was appointed to the board of directors in June 2014. The board of directors’ independent directors did not meet separately from the board meetings that were held during fiscal 2014, but performed the necessary functions as audit, nominating and compensation committees during these meetings as necessary.

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We do not have a formal policy respecting attendance by our board of directors of annual meetings of the shareholders. However, we attempt to schedule our annual meetings so that all of our directors can attend and encourage them to do so. All of the then current members of our board of directors attended the Company’s 2013 Annual Meeting of Shareholders.

Board Leadership Structure and Role in Risk Oversight

Mr. Barksdale serves both as our Chief Executive Officer and Chairman of our board of directors. At this time, our board of directors believes that the Company is best served by having one person serve as both chief executive officer and the chairman because this structure provides unified leadership and direction. Given Mr. Barksdale’s extensive experience in operating, managing, financing and investing in oil and natural gas wells and his capital markets experience, Mr. Barksdale is uniquely situated to provide day-to-day operational guidance, as well as broader strategic and management direction for the Company. His knowledge of the Company’s daily operations as Chief Executive Officer ensures that key business issues are brought to our board of directors’ attention and prioritized as appropriate for the Company’s success. Our board of directors has not appointed a lead independent director.

Our board of directors’ role in the risk oversight process includes receiving regular reports from senior management on areas of material risk, including operational, financial, legal and regulatory and strategic and reputational risks. In connection with its review of the operations of our business and corporate functions, our board of directors considers and addresses the primary risks associated with those functions. Our board of directors regularly engages in discussions of the most significant risks that we are facing and how we manage these risks.

Code of Conduct and Ethics

Our board of directors has adopted a code of conduct and ethics that applies to our directors, officers, and employees. A copy of our code of conduct and ethics is available on our website atwww.redmountainresources.com/investor-information under the “Governance” heading. We intend to post any amendments to, or waivers from, our code of conduct and ethics that apply to our principal executive officer, principal financial officer, and principal accounting officer on our website atwww.redmountainresources.com/investor-information.

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DESCRIPTION OF THE SERIES A PREFERRED STOCK

The description of certain terms of the Series A Preferred Stock in this prospectus supplement does not purport to be complete and is in all respects subject to, and qualified in its entirety by references to, the relevant provisions of our certificate of formation pursuant to which the preferences, limitations, and relative rights of the Series A Preferred Stock has been established, our bylaws and Texas law. Copies of our certificate of formation and our bylaws are available from us upon request. As used under this caption “Description of the Series A Preferred Stock,” references to “us,” “our” and “we” mean Red Mountain Resources, Inc. and not its subsidiaries.

General

Our certificate of formation provides us the authority to issue up to 50,000,000 shares of common stock, par value $0.00001 per share, and 100,000,000 shares of preferred stock, par value $0.0001 per share. We may issue preferred stock from time to time in one or more classes or series, with such distinctive designations, rights and preferences as our board of directors may fix in the resolutions providing for the issuance of such class or series.

Our certificate of formation authorizes the issuance of up to 1,200,000 shares of Series A Preferred Stock, of which 254,463 shares are currently outstanding, and creates and establishes the number and fixes the terms, preferences, or other rights, voting powers, restrictions, limitations as to dividends or other distributions, qualifications and terms or conditions of redemption of our Series A Preferred Stock.

We have applied to list the shares of the Series A Preferred Stock on the NASDAQ Capital Market under the trading symbol “RMRAP”. If listing is approved, we expect trading to commence within 30 days after the initial delivery of the shares of Series A Preferred Stock offered hereby.

The registrar, transfer agent and dividend and redemption price disbursing agent in respect of the Series A Preferred Stock is Broadridge Corporate Issuer Solutions, Inc. (the “Transfer Agent”). The principal business address for the Transfer Agent is 1717 Arch St., Suite 1300, Philadelphia, Pennsylvania 19103, and its telephone number is (855) 793-5068. Our certificate of formation provides that we will maintain an office or agency where shares of Series A Preferred Stock may be surrendered for payment (including redemption), registration of transfer or exchange.

Ranking

The Series A Preferred Stock ranks: (i) senior to all Junior Stock; (ii) equal to any Parity Stock; (iii) junior to all Senior Stock; and (iv) junior to all of our existing and future indebtedness.

Dividends

Holders of shares of the Series A Preferred Stock are entitled to receive, when, as and if declared by our board of directors, out of funds legally available for the payment of dividends under Texas law, cumulative cash dividends at the Dividend Rate. Dividends on the Series A Preferred Stock shall accrue daily and be cumulative from, and including, July 1, 2014, the first day of the most recent quarterly dividend period. The next scheduled dividend will be payable on October 15, 2014 in the amount of approximately $0.65 per share, which will be paid to the persons who are the holders of record of the Series A Preferred Stock at the close of business on the corresponding record date, which will be September 30, 2014. Dividends on the Series A Preferred Stock are payable quarterly in arrears on each dividend payment date; provided that if any dividend payment date is not a business day, as defined in our certificate of formation, then the dividend which would otherwise have been payable on that dividend payment date may be paid on the next succeeding business day and no interest, additional dividends or other sums will accrue on the amount so payable for the period from and after that dividend payment date to that next succeeding business day. Any dividend payable on the Series A Preferred

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Stock, including dividends payable for any partial dividend period as prorated, will be computed on the basis of a 360-day year consisting of twelve 30-day months. Dividends will be payable to holders of record as they appear in our stock records for the Series A Preferred Stock at the close of business on the applicable record date, which shall be the last day of the applicable dividend period, whether or not a business day (each, a “dividend record date”).

No dividends on shares of Series A Preferred Stock shall be authorized by our board of directors or paid or set apart for payment by us at any time when the payment thereof would be unlawful under the laws of the State of Texas.

Dividends on the Series A Preferred Stock will accrue regardless of whether (i) the terms of any of our agreements, including any documents governing our indebtedness, at any time prohibit the declaration, payment or setting apart for payment, or provide that any such action would constitute a breach or default; (ii) we have earnings or profits; (iii) there are funds legally available for the payment of such dividends; or (iv) such dividends are declared by our board of directors. Any dividend payment made on the Series A Preferred Stock shall first be credited against the earliest accumulated but unpaid dividend due with respect to those shares. No interest, or sum in lieu of interest, will be payable in respect of any dividend payment or payments on the Series A Preferred Stock which may be in arrears, and holders of the Series A Preferred Stock will not be entitled to any dividends in excess of full cumulative dividends described above.

Future distributions on our common stock and preferred stock, including the Series A Preferred Stock, will be at the discretion of our board of directors and will depend on, among other things, our results of operations, cash flow from operations, financial condition and capital requirements, any debt service requirements and any other factors our board of directors deems relevant.

Unless full cumulative dividends on the Series A Preferred Stock have been or contemporaneously are declared and paid in cash or declared and a sum of cash sufficient for the payment thereof is set apart for payment for all past dividend periods, no dividends (other than in shares of Junior Stock) shall be declared or paid or set aside for payment upon shares of Junior Stock or Parity Stock. In addition, any shares of Junior Stock or Parity Stock shall not be redeemed, purchased or otherwise acquired for any consideration (or any monies paid to or made available for a sinking fund for the redemption of any such shares) by us.

When dividends are not paid in full (or a sum sufficient for such full payment is not so set apart) upon the Series A Preferred Stock and Parity Stock, all dividends declared, paid or set apart for payment upon the Series A Preferred Stock and any Parity Stock shall be declared, paid or set apart for payment pro rata so that the amount of dividends declared per share of Series A Preferred Stock and such other series of Parity Stock shall in all cases bear to each other the same ratio that accrued dividends per share on the Series A Preferred Stock and such other series of Parity Stock (which shall not include any accrual in respect of unpaid dividends for prior dividend periods if such Parity Stock does not have a cumulative dividend) bear to each other. No interest, or sum of money in lieu of interest, shall be payable in respect of any dividend payment or payments on the Series A Preferred Stock which may be in arrears.

In the event of a Dividend Default, the Dividend Rate specified shall be increased to the Default Rate. This Default Rate shall remain in effect until we have paid accrued but unpaid dividends on the Series A Preferred Stock and timely paid the accrued dividends for the two subsequent quarterly dividend payment periods, at which time the Dividend Rate shall revert to the rate of 10.0% of the $25.00 per share stated liquidation preference per annum otherwise specified for the next occurring dividend payment period and shall remain at 10.0% until a subsequent Dividend Default shall occur.

Whenever a Financial Covenant Default occurs, the Dividend Rate specified shall be increased to the Default Rate. The Default Rate shall remain in effect until our Asset Coverage Ratio on two consecutive quarterly balance sheets (not including the balance sheet for the quarter in which the Financial Covenant Default

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occurs) is 2.0 or greater, at which time the Dividend Rate shall revert to the rate of 10.0% of the $25.00 per share stated liquidation preference per annum otherwise specified effective as of the day after the second balance sheet date and shall remain at 10.0% until a subsequent Financial Covenant Default shall occur.

Whenever a Listing Default (as defined herein) occurs, the Dividend Rate specified shall be increased to the Default Rate. The Default Rate shall remain in effect until the Series A Preferred Stock is listed on a National Exchange, at which time the Dividend Rate shall revert to the rate of 10.0% of the $25.00 per share stated liquidation preference per annum otherwise specified for the next occurring dividend payment period and shall remain at 10.0% until a subsequent Listing Default shall occur.

Financial Covenant

We are required to have an Asset Coverage Ratio (as defined below) of 2-to-1 or greater as of the date of any issuance of additional debt (excluding any borrowings under the Credit Facility or any revolving credit facility in replacement thereof), Series A Preferred Stock, Senior Stock or Parity Stock.

“Asset Coverage Ratio” means the ratio, determined on a consolidated basis, without duplication, in accordance with generally accepted accounting principles, of (a) total assets less goodwill, intellectual property and other intangible assets but excluding intangible drilling costs, divided by (b) the sum of total debt plus the aggregate liquidation preference of Series A Preferred Stock, Senior Stock and Parity Stock then outstanding, less cash, cash equivalents and marketable securities. The Asset Coverage Ratio shall be calculated based on our balance sheet for the most recent fiscal period then ended that has been filed with the SEC on a pro forma basis after giving effect to (i) the issuance of such additional debt (excluding any borrowings under the Credit Facility or any revolving credit facility in replacement thereof), Series A Preferred Stock, Senior Stock or Parity Stock and (ii) the application of the proceeds from the issuance of such additional debt (excluding any borrowings under the Credit Facility or any revolving credit facility in replacement thereof), Series A Preferred Stock, Senior Stock or Parity Stock. Notwithstanding the classification of the Series A Preferred Stock on our balance sheet, the Series A Preferred Stock shall not be deemed debt for purposes of the Asset Coverage Ratio.

For purposes of this determination, no shares of Series A Preferred Stock, if any, will be deemed to be outstanding for purposes of the computation of the Asset Coverage Ratio if, prior to or concurrently with such determination, sufficient funds to pay the full redemption price for such Series A Preferred Stock (or the portion thereof to be redeemed) will have been deposited in trust with the paying agent for such Series A Preferred Stock and the requisite notice of redemption for such Series A Preferred Stock (or the portion thereof to be redeemed) will have been given or other sufficient funds (in accordance with the terms of such Series A Preferred Stock) to pay the full redemption price for such Series A Preferred Stock (or the portion thereof to be redeemed) will have been segregated by us and the Transfer Agent from our assets, by means of appropriate identification on the Transfer Agent’s books and records or otherwise in accordance with the Transfer Agent’s normal procedures. In such event, the sufficient funds so deposited or segregated will not be included as our assets for purposes of the computation of the Asset Coverage Ratio.

Listing Covenant

Our certificate of formation requires us to list the Series A Preferred Stock on a National Exchange prior to April 30, 2014. Because we are currently in default pursuant to this listing requirement, the Dividend Rate specified was increased by one-half percent on May 1, 2014 and shall be increased by one-half percent per quarter, up to a rate not to exceed the Default Rate, until such listing occurs at which time the Dividend Rate shall revert to the rate of 10.0% until a subsequent Listing Default occurs. We have applied to list the Series A Preferred Stock on the NASDAQ Capital Market concurrently with the consummation of this offering, at which time the Dividend Rate will revert to 10.0%.

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Liquidation Preference

In the event of our voluntary or involuntary liquidation, dissolution or winding up, then, before any distribution or payment shall be made to or set apart for the holders of any Junior Stock, the holders of Series A Preferred Stock shall be entitled to receive out of our assets legally available for distribution to shareholders, liquidating distributions in the amount of the liquidation preference, or $25.00 per share, plus an amount equal to all dividends (whether or not declared) accrued and unpaid thereon to and including the date of payment. In the event that, upon any such voluntary or involuntary liquidation, dissolution or winding up, our available assets or proceeds thereof are insufficient to pay in full the amount of the liquidating distributions on all outstanding shares of Series A Preferred Stock and the corresponding amounts payable on all Senior Stock and Parity Stock, then after payment of the liquidating distribution on all outstanding Senior Stock, the holders of the Series A Preferred Stock and all other such classes or series of Parity Stock shall share ratably in any such distribution of assets in proportion to the full liquidating distributions to which they would otherwise be respectively entitled. After payment of the full amount of the liquidating distributions to which they are entitled, the holders of Series A Preferred Stock will have no right or claim to any of our remaining assets.

For purposes hereof, none of (i) the consolidation or merger of us with one or more corporations or other entities, (ii) a sale, lease or transfer of all or substantially all of our assets, or (iii) a statutory share exchange shall be deemed to constitute a voluntary or involuntary liquidation, dissolution or winding up of us (although such events may give rise to a “Change of Control” as described below).

Our certificate of formation does not contain any provision requiring funds to be set aside to protect the liquidation preference of the Series A Preferred Stock.

Redemption

Mandatory Redemption. The Series A Preferred Stock is subject to a mandatory redemption by the Company on July 15, 2018, for $25.00 per share, plus accrued and unpaid dividends.

Optional Redemption. The Series A Preferred Stock is currently redeemable, in whole or in part, at our option, at any time or from time to time, for cash at the redemption prices (expressed as percentages of the liquidation preference) set forth in the following table plus accrued and unpaid dividends, if any, if redeemed during the twelve month period commencing on the dates set forth below:

Redemption Dates	Redemption Prices (expressed as  percentage of liquidation preference)
July 15, 2014	105%
July 15, 2015	103%
July 15, 2016 and thereafter	100%

If we elect to redeem any shares of Series A Preferred Stock as described above, we may use any available cash legally available under Texas law to pay the redemption price, and we will not be required to pay the redemption price only out of the proceeds from the issuance of other equity securities or any other specific source.

Redemption Upon a Change of Control

Upon the occurrence of a Change of Control (as defined below), provided the terms and provisions of any agreement of ours, including agreements related to our indebtedness do not prohibit it, we will be required to redeem the Series A Preferred Stock within 120 days after the first date on which such Change of Control occurs, for cash at a redemption price of $25.00 per share, plus any accrued and unpaid dividends. If we redeem any shares of the Series A Preferred Stock as described in this paragraph, we may use any available cash legally

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available under Texas law to pay the redemption price, and we will not be required to pay the redemption price only out of the proceeds from the issuance of other equity securities or any other specific source.

A “Change of Control” is deemed to occur when, after the original issuance of the Series A Preferred Stock, the following has occurred and is continuing: (i) the acquisition by any person, including any syndicate or group deemed to be a “person” under Section 13(d)(3) of the Exchange Act of beneficial ownership, directly or indirectly, through a purchase, merger or other acquisition transaction or series of purchases, mergers or other acquisition transactions of our stock entitling that person to exercise more than 50% of the total voting power of all our stock entitled to vote generally in the election of our directors (except that such person will be deemed to have beneficial ownership of all securities that such person has the right to acquire, whether such right is currently exercisable or is exercisable only upon the occurrence of a subsequent condition) and (ii) following the closing of any transaction referred to in (i) above, neither we nor the acquiring or surviving entity has a class of common securities (or American Depositary Receipts representing such securities) listed on a National Exchange; provided, that a merger effected to change our jurisdiction of incorporation shall not be deemed a Change of Control.

Redemption Procedures

Notice of redemption will be mailed at least 30 days but not more than 60 days before the redemption date to each holder of record of Series A Preferred Stock at the address shown on our share transfer books. Each notice shall state: (i) the redemption date, (ii) the number of shares of Series A Preferred Stock to be redeemed, (iii) the redemption price per share of Series A Preferred Stock, plus any accrued and unpaid dividends to but not including the date of redemption, (iv) the place or places where any certificates issued for Series A Preferred Stock other than through the DTC book-entry described below, are to be surrendered for payment of the redemption price, (v) that dividends on the Series A Preferred Stock will cease to accrue on such redemption date, and (vi) any other information required by law or by the applicable rules of any exchange upon which the Series A Preferred Stock may be listed or admitted for trading. If fewer than all outstanding shares of Series A Preferred Stock are to be redeemed, the notice mailed to each such holder thereof shall also specify the number of shares of Series A Preferred Stock to be redeemed from each such holder.

At our election, on or prior to the redemption date, we may irrevocably deposit the redemption price (including accrued and unpaid dividends) of the Series A Preferred Stock so called for redemption in trust for the holders thereof with a bank or trust company as provided in our certificate of formation, in which case the notice to holders of the Series A Preferred Stock will (i) state the date of such deposit, (ii) specify the office of such bank or trust company as the place of payment of the redemption price, and (iii) require such holders to surrender any certificates issued for Series A Preferred Stock other than through the DTC book-entry described below at such place on or about the date fixed in such redemption notice (which may not be later than such redemption date) against payment of the redemption price (including all accrued and unpaid dividends to the redemption date). Any interest or other earnings earned on the redemption price (including all accrued and unpaid dividends) deposited with a bank or trust company will be paid to us. Any monies so deposited that remain unclaimed by the holders of the Series A Preferred Stock at the end of one year after the redemption date will be returned to us by such bank or trust company. If we make such a deposit, shares of the Series A Preferred Stock shall not be considered outstanding for purposes of voting or determining shares entitled to vote on any matter on or after the date of such deposit and the term of office of any director elected by the Series A Preferred Stock shall immediately terminate.

