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

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

PROSPECTUS SUPPLEMENT

(To Prospectus dated February 1, 2013)

Red Mountain Resources, Inc.

11,500,000 Shares

Common Stock

We are offering up to 11,500,000 shares of common stock directly to investors in this offering.

You should read carefully this prospectus supplement and the accompanying prospectus, together with the documents we incorporate by reference, before you invest in our common stock.

Our common stock is traded on the OTCQB market (the “OTCQB”) under the symbol “RDMP.” On August 21, 2013, the last reported sale price of our common stock as reported on the OTCQB was $0.74 per share.

Investing in our common stock involves a high degree of risk. You should carefully consider the risks relating to an investment in our common stock and each of the other risk factors described under “Risk Factors” beginning on page S-13 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 common stock.

	Price		Proceeds, Before Expenses, to Us
Offering price per share	$	0.70	$	8,050,000.00
Total	$	0.70	$	8,050,000.00

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 the accompanying prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

We expect to deliver the shares of common stock to purchasers on or about August 27, 2013.

The date of this prospectus supplement is August 22, 2013.

Company Overview

Summary of Combined Properties of Red

Mountain, Cross Border and Bamco

Pro Forma Production¹: 913 (Boe/d) – 52% oil

Reserves²: 3.5 MMBoe

53% Proved Developed

¹  Average net daily pro forma production for the twelve months ended May 31, 2013. Includes net production sold represented by the 17% of Cross Border’s common stock not owned by us.

²  As of May 31, 2013. Includes reserves represented by the 17% of Cross Border’s common stock not owned by us.

98% of Acreage Either Owned Mineral Rights or Leases Held by Production as of May 31, 2013
Prospect	Gross Acres		Net Acres
Developed Permian		11,108		5,237
Undeveloped Permian1		325,743		25,774
Undeveloped Southwest New Mexico2		536,340		268,170
Developed South Texas		4,776		1,405
Kansas		5,215		5,215
TOTAL		883,182		305,801

¹  Includes mineral ownership.

²  Reflects mineral ownership.

³  Includes acreage represented by the 17% of Cross Border’s common stock not owned by us.

TABLE OF CONTENTS

PROSPECTUS SUPPLEMENT

ABOUT THIS PROSPECTUS SUPPLEMENT	S-1
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS	S-1
PROSPECTUS SUPPLEMENT SUMMARY	S-3
RISK FACTORS	S-13
CONCURRENT OFFERING	S-32
USE OF PROCEEDS	S-32
CAPITALIZATION	S-33
COMMON STOCK PRICE RANGE	S-34
DIVIDEND POLICY	S-34
UNAUDITED PRO FORMA COMBINED FINANCIAL INFORMATION	S-35
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS OF RED MOUNTAIN	S-40
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS OF CROSS BORDER	S-54
BUSINESS	S-58
PROPERTIES	S-73
MANAGEMENT	S-82
PLAN OF DISTRIBUTION	S-87
LEGAL MATTERS	S-89
EXPERTS	S-89
INDEPENDENT PETROLEUM ENGINEERS	S-90
WHERE YOU CAN FIND MORE INFORMATION	S-90
INCORPORATION OF CERTAIN INFORMATION BY REFERENCE	S-91
GLOSSARY OF OIL AND NATURAL GAS TERMS	S-93
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

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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 shares of common stock offered by this prospectus supplement and the accompanying prospectus. For more information about our common stock offered in this offering, see “Description of Capital Stock—Common Stock” in the accompanying prospectus.

Before you invest in our common 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, any free writing prospectus we may file 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 authorized any other person to provide you with different information. We 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.

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

Certain statements contained in this prospectus supplement 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 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;

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• 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.”

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 securities. 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, unless the context otherwise requires, the terms “we,” “us,” “our” and the “Company” refer to Red Mountain Resources, Inc. and its consolidated subsidiaries, including Black Rock Capital, Inc. (“Black Rock”) and RMR Operating, LLC (“RMR Operating”) and, subsequent to January 28, 2013, Cross Border Resources, Inc. (“Cross Border”). See “—Recent Developments—Acquisition of Cross Border.” Pro forma production data reflects the acquisition of Cross Border as if it occurred on June 1, 2012. As of May 31, 2013, we owned 83% of the outstanding common stock of Cross Border.

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 May 31, 2013, we had proved reserves of approximately 3.5 MMBoe. For the twelve months ended May 31, 2013, on a pro forma basis, we produced 172.2 MBbls of oil and 966.9 MMcf of natural gas, resulting in average net daily production of 913 Boe/d. For additional information regarding our reserves and production, see “—Summary Reserves and Historical and Pro Forma Operating Data.”

As of May 31, 2013, we owned interests in 883,226 gross (305,845 net) mineral and lease acres in New Mexico, Texas and Kansas, of which 336,851 gross (31,011 net) acres were within the Permian Basin. We have successfully leased over 5,200 net acres in Kansas located on the Central Kansas Uplift, and we also owned interests in over 1,400 net acres located on the Villarreal, Frost Bank, Resendez, Peal Ranch and La Duquesa Prospects in the Gulf Coast of Texas.

Permian Basin

As of May 31, 2013, approximately 89% 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.

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The following table presents the project name, location, operator, wellbore orientation and targeted primary formation for our Permian Basin properties with active and planned development as of May 31, 2013. During fiscal year 2014, we plan to spend between $35.0 million and $45.0 million to develop our properties. Of this amount, we expect to spend between $25.0 million and $35.0 million on the operated Permian properties listed in the table below and between $5.0 million and $7.0 million on the non-operated Permian properties listed in the table below. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations of Red Mountain—Planned Operations.”

Operated Projects	Location	Operator(s)	Wellbore Orientation	Target Primary Formation
Madera	Lea, NM	RMR Operating	Horizontal	Brushy Canyon
Cowden	Ector, TX	RMR Operating	Vertical	Grayburg, San Andres
Tom Tom	Chaves and Roosevelt, NM	Cross Border	Vertical	San Andres
Shafter Lake	Andrews, TX	RMR Operating	Vertical	San Andres
Non-Operated Projects	Location	Operator(s)	Wellbore Orientation	Target Primary Formation
Lusk	Eddy, NM	Apache Corporation	Horizontal	Bone Spring
Turkey Track	Eddy, NM	Mewbourne Oil Company	Horizontal	Bone Spring
Cemetary	Eddy, NM	COG Operating LLC	Horizontal	Yeso
Red Lake	Eddy, NM	Alamo Permian Resources, LLC LRE Operating, LLC Oxy USA Inc.	Vertical	Yeso, Queen, Grayburg, San Andres
Corbin	Lea, NM	Devon Energy Production Company, LP	Horizontal	Bone Spring

Our Business Strategies

Key elements of our business strategy include:

• Increase Reserves and Production Through Low-Risk Drilling Program. We intend to achieve reserves and production growth over the next few years through our drilling program, which will focus on low risk opportunities with attractive rates of return. In addition to our proved reserve base of 3.5 MMBoe at May 31, 2013, we believe we have significant upside potential to convert our current probable and possible reserves into proved reserves. Following completion of this offering, we plan to drill and complete, workover or recomplete 55 gross wells (38.1 net) through fiscal 2014 to develop our current properties. If the results of the drilling, completion and operations meet our expectations, we believe it should result in an estimated increase in our proved reserves of 5.0 to 6.0 MMBoe.

• 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 by drilling primarily within cash flows, 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.

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• Retain Operational Control.We intend to retain a high degree of operational control over our interests, through a high average working interest or acting as the operator in areas of significant exploration and development activity. This strategy is intended to provide us with controlling interests in a multi-year inventory of drilling locations, positioning us for reserve and production growth through drilling. We plan to control the timing, level and allocation of our drilling capital expenditures and the technology and methods utilized in the planning, drilling and completion process on related targets. We believe this flexibility to opportunistically pursue development on properties provides us with a meaningful competitive advantage.

• Mitigate Operational and Financial Risk. Our goal is to generate attractive rates of return on every dollar invested. Concurrently, our goal is to manage risk by spreading our capital dollars over a significant number of wells to mitigate capital, geologic and mechanical concentration risk to any one project. The combination may prevent us from aggressively and continuously drilling in any one area but the participation in more projects allows us to better manage our production growth, effectively procure services, and provides ample time necessary to evaluate results in order to attempt to improve future wells.

Our Competitive Strengths

We believe that the following competitive strengths will help us successfully execute our business strategies and create substantial value:

• Large Acreage Position Consisting of Mineral Ownership and Leases Held by Production. As of May 31, 2013, we controlled 305,845 net acres, 98% of which is in Texas and New Mexico. Included in this acreage position are approximately 275,000 net mineral acres within Southwest New Mexico and the Permian Basin region of Southeast New Mexico. This net mineral acreage carries no drilling commitments or leasehold obligations. Furthermore, 93% of our leasehold acreage in the Permian Basin is currently held by existing production. The combination of perpetual mineral ownership and leases held by production provides us with ample time to exploit our drilling inventory in the Permian Basin.

• Long-Life Reserves and Multi-Horizon Drilling Opportunities. One of the great attributes of the Permian Basin is that there are dozens of productive formations that lie deep into the Earth. Enhancements in drilling and completion technology have improved the economics of drilling and producing various hydrocarbon bearing strata that previously were uneconomic. We believe that much of our productive acreage has drilling opportunities into multiple hydrocarbon bearing zones that we have yet to evaluate which could provide substantial upside to our reserve base. Many of these zones are productive on nearby leases owned by other operators. Cash flow from our longer life reserve base combined with existing infrastructure should allow us to opportunistically test numerous potentially productive zones in the San Andres, Bone Spring, Brushy Canyon and other known horizons providing us with a multi-year drilling inventory.

• Strong Management and Operations Team. Our team of managers, employees, consultants and directors combine to represent over 300 years of experience in the oil and natural gas industry as owners, investors, company builders, financiers, operators, geologists, service providers and petroleum engineers. In these various capacities, the Red Mountain team has participated in more than 10,000 wells in 20 states and 22 countries. We intend to utilize sophisticated geologic and 3-D seismic models to enhance the predictability and reproducibility of our operations. We also intend to utilize multi-zone, multi-stage hydraulic fracturing technology in completing wells to substantially increase near-term production, resulting in faster payback periods and higher rates of return and present values. Our team has applied these techniques to improve initial and ultimate production and returns for other organizations. We believe that the depth and breadth of our operations team coupled with a proven team in the areas of accounting, finance and capital markets, positions us well to take advantage of our large inventory of acreage and drilling opportunities.

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• Management with Meaningful Equity Ownership. As of August 20, 2013, our chairman of the board and chief executive officer, Alan Barksdale, owned 8.7% of our outstanding shares of common stock, and other members of our management and board of directors owned 1.2% of our outstanding shares of common stock. As a result of their equity investment in us, we believe our management’s interests are highly aligned with our stockholders’ interests in stock price appreciation and profitable growth.

• Existing Infrastructure. All of our properties are located within established oil and natural gas producing areas or existing fields. We seek to enhance existing production in these properties by using our engineering and geological expertise. These areas also have a fully developed transportation infrastructure, which allows us to transport our oil and natural gas to market without long-term delay or significant investment.

Recent Developments

Bamco Asset Purchase Agreement. On December 10, 2012, we entered into an Asset Purchase Agreement (the “Asset Purchase Agreement”) with Bamco Gas, LLC (“Bamco”). Mr. Barksdale was the receiver for the receivership estate of Bamco. Pursuant to the Asset Purchase Agreement, we agreed to acquire working interests and claims and causes of action in or relating to certain oil and gas exploration projects in Duval, Johnson and Zapata Counties in Texas (the “Bamco Properties”). On December 10, 2012, pursuant to the Asset Purchase Agreement, we issued 2,375,000 shares of our common stock to the indenture trustee of certain debentures of Bamco, and we executed a waiver and release of a claim against the receivership estate of Bamco for a $2.7 million note receivable that we deemed uncollectible in 2011.

Acquisition of Cross Border. On January 28, 2013, pursuant to privately negotiated transactions, we acquired 5,091,210 shares of common stock of Cross Border from a limited number of stockholders in exchange for the issuance of 10,182,420 shares of our common stock, bringing our total ownership to approximately 78% of Cross Border’s outstanding common stock (the “Acquisition”). Prior to the Acquisition, we owned 47% of Cross Border’s outstanding common stock, and the investment was accounted for under the equity method of accounting. Subsequent to the Acquisition, we account for Cross Border as a consolidated subsidiary. As of May 31, 2013, we owned of record 14,327,767 shares of Cross Border common stock, representing 83% of Cross Border’s outstanding common stock. In addition, as of May 31, 2013, we owned warrants to acquire an additional 2,502,831 shares of Cross Border common stock. The warrants have an exercise price of $2.25 per share and are exercisable until May 26, 2016.

Senior Credit Facility. On February 5, 2013, we entered into a Senior First Lien Secured Credit Agreement (as amended, the “Credit Agreement”) with Cross Border, Black Rock and RMR Operating (collectively with the Company, the “Borrowers”) and Independent Bank, as Lender (the “Lender”). The Credit Agreement provides for an up to $100.0 million revolving credit facility (the “Credit Facility”) with an initial commitment of $20.0 million and a maturity date of February 5, 2016.

Simultaneously with entering into the Credit Agreement, we borrowed $7.6 million under the Credit Facility and used a portion of the proceeds to repay outstanding indebtedness, and Cross Border borrowed $8.9 million and used a portion of the proceeds to repay in full its existing credit facility. As of May 31, 2013, the Borrowers had collectively borrowed $19.8 million and had availability of $0.2 million under the Credit Facility. On February 21, 2013, pursuant to the terms of the Credit Agreement, we entered into a hedge agreement with BP Energy Company, LP (“BP Energy”) to hedge a portion of the future oil production of the Borrowers.

On July 19, 2013, we entered into an amendment to the Credit Agreement to permit the payment of cash dividends on our 10.0% Series A Cumulative Redeemable Preferred Stock (the “Series A Preferred Stock”) so long as we are not otherwise in default under the Credit Agreement and payment of such cash dividends would not cause us to be in default under the Credit Agreement.

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Private Placements. On February 5, 2013, we closed a private placement for 7,058,823 shares of common stock at a purchase price of $0.85 per share, raising gross proceeds of $6.0 million, from certain of the initial investors in our company. We used the proceeds for drilling expenses, repayment of debt and general working capital. On May 3, 2013, we closed a private placement for 3,529,412 shares of common stock at a purchase price of $0.85 per share, raising gross proceeds of $3.0 million, from certain of the initial investors in our company. We used the proceeds for general working capital.

Reverse Stock Split. On April 22, 2013, our Board of Directors approved a reverse stock split. The Board authorized management to effectuate the reserve stock split in its discretion within a range of 1 for 5 to 1 for 10. We intend to consummate the reverse stock split during the first quarter of fiscal 2014.

Madera 24 Federal 3H Well. During the three months ended February 28, 2013, we commenced drilling the Madera 24 Federal 3H well, which is located in the Madera prospect just to the west of the Madera 24 Federal 2H well. We are the operator of the well and own a 33% working interest and 25% net revenue interest. The well was spudded on February 6, 2013, and on May 10, 2013, we finished drilling and completing the well. The initial production rate from the well was 1,491 Boe (81% oil). The well has a total measured depth of 13,570 feet, including a true vertical depth of 9,062 feet and a lateral length of 4,508 feet. At May 31, 2013, the well was still producing and permanent production facilities were under construction.

Change of Fiscal Year End. On July 17, 2013, we changed our fiscal year end from May 31 to June 30, effective June 30, 2013.

Closing of Units Offering. In August 2013, we closed an offering of 375,676 Units (the “Units”), including 100,002 Units sold in cancellation of $2.3 million in debt, raising gross cash proceeds of $6.2 million. Each Unit consisted of one share of Series A Preferred Stock and one warrant to purchase up to 25 shares of common stock. We intend to use the proceeds for general corporate purposes, including to fund a portion of our fiscal 2014 drilling and development expenditures and the payment of accrued interest and fees on indebtedness that was cancelled.

Late Filing of Form 10-K. Our Annual Report on Form 10-K for the fiscal year ended May 31, 2013 (the “Form 10-K”) is due on August 29, 2013. We expect that we will be unable to timely file the Form 10-K because we need additional time to prepare and review our fiscal year 2013 financial statements due to purchase price accounting and consolidation issues related to Cross Border. As a result, we expect to file a Notification of Late Filing on Form 12b-25.

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

Issuer Red Mountain Resources, Inc.

Common stock offered by us 11,500,000 shares

Common stock outstanding immediately after this offering 138,211,731 shares

Use of proceeds We intend to use the net proceeds from this offering for general corporate purposes, including to fund a portion of our fiscal 2014 drilling and development expenditures. See “Use of Proceeds”

Dividend policy We have not declared or paid any cash or other dividends on our common stock and do not expect to declare or pay any cash or other dividends in the foreseeable future. See “Dividend Policy.”

Risk factors You should carefully read and consider the information beginning on page S-13 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 our common stock.

OTCQB symbol “RDMP”

The number of shares to be outstanding after this offering is based on 126,711,731 shares of our common stock outstanding as of August 20, 2013 and excludes (1) 8,200,000 additional shares that are authorized for future issuance under our equity incentive plans, (2) 13,010,324 additional shares that are issuable under warrants and (3) 6,250,000 additional shares that may be issuable under warrants offered for sale as part of the concurrent Units offering. See “Concurrent Offering.”

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SUMMARY HISTORICAL AND PRO FORMA COMBINED FINANCIAL INFORMATION

The following summary historical and pro forma combined financial information should be read together with our most recent Annual Report on Form 10-K for the fiscal year ended May 31, 2012, Quarterly Report on Form 10-Q for the nine months ended February 28, 2013 and Amendment No. 1 to the Current Report on Form 8-K/A filed with the Securities and Exchange Commission (“SEC”) on April 12, 2013, each of which is incorporated by reference in this prospectus supplement and accompanying prospectus. The summary historical consolidated statement of operations data below for the fiscal years ended May 31, 2012 and 2011, and the summary historical balance sheet data as of February 28, 2013, May 31, 2012 and 2011 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 February 28, 2013 are not necessarily indicative of results that may be expected for the full year or future periods.

On January 28, 2013, Red Mountain acquired 5,091,210 shares of common stock of Cross Border from a limited number of stockholders of Cross Border in exchange for the issuance of 10,182,420 shares of common stock of Red Mountain. This acquisition was a step-acquisition in which Red Mountain acquired an additional 31% of Cross Border’s outstanding common stock, increasing Red Mountain’s ownership of Cross Border’s outstanding common stock from 47% to 78%. Prior to January 28, 2013, Red Mountain accounted for its investment in Cross Border as an equity method investment. After January 28, 2013, Red Mountain accounts for Cross Border as a consolidated subsidiary.

Red Mountain’s fiscal year ends on May 31, and Cross Border’s fiscal year ends on December 31.

The unaudited pro forma combined statement of operations for the twelve months ended May 31, 2012 was derived from (i) our audited statement of operations for the fiscal year ended May 31, 2012 and (ii) the unaudited statement of operations of Cross Border for the twelve months ended June 30, 2012. Cross Border’s unaudited statement of operations for the twelve months ended June 30, 2012 was derived by using its audited results for the fiscal year ended December 31, 2011 and deducting its unaudited results for the interim six-month period ended June 30, 2011 and adding its unaudited results for the interim six-month period ended June 30, 2012.

The interim unaudited pro forma combined statement of operations for the nine months ended February 28, 2013 was derived from (i) our unaudited statement of operations for the nine months ended February 28, 2013 and (ii) the unaudited statement of operations for Cross Border for the seven months ended January 31, 2013. Cross Border’s results for the seven months ended January 31, 2013 were derived by using its audited results for the year ended December 31, 2012, deducting its unaudited results for the interim six-month period ended June 30, 2012 and adding its unaudited results for the interim one-month period ended January 31, 2013.

The pro forma statements of operations reflect the Acquisition and related events as if they occurred on June 1, 2011 and 2012 for purposes of the statement of operations for the year ended May 31, 2012 and the nine months ended February 28, 2013, respectively, for Red Mountain; and on January 1, 2012 and July 1, 2012 for the year ended May 31, 2012 and the seven months ended January 31, 2013, respectively, for Cross Border.

The pro forma adjustments used in the preparation of the pro forma combined financial information are based upon available information and assumptions that we believe are reasonable; however, we can provide no assurance that the assumptions are correct. The pro forma combined financial information is for illustrative and informational purposes only and is not intended to represent or be indicative of what our financial condition or

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results of operations would have been had our acquisition of Cross Border occurred on June 1, 2011 and 2012 for purposes of the pro forma combined statement of operations for the fiscal year ended May 31, 2012 and the nine months ended February 28, 2013, respectively. The pro forma combined financial information also should not be considered representative of our future financial condition or results of operations.

	Historical													Pro Forma
	Fiscal Year Ended May 31,							Nine Months Ended February 28,						Fiscal Year Ended May 31, 2012			Nine Months Ended February 28, 2013
(in thousands)	2011				2012			2012			2013
STATEMENT OF OPERATIONS DATA:								(unaudited)						(unaudited)
Revenue:
Oil and natural gas sales	$	3,712			$	6,325		$	3,780		$	4,917		$	17,696		$	13,068
Operating Expenses:
Exploration expense		—				265			92			53			314			53
Production taxes		161				403			221			180			1,217			896
Lease operating expenses		165				943			689			966			2,842			2,769
Natural gas transportation and marketing expenses		236				170			142			77			180			206
Depletion, depreciation, amortization and impairment		717				5,149			1,194			3,193			7,565			5,747
Environmental remediation liability		—				—			—			—			—			2,100
Accretion of discount on asset retirement obligations		9				44			29			74			110			161
General and administrative expense		293				6,165			3,478			6,205			9,534			6,096
Total operating expense		1,581				13,139			5,845			10,748			21,762			18,028
Income (Loss) from Operations		2,131				(6,814	)		(2,065	)		(5,831	)		(4,066	)		(4,960	)
Other Income (Expense):
Interest and other income		—				1			1			29			204			29
Bond issuance amortization		—				—			—			—			(200	)		(57	)
Change in fair value of derivative liability		—				—			—			359			—			(462	)
Change in fair value of warrant liability		—				(763	)		(1,177	)		—			(763	)		—
Unrealized gain (loss) on investment in Cross Border Resources, Inc. warrants		899				282			494			(1,304	)		—			—
Equity in earnings (losses) of Cross Border Resources, Inc.		—				(316	)		(448	)		(332	)		—			—
Gain on consolidation of Cross Border Resources, Inc.		—				—			—			736			—			—
Interest expense		(228	)			(2,097	)		(1,461	)		(2,310	)		(2,501	)		(2,496	)
Realized gain on derivatives		—				—			—			17			844			259
Impairment on debentures		—				—			—			(503	)		—			(503	)
Impairment on note receivable		—				(2,725	)		(2,725	)		(856	)		(2,725	)		—
Total Other Income (Expense)		671				(5,618	)		(5,316	)		(4,164	)		(5,141	)		(3,230	)
				��
Income (Loss) Before Income Taxes		2,802				(12,432	)		(7,381	)		(9,995	)		(9,207	)		(8,190	)
Income tax provision		—				—			—			—			—			—
Net Income (Loss)		2,802				(12,432	)		(7,381	)		(9,995	)		(9,207	)		(8,190	)
Net income attributable to noncontrolling interest		—				—			—			344			—			—
Net income (loss) attributable to Red Mountain Resources, Inc.	$	2,802			$	(12,432	)	$	(7,381	)	$	(10,339	)	$	(9,207	)	$	(8,190	)
Basic and diluted net income (loss) per common share	$	0.10			$	(0.17	)	$	(0.11	)	$	(0.10	)	$	(0.11	)	$	(0.08	)
Basic and diluted weighted average common shares outstanding		27,000				73,775			70,659			93,801			89,513			104,436

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	Historical
	As of May 31,				As of February 28, 2013
	2011		2012
BALANCE SHEET DATA:					(unaudited)
Cash and cash equivalents	$	121	$	168	$	2,780
Oil and natural gas properties, net		8,815		23,680		70,307
Total assets		13,616		35,052		85,030
Line of credit		2,003		1,787		18,500
Total liabilities		11,263		14,732		39,342
Stockholders’ equity		2,353		20,320		45,688

	Historical
	Year Ended May 31,						Nine Months Ended February 28,
	2011			2012			2012			2013
CASH FLOW DATA:							(unaudited)
Net cash provided by (used in) operating activities	$	1,716		$	(1,194	)	$	(1,803	)	$	(5,036	)
Net cash used in investing activities		(3,604	)		(18,267	)		(12,539	)		(178	)
Net cash provided by financing activities		2,009			19,508			15,143			7,826

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SUMMARY RESERVES AND HISTORICAL

AND PRO FORMA OPERATING DATA

The following tables present summary data with respect to our estimated proved reserves and historical and pro forma 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 May 31, 2013
Estimated proved reserve data (1)(2)	Oil (MBbls)		Natural Gas (MMcf)		Total (MBoe)
Proved developed producing reserves		867		4,998		1,700
Proved developed nonproducing reserves		150		322		203
Proved undeveloped reserves		1,304		2,041		1,644
Total proved reserves		2,321		7,361		3,547

(1) Prices used are based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the period June 2012 through May 2013. For oil volumes, the average NYMEX spot price is $90.87 per Bbl. For natural gas volumes, the average Henry Hub spot price is $3.31 per MMBtu. The oil price of $82.89 per barrel is adjusted for quality, transportation fees and a regional price differential and the natural gas price of $5.08 per MMBtu is adjusted for energy content, transportation fees and a regional price differential. The adjusted oil 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

	Historical								Pro Forma
	Fiscal Year Ended,				Nine Months Ended,				Nine Months  Ended February 28, 2013
	May 31, 2011		May 31, 2012		February 29, 2012		February 28, 2013 (1)
Net production sold
Oil (Bbl)		—		37,004		13,968		43,754		126,807
Natural gas (Mcf)		900,332		795,659		652,488		432,810		646,999
Total (Boe) (2)		150,055		169,614		122,716		115,889		234,640
Total (Boe/d) (3)		411		465		450		425		859
Average sales prices
Oil ($/Bbl)	$	—	$	93.97	$	95.11	$	79.23	$	85.26
Natural gas ($/Mcf)		4.12		3.58		3.57		3.13		3.85
Total average price ($/Boe)	$	24.74	$	37.29	$	30.80	$	42.43	$	57.86

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

(2) Includes immaterial amounts of natural gas liquids.

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

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RISK FACTORS

Investing in our securities involves a high degree of risk. In addition to the other information contained in this prospectus supplement 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 our common 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

We currently do not have sufficient funds for our planned exploration or development activities for fiscal 2014 and will need to raise additional capital.

The oil and natural gas industry is capital intensive. We make and expect to continue to make significant capital expenditures in our business for the exploration, development, production and acquisition of oil and natural gas reserves. Improvement in commodity prices may result in an increase in our actual capital expenditures.

We plan to spend between $35.0 million and $45.0 million during fiscal 2014 to drill and complete wells or re-enter and complete wells, most of which will be spent in the Permian Basin. We currently do not have sufficient funds for our planned exploration or development activities for fiscal 2014 and will need to raise between $10.8 million and $20.8 million of gross proceeds from this offering and our concurrent Units offering or from other sources. If we are unable to finance our operations on acceptable terms or at all, we may be forced to curtail or suspend our planned exploration and development activities and our business, financial condition and results of operations may be materially and adversely affected.

Our cash flows from operations and access to capital are subject to a number of variables, including:

• our proved reserves;

• the level of oil and natural gas we are able to produce from existing wells;

• the prices at which our oil and natural gas are sold;

• our ability to acquire, locate and produce new reserves; and

• the ability of our banks to lend.

Debt financing could lead to:

• a substantial portion of operating cash flow being dedicated to the payment of principal and interest;

• us being more vulnerable to competitive pressures and economic downturns; and

• restrictions on our operations, including our ability to pay dividends.

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If sufficient capital resources are not available, we might be forced to cease operations entirely, curtail developmental and exploratory drilling and other activities or be forced to sell some assets on an untimely or unfavorable basis, which would have a material adverse effect on our business, financial condition and results of operations.

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. 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. The Credit Agreement also requires us to maintain specified financial ratios. 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.

We were not in compliance with certain financial covenants in the Credit Agreement for the three months ended February 28, 2013. On May 2, 2013, we entered into an amendment to the Credit Agreement, which waived the non-compliance and amended certain financial ratios in the Credit Agreement to become effective starting May 31, 2013. As a result, as of May 2, 2013, we are no longer in default under the Credit Agreement.

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

In the event of a default and acceleration of indebtedness under the Credit Facility, our business, financial condition and results of operations may be materially and adversely affected.

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 of $12.4 million and $10.0 million during the fiscal year ended May 31, 2012 and the nine months ended February 28, 2013, respectively. As a result, there is only limited historical financial and operating information available upon which to base your evaluation of our performance.

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

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

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

Our producing properties are geographically concentrated in the Permian Basin of Southeast New Mexico and West Texas. At May 31, 2013, approximately 89% of our proved reserves were concentrated in this area. Additionally, for the nine months ended February 28, 2013, approximately 89.6% of our pro forma combined revenues were concentrated in this area. As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, processing or transportation capacity constraints, market limitations, water shortages or other drought related conditions or interruption of the processing or transportation of oil, natural gas or natural gas liquids.

In addition to the geographic concentration of our producing properties described above, at May 31, 2013, approximately (i) 29% of our proved reserves were attributable to the Brushy Canyon formation in the Madera Prospect; and (ii) 15% of our proved reserves were attributable to the San Andres formation in the Tom Tom prospect. This concentration of assets within a small number of producing horizons exposes us to additional risks, such as changes in field-wide rules and regulations that could cause us to permanently or temporarily shut-in all of our wells within a field.

A substantial or extended decline in oil and natural gas prices may adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments.

The price we receive for our oil and natural gas will heavily influence our revenue, profitability, access to capital and future rate of growth. Oil and natural gas are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil and natural gas have been volatile. These markets will likely continue to be volatile in the future. The prices we receive for our production depend on numerous factors beyond our control. These factors include the following:

• worldwide and regional economic conditions impacting the global supply and demand for oil and natural gas;

• the price and quantity of imports of foreign oil and natural gas;

• the actions of the Organization of Petroleum Exporting Countries, or OPEC, and other state-controlled oil companies relating to oil and natural gas price and production control;

• political conditions in or affecting other oil-producing and natural gas-producing countries, including the current conflicts in the Middle East and conditions in South America and Russia;

• the level of global oil and natural gas inventories;

• localized supply and demand fundamentals;

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• the availability of refining capacity;

• price and availability of transportation and pipeline systems with adequate capacity;

• weather conditions and natural disasters;

• governmental regulations;

• speculation as to the future price of oil and the speculative trading of oil and natural gas futures contracts;

• price and availability of competitors’ supplies of oil and natural gas;

• energy conservation and environmental measures;

• technological advances affecting energy consumption;

• the price and availability of alternative fuels and energy sources; and

• domestic and international drilling activity.

Declines in oil and natural gas prices may materially adversely affect our financial condition, liquidity, and ability to finance planned capital expenditures and results of operations and may reduce the amount of oil and natural gas that we can produce economically. There can be no assurance that the prices of oil and natural gas will increase in the future. If oil and natural gas prices decline, (i) our net cash flow attributable to current production will decline; (ii) our exploration and development activity may decline as some investments may become uneconomic and are either delayed or eliminated, and (iii) the value of proved developed, producing reserves and proved undeveloped reserves could decline. It is impossible to predict future oil and natural gas price movements, and declines in oil and natural gas prices could have a material adverse effect on our liquidity and financial condition.

Properties that we acquire may not produce as projected, and we may be unable to accurately predict reserve potential, identify liabilities associated with the properties or obtain protection from sellers against such liabilities.

As part of our growth strategy, we intend to acquire additional interests in oil and natural gas properties. Any future acquisitions will require an assessment of recoverable reserves, title, future oil and natural gas prices, operating costs, potential environmental hazards and liabilities, potential tax and Employee Retirement Income Security Act liabilities, and other liabilities and other similar factors. Generally, it is not feasible for us to review in detail every individual property involved in an acquisition, and our review efforts are normally focused on the higher-valued properties. Even a detailed review of properties and records may not reveal existing or potential problems, nor will it permit us to become sufficiently familiar with the properties to assess fully their deficiencies and capabilities. We do not inspect every well that we acquire. Potential problems, such as deficiencies in the mechanical integrity of equipment or environmental conditions that may require significant remedial expenditures, are not necessarily observable even when we inspect a well. Any unidentified problems could result in material liabilities and costs that negatively impact our financial condition and results of operations.

Even if we are able to identify problems with an acquisition, the seller may be unwilling or unable to provide effective contractual protection or indemnity against all or part of these problems. Even if a seller agrees to provide indemnity, the indemnity may not be fully enforceable and may be limited by floors and caps on such indemnity. In addition, we may acquire oil and natural gas properties that contain commercially productive reserves which are less than predicted. Any of these factors could have a material adverse effect on our results of operations and reserve growth.

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Our failure to successfully identify, complete and integrate future acquisitions of properties or businesses could reduce our earnings and slow our growth.

There is intense competition for acquisition opportunities in our industry. Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions. Our ability to complete acquisitions is dependent upon, among other things, our ability to obtain debt and equity financing and, in some cases, regulatory approvals. Further, these acquisitions may be in geographic regions in which we do not currently operate, which could result in unforeseen operating difficulties and difficulties in coordinating geographically dispersed operations, personnel and facilities. In addition, if we enter into new geographic markets, we may be subject to additional and unfamiliar legal and regulatory requirements. Compliance with regulatory requirements may impose substantial additional obligations on us and our management, cause us to expend additional time and resources in compliance activities and increase our exposure to penalties or fines for non-compliance with such additional legal requirements. Completed acquisitions could require us to invest further in operational, financial and management information systems and to attract, retain, motivate and effectively manage additional employees. The inability to effectively manage the integration of acquisitions could reduce our focus on subsequent acquisitions and current operations, which, in turn, could negatively impact our earnings and growth. Our financial position and results of operations may fluctuate significantly from period to period, based on whether or not significant acquisitions are completed in particular periods.

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

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

• the timing and amount of capital expenditures;

• the operators’ expertise and financial resources;

• the approval of other participants in drilling wells; and

• the selection of suitable technology.

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

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

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

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

Our future financial condition and results of operations will depend on the success of our acquisition, exploitation, development and production activities. Our oil and natural gas exploration and production activities are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially productive oil or natural gas reservoirs. Our decisions to acquire, explore, develop or otherwise exploit drilling locations or properties will depend in part on the evaluation of data obtained through geophysical and geological

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analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. In addition, our cost of drilling, completing and operating wells is often uncertain before drilling commences. Overruns in budgeted expenditures are common risks that can make a particular project uneconomical. Further, many factors may curtail, delay or cancel our scheduled drilling projects, including the following:

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

• facility or equipment malfunctions;

• unexpected operational events;

• pressure or irregularities in geological formations;

• adverse weather conditions, such as flooding;

• reductions in oil and natural gas prices;

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

• proximity to and capacity of transportation facilities;

• title problems;

• limitations in the market for oil and natural gas; and

• costs and availability of drilling rigs, equipment, supplies, personnel and oilfield services.

Even if drilled, our completed wells may not produce reserves of oil or natural gas that are commercially productive or that meet our earlier estimates of economically recoverable reserves. A productive well may become uneconomic if water or other deleterious substances are encountered, which impair or prevent the production of oil and/or natural gas from the well. Our overall drilling success rate or our drilling success rate for activity within a particular project area may decline. Unsuccessful drilling activities could result in a significant decline in our production and revenues and materially harm our operations and financial condition by reducing our available cash and resources.

Reserve estimates depend on many assumptions that may turn out to be inaccurate.

The calculation of reserves and estimating reserves are inherently imprecise. The accuracy of any reserve estimate is a function of the quality of available data, engineering interpretation and judgment and the assumptions used regarding the quantities of recoverable oil and natural gas and the future prices of oil and natural gas. Petroleum engineers consider many factors and make many assumptions in estimating reserves. Those factors and assumptions include, but are not limited to, the following: historical production from the area compared with production rates from similarly situated producing areas; the effects of governmental regulation; assumptions about future commodity prices, production and taxes; the availability of enhanced recovery techniques; and relationships with landowners, working interest partners, pipeline companies and others.

Any material inaccuracies in our reserve estimates or underlying assumptions could materially affect the quantities and present values of our reserves. This prospectus supplement contains estimates of our proved oil and natural gas reserves. The process of estimating oil and natural gas reserves is complex. It requires interpretations of available technical data and various assumptions, including assumptions relating to economic factors. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities of reserves 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.

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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 that we may report. In addition, we may adjust estimates of proved reserves 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.

Approximately 46% of our total estimated proved reserves as of May 31, 2013 were classified as proved undeveloped and may not be ultimately developed or produced.

As of May 31, 2013, approximately 46% of our total estimated proved reserves were undeveloped. Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations. The future drilling of proved undeveloped reserves is highly dependent upon our ability to fund our capital expenditures, which we estimate will be approximately $35.0 million to $45.0 million for fiscal 2014. We cannot be sure that these estimated costs are accurate, and we may be unable to obtain sufficient capital. Further, our drilling efforts may be delayed or unsuccessful, and actual reserves may prove to be less than current reserve estimates, which could have a material adverse effect on our financial condition, future cash flows and results of operations.

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

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

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

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

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

Our future success will depend on our ability to find, develop or acquire additional reserves that are commercially productive. If we are unable to replace reserves through drilling or acquisitions, our level of production and cash flows will be adversely affected. In general, production from oil and natural gas properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. Our total proved reserves decline as reserves are produced unless we conduct other successful exploration and development activities or acquire properties containing proved reserves, or both. Our ability to make the necessary capital investment to maintain or expand our asset base of oil and natural gas reserves would be impaired to the extent

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cash flow from operations is reduced and external sources of capital become limited or unavailable. We may not be successful in exploring for, developing or acquiring additional reserves. We also may not be successful in raising funds to acquire, explore or develop additional reserves.

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

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

At May 31, 2013, of our total undeveloped leasehold acreage, 24.4% is currently not held by production and will expire during fiscal 2015 or fiscal 2016 unless production in paying quantities is established and maintained on units containing these leases during their primary terms or we obtain extensions of the leases. If our leases expire, we will lose our right to develop the related properties.

Our drilling plans for these areas are subject to change based upon various factors, including factors that are beyond our control. Such factors include drilling results, oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, gathering system and pipeline transportation constraints, and regulatory approvals.

Our operations could be impacted by burdens and encumbrances on title to our properties.

Our leasehold acreage may be subject to existing oil and natural gas leases, liens for current taxes and other burdens, including other mineral encumbrances and restrictions customary in the oil and natural gas industry, that should not materially interfere with the use or otherwise affect the value of such properties. However, we cannot guarantee that we have or will have clear and unobstructed title to leases or other rights assigned to us. We also cannot guarantee that the mineral encumbrances and restrictions mentioned above will not materially interfere with the use of or affect the value of leasehold acreage. Any cloud on the title of the working interests, leases and other rights owned by us could have a material adverse effect on our operations.

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

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

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

Market conditions, the unavailability of satisfactory oil and natural gas transportation or the remote location of our drilling operations may restrict our access to oil and natural gas markets or delay production. The availability of a ready market for oil and natural gas production depends on a number of factors, including the demand for and supply of oil and natural gas, the proximity of reserves to pipelines or trucking and terminal facilities and the availability of trucks and other transportation equipment. We may be required to shut-in wells

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or delay initial production for lack of a viable market or because of inadequacy or unavailability of pipeline or gathering system capacity. When that occurs, we will be unable to realize revenue from those wells until the production can be tied to a gathering system. This can result in considerable delays from the initial discovery of a reservoir to the actual production of the oil and natural gas and realization of revenues.

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

We are required to obtain permits from one or more governmental agencies in order to perform drilling and completion activities, including hydraulic fracturing. Such permits are typically required by state agencies, but can also be required by federal and local governmental agencies. As with all governmental permitting processes, there is a degree of uncertainty as to whether a permit will be granted, the time it will take for a permit to be issued, and the conditions which may be imposed in connection with the granting of the permit. Hydraulic fracturing activities, which we estimate will represent approximately 40% of our forecasted development costs for fiscal 2014, has been particularly scrutinized. New York, for example, recently issued a moratorium currently in effect on the issuance of permits for inland drilling and completion activities. Subject to an Executive Order issued by Governor Paterson on December 13, 2010, the New York Department of Environmental Conservation will not issue permits for drilling and completion activities until it completes a final environmental impact study following public comment. Texas is not currently considering such a measure. In addition, on May 17, 2012, the Governor of Vermont signed a bill banning hydraulic fracturing in the state of Vermont. To date, Vermont is the first and only state to ban hydraulic fracturing. If we are unable to obtain the necessary permits for our operations, it could have a material adverse effect on our results of operations and profitability.

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

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

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

Our business and operations are subject to and impacted by a wide array of federal, state, and local laws and regulations on the exploration for and development, production, and marketing of oil and natural gas, the operation of oil and natural gas wells, taxation, and environmental and safety matters. Many laws and regulations require drilling permits and govern the spacing of wells, rates of production, prevention of waste and other matters. From time to time, regulatory agencies have imposed price controls and limitations on production in

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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 “CAA”), the Federal Water Pollution Control Act and the Oil Pollution Act, as well as by regulations promulgated pursuant to these actions.

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

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

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

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

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

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

• evacuation of personnel and curtailment of operations;

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

• inability to deliver materials to worksites; and

• damage to pipelines and other transportation facilities.

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

Operating hazards, natural disasters or other interruptions of our operations could result in potential liabilities, which may not be fully covered by our insurance.

The oil and natural gas business generally, and our operations specifically, are subject to certain operating hazards such as:

• accidents resulting in serious bodily injury and the loss of life or property;

• liabilities from accidents or damage by our equipment;

• well blowouts;

• cratering (catastrophic failure);

• explosions;

• uncontrollable flows of oil, natural gas or well fluids;

• abnormally pressurized formations;

• fires;

• reservoir damage;

• oil spills;

• pollution and other damage to the environment; and

• releases of toxic gas.

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

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

We may not be able to keep pace with technological developments in our industry.

The oil and natural gas industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. As others use or develop new technologies, we may be placed at a competitive disadvantage or competitive pressures may force us to implement those new technologies at substantial costs. In addition, other oil and natural gas companies may have greater financial, technical and personnel resources that allow them to enjoy technological advantages and may in the future allow them to implement new technologies before we can. We may not be able to respond to these competitive

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pressures and implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use now or in the future were to become obsolete or if we are unable to use the most advanced commercially available technology, our business, financial condition and results of operations could be materially adversely affected.

Competition in the oil and natural gas industry is intense, and many of our competitors have resources that are greater than ours.

We operate in a highly competitive environment for developing and acquiring properties, marketing oil and natural gas and securing equipment and trained personnel. As a relatively small oil and natural gas company, many of our competitors, major and large independent oil and natural gas companies, possess and employ financial, technical and personnel resources substantially greater than ours. Those companies may be able to develop and acquire more prospects and productive properties than our financial or personnel resources permit. Our ability to acquire additional prospects and discover reserves in the future will depend on our ability to evaluate and select suitable properties and execute our exploration and development activities in a highly competitive environment. Also, there is substantial competition for capital available for investment in the oil and natural gas industry. Larger competitors may be better able to withstand sustained periods of unsuccessful drilling and absorb the burden of changes in laws and regulations more easily than we can, which would adversely affect our competitive position. We may not be able to compete successfully in the future in developing reserves, acquiring prospective oil and natural gas properties and reserves, attracting and retaining highly skilled personnel and raising additional capital.

We may be unable to diversify our operations to avoid any downturn in the oil and natural gas industry.

Because of our limited financial resources, it is unlikely that we will be able to diversify our operations the way companies with greater financial resources are able to do. Our inability to diversify our activities will subject us to economic fluctuations within the oil and natural gas industry and therefore increase the risks associated with our operations as limited to one industry.

Certain federal income tax deductions currently available with respect to oil and natural gas exploration and development may be eliminated as a result of future legislation.