All shares of Series A Preferred Stock issued and redeemed by us shall be restored to the status of undesignated, authorized shares of preferred stock.

If we redeem the Series A Preferred Stock and if the redemption date occurs after a dividend record date and on or prior to the related dividend payment date, the dividend payable on such dividend payment date with respect to such shares called for redemption shall be payable on such dividend payment date to the holders of

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record at the close of business on such dividend record date, and shall not be payable as part of the redemption price for such shares.

Voting Rights

Except as indicated below or under Texas law, the holders of the Series A Preferred Stock will have no voting rights.

In the event of a Dividend Default or Listing Default, the number of directors then constituting our board of directors will be increased, and the holders of the Series A Preferred Stock, voting together as a single class with the holders of any other series of Parity Stock upon which like voting rights have been conferred and are exercisable (any such other series, the “voting preferred stock”), will have the right to elect two directors, in the case of a Dividend Default, or one director, in the case of a Listing Default, in addition to those directors then serving on the board of directors at an annual meeting of shareholders or a properly called special meeting of the holders of the Series A Preferred Stock and such voting preferred stock and at each subsequent annual meeting of shareholders until such right to elect directors shall cease, as described below. In no event will holders of the Series A Preferred Stock be entitled to elect more than two directors under the above default provisions, regardless of whether there is both a Dividend Default and a Listing Default.

After (i) we have paid all accrued but unpaid dividends on the Series A Preferred Stock, and timely paid in full the accrued dividends for the two subsequent quarterly dividend payment periods or (ii) any Listing Default is cured, as applicable, then the right of the holders of the Series A Preferred Stock to elect the additional directors will cease, the terms of office of the directors will forthwith terminate and the number of directors constituting our board of directors will be reduced accordingly. However, the right of the holders of the Series A Preferred Stock to elect additional directors will again vest if and whenever there is a subsequent Dividend Default or Listing Default, as described above.

The approval of two-thirds of the votes entitled to be cast by the holders of outstanding Series A Preferred Stock, voting separately as a class, either at a meeting of shareholders or by written consent, is required in order:

(i) to amend, alter or repeal any provisions of our certificate of formation or our bylaws if such change would affect materially and adversely the rights, preferences or voting powers of the holders of the Series A Preferred Stock;

(ii) to effect a statutory share exchange that affects the Series A Preferred Stock, or to merge or consolidate with another entity, unless (x) we are the surviving entity and the Series A Preferred Stock remains outstanding with no material and adverse change to its terms, voting powers, preferences and rights, or (y) the resulting surviving entity or transferee entity is organized under the laws of any state and the Series A Preferred Stock is substituted or exchanged for other preferred equity or shares of the surviving entity having preferences, conversion and other rights, voting powers, restrictions, limitations as to dividends or distributions, qualifications and terms or conditions of redemption thereof substantially similar to that of a share of Series A Preferred Stock (except for changes that do not materially and adversely affect the Series A Preferred Stock); or

(iii) to authorize, reclassify, create, issue or increase the authorized amount of any shares of any class or any security convertible or exchangeable for Senior Stock.

For purposes of the voting requirements in subsection (i) above, neither of the following shall be deemed to materially and adversely affect the rights, preferences or voting powers of the Series A Preferred Stock or voting preferred stock:

(i) an amendment to the provisions of our certificate of formation so as to authorize or create, or to increase the authorized amount of, any Junior Stock or any Parity Stock, including additional shares of Series A Preferred Stock; or

(ii) an amendment to the provisions of our certificate of formation to effectuate a reverse stock split.

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The above voting rights of the Series A Preferred Stock will not apply if, at or before the time when the act with respect to which the vote would otherwise be required is effected, such outstanding shares of Series A Preferred Stock are subject to a notice of redemption pursuant to the provisions described above under “—Redemption” and funds sufficient to pay the applicable redemption price, including accrued and unpaid dividends, for all of such shares of Series A Preferred Stock called for redemption have been deposited with a bank or trust company, as described under “—Redemption—Redemption Procedures.”

When the Series A Preferred Stock is entitled to vote, such shares are entitled to one vote per share. In any matter in which the Series A Preferred Stock may vote as a single class with any other series of our preferred stock (as described in the certificate of formation or as may be required by law), each share of Series A Preferred Stock shall be entitled to one vote per $25.00 of stated liquidation preference.

However, we may create additional series or classes of Parity Stock and Junior Stock, increase the authorized number of shares of Parity Stock (including the Series A Preferred Stock) and Junior Stock and issue additional series of Parity Stock and Junior Stock without the consent of any holder of the Series A Preferred Stock.

No Exchange or Conversion Rights; No Sinking Fund

Shares of the Series A Preferred Stock are not exchangeable or convertible into any other class or series of our capital stock or other securities or property. The Series A Preferred Stock is not subject to the operation of a purchase, retirement or sinking fund.

No Preemptive Rights

Holders of the Series A Preferred Stock have no preemptive right to acquire shares of any class or series of our capital stock.

Information Rights

During any period in which we are not subject to Section 13 or 15(d) of the Exchange Act and any shares of Series A Preferred Stock are outstanding, we will: (i) transmit by mail to all holders of Series A Preferred Stock, as their names and addresses appear in our record books, and without cost to such holders, copies of the annual reports and quarterly reports that we would have been required to file with the SEC pursuant to Section 13 or 15(d) of the Exchange Act if we were subject to such sections (other than any exhibits that would have been required); and (ii) promptly upon written request, supply copies of such reports to any prospective holder of Series A Preferred Stock. We will mail the reports to the holders of Series A Preferred Stock within fifteen days after the respective dates by which we would have been required to file the reports with the SEC if we were subject to Section 13 or 15(d) of the Exchange Act, assuming we are a “non-accelerated” filer in accordance with the Exchange Act.

Book-Entry Procedures

The Depository Trust Company (“DTC”) will act as securities depositary for the Series A Preferred Stock. We will issue one or more fully registered global securities certificates in the name of DTC’s nominee, Cede & Co. These certificates will represent the total aggregate number of shares of Series A Preferred Stock. We will deposit these certificates with DTC or a custodian appointed by DTC. We will not issue certificates to you for shares of Series A Preferred Stock that you purchase, unless DTC’s services are discontinued as described below.

Title to book-entry interests in the Series A Preferred Stock will pass by book-entry registration of the transfer within the records of DTC, as the case may be, in accordance with their respective procedures. Book-entry interests in the securities may be transferred within DTC in accordance with procedures established for these purposes by DTC.

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Each person owning a beneficial interest in the Series A Preferred Stock must rely on the procedures of DTC and the participant through which such person owns its interest to exercise its rights as a holder of the Series A Preferred Stock.

DTC has advised us that it is a limited-purpose trust company organized under the New York Banking Law, a member of the Federal Reserve System, a “clearing corporation” within the meaning of the New York Uniform Commercial Code, and a “clearing agency” registered under the provisions of Section 17A of the Exchange Act. DTC holds securities that its participants, referred to as Direct Participants, deposit with DTC. DTC also facilitates the settlement among Direct Participants of securities transactions, such as transfers and pledges, in deposited securities through electronic computerized book-entry changes in Direct Participants’ accounts, thereby eliminating the need for physical movement of securities certificates. Direct Participants include securities brokers and dealers, banks, trust companies, clearing corporations, and certain other organizations. DTC is owned by a number of its Direct Participants and by the New York Stock Exchange, Inc., the NYSE MKT, and the Financial Industry Regulatory Authority, Inc. Access to the DTC system is also available to others such as securities brokers and dealers, banks and trust companies that clear through or maintain a custodial relationship with a Direct Participant, either directly or indirectly, referred to as “Indirect Participants.” The rules applicable to DTC and its Direct and Indirect Participants are on file with the SEC.

When you purchase the Series A Preferred Stock within the DTC system, the purchase must be made by or through a Direct Participant. The Direct Participant will receive a credit for the Series A Preferred Stock on DTC’s records. You, as the actual owner of the Series A Preferred Stock, are the “beneficial owner.” Your beneficial ownership interest will be recorded on the Direct and Indirect Participants’ records, but DTC will have no knowledge of your individual ownership. DTC’s records reflect only the identity of the Direct Participants to whose accounts Series A Preferred Stock are credited.

You will not receive written confirmation from DTC of your purchase. The Direct or Indirect Participants through whom you purchased the Series A Preferred Stock should send you written confirmations providing details of your transactions, as well as periodic statements of your holdings. The Direct and Indirect Participants are responsible for keeping an accurate account of the holdings of their customers like you.

Transfers of ownership interests held through Direct and Indirect Participants will be accomplished by entries on the books of Direct and Indirect Participants acting on behalf of the beneficial owners.

The laws of some states may require that specified purchasers of securities take physical delivery of the Series A Preferred Stock in definitive form. These laws may impair the ability to transfer beneficial interests in the global certificates representing the Series A Preferred Stock.

Conveyance of notices and other communications by DTC to Direct Participants, by Direct Participants to Indirect Participants, and by Direct Participants and Indirect Participants to beneficial owners will be governed by arrangements among them, subject to any statutory or regulatory requirements as may be in effect from time to time.

We understand that, under DTC’s existing practices, in the event that we request any action of holders, or an owner of a beneficial interest in a global security such as you desires to take any action which a holder is entitled to take under our certificate of formation, as amended or supplemented, DTC would authorize the Direct Participants holding the relevant shares to take such action, and those Direct Participants and any Indirect Participants would authorize beneficial owners owning through those Direct and Indirect Participants to take such action or would otherwise act upon the instructions of beneficial owners owning through them.

Redemption notices will be sent to Cede & Co. If less than all of the outstanding shares of Series A Preferred Stock are being redeemed, DTC will reduce each Direct Participant’s holdings of Series A Preferred Stock in accordance with its procedures.

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In those instances where a vote is required, neither DTC nor Cede & Co. itself will consent or vote with respect to the Series A Preferred Stock. Under its usual procedures, DTC would mail an omnibus proxy to us as soon as possible after the record date. The omnibus proxy assigns Cede & Co.’s consenting or voting rights to those Direct Participants to whose accounts the Series A Preferred Stock is credited on the record date, which are identified in a listing attached to the omnibus proxy.

Dividends on the Series A Preferred Stock will be paid directly to DTC. DTC’s practice is to credit participants’ accounts on the relevant payment date in accordance with their respective holdings shown on DTC’s records unless DTC has reason to believe that it will not receive payment on that payment date.

Payments by Direct and Indirect Participants to beneficial owners such as you will be governed by standing instructions and customary practices, as is the case with securities held for the accounts of customers in bearer form or registered in “street name.” These payments will be the responsibility of the participant and not of DTC, us or any agent of ours.

DTC may discontinue providing its services as securities depositary with respect to the Series A Preferred Stock at any time by giving us reasonable notice. Additionally, we may decide to discontinue the book-entry only system of transfers with respect to the Series A Preferred Stock. In that event, we will print and deliver certificates in fully registered form for the Series A Preferred Stock. If DTC notifies us that it is unwilling to continue as securities depositary, or if it is unable to continue or ceases to be a clearing agency registered under the Exchange Act and we do not appoint a successor depositary within 90 days after receiving such notice or becoming aware that DTC is no longer so registered, we will issue the Series A Preferred Stock in definitive form, at our expense, upon registration of transfer of, or in exchange for, such global security.

According to DTC, the foregoing information with respect to DTC has been provided to the financial community for informational purposes only and is not intended to serve as a representation, warranty or contract modification of any kind.

Initial settlement for the Series A Preferred Stock will be made in immediately available funds. Secondary market trading between DTC’s participants will occur in the ordinary way in accordance with DTC’s rules and will be settled in immediately available funds using DTC’s Same-Day Funds Settlement System.

Direct Registration System

The Series A Preferred Stock is registered in book-entry form through the Direct Registration System (the “DRS”). The DRS is a system administered by DTC pursuant to which the depositary may register the ownership of uncertificated shares, which ownership shall be evidenced by periodic statements issued by the depositary to the Series A Preferred Stock holders entitled thereto. This direct registration form of ownership allows investors to have securities registered in their names without requiring the issuance of a physical stock certificate, eliminates the need for you to safeguard and store certificates and permits the electronic transfer of securities to effect transactions without transferring physical certificates.

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MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES

The following discussion summarizes the material U.S. federal income tax consequences that may be applicable to “U.S. holders” and “non-U.S. holders” (each as defined below) with respect to the purchase, ownership, and disposition of the Series A Preferred Stock offered by this prospectus supplement. This discussion only applies to purchasers who purchase and hold the Series A Preferred Stock as capital assets within the meaning of Section 1221 of the Internal Revenue Code of 1986, as amended (the “Code”) (generally property held for investment). This discussion does not describe all of the tax consequences that may be relevant to each purchaser or holder of Series A Preferred Stock in light of its particular circumstances.

This discussion is based upon provisions of the Code, Treasury regulations, rulings and judicial decisions as of the date hereof. These authorities may change, perhaps retroactively, or may be subject to different interpretations which could result in U.S. federal income tax consequences different from those summarized below. We cannot assure you that the Internal Revenue Service (“IRS”) will not challenge one or more of the tax consequences described in this discussion, and we have not obtained, nor do we intend to obtain, a ruling from the IRS with respect to the U.S. federal tax consequences of acquiring, holding or disposing of the Series A Preferred Stock. This discussion does not address all aspects of U.S. federal income taxes (such as the alternative minimum tax) and does not describe any foreign, state, local or other tax considerations that may be relevant to a purchaser or holder of Series A Preferred Stock in light of their particular circumstances. In addition, this discussion does not describe the U.S. federal income tax consequences applicable to a purchaser or a holder of Series A Preferred Stock, who is subject to special treatment under U.S. federal income tax laws (including, a corporation that accumulates earnings to avoid U.S. federal income tax, a pass-through entity or an investor in a pass-through entity, a tax-exempt entity, pension or other employee benefit plans, financial institutions or broker-dealers, persons holding Series A Preferred Stock as part of a hedging or conversion transaction or straddle, a person subject to the alternative minimum tax, an insurance company, former U.S. citizens, or former long-term U.S. residents). We cannot assure you that a change in law will not significantly alter the tax considerations that we describe in this discussion.

If a partnership (or any other entity treated as a partnership for U.S. federal income tax purposes) holds Series A Preferred Stock, the U.S. federal income tax treatment of a partner of that partnership generally will depend upon the status of the partner and the activities of the partnership. If you are a partnership or a partner of a partnership holding the Series A Preferred Stock, you should consult your tax advisors as to the particular U.S. federal income tax consequences of holding and disposing of the Series A Preferred Stock.

For purposes of this discussion, a “U.S. holder” is a beneficial owner of our Series A Preferred Stock, that is:

• an individual citizen or resident of the United States;

• a corporation (or other entity treated as a corporation for U.S. federal income tax purposes) created or organized in or under the laws of the United States, any state thereof or the District of Columbia;

• an estate the income of which is subject to U.S. federal income taxation regardless of its source; or

• a trust if it (a) is subject to the primary supervision of a court within the United States and one or more United States persons have the authority to control all substantial decisions of the trust or (b) has a valid election in effect under applicable United States Treasury regulations to be treated as a United States person.

The term “non-U.S. holder” means a beneficial owner of our Series A Preferred Stock that is not a U.S. holder.

THIS DISCUSSION IS PROVIDED FOR GENERAL INFORMATION ONLY AND DOES NOT CONSTITUTE LEGAL ADVICE TO ANY PROSPECTIVE PURCHASER OR HOLDER OF OUR SERIES A PREFERRED STOCK. ADDITIONALLY, THIS DISCUSSION CANNOT BE USED BY ANY

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HOLDER FOR THE PURPOSE OF AVOIDING FEDERAL TAX PENALTIES THAT MAY BE IMPOSED ON SUCH HOLDER. IF YOU ARE CONSIDERING THE PURCHASE OF OUR SERIES A PREFERRED STOCK, YOU SHOULD CONSULT YOUR OWN TAX ADVISORS CONCERNING THE U.S. FEDERAL INCOME TAX CONSEQUENCES OF PURCHASING, OWNING AND DISPOSING OF OUR SERIES A PREFERRED STOCK IN LIGHT OF YOUR PARTICULAR CIRCUMSTANCES AND ANY CONSEQUENCES ARISING UNDER THE LAWS OF APPLICABLE STATE, LOCAL OR FOREIGN TAXING JURISDICTIONS. YOU SHOULD ALSO CONSULT WITH YOUR TAX ADVISORS CONCERNING ANY POSSIBLE ENACTMENT OF LEGISLATION THAT WOULD AFFECT YOUR INVESTMENT IN OUR SERIES A PREFERRED STOCK IN YOUR PARTICULAR CIRCUMSTANCES.

U.S. Holders

Subject to the qualifications set forth above, the following discussion summarizes the material U.S. federal income tax consequences of the purchase, ownership and disposition of the Series A Preferred Stock by “U.S. holders.”