President Obama’s proposed Fiscal Year 2014 Budget includes proposed legislation that would, if enacted into law, make significant changes to United States tax laws, including the elimination or postponement of certain key United States federal income tax incentives currently available to oil and natural gas exploration and production companies. These changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and natural gas properties, (ii) the elimination of the current deduction for intangible drilling and development costs, (iii) the elimination of the deduction for certain domestic production activities and (iv) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could become effective. The passage of any legislation as a result of these proposals or any other similar changes in United States federal income tax laws could eliminate certain tax deductions that are currently available with respect to oil and natural gas exploration and development, which could have a material adverse effect on our business, financial condition, operations and cash flows.

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

Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons from tight formations. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The process is typically

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regulated by state oil and gas commissions. However, the 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 December 2011, the Railroad Commission of Texas finalized regulations requiring public disclosure of all the chemicals in fluids used in the hydraulic fracturing process. Local ordinances or other regulations may regulate or prohibit the performance of well drilling in general and hydraulic fracturing in particular. If new laws or regulations that significantly restrict or regulate hydraulic fracturing are adopted, such legal requirements could cause project delays and make it more difficult or costly for us to perform fracturing to stimulate production from a formation. These delays or additional costs could adversely affect the determination of whether a well is commercially viable. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that we are ultimately able to produce in commercial quantities.

In addition, a number of federal agencies are analyzing, or have been requested to review, a variety of environmental issues associated with hydraulic fracturing. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices, and a committee of the United States House of Representatives has conducted an investigation of hydraulic fracturing practices. On November 3, 2011, the EPA released its Plan to Study the Potential Impacts of Hydraulic Fracturing on Drinking Water Resources. The study will include both analysis of existing data and investigative activities designed to generate future data. The EPA issued a progress report in December 2012, and expects to release a final report for public comment and peer review in 2014. Moreover, the EPA announced on October 20, 2011 that it is also launching a study regarding wastewater resulting from hydraulic fracturing activities and currently plans to propose standards by 2014 that such wastewater must meet before being transported to a treatment plant. On August 16, 2012, the EPA published final rules under the CAA that, among other things, imposed new source performance standards (“NSPS”) for completions of hydraulically fractured natural gas wells, requiring the use of reduced emission completion techniques.

Our business exposes us to liability and extensive regulation on environmental matters, which could result in substantial expenditures.

Our operations are subject to numerous U.S. federal, state and local laws and regulations relating to the protection of the environment, including those governing the discharge of materials into the water and air, the generation, management and disposal of hazardous substances and wastes and the clean-up of contaminated sites. We could incur material costs, including clean-up costs, fines and civil and criminal sanctions, injunctive relief and third-party claims for property damage and personal injury as a result of violations of, or liabilities under, environmental laws and regulations. Such laws and regulations not only expose us to liability for our own activities, but may also expose us to liability for the conduct of others or for actions by us that were in compliance with all applicable laws at the time those actions were taken.

For example, on February 11, 2013, the United States Department of the Interior 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 $2.1 million during fiscal 2014 and 2015 to correct environmental issues on these fields.

In addition, we could incur substantial expenditures complying with environmental laws and regulations, including future environmental laws and regulations which may be more stringent, for example, the regulation of greenhouse gas (“GHG”) emissions under the federal CAA, or state or regional regulatory programs. Regulation of GHG emissions by the EPA, or various states in the United States in areas in which we conduct business, could have an adverse effect on our operations and demand for our oil and natural gas production. Moreover, the EPA has shown a general increased scrutiny on the oil and gas industry through its GHG, CAA and SDWA regulations.

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In August 2012, the EPA adopted rules that subject oil and natural gas production, processing, transmission, and storage operations to regulation under the New Source Performance Standards, or NSPS, and National Emission Standards for Hazardous Air Pollutants, or NESHAP, programs. The rule includes NSPS standards for completions of hydraulically fractured gas wells and establishes specific new requirements for emissions from compressors, controllers, dehydrators, storage vessels, natural gas processing plants and certain other equipment. The final rule became effective October 15, 2012; however, a number of the requirements did not take immediate effect. The final rule establishes a phase-in period to allow for the manufacture and distribution of required emissions reduction technology. During the first phase, ending December 31, 2014, owners and operators of gas wells must either flare their emissions or use emissions reduction technology called “green completions” technologies already deployed at wells. On or after January 1, 2015, all newly fractured gas wells will be required to use green completions. Controls for certain storage vessels and pneumatic controllers may phase-in over one year beginning on the date the final rule is published in the Federal Register, while certain compressors, dehydrators and other equipment must comply with the final rule immediately or up to three years and 60 days after publication of the final rule, depending on the construction date and/or nature of the unit. We continue to evaluate the EPA’s final rule, as it may require changes to our operations, including the installation of new emissions control equipment. These standards, as well as any future laws and their implementing regulations, may require us to obtain pre-approval for the expansion or modification of existing facilities or the construction of new facilities expected to produce air emissions, impose stringent air permit requirements, or utilize specific equipment or technologies to control emissions. Our failure to comply with these requirements could subject us to monetary penalties, injunctions, conditions or restrictions on operations and, potentially, criminal enforcement actions. These new requirements may result in increased operating and compliance costs, increased regulatory burdens and delays in our operations.

The EPA’s implementation of climate change regulations could result in increased operating costs and reduced demand for our oil and natural gas production.

Although federal legislation regarding the control of emissions of GHGs, for the present, appears unlikely, the EPA has been implementing regulatory measures under existing CAA authority and some of those regulations may affect our operations. GHGs are certain gases, including carbon dioxide, a product of the combustion of natural gas, and methane, a primary component of natural gas, that may be contributing to the warming of the Earth’s atmosphere, resulting in climatic changes. These GHG regulations could require us to incur increased operating costs and could have an adverse effect on demand for our oil and natural gas production.

On June 3, 2010, the EPA published its so-called GHG tailoring rule that will phase in federal prevention of significant deterioration permit requirements for new sources and modifications, and Title V operating permits for all sources, that have the potential to emit specific quantities of GHGs. Those permitting provisions, should they become applicable to our operations, could require controls or other measures to reduce GHG emissions from new or modified sources, and we could incur additional costs to satisfy those requirements. In October 2009, the EPA issued a final rule requiring the reporting of GHG emissions from specified large GHG emission sources in the U.S., including natural gas liquids fractionators and local natural gas/distribution companies, beginning in 2011 for emissions occurring in 2010. In November 2010, the EPA published a final rule expanding the GHG reporting rule to include onshore oil and natural gas production, processing, transmission, storage and distribution facilities. This rule requires reporting of GHG emissions from such facilities on an annual basis, with reporting beginning in 2012 for emissions occurring in 2011. Finally, on March 27, 2012, the EPA issued a proposed rule establishing carbon pollution standards for new fossil-fuel-fired electric utility generating units. The proposed rule underwent an extended public comment process, which concluded on June 25, 2012. The EPA is presently evaluating the public comments and is expected to issue a final rule at a later date. The EPA plans to implement GHG emissions standards for refineries at a later date.

We have identified material weaknesses in our internal control over financial reporting. These material weaknesses, if not corrected, could affect the reliability of our financial statements and have other adverse consequences.

Under Section 404 of the Sarbanes-Oxley Act of 2002, we are required to furnish a report by our management on internal control over financial reporting. This report must contain, among other matters, an

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assessment of the effectiveness of our internal control over financial reporting, including a statement as to whether or not our internal control over financial reporting is effective. This assessment must include disclosure of any material weaknesses in our internal control over financial reporting identified by our management.

We have identified material weaknesses in our internal control over financial reporting as of May 31, 2012 relating primarily to the (i) lack of accounting expertise to appropriately apply GAAP for complex or non-recurring transactions and (ii) lack of sufficient accounting personnel to properly design and implement internal control over financial reporting. Failure to have effective internal controls could lead to a misstatement of our financial statements. If, as a result of deficiencies in our internal controls, we cannot provide reliable financial statements, our business decision process may be adversely affected, our business and operating results could be harmed, investors could lose confidence in our reported financial information, the market price of our securities could decrease and our ability to obtain additional financing, or additional financing on favorable terms, could be adversely affected. In addition, failure to maintain effective internal control over financial reporting could result in investigations or sanctions by regulatory authorities.

We intend to take further action to remediate the material weaknesses and improve the effectiveness of our internal control over financial reporting. However, we can give no assurances that the measures we may take will remediate the material weaknesses identified or that any additional material weaknesses will not arise in the future due to our failure to implement and maintain adequate internal control over financial reporting. In addition, even if we are successful in strengthening our controls and procedures, those controls and procedures may not be adequate to prevent or identify irregularities or ensure the fair presentation of our financial statements included in our periodic reports filed with the SEC.

Our business may suffer if we lose key personnel.

We depend to a large extent on the services of our officers, including Alan Barksdale, our President and Chief Executive Officer, Michael Uffman, our Chief Financial Officer, Hilda Kouvelis, our Chief Accounting Officer, and Tommy Folsom, Executive Vice President and Director of Exploration and Production for RMR Operating. These individuals have extensive experience and expertise in evaluating and analyzing producing oil and natural gas properties and drilling prospects, maximizing production from oil and natural gas properties and developing and executing financing strategies. Although we have employment agreements with Ms. Kouvelis and Mr. Folsom, we do not currently have an employment agreement with Messrs. Barksdale or Uffman and they are free to terminate their employment with us at any time and compete with us immediately thereafter. The loss of any of these individuals could have a material adverse effect on our operations. We do not maintain key-man life insurance with respect to any management personnel. Our success will be dependent on our ability to continue to retain and utilize skilled technical personnel.

Our officers and directors are engaged in other business activities and conflicts of interest may arise in their daily activities which may not be resolved in our favor.

Various actual and potential conflicts of interest may exist between us and our officers and directors. Our officers and directors have other business interests to which they devote their attention, and we expect they will continue to do so, although our officers will devote the majority of their business time to our affairs. As a result, conflicts of interest or potential conflicts of interest may arise from time to time that can be resolved only through the officers or directors exercising such judgment as is consistent with fiduciary duties to their other business interests and to us. These conflicts of interest may not be resolved in our favor.

Compliance with changing regulation of corporate governance and public disclosure will result in additional expenses and pose challenges for our management.

Changing laws, regulations and standards relating to corporate governance and public disclosure, including the Dodd-Frank Act and the rules and regulations promulgated thereunder, the Sarbanes-Oxley Act and SEC regulations, have created uncertainty for public companies and significantly increased the costs and risks

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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.

There can be no assurance that we will be able to file our Form 10-K within the deadline to remain timely in our filings.

Our Form 10-K is due on August 29, 2013. We expect that we will be unable to timely file the Form 10-K because we need additional time to prepare and review our fiscal year 2013 financial statements due to purchase price accounting and consolidation issues related to Cross Border. As a result, we expect to file a Notification of Late Filing on Form 12b-25. There can be no assurance that we will be able to file our Form 10-K within the deadline, including any such extensions to remain timely in our filings. If we are not timely in our filings, we may be unable to sell securities utilizing our $150.0 million shelf registration statement, and the price of our common stock and Series A preferred stock may decline.

Risks Related to This Offering

The price of our common stock may fluctuate significantly, which could negatively affect us and holders of our common stock.

The trading price of our common stock may fluctuate significantly in response to a number of factors, many of which are beyond our control. For instance, if our financial results are below the expectations of securities analysts and investors, the market price of our common stock could decrease, perhaps significantly. Other factors that may affect the market price of our common stock include:

• actual or anticipated fluctuations in our quarterly results of operations;

• liquidity;

• sales of common stock by our stockholders;

• changes in oil and natural gas prices;

• changes in our cash flow from operations or earnings estimates;

• publication of research reports about us or the oil and natural gas exploration and production industry generally;

• competition for, among other things, capital, acquisition of reserves, undeveloped land and skilled personnel;

• increases in market interest rates which may increase our cost of capital;

• changes in applicable laws or regulations, court rulings and enforcement and legal actions;

• changes in market valuations of similar companies;

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• adverse market reaction to any indebtedness we incur in the future;

• additions or departures of key management personnel;

• actions by our stockholders;

• commencement of or involvement in litigation;

• news reports relating to trends, concerns, technological or competitive developments, regulatory changes and other related issues in our industry;

• speculation in the press or investment community regarding our business;

• political conditions in oil and natural gas producing regions;

• general market and economic conditions; and

• domestic and international economic, legal and regulatory factors unrelated to our performance.

In addition, the U.S. securities markets have experienced significant price and volume fluctuations. These fluctuations often have been unrelated to the operating performance of companies in these markets. Our common stock is traded on the OTCQB, which is subject to greater volatility than a national exchange or quotation system. This volatility may be caused by a variety of factors, including the lack of readily available price quotations, the absence of consistent administrative supervision of bid and ask quotations, lower trading volume, and market conditions.

Market fluctuations and broad market, economic and industry factors may negatively affect the price of our common stock, regardless of our operating performance. Any volatility or a significant decrease in the market price of our common stock could also negatively affect our ability to make acquisitions using common stock. Further, if we were to be the object of securities class action litigation as a result of volatility in our common stock price or for other reasons, it could result in substantial costs and diversion of our management’s attention and resources, which could negatively affect our financial results.

Offers or availability for sale of a substantial number of shares of our common stock by our shareholders may cause the market price of our common stock to decline.

On May 3, 2013, we filed a resale shelf registration statement on a Form S-3 covering 15,438,805 shares of common stock with the SEC. The ability of our shareholders to sell shares of our common stock in the public market, or upon the expiration of any statutory holding period under Rule 144 of the Securities Act of 1933, as amended (the “Securities Act”), could create a circumstance commonly referred to as an “overhang,” which could cause the market price of our common stock to fall. The existence of an overhang, whether or not sales have occurred or are occurring, could make it more difficult for us to raise additional financing through future sales of equity or equity-related securities at a time and price that we deem reasonable or appropriate. Additionally, we filed a universal shelf registration statement on Form S-3 on January 17, 2013, registering the possible issuance of $150.0 million of common stock, preferred stock, warrants and debt securities. Sales of a substantial number of shares of our common stock, or the perception that sales could occur, could adversely affect the market price of our common stock. In addition, these sales may be dilutive to existing shareholders.

The issuance of additional shares of our common stock or other equity securities will dilute all other stockholdings.

After this offering, we will have 138,211,731 shares of common stock outstanding, which amount excludes (i) 8,200,000 additional shares that are authorized for future issuance under our equity incentive plans; (ii) 13,010,324 additional shares that are issuable under warrants and (iii) 6,250,000 additional shares that may be issuable under warrants offered for sale as part of the concurrent stock Units offering. We may issue additional

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shares without any action or approval by our shareholders. The issuance of additional shares of our common stock or other equity securities, whether issued in connection with the exercise of stock options or otherwise, would result in dilution of the percentage ownership held by the investors who purchase our common stock in this offering.

Holders of our outstanding shares of Series A Preferred Stock have, and holders of any future outstanding shares of preferred stock will have, liquidation, dividend and other rights that are senior to the rights of the holders of our common stock and may restrict a takeover attempt that you may favor.

Our board of directors has the authority to designate and issue preferred stock with liquidation, dividend and other rights that are senior to those of our common stock. Our preferred stock, including our issued and outstanding shares of Series A Preferred Stock, as well as any other shares of preferred stock that may be issued in the future, would receive, upon our voluntary or involuntary liquidation, dissolution or winding up, before any payment is made to holders of our common stock, their liquidation preferences as well as any accrued and unpaid distributions. These payments would reduce the remaining amount of our assets, if any, available for distribution to holders of our common stock. Outstanding preferred stock may make a takeover or change in control of us more difficult.

Management will have broad discretion as to the use of the proceeds from this offering, and we may not use the proceeds effectively.

Our management will have broad discretion in the application of the net proceeds from this offering and could spend the proceeds in ways that do not improve our results of operations or enhance the value of our common stock. Our failure to apply these funds effectively could have a material adverse effect on our business and cause the trading price of our common stock to decline.

Limited trading volume in our common stock may contribute to price volatility.

As a relatively small company with a limited market capitalization, even if our shares are more widely disseminated, we are uncertain as to whether a more active trading market in our common stock will develop. As a result, relatively small trades may have a significant impact on the price of our common stock. In addition, because of the limited trading volume in our common stock and the price volatility of our common stock, you may be unable to sell your shares of common stock when you desire or at the price you desire. The inability to sell your shares in a declining market because of such illiquidity or at a price you desire may substantially increase your risk of loss.

Our common stock is subject to penny stock regulation.

Our shares are subject to the provisions of Section 15(g) and Rule 15g-9 of the Exchange Act, commonly referred to as the “penny stock” rule, which set forth certain requirements for transactions in penny stocks. The SEC generally defines penny stock to be any equity security that has a market price less than $5.00 per share, subject to certain exceptions. Rule 3a51-1 provides that any equity security is considered to be penny stock unless that security is: registered and traded on a national securities exchange meeting specified criteria set by the SEC; authorized for quotation on the NASDAQ Stock Market; issued by a registered investment company; excluded from the definition on the basis of price (at least $5.00 per share) or the registrant’s net tangible assets; or exempted from the definition by the SEC. Since our shares are deemed to be “penny stock”, trading in the shares will be subject to additional sales practice requirements on broker-dealers who sell penny stock to persons other than established customers and accredited investors.

FINRA Sales Practice requirements may also limit a stockholder’s ability to buy and sell our stock.

In addition to the “penny stock” rules described above, the Financial Industry Regulatory Authority (“FINRA”) has adopted rules that require that in recommending an investment to a customer, a broker-dealer must have reasonable grounds for believing that the investment is suitable for that customer. Prior to recommending speculative low priced securities to their non-institutional customers, broker-dealers must make

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reasonable efforts to obtain information about the customer’s financial status, tax status, investment objectives and other information. Under interpretations of these rules, FINRA believes that there is a high probability that speculative low priced securities will not be suitable for at least some customers. FINRA requirements make it more difficult for broker-dealers to recommend that their customers buy our common stock, which may have an adverse effect on the market for our shares.

We do not intend to pay dividends on our common stock in the future.

We have not paid dividends on our common stock and do not intend to pay dividends in the foreseeable future. The payment of cash dividends on our common stock in the future will be dependent on our revenues and earnings, if any, capital requirements and general financial condition and will be entirely within the discretion of our Board of Directors at such time. It is the present intention of our Board of Directors to retain earnings, if any, to fund our future growth, and there is no assurance we will ever pay dividends on our common stock in the future. As a result, any gain you will realize on our common stock will result solely from the appreciation of such common stock.

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CONCURRENT OFFERING

We are also offering concurrently, pursuant to a prospectus supplement dated August 21, 2013, up to 250,000 Units, including up to 22,223 Units in cancellation of up to $0.5 million principal amount of our indebtedness. This indebtedness consists of an unsecured subordinated promissory note, the proceeds of which were used to refinance existing debt, in the principal amount of $500,000 payable to Hyman Belzberg, William Belzberg and Caddo Management, Inc., which accrues interest at 12% per annum and matures on August 31, 2013 (the “Belzberg Note”). There is no assurance that all of the indebtedness will be cancelled in exchange for Units. The concurrent Units offering is being conducted on a best efforts basis and there is no assurance how many Units will be sold. The closing of the concurrent offering of Units is not conditioned on or subject to the closing of the common stock offering.

USE OF PROCEEDS

We intend to use the net proceeds from this offering for general corporate purposes, including to fund a portion of our fiscal 2014 drilling and development program. In addition, we may use up to $2.0 million of net proceeds to repay the Belzberg Note and a convertible promissory note payable to Personalversorge der Autogrill Schweiz AG in a principal amount of $1.5 million, which accrues interest at 10% per annum and matures on November 25, 2013. 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 and may be used to facilitate compliance with the financial covenants in the Credit Facility. Amounts repaid under our Credit Facility may be reborrowed.

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CAPITALIZATION

The following table presents a summary of our cash and cash equivalents and capitalization as of February 28, 2013:

• on an actual basis;

• on an as adjusted basis, giving effect to (i) gross proceeds from the sale of 3,529,412 shares of common stock in our May 2013 private placement at $0.85 per share; (ii) the issuance on May 3, 2013 of 575,306 shares of our common stock in exchange for shares of Cross Border common stock; (iii) an additional $1.3 million draw under the Credit Facility on May 23, 2013; (iv) the sale of 275,674 Units to the public for net proceeds of $5.7 million prior to August 15, 2013; and (v) the sale of 100,002 Units in cancellation of $2.3 million aggregate principal amount of our indebtedness in August 2013; and

• on a further adjusted basis, giving effect to (i) the sale of 11,500,000 shares of common stock offered to the public by this prospectus supplement and the accompanying prospectus, assuming net proceeds of $7.4 million, after deducting offering expenses payable by us, (ii) the sale of 227,777 Units offered in the concurrent Units offering, assuming net proceeds of $4.1 million, after deducting underwriting discounts and commissions and other offering expenses payable by us, (iii) the issuance of 22,223 Units offered in the concurrent Units offering in cancellation of $0.5 million principal amount of indebtedness under the Belzberg Note and the payment of accrued interest and fees thereon.

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.

	February 28, 2013
(in thousands)	Actual			As Adjusted			As Further Adjusted
Cash and cash equivalents	$	2,780		$	11,348	(1)	$	22,648	(1)
Debt
Line of credit (2)	$	18,500		$	19,800		$	19,800
Convertible notes payable, net of discount of $719 and $216		3,031			1,284			1,284
Notes payable		500			500			—
Series A Preferred Stock, net of discount (3)		—			6,612			11,012
Stockholders’ equity
Common stock		1			1			1
Stock subscription receivable		(100	)		(100	)		(100	)
Noncontrolling interest		5,756			5,289			5,289
Additional paid-in-capital		62,404			67,712			76,323
Accumulated deficit		(22,373	)		(22,373	)		(22,373	)
Total stockholders’ equity		45,688			50,259			59,140
Total capitalization	$	67,719		$	77,425		$	91,236

(1) As of August 15, 2013, we had $1.4 million in cash and cash equivalents.

(2) 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.

(3) The amounts shown as adjusted and as further adjusted are net of an original issue discount of $0.9 million and $1.6 million, respectively, and a discount for warrants of $1.8 million, and $3.1 million respectively.

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COMMON STOCK PRICE RANGE

Our common stock is quoted on the OTCQB under the symbol “RDMP.” The following table sets forth the range of high and low bid prices for our common stock for the periods indicated. The over-the-counter market quotations reflect inter-dealer prices, without retail mark-up, mark-down or commission and may not necessarily represent actual transactions.