Distributions in General. In general, if distributions are made with respect to the Series A Preferred Stock, such distributions will be treated as dividends to the extent of our current and accumulated earnings and profits as determined under the Code. Any portion of a distribution that exceeds our current and accumulated earnings and profits will first be applied to reduce a U.S. holder’s tax basis in the Series A Preferred Stock, and the excess will be treated as gain from the disposition of the Series A Preferred Stock, the tax treatment of which is discussed below under “U.S. holder: Disposition of Series A Preferred Stock, Including Redemptions.” As of the date of this prospectus supplement, we do not believe we have any accumulated earnings and profits for U.S. federal income tax purposes. Additionally, we may not have sufficient current earnings and profits during future fiscal years for the distributions on the Series A Preferred Stock to qualify as dividends for U.S. federal income tax purposes.

Distributions treated as dividends that are received by individual holders of Series A Preferred Stock currently will be subject to a reduced maximum tax rate of 20% if such dividends are treated as “qualified dividend income” for U.S. federal income tax purposes. The rate reduction does not apply to dividends received to the extent that the individual stockholder elects to treat the dividends as “investment income,” which may be offset against investment expenses. Furthermore, the rate reduction does not apply to dividends that are paid to individual stockholders with respect to the Series A Preferred Stock that are held for 60 days or less during the 121-day period beginning on the date which is 60 days before the date on which the Series A Preferred Stock become ex-dividend. Individual stockholders should consult their own tax advisors regarding the implications of these rules in light of their particular circumstances.

Distributions treated as dividends that are received by corporations generally will be eligible for the dividends-received deduction. Generally, this deduction is allowed if the underlying stock is held for at least 46 days during the 91 day period beginning on the date 45 days before the ex-dividend date of the stock, and for cumulative preferred securities with an arrearage of dividends, the holding period is at least 91 days during the 181 day period beginning on the date 90 days before the ex-dividend date of the stock. Each domestic corporate holder of Series A Preferred Stock is urged to consult with its tax advisors with respect to the eligibility for and amount of any dividends received deduction.

Constructive Distributions on Series A Preferred Stock. A distribution by a corporation of its stock deemed made with respect to its preferred stock is generally treated as a distribution of property to which Section 301 of the Code applies. If a corporation issues preferred stock that may be redeemed at a price higher than its issue price, the excess (a “redemption premium”) is treated under certain circumstances as a constructive distribution (or series of constructive distributions) of additional preferred stock.

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The constructive distribution of property equal to the redemption premium would accrue without regard to the holder’s method of accounting for U.S. federal income tax purposes at a constant yield determined under principles similar to the determination of original issue discount (“OID”) under Treasury regulations under Sections 1271 through 1275 of the Code (the “OID Rules”). Under those rules, the constructive distributions of property would be treated for U.S. federal income tax purposes as actual distributions of the Series A Preferred Stock that would constitute a dividend, return of capital or capital gain to the holder of the stock in the same manner as cash distributions described under “Material U.S. Federal Income Tax Considerations—U.S. Holders: Distributions in General.” The actual application of principles similar to those applicable to debt instruments with OID to a redemption premium for the Series A Preferred Stock is uncertain, and each investor is encouraged to review this matter with his or her tax advisor.

We have the right to call the Series A Preferred Stock for redemption on or after July 15, 2014 (the “call option”), and are required to redeem the Series A Preferred Stock upon any Change of Control (the “contingent call obligation”). We are also required to redeem all of the shares of Series A Preferred Stock outstanding on July 15, 2018 (the “mandatory redemption obligation”). The stated redemption price of the Series A Preferred Stock upon any redemption pursuant to our contingent call obligation or mandatory redemption obligation is equal to the liquidation preference of the Series A Preferred Stock (i.e., $25.00, plus accrued and unpaid dividends) and is payable in cash. The stated redemption price of the Series A Preferred Stock upon any redemption pursuant to our call option is a percentage of the liquidation preference of the Series A Preferred Stock ranging from 100% to 105% of the liquidation preference and is also payable in cash.

If the redemption price of the Series A Preferred Stock exceeds the issue price of the Series A Preferred Stock, the excess may be treated as a redemption premium that may result in certain circumstances in a constructive distribution or series of constructive distributions to U.S. holders of additional Series A Preferred Stock.

A redemption premium for the Series A Preferred Stock should not result in constructive distributions to U.S. holders of the Series A Preferred Stock if the redemption premium is less than a de minimis amount as determined under principles similar to the OID Rules. A redemption premium for the Series A Preferred Stock should be considered de minimis if such premium is less than ..0025 of the Series A Preferred Stock’s redemption price, multiplied by the number of complete years to maturity. Because the determination under the OID Rules of a maturity date for the Series A Preferred Stock is unclear, the remainder of this discussion assumes that the Series A Preferred Stock is issued with a redemption premium greater than a de minimis amount with respect to the call option and the contingent call obligation. However, we believe that the redemption premium for the Series A Preferred Stock should be considered de minimis with respect to the mandatory redemption obligation.

The call option should not require constructive distributions of the redemption premium, if based on all of the facts and circumstances as of the issue date, a redemption pursuant to the call option is not more likely than not to occur. The Treasury regulations provide that an issuer’s right to redeem will not be treated as more likely than not to occur if: (i) the issuer and the holder of the stock are not related within the meaning of Section 267(b) or Section 707(b) of the Code (substituting “20%” for the phrase “50%”); (ii) there are no plans, arrangements, or agreements that effectively require or are intended to compel the issuer to redeem the stock; and (iii) exercise of the right to redeem would not reduce the yield on the stock determined using principles applicable to the determination of OID under the OID rules. The fact that a redemption right is not within the safe harbor described in the preceding sentence does not mean that an issuer’s right to redeem is more likely than not to occur and the issuer’s right to redeem must still be tested under all the facts and circumstances to determine if it is more likely than not to occur. We do not believe that a redemption pursuant to the call option should be treated as more likely than not to occur under the foregoing test or that such a redemption would reduce the yield of the Series A Preferred Stock. Accordingly, we believe that no unrelated U.S. holder of the Series A Preferred Stock should be required to recognize constructive distributions of the redemption premium because of our call option.

Also, under the Treasury regulations, a constructive distribution would be required if we are obligated to redeem the Series A Preferred Stock at a “specified time” unless such obligation is subject to a contingency that

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is beyond the legal or practical control of the holder or holders as a group and that, based on all of the facts and circumstances as of the issue date, renders remote the likelihood of redemption. We believe that our contingent call obligation to redeem the Series A Preferred Stock upon a Change of Control is beyond the legal or practical control of the holder or holders of the Series A Preferred Stock. In addition, the Series A Preferred Stock generally does not possess voting rights except in the limited circumstances described in the certificate of formation or as otherwise required under Texas law. We do not believe, however, that the holders of the Series A Preferred Stock by reason of holding such stock possess the power or authority to require a Change of Control. Accordingly, we believe that no U.S. holder of the Series A Preferred Stock should be required to recognize constructive distributions of the redemption premium because of our contingent call obligation.

Prospective purchasers of the Series A Preferred Stock should consult their own tax advisors regarding the potential implications of these rules.

Disposition of Series A Preferred Stock, Including Redemptions. Upon any sale, exchange, redemption (except as discussed below), or other disposition of the Series A Preferred Stock, a U.S. holder generally will recognize capital gain or loss equal to the difference between the amount realized by the U.S. holder on any sale, exchange, redemption (except as discussed below), or other disposition, and the U.S. holder’s adjusted tax basis in the Series A Preferred Stock. Such capital gain or loss will be long-term capital gain or loss if the U.S. holder’s holding period for the Series A Preferred Stock is longer than one year. A U.S. holder should consult its own tax advisors with respect to applicable tax rates and netting rules for capital gains and losses. Certain limitations exist on the deduction of capital losses by both corporate and non-corporate taxpayers.

A redemption of shares of the Series A Preferred Stock will generally be a taxable event. If the redemption is treated as a sale or exchange, instead of a dividend, a U.S. holder generally will recognize capital gain or loss (which will be long-term capital gain or loss, if the U.S. holder’s holding period for such Series A Preferred Stock exceeds one year at the time of the redemption), equal to the difference between the amount realized by the U.S. holder and the U.S. holder’s adjusted tax basis in the Series A Preferred Stock redeemed, except to the extent that any cash received is attributable to any accrued but unpaid dividends on the Series A Preferred Stock, which generally will be subject to the rules discussed above in “—Distributions in General.” A payment made in redemption of Series A Preferred Stock may be treated as a dividend, rather than as payment in exchange for the Series A Preferred Stock, unless the redemption:

• is “not essentially equivalent to a dividend” with respect to a U.S. holder under Section 302(b)(1) of the Code;

• is a “substantially disproportionate” redemption with respect to a U.S. holder under Section 302(b)(2) of the Code;

• results in a “complete redemption” of a U.S. holder’s stock interest in us under Section 302(b)(3) of the Code; or

• is a redemption of stock held by a non-corporate shareholder, where such redemption results in a partial liquidation of our company under Section 302(b)(4) of the Code.

In determining whether any of these tests has been met, a U.S. holder must take into account not only shares of Series A Preferred Stock and our common stock that the U.S. holder actually owns, but also shares that the U.S. holder constructively owns within the meaning of Section 318 of the Code.

A redemption payment will be treated as “not essentially equivalent to a dividend” if it results in a “meaningful reduction” in a U.S. holder’s aggregate stock interest in our company, which will depend on the U.S. holder’s particular facts and circumstances at such time.

Satisfaction of the “complete redemption” and “substantially disproportionate” exceptions is dependent upon compliance with the objective tests set forth in Section 302(b)(3) and Section 302(b)(2) of the Code. A

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redemption will result in a “complete redemption” if either all of our stock actually and constructively owned by a U.S. holder is redeemed or all of our stock actually owned by the U.S. holder is redeemed and the U.S. holder is eligible to waive, and the U.S. holder effectively waives, the attribution of our stock constructively owned by the U.S. holder in accordance with the procedures described in Section 302(c)(2) of Code. A redemption does not qualify for the “substantially disproportionate” exception if the stock redeemed is only non-voting stock, and for this purpose, stock which does not have voting rights until the occurrence of an event is not voting stock until the occurrence of the specified event. Accordingly, any redemption of Series A Preferred Stock will likely not qualify for this exception because the voting rights are limited as provided in the “Description of Series A Preferred Stock—Voting Rights.”

For purposes of the “redemption from non-corporate shareholders in a partial liquidation” test, a distribution will be treated as in partial liquidation of a corporation if the distribution is not essentially equivalent to a dividend (determined at the corporate level rather than the shareholder level) and the distribution is pursuant to a plan and occurs within the taxable year in which the plan was adopted or within the succeeding taxable year. For these purposes, a distribution is generally not essentially equivalent to a dividend if the distribution results in a corporate contraction. The determination of what constitutes a corporate contraction is generally factual in nature and has been interpreted under case law to include the termination of a business or line of businesses.

If none of the foregoing tests result in sale or exchange treatment upon redemption, and instead a redemption payment is treated as a dividend distribution, the rules discussed above in “—Distributions in General” apply.

Because of the factual nature of the foregoing tests, each U.S. holder of Series A Preferred Stock should consult its own tax advisors to determine whether a payment made in redemption of Series A Preferred Stock will be treated as a dividend or as payment in exchange for the Series A Preferred Stock.

Corporate Dividends Received Deduction. Dividends paid or deemed paid by a corporation to corporate investors are generally eligible for the corporate dividends received deduction under Section 243 of the Code (the “Dividends Received Deduction”). For U.S. federal income tax purposes, a dividend is a distribution that is paid with respect to a corporation’s stock out of the corporation’s earnings and profits for the corporation’s taxable year (computed at the close of the corporation’s taxable year without any diminution by reason of any distributions made during the taxable year) plus accumulated earnings and profits. The calculation of a corporation’s earnings and profits generally starts with a company’s net earnings; however numerous adjustments are required under the Code and Treasury regulations in order to determine the earnings and profits amount to determine if a dividend has been paid for federal income tax purposes.

As discussed above in “—U.S. holders—Distributions in General,” if a corporation makes a distribution with respect to the Series A Preferred Stock, or is deemed to have made such a distribution, to a U.S. holder in any year when the amount distributed exceeds the distributing corporation’s current and accumulated earnings and profits balance, the excess amount paid to the U.S. holder will first reduce the U.S. holder’s basis in the Series A Preferred Stock until such basis equals zero and then produce capital gain to the extent that the amount distributed exceeds the U.S. holder’s basis in such stock.

Although corporate distributions that reduce tax basis are generally received tax free, the reduced basis could produce capital gains when the Series A Preferred Stock is disposed of, possibly equal to the reduction in tax basis. Any such capital gain recognized at that time could be taxed to a U.S. holder that is a corporation, absent offsetting capital losses, at a current maximum U.S. federal income tax rate of 35%. Similarly, if any corporate distributions exceed the basis of U.S. holder that is a corporation in its Series A Preferred Stock, any capital gain produced, absent offsetting capital losses, would be currently taxable at a maximum U.S. federal income tax rate of 35% even though such Series A Preferred Stock is not sold. The Dividends Received Deduction would not be applicable to either situation because capital gains are not dividends since they are not paid out of earnings and profits.

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As of the date of this prospectus supplement, we do not believe we have any accumulated earnings and profits for U.S. federal income tax purposes. Additionally, we may not have sufficient current earnings and profits during future years for the distributions on the Series A Preferred Stock to qualify as dividends for U.S. federal income tax purposes. Each U.S. holder of Series A Preferred Stock that is a corporation should consult its own tax advisors to determine the availability of the Dividends Received Deduction and the potential tax consequences of its unavailability with respect to distributions received with respect to Series A Preferred Stock or dispositions of Series A Preferred Stock.

Information Reporting and Backup Withholding. Information reporting and backup withholding may apply with respect to payments of dividends on the Series A Preferred Stock and to certain payments of proceeds on the sale or other disposition of the Series A Preferred Stock. Certain non-corporate U.S. holders may be subject to U.S. backup withholding (currently at a rate of 28%) on payments of dividends on the Series A Preferred Stock and certain payments of proceeds on the sale or other disposition of the Series A Preferred Stock unless the beneficial owner of such Series A Preferred Stock furnishes the payor or its agent with a taxpayer identification number, certified under penalties of perjury, and certain other information, or otherwise establishes, in the manner prescribed by law, an exemption from backup withholding.

U.S. backup withholding tax is not an additional tax. Any amounts withheld under the backup withholding rules may be allowed as a refund or a credit against a U.S. holder’s U.S. federal income tax liability, which may entitle the U.S. holder to a refund, provided the U.S. holder timely furnishes the required information to the IRS.

Non-U.S. Holders

Subject to the qualifications set forth above under the caption “Material U.S. Federal Income Tax Consequences,” the following discussion summarizes the material U.S. federal income tax consequences of the purchase, ownership and disposition of the Series A Preferred Stock by certain “non-U.S. holders” (as defined below).

Distributions on the Series A Preferred Stock. In general, if distributions are made with respect to the Series A Preferred Stock, such distributions will be treated as dividends to the extent of our current and accumulated earnings and profits as determined under the Code and will be subject to withholding as discussed below. Any portion of a distribution that exceeds our current and accumulated earnings and profits will first be applied to reduce the non-U.S. holder’s basis in the Series A Preferred Stock and, to the extent such portion exceeds the non-U.S. holder’s basis, the excess will be treated as gain from the disposition of the Series A Preferred Stock, the tax treatment of which is discussed below under “Non-U.S. holder: Disposition of Series A Preferred Stock, Including Redemptions.” As of the date of this prospectus supplement, we do not believe that we have any accumulated earnings and profits for U.S. federal income tax purposes. Additionally, we may not have sufficient current earnings and profits during future fiscal years for the distributions on the Series A Preferred Stock to qualify as dividends for U.S. federal income tax purposes. In addition, if we are a U.S. real property holding corporation, or a “USRPHC,” which we believe that we are, and any distribution exceeds our current and accumulated earnings and profits, we will need to choose to satisfy our withholding requirements either by treating the entire distribution as a dividend, subject to the withholding rules in the following paragraph (and withhold at a minimum rate of 10% or such lower rate as may be specified by an applicable income tax treaty for distributions from a USRPHC), or by treating only the amount of the distribution equal to our reasonable estimate of our current and accumulated earnings and profits as a dividend, subject to the withholding rules in the following paragraph, with the excess portion of the distribution subject to withholding at a rate of 10% or such lower rate as may be specified by an applicable income tax treaty as if such excess were the result of a sale of shares in a USRPHC (discussed below under “Non-U.S. holder: Disposition of Series A Preferred Stock, Including Redemptions”), with a credit generally allowed against the non-U.S. holder’s U.S. federal income tax liability in an amount equal to the amount withheld from such excess.

Dividends paid to a non-U.S. holder of the Series A Preferred Stock will generally be subject to withholding of U.S. federal income tax at a 30% rate or such lower rate as may be specified by an applicable income tax

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treaty. But, dividends that are effectively connected with the conduct of a trade or business by the non-U.S. holder within the United States (and, where a tax treaty applies, are attributable to a permanent establishment maintained by the non-U.S. holder in the United States) are not subject to the withholding tax, provided certain certification and disclosure requirements are satisfied, including by providing a properly executed IRSForm W-8ECI (or other applicable form). Instead, such dividends will be subject to U.S. federal income tax on a net income basis in the same manner as if the non-U.S. holder were a United States person as defined under the Code, unless an applicable income tax treaty provides otherwise. Any such effectively connected dividends received by a foreign corporation may be subject to an additional “branch profits tax” at a 30% rate or such lower rate as may be specified by an applicable income tax treaty.

A non-U.S. holder of the Series A Preferred Stock who wishes to claim the benefit of an applicable treaty rate and avoid backup withholding, as discussed below, for dividends will be required to (a) complete IRS Form W-8BEN (or other applicable form) and certify under penalty of perjury that such holder is not a United States person as defined under the Code and is eligible for treaty benefits, or (b) if the Series A Preferred Stock are held through certain foreign intermediaries, satisfy the relevant certification requirements of applicable Treasury regulations.

A non-U.S. holder of the Series A Preferred Stock eligible for a reduced rate of U.S. withholding tax pursuant to an income tax treaty may obtain a refund of any excess amounts withheld by timely filing an appropriate claim for refund with the IRS.

Disposition of Series A Preferred Stock, Including Redemptions. Any gain realized by a non-U.S. holder on the disposition of the Series A Preferred Stock will generally not be subject to U.S. federal income or withholding tax unless:

• the gain is effectively connected with a trade or business of the non-U.S. holder in the United States (and, if required by an applicable income tax treaty, is attributable to a permanent establishment maintained by the non-U.S. holder in the United States);

• the non-U.S. holder is an individual who is present in the United States for 183 days or more in the taxable year of that disposition, and certain other conditions are met; or

• we are or have been a “U.S. real property holding corporation,” or a USRPHC, for United States federal income tax purposes.

A non-U.S. holder described in the first bullet point immediately above will generally be subject to tax on the net gain derived from the sale under regular graduated U.S. federal income tax rates in the same manner as if the non-U.S. holder were a United States person as defined under the Code, and if it is a corporation, may be subject to the branch profits tax equal to 30% of its effectively connected earnings and profits or at such lower rate as may be specified by an applicable income tax treaty. An individual non-U.S. holder described in the second bullet point immediately above will be subject to a flat 30% tax (unless an applicable income tax treaty provides for a lower rate) on the gain derived from the sale, which may be offset by U.S. source capital losses, even though the individual is not considered a resident of the United States.

With respect to the third bullet point above, a corporation is a USRPHC if the fair market value of its “U.S. real property interests,” as defined in the Code and applicable Treasury regulations, equals or exceeds 50% of the sum of the fair market value of its worldwide real property interests and its other assets used or held for use in a trade or business. We believe that we are a USRPHC. However, gain on the sale or other disposition of a class of stock of a USRPHC that is “regularly traded” on an established securities market will be subject to U.S. federal income tax only in the case of a holder that owns more than 5% of the total fair market value of that class of stock at any time during the five-year period ending on the date of disposition. No assurance can be given that Series A Preferred Stock will be considered regularly traded when a non-U.S. holder sells its Series A Preferred Stock. Non-U.S. holders that may be treated as actually or constructively owning more than 5% of our Series A

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Preferred Stock should consult their own tax advisors with respect to the U.S. federal income tax consequences of the ownership and disposition of Series A Preferred Stock.

If a non-U.S. holder is subject to regular U.S. federal income tax upon any sale, exchange, redemption (except as discussed below), or other disposition of the Series A Preferred Stock, such a non-U.S. holder will recognize capital gain or loss equal to the difference between the amount realized by the non-U.S. holder on any sale, exchange, redemption (except as discussed below), or other disposition, and the non-U.S. holder’s adjusted tax basis in the Series A Preferred Stock. Such capital gain or loss will be long-term capital gain or loss if the non-U.S. holder’s holding period for the Series A Preferred Stock is longer than one year. A non-U.S. holder should consult its own tax advisors with respect to applicable tax rates and netting rules for capital gains and losses. Certain limitations exist on the deduction of capital losses by both corporate and non-corporate taxpayers.

A redemption of shares of Series A Preferred Stock will generally be a taxable event. If the redemption is treated as a sale or exchange, instead of a dividend, a non-U.S. holder generally will recognize capital gain or loss (either short or long term capital gain or loss, as discussed above) equal to the difference between the amount of cash received and fair market value of property received and the non-U.S. holder’s adjusted tax basis in the Series A Preferred Stock redeemed, except that to the extent that any cash received is attributable to any accrued but unpaid dividends on the Series A Preferred Stock, which generally will be subject to the rules discussed above in “—Distributions on the Series A Preferred Stock, Including Redemptions.” A payment made in redemption of Series A Preferred Stock may be treated as a dividend, rather than as payment in exchange for the Series A Preferred Stock, in the same circumstances discussed above under “U.S. holder—Disposition of Series A Preferred Stock, Including Redemptions.” Each non-U.S. holder of Series A Preferred Stock should consult its own tax advisors to determine whether a payment made in redemption of Series A Preferred Stock will be treated as a dividend or as payment in exchange for the Series A Preferred Stock.

Information Reporting and Backup Withholding. We must report annually to the IRS and to each non-U.S. holder the amount of dividends paid to such non-U.S. holder and the tax withheld with respect to such dividends, regardless of whether withholding was required. Copies of the information returns reporting such dividends and withholding may also be made available to the tax authorities in the country in which the non-U.S. holder resides under the provisions of an applicable income tax treaty.

A non-U.S. holder will not be subject to backup withholding on dividends paid to such non-U.S. holder as long as such non-U.S. holder certifies under penalty of perjury that it is a non-U.S. holder (and the payor does not have actual knowledge or reason to know that such non-U.S. holder is a United States person as defined under the Code), or such non-U.S. holder otherwise establishes an exemption.

Depending on the circumstances, information reporting and backup withholding may apply to the proceeds received from a sale or other disposition of the Series A Preferred Stock, unless the beneficial owner certifies under penalty of perjury that it is a non-U.S. holder (and the payor does not have actual knowledge or reason to know that the beneficial owner is a United States person as defined under the Code), or such owner otherwise establishes an exemption.

U.S. backup withholding tax is not an additional tax. Any amounts withheld under the backup withholding rules may be allowed as a refund or a credit against a non-U.S. holder’s U.S. federal income tax liability provided the required information is timely furnished to the IRS.

PROSPECTIVE PURCHASERS OF SERIES A PREFERRED STOCK SHOULD SEEK ADVICE BASED ON THEIR PARTICULAR CIRCUMSTANCES FROM AN INDEPENDENT TAX ADVISOR.

Medicare Tax

In addition to the above described income taxes, a 3.8% Medicare tax is imposed on the “net investment income” of certain United States citizens and resident aliens, and on the undistributed “net investment income”

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of certain estates and trusts. Among other items, “net investment income” would generally include dividends on our Series A Preferred Stock and common stock and net gain from the sale, taxable exchange, redemption, retirement or other taxable disposition of our Series A Preferred Stock, less certain deductions. Individual stockholders should consult their own tax advisors regarding the implications of these rules in light of their particular circumstances.

Foreign Account Tax Compliance Act

Sections 1471 through 1474 of the Code (provisions which are commonly referred to as “FATCA”), recently released final regulations thereunder, and administrative guidance will generally impose a 30% withholding tax on dividends on Series A Preferred Stock paid on or after July 1, 2014 and the gross proceeds of a sale or other disposition of Series A Preferred Stock paid on or after January 1, 2017 to: (i) a foreign financial institution (as that term is defined in Section 1471(d)(4) of the Code) unless that foreign financial institution enters into an agreement with the U.S. Treasury Department to collect and disclose information regarding U.S. account holders of that foreign financial institution (including certain account holders that are foreign entities that have U.S. owners) and satisfies other requirements; and (ii) specified other foreign entities unless such an entity certifies that it does not have any substantial U.S. owners or provides the name, address and taxpayer identification number of each substantial U.S. owner and such entity satisfies other specified requirements. Non-U.S. holders should consult their own tax advisors regarding the application of FATCA to them and whether it may be relevant to their purchase, ownership and disposition Series A Preferred Stock.

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UNDERWRITING

Under the terms and subject to the conditions contained in an underwriting agreement between us and Northland Securities, Inc., as representative of the underwriters, with respect to the shares of Series A Preferred Stock subject to this offering, we have agreed to sell to the underwriters, and the underwriters have severally agreed to purchase, the number shares provided below opposite their names.

Underwriters	Number of Shares (1)
Northland Capital Markets
Euro Pacific Capital Inc.
Total

(1) The underwriters may purchase up to an additional                 shares of Series A Preferred Stock to cover over-allotments, as described below.

The underwriters are offering the shares of Series A Preferred Stock subject to their acceptance of the shares from us and subject to prior sale. The underwriting agreement provides that the obligations of the several underwriters to pay for and accept delivery of the shares offered by this prospectus supplement are subject to the approval of certain legal matters by their counsel and to certain other conditions, including the approval of the Series A Preferred Stock for listing on the NASDAQ Capital Market. The underwriters are obligated to take and pay for all of the shares if any such shares are taken. The underwriters may, but are not obligated to, retain other selected dealers that are qualified to offer and sell the shares and that are members of the Financial Industry Regulatory Authority (“FINRA”).

Discounts, Commissions and Expenses

The underwriters have advised us that they propose to offer the shares of Series A Preferred Stock to the public at the public offering price set forth on the cover page of this prospectus supplement and to certain dealers at that price less a concession not in excess of $         per share. The underwriters may allow, and certain dealers may reallow, a discount from the concession not in excess of $         per share to certain brokers and dealers. After this offering, the public offering price, concession and reallowance to dealers may be changed by the underwriters. No such change shall change the amount of proceeds to be received by us as set forth on the cover page of this prospectus supplement. The shares are offered by the underwriters as stated herein, subject to receipt and acceptance by them and subject to their right to reject any order in whole or in part.

The underwriters initially propose to offer the shares of Series A Preferred Stock to investors at the public offering price set forth on the cover of this prospectus supplement. The underwriting discount is equal to the public offering price per share of Series A Preferred Stock less the amount paid by the underwriters to us per share of Series A Preferred Stock. There is no arrangement for funds to be received in escrow, trust or similar arrangement.

We have also agreed to pay the underwriters’ reasonable out-of-pocket expenses (including fees and expense of the underwriters’ counsel) incurred by the underwriters in connection with this offering up to $200,000. In addition, we estimate that our share of the total expenses of this offering, excluding underwriting discounts and commissions and payment of the underwriters’ expenses referred to above, will be approximately $350,000.

We also granted Northland Capital Markets a right of first refusal to serve as (at a minimum) co-lead orco-bookrunning manager in connection with future preferred equity financing transactions we undertake within one year following the effective date of this offering. In accordance with applicable rules of FINRA, Northland Capital Markets does not have more than one opportunity to waive or terminate the right of first refusal in consideration of any payment or fee, and any payment or fee to waive or terminate the right of first refusal must

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be paid in cash and have a value not in excess of the greater of 1% of the proceeds in this offering (or, if greater, the maximum amount permitted by FINRA rules for compensation in connection with this offering) or 5% of the underwriting discount or commission paid in connection with any future financing subject to right of first refusal (including any overallotment option that may be exercised). This right of first refusal is not reflected in the table below.

Except as disclosed in this prospectus supplement, the underwriter has not received and will not receive from us any other item of compensation or expense in connection with this offering considered by FINRA to be underwriting compensation under its rule of fair price.

The following table summarizes the compensation and estimated expenses we will pay. The amounts are shown assuming both no exercise and full exercise of the underwriters’ option to purchase an additional shares of Series A Preferred Stock.

		Total
	Per Share	No Exercise	Full Exercise
Public offering price	$	$	$
Underwriting discount paid by us	$	$	$
Proceeds, before expenses, to us	$	$	$

Over-allotment Option

We have granted the underwriters an over-allotment option. This option, which is exercisable for up to 45 days after the date of this prospectus supplement, permits the underwriters to purchase a maximum of             additional shares of Series A Preferred Stock from us to cover over-allotments. If the underwriters exercise all or part of this option, they will purchase the shares of Series A Preferred Stock covered by the option at the public offering price that appears on the cover page of this prospectus supplement, less the underwriting discount. If this option is exercised in full, the total price to the public will be $         million and the total proceeds to us will be $         million.

Indemnification of Underwriters

We will indemnify the underwriters against some civil liabilities, including liabilities under the Securities Act of 1933, as amended, and liabilities arising from breaches of our representations and warranties contained in the underwriting agreement. If we are unable to provide this indemnification, we will contribute to payments the underwriters may be required to make in respect of those liabilities.

No Sales of Series A Preferred Stock

The underwriters have required each of our directors and officers to agree not to offer, sell, agree to sell, directly or indirectly, or otherwise dispose of any shares of Series A Preferred Stock without the prior written consent of Northland Securities, Inc. for a period of 90 days after the date of the final prospectus supplement.

The restrictions described in the immediately preceding paragraph do not apply to certain items, including transfers as a bona fide gift or gifts, transfers by will or intestate succession, or to any trust for the direct or indirect benefit of the director or officer or his or her immediate family, provided that in each case any such recipient agrees to be bound by the terms of the restrictions described above.

We have agreed that for a period of 90 days after the date of the final prospectus supplement, we will not, without the prior written consent of Northland Securities, Inc., offer, sell or otherwise dispose of any shares of our Series A Preferred Stock.

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The 90-day restricted period in all of the agreements described above is subject to extension if (i) during the last 17 days of the restricted period we issue an earnings release or material news or a material event relating to us occurs or (ii) prior to the expiration of the restricted period, we announce that we will release earnings results during the 16-day period beginning on the last day of the lock-up period, in which case the restrictions imposed in these lock-up agreements shall continue to apply until the expiration of the 18-day period beginning on the issuance of the earnings release or the occurrence of the material news or material event, unless Northland Securities, Inc. waives the extension in writing.

Short Sales, Stabilizing Transactions and Penalty Bids

In order to facilitate this offering, persons participating in this offering may engage in transactions that stabilize, maintain, or otherwise affect the price of our Series A Preferred Stock during and after this offering. Specifically, the underwriters may engage in the following activities in accordance with the rules of the SEC.

Short sales. Short sales involve the sales by the underwriters of a greater number of shares than they are required to purchase in the offering. Covered short sales are short sales made in an amount not greater than the underwriters’ over-allotment option to purchase additional shares from us in this offering. The underwriters may close out any covered short position by either exercising their over-allotment option to purchase shares or purchasing shares in the open market. In determining the source of shares to close out the covered short position, the underwriters will consider, among other things, the price of shares available for purchase in the open market as compared to the price at which they may purchase shares through the over-allotment option. Naked short sales are any short sales in excess of such over-allotment option. The underwriters must close out any naked short position by purchasing shares in the open market. A naked short position is more likely to be created if the underwriters are concerned that there may be downward pressure on the price of the Series A Preferred Stock in the open market after pricing that could adversely affect investors who purchase in this offering.

Stabilizing transactions. The underwriters may make bids for or purchases of the shares for the purpose of pegging, fixing, or maintaining the price of the shares, so long as stabilizing bids do not exceed a specified maximum.

Penalty bids. If the underwriters purchase shares in the open market in a stabilizing transaction or syndicate covering transaction, they may reclaim a selling concession from the underwriters and selling group members who sold those shares as part of this offering. Stabilization and syndicate covering transactions may cause the price of the shares to be higher than it would be in the absence of these transactions. The imposition of a penalty bid might also have an effect on the price of the shares if it discourages presales of the shares.

The transactions above may occur on the NASDAQ Stock Market or otherwise. Neither we nor the underwriters make any representation or prediction as to the effect that the transactions described above may have on the price of the shares. If these transactions are commenced, they may be discontinued without notice at any time.

Additional Information

In the ordinary course of its business, the underwriters and their affiliates may actively trade or hold our securities for their own accounts or for the accounts of customers and, accordingly, may at any time hold long or short positions in our securities. The underwriters and their affiliates may in the future perform various financial advisory and investment banking services for us, for which they will receive customary fees and expense.

Northland Capital Markets is the trade name for certain capital markets and investment banking services of Northland Securities, Inc., member FINRA/SIPC.

This prospectus supplement may be made available on web sites maintained by the underwriters and the underwriters may distribute prospectuses electronically.

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Foreign Regulatory Restrictions on Purchase of the Series A Preferred Stock

No action may be taken in any jurisdiction other than the United States that would permit a public offering of the Series A Preferred Stock or the possession, circulation or distribution of this prospectus supplement in any jurisdiction where action for that purpose is required. Accordingly, the Series A Preferred Stock may not be offered or sold, directly or indirectly, and neither the prospectus supplement nor any other offering material or advertisements in connection with the Series A Preferred Stock may be distributed or published in or from any country or jurisdiction except under circumstances that will result in compliance with any applicable rules and regulations of any such country or jurisdiction.

If you purchase shares of Series A Preferred Stock offered by this prospectus supplement, you may be required to pay stamp taxes and other charges under the laws and practices of the country of purchase, in addition to the offering price listed on the cover page of this prospectus supplement.

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LEGAL MATTERS

Certain legal matters with respect to the securities offered hereby will be passed upon for us by Akin Gump Strauss Hauer & Feld, LLP, Dallas, Texas. The underwriters have been represented in connection with this offering by Faegre Baker Daniels LLP, Minneapolis, Minnesota.

EXPERTS

The consolidated financial statements as of May 31, 2013 and 2012 and for each of the years then ended have been incorporated herein by reference to our Annual Report on Form 10-K in reliance upon the report of Hein & Associates LLP, independent registered public accounting firm also incorporated herein by reference, and upon the authority of said firm as experts in accounting and auditing. The consolidated financial statements as of May 31, 2011 and for the year then ended have been incorporated herein by reference to our Annual Report on Form 10-K in reliance upon the report of L J Soldinger Associates, LLC, independent registered public accounting firm, also incorporated herein by reference, and upon the authority of said firm as experts in accounting and auditing. The consolidated financial statements of Cross Border as of December 31, 2013 and 2012 and for the years then ended have been incorporated herein by reference to our Current Report onForm 8-K/A filed with the SEC on August 7, 2014, in reliance upon the report of Darilek Butler & Associates, PLLC, independent registered public accounting firm, also incorporated herein by reference, and upon the authority of said firm as experts in accounting and auditing.

INDEPENDENT PETROLEUM ENGINEERS

Certain estimates of our oil and natural gas reserves that are set forth in or incorporated by reference in this prospectus supplement were based in part upon engineering reports prepared by independent petroleum engineers Cawley, Gillespie & Associates, Inc. These estimated are set forth in or incorporated by reference in this prospectus supplement in reliance upon the authority of said firm as experts in such matters.