	Price Range
	High		Low
Fiscal Year 2014:
First Quarter (through August 21, 2013)	$	0.89	$	0.55
Fiscal Year 2013:
Fourth Quarter	$	0.91	$	0.60
Third Quarter	$	0.95	$	0.76
Second Quarter	$	1.30	$	0.76
First Quarter	$	1.52	$	1.16
Fiscal Year 2012:
Fourth Quarter	$	1.57	$	1.40
Third Quarter	$	1.65	$	1.37
Second Quarter	$	1.68	$	1.27
First Quarter	$	1.37	$	1.24

The reported last sales price for our common stock on the OTCQB on August 21, 2013 was $0.74 per share. As of August 20, 2013, we had 126,711,731 shares of common stock outstanding, and our outstanding shares of common stock were held by 157 stockholder accounts of record.

DIVIDEND POLICY

We have not paid any cash dividends on our common stock to date. The payment of any dividends on our common stock is within the discretion of our Board of Directors. It is the present intention of the Board of Directors to retain all earnings for use in the business operations and, accordingly, the Board does not anticipate declaring any dividends on our common stock in the foreseeable future.

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UNAUDITED PRO FORMA COMBINED FINANCIAL INFORMATION

The following unaudited pro forma combined financial information reflects the historical results of Red Mountain as adjusted on a pro forma basis to give effect to Red Mountain’s acquisition of Cross Border.

On January 28, 2013, Red Mountain acquired 5,091,210 shares of common stock of Cross Border from a limited number of stockholders of Cross Border in exchange for the issuance of 10,182,420 shares of our common stock. The Acquisition was a step-acquisition in which we acquired an additional 31% of Cross Border’s outstanding common stock, increasing our ownership of Cross Border’s outstanding common stock from 47% to 78%. Prior to January 28, 2013, we accounted for our investment in Cross Border as an equity method investment. After January 28, 2013, we account for Cross Border as a consolidated subsidiary. Red Mountain incurred transaction expense of $0.8 million for the nine months ended February 28, 2013 and $0.6 million for the twelve months ended May 31, 2012 in connection with its acquisition of Cross Border.

Red Mountain’s fiscal year ends on May 31, and Cross Border’s fiscal year ends on December 31.

Red Mountain recorded the purchase price as follows:

Purchase Price:
Fair value of 20,542,009 shares of Red Mountain common stock exchanged for Cross Border common stock	$	18,282,388
Cash acquisition of Cross Border common stock		3,491,793
Acquisition of Cross Border note payable and accrued interest		697,039
Total consideration paid	$	22,471,220
Add: Estimated Fair Value of Liabilities Assumed:
Accounts payable	$	4,608,926
Asset retirement obligations		3,329,192
Environmental liability		2,100,000
Line of credit		8,750,000
Creditors payable		1,352,783
Accrued expense and other liabilities		114,692
Amount attributable to liabilities assumed		20,255,593
Noncontrolling interest		6,358,594
Total purchase price	$	49,085,407

Estimated Fair Value of Net Assets Acquired:
Cash	$	279,233
Accounts receivable		3,147,226
Prepaid and other current assets		450,615
Derivative assets		34,976
Other property and equipment		51,726
Proven oil and gas assets		19,959,000
Unproven oil and gas assets		25,108,307
Other long-term assets		54,324
Amount attributable to net assets acquired	$	49,085,407

Red Mountain’s historical consolidated balance sheet as of February 28, 2013 includes the consolidation of Cross Border, and accordingly, no unaudited pro forma combined balance sheet as of February 28, 2013 is presented. The Company has not finalized the determination of the fair values of the assets acquired and liabilities assumed for Cross Border and, therefore, the estimated fair values are subject to final adjustment.

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Red Mountain consolidated the results of operations of Cross Border for the one month period from January 28, 2013 to February 28, 2013. Accordingly, Red Mountain recorded a $2.0 million charge to accumulated deficit in its consolidated balance sheet for the two-month lag resulting from differences in its and Cross Border’s fiscal year ends and quarterly periods.

The unaudited pro forma combined statement of operations for the twelve months ended May 31, 2012 was derived from (i) our audited statement of operations for the fiscal year ended May 31, 2012 and (ii) the unaudited statement of operations of Cross Border for the twelve months ended June 30, 2012. Cross Border’s unaudited statement of operations for the twelve months ended June 30, 2012 was derived by using its audited results for the fiscal year ended December 31, 2011 and deducting its unaudited results for the interim six-month period ended June 30, 2011 and adding its unaudited results for the interim six-month period ended June 30, 2012.

The interim unaudited pro forma combined statement of operations for the nine months ended February 28, 2013 was derived from (i) our unaudited statement of operations for the nine months ended February 28, 2013 and (ii) the unaudited statement of operations for Cross Border for the seven months ended January 31, 2013. Cross Border’s results for the seven months ended January 31, 2013 were derived by using its audited results for the year ended December 31, 2012, deducting its unaudited results for the interim six-month period ended June 30, 2012 and adding its unaudited results for the one month ended January 31, 2013.

The historical consolidated statements of operations have been adjusted in the pro forma statements of operations to give effect to pro forma events that are: (1) directly attributable to the Acquisition; (2) factually supportable; and (3) expected to have a continuing impact on the combined results of Red Mountain and Cross Border following the Acquisition. The pro forma financial statements do not reflect any cost savings (or associated costs to achieve such savings) from operating efficiencies or synergies that could result from the Acquisition, nor do they include any potential revenue or earnings enhancements that may be achieved with the combined capabilities of the companies.

Assumptions and estimates underlying the unaudited adjustments to the pro forma financial statements (the “pro forma adjustments”) are described in the accompanying notes to the pro forma financial statements. Since the pro forma financial statements have been prepared based on preliminary estimates, the final amounts recorded may differ materially from the information presented, as described further in the accompanying notes.

These unaudited pro forma combined financial statements are provided for illustrative purposes only and are not necessarily indicative of the results that actually would have occurred had the transactions been in effect on the dates or for the periods indicated or of results that may occur in the future. The unaudited pro forma combined financial statements do not include the results of operations from the Bamco Properties prior to the acquisition date of December 10, 2012 because this transaction was not a significant acquisition. The unaudited pro forma combined financial statements should be read in conjunction with (1) our historical consolidated financial statements and accompanying notes and “Management’s Discussion and Analysis of Financial Condition and Results of Operations for Red Mountain” for the year ended May 31, 2012 and the nine months ended February 28, 2013 which are set forth or incorporated by reference herein, and (2) Cross Border’s historical consolidated financial statements and accompanying notes and “Management’s Discussion and Analysis of Financial Condition and Results of Operations for Cross Border” for the year ended December 31, 2012 which are set forth or incorporated by reference herein.

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RED MOUNTAIN RESOURCES, INC.

UNAUDITED PRO FORMA COMBINED STATEMENT OF OPERATIONS

Twelve Months Ended May 31, 2012

(in thousands)

(unaudited)

	Red Mountain Twelve Months Ended May 31, 2012			Cross Border Twelve Months Ended June 30, 2012			Pro Forma Adjustments			Pro Forma Combined
Revenue:
Oil and natural gas sales	$	6,325		$	11,371		$	—		$	17,696
Operating Expenses:
Exploration expense		265			49			—			314
Production taxes		403			814			—			1,217
Lease operating expenses		943			1,899			—			2,842
Natural gas transportation and marketing expenses		170			10			—			180
Depreciation, depletion, amortization and impairment		5,149			4,345			(1,929	)    (A)		7,565
Accretion of discount on asset retirement obligation		44			66			—			110
General and administrative expense		6,165			3,924			(555	)    (B)		9,534
Total operating expense		13,139			11,107			(2,484	)		21,762
Income (Loss) from Operations		(6,814	)		264			2,484			(4,066	)
Other Income (Expense):
Change in fair value of warrant liability		(763	)		—			—			(763	)
Bond issuance amortization		—			(200	)		—			(200	)
Gain on derivatives		—			844			—			844
Unrealized gain on investment in Cross Border warrants		282			—			(282	)    (C)		—
Equity in losses of Cross Border		(316	)		—			316	(D)		—
Interest expense		(2,097	)		(481	)		77	(E)		(2,501	)
Loss on note receivable		(2,725	)		—			—			(2,725	)
Interest and other income		1			203			—			204
Total Other Income (Expense)		(5,618	)		366			111			(5,141	)
Income (Loss) Before Income Taxes		(12,432	)		630			2,595			(9,207	)
Income tax provision		—			—			—			—
Net income (loss)	$	(12,432	)	$	630		$	2,595		$	(9,207	)
Basic and diluted net earnings (loss) per common share	$	(0.17	)	$	0.04		$	0.02		$	(0.11	)
Basic and diluted weighted average common shares outstanding		73,775			16,152			(414	)    (F)		89,513

See notes to unaudited pro forma combined financial statements

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RED MOUNTAIN RESOURCES, INC.

UNAUDITED PRO FORMA COMBINED STATEMENT OF OPERATIONS

Nine Months Ended February 28, 2013

(in thousands)

(unaudited)

	Red Mountain Nine Months Ended February 28, 2013			Cross Border Seven Months Ended January 31, 2013			Pro Forma Adjustments			Pro Forma Combined
Revenue:
Oil and natural gas sales	$	4,917		$	8,151		$	—		$	13,068
Operating Expenses:
Exploration expense		53			—			—			53
Production taxes		180			716			—			896
Lease operating expenses		966			1,803			—			2,769
Natural gas transportation and marketing expenses		77			129			—			206
Depletion, depreciation, amortization, accretion and impairment		3,193			5,206			(2,652	)    (A)		5,747
Environmental remediation liability		—			2,100			—			2,100
Accretion of discount on asset retirement obligation		74			87			—			161
General and administrative expense		6,205			679			(788	)    (B)		6,096
Total operating expense		10,748			10,720			(3,440	)		18,028
Income (Loss) from Operations		(5,831	)		(2,569	)		3,440			(4,960	)
Other Income (Expense):
Interest and other income		29			—			—			29
Bond issuance amortization		—			(57	)		—			(57	)
Change in fair value of derivative liability		359			(821	)		—			(462	)
Change in fair value of warrant liability		—			—			—			—
Unrealized loss on investment in Cross Border warrants		(1,304	)		—			1,304	(C)		—
Equity in losses of Cross Border		(332	)		—			322	(D)		—
Gain on consolidation of Cross Border		736			—			(736	)    (G)		—
Interest expense		(2,310	)		(241	)		55	(E)		(2,496	)
Realized gain on derivatives		17			242			—			259
Impairment on debentures		(503	)		—			—			(503	)
Impairment on note receivable		(856	)		—			856	(H)		—
Total Other Expense		(4,164	)		(877	)		1,811			(3,230	)
Income (Loss) Before Income Taxes		(9,995	)		(3,446	)		5,251			(8,190	)
Income tax provision		—			—			—			—
Net income (loss)	$	(9,995	)	$	(3,446	)	$	5,251		$	(8,190	)
Basic and diluted net loss per common share	$	(0.11	)	$	(0.21	)	$	0.25		$	(0.08	)
Basic and diluted weighted average common shares outstanding		93,801			16,211			(5,576	)    (F)		104,436

See notes to unaudited pro forma combined financial statements

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NOTE 1. BASIS OF PRO FORMA PRESENTATION

The unaudited pro forma combined financial statements of Red Mountain were prepared using the acquisition method of accounting as set forth under applicable Financial Accounting Standards Board (“FASB”) accounting guidance for business combinations. Under this guidance, Red Mountain is the acquirer. The pro forma information is based on the historical financial statements of Red Mountain and Cross Border.

The pro forma adjustments represent management’s estimates based on information available as of the time this document was prepared and are subject to revision as additional information becomes available and additional analyses are performed. The pro forma financial statements do not reflect the impact of possible revenue or earnings enhancements, cost savings from operating efficiencies or synergies, or asset dispositions. Also, the pro forma financial statements do not reflect possible adjustments related to restructuring or integration activities that have yet to be determined or transaction or other costs following the Acquisition that are not expected to have a continuing impact.

NOTE 2. PRO FORMA ADJUSTMENTS AND ASSUMPTIONS

The pro forma statements of operations reflect the Acquisition and related events as if they occurred on June 1, 2011 and 2012 for purposes of the statement of operations for the year ended May 31, 2012 and the nine months ended February 28, 2013, respectively, for Red Mountain and on January 1, 2012 and July 1, 2012 for the year ended May 31, 2012 and the seven months ended January 31, 2013, respectively, for Cross Border.

The accompanying unaudited pro forma combined financial statements reflect the following pro forma adjustments:

A. Pro forma depletion expense gives effect to the Acquisition which required the application of purchase accounting. The expense was calculated using estimated proved reserves as of the beginning of the period, production for the applicable period, and the fair value of the purchase price allocated to proved oil and gas properties.

B. To eliminate transaction costs incurred by Red Mountain for the fiscal year ended May 31, 2012 and the nine months ended February 28, 2013.

C. To eliminate Red Mountain’s change in fair value in warrants to acquire common stock of Cross Border during the fiscal year ended May 31, 2012 and the nine months ended February 28, 2013.

D. To eliminate Red Mountain’s equity method losses in outstanding shares of common stock of Cross Border for the fiscal year ended May 31, 2012 and the nine months ended February 28, 2013.

E. To eliminate Cross Border’s accrued interest on subordinated debt held by Red Mountain as of December 12, 2012 for the twelve months ended June 30, 2012 and the seven months ended January 31, 2013.

F. Adjustment to basic and diluted weighted average common shares outstanding for the fiscal year ended May 31, 2012 to remove the shares of outstanding Cross Border common stock and to reflect the shares of Red Mountain common stock that were issued to acquire Cross Border.

G. To eliminate Red Mountain’s gain on the consolidation of Cross Border for the nine months ended February 28, 2013.

H. To eliminate Red Mountain’s impairment on subordinated debt of Cross Border for the nine months ended February 28, 2013.

NOTE 3. PRO FORMA NET LOSS PER COMMON SHARE

Pro forma net loss per common share was determined by dividing the pro forma net loss by the weighted average number of common shares expected to be outstanding. All shares related to the Acquisition were assumed to have been outstanding since the beginning of each respective period presented. There were no potentially dilutive shares for either statement of operations presented.

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

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 May 31, 2013, we owned interests in 883,226 gross (305,845 net) mineral and lease acres in New Mexico, Texas and Kansas, of which 336,851 gross (31,011 net) acres are within the Permian Basin. We have successfully leased over 5,200 net acres in Kansas located on the Central Kansas Uplift, and we also owned interests in over 1,400 net acres located on the Villarreal, Frost Bank, Resendez, Peal Ranch and La Duquesa Prospects in the Gulf Coast of Texas.

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 acquisition, we owned 47% of Cross Border’s outstanding common stock, and the investment was accounted for under the equity method of accounting. Subsequent to this transaction, we account for Cross Border as a consolidated subsidiary. As of May 31, 2013, we owned of record 14,327,767 shares of Cross Border common stock, representing 83% of Cross Border’s outstanding common stock.

History

Red Mountain was originally formed in January 2010 as Teaching Time, Inc. in order to design, develop, and market instructional products and services for the corporate, education, government, and healthcaree-learning industries. In March 2011, Teaching Time, Inc. determined to enter into oil and natural gas exploration, development and production and changed its name to Red Mountain Resources, Inc. to better reflect that plan. On March 22, 2011, we entered into a Plan of Reorganization and Share Exchange Agreement, as amended on June 17, 2011 and June 20, 2011 (the “Share Exchange Agreement”), with Black Rock Capital, LLC and The StoneStreet Group, Inc. (“StoneStreet”), the sole shareholder of Black Rock Capital, LLC. Alan W. Barksdale, our current president, chief executive officer and chairman of the board, was the president and the sole member of Black Rock Capital, LLC and the sole owner and the president of StoneStreet. On June 22, 2011, we completed a reverse merger pursuant to the Share Exchange Agreement in which we issued 27,000,000 shares of common stock to StoneStreet in exchange for 100% of the interests in Black Rock Capital, LLC. Concurrently with the closing, we retired 225,000,000 shares of common stock for no additional consideration. In connection with the reverse merger, the management of Black Rock Capital, LLC became our management.

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

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

Recent Developments

Bamco Asset Purchase Agreement.On December 10, 2012, we entered into the Asset Purchase Agreement with Bamco. Mr. Barksdale was the receiver for the receivership estate of Bamco. Pursuant to the Asset Purchase Agreement, we agreed to acquire the Bamco Properties. On December 10, 2012, pursuant to the Asset Purchase Agreement, we issued 2,375,000 shares of our common stock to the indenture trustee of certain debentures of Bamco, and we executed a waiver and release of a claim against the receivership estate of Bamco for a $2.7 million note receivable that we deemed uncollectible in 2011.

Amended and Restated Promissory Note. On December 10, 2012, we entered into a Loan Modification Agreement (the “Loan Agreement”) with Hyman Belzberg (“HB”), William Belzberg (“WB”), Caddo Management, Inc. (“Caddo”) and RMS Advisors, Inc. (“RMS” and together with HB, WB and Caddo, collectively the “Note Lender”). Pursuant to the Loan Agreement, we and the Note Lender agreed to modify that certain Senior Secured Promissory Note of Red Mountain Resources, Inc., dated as of November 16, 2011, in the aggregate principal amount of $4.0 million made by the Company in favor of the Note Lender, as amended by the Amendment No. 1 to Senior Secured Promissory Note of Red Mountain Resources, Inc., dated November 16, 2012 (as amended, the “Original Note”), to increase the amount of the Original Note to $6.0 million. Pursuant to the Loan Agreement, we entered into an Amended and Restated Senior Secured Promissory Note of Red Mountain Resources, Inc. (the “Amended and Restated Note”) with the Note Lender, dated as of December 10, 2012, in the aggregate principal amount of $6.0 million. The Amended and Restated Note was repaid at maturity on February 14, 2013. The Amended and Restated Note accrued interest at a rate of 12% per annum.

Acquisition of Cross Border. On January 28, 2013, pursuant to privately negotiated transactions, we acquired 5,091,210 shares of common stock of Cross Border from a limited number of stockholders of Cross Border in exchange for the issuance of 10,182,420 shares of our common stock, bringing our total ownership to approximately 78% of the outstanding Cross Border common stock. Prior to the Acquisition, we owned 47% of Cross Border’s outstanding common stock, and the investment was accounted for under the equity method of accounting. Subsequent to this transaction, we account for Cross Border as a consolidated subsidiary. As of May 31, 2013, we owned of record 14,327,767 shares of Cross Border common stock, representing 83% of Cross Border’s outstanding common stock. In addition, as of May 31, 2013, we owned warrants to acquire an additional 2,502,831 shares of Cross Border common stock. The warrants have an exercise price of $2.25 per share and are exercisable until May 26, 2016.

Senior Credit Facility. On February 5, 2013, we entered into the Credit Agreement with Cross Border, Black Rock and RMR Operating, as Borrowers, and Independent Bank, as Lender. The Credit Agreement provides for an up to $100.0 million Credit Facility with an initial commitment of $20.0 million and a maturity date of February 5, 2016.

Simultaneously with entering into the Credit Agreement, we borrowed $7.6 million under the Credit Facility and used a portion of the proceeds to repay in full (i) outstanding promissory notes payable to First State Bank of Lonoke and (ii) the Amended and Restated Note, and Cross Border borrowed $8.9 million and used a portion of

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the proceeds to repay in full its existing credit facility. On February 21, 2013, pursuant to the terms of the Credit Agreement, we entered into a hedge agreement with BP Energy to hedge a portion of the future oil production of the Borrowers. See “—Liquidity and Capital Resources—Indebtedness—Senior Credit Facility.”

We were not in compliance with the financial covenants in the Credit Agreement for the three months ended February 28, 2013. On May 2, 2013, we entered into an amendment to the Credit Agreement, which waived the non-compliance and amended certain financial ratios in the Credit Agreement to become effective starting May 31, 2013. As a result, as of May 2, 2013, we are no longer in default under the Credit Agreement.

On July 19, 2013, we entered into an amendment to the 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.

Private Placements. On February 5, 2013, we closed a private placement for 7,058,823 shares of common stock at a purchase price of $0.85 per share, raising gross proceeds of $6.0 million, from certain of the initial investors in our company. We used the proceeds for drilling expenses, repayment of debt and general working capital. On May 3, 2013, we closed a private placement for 3,529,412 shares of common stock at a purchase price of $0.85 per share, raising gross proceeds of $3.0 million, from certain of the initial investors in our company. We used the proceeds for general working capital.

Unsecured Promissory Note. On February 6, 2013, we issued an Unsecured Subordinated Promissory Note (as amended, the “Subordinated Note”) in the aggregate principal amount of $500,000 payable to HB, WB and Caddo (the “Subordinated Lender”). The Subordinated Note matures on August 31, 2013 and accrues interest at a rate of 12% per annum, payable monthly. See “—Liquidity and Capital Resources—Indebtedness—Subordinated Note.”

Environmental Remediation Plan. On February 11, 2013, the BLM accepted a remediation plan submitted by Cross Border for its Tom Tom and Tomahawk fields. Pursuant to the remediation plan, Cross Border expects to spend $2.1 million during fiscal 2014 and 2015 to correct environmental issues on these fields.

Madera 24 Federal 3H Well. During the three months ended February 28, 2013, we commenced drilling the Madera 24 Federal 3H well, which is located in the Madera prospect just to the west of the Madera 24 Federal 2H well. We are the operator of the well and own a 33% working interest and 25% net revenue interest. The well was spudded on February 6, 2013, and on May 10, 2013, we finished drilling and completing the well. The initial production rate from the well was 1,491 Boe (81% oil). The well has a total measured depth of 13,570 feet, including a true vertical depth of 9,062 feet and a lateral length of 4,508 feet. At May 31, 2013, the well was still producing and permanent production facilities were under construction.

Change of Fiscal Year End. On July 17, 2013, we changed our fiscal year end from May 31 to June 30, effective June 30, 2013.

Closing of Units Offering. In August 2013, we closed an offering of 375,676 Units, including 100,002 Units sold in cancellation of $2.3 million in debt, raising gross cash proceeds of $6.2 million. Each Unit consisted of one share of Series A Preferred Stock and one warrant to purchase up to 25 shares of common stock. We intend to use the proceeds for general corporate purposes, including to fund a portion of our fiscal 2014 drilling and development expenditures and the payment of accrued interest and fees on indebtedness that was cancelled.