WHERE YOU CAN FIND MORE INFORMATION

We file annual, quarterly and current reports, proxy statements and other information with the SEC. You can read these SEC filings, and this registration statement, over the Internet at the SEC’s website at www.sec.gov. You may also read and copy any document we file with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. You may also obtain copies of the documents at prescribed rates by writing to the SEC’s Public Reference Room at the address above. Please call the SEC at 1-800-SEC-0330 for further information on the operation of the SEC’s Public Reference Room.

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INCORPORATION OF CERTAIN INFORMATION BY REFERENCE

The SEC allows us to “incorporate by reference” certain information we have filed with them, which means that we can disclose important information to you by referring you to documents we have filed with the SEC. The information incorporated by reference is considered to be part of this prospectus. We incorporate by reference the documents listed below, excluding any disclosures therein that are furnished and not filed:

• Annual Report on Form 10-K for the fiscal year ended May 31, 2013, filed on September 13, 2013, as amended by Amendment No. 1 on Form 10-K/A filed on September 27, 2013;

• Quarterly Report on Form 10-Q for the fiscal quarter ended September 30, 2013, filed on November 18, 2013;

• Quarterly Report on Form 10-Q for the fiscal quarter ended December 31, 2013, filed on February 10, 2014;

• Quarterly Report on Form 10-Q for the fiscal quarter ended March 31, 2014, filed on May 12, 2013;

• Current Report on Form 8-K dated July 17, 2013, and filed on July 23, 2013;

• Current Report on Form 8-K dated July 19, 2013, and filed on July 25, 2013;

• Current Report on Form 8-K dated July 26, 2013, and filed on July 31, 2013;

• Current Report on Form 8-K dated August 16, 2013, and filed on August 19, 2013;

• Current Report on Form 8-K dated August 20, 2013, and filed on August 20, 2013;

• Current Report on Form 8-K dated August 22, 2013, and filed on August 26, 2013;

• Current Report on Form 8-K dated September 12, 2013, and filed on September 17, 2013;

• Current Report on Form 8-K dated October 3, 2013, and filed on October 9, 2013;

• Current Report on Form 8-K dated December 16, 2013, and filed on December 16, 2013;

• Current Report on Form 8-K dated December 20, 2013, and filed on December 20, 2013;

• Current Report on Form 8-K dated January 29, 2014, and filed on February 4, 2014;

• Current Report on Form 8-K dated March 21, 2014, and filed on March 26, 2014;

• Current Report on Form 8-K dated April 11, 2014, and filed on April 11, 2014;

• Current Report on Form 8-K dated May 12, 2014, and filed on May 13, 2014;

• Current Report on Form 8-K dated June 11, 2014, and filed on June 12, 2014;

• Current Report on Form 8-K/A dated January 28, 2013, and filed on August 7, 2014;

• Current Report on Form 8-K dated August 7, 2014, and filed on August 11, 2014; and

• The description of our Series A Preferred Stock, which is contained in our registration statement on Form 8-A/A filed with the SEC on February 20, 2014, as updated or amended in any amendment or report filed for such purpose.

In addition, all documents we subsequently file with the SEC pursuant to Sections 13(a), 13(c), 14 or 15(d) of the Exchange Act, after the initial filing of the registration statement related to this prospectus and prior to the termination of the offering of the securities described in this prospectus supplement, shall be deemed to be incorporated by reference herein and to be part of this prospectus supplement from the respective dates of filing such documents. Information contained in this prospectus supplement modifies or supersedes, as applicable, the information contained in earlier-dated documents incorporated by reference. Information contained in later-dated documents incorporated by reference will automatically supplement, modify or supersede, as applicable, the information contained in this prospectus supplement or in earlier-dated documents incorporated by reference.

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We will provide, upon written or oral request, to each person, including any beneficial owner, to whom a prospectus supplement is delivered, a copy of these filings (other than exhibits to such documents, unless such exhibits are specifically incorporated by reference in any such documents), at no cost. Any person requesting such information can contact us at the address and telephone phone number indicated below:

Red Mountain Resources, Inc.

2515 McKinney Avenue, Suite 900

Dallas, Texas 75201

Attention: Chief Executive Officer

Telephone (214) 871-0400

Our incorporated reports and other documents may be accessed at our website address:www.redmountainresources.com or by contacting the SEC as described below in “Where You Can Find More Information.”

The information contained on our website does not constitute a part of this prospectus supplement, and our website address supplied above is intended to be an inactive textual reference only and not an active hyperlink to our website.

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GLOSSARY OF OIL AND NATURAL GAS TERMS

The following are abbreviations and definitions of terms commonly used in the oil and natural gas industry and this prospectus supplement.

“Bbl” One stock tank barrel or 42 U.S. gallons liquid volume of oil or other liquid hydrocarbons.

“Boe” One barrel of oil equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of oil and 42 gallons of NGLs to one Bbl of oil.

“Boe/d” Boe per day.

“Btu” A British thermal unit is a measurement of the heat generating capacity of natural gas. One Btu is the heat required to raise the temperature of a one-pound mass of pure liquid water one degree Fahrenheit at the temperature at which water has its greatest density (39 degrees Fahrenheit).

“completion” The process of treating a drilled well followed by the installation of permanent equipment for the production of oil or natural gas, or in the case of a dry well, the reporting of abandonment to the appropriate agency.

“condensate” A mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

“developed acreage” The number of acres that are allocated or assignable to productive wells or wells capable of production.

“development costs” Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and natural gas. More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to:

• gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, natural gas lines, and power lines, to the extent necessary in developing the proved reserves;

• drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly;

• acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems; and

• provide improved recovery systems.

“development well” A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

“dry well” A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

“exploration costs” Costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing oil and natural gas reserves, including costs of drilling exploratory wells and exploratory-type stratigraphic test wells.

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“exploratory well” A well drilled for the purpose of discovering new reserves in unproven areas.

“field” An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.

“formation” A layer of rock which has distinct characteristics that differ from nearby rock.

“gross acres” The total acres in which a working interest is owned.

“Henry Hub” The pricing point for natural gas futures contracts traded on the NYMEX.

“horizontal well” A well that is drilled vertically to a certain depth and then drilled at a right angle within a specific interval.

“hydraulic fracturing” or “fracing” A process involving the injection of fluids, usually consisting mostly of water, but typically including small amounts of sand and other chemicals, in order to create fractures extending from the wellbore through the rock formation to enable oil or natural gas to move more easily through the rock pores to a production well.

“lease operating expenses” The expenses, usually recurring, which pay for operating the wells and equipment on a producing lease.

“MBbl” One thousand barrels of oil or other liquid hydrocarbons.

“MBoe” One thousand barrels of oil equivalent.

“Mcf” One thousand cubic feet of natural gas.

“Mcf/d” One thousand cubic feet of natural gas per day.

“MMBoe” One million barrels of oil equivalent.

“MMBtu” One million British thermal units.

“MMcf” One million cubic feet of natural gas.

“natural gas” Natural gas and NGLs.

“net acres” The sum of the fractional working interests owned in gross acres.

“net revenue interest” An owner’s interest in the revenues of a well after deducting proceeds allocated to royalty and overriding interests.

“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.

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“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

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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

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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.

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Prospectus

Red Mountain Resources, Inc.

$150,000,000

Common Stock

Preferred Stock

Warrants

Debt Securities

We may offer, from time to time, in one or more offerings at prices and on terms that will be determined at the time of any such offering, up to $150.0 million in aggregate initial offering price of common stock, preferred stock, warrants or debt securities, which may be offered separately, together or as units with any such other securities. We will provide the specific terms of any offering and the offered securities in supplements to this prospectus. Any prospectus supplement may also add, update or change information contained in this prospectus. This prospectus may not be used to sell securities unless accompanied by a prospectus supplement which will describe the method and the terms of the related offering. You should carefully read this prospectus, any prospectus supplement and the documents incorporated by reference before you make your investment decision.

We may sell our securities to or through agents, dealers or underwriters as designated from time to time, or through a combination of these methods. For additional information on the method of sales, you should refer to the section of this prospectus entitled “Plan of Distribution.” If any agents, dealers or underwriters are involved in the sale of our securities, the applicable prospectus supplement will set forth the names of the underwriters and any applicable commission or discounts. We may also sell securities directly to investors.

Our common stock is quoted on the OTCBB under the symbol “RDMP.” On January 16, 2013, the closing price of our common stock on the OTCBB was $0.85 per share.

Investing in our securities involves risks. You should carefully consider the “Risk Factors” referred to on page 3 of this prospectus, in any applicable prospectus supplement and the documents incorporated or deemed incorporated by reference in this prospectus before investing in our securities.

NEITHER THE SECURITIES AND EXCHANGE COMMISSION NOR ANY STATE SECURITIES COMMISSION HAS APPROVED OR DISAPPROVED OF THESE SECURITIES OR PASSED UPON THE ADEQUACY OR ACCURACY OF THIS PROSPECTUS. ANY REPRESENTATION TO THE CONTRARY IS A CRIMINAL OFFENSE.

The date of this prospectus is February 1, 2013.

TABLE OF CONTENTS

ABOUT THIS PROSPECTUS	1
RED MOUNTAIN RESOURCES, INC.	2
RISK FACTORS	3
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS	4
RATIO OF EARNINGS TO FIXED CHARGES	6
USE OF PROCEEDS	6
DESCRIPTION OF CAPITAL STOCK	7
DESCRIPTION OF WARRANTS	10
DESCRIPTION OF DEBT SECURITIES	11
PLAN OF DISTRIBUTION	22
LEGAL MATTERS	25
EXPERTS	25
INDEPENDENT PETROLEUM ENGINEERS	25
MATERIAL CHANGES	25
INCORPORATION OF CERTAIN INFORMATION BY REFERENCE	26
WHERE YOU CAN FIND MORE INFORMATION	28

You should rely only on the information contained or incorporated by reference in this prospectus and any accompanying prospectus supplement. We have not authorized any person to provide you with different information. This prospectus is not an offer to sell, nor is it an offer to buy, these securities in any state where the offer or sale is not permitted. The information in this prospectus is complete and accurate as of the date on the front cover, but the information may have changed since that date.

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ABOUT THIS PROSPECTUS

This prospectus is part of a registration statement that we filed with the Securities and Exchange Commission (the “SEC”) using a “shelf” registration process. Under this shelf registration process, we may, from time to time, sell any combination of the securities described in this prospectus, in one or more offerings up to a total dollar amount of $150.0 million. This prospectus provides you with a general description of the securities that we may offer. Each time we sell securities, we will provide a prospectus supplement containing specific information about the terms of that offering and the manner in which the securities will be offered, including the specific amounts, prices and terms of the securities offered. The prospectus supplement may also add, update or change information contained in this prospectus. Any statement that we make in this prospectus will be modified or superseded by any inconsistent statement made by us in a prospectus supplement. This prospectus may not be used to sell securities unless accompanied by a prospectus supplement which will describe the method and the terms of the related offering. You should carefully read both this prospectus and any prospectus supplement, together with the additional information that is incorporated or deemed incorporated by reference in this prospectus. See “Incorporation of Certain Information by Reference.”

You should assume that the information appearing in this prospectus and in any prospectus supplement is only accurate as of the date on its respective cover and that any information incorporated by reference is accurate only as of the date of the document incorporated by reference, unless we indicate otherwise. Our business, properties, financial condition, results of operations and prospects may have changed since those dates.

Unless the context requires otherwise, all references in this prospectus to “Red Mountain,” the “Company,” “we,” “our” and “us” refer to Red Mountain Resources, Inc. and its subsidiaries on a consolidated basis.

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RED MOUNTAIN RESOURCES, INC.

Red Mountain Resources, Inc. is a growth-oriented energy company engaged in the acquisition, development and exploration of oil and natural gas properties in established basins with demonstrable prolific producing zones. Currently, we have established acreage positions and production primarily in the Permian Basin of West Texas and Southeast New Mexico and the onshore Gulf Coast of Texas. Our focus is to grow production and reserves by acquiring and developing an inventory of long-life, low risk drilling opportunities in and around producing oil and natural gas properties.

Our principal executive office is located at 2515 McKinney Avenue, Suite 900, Dallas, Texas 75201. Our telephone number is (214) 871-0400. Our website address iswww.redmountainresources.com . Except for any documents that are incorporated by reference into this prospectus that may be accessed from our website, the information available on or through our website is not part of this prospectus.

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RISK FACTORS

An investment in our securities involves risks. Investors should carefully consider the risks and uncertainties and all other information contained or incorporated by reference in this prospectus, including the risks and uncertainties discussed under “Risk Factors” in our most recent Annual Report on Form 10-K and any subsequent Quarterly Reports on Form 10-Q or Current Reports on Form 8-K, and all other documents incorporated by reference into this prospectus, as updated by our subsequent filings under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), and the risk factors and other information contained in the applicable prospectus supplement.

Any of these risks and uncertainties could materially and adversely affect our business, results of operations and financial condition. The trading price of our common stock could decline due to the occurrence of any of these risks and uncertainties, and investors could lose all or part of their investment. In assessing these risks and uncertainties, investors should also refer to the information contained or incorporated by reference in our other filings with the SEC.

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

Certain statements contained in this prospectus are “forward-looking statements” and are prospective. Forward-looking statements include statements preceded by, followed by or that include the words “may,” “could,” “would,” “should,” “believe,” “expect,” “anticipate,” “plan,” “estimate,” “target,” “project,” “intend,” “understand,” or similar expressions and the negative of such words and expressions, although not all forward-looking statements contain such words or expressions.

Forward-looking statements are only predictions and are not guarantees of performance. These statements generally relate to our plans, objectives and expectations for future operations and are based on management’s current beliefs and assumptions, which in turn are based on its experience and its perception of historical trends, current conditions and expected future developments as well as other factors it believes are appropriate under the circumstances. Although we believe that the plans, objectives and expectations reflected in or suggested by the forward-looking statements are reasonable, there can be no assurance that actual results will not differ materially from those expressed or implied in such forward-looking statements. Forward-looking statements also involve risks and uncertainties. Many of these risks and uncertainties are beyond our ability to control or predict and could cause results to differ materially from the results discussed in such forward-looking statements. Such risks and uncertainties include, but are not limited to, the following:

• our ability to raise additional capital to fund future capital expenditures;

• our ability to generate sufficient cash flow from operations, borrowings or other sources to enable us to fully develop and produce our oil and natural gas properties;

• declines or volatility in the prices we receive for our oil and natural gas;

• general economic conditions, whether internationally, nationally or in the regional and local market areas in which we do business;

• risks associated with drilling, including completion risks, cost overruns and the drilling of non-economic wells or dry holes;

• uncertainties associated with estimates of proved oil and natural gas reserves;

• the presence or recoverability of estimated oil and natural gas reserves and the actual future production rates and associated costs;

• risks and liabilities associated with acquired companies and properties;

• risks related to integration of acquired companies and properties;

• potential defects in title to our properties;

• cost and availability of drilling rigs, equipment, supplies, personnel and oilfield services;

• geological concentration of our reserves;

• environmental or other governmental regulations, including legislation of hydraulic fracture stimulation;

• our ability to secure firm transportation for oil and natural gas we produce and to sell the oil and natural gas at market prices;

• exploration and development risks;

• management’s ability to execute our plans to meet our goals;

• our ability to retain key members of our management team;

• weather conditions;

• actions or inactions of third-party operators of our properties;

• costs and liabilities associated with environmental, health and safety laws;

• our ability to find and retain highly skilled personnel;

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• 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 our Annual Report on Form 10-K for the fiscal year ended May 31, 2012, and may be identified in our Quarterly Reports on Form 10-Q and our other filings with the SEC and/or press releases from time to time.

Forward-looking statements speak only as of the date hereof. All such forward-looking statements and any subsequent written and oral forward-looking statements attributable to us or any person acting on our behalf are expressly qualified in their entirety by the cautionary statements contained or referred to in this section and any other cautionary statements that may accompany such forward-looking statements. Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements.

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RATIO OF EARNINGS TO FIXED CHARGES

	Six Months Ended November 30, 2012			Fiscal Year Ended May 31,
				2012			2011		2010
Ratio of earnings to fixed charges(1)		(2	)		(2	)		13.3x		(3	)

(1) For purposes of calculating the ratio of earnings to fixed charges, “earnings” represents income (loss) before income taxes and before adjustment for income or loss from equity investees plus fixed charges. “Fixed charges” includes interest expense, capitalized interest and the portion of rental expense that management believes is representative of the interest component of rental expense.

(2) For these periods, earnings were insufficient to cover fixed charges. The amount of the coverage deficiencies were $6,947 and $12,432 for the six months ended November 30, 2012 and the fiscal year ended May 31, 2012.

(3) The Company commenced operations on June 1, 2010 with the purchase of two separate oil and natural gas fields. As a result, no ratio is presented for the fiscal year ended May 31, 2010 or prior periods.

USE OF PROCEEDS

Unless we indicate otherwise in the applicable prospectus supplement, we intend to use the net proceeds of the securities offered by this prospectus for general corporate purposes, which may include an increase in working capital, the repayment or refinancing of outstanding indebtedness and the acquisition of assets or businesses. We will set forth in the prospectus supplement our intended use for the net proceeds received from the sale of any securities.

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DESCRIPTION OF CAPITAL STOCK

The following summarizes the material terms of our capital stock. This summary does not purport to be complete and is qualified in its entirety by reference to our articles of incorporation and by-laws, which are filed as exhibits to the registration statement of which this prospectus forms a part, and by the applicable provisions of the Florida Business Corporation Act (the “Florida Act”).