Late Filing of Form 10-K. Our Form 10-K is due on August 29, 2013. We expect that we will be unable to timely file the Form 10-K because we need additional time to prepare and review our fiscal year 2013 financial statements due to purchase price accounting and consolidation issues related to Cross Border. As a result, we expect to file a Notification of Late Filing on Form 12b-25.

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Fiscal 2013 Fourth Quarter Operational Update

During the three months ended May 31, 2013, we completed drilling the Madera 24 Federal 3H well. The initial production rate from the well was 1,491 Boe (81% oil). We own a 33% working interest and 25% net revenue interest in the well. Since the initial production test, the well has been choked back while additional production facilities are being constructed. During the three months ended May 31, 2013, we converted the Madera 25 Federal 1 well into a salt water disposal well for the Madera lease, which will significantly reduce our disposal costs across the field. We also commenced work on a 10-well workover program in the Tom Tom field. At May 31, 2013, one workover had been completed, showing positive results.

On Cross Border’s non-operated acreage, our partners completed seven gross (1.0 net) wells in the three months ended May 31, 2013. The most significant of these wells were two Apache-operated horizontal Bone Spring wells in the Lusk field and one Mewbourne-operated horizontal Bone Spring well in the Turkey Track field. Cross Border owns a 29% working interest in both of the Lusk wells and a 13% working interest in the Turkey Track well. In addition, at May 31, 2013, two gross wells (0.1 net) were being drilled and awaiting completion. All of these wells are infill development wells.

Planned Operations

During fiscal year 2014, we plan to spend between $35.0 million and $45.0 million for continued development, workovers, and recompletions on our properties including Madera, Tom Tom, Cowden and our prospect located in Andrews County, Texas. If we do not raise minimum gross proceeds of between $10.8 million and $20.8 million from this offering and the concurrent Units offering, we will need to either curtail our fiscal 2014 development program or raise additional funds.

Critical Accounting Policies and Estimates

Our discussion and analysis of our financial condition and results of operations is based upon our consolidated financial statements, which have been prepared in accordance with U.S. generally accepted accounting principles (“GAAP”). The preparation of these consolidated financial statements requires management to make estimates and judgments that affect the reported amounts of assets, liabilities, revenue and expenses, and related disclosures. Our significant accounting policies are described in “Note 3 — Significant Accounting Policies” to our consolidated financial statements incorporated by reference in this prospectus supplement. We have identified below policies that are of particular importance to the portrayal of our financial position and results of operations and which require the application of significant judgment by management. These estimates are based on historical experience, information received from third parties, and on various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates under different assumptions or conditions.

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

Oil and Gas Properties

Effective June 1, 2011, we follow the successful efforts method of accounting for our oil and natural gas producing activities. The change in accounting principle has been applied retroactively to prior periods. Costs to acquire mineral interests in oil and natural gas properties and to drill and equip development wells and related asset retirement costs are capitalized. Costs to drill exploratory wells are capitalized pending determination of whether the wells have proved reserves. If we determine that the wells do not have proved reserves, the costs are charged to expense. There were no exploratory wells capitalized pending determination of whether the wells have proved reserves at February 28, 2013 or February 29, 2012. Geological and geophysical costs, including seismic studies and costs of carrying and retaining unproved properties, are charged to expense as incurred. We

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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 February 28, 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 its property account and release this account when the actual expenditure is later billed to it by the operator.

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

Impairment of Long-Lived Assets

We evaluate our long-lived assets for potential impairment in their carrying values whenever events or changes in circumstances indicate such impairment may have occurred. Oil and natural gas properties are evaluated for potential impairment by field. Other properties are evaluated for impairment on a specific asset basis or in groups of similar assets, as applicable. An impairment on proved properties is recognized when the estimated undiscounted future net cash flows of an asset are less than its carrying value. If an impairment occurs, the carrying value of the impaired asset is reduced to its estimated fair value, which is generally estimated using a discounted cash flow approach. If the results of an assessment indicate that the properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized.

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

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

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acquisition date. We have not finalized the determination of the fair values of the assets acquired and liabilities assumed for both Cross Border and Bamco and, therefore, the estimated fair values are subject to adjustment when the valuations are completed. Under GAAP, companies have one year following an acquisition to finalize acquisition accounting.

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 May 2011, the FASB issued Accounting Standards Update (“ASU”) No. 2011-04, Fair Value Measurements (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs (“ASU 2011-04”). ASU 2011-04 changes the wording used to describe many of the requirements in GAAP for measuring fair value and for disclosing information about fair value measurements to ensure consistency between GAAP and International Financial Reporting Standards (“IFRS”). ASU 2011-04 also expands the disclosures for fair value measurements that are estimated using significant unobservable (Level 3) inputs. This new guidance is to be applied prospectively. ASU 2011-04 became effective for interim and annual periods beginning after December 15, 2011. The adoption of this amendment did not have a material impact on our consolidated financial statements.

On June 16, 2011, the FASB issued ASU No. 2011-05 Comprehensive Income (Topic 220): Presentation of Comprehensive Income (“ASU 2011-05”). ASU 2011-05 requires entities to report items of other comprehensive income on either part of a single contiguous statement of comprehensive income or in a separate statement of comprehensive income immediately following the statement of income. On December 23, 2011, the FASB issued an update to this pronouncement, ASU No. 2011-12 Comprehensive Income (Topic 220): Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05. The update defers the specific requirement to present items that are reclassified from accumulated other comprehensive income to net income separately with their respective components of net income and other comprehensive income. While early adoption is permitted, the amendments are effective for fiscal years, and interim periods within those years, beginning after December 15, 2011 and must be applied retrospectively. Presently, we do not have any transactions which require the reporting of comprehensive income; therefore, we do not anticipate any material impact from this pronouncement.

On December 16, 2011, the FASB issued ASU No. 2011-11 Balance Sheet (Topic 210), Disclosures about Offsetting Assets and Liabilities (“ASU 2011-11”). ASU 2011-11 requires entities to disclose both gross information and net information about both instruments and transactions eligible for offset in the statement of financial position and instruments and transactions subject to an agreement similar to a master netting arrangement. Application of ASU 2011-11 is required for annual reporting periods beginning on or after January 1, 2013 and interim periods within those annual periods. We do not expect the adoption of this amendment to have a material impact on our consolidated financial statements.

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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 and 2012 and the nine months ended February 29, 2012 and February 28, 2013. The results for the nine months ended February 28, 2013 only include results and estimated net production sold from Cross Border since February 1, 2013.

	Fiscal Year Ended,				Nine Months Ended,
	May 31, 2011		May 31, 2012		February 29, 2012		February 28, 2013
Revenue
Oil and natural gas sales (in thousands)	$	3,712	$	6,325	$	3,780	$	4,917
Net production sold
Oil (Bbl)		—		37,004		13,968		43,754
Natural gas (Mcf)		900,332		795,659		652,488		432,810
Total (Boe) (1)		150,055		169,614		122,716		115,889
Total (Boe/d) (2)		411		465		450		425
Average sales prices
Oil ($/Bbl)	$	—	$	93.97	$	95.11	$	79.23
Natural gas ($/Mcf)		4.12		3.58		3.57		3.13
Total average price ($/Boe)	$	24.74	$	37.29	$	30.80	$	42.43
Costs and expenses (per Boe)
Exploration expense	$	—	$	1.56	$	0.75	$	0.45
Production taxes		1.07		2.38		1.79		1.55
Lease operating expenses		1.10		5.56		5.83		8.33
Natural gas transportation and marketing expenses		1.57		1.00		1.15		0.66
Depreciation, depletion, amortization and impairment		4.78		30.36		9.86		27.55
Accretion of discount on asset retirement obligation		0.06		0.25		0.24		0.64
General and administrative expense		1.95		36.35		28.22		53.54

(1) Includes immaterial amounts of natural gas liquids.

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

Nine Months Ended February 28, 2013 Compared to Nine Months Ended February 29, 2012

Revenues and Production

Oil and Natural Gas Production. During the nine months ended February 28, 2013, we had net production sold of 115,889 Boe, compared to net production sold of 122,716 Boe during the nine months ended February 29, 2012. The decrease in net production sold was primarily attributable to a 33.7% decrease in natural gas production due to the flaring of natural gas from our Madera 24 Federal 2H well when the well was constrained and the natural decline of our natural gas producing properties, particularly in the onshore Gulf Coast. For the nine months ended February 28, 2013, 37.8% of our net production sold was oil and 62.2% was natural gas, compared to 88.6% natural gas for the nine months ended February 29, 2012.

Oil and Natural Gas Sales. During the nine months ended February 28, 2013, we had oil and natural gas sales of $4.9 million, as compared to $3.8 million during the nine months ended February 29, 2012. The increase in oil and natural gas sales was primarily attributable to an additional 29.8 MBbls net production sold of oil and consolidating the operations of Cross Border during the nine months ended February 28, 2013, partially offset by a 33.7% decrease in natural gas production and a 16.7% decrease in the price of oil as compared to the nine months ended February 29, 2012.

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Costs and Expenses

Production Taxes. Production taxes were unchanged at $0.2 million for the nine months ended February 28, 2013, as compared to the nine months ended February 29, 2012.

Lease Operating Expenses. During the nine months ended February 28, 2013, we incurred lease operating expenses of $1.0 million, as compared to $0.7 million during the nine months ended February 29, 2012. The increase in lease operating expenses was attributable to increased oil production and a corresponding increase in direct costs such as salt water disposal.

Depreciation, Depletion, Amortization and Impairment. For the nine months ended February 28, 2013, depreciation, depletion, amortization and impairment was $3.2 million, as compared to $1.2 million for the nine months ended February 29, 2012. The increase in depreciation, depletion, amortization and impairment was attributable to lower reserve volumes, which resulted in higher depletion rates, as well as the consolidation of Cross Border.

General and Administrative Expense. General and administrative expense was $6.2 million for the nine months ended February 28, 2013, as compared to $3.5 million for the nine months ended February 29, 2012. The increase in general and administrative expense was due primarily to increased employee headcount as well as increased professional fees relating to the acquisition of Cross Border, other entities and debentures. Total acquisitions related cost for the nine months ended February 28, 2013 totaled $1.6 million as compared to $0.4 million for the nine months ended February 29, 2012.

Other Expense. Other expense was $4.2 million for the nine months ended February 28, 2013, as compared to other expense of $5.3 million for the nine months ended February 29, 2012. The decrease in other expense was primarily attributable to realizing a $0.7 million gain on the consolidation of Cross Border and a $1.9 million lower impairment on note receivable in the nine months ended February 28, 2013, partially offset by a $0.5 million impairment on debentures and incurring $0.8 million of more interest in the nine months ended February 28, 2013 as compared to the nine months ended February 29, 2012. In addition, we recorded an unrealized loss on Cross Border warrants of $1.3 million in nine months ended February 28, 2013, as compared to a $0.5 million unrealized gain in the nine months ended February 29, 2012. Finally, during the nine month ended February 29, 2012, we recorded a $1.2 million charge for a change in the fair value of warrant liabilities, as compared to no charge in the nine months ended February 28, 2013.

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 169,614 Boe, compared to net production sold of 150,055 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, 21.8% of our net production sold was oil and 78.2% was natural gas, compared to 100% natural gas for the fiscal year ended May 31, 2011.

Oil and Natural Gas Sales. During the fiscal year ended May 31, 2012, we had oil and natural gas sales of $6.3 million, as compared to $3.7 million during the fiscal year ended May 31, 2011. The increase in oil and natural gas sales was primarily attributable to 46.1 MBoe of net production sold from the Madera Prospect partially offset by lower natural gas production and lower average prices for natural gas sales. For fiscal 2011, we had no oil production.

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Costs and Expenses

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

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

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

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

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

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

Other Expense. Other expense was $5.6 million for the fiscal year ended May 31, 2012, as compared to other income of $0.7 million for the fiscal year ended May 31, 2011. The increase in other expense was primarily attributable to increased interest expense due to $6.7 million aggregate principal amount of promissory notes and $2.8 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 fiscal 2012 and the first nine months of fiscal 2013 were borrowings under our Credit Facility and Loan Agreement and proceeds from a $6.0 million private placement 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.

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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 $35.0 million and $45.0 million for fiscal year 2014. If we do not raise minimum gross proceeds of between $10.8 million and $20.8 million from this offering and the concurrent Units offering, we will need to either curtail our fiscal 2014 development program or raise additional funds. See “— Planned Operations” for more information about our planned capital expenditures.

Liquidity

At February 28, 2013, we had $2.8 million in cash and cash equivalents, $18.5 million outstanding under the Credit Facility, $500,000 outstanding under the Subordinated Note and $3.0 million outstanding under various convertible promissory notes, net of an aggregate discount of $0.7 million. At February 28, 2013, we had a working capital deficit of $24.3 million compared to a working capital deficit of $10.4 million at May 31, 2012. On February 11, 2013, the BLM accepted a remediation plan submitted by Cross Border for its Tom Tom and Tomahawk fields. Pursuant to the remediation plan, Cross Border expects to spend $2.1 million during fiscal 2014 and 2015 to correct environmental issues on these fields.

Assuming we raise minimum gross proceeds of between $10.8 million and $20.8 million from this offering and the concurrent Units 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. If we do not raise minimum gross proceeds of between $10.8 million and $20.8 million from this offering and the concurrent Units offering, we will need to either curtail our fiscal 2014 development program or raise additional funds.

Financings

On December 10, 2012, we entered into the Loan Agreement with the Note Lender. Pursuant to the Loan Agreement, we and the Note Lender agreed to modify the Original Note to increase the amount of the Original Note to $6.0 million. Pursuant to the Loan Agreement, we and the Note Lender entered into the Amended and Restated Note in the aggregate principal amount of $6.0 million. We used $0.4 million of the proceeds from the Amended and Restated Note to repay the notes issued to Veladen Investments Corp., LLC, DIT Equity Holdings, LLC and RMS during October and November 2012, and the remainder of the proceeds were used for working capital. Pursuant to the Loan Agreement, we issued Warrants to Purchase Shares of Common Stock of Red Mountain Resources, Inc. (the “Warrants”) to (i) HB for the purchase of 75,000 shares of the Company’s common stock, (ii) WB for the purchase of 75,000 shares of the Company’s common stock and (iii) Caddo for the purchase of 50,000 shares of the Company’s common stock. Each of the Warrants has an exercise price of $1.00 per share, subject to certain customary adjustments, and is exercisable through December 1, 2014. The Warrants grant piggyback registration rights pursuant to which the holders will have the right to include the shares issuable upon exercise of the Warrants in certain registration statements that may be filed by the Company in the future.

On February 5, 2013, we entered into the Credit Agreement. The Credit Agreement provides for an up to $100.0 million revolving credit facility with an initial commitment of $20.0 million and a maturity date of February 5, 2016. Simultaneously with entering into the Credit Agreement, we borrowed $7.6 million under the Credit Facility and used a portion of the proceeds to repay in full (i) outstanding promissory notes payable to First State Bank of Lonoke and (ii) the Amended and Restated Note, and Cross Border borrowed $8.9 million and used a portion of the proceeds to repay in full its existing credit facility. See “—Indebtedness—Senior Credit Facility.”

On February 5, 2013, we closed a private placement for 7,058,823 shares of common stock at a purchase price of $0.85 per share, raising gross proceeds of $6.0 million, from certain of the initial investors in our company. We used the proceeds for drilling expenses, repaying debt and general working capital.

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On February 6, 2013, we issued the Subordinated Note in the aggregate principal amount of $500,000 payable to the Subordinated Lender. The Subordinated Note matures on August 31, 2013 and accrues interest at a rate of 12% per annum, payable monthly. See “—Indebtedness—Subordinated Note.” We used the proceeds to refinance existing debt.

On May 3, 2013, we closed a private placement for 3,529,412 shares of common stock at a purchase price of $0.85 per share, raising gross proceeds of $3.0 million, from certain of the initial investors in our company. We used the proceeds for general working capital.

In August 2013, we closed an offering of 375,676 Units, including 100,002 Units sold in cancellation of $2.3 million in debt, raising gross cash proceeds of $6.2 million. We intend to use the proceeds for general corporate purposes, including to fund a portion of our fiscal 2014 drilling and development expenditures and the payment of accrued interest and fees on indebtedness that was cancelled.

Cash Flows

Net cash used in operating activities was $5.0 million for the nine months ended February 28, 2013, compared to net cash used in operating activities of $1.8 million for the nine months ended February 29, 2012. The increase in net cash used in operating activities was primarily due to changes in working capital and a higher net loss.

Net cash used in investing activities was $0.2 million for the nine months ended February 28, 2013 compared to $12.5 million for the nine months ended February 29, 2012 due to reduced drilling activity.

Net cash provided by financing activities was $7.8 million for the nine months ended February 28, 2013, as compared to $15.1 million for the nine months ended February 29, 2012. Net cash provided by financing activities for the nine months ended February 28, 2013 was primarily comprised of borrowings of $11.2 million under our Credit Facility and $2.4 million from notes payable and proceeds from our private placement, partially offset by repayments of promissory notes with First State Bank of Lonoke, the Amended and Restated Note and the Cross Border credit facility.

Indebtedness

Senior Credit Facility

The Credit Agreement provides for an up to $100.0 million revolving credit facility with an initial commitment of $20.0 million and a maturity date of February 5, 2016. The borrowing base under the Credit Facility is determined at the discretion of the Lender based on, among other things, the Lender’s estimated value of the proved reserves attributable to the Borrowers’ oil and gas properties that have been mortgaged to the Lender, and is subject to regular redeterminations on August 31 and February 28 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 May 31, 2013, the borrowing base was $20.0 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.

Amounts outstanding under the Credit Facility will 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.

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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. 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.

The Credit Agreement also contains financial covenants, measured as of the last day of each fiscal quarter of Red Mountain starting May 31, 2013, 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. 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. On February 21, 2013, pursuant to the terms of the Credit Agreement, Red Mountain entered into a hedge agreement with BP Energy to hedge a portion of the future oil production of the Borrowers.

As of May 31, 2013, the Borrowers had collectively borrowed $19.8 million and had availability of $0.2 million under the Credit Facility.

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Subordinated Note

On February 6, 2013, we issued the Subordinated Note in the aggregate principal amount of $500,000 payable to the Subordinated Lender. The Subordinated Note matures on August 31, 2013 and accrues interest at a rate of 12% per annum, payable monthly. Upon an event of default, interest will accrue on all outstanding principal at a rate of the lesser of (i) 18% per annum or (ii) the maximum rate permitted by applicable law.

The Subordinated Note contains customary non-financial covenants governing the conduct of our business. An event of default includes, among other things, (i) failure to make payments when due; (ii) any representation or warranty proves false; (iii) failure to comply with any provision of the note; (iv) bankruptcy or insolvency; (v) the Subordinated Lender determines in its reasonable discretion that we are unable in the ordinary course of business to pay our debts as they are due or our debts exceed the fair market value of all of our assets and property or (vi) a default under any of our material agreements. Immediately upon the occurrence of an event of default, the Subordinated Lender has the right, in its sole and absolute discretion, to accelerate and declare the outstanding amount immediately due and payable.

Convertible Promissory Notes

On November 25, 2011, we issued convertible promissory notes to Hohenplan Privatstiftung (“Hohenplan”), Personalversorge der Autogrill Schweiz AG and SST Advisors, Inc. in an aggregate principal amount of $2.8 million. The convertible promissory notes issued to Hohenplan and SST Advisors, Inc., in an aggregate principal amount of $1.3 million, were cancelled in exchange for 55,557 Units in August 2013. The remaining convertible promissory note is due and payable on November 25, 2013 and bears interest at the rate of 10% per annum. Prior to repayment, the holder of the convertible promissory note has the option of converting all or any portion of the unpaid balance of the convertible promissory note (including accrued and unpaid interest) into shares of our common stock at a conversion price equal to $1.00 per share, subject to standard anti-dilution provisions if we issue any stock dividends, subdivide or combine our outstanding shares of common stock, or effect a reclassification, consolidation, merger or sale of all or substantially all of our assets. The value of the beneficial conversion feature of the three convertible promissory notes was $0.6 million as of February 28, 2013. The beneficial conversion feature has been recorded as a discount to the convertible notes payable and to additional paid-in-capital and will be amortized to interest expense over the life of the convertible promissory notes. We amortized $0.2 million of the discount to interest expense during the three months ended February 28, 2013.

On July 30, 2012, we issued a convertible promissory note (the “Convertible Note”) in the principal amount of $1.0 million to Hohenplan. The Convertible Note was cancelled in exchange for 44,445 units in August 2013.

We determined that the terms of the Convertible Note contained a down round provision under which the conversion price could be decreased as a result of future equity offerings. Accordingly, the conversion feature was accounted for as a derivative liability and discount on note payable. On February 5, 2013, we closed a private placement of 7,058,823 shares of common stock at a purchase price of $0.85 per share, from certain of the initial investors in our company. As a result, the conversion price of the Convertible Note was adjusted from $1.50 to $0.85. The fair value of the discount on Convertible Note was approximately $117,000 as of February 28, 2013, resulting in an unrealized gain of $91,800 during the three months ended February 28, 2013. We amortized approximately $74,000 of the discount to interest expense during the three months ended February 28, 2013.

In connection with the issuance of the Convertible Note, we incurred approximately $210,000 of debt issuance costs related to the issuance to a broker of 125,000 shares of our common stock with a value of $161,000, and warrants to purchase 83,333 shares of our common stock at an exercise price of $1.50 per share, with a value of $49,000. The warrants expire on July 30, 2015. The shares issued to the broker were valued using

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the closing market price of our common stock on the OTCQB on the debt issuance date, July 30, 2012. We valued the warrants using the Black-Scholes valuation model with a volatility based on the historical closing price of common stock of industry peers. During the three months ended February 28, 2013, we amortized approximately $52,000 of the capitalized debt issuance costs to interest expense.

Off-Balance Sheet Arrangements

As of February 28, 2013, we did not have any off-balance sheet arrangements as defined byRegulation S-K.

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

The following discussion and analysis of Cross Border’s financial condition and results of operations should be read in conjunction with its 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. Cross Border’s 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.

Company

Cross Border is an oil and gas exploration company resulting from the business combination of Doral Energy Corp. and Pure Gas Partners II, L.P. (“Pure L.P.”), effective January 3, 2011. As of February 28, 2013, Cross Border owned over 865,893 gross (293,843 net) mineral and lease acres in New Mexico and Texas. Approximately 25,000 of these net acres exist within the Permian Basin. A significant majority of its acreage consists of either owned mineral rights or leases held by production, allowing Cross Border to hold lease rental payments to under $5,000 annually. The majority of its acreage interests consists of non-operated working interests except for certain core San Andres properties which Cross Border operates.

Current development of its acreage is focused on its prospective Bone Spring acreage located in the heart of the 1st and 2nd Bone Spring play. This play encompasses approximately 4,390 square miles across both New Mexico and Texas. Cross Border currently owns varying, non-operated working interests in both Eddy and Lea Counties, New Mexico, along with its operating partners that include Apache Corporation, Mewbourne Oil Company, COG Operating LLC, Alamo Permian Resources, LLC, LRE Operating, LLC, Oxy USA Inc. and Devon Energy Production Company, LP. All of these companies have significant footprints within this play and are adding to those footprints through lease and corporate acquisitions.

History

Cross Border was originally formed on October 25, 2005 under the name “Language Enterprises Corp.” Language Enterprises, Corp. subsequently merged with Doral Energy Corp. (“Doral Energy”). Language Enterprises Corp. was the surviving entity in the merger and changed its name to Doral Energy Corp. On July 29, 2008, Doral Energy acquired a working interest in 66 producing oil fields and approximately 186 wells (the “Eddy County Properties”) in and around Eddy County, New Mexico. As a result of its acquisition of the Eddy County Properties, Doral Energy changed its business focus to the acquisition, exploration, operation and development of oil and gas projects and ceased being a “shell company.” On August 4, 2008, Doral Energy filed its Form 8-K that included the information that would be required if Cross Border was filing a general form for registration of securities on Form 10 as a smaller reporting company.

Effective January 3, 2011, Doral Energy and its wholly-owned subsidiary, Doral Acquisition Corp., completed the acquisition of Pure Energy Group, Inc. as contemplated pursuant to an Acquisition and Plan of Merger (the “Pure Merger Agreement”) among Doral Energy, Doral Acquisition Corp. (“Doral Sub”), Pure Gas Partners II, L.P. (“Pure L.P.”), and Pure Energy Group, Inc. (“Pure Sub”) (the “Pure Merger”). Pursuant to the provisions of the Pure Merger Agreement, all of Pure L.P.’s oil and gas assets and liabilities were transferred to Pure Sub. Pure Sub was then merged with and into Doral Sub, with Doral Sub continuing as the surviving corporation. Upon completion of the Pure Merger, the outstanding shares of Pure Sub were converted into an aggregate of 9,981,536 shares of Doral Energy’s common stock. Since the Pure Merger, Pure L.P. has distributed all of its shares of Doral Energy’s common stock acquired pursuant to the Pure Merger to the partners of Pure L.P. so that it is no longer a shareholder of Doral Energy, which is now Cross Border.

Effective January 4, 2011, following closing of the Pure Merger, Doral Sub was merged with and into Doral Energy, with Doral Energy continuing as the surviving corporation. Upon completing the merger of Doral Sub with and into Doral Energy, Doral Energy changed its name to “Cross Border Resources, Inc.”

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Significant Fiscal 2012 Operations

Successful 2nd Bone Spring and Yeso horizontal and vertical completions during 2012 have been instrumental in increasing Cross Border’s net daily production sold to a net daily production sold rate of approximately 426 Boe/d for the fourth quarter of 2012. The net daily production sold rate has dropped from 675 Boe/d in March 2012 due to the normal decline of new wells put on production during the first quarter of 2012, storage and facility limitations on these wells, fewer new high impact wells coming on during the second half of 2012, and the sale of assets.

During 2012, Cross Border participated in 27 gross (2.6 net) new wells. In the months of July and August, Cross Border participated in seven gross (0.75 net) new wells. Of these 27 wells, as of December 31, 2012, 21 had been placed on production, while six are awaiting completion. Additionally, all four of the wells that were drilled during 2011 and were awaiting completion at year end 2011 were successfully completed during 2012.

In August 2012, Cross Border sold all of its Wolfberry assets located in the Texas counties of Dawson, Howard, Martin and Borden to Big Star Oil and Gas, LLC for $2.3 million in cash. An impairment of approximately $1.8 million was recorded in June 2012 to reduce the carrying value of these assets to the sales price. The average daily net production sold from this area was approximately 29 Boe/d, which was replaced by new production from other areas.

Results of Operations

Year Ended December 31, 2012 Compared to Year Ended December 31, 2011

The following table sets forth summary information regarding Cross Border’s oil and natural gas sales, net production sold, average sales prices and production costs and expenses for the years ended December 31, 2012 and 2011.

	Year Ended December 31,
	2012		2011
(dollars in thousands, except per unit prices)
Revenue
Oil and natural gas sales	$	14,781	$	6,584
Net production sold
Oil (Bbl)		149,600		56,740
Natural gas (Mcf)		285,885		252,690
Total (Boe)		197,247		98,855
Total (Boe/d) (1)		539		271
Average sales prices
Oil ($/Bbl)	$	87.95	$	86.70
Natural gas ($/Mcf)		4.47		6.03
Total average price ($/Boe)	$	73.19	$	65.17
Costs and expenses (per Boe)
Operating costs	$	11.57	$	14.52
Environmental cleanup		10.65		—
Natural gas marketing and transportation expenses		0.73		0.10
Impairment expense		13.35		0.50
Production taxes		5.94		5.62
Depreciation, depletion, and amortization		28.75		21.30
Gain on sale of oil and gas properties		—		(6.06	)
Accretion of discount on asset retirement obligation		0.48		0.85
General and administrative expense		14.45		37.07

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

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Revenues and Production

Oil and Natural Gas Production.During the year ended December 31, 2012, Cross Border had net production sold of 197,247 Boe, compared to net production sold of 98,855 Boe during the year ended December 31, 2011. The increase in net production sold was attributable to the completion and bringing online of 20 new wells in 2012, offset by natural declines in existing wells. For the year ended December 31, 2012, 75.8% of its net production sold was oil and 24.2% was natural gas, compared to 57.4% oil and 42.6% natural gas for the year ended December 31, 2011.

Oil and Natural Gas Sales.During the year ended December 31, 2012, Cross Border had oil and natural gas sales of $14.8 million, as compared to $6.6 million during the year ended December 31, 2011. The increase in oil and natural gas sales was attributable to the completion and bringing online of 20 new wells in 2012, offset by natural declines in existing wells.

Costs and Expenses

Operating Costs. During the year ended December 31, 2012, Cross Border incurred operating costs of $2.3 million, as compared to $1.4 million during the year ended December 31, 2011. The increase in operating costs can be attributed to the completion and bringing online of new wells during the year. In addition, Cross Border incurred approximately $0.8 million to recomplete three salt water disposal wells in which Cross Border owns a 100% working interest.

Environmental Cleanup. For the year ended December 31, 2012, Cross Border incurred a $2.1 million non-cash charge related to required environmental remediation activities on its Tom Tom/Tomahawk field. There were no such charges in the year ended December 31, 2011.

Impairment. For the year ended December 31, 2012, impairment expense was $2.6 million compared to approximately $49,000 for the year ended December 31, 2011. Cross Border incurred a $1.8 million impairment charge related to its Wolfberry assets which were sold effective August 1, 2012. Further, due to the decline in the value of its reserves, Cross Border incurred an approximately $0.8 million impairment charge in the fourth quarter.

Production Taxes. Production taxes were $1.2 million for the year ended December 31, 2012, as compared to $0.6 million for the year ended December 31, 2011. The increase in production taxes was attributable to increased production from the completion and bringing online of new wells during the year.

Depreciation, Depletion, and Amortization. For the year ended December 31, 2012, depreciation, depletion, and amortization was $5.7 million, as compared to $2.1 million for the year ended December 31, 2011. The increase in depreciation, depletion, and amortization was attributable to increased production and a higher rate of depletion in 2012 due to overall lower reserve volumes.

General and Administrative Expense. General and administrative expense was $2.9 million for the year ended December 31, 2012, as compared to $3.7 million for the year ended December 31, 2011. In general, general and administrative expenditures were dramatically lower year-over-year. Professional fees were lower by $0.7 million in 2012 as compared to the prior year. In May 2012, its former Chief Executive Officer and former Chief Operations Officer resigned their positions. Further, effective July 31, 2012, its former Chief Accounting Officer resigned her position. Accordingly, personnel costs were $0.4 million lower in 2012 than in 2011. There was no stock based compensation in 2012 while in 2011 Cross Border incurred $0.5 million in stock based compensation expenditures. These reductions in expenditures were offset by $0.9 million related to change in control payments made to its former officers and employees. There were no change of control expenditures in the year ended December 31, 2011.

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Other Expense. Other expense was $0.2 million for the year ended December 31, 2012, as compared to $0.3 million for the year ended December 31, 2011. The decrease in other expense was related to an increase in bond issuance amortization, an increase in interest expense, and a decrease in other income offset by an increase in gain on its derivatives contracts.

Liquidity and Capital Resources

General

Cross Border’s primary sources of liquidity are cash flow from operations and borrowings under its line of credit. Its ability to fund planned capital expenditures and to make acquisitions depends upon its future operating performance, availability of borrowings under its line of credit and availability of equity and debt financing, which is affected by prevailing economic conditions in its industry and financial, business and other factors, some of which are beyond its control. Its cash flow from operations is mainly influenced by the prices Cross Border receives for its oil and natural gas production and the quantity of oil and natural gas it produces. 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 its control.

Liquidity

At December 31, 2012, Cross Border had $0.2 million in cash and cash equivalents, $8.8 million outstanding under its line of credit with Texas Capital Bank (“TCB”), $0.8 million in subordinated unsecured debt, and $1.4 million due to bankruptcy creditors. At December 31, 2012, its line of credit with TCB was fully drawn. At December 31, 2012, Cross Border had a working capital deficit of $3.3 million compared to a working capital deficit of $40,000 at December 31, 2011.

On February 5, 2013, Cross Border entered into the Credit Agreement with Independent Bank. Its initial draw on the line of credit was $8.9 million which was primarily used to pay off the TCB line of credit. On February 28, 2013, Cross Border drew another $2.0 million on the line of credit and utilized those funds to pay for capital expenditures associated with its drilling activity.

In February 2013, Cross Border settled certain liabilities to its creditors for $633,975 in cash and by arranging for its largest shareholder, Red Mountain, to issue the creditors an aggregate of 745,854 shares of its common stock. Further, Red Mountain, the holder of the subordinated unsecured debt of Cross Border, elected to convert the entire principal and accrued interest balance of the debt into 611,630 shares of Cross Border’s common stock.

Cash Flows

Net cash provided by operating activities was $7.0 million for the year ended December 31, 2012, compared to net cash used by operating activities of $2.9 million for the year ended December 31, 2011. The increase in net cash provided by operating activities was primarily due to a $2.4 million loss, offset by $8.3 million of non-cash depreciation, depletion, amortization and impairment, and $2.1 million non-cash environmental liability cleanup charge.

Net cash used in investing activities increased to $10.0 million for the year ended December 31, 2012 from $2.1 million for the year ended December 31, 2011 due to an increase in capital expenditures for the continued development of Cross Border’s oil and natural gas properties, offset by the receipt of approximately $2.3 million of proceeds from the sale of some of its oil and natural gas properties.

During the year ended December 31, 2012, Cross Border’s net cash provided by financing activities was $2.8 million, as compared to $4.5 million during the year ended December 31, 2011. Net cash provided by financing activities during the year ended December 31, 2012 was primarily comprised of $7.1 million drawn under Cross Border’s line of credit, offset by repayments of its line of credit of $0.8 million, repayments of bonds of $3.4 million, and repayments to creditors of $0.2 million.

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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 have established acreage positions and production in the Permian Basin of West Texas and Southeast New Mexico and the onshore Gulf Coast of Texas. Additionally, we have an established and growing acreage position in Kansas.

We plan to grow production and reserves by acquiring, exploring and developing an inventory of long-life, low risk drilling opportunities with attractive rates of return. Our focus is on opportunities in and around producing oil and natural gas properties where we can enhance production and reserves through application of newer drilling and completion techniques, infill drilling, targeting untapped but known productive hydrocarbon strata, and enhanced oil recovery applications.

As of May 31, 2013, we owned interests in 883,226 gross (305,845 net) mineral and lease acres in New Mexico, Texas and Kansas, of which 336,851 gross (31,011 net) acres are within the Permian Basin. We have successfully leased over 5,200 net acres in Kansas located on the Central Kansas Uplift, and we also owned interests in over 1,400 net acres located on the Villarreal, Frost Bank, Resendez, Peal Ranch and La Duquesa Prospects in the Gulf Coast of Texas.

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 acquisition, we owned 47% of Cross Border’s outstanding common stock, and the investment was accounted for under the equity method of accounting. Subsequent to this transaction, we account for Cross Border as a consolidated subsidiary. As of May 31, 2013, we owned of record 14,327,767 shares of Cross Border common stock, representing 83% of Cross Border’s outstanding common stock.

History

Red Mountain, a Florida corporation, was originally formed in January 2010 as Teaching Time, Inc. in order to design, develop, and market instructional products and services for the corporate, education, government, and healthcare e-learning industries. In March 2011, Teaching Time, Inc. determined to enter into oil and natural gas exploration, development and production and changed its name to Red Mountain Resources, Inc. to better reflect that plan. On March 22, 2011, we entered into the Share Exchange Agreement with Black Rock Capital, LLC and StoneStreet, the sole shareholder of Black Rock Capital, LLC. Alan W. Barksdale, our current president, chief executive officer and chairman of the board, was the president and the sole member of Black Rock Capital, LLC and sole owner and the president of StoneStreet. On June 22, 2011, we completed a reverse merger pursuant to the Share Exchange Agreement in which we issued 27,000,000 shares of common stock to StoneStreet in exchange for 100% of the interests in Black Rock Capital, LLC. Concurrently with the closing, we retired 225,000,000 shares of common stock for no additional consideration. In connection with the reverse merger, the management of Black Rock Capital, LLC became our management.

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

Black Rock was originally formed on October 28, 2005 as an Arkansas limited liability company under the name “Black Rock Capital, LLC.” From inception through May 2010, Black Rock had no operations. Effective June 1, 2010, Black Rock purchased two separate oil and natural gas fields out of the bankruptcy estate of MSB

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Energy, Inc. located in Zapata County and Duval County in the onshore Gulf Coast of Texas. Effective May 31, 2011, Black Rock acquired our current interests in the Madera Prospect. In June 2011, Black Rock Capital, LLC filed Articles of Conversion with the Secretary of State for the State of Arkansas to convert Black Rock Capital, LLC into a corporation. The conversion became effective July 1, 2011 and, accordingly, Black Rock Capital, LLC was converted to Black Rock Capital, Inc. As a result of the conversion, our 100% membership interest in Black Rock Capital, LLC became an interest in all of the outstanding common stock of Black Rock.

Recent Developments

Bamco Asset Purchase Agreement. On December 10, 2012, we entered into the Asset Purchase Agreement with Bamco. Mr. Barksdale was the receiver for the receivership estate of Bamco. Pursuant to the Asset Purchase Agreement, we agreed to acquire the Bamco Properties. On December 10, 2012, pursuant to the Asset Purchase Agreement, we issued 2,375,000 shares of our common stock to the indenture trustee of certain debentures of Bamco, and we executed a waiver and release of a claim against the receivership estate of Bamco for a $2.7 million note receivable that we deemed uncollectible in 2011.

Acquisition of Cross Border.On January 28, 2013, pursuant to privately negotiated transactions, we acquired 5,091,210 shares of common stock of Cross Border from a limited number of stockholders in exchange for the issuance of 10,182,420 shares of our common stock, bringing our total ownership to approximately 78% of Cross Border’s outstanding common stock. Prior to the Acquisition, we owned 47% of Cross Border’s outstanding common stock, and the investment was accounted for under the equity method of accounting. Subsequent to the Acquisition, we account for Cross Border as a consolidated subsidiary. As of May 31, 2013, we owned of record 14,327,767 shares of Cross Border common stock, representing 83% of Cross Border’s outstanding common stock. In addition, as of May 31, 2013, we owned warrants to acquire an additional 2,502,831 shares of Cross Border common stock. The warrants have an exercise price of $2.25 per share and are exercisable until May 26, 2016.

As of February 28, 2013, Cross Border owned over 865,893 gross (293,843 net) mineral and lease acres in New Mexico and Texas, of which approximately 25,000 net acres were located in the Permian Basin. A significant majority of Cross Border’s acreage consists of either owned mineral rights or leases held by production, allowing it to hold lease rental payments to under $5,000 annually. The majority of Cross Border’s acreage interests consists of non-operated working interests except for certain core San Andres properties which it operates.

Senior Credit Facility. On February 5, 2013, we entered into the Credit Agreement with Independent Bank. The Credit Agreement provides for an up to $100.0 million revolving credit facility with an initial commitment of $20.0 million and a maturity date of February 5, 2016. Simultaneously with entering into the Credit Agreement, we borrowed $7.6 million under the Credit Facility and used a portion of the proceeds to repay outstanding indebtedness, and Cross Border borrowed $8.9 million and used a portion of the proceeds to repay in full its existing credit facility. As of May 31, 2013, the Borrowers had collectively borrowed $19.8 million and had availability of $0.2 million under the Credit Facility. On February 21, 2013, pursuant to the terms of the Credit Agreement, we entered into a hedge agreement with BP Energy to hedge a portion of the future oil production of the Borrowers.

We were not in compliance with the financial covenants in the Credit Agreement for the three months ended February 28, 2013. On May 2, 2013, we entered into an amendment to the Credit Agreement, which waived the non-compliance and amended certain financial ratios in the Credit Agreement to become effective starting May 31, 2013. As a result, as of May 2, 2013, we are no longer in default under the Credit Agreement.

On July 19, 2013, we entered into an amendment to the 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.

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Private Placements. On February 5, 2013, we closed a private placement for 7,058,823 shares of common stock at a purchase price of $0.85 per share, raising gross proceeds of $6.0 million, from certain of the initial investors in our company. We used the proceeds for drilling expenses, repayment of debt and general working capital. On May 3, 2013, we closed a private placement for 3,529,412 shares of common stock at a purchase price of $0.85 per share, raising gross proceeds of $3.0 million, from certain of the initial investors in our company. We used the proceeds for general working capital.

Madera 24 Federal 3H Well. During the three months ended February 28, 2013, we commenced drilling the Madera 24 Federal 3H well, which is located in the Madera prospect just to the west of the Madera 24 Federal 2H well. We are the operator of the well and own a 33% working interest. The well was spudded on February 6, 2013 and, on May 10, 2013, we finished drilling and completing the well. The initial production rate from the Madera 24 Federal 3H well was 1,491 Boe (81% oil). The well has a total measured depth of 13,570 feet, including a true vertical depth of 9,062 feet and a lateral length of 4,508 feet. At May 31, 2013, the well was still producing and permanent production facilities were under construction.

Change of Fiscal Year End. On July 17, 2013, we changed our fiscal year end from May 31 to June 30, effective June 30, 2013.

Closing of Units Offering. In August 2013, we closed an offering of 375,676 Units, including 100,002 Units sold in cancellation of $2.3 million in debt, raising gross cash proceeds of $6.2 million. Each Unit consisted of one share of Series A Preferred Stock and one warrant to purchase up to 25 shares of common stock. We intend to use the proceeds for general corporate purposes, including to fund a portion of our fiscal 2014 drilling and development expenditures and the payment of accrued interest and fees on indebtedness that was cancelled.

Our Properties

Currently, our oil and natural gas properties are concentrated in the Permian Basin, the onshore Gulf Coast of Texas, Southwest New Mexico and Kansas. The Permian Basin covers an area approximately 250 miles wide and 300 miles long in West Texas and Southeast New Mexico. The Permian Basin is one of the most prolific onshore oil and natural gas producing regions in the United States. It is characterized by an extensive production history, mature infrastructure, long reserve life and hydrocarbon potential in multiple producing formations. Our primary operations in the onshore Gulf Coast are in conventional fields that produce primarily from the Wilcox formation in Zapata and Duval Counties of Texas.

Permian Basin. As of May 31, 2013, we had interests in 336,851 gross (31,011 net) acres in the Permian Basin, consisting of the Madera Prospect, Pawnee Prospect, Cowden Lease, Shafter Lake Lease, Martin Lease, Jackson Bough C Prospect, East Ranch Prospect and West Ranch Prospect. We are the operator of each of these properties.

This includes the oil and gas interests of Cross Border in the Permian Basin, a large portion of which is nonoperated acreage located in the heart of the Bone Spring play in central Lea and Eddy counties. Cross Border also has nonoperated acreage in the Yeso and Abo trends along the Northwest Shelf and in areas targeting the Queen, Grayburg, and San Andres reservoirs. Cross Border also holds acreage in the Tom Tom area, where it is the operator.

In the aggregate, as of May 31, 2013, these properties had 209 gross (92.4 net) producing wells and, during the month of May 2013, had daily average net production of 636 Boe/d, substantially all of which was oil. As of May 31, 2013, our Permian Basin properties had approximately 3,147 MBoe of proved reserves, of which 74% was oil. Of our proved reserves in the Permian Basin, 32% are from the Madera Prospect. On a pro forma basis, during the nine months ended February 28, 2013, we derived approximately 89.6% of our revenue from the Permian Basin.

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Onshore Gulf Coast. As of May 31, 2013, we had interests in 4,776 gross (1,405 net) acres in the onshore Gulf Coast of Texas, consisting of the Villarreal Prospect, Frost Bank Prospect, 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.

In the aggregate, as of May 31, 2013, these properties had 39 gross (13.0 net) wells and, during the month of May 2013, had daily average net production of 244 Boe/d, substantially all of which was natural gas. As of May 31, 2013, our onshore Gulf Coast properties had approximately 401 MBoe of proved reserves, substantially all of which was natural gas. Of our proved reserves in the onshore Gulf Coast, 74% are from the Villarreal Prospect. On a pro forma basis, during the nine months ended February 28, 2013, we derived approximately 7.7% of our revenue from the onshore Gulf Coast.