Common Stock

Our articles of incorporation authorizes us to issue 500,000,000 shares of common stock, par value $0.00001 per share. As of December 31, 2012, we had approximately 100,752,650 shares of common stock outstanding. Our common stock is quoted on the OTCBB under the symbol “RDMP.”

Holders of common stock are entitled to one vote per share on each matter submitted to a vote at a meeting of our shareholders. Holders of our common stock are not entitled to cumulative voting rights. Subject to preferences that may be applicable to any preferred stock outstanding at the time, the holders of outstanding shares of common stock are entitled to receive ratably any dividends out of assets legally available as our board of directors may from time to time determine. Upon liquidation, dissolution or winding up of our Company, holders of our common stock are entitled to share ratably in all assets remaining after payment of liabilities and the liquidation preference of any then outstanding shares of preferred stock. Holders of our common stock have no preemptive or conversion rights or other subscription rights. There are no redemption or sinking fund provisions applicable to the common stock. All outstanding shares of common stock are fully paid and nonassessable.

Preferred Stock

Our articles of incorporation permit our board of directors to issue up to 100,000,000 shares of preferred stock, par value $0.0001 per share, and to establish by resolution one or more series of preferred stock and the powers, designations, preferences and participating, optional or other special rights of each series or classes of preferred stock, including the dividend rights, original issue price, conversion rights, voting rights, terms of redemption, liquidation preferences and sinking fund terms thereof, and the number of shares constituting any such series and the designation thereof and to increase or decrease the number of shares of such series subsequent to the issuance of shares of such series but not below the number of shares then outstanding. The issuance of preferred stock could decrease the amount of earnings and assets available for distribution to holders of our common stock, and may have the effect of delaying, deferring or preventing a change of control of us without further action by the stockholders and may adversely affect the voting and other rights of the holders of common stock. Preferred stock could have preferences over common stock with respect to liquidation rights or dividends. None of our preferred stock is currently outstanding.

Florida Anti-Takeover Provisions

Certain provisions of the Florida Act could make our acquisition by a third party or a similar change of control more difficult. The “control share” provision and the “affiliated transaction” provision are anti-takeover provisions under Florida law that apply to public corporations organized under Florida law, unless the corporation has elected to opt out of those provisions in its articles of incorporation or by-laws. We have elected to opt out of the “affiliated transaction” provision, but have not elected to opt out of the “control share” provision, although such provision may not be applicable to us or to a specific transaction if certain conditions are not met. The Florida Act contains a “control share” provision that, when applicable, generally prohibits the voting of shares in a publicly-held Florida corporation that are acquired in a “control share acquisition” unless the holders of a majority of the corporation’s voting shares (exclusive of shares held by officers of the corporation, inside directors, or the acquiring party) approve the granting of voting rights as to the shares acquired in the control share acquisition. A “control share acquisition” is defined as an acquisition that immediately thereafter entitles the acquiring party to vote in the election of directors within each of the following ranges of voting power: (i) one-fifth or more but less than one-third of such voting power, (ii) one-third or more but less than a majority of such voting power, and (iii) a majority or more of such voting power. However, the

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acquisition of a publicly-held Florida corporation’s shares is not deemed to be a control-share acquisition if it is either (i) approved by such corporation’s board of directors, or (ii) made pursuant to a merger agreement to which such Florida corporation is a party.

Director and Officer Indemnity

The Florida Act and our by-laws permit us to indemnify any person who was or is a party to any proceeding (other than an action by, or in the right of, the Company), by reason of the fact that such person is or was a director, officer, employee, or agent of the Company or is or was serving at the request of the Company as a director, officer, employee, or agent of another corporation, partnership, joint venture, trust, or other enterprise against liability incurred in connection with such proceeding, including any appeal thereof, if such person acted in good faith and in a manner he or she reasonably believed to be in, or not opposed to, the best interests of the Company, and, with respect to any criminal action or proceeding, had no reasonable cause to believe his or her conduct was unlawful.

In addition, the Florida Act and our by-laws permit us to indemnify any person, who was or is a party to any proceeding by or in the right of the Company to procure a judgment in its favor by reason of the fact that such person is or was a director, officer, employee, or agent of the Company or is or was serving at the request of the Company as a director, officer, employee, or agent of another corporation, partnership, joint venture, trust, or other enterprise, against expenses and amounts paid in settlement not exceeding, in the judgment of the board of directors, the estimated expense of litigating the proceeding to conclusion, actually and reasonably incurred in connection with the defense or settlement of such proceeding, including any appeal thereof. Such indemnification shall be authorized if such person acted in good faith and in a manner he or she reasonably believed to be in, or not opposed to, the best interests of the Company, except that no indemnification shall be made in respect of any claim, issue, or matter as to which such person shall have been adjudged to be liable unless, and only to the extent that, the court in which such proceeding was brought, or any other court of competent jurisdiction, shall determine upon application that, despite the adjudication of liability but in view of all circumstances of the case, such person is fairly and reasonably entitled to indemnity for such expenses which such court shall deem proper.

To the extent that a director, officer, employee, or agent of the Company has been successful on the merits or otherwise in defense of any proceeding referred to above, or in defense of any claim, issue, or matter therein, the Florida Act and our by-laws provide that such person shall be indemnified against expenses actually and reasonably incurred by such person in connection therewith.

The Florida Act and our by-laws permit us to pay expenses incurred by a director or officer in any suit in advance of the final disposition of such suit upon receipt of an undertaking by or on behalf of such person to repay such amount if it shall ultimately be determined that he or she is not entitled to be indemnified by the Company. The Florida Act and our by-laws prohibit indemnification or advancement of expenses if a final adjudication establishes that the actions of a director or officer constitute (i) a violation of criminal law, unless the person had reasonable cause to believe his or her conduct was lawful or had no reasonable cause to believe his or her conduct was unlawful, (ii) a transaction from which such person derived an improper personal benefit, (iii) willful misconduct or conscious disregard for the best interests of the Company in the case of a suit by the Company or in a derivative suit by a stockholder or in a suit by or in the right of a stockholder, or (iv) in the case of a director, a circumstance under which a director would be liable for improper distributions under Section 607.0834 of the Florida Act.

In accordance with our articles of incorporation, we shall, to the fullest extent permitted by the Florida Act, indemnify or advance expenses to any person made, or threatened to be made, a party to any action, suit or proceeding by reason of the fact that such person (i) is or was a director of the Company; (ii) is or was serving at the request of the Company as a director of another corporation, provided that such person is or was at the time a director of the Company; or (iii) is or was serving at the request of the Company as an officer of another corporation, provided that such person is or was at the time a director of the Company or a director of such other corporation, serving at the request of the Company. In addition, our articles of incorporation provide that, unless otherwise expressly prohibited by the Florida Act, and except as otherwise provided in the previous sentence, our

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board of directors shall have the sole and exclusive discretion, on such terms and conditions as it shall determine, to indemnify, or advance expenses to, any person made, or threatened to be made, a party to any action, suit, or proceeding by reason of the fact such person is or was an officer, employee or agent of the Company as an officer, employee or agent of another corporation, partnership, joint venture, trust or other enterprise.

A Florida company also is authorized to purchase and maintain liability insurance for its directors, officers, employees and agents.

The Company’s articles of incorporation and bylaws provide that the Company shall indemnify each of its directors and officers to the fullest extent permitted by law. The bylaws further provide that the indemnity will include advances for expenses and costs incurred by such director or officer related to any action in regard to which indemnity is permitted. In this regard, the Company has entered into separate indemnity agreements with each of its directors and officers to provide additional indemnification rights and protections to those persons. The Company maintains directors’ and officers’ liability insurance covering its directors and officers against expenses and liabilities arising from certain actions to which they may become subject by reason of having served in such role, including insurance for claims against these persons brought under securities laws. Such insurance is subject to the coverage amounts, exceptions, deductibles and other conditions set forth in the policy. There is no assurance that the Company will maintain liability insurance for its directors and officers.

Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers, or persons controlling the Company pursuant to the foregoing provisions, the Company has been informed that in the opinion of the SEC that such indemnification is against public policy as expressed in the Securities Act and is therefore unenforceable.

Registrar and Transfer Agent

The registrar and transfer agent for our common stock is Broadridge Corporate Issuer Solutions, Inc., located at 44 West Lancaster Avenue, Ardmore, Pennsylvania 19003, and its telephone number is (610) 649-7300.

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DESCRIPTION OF WARRANTS

The following description of the terms of warrants we may issue sets forth certain general terms and provisions of any warrants to which any prospectus supplement may relate. The particular terms of warrants offered by any prospectus supplement and the extent, if any, to which these general terms and provisions may apply to those warrants will be described in the prospectus supplement relating to the warrants. The applicable prospectus supplement may also state that any of the terms set forth in this description are inapplicable to such warrants. This description does not purport to be complete.

We may issue warrants, including warrants to purchase common stock, preferred stock and debt securities. Warrants may be issued independently or together with any such underlying warrant securities and may be attached to or separate from such underlying warrant securities. Each series of warrants will be issued under a separate warrant agreement to be entered into between us and a warrant agent. The warrant agent will act solely as our agent in connection with the warrants of such series and will not assume any obligation or relationship of agency for or with holders or beneficial owners of warrants.

We will describe in the applicable prospectus supplement, the specific terms of any warrants offered thereby, including:

• the title or designation of such warrants;

• the aggregate number of such warrants;

• the price or prices at which such warrants will be issued;

• the currency or currencies, including composite currencies or currency units, in which the exercise price of such warrants may be payable;

• the designation, aggregate principal amount and terms of the underlying warrant securities purchasable upon exercise of such warrants, and the procedures and conditions relating to the exercise of the warrants;

• the price at which the underlying warrant securities purchasable upon exercise of such warrants may be purchased;

• the date on which the right to exercise such warrants shall commence and the date on which such right shall expire;

• if applicable, whether such warrants will be issued in registered form or bearer form;

• if applicable, the minimum or maximum amount of such warrants which may be exercised at any one time;

• if applicable, the number, designation and terms of the underlying warrant securities issuable upon exercise of such warrants;

• if applicable, the currency or currencies, including composite currencies or currency units, in which any principal, premium, if any, or interest on the underlying warrant securities purchasable upon exercise of the warrant will be payable;

• if applicable, the date on and after which such warrants and the related underlying warrant securities will be separately transferable;

• if applicable, any anti-dilutive rights of such warrants;

• information with respect to book-entry procedures, if any;

• if applicable, a discussion of material U.S. federal income tax considerations applicable to the warrants; and

• any other terms of such warrants, including terms, procedures and limitations relating to the exchange and exercise of such warrants.

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DESCRIPTION OF DEBT SECURITIES

The following description sets forth some general terms and provisions of the debt securities to which any prospectus supplement may relate. The particular terms of the debt securities offered by any prospectus supplement and the extent, if any, to which such general terms and provisions may not apply to the debt securities so offered will be described in the prospectus supplement relating to such debt securities. If there are any differences between the prospectus supplement relating to a particular series of debt securities and this prospectus, the prospectus supplement will control with respect to such debt securities. For more information please refer to the applicable indenture. Capitalized terms used in this prospectus that are not defined will have the meanings given to them in these documents.

Any senior debt securities will be issued under a senior indenture to be entered into among us and the trustee named in the senior indenture, also referred to as the “senior trustee.” Any subordinated debt securities will be issued under a subordinated indenture to be entered into among us and the trustee named in the subordinated indenture, also referred to as the “subordinated trustee.” As used in this prospectus, the term “indentures” refers to both the senior indenture and the subordinated indenture, as applicable. The form of each indenture has been filed with the SEC as an exhibit to the registration statement of which this prospectus is a part. Both indentures will be qualified under the Trust Indenture Act of 1939, as amended. As used in this prospectus, the term “trustee” refers to either the senior trustee or the subordinated trustee, as applicable.

In this summary description of debt securities, all references to “we,” “us,” “our” and the “Company” refer solely to Red Mountain Resources, Inc. and not to any of its subsidiaries.

We currently conduct substantially all of our operations through our subsidiaries, and the holders of debt securities (whether senior debt securities or subordinated debt securities) will be effectively subordinated to the creditors of our subsidiaries.

The following summaries of some material provisions of the senior debt securities, the subordinated debt securities and the indentures are subject to, and qualified in their entirety by reference to, all the provisions of the indentures and any supplemental indenture applicable to a particular series of debt securities, including the definitions in this prospectus of some terms. Except as otherwise indicated, the terms of any senior indenture and subordinated indenture, as applicable, will be identical.

General

The indentures provide that debt securities in separate series may be issued from time to time without limitation as to aggregate principal amount. The particular terms of each series of debt securities will be established by or pursuant to a resolution of our board of directors and set forth in an officers’ certificate or established by a supplemental indenture. We will describe the particular terms of each series of debt securities in a prospectus supplement relating to that series.

In particular, each prospectus supplement will describe the following terms relating to a series of debt securities:

• the title and aggregate principal amount of the debt securities;

• in the case of any subordinated debt securities, any change from the subordinated indenture to the subordination provisions or the definition of senior indebtedness that applies to the debt securities of such series;

• whether the debt securities are senior debt securities or subordinated debt securities and the terms of subordination;

• any provisions granting special rights to you when a specified event occurs;

• any limit on the amount of debt securities that may be issued;

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• whether any of the debt securities will be issuable in whole or in part in temporary or permanent global form and, in such case, the identity for the depositary for such series and if in global form whether beneficial owners of interests in any such global security may exchange such interests for securities of such series, and the form of legend or legends that shall be borne by any such global security;

• the person to whom any interest payable on a debt security shall be payable, if other than the person in whose name that debt security is registered at the close of business on the regular record date for such payment;

• the manner in which any interest payable on a temporary global security on any interest payment date will be paid, if other than in the manner provided in the indenture;

• the maturity date(s) of the debt securities;

• the annual interest rate(s) (which may be fixed or variable) or the method for determining the rate(s) and the date(s) interest will begin to accrue on the debt securities, the date(s) interest will be payable, and the regular record date(s) for interest payment date(s) or the method for determining the record date(s);

• the place(s) where payments with respect to the debt securities shall be payable;

• the date, if any, after which, and the price(s) at which, the series of debt securities may, pursuant to any optional redemption provisions, be redeemed at our option, and other related terms and provisions;

• the date(s), if any, on which, and the price(s) at which, if applicable, we are obligated, pursuant to any mandatory sinking fund provisions or otherwise, to redeem, or at your option to purchase in whole or in part, the series of debt securities and other related terms and provisions;

• the denominations and currency in which the series of debt securities will be issued, if other than denominations of $1,000 and any integral multiple thereof;

• any mandatory or optional sinking fund or similar provisions respecting the debt securities;

• the currency or currency units in which payment of the principal of, premium, if any, and interest on the debt securities shall be payable;

• if the amount of payments of principal of (and premium, if any), and any interest on, the debt securities of the series may be determined with reference to any commodities, currencies or indices, values, rates or prices or any other index or formula, the manner in which such amounts shall be determined;

• if other than the entire principal amount, the portion of the principal amount of debt securities of the series which shall be payable upon declaration of acceleration of the maturity of a series of debt securities in case of an event of default under the indenture;

• any additional means of satisfaction and discharge, and any additional conditions to discharge, of the indenture;

• if the debt securities of the series are to be convertible into or exchangeable for our common stock (or cash in lieu thereof), preferred stock, other debt securities (including other debt securities issued under the indenture), warrants or any other securities at our or the holder of debt securities’ option or upon the occurrence of any condition or event, the terms and conditions for such conversion or exchange;

• whether and under what circumstances we will pay additional amounts on any debt securities held by a person who is not a United States person for tax or other regulatory purposes and whether we can redeem the debt securities rather than pay these additional amounts;

• any addition to, or modification or deletion of, any definition, any event of default or any covenant specified in the applicable indenture and supplemental indenture with respect to the debt securities;

• the terms and conditions, if any, pursuant to which the debt securities are secured; and

• any other terms of the debt securities.

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Further, each prospectus supplement will describe the supplemental indenture provisions that amend the indenture without the consent of the holders of debt securities where such amendment is not specifically permitted under the indenture without such consent; provided, however, that any such amendment (i) shall neither (a) apply to any debt security of any series created prior to the execution of such supplemental indenture nor (b) modify the rights of the holders of any such debt security or (ii) shall become effective only when there is no such debt security outstanding.

The debt securities may be issued as original issue discount securities as described in a prospectus supplement. An original issue discount security is a debt security, including any zero coupon debt security, which:

• is issued at a price lower than the amount payable upon its stated maturity; and

• provides that upon redemption or acceleration of the maturity, an amount less than the amount payable upon the stated maturity, shall become due and payable.

Material United States federal income tax considerations applicable to debt securities sold as an original issue discount security will be described in the applicable prospectus supplement. In addition, material United States federal income tax or other considerations applicable to any debt securities which are denominated in a currency or currency unit other than United States dollars may be described in the applicable prospectus supplement.

Unless otherwise specified in a supplemental indenture, under the indentures, we will have the ability, in addition to the ability to issue debt securities with terms different from those of debt securities previously issued, without your consent, to reopen a previous issue of a series of debt securities and issue additional debt securities of that series, unless such reopening was restricted when the series was created, in an aggregate principal amount determined by us. Additional debt securities of a particular series will have the same terms and conditions as outstanding debt securities of such series, except that the additional debt securities may have a different date of original issuance, offering price and first interest payment date, and, unless otherwise provided in the applicable prospectus supplement, will be consolidated with, and form a single series with, such outstanding debt securities.

Conversion or Exchange of Rights

The terms, if any, on which a series of debt securities may be convertible into or exchangeable for our common stock, preferred stock, other debt securities or warrants will be detailed in the prospectus supplement relating thereto. Such terms will include provisions as to whether conversion or exchange is mandatory, at your option, or at our option, and may include provisions pursuant to which the number of shares of common stock or preferred stock, other debt securities or warrants to be received by you and other holders of such series of debt securities would be subject to adjustment.

No Protection in the Event of Change of Control

The indentures do not have any covenants or other provisions providing for a put or increased interest or otherwise that would afford holders of debt securities additional protection in the event of a recapitalization transaction, a change of control of the Company, or a highly leveraged transaction. If we offer any covenants or provisions of this type with respect to any debt securities covered by this prospectus, we will describe them in the applicable prospectus supplement.

Covenants

Unless otherwise indicated in this prospectus or a prospectus supplement, the debt securities will not have the benefit of any covenants that limit or restrict our business or operations, the pledging of our assets or the incurrence by us of indebtedness. We will describe in the applicable prospectus supplement any material covenants in respect of a series of debt securities.

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Consolidation, Merger or Sale

Unless otherwise specified in the prospectus supplement, we may not merge, consolidate or amalgamate with or into any other person, or sell, transfer, assign, lease, convey or otherwise dispose of all or substantially all of our assets to, any person (a “successor Person”), unless:

• the successor Person (if not us) is a corporation, partnership, trust or other entity organized and validly existing under the laws of any domestic jurisdiction and assumes our obligations on the debt securities and under the indentures;

• immediately before and after giving pro forma effect to the transaction, no event of default, and no event which, after notice or lapse of time or both, would become an event of default, has occurred and is continuing; and

• other conditions, including any additional conditions with respect to any particular debt securities specified in the applicable prospectus supplement, are met.

The successor Person (if not us) will be substituted for us under the applicable indenture with the same effect as if it had been an original party to such indenture, and, except in the case of a lease, we will be relieved from any further obligations under such indenture and the debt securities.

Events of Default under the Indentures

Unless otherwise specified in a supplemental indenture, an event of default typically will occur under the indentures with respect to any series of debt securities issued upon:

• failure to pay interest and any additional amounts (other than principal and premium, if any) on the debt securities when due if such failure continues for 30 consecutive days and the time for payment has not been extended or deferred;

• failure to pay the principal or premium of the debt securities, if any, when due;

• failure to deposit any sinking fund payment, when due, for any debt security if such failure continues for 30 days and in the case of the subordinated indenture, whether or not the deposit is prohibited by the subordination provisions;

• failure to observe or perform any other covenant contained in the debt securities or the indentures other than a covenant specifically relating to another series of debt securities, if such failure continues for 90 days after we receive notice from a trustee or holders of at least 25% in aggregate principal amount of the outstanding debt securities of that series;

• if the debt securities are convertible into common stock, preferred stock, other debt securities or warrants, failure by us to deliver common stock or the other securities when you and other holders of the debt securities elect to convert the debt securities into common stock or other securities; and

• particular events of bankruptcy, insolvency, or reorganization.

The supplemental indentures or the form of security for a particular series of debt securities may include additional events of default or changes to the events of default described above. For any additional or different events of default applicable to a particular series of debt securities, see the prospectus supplement relating to such series.

Subject to the provisions of the supplemental indentures, an event of default for a particular series of debt securities may, but does not necessarily, constitute an event of default for any other series of debt securities.

Unless otherwise specified in a supplemental indenture, if an event of default with respect to debt securities of any series occurs and is continuing, the trustee or the holders of at least 25% in aggregate principal amount of the outstanding debt securities of that series, by notice in writing to us and to the trustee if notice is given by such holders, may declare the unpaid principal, premium, if any, and accrued interest, if any, due and payable immediately.

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Subject to the provisions of the supplemental indentures, the holders of a majority in principal amount of the outstanding debt securities of an affected series may waive any default or event of default with respect to such series and its consequences, except defaults or events of default regarding payment of principal, premium, if any, or interest on, or any additional amounts with respect to, the debt securities. Any such waiver shall cure such default or event of default.

Subject to the provisions of the supplemental indentures, in the case of any series of subordinated debt securities, the amounts collected by a trustee from us as a result of an event of default must first be applied towards any amounts due to the trustee and then to the payment of any senior series of debt securities before being paid to holders of such series of subordinated debt securities.

Subject to the terms of the supplemental indentures, if an event of default under an indenture shall occur and be continuing, the trustee named in such indenture will be under no obligation to exercise any of its rights or powers under such indenture at your request or direction or that of any other holders of the applicable series of debt securities, unless you or such holders have offered the trustee indemnity reasonably satisfactory to it. The holders of a majority in principal amount of the outstanding debt securities of any series will have the right to direct the time, method and place of conducting any proceeding for any remedy available to the trustee, or exercising any trust or power conferred on the trustee, with respect to the debt securities of that series, provided that:

• it is not in conflict with any law or the applicable indenture;

• the trustee may take any other action deemed proper by it which is not inconsistent with such direction;

• such holders have offered the trustee indemnity reasonably satisfactory to it against the reasonable costs, expenses and liabilities to be incurred in compliance with such direction; and

• subject to its duties under the Trust Indenture Act of 1939, as amended, the trustee need not take any action that might involve it in personal liability or might be unduly prejudicial to the holders not involved in the proceeding.

Subject to the terms of the supplemental indentures, as a holder of the debt securities of any series, you will only have the right to institute a proceeding or to appoint a receiver or trustee, or to seek other remedies if:

• you have given written notice to the trustee of a continuing event of default with respect to that series;

• the holders of at least 25% in aggregate principal amount of the outstanding debt securities of that series have made written request, and have offered the trustee indemnity reasonably satisfactory to it to institute such proceedings as trustee; and

• the trustee does not institute such proceeding, and does not receive from the holders of a majority in aggregate principal amount of the outstanding debt securities of that series other conflicting directions within 60 days after such notice, request, and offer. These limitations do not apply to a suit instituted by you if we default in the payment of the principal, premium, if any, or interest on, your debt securities.

Subject to the terms of the supplemental indentures, we will periodically file statements with the trustee regarding our compliance with all of the conditions and covenants in the indentures.

Modification and Waiver

We and a trustee may change an indenture, or waive compliance in a particular instance by us with any provision of the indenture, without your consent with respect to specific matters, including:

• to cure any ambiguity, omission, defect or inconsistency;

• to provide for the assumption by a successor person of our obligations under such indenture;

• to add guarantees with respect to debt securities;

• to add to the covenants for the benefit of the holders of all, or a specific series, of the debt securities;

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• to add additional events of default with respect to all, or a specific series, of the debt securities;

• add to, change or eliminate any of the provisions of such indenture; provided, however that any such addition, change or elimination (i) shall neither (a) apply to any debt security of any series created prior to such addition, change or elimination nor (b) modify the rights of the holders of any such debt security with respect to such provision or (ii) shall become effective only when there is no such debt security outstanding;

• to supplement any of the provisions of the indenture to such extent as shall be necessary to permit or facilitate the defeasance and discharge of any series of debt securities in accordance with the terms of the indenture; provided, however, that any such action shall not adversely affect the interest of the holders of debt securities of such series or any other series of debt securities in any material respect;

• evidence and provide for the appointment of a successor trustee and to add to or change any of the provisions to facilitate the administration of trusts under an indenture by more than one trustee;

• to secure the debt securities;

• to surrender any right or power conferred to us under the indenture;

• to make a change that does not materially adversely affect your rights as a holder of debt securities of any series; or

• to comply with any requirement of the SEC in connection with the qualification of an indenture under the Trust Indenture Act of 1939, as amended; or

• in the case of any subordinated debt security, make any change to the subordination provisions that limits or terminates the benefits applicable to any holder of our senior indebtedness.

In addition, under the indentures, but subject to the terms of the supplemental indenture, your rights as a holder of a series of debt securities may be changed, or compliance in a particular instance by us with any provision of the indenture may be waived, by us and a trustee with the written consent of the holders of at least a majority in aggregate principal amount of the outstanding debt securities of each series that is affected. However, the following changes or waivers may only be made with the consent of each holder of any outstanding debt securities affected:

• change the stated maturity of the principal of, or any installment of principal of, interest on or any additional amounts with respect to, such series of debt securities;

• reduce the principal amount, reduce the rate of, or extend the time of payment of interest, or any premium payable upon the redemption of any such debt securities;

• reduce the amount of principal of an original issue discount security or any other debt security payable upon acceleration of the maturity thereof;

• change the place where principal or interest under the debt securities is payable;

• a change in the currency in which any debt security or any premium or interest is payable;

• impair the right to enforce any payment on or with respect to, or any conversion right with respect to, any debt security;

• reduce the percentage in principal amount of outstanding debt securities of any series, the consent of whose holders is required for modification or amendment of the applicable indenture or for waiver of compliance with certain provisions of the applicable indenture or for waiver of certain defaults; or

• modify any of the above provisions.

Special Rules for Action by Holders

Only holders of outstanding debt securities of the applicable series will be eligible to take any action under the indentures, such as giving a notice of default, declaring an acceleration, approving any change or waiver or giving the

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trustee an instruction with respect to debt securities of that series. Also, we will count only outstanding debt securities in determining whether the various percentage requirements for taking action have been met. Any debt securities owned by us or any of our affiliates or surrendered for cancellation or for payment or redemption of which money has been set aside in trust are not deemed to be outstanding. Any required approval or waiver must be given by written consent.

In some situations, we may follow special rules in calculating the principal amount of debt securities that are to be treated as outstanding for the purposes described above. This may happen, for example, if the principal amount is payable in a non-U.S. dollar currency, increases over time or is not to be fixed until maturity.

We will generally be entitled to set any day as a record date for the purpose of determining the holders that are entitled to take action under the indentures. In certain limited circumstances, only the trustee will be entitled to set a record date for action by holders. If we or the trustee sets a record date for an approval or other action to be taken by holders, that vote or action may be taken only by persons or entities who are holders on the record date and must be taken during the period that we specify for this purpose, or that the trustee specifies if it sets the record date. We or the trustee, as applicable, may shorten or lengthen this period from time to time. This period, however, may not extend beyond the 180^th day after the record date for the action. In addition, record dates for any global debt security may be set in accordance with procedures established by the depositary from time to time. Accordingly, record dates for global debt securities may differ from those for other debt securities.

Form, Exchange and Transfer

The debt securities of each series will be issuable only in fully registered form without coupons and, unless otherwise specified in the applicable prospectus supplement, in denominations of $1,000 (or the equivalent amount in foreign currency) and any integral multiple thereof. Subject to the terms of the supplemental indentures, the indentures will provide that debt securities of a series may be issuable in temporary or permanent global form and may be issued as book entry securities that will be deposited with, or on behalf of, The Depository Trust Company or another depository we name and identify in a prospectus supplement with respect to such series.

At your option, subject to the terms of the supplemental indentures and the limitations applicable to global securities described in the applicable prospectus supplement, debt securities of any series will be exchangeable for other debt securities of the same series, in any authorized denomination and of like tenor and aggregate principal amount.

Subject to the terms of the supplemental indentures and the limitations applicable to global securities detailed in the applicable prospectus supplement, debt securities may be presented for exchange or for registration of transfer (duly endorsed or with the form of transfer endorsed thereon duly executed if so required by us or the security registrar) at the office of the security registrar or at the office of any transfer agent designated by us for such purpose. Unless otherwise provided in the debt securities to be transferred or exchanged, no service charge will be made for any registration of transfer or exchange, but we may require payment of any taxes or other governmental charges. The security registrar and any transfer agent (in addition to the security registrar) initially designated by us for any debt securities will be named in the applicable prospectus supplement. We may at any time designate additional transfer agents or rescind the designation of any transfer agent or approve a change in the office through which any transfer agent acts, except that we will be required to maintain a transfer agent in each place of payment for the debt securities of each series.

Subject to the terms of the supplemental indentures, if the debt securities of any series are to be redeemed, we will not be required to:

• issue, register the transfer of, or exchange any debt securities of that series during a period beginning at the opening of business 15 days before the day of mailing of a notice of redemption of any such debt securities that may be selected for redemption and ending at the close of business on the day of such mailing; or

• register the transfer of or exchange any debt securities so selected for redemption, in whole or in part, except the unredeemed portion of any such debt securities being redeemed in part.

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Information Concerning Trustees

A trustee, other than during the occurrence and continuance of an event of default under an indenture, undertakes to perform only such duties as are specifically detailed in the indentures and, upon an event of default under an indenture, must use the same degree of care as a prudent person would exercise or use in the conduct of his or her own affairs. Subject to this provision, a trustee is under no obligation to exercise any of the powers given it by the indentures at the request of any holder of debt securities unless it is offered reasonable security and indemnity against the costs, expenses, and liabilities that it might incur. A trustee is not required to spend or risk its own money or otherwise become financially liable while performing its duties unless it reasonably believes that it will be repaid or receive adequate indemnity.

Payment and Paying Agents

Unless otherwise indicated in the applicable prospectus supplement, payment of the interest on any debt securities on any interest payment date will be made to the person in whose name such debt securities (or one or more predecessor securities) are registered at the close of business on the regular record date for such interest.

Principal of and any premium and interest on the debt securities of a particular series will be payable at the office of the paying agents designated by us, except that unless otherwise indicated in the applicable prospectus supplement, interest payments may be made by check mailed to the holder. Unless otherwise indicated in such prospectus supplement, the corporate trust office of a trustee in The City of New York will be designated as our sole paying agent for payments with respect to debt securities of each series. Any other paying agents initially designated by us for the debt securities of a particular series will be named in the applicable prospectus supplement. We will be required to maintain a paying agent in each place of payment for the debt securities of a particular series.

All moneys paid by us to a paying agent or a trustee for the payment of the principal of or any premium or interest on any debt securities which remains unclaimed at the end of two years after such principal, premium, or interest has become due and payable will be repaid to us, and the holder of the security thereafter may look only to us for payment thereof.

Satisfaction and Discharge

Each indenture will be discharged and will cease to be of further effect with respect to the debt securities of any series issued thereunder, when:

(1) either (A) all outstanding debt securities of such series that have been authenticated (except lost, stolen or destroyed debt securities that have been replaced or paid and debt securities for whose payment money has theretofore been deposited in trust and thereafter repaid to us) have been delivered to the trustee for cancellation, (B) with respect to all outstanding debt securities of such series that have not been delivered to the trustee for cancellation, we have deposited or caused to be deposited with the trustee as trust funds, under the terms of an irrevocable escrow agreement in form and substance satisfactory to the trustee, money or United States government obligations sufficient to pay and discharge (with such delivery in trust to be for the stated purpose of paying and discharging) the entire indebtedness on all outstanding debt securities of such series not theretofore delivered to the trustee for cancellation for principal (and premium and additional amounts, if any)

and interest to the stated maturity or any redemption date, as the case may be or (C) we have properly fulfilled such other means of satisfaction and discharge as is specified to be applicable to the debt securities of such series;

(2) we have paid or caused to be paid all other sums payable hereunder by us with respect to the outstanding debt securities of such series;

(3) we have complied with any other conditions to be applicable to the discharge of the debt securities of such series;

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(4) we have delivered to the trustee an officers’ certificate and an opinion of our legal counsel, each stating that all conditions precedent herein provided for relating to the satisfaction and discharge of such indenture with respect to the outstanding debt securities of such series have been complied with; and

(5) if the conditions set forth in (1)(A) have not been satisfied, and unless otherwise specified in such indenture, we have delivered to the trustee an opinion of our legal counsel to the effect that the holders of the debt securities of such series will not recognize income, gain or loss for United States federal income tax purposes as a result of such deposit, satisfaction and discharge and will be subject to United States federal income tax on the same amount and in the same manner and at the same time as would have been the case if such deposit, satisfaction and discharge had not occurred.

Legal Defeasance and Covenant Defeasance

We at any time may terminate all of our obligations under the indenture and any applicable supplemental indenture (“legal defeasance”), except for certain obligations, including those respecting the defeasance trust and obligations to replace mutilated, destroyed, lost or stolen certificates representing the debt securities and to maintain a registrar and paying agent in respect of the debt securities. Additionally, we at any time may terminate certain covenants under the indenture or any supplemental indenture (“covenant defeasance”).

We may exercise our legal defeasance option notwithstanding our prior exercise of our covenant defeasance option.

If we exercise our legal defeasance option, payment of the debt securities may not be accelerated because of an event of default with respect to the indenture or a supplemental indenture. If we exercise our covenant defeasance option, payment of the debt securities may not be accelerated because of an event of default relating to the terminated covenants.

The legal defeasance option or the covenant defeasance option with respect to a series of debt securities may be exercised only if:

• we irrevocably deposit in trust with the trustee money or United States government obligations for the payment of principal of, premium, if any, and interest on, and any additional amounts with respect to, such debt securities to maturity or redemption, as the case may be;

• we deliver to the trustee a certificate from a nationally recognized firm of independent certified public accountants expressing their opinion that the payments of principal, premium, if any and interest when due and without reinvestment on the deposited United States government obligations plus any deposited money without investment will provide cash at such times and in such amounts as will be sufficient to pay principal, premium, if any, and interest when due on all such debt securities to maturity or redemption, as the case may be;

• 91 days pass after the deposit is made and during the 91-day period we are not in default under the indenture as a result of the initiation of a bankruptcy or similar proceeding with respect to us or any other person or entity making such deposit which is continuing at the end of the period;

• no event of default has occurred and is continuing on the date of such deposit and after giving effect to such deposit;

• such deposit does not constitute a default under any other agreement or instrument binding on us;

• we deliver to the trustee an opinion of our legal counsel to the effect that the trust resulting from the deposit does not constitute, or is qualified as, a regulated investment company under the Investment Company Act of 1940;

• in the case of the legal defeasance option, we deliver to the trustee an opinion of our legal counsel stating that:

• we have received from the Internal Revenue Service a ruling, or

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• since the date of the indenture there has been a change in the applicable federal income tax law, to the effect,

in either case, that, and based thereon such opinion of our legal counsel shall confirm that, the holders of the debt securities will not recognize income, gain or loss for federal income tax purposes as a result of such legal defeasance and will be subject to federal income tax on the same amounts, in the same manner and at the same time as would have been the case if such legal defeasance has not occurred;

• in the case of the covenant defeasance option, we deliver to the trustee an opinion of our legal counsel to the effect that the holders of the debt securities will not recognize income, gain or loss for federal income tax purposes as a result of such covenant defeasance and will be subject to federal income tax on the same amounts, in the same manner and at the same times as would have been the case if such covenant defeasance had not occurred; and

• we deliver to the trustee an officers’ certificate and an opinion of our legal counsel, each stating that all conditions precedent to the legal defeasance or covenant defeasance of the debt securities have been complied with as required by the applicable indenture.

Governing Law

The indentures and the debt securities will be governed by and construed in accordance with the laws of the State of New York, except for conflicts of laws provisions and to the extent that the Trust Indenture Act of 1939, as amended, shall be applicable.

Subordination of Subordinated Debt Securities

The indebtedness evidenced by the subordinated debt securities will, to the extent set forth in the subordinated indenture with respect to each series of subordinated debt securities, be subordinate in right of payment to the prior payment in full of all of our senior indebtedness, including the senior debt securities, and it may also be senior in right of payment to all of our other subordinated debt. The indenture supplement relating to any series of subordinated debt securities will include the subordination provisions of such series including:

• the applicability and effect of such provisions upon any payment or distribution of our assets to creditors upon any liquidation, dissolution, winding-up, reorganization, assignment for the benefit of creditors or marshaling of assets or any bankruptcy, insolvency or similar proceedings;

• the applicability and effect of such provisions in the event of specified defaults with respect to any senior indebtedness, including the circumstances under which and the periods in which we will be prohibited from making payments on the subordinated debt securities;

• the definition of senior indebtedness applicable to the subordinated debt securities of that series and, if the series is issued on a senior subordinated basis, the definition of subordinated debt applicable to that series; and

• any changes to the subordination provisions of the indenture that we make without the consent of the holders of debt securities and which changes are not specifically permitted under the indenture without such consent; provided that such changes shall become effective only when there is no debt security of any series which (i) is outstanding, (ii) was created prior to the execution of the supplemental indenture providing for such change and (iii) is adversely affected by such change.

The indenture supplement will also describe as of a recent date the approximate amount of senior indebtedness to which the subordinated debt securities of such series will be subordinated.

The failure to make any payment on any of the subordinated debt securities by reason of the subordination provisions of the subordinated indenture described in the applicable supplemental indenture will not be construed as preventing the occurrence of an event of default with respect to the subordinated debt securities arising from any such failure to make payment.

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The subordination provisions described above will not be applicable to payments in respect of the subordinated debt securities from a defeasance trust established in connection with any legal defeasance or covenant defeasance of the subordinated debt securities as described under “—Legal Defeasance and Covenant Defeasance.”

Redemption or Repayment

If there are any provisions regarding redemption or repayment applicable to a debt security, we will describe them in the applicable prospectus supplement. Notice of any redemption may, at the Company’s discretion, be subject to one or more conditions precedent (such as the consummation of refinancings or acquisitions, whether of the Company or by the Company).

We or our affiliates may purchase debt securities from investors who are willing to sell from time to time, either in the open market at prevailing prices or in private transactions at negotiated prices. Debt securities that we or they purchase may, at our discretion, be held, resold or canceled.

Notices

Notices to be given to holders of a global debt security will be given only to the depositary, in accordance with its applicable policies as in effect from time to time. Notices to be given to holders of debt securities not in global form will be given by mail to the addresses of such Holders as they may appear in the Security Register. Neither the failure to give any notice to a particular holder, nor any defect in a notice given to a particular holder, will affect the sufficiency of any notice given to another holder.

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PLAN OF DISTRIBUTION

We may sell the securities offered by this prospectus from time to time in one or more transactions:

• directly to purchasers;

• through agents;

• to or through underwriters or dealers; or

• through a combination of these methods.

A distribution of the securities offered by this prospectus may also be effected through the issuance of derivative securities, including without limitation, warrants, exchangeable securities, forward delivery contracts and the writing of options.

In addition, the manner in which we may sell some or all of the securities covered by this prospectus includes, without limitation, through:

• a block trade in which a broker-dealer will attempt to sell as agent, but may position or resell a portion of the block, as principal, in order to facilitate the transaction;

• purchases by a broker-dealer, as principal, and resale by the broker-dealer for its account;

• ordinary brokerage transactions and transactions in which a broker solicits purchasers; or

• any other method permitted pursuant to applicable law.

In addition, we may enter into derivative or hedging transactions with third parties, or sell securities not covered by this prospectus to third parties in privately negotiated transactions. In connection with such a transaction, the third parties may sell securities covered by and pursuant to this prospectus and an applicable prospectus supplement or other offering materials, as the case may be. If so, the third party may use securities borrowed from us or others to settle such sales and may use securities received from us to close out any related short positions. We may also loan or pledge securities covered by this prospectus and an applicable prospectus supplement to third parties, who may sell the loaned securities or, in an event of default in the case of a pledge, sell the pledged securities pursuant to this prospectus and the applicable prospectus supplement or other offering materials, as the case may be.

A prospectus supplement with respect to each series of securities will state the terms of the offering of the securities, including:

• the terms of the offering;

• the name or names of any underwriters or agents and the amounts of securities underwritten or purchased by each of them, if any;

• the public offering price or purchase price of the securities and the net proceeds to be received by us from the sale;

• any delayed delivery arrangements;

• any initial public offering price;

• any underwriting discounts or agency fees and other items constituting underwriters’ or agents’ compensation;

• any discounts or concessions allowed or reallowed or paid to dealers; and

• any securities exchange on which the securities may be listed.

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The offer and sale of the securities described in this prospectus by us, the underwriters or the third parties described above may be effected from time to time in one or more transactions, including privately negotiated transactions, either:

• at a fixed price or prices, which may be changed;

• in an “at the market” offering within the meaning of Rule 415(a)(4) of the Securities Act of 1933, as amended (the “Securities Act”);

• at prices related to the prevailing market prices; or

• at negotiated prices.

General

Underwriters, dealers, agents and remarketing firms that participate in the distribution of the offered securities may be “underwriters” as defined in the Securities Act. Any discounts or commissions they receive from us and any profits they receive on the resale of the offered securities may be treated as underwriting discounts and commissions under the Securities Act. We will identify any underwriters, agents or dealers and describe their commissions, fees or discounts in the applicable prospectus supplement, as the case may be.

Underwriters and Agents

If underwriters are used in a sale, they will acquire the offered securities for their own account. The underwriters may resell the offered securities in one or more transactions, including negotiated transactions. These sales will be made at a fixed public offering price or at varying prices determined at the time of the sale. We may offer the securities to the public through an underwriting syndicate or through a single underwriter. The underwriters in any particular offering will be mentioned in the applicable prospectus supplement or other offering materials, as the case may be.

Unless the applicable prospectus supplement states otherwise, the obligations of the underwriters to purchase the offered securities will be subject to certain conditions contained in an underwriting agreement that we will enter into with the underwriters at the time of the sale to them. The underwriters will be obligated to purchase all of the securities of the series offered if any of the securities are purchased, unless the applicable prospectus supplement says otherwise. Any initial public offering price and any discounts or concessions allowed, reallowed or paid to dealers may be changed from time to time.

We may designate agents to sell the offered securities. Unless the applicable prospectus supplement states otherwise, the agents will agree to use their best efforts to solicit purchases for the period of their appointment. We may also sell the offered securities to one or more remarketing firms, acting as principals for their own accounts or as agents for us. These firms will remarket the offered securities upon purchasing them in accordance with a redemption or repayment pursuant to the terms of the offered securities. A prospectus supplement or other offering materials, as the case may be, will identify any remarketing firm and will describe the terms of its agreement, if any, with us and its compensation.

In connection with offerings made through underwriters or agents, we may enter into agreements with such underwriters or agents pursuant to which we receive our outstanding securities in consideration for the securities being offered to the public for cash. In connection with these arrangements, the underwriters or agents may also sell securities covered by this prospectus to hedge their positions in these outstanding securities, including in short sale transactions. If so, the underwriters or agents may use the securities received from us under these arrangements to close out any related open borrowings of securities.

Dealers

We may sell the offered securities to dealers as principals. The dealer may then resell such securities to the public either at varying prices to be determined by the dealer or at a fixed offering price agreed to with us at the time of resale.

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Direct Sales

We may choose to sell the offered securities directly. In this case, no underwriters or agents would be involved.

Institutional Purchasers

We may authorize agents, dealers or underwriters to solicit certain institutional investors to purchase offered securities on a delayed delivery basis pursuant to delayed delivery contracts providing for payment and delivery on a specified future date. The applicable prospectus supplement or other offering materials, as the case may be, will provide the details of any such arrangement, including the offering price and commissions payable on the solicitations.

We will enter into such delayed contracts only with institutional purchasers that we approve. These institutions may include commercial and savings banks, insurance companies, pension funds, investment companies and educational and charitable institutions.

Indemnification; Other Relationships

We may have agreements with agents, underwriters, dealers and remarketing firms to indemnify them against certain civil liabilities, including liabilities under the Securities Act. Agents, underwriters, dealers and remarketing firms, and their affiliates, may engage in transactions with, or perform services for, us in the ordinary course of business. This includes commercial banking and investment banking transactions.

Market-Making, Stabilization and Other Transactions

There is currently no market for any of the offered securities, other than our common stock which is quoted on the OTCBB. If the offered securities are traded after their initial issuance, they may trade at a discount from their initial offering price, depending upon prevailing interest rates, the market for similar securities and other factors. While it is possible that an underwriter could inform us that it intends to make a market in the offered securities, such underwriter would not be obligated to do so, and any such market-making could be discontinued at any time without notice. Therefore, no assurance can be given as to whether an active trading market will develop for the offered securities. We have no current plans for listing of the debt securities, preferred stock or warrants on any securities exchange or quotation system; any such listing with respect to any particular debt securities, preferred stock, or warrants will be described in the applicable prospectus supplement or other offering materials, as the case may be.

Any underwriter may engage in stabilizing transactions, syndicate covering transactions and penalty bids in accordance with Regulation M under the Exchange Act. Stabilizing transactions involve bids to purchase the underlying security in the open market for the purpose of pegging, fixing or maintaining the price of the securities. Syndicate covering transactions involve purchases of the securities in the open market after the distribution has been completed in order to cover syndicate short positions.

Penalty bids permit the underwriters to reclaim a selling concession from a syndicate member when the securities originally sold by the syndicate member are purchased in a syndicate covering transaction to cover syndicate short positions. Stabilizing transactions, syndicate covering transactions and penalty bids may cause the price of the securities to be higher than it would be in the absence of these transactions. The underwriters may, if they commence these transactions, discontinue them at any time.

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LEGAL MATTERS

Akin Gump Strauss Hauer & Feld LLP will issue an opinion about certain legal matters with respect to the enforceability of debt securities and warrants for us. Certain matters relating to Florida law regarding the validity of our common stock and preferred stock will be passed on by Carlton Fields, P.A. In connection with any particular offering of the securities in the future, the validity of those securities may be passed upon for us by Akin Gump Strauss Hauer & Feld LLP, Carlton Fields, P.A. or such other counsel as may be specified in the applicable prospectus supplement. Any underwriters will be advised about the other issues relating to any offering by their own legal counsel.

EXPERTS

The consolidated financial statements as of May 31, 2012 and for the year then ended have been incorporated herein by reference to our Annual Report on Form 10-K in reliance upon the report of Hein & Associates LLP, independent registered public accounting firm, (which report expresses an unqualified opinion and includes an explanatory paragraph related to the Company’s ability to continue as a going concern) also incorporated herein by reference, and upon the authority of said firm as experts in accounting and auditing. The financial statements as of May 31, 2011 and for the year then ended have been incorporated herein by reference to our Annual Report on Form 10-K in reliance upon the report of L J Soldinger Associates, LLC, independent registered public accounting firm, also incorporated herein by reference, and upon the authority of said firm as experts in accounting and auditing.

INDEPENDENT PETROLEUM ENGINEERS

Certain estimates of our oil and natural gas reserves that are incorporated by reference in this prospectus were based in part upon engineering reports prepared by independent petroleum engineers Forrest A. Garb & Associates, Inc. and Lee Engineering. These estimates are incorporated by reference in this prospectus in reliance upon the authority of said firms as experts in such matters.

MATERIAL CHANGES

There have been no material changes to us since May 31, 2012 that have not been described in our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q and Current Reports on Form 8-K.

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INCORPORATION OF CERTAIN INFORMATION BY REFERENCE

The SEC allows us to “incorporate by reference” certain information we have filed with them, which means that we can disclose important information to you by referring you to documents we have filed with the SEC. The information incorporated by reference is considered to be part of this prospectus. We incorporate by reference the documents listed below, excluding any disclosures therein that are furnished and not filed:

• Annual Report on Form 10-K for the fiscal year ended May 31, 2012, filed on September 13, 2012;

• Quarterly Report on Form 10-Q for the fiscal quarter ended August 31, 2012, filed on October 15, 2012, as amended by Amendment No. 1 on Form 10-Q/A filed on November 8, 2012;

• Quarterly Report on Form 10-Q for the fiscal quarter ended November 30, 2012, filed on January 14, 2013;

• Current Report on Form 8-K dated December 24, 2012, and filed on December 31, 2012;

• Current Report on Form 8-K dated December 10, 2012, and filed on December 14, 2012;

• Current Report on Form 8-K dated November 30, 2012, and filed on November 30, 2012;

• Current Report on Form 8-K dated November 16, 2012, and filed on November 16, 2012;

• Current Report on Form 8-K dated November 14, 2012, and filed on November 14, 2012;

• Current Report on Form 8-K dated November 6, 2012, and filed on November 13, 2012;

• Current Report on Form 8-K dated October 30, 2012, and filed on November 2, 2012;

• Current Report on Form 8-K dated October 18, 2012, and filed on October 29, 2012;

• Current Report on Form 8-K dated October 19, 2012, and filed on October 19, 2012, as amended by Amendment No. 1 on Form 8-K/A filed on November 7, 2012 and Amendment No. 2 to Form 8-K/A filed on January 15, 2013;

• Current Report on Form 8-K dated September 7, 2012, and filed on September 7, 2012;

• Current Report on Form 8-K dated August 28, 2012, and filed on August 29, 2012;

• Current Report on Form 8-K dated August 10, 2012, and filed on August 13, 2012;

• Current Report on Form 8-K dated July 25, 2012, and filed on July 30, 2012;

• Current Report on Form 8-K dated July 19, 2012, and filed on July 25, 2012, as amended by Amendment No. 1 on Form 8-K/A filed on August 16, 2012;

• Current Report on Form 8-K dated June 30, 2012, and filed on July 3, 2012;

• Amendment No. 1 on Form 8-K/A filed on June 21, 2012 to the Current Report on Form 8-K dated August 30, 2011;

• Amendment No. 5 on Form 8-K/A filed on June 21, 2012, and Amendment No. 6 on Form 8-K/A filed on September 14, 2012, to the Current Report on Form 8-K dated May 26, 2011;

• Current Report on Form 8-K dated June 13, 2012, and filed on June 18, 2012; and

• The description of our common stock, which is contained in our registration statement on Form 8-A filed with the SEC on September 22, 2011, as updated or amended in any amendment or report filed for such purpose.

In addition, all documents we subsequently file with the SEC pursuant to Sections 13(a), 13(c), 14 or 15(d) of the Exchange Act, after the initial filing of the registration statement related to this prospectus and prior to the termination of the offering of the securities described in this prospectus, shall be deemed to be incorporated by

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reference herein and to be part of this prospectus from the respective dates of filing such documents. Information contained in this prospectus modifies or supersedes, as applicable, the information contained in earlier-dated documents incorporated by reference. Information contained in later-dated documents incorporated by reference will automatically supplement, modify or supersede, as applicable, the information contained in this prospectus or in earlier-dated documents incorporated by reference.

We will provide, upon written or oral request, to each person, including any beneficial owner, to whom a prospectus is delivered, a copy of these filings (other than exhibits to such documents, unless such exhibits are specifically incorporated by reference in any such documents), at no cost. Any person requesting such information can contact us at the address and telephone phone number indicated below:

Red Mountain Resources, Inc.

2515 McKinney Avenue, Suite 900

Dallas, Texas 75201

Attention: Chief Executive Officer

Telephone (214) 871-0400

Our incorporated reports and other documents may be accessed at our website address:www.redmountainresources.com or by contacting the SEC as described below in “Where You Can Find More Information.”

The information contained on our website does not constitute a part of this prospectus, and our website address supplied above is intended to be an inactive textual reference only and not an active hyperlink to our website.

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WHERE YOU CAN FIND MORE INFORMATION

We file annual, quarterly and current reports, proxy statements and other information with the SEC. You can read these SEC filings, and this registration statement, over the Internet at the SEC’s website atwww.sec.gov . You may also read and copy any document we file with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. You may also obtain copies of the documents at prescribed rates by writing to the SEC’s Public Reference Room at the address above. Please call the SEC at 1-800-SEC-0330 for further information on the operation of the SEC’s Public Reference Room.

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Red Mountain Resources, Inc.

            Shares

10.0% Series A Cumulative Redeemable Preferred Stock

Prospectus Supplement

Northland Capital Markets Euro Pacific Capital

                    , 2014