Southwest New Mexico. As of May 31, 2013, owned 536,340 gross (268,170 net) mineral acres in Hidalgo, Grant, Sierra, and Socorro Counties, New Mexico. This mineral ownership carries no drilling commitments or leasehold obligations. As of May 31, 2013 this acreage had no proved reserves or production.

Kansas. As of May 31, 2013, we owned oil and natural gas interests in 5,215 gross and net acres in central Kansas. There are multiple target horizons in this prospect including the Arbuckle and the Lansing Kansas City formations. We own a 100% working interest and an average net revenue interest of 80%. RMR Operating is the operator. As of May 31, 2013, the Kansas acreage had no proved reserves or production.

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

Planned Operations

During fiscal year 2014, we plan to spend between $35.0 million and $45.0 million for drilling, completion, workovers, and recompletion on our properties including Madera, Tom Tom, Cowden, Central Kansas Uplift acreage and our prospect located in Pecos County, Texas. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations of Red Mountain—Planned Operations.”

Marketing and Customers

During the nine months ended February 28, 2013, we sold $2.2 million of oil to Andrews Oil Buyers, Inc. (“Andrews Oil”), representing approximately 44% of our total revenues. We sell our oil to Andrews Oil from our Good Chief State #1, Big Brave State #1 and Madera 24 Federal 2H wells pursuant to crude oil purchase contracts. The price of the oil delivered is based on the West Texas Intermediate price, subject to certain price adjustments. The purchase agreements continue until terminated by either party with thirty days prior written notice. We believe that the loss of Andrews Oil would not have a material adverse effect on us because alternative purchasers are readily available.

Competition

The oil and natural gas industry is highly competitive and we compete with a substantial number of other companies that have greater resources than we do. The largest of these companies explore for, produce and market oil and natural gas, carry on refining operations and market the resultant products on a worldwide basis. The primary areas in which we encounter substantial competition are in our drilling and development operations, locating and acquiring prospective oil and natural gas properties and reserves and attracting and retaining highly skilled personnel. There is also competition between producers of oil and natural gas and other industries producing alternative energy and fuel. Furthermore, competitive conditions may be substantially affected by various forms of energy legislation and/or regulation considered from time to time by the United States government; however, it is not possible to predict the nature of any such legislation or regulation that may ultimately be adopted or its effects upon our future operations. Such laws and regulations may, however,

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substantially increase the costs of exploring for, developing or producing oil and natural gas and may prevent or delay the commencement or continuation of a given operation. The effect of these risks cannot be accurately predicted.

Insurance

We currently maintain oil and gas commercial general liability protection relating to all of our oil and gas operations (including environmental and pollution claims) with a total limit of coverage in the amount of $2.0 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 gas industry, we will not insure fully against all risks associated with our business either because such insurance is not available or because premium costs are considered prohibitive. In addition, pollution and environmental risks generally are not fully insurable. A loss not fully covered by insurance could have a material adverse effect on our business, financial condition and results of operations.

Legal Proceedings

On May 4, 2011, Clifton M. (Marty) Bloodworth filed a lawsuit in the State District Court of Midland County, Texas, against Doral West Corp. d/b/a Doral Energy Corp. and Everett Willard Gray II. Mr. Bloodworth alleges that Mr. Gray, as CEO of Cross Border, made false representations which induced Mr. Bloodworth to enter into an employment contract that was subsequently breached by Cross Border. The claims that Mr. Bloodworth has alleged are: breach of his employment agreement with Doral West Corp, common law fraud, civil conspiracy breach of fiduciary duty, and violation of the Texas Deceptive Trade Practices-Consumer Protection Act. Mr. Bloodworth is seeking damages of approximately $280,000. Mr. Gray and Cross Border deny that Mr. Bloodworth’s claims have any merit.

Cross Border was previously party to an engagement letter, dated February 7, 2012 (the “Engagement Letter”), with KeyBanc Capital Markets Inc. (“KeyBanc”) pursuant to which KeyBanc was to act as exclusive financial advisor to Cross Border’s Board of Directors in connection with a possible “Transaction” (as defined in the Engagement Letter). The Engagement Letter was formally terminated by Cross Border on August 21, 2012. The Engagement Letter provided that KeyBanc would be entitled to a fee upon consummation of a Transaction within a certain period of time following termination of the Engagement Letter. On May 16, 2013, KeyBanc delivered an invoice to Cross Border in the amount of $751,334, representing amounts purportedly owed by Cross Border to KeyBanc as a result of the consummation of a purported Transaction that KeyBanc asserts had been consummated within the required time period and its out-of-pocket expenses in connection therewith. Cross Border disputes that any Transaction was consummated and that KeyBanc is entitled to any out-of-pocket expenses. The matter was originally filed in the 44th-B Judicial District Court for the State of Texas, Dallas County but was subsequently removed to the United States District Court for the Northern District of Texas, Dallas Division. Cross Border intends to vigorously defend the action.

Employees

As of May 31, 2013, we had 27 full-time employees. We are not a party to any collective bargaining agreements and have not experienced any strikes or work stoppages. We believe our relationships with our employees are good.

Hydraulic Fracturing Policies and Procedures

We contract with third parties to conduct hydraulic fracturing as a means to maximize the productivity of our oil and natural gas wells in almost all of our wells. Hydraulic fracturing involves the injection of water, sand, gel and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. All of our proved non-producing and proved undeveloped reserves associated with future drilling, completion and recompletion projects will require hydraulic fracturing.

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Although average drilling and completion costs for each area will vary, as will the cost of each well within a given area, on average approximately 40% of the drilling and completion costs for our wells are associated with hydraulic fracturing activities. These costs are treated in the same way that all other costs of drilling and completing our wells are treated and are built into and funded through our normal capital expenditures budget. A change to any federal and state laws and regulations governing hydraulic fracturing could impact these costs and adversely affect our business and financial results. See “Risk Factors—Federal and state legislative and regulatory initiatives as well as governmental reviews relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays as well as adversely affect our level of production.”

The protection of groundwater quality is important to us. Our policy and practice is to ensure our service providers follow all applicable guidelines and regulations in the areas where we have hydraulic fracturing operations. In addition, we send at least one of our own engineers or an experienced consultant to the well site to personally supervise each hydraulic fracture treatment.

We believe that the hydraulic fracturing operations on our properties are conducted in compliance with all state and federal regulations and in accordance with industry standard practices for groundwater protection. These protective measures include setting surface casing at a depth sufficient to protect fresh water zones as determined by applicable state regulatory agencies, and cementing the casing to create a permanent isolating barrier between the casing pipe and surrounding geological formations. The casing plus the cement are intended to prevent contact between the fracturing fluid and any aquifers during the hydraulic fracturing or other well operations. For recompletions of existing wells, the production casing is pressure tested prior to perforating the new completion interval. Injection rates and pressures are monitored at the surface during our hydraulic fracturing operations. Pressure is monitored on both the injection string and the immediate annulus to the injection string.

The vast majority of hydraulic fracturing treatments are made up of water and sand or other kinds of man-made propping agents. Our service providers track and report chemical additives that are used in the fracturing operation as required by the applicable governmental agencies.

Hydraulic fracturing requires the use of a significant amount of water. All produced water, including fracture stimulation water, is disposed of in a way that does not impact surface waters. All produced water is disposed of in permitted and regulated disposal facilities.

Environmental Matters and Regulation

Our exploration, development and production operations are subject to various federal, state and local laws and regulations governing health and safety, the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may, among other things: require the acquisition of permits to conduct exploration, drilling and production operations; govern the amounts and types of substances that may be released into the environment in connection with oil and natural gas drilling and production; restrict the way we handle or dispose of our wastes or of naturally occurring radioactive materials generated by our operations; cause us to incur significant capital expenditures to install pollution control or safety related equipment operating at our facilities; limit or prohibit construction or drilling activities in sensitive areas such as wetlands, wilderness areas or areas inhabited by endangered or threatened species; impose specific health and safety criteria addressing worker protection; require investigatory and remedial actions to mitigate pollution conditions caused by our operations or attributable to former operations; impose obligations to reclaim and abandon well sites and pits and impose substantial liabilities on us for pollution resulting from our operations. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations and the issuance of orders enjoining some or all of our operations in affected areas.

Additionally, the United States Congress and federal and state agencies frequently revise environmental, health and safety laws and regulations, and their interpretations thereof, and any changes that result in more stringent and costly operational requirements or waste handling, disposal, cleanup and remediation requirements

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for the oil and natural gas industry could have a significant impact on our operating costs. The trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, and thus, any changes in environmental laws and regulations or new interpretations of enforcement policies that result in more stringent and costly waste handling, storage, transport, disposal or remediation requirements could have a material adverse effect on our financial condition and results of operations. We may be unable to pass on such increased compliance costs to our customers.

We believe that we are in substantial compliance with all existing environmental laws and regulations applicable to our current operations and that our continued compliance with existing requirements will not have a material adverse impact on our financial condition and results of operations. We have not incurred any material capital expenditures for remediation or pollution control activities during fiscal 2012, and we are not aware of any environmental issues or claims that will require material capital expenditures during fiscal 2013, other than the remediation plan for Cross Border’s Tom Tom and Tomahawk fields, or that will otherwise have a material impact on our financial condition and results of operations in the future. However, we cannot assure you that the passage of more stringent laws and regulations in the future will not have a negative impact on our business, financial condition or results of operations.

The following is a summary of the more significant existing environmental, health and safety laws and regulations to which our business is subject and for which compliance may have a material adverse impact on our capital expenditures, financial condition or results of operations.

Comprehensive Environmental Response, Compensation and Liability Act. Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the “Superfund” law, and comparable state statutes impose strict and joint and several liability for costs of investigation and removal and remediation of previously disposed wastes (including wastes disposed of or released by prior owners or operators) or property contamination (including groundwater contamination), for natural resource damages and the cost of certain health studies without regard to fault or legality of the original conduct, on certain classes of persons with respect to the release into the environment of substances designated under CERCLA as hazardous substances. These classes of persons, or so-called potentially responsible parties (“PRPs”) include the current and past owners or operators of a site where the release occurred and anyone who transported or disposed or arranged for the transport or disposal of a hazardous substance found at the site. CERCLA also authorizes the Environmental Protection Agency (the “EPA”) and, in some instances, third parties to take actions in response to threats to public health or the environment and to seek to recover from the PRPs the costs of such action. Additionally, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. Many states have adopted comparable or more stringent state statutes.

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

Solid and Hazardous Waste Handling. The Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes and regulations promulgated thereunder regulate the generation, transportation, treatment, storage, disposal and cleanup of solid and hazardous waste. With federal approval, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent regulations. Although oil and natural gas waste generally is exempt from regulations as hazardous waste under RCRA, such wastes may constitute “solid wastes” that are subject to the less stringent requirements of non-hazardous waste provisions. Additionally, we will generate waste as a routine part of our operations that may be subject to RCRA and not all state and local laws contain a comparable exemption. Further, there is no guarantee that the Environmental Protection Agency (“EPA”) or individual states or local governments will not adopt more stringent requirements for the handling of non-hazardous waste or categorize some non-hazardous

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waste as hazardous in the future. Indeed, legislation has been proposed from time to time in Congress to re-categorize certain oil and natural gas exploration, development and production wastes as “hazardous wastes.” Any such change could result in an increase in our costs to manage and dispose of waste, which could have a material adverse effect on our financial condition and results of operations.

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

Administrative, civil and criminal penalties can be imposed for failure to comply with waste handling requirements. We believe that we are in substantial compliance with applicable requirements related to waste handling, and that we hold all necessary and up-to-date permits, registrations and other authorizations to the extent that our operations require them under such laws and regulations. Although we do not believe the current costs of managing our wastes, as presently classified, to be significant, any legislative or regulatory reclassification of oil and natural gas exploration and production wastes could increase our costs to manage and dispose of such wastes.

Water Discharges. The Federal Water Pollution Control Act of 1972, as amended, also known as the Clean Water Act (the “CWA”), the Safe Drinking Water Act (the “SDWA”), the Oil Pollution Act (the “OPA”) and analogous state laws and regulations promulgated thereunder impose restrictions and strict controls regarding the unauthorized discharge of pollutants, including produced waters and other gas and oil wastes, into navigable waters of the United States, as well as state waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of certain permits issued by the EPA or an analogous state agency. Spill prevention, control and countermeasure (“SPCC”) requirements under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. In addition, the Clean Water Act and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. The Clean Water Act also prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by a permit issued by the United States Army Corps of Engineers. In addition, on October 20, 2011, the EPA announced a schedule to develop pre-treatment standards for wastewater discharges produced by natural gas extraction from underground coalbed and shale formations. The EPA stated that it will gather data, consult with stakeholders, including ongoing consultation with industry, and solicit public comment on a proposed rule for coalbed methane in 2013 and a proposed rule for shale gas in 2014. Costs may be associated with the treatment of wastewater or developing and implementing storm water pollution prevention plans, as well as for monitoring and sampling the storm water runoff from certain of our facilities. Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions.

Federal and state regulatory agencies can impose administrative, civil and criminal penalties, as well as require remedial or mitigation measures, for non–compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations. In the event of an unauthorized discharge of wastes, we may be liable for penalties and costs of remediation. The Oil Pollution Act of 1990 (“OPA”) is the primary federal law for oil spill liability. The OPA imposes requirements on “responsible parties” related to the prevention of oil spills and liability for damages resulting from oil spills into or upon navigable waters, adjoining shorelines or in the exclusive economic zone of the United States. A “responsible party” under the OPA may include the owner or operator of an onshore facility. The OPA subjects responsible parties to strict, joint and several financial liability for removal costs and other damages, including natural resource damages, caused by an oil spill that is covered by the statute. It also imposes other requirements on responsible parties, such as the preparation of an oil spill contingency plan and maintaining certain significant levels of financial assurance to cover potential environmental cleanup and restoration costs. Failure to comply with the OPA may subject a

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responsible party to civil or criminal enforcement action. We may conduct operations on acreage located near, or that affects, navigable waters subject to the OPA. We believe that compliance with applicable requirements under the OPA will not have a material and adverse effect on us.

Hydraulic fracturing is a practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations. The process involves the injection of water, sand and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. Although hydraulic fracturing has historically been regulated by state oil and gas commissions the EPA recently asserted federal regulatory authority over the process under the SDWA’s Underground Injection Control (“UIC”) Program. Under this assertion of authority, the EPA requires facilities to obtain permits to use diesel fuel in hydraulic fracturing operations, specifically in Class II wells, which are those wells injecting fluids associated with oil and natural gas production activities. The U.S. Energy Policy Act of 2005, which exempts hydraulic fracturing from regulation under the SDWA, prohibits the use of diesel fuel in the fracturing process without a UIC permit. On May 4, 2012, the EPA published a draft UIC Program permitting guidance for oil and natural gas hydraulic fracturing activities using diesel fuel. The guidance document is designed for use by EPA UIC permit writers, and describes how Class II regulations may be tailored to address the purported unique risks of diesel fuel injection during the hydraulic fracturing process. Although EPA has delegated UIC permitting authority to many states, it is encouraging those states to review and consider use of this permit guidance. The draft guidance document underwent an extended public comment process, which concluded on August 23, 2012. The EPA is presently evaluating the public comments and will likely issue a final guidance document at a later date. On November 3, 2011, the EPA released its Plan to Study the Potential Impacts of Hydraulic Fracturing on Drinking Water Resources. The study will include both analysis of existing data and investigative activities designed to generate future data. The EPA issued a progress report in December 2012, and expects to release a final report for public comment and peer review in 2014. In addition, legislation is pending in Congress to repeal the hydraulic fracturing exemption from the SDWA, provide for federal regulation of hydraulic fracturing, and require public disclosure of the chemicals used in the fracturing process, and such legislation could be introduced in the current session of Congress. The agency also announced that one of its enforcement initiatives for 2011 to 2013 would be to focus on environmental compliance by the energy extraction sector. This additional regulatory scrutiny could make it difficult to perform hydraulic fracturing and increase our costs of compliance and doing business.

Many states have adopted, and other states are considering adopting, legislation or regulations requiring the disclosure of the chemicals used in hydraulic fracturing or otherwise restrict hydraulic fracturing in certain circumstances. For example, pursuant to legislation adopted by the State of Texas in June 2011, beginning February 1, 2012, companies were required to disclose to the Railroad Commission of Texas (the “RRC”) and the public the chemical components used in the hydraulic fracturing process, as well as the volume of water used. Furthermore, on May 23, 2013, the RRC issued the “well integrity rule,” which updates the RRC’s Rule 13 requirements for drilling, putting pipe down, and cementing wells. The rule also includes new testing and reporting requirements, such as (i) the requirement to submit to the RRC cementing reports after well completion or after cessation of drilling, whichever is later, and (ii) the imposition of additional testing on wells less than 1,000 feet below usable groundwater. The “well integrity rule” takes effect in January 2014. The Wyoming Oil and Gas Conservation Commission also passed a rule requiring disclosure of hydraulic fracturing fluid. In addition, a number of states in which we plan to conduct, are currently conducting, or may in the future conduct, hydraulic fracturing operations regularly review hydraulic fracturing and new regulations from such reviews could restrict or limit our access to shale formations or could delay our operations or make them more costly. In addition to state law, local land use restrictions, such as city ordinances, may restrict or prohibit the performance of well drilling in general and/or hydraulic fracturing in particular.

Finally, with respect to our operations that occur on federally managed public lands, on May 16, 2013, the U.S. Department of Interior (“DOI”) issued a proposed rule that seeks to require companies operating on federal and Indian lands to (i) publicly disclose the chemicals used in the hydraulic fracturing process, (ii) confirm their wells meet certain construction standards and (iii) establish site plans to manage flowback water. The revised proposed rule is presently subject to an extended 90-day public comment period, which ends on August 23, 2013.

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Air Emissions. Our operations are subject to federal regulations for the control of emissions from sources of air pollution under the Clean Air Act (“CAA”), as amended, and analogous state and local regulations. Federal and state laws require new and modified sources of air pollutants to obtain permits prior to commencing construction and also impose various monitoring and reporting requirements. Major sources of air pollutants are subject to more stringent, federally imposed requirements including additional permits. Federal and state laws designed to control hazardous or toxic air pollutants may require installation of additional controls. Administrative enforcement actions for failure to comply strictly with air pollution regulations or permits are generally resolved by payment of monetary fines and correction of any identified deficiencies. Alternatively, regulatory agencies could bring lawsuits for civil penalties or require us to forego construction, modification or operation of certain air emission sources.

In August 2012, the EPA adopted rules that subject oil and natural gas production, processing, transmission, and storage operations to regulation under the New Source Performance Standards, or NSPS, and National Emission Standards for Hazardous Air Pollutants, or NESHAP, programs. The rule includes NSPS standards for completions of hydraulically fractured gas wells and establishes specific new requirements for emissions from compressors, controllers, dehydrators, storage vessels, natural gas processing plants and certain other equipment. The final rule became effective October 15, 2012; however, a number of the requirements did not take immediate effect. The final rule establishes a phase-in period to allow for the manufacture and distribution of required emissions reduction technology. During the first phase, ending December 31, 2014, owners and operators of gas wells must either flare their emissions or use emissions reduction technology called “green completions” technologies already deployed at wells. On or after January 1, 2015, all newly fractured gas wells will be required to use green completions. Controls for certain storage vessels and pneumatic controllers may phase-in over one year beginning on the date the final rule is published in the Federal Register, while certain compressors, dehydrators and other equipment must comply with the final rule immediately or up to three years and 60 days after publication of the final rule, depending on the construction date and/or nature of the unit. We continue to evaluate the EPA’s final rule, as it may require changes to our operations, including the installation of new emissions control equipment. These standards, as well as any future laws and their implementing regulations, may require us to obtain pre-approval for the expansion or modification of existing facilities or the construction of new facilities expected to produce air emissions, impose stringent air permit requirements, or utilize specific equipment or technologies to control emissions. Our failure to comply with these requirements could subject us to monetary penalties, injunctions, conditions or restrictions on operations and, potentially, criminal enforcement actions.

We have incurred additional capital expenditures to insure compliance with these new regulations as they come into effect. We may also be required to incur additional capital expenditures in the next few years for air pollution control equipment in connection with maintaining or obtaining operating permits addressing other air emission related issues, which may have a material adverse effect on our operations. Obtaining permits also has the potential to delay the development of oil and natural gas projects. We believe that we currently are in substantial compliance with all air emissions regulations and that we hold all necessary and valid construction and operating permits for our current operations.

Climate Change Legislation. In response to certain scientific studies suggesting that emissions of carbon dioxide, methane and other greenhouse gases (“GHGs”) are contributing to the warming of the Earth’s atmosphere and other climatic changes, the United States Congress has considered legislation to reduce such emissions. To date, the United States Congress has failed to enact a comprehensive GHG program. Some states, either individually or on a regional level, have considered or enacted legal measures to reduce GHG emissions. Although most of the state-level initiatives have to date focused on large sources of GHG emissions, it is possible that smaller sources of emissions could become subject to GHG emission limitations. The cost of complying with these programs could be significant.

The EPA published finding that emissions of GHGs presented an endangerment to public health and the environment. These findings by the EPA allowed the agency to proceed through a rule-making process with the adoption and implementation of regulations that would restrict emissions of GHGs under existing provisions of

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the CAA. Consequently, the EPA adopted two sets of regulations that would require a reduction in emissions of GHGs from motor vehicles and could trigger permit review for GHG emissions from certain stationary sources. The EPA adopted the stationary source rule (or the “tailoring rule”) in May 2010, and it also became effective January 2011, although it remains the subject of several pending lawsuits filed by industry groups. The tailoring rule establishes new GHG emissions thresholds that determine when stationary sources must obtain permits under the Prevention of Significant Deterioration, or PSD, and Title V programs of the Clean Air Act. The permitting requirements of the PSD program apply only to newly constructed or modified major sources. Obtaining a PSD permit requires a source to install best available control technology, or BACT, for those regulated pollutants that are emitted in certain quantities. Phase I of the tailoring rule, which became effective on January 2, 2011, requires projects already triggering PSD permitting that are also increasing GHG emissions by more than 75,000 tons per year to comply with BACT rules for their GHG emissions. Phase II of the tailoring rule, which became effective on July 1, 2011, requires preconstruction permits using BACT for new projects that emit 100,000 tons of GHG emissions per year or existing facilities that make major modifications increasing GHG emissions by more than 75,000 tons per year. Phase III of the tailoring rule, which is expected to go into effect in 2013, will seek to streamline the permitting process and permanently exclude smaller sources from the permitting process. Finally, in October 2009, the EPA issued a final rule requiring the reporting of GHG emissions from specified large GHG emission sources in the U.S., including natural gas liquids fractionators and local natural gas/distribution companies, beginning in 2011 for emissions occurring in 2010. In November 2010, the EPA published a final rule expanding the GHG reporting rule to include onshore oil and natural gas production, processing, transmission, storage and distribution facilities. This rule requires reporting of GHG emissions from such facilities on an annual basis, with reporting beginning in 2012 for emissions occurring in 2011. On March 27, 2012, the EPA issued a proposed rule establishing carbon pollution standards for newfossil-fuel-fired electric utility generating units. The proposed rule underwent an extended public comment process, which concluded on June 25, 2012. The EPA is presently evaluating the public comments and is expected to issue a final rule at a later date. The EPA plans to implement GHG emissions standards for refineries at a later date. . The adoption and implementation of any regulations imposing reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations or could adversely affect demand for the oil and natural gas we produce. Any one of these climate change regulatory and legislative initiatives could have a material adverse effect on our business, financial condition and results of operations.

Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts and floods and other climatic events; if any such effects were to occur, they could have a material adverse effect on our business and results of operations.

OSHA and Other Laws and Regulations on Employee Health and Safety.To the extent not preempted by other applicable laws, we are subject to the requirements of the Occupational Safety and Health Act (“OSHA”) and comparable state statutes, where applicable. These laws and the implementing regulations strictly govern the protection of the health and safety of employees. The OSHA hazard communication standard, the EPA community right-to-know regulations under the Title III of CERCLA and similar state statutes, where applicable, require us to organize and maintain information about hazardous materials used or, as applicable, produced in our operations and that this information be provided to employees, state and local government authorities and, where applicable, citizens. OSHA may enforce workplace safety regulations through issuance of citations for violations of its standards, which include, but are not limited to, those regarding hazard communication, personal protective equipment, general environmental controls, and materials handling and storage. We believe that we are in substantial compliance with these requirements where applicable and with other applicable OSHA and comparable requirements.

National Environmental Policy Act.Oil and natural gas exploration and production activities on federal lands may be subject to the National Environmental Policy Act (“NEPA”) which requires federal agencies, including the U.S. Department of the Interior, to evaluate major agency actions having the potential to

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significantly impact the environment. In the course of such evaluations, an agency will prepare an Environmental Assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. All of our current exploration and production activities, as well as proposed exploration and development plans, on federal lands require governmental permits that are subject to the requirements of NEPA. This process has the potential to delay or impose additional conditions upon the development of oil and natural gas projects.

Endangered Species Act.The Endangered Species Act, as amended (the “ESA”), and analogous state statutes restrict activities that may affect endangered and threatened species or their habitats. While some of our facilities may be located in areas that are designated as habitat for endangered or threatened species, we believe that we are in substantial compliance with the ESA. However, the designation of previously unidentified endangered or threatened species could cause us to incur additional costs or become subject to operating restrictions or bans in the affected areas.

Other Regulation of the Oil and Natural Gas Industry

The oil and natural gas industry is extensively regulated by numerous federal, state and local authorities. In particular, oil and natural gas production and related operations are, or have been, subject to price controls, taxes and numerous other laws and regulations. These laws and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability.

Failure to comply with applicable laws and regulations can result in substantial penalties and possibly cessation of drilling and production operations. The regulatory burden on the industry increases the cost of doing business and affects profitability. We believe that we are in substantial compliance with existing requirements and such compliance will not have a material adverse effect on our financial condition, cash flows or results of operations. Nevertheless, such laws and regulations are frequently amended or reinterpreted. Therefore, we are unable to predict the future costs or impact of compliance. Additional proposals and proceedings that affect the oil and natural gas industry are regularly considered by the United States Congress, the states, the Federal Energy Regulatory Commission (“FERC”) and the courts. We cannot predict when or whether any such proposals may become effective.

Drilling and Production.Our operations are subject to various types of regulation at the federal, state and local levels. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. The states and some counties and municipalities in which we operate also regulate one or more of the following:

• the location of wells;

• the method of drilling and casing wells;

• the surface use and restoration of properties upon which wells are drilled; and

• the plugging and abandonment of wells.

State laws, including Texas, regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploitation while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and natural gas we can produce from our wells or limit the number of wells or the locations at which we can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil and natural gas within its jurisdiction.

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In addition, 11 states have enacted surface damage statutes (“SDAs”). These laws are designed to compensate for damage caused by mineral development. Most SDAs contain entry notification and negotiation requirements to facilitate contact between operators and surface owners and users. Most also contain bonding requirements and specific expenses for exploration and producing activities. Costs and delays associated with SDAs could impair operational effectiveness and increase development costs.

We do not control the availability of transportation and processing facilities used in the marketing of our production. For example, we may have to shut-in a productive natural gas well because of a lack of available natural gas gathering or transportation facilities.

If we conduct operations on federal, state or Indian oil and natural gas leases, these operations must comply with numerous regulatory restrictions, including various non-discrimination statutes, royalty and related valuation requirements, and certain of these operations must be conducted pursuant to certain on-site security regulations and other appropriate permits issued by the BLM, the Bureau of Ocean Energy Management, Regulation and Enforcement or other appropriate federal or state agencies.

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

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

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

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

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

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FERC regulates interstate natural gas transportation rates, and terms and conditions of service, and this regulation affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas. Since 1985, the FERC has endeavored to make natural gas transportation more accessible to natural gas buyers and sellers on an open and non-discriminatory basis. The FERC has stated that open access policies are necessary to improve the competitive structure of the interstate natural gas pipeline industry and to create a regulatory framework that will put natural gas sellers into more direct contractual relations with natural gas buyers by, among other things, unbundling the sale of natural gas from the sale of transportation and storage services. Beginning with Order No. 636 in 1992, FERC adopted mandatory open access policies including mandatory standards of conduct governing communications and information sharing between affiliated natural gas transportation and gas marketing employees. As a result, the interstate pipelines’ traditional role of providing the sale and transportation of natural gas as a single service has been eliminated and replaced by a structure under which pipelines provide transportation and storage service on a non-discriminatory, open access basis to others who buy and sell natural gas. Although the FERC’s open access orders do not directly regulate natural gas producers, they are intended to foster increased competition within all phases of the natural gas industry.

The price at which we sell natural gas is not currently subject to federal rate regulation and, for the most part, is not subject to state regulation. However, with regard to our physical sales of these energy commodities, we are required to observe anti-market manipulation laws and related regulations enforced by the FERC and/or the Commodity Futures Trading Commission (the “CFTC”). See “—Other Federal Laws and Regulations Affecting Our Industry—Energy Policy Act of 2005.” Should we violate the anti-market manipulation laws and regulations, we could also be subject to related third party damage claims by, among others, sellers, royalty owners and taxing authorities.

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

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

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

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

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

Other Federal Laws and Regulations Affecting Our Industry

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

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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 location of our core properties as of May 31, 2013.

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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 May 31, 2013. 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)		Oil (MBbls)		Natural Gas (MMcf)		Oil (MBbls)		Natural Gas (MMcf)		Oil (MBbls)		Natural Gas (MMcf)
Permian Basin		864		2,741		150		193		1,304		2,041		2,318		4,975
Onshore Gulf Coast		3		2,257		—		129		—		—		3		2,386
Total		867		4,998		150		322		1,304		2,041		2,321		7,361

Permian Basin

The following description of our properties in the Permian Basin is presented as of May 31, 2013.

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 (3.5 net) producing wells with an average working interest of 49.7% and an average net revenue interest of 38.8%. This acreage includes acreage acquired through an agreement with Chevron in January 2013 to sell ownership in our then existing acreage and associated wells in exchange for ownership in Chevron’s adjoining acreage and associated wells in order to more efficiently develop the prospect. 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 May 31, 2013, the Madera 24 Federal 2H well has produced over 111 MBoe, of which 77% was oil. A portion of the other working interest owners elected not to participate in the drilling and completion of the Madera 24 Federal 2H well. As a result, we increased our ownership to an 80.1% working interest (60.1% net revenue interest). Our ownership will revert to a 23.3% working interest (17.5% net revenue interest) when we recover an amount equal to 300% of the costs to drill and complete the well plus operating costs through that date.

We commenced drilling of the second horizontal well in the Madera prospect, Madera 24 Federal 3H, on February 6, 2013. This well is located just to the west of the Madera 24 Federal 2H well. We are the operator of the well and own a 33% working interest and 25% net revenue interest. At May 31, 2013, we had finished drilling and completing the well. The initial production rate from the Madera 24 Federal 3H well was 1,491 Boe (81% oil). The well has a total measured depth of 13,570 feet, including a true vertical depth of 9,062 feet and a lateral length of 4,508 feet. At May 31, 2013, the well was still producing and permanent production facilities were under construction. The Madera Prospect contains an additional 4 proved undeveloped locations (1.7 net) that target the Brushy Canyon reservoir.

As of May 31, 2013, the Madera Prospect had estimated proved reserves of 1,015 MBoe, of which 690 MBoe were proved undeveloped, and had net daily average production for the month of May 2013 of 76 Boe/d, of which 66% was oil. Production from the Madera 24 Federal 2H well was shut in during May 2013 for the completion of the Madera 24 Federal 3H well.

Pawnee Prospect. We own oil and natural gas interests in 1,575 gross (1,445 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

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formations. RMR Operating is the operator of the Pawnee Prospect. We have a total of six gross and net productive wells on the Pawnee Prospect, four of which we acquired in December 2011 in exchange for the assumption of the plugging liability. Two wells were drilled during fiscal 2012. We completed the Big Brave State #1 well in January 2012 and the Good Chief State #1 well in December 2011, with initial production rates of 52 Boe/d and 28 Boe/d, respectively, consisting of substantially all oil production. Both wells are marginal producers, and we plan to evaluate the wells for potential conversion to salt water disposal wells. As of May 31, 2013, the Pawnee Prospect had estimated proved reserves of 3 MBoe and had net daily average production sold for the month of May 2013 of 8 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 proved undeveloped drilling locations (three net wells). As of May 31, 2013, the Cowden Lease had estimated proved reserves of 100 MBoe, of which 76 MBoe were proved undeveloped, and had net daily average production sold for the month of May 2013 of 9 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 May 31, 2013, 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 351 gross (209 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 May 31, 2013, 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 May 31, 2013, 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 May 31, 2013, 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 78% and an average net revenue interest of 65%. As of May 31, 2013, the Tom Tom area had estimated proved reserves of 518 MBoe, of which 93 MBoe were proved developed non-producing and 357 MBoe were proved undeveloped. The area had net daily average production sold for the month of May 2013 of 14 Boe/d, all of which was oil production.

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On February 11, 2013, the BLM accepted a remediation plan submitted by Cross Border for its Tom Tom and Tomahawk fields. Pursuant to the remediation plan, Cross Border expects to spend $2.1 million during fiscal 2014 and 2015 to correct environmental issues on these fields.

We commenced a 10-well workover program in May 2013 to reenter existing wells, clean out the wellbores, open unperforated pay, and increase pump efficiency. We have identified 12 wells (7.2 net) with proved developed nonproducing reserves. Additionally, there are 14 proved undeveloped locations (10.6 net) that target the San Andres formation.

Non-Operated. Cross Border owns non-operated, oil and natural gas interests in 321,253 gross (19,473 net) acres in Eddy, Lea and Chaves 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, that include Apache Corporation, Mewbourne Oil Company, COG Operating LLC, Alamo Permian Resources, LLC, LRE Operating, LLC, Oxy USA Inc. and Devon Energy Production Company, LP, have significant footprints within these plays and are seeking to add to those footprints through lease and corporate acquisitions. As of May 31, 2013, this non-operated acreage had estimated proved reserves of 1,445 MBoe and had net daily average production sold for the month of May 2013 of 528 Boe/d, 72% of which was oil.

Onshore Gulf Coast

The following is a description of our properties in the onshore Gulf Coast as of May 31, 2013.

Villarreal Prospect. The Villarreal Prospect covers 1,099 gross (154 net) acres in Zapata County, Texas. We own an average working interest of 13.9% and an average net revenue interest of 10.5% in this acreage. We have 13 gross wells on the prospect producing from the Wilcox formation (1.8 net wells). 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 May 31, 2013, the Villarreal Prospect had estimated proved reserves of 295 MBoe and had net daily average production sold for the month of May 2013 of 192 Boe/d, all of which was natural gas.

Frost Bank Prospect. The Frost Bank Prospect covers 998 gross (521 net) acres in Duval County, Texas. We own an average working interest of 56.3% and an average net revenue interest of 42.2% in this acreage. There are five gross wells on the Frost Bank Prospect (2.8 net wells) producing from the Wilcox formation. RMR Operating is the operator of the Frost Bank Prospect. As of May 31, 2013, the Frost Bank Prospect had estimated proved reserves of 25 MBoe, of which 22 MBoe were proved developed non-producing, and had net daily average production sold for the month of May 2013 of 6 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. 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 May 31, 2013, the Peal Ranch Prospect had proved reserves of 65 MBoe, all of which were proved developed producing. The prospect had net daily average production sold for the month of May 2013 of 31 Boe/d, 95% 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 wells (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 81.5% working interest and a 61.1% 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 May 31, 2013, the Resendez and La Duquesa Prospect had estimated proved reserves of 12 MBoe and had net daily average production sold for the month of May 2013 of 15 Boe/d, all of which was natural gas.

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Southwest New Mexico

Cross Border owns 536,340 gross (268,170 net) mineral acres in Hidalgo, Grant, Sierra, and Socorro Counties, New Mexico. This mineral ownership carries no drilling commitments or leasehold obligations. As of May 31, 2013, this acreage had no proved reserves or production.

Kansas

As of May 31, 2013, we owned oil and natural gas interests in 5,215 gross and net acres in central Kansas. There are multiple target horizons in this prospect including the Arbuckle and the Lansing-Kansas City and Viola formations. We own a 100% working interest and an average net revenue interest of 80%. RMR Operating is the operator. As of May 31, 2013, the Kansas acreage had no proved reserves or production.

Title to Properties

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

Our properties are generally subject to royalty, overriding royalty and other interests customary in the industry, liens incident to agreements, current taxes and other burdens, minor encumbrances, easements and restrictions. We do not believe any of these burdens will materially interfere with our use of these properties. Substantially all of the properties of the Company, Black Rock, RMR Operating and Cross Border are pledged as collateral under the Credit Agreement with Independent Bank.

Summary of Oil and Natural Gas Reserves

Proved Reserves

The following table sets forth estimated proved reserves as of May 31, 2013.

	Reserves
Estimated proved reserve data (1)(2)	Oil (MBbls)		Natural Gas (MMcf)		Total (MBoe)
Proved developed producing reserves		867		4,998		1,700
Proved developed nonproducing reserves		149		322		203
Proved undeveloped reserves		1,304		2,041		1,644
Total proved reserves		2,320		7,361		3,547

(1) Prices used are based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the period June 2012 through May 2013. For oil volumes, the average NYMEX spot price is $90.87 per Bbl. For natural gas volumes, the average Henry Hub spot price is $3.31 per MMBtu. The oil price of $82.89 per barrel is adjusted for quality, transportation fees and a regional price differential and the natural gas price of $5.08 per MMBtu is adjusted for energy content, transportation fees and a regional price differential. The adjusted oil 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.

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Estimates of proved developed and undeveloped reserves are inherently imprecise and are continually subject to revision based on production history, results of additional exploration and development, price changes and other factors. See “—Qualifications of Technical Persons and Internal Controls Over Reserves Estimation Process.”

At May 31, 2013, our estimated proved reserves were 3.5 MMBoe, consisting of 65% oil, which is an increase of 70% compared to our proved reserves of 2.1 MMBoe at May 31, 2012. During fiscal 2013, we added estimated proved reserves through our acquisitions, including the acquisition of Cross Border. These additions were partially offset by production and by downward revisions in previous estimates.

Proved Undeveloped Reserves

Our estimated proved undeveloped reserves at May 31, 2013 were 1.6 MMBoe, consisting of 79% oil. During fiscal 2013, we added estimated proved undeveloped reserves through the acquisition of Cross Border, our exchange of Madera acreage with Chevron, and extensions and discoveries. We converted some 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 million. All of our currently identified proved undeveloped reserves are scheduled to be drilled by May 31, 2016.

Qualifications of Technical Persons and Internal Controls Over Reserves Estimation Process

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

The technical persons responsible for preparing the reserves estimates presented herein meet the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Natural Gas Reserves Information promulgated by the Society of Petroleum Engineers.

The principal person at CG&A who prepared the reserve report is Mr. Zane Meekins. Mr. Meekins has been a practicing consulting petroleum engineer at CG&A since 1989. Mr. Meekins is a Registered Professional Engineer in the State of Texas (License No. 71055) and has over 23 years of practical experience in petroleum engineering, with over 20 years of experience in the estimation and evaluation of reserves. He graduated from Texas A&M University in 1987 with a Bachelor of Science degree in Petroleum Engineering. Mr. Meekins meets or exceeds the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. He is proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserve definitions and guidelines.

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

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Estimates of oil and natural gas reserves are projections based on a process involving an independent third party engineering firm’s collection of all required geologic, geophysical, engineering and economic data, and such firm’s complete external preparation of all required estimates and are forward-looking in nature. These reports rely upon various assumptions, including assumptions required by the SEC, such as constant oil and natural gas prices, operating expenses and future capital costs. The process also requires assumptions relating to availability of funds and timing of capital expenditures for development of our proved undeveloped reserves. These reports should not be construed as the current market value of our reserves. The process of estimating oil and natural gas reserves is also dependent on geological, engineering and economic data for each reservoir. Because of the uncertainties inherent in the interpretation of this data, we cannot be certain that the reserves will ultimately be realized. Our actual results could differ materially. See “Note 17 – Supplemental Information Relating to Oil and Natural Gas Producing Activities (Unaudited)” to our audited consolidated financial statements for additional information regarding our oil and natural gas reserves.

Under SEC rules, proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil and/or natural gas actually recovered will equal or exceed the estimate. To achieve reasonable certainty, 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, 2011 and 2012 and the nine months ended February 29, 2012 and February 28, 2013. The results for the nine months ended February 28, 2013 only include results and estimated net production sold from Cross Border since February 1, 2013.

	Fiscal Year Ended,				Nine Months Ended,
	May 31, 2011		May 31, 2012		February 29, 2012		February 28, 2013
Net production sold
Oil (Bbl)		—		37,004		13,968		43,754
Natural gas (Mcf)		900,332		795,659		652,488		432,810
Total (Boe) (1)		150,055		169,614		122,716		115,889
Total (Boe/d) (2)		411		465		450		425
Average sales prices
Oil ($/Bbl)	$	—	$	93.97	$	95.11	$	79.23
Natural gas ($/Mcf)		4.12		3.58		3.57		3.13
Total average price ($/Boe)	$	24.74	$	37.29	$	30.80	$	42.43
Costs and expenses (per Boe)
Exploration expense	$	—	$	1.56	$	0.75	$	0.45
Production taxes		1.07		2.38		1.79		1.55
Lease operating expenses		1.10		5.56		5.83		8.33
Natural gas transportation and marketing expenses		1.57		1.00		1.15		0.66
Depreciation, depletion, amortization and impairment		4.78		30.36		9.86		27.55
Accretion of discount on asset retirement obligation		0.06		0.25		0.24		0.64
General and administrative expense		1.95		36.35		28.22		53.54

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(1) Includes immaterial amounts of natural gas liquids. The Madera Prospect had net production sold of 46,162 Boe and 0 Boe for the fiscal years ended May 31, 2012 and 2011, respectively. The Villarreal Prospect had net production sold of 115,816 Boe and 144,922 Boe for the fiscal years ended May 31, 2012 and 2011, respectively. The Madera Prospect had net production sold of 25,984 Boe and 69,291 Boe for the nine months ended February 29, 2012 and February 28, 2013, respectively.

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

Developed and Undeveloped Acreage

The following table presents our total gross and net developed and undeveloped acreage by region as of May 31, 2013:

	Developed Acres				Undeveloped Acres
	Gross (1)		Net (2)		Gross (1)		Net (2)
Permian Basin		11,108		5,237		325,743		25,774
Onshore Gulf Coast		4,776		1,405		—		—
Southwest New Mexico		—		—		536,340		268,170
Kansas		—		—		5,215		5,215
Total		15,884		6,642		867,298		299,159

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

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

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

	Undeveloped Leasehold Acres				% of Total Undeveloped Leasehold Acres
As of May 31,	Gross (1)		Net (2)		Net (2)
2014		320		190		0.7	%
2015		2,476		2,476		8.6	%
2016		4,484		4,364		15.1	%
2017		—		—		—
2018		—		—		—

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

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

Productive Wells

The following table presents the total gross and net productive wells by area and by oil or natural gas completion as of May 31, 2013. Cross Border owns royalty interests in 17 gross wells (average of 0.42%), which have been excluded from these well counts.

	Oil Wells				Natural Gas Wells
	Gross (1)		Net (2)		Gross (1)		Net (2)
Permian Basin		168		86.4		41		6.0
Onshore Gulf Coast		—		—		39		13.0
Total		168		86.4		80		19.0

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(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.

Drilling Activity

At May 31, 2013, we had one gross well (0.03 net) being drilled in the Red Lake area, and we had two gross wells (0.06 net) awaiting completion, also in the Red Lake area.

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 May 31,	Productive		Dry		Productive		Dry
2013		2.52		—		—		—
2012		1.01		—		4.26		—
2011		0.60		0.05		0.35		—

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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		35	President, Chief Executive Officer and Director
Michael R. Uffman		37	Chief Financial Officer
Hilda D. Kouvelis		50	Chief Accounting Officer and Executive Vice President
Tommy W. Folsom		59	Executive Vice President and Director of Exploration and Production of RMR Operating, LLC
David M. Heikkinen		41	Director
Paul N. Vassilakos		36	Director
Richard Y. Roberts		61	Director
Randell K. Ford		64	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 Capital, Inc., our wholly owned subsidiary (“Black Rock”), since its inception. Mr. Barksdale has also been the owner and president of The StoneStreet Group, Inc. (“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, an oil and gas exploration company, since May 2012. We believe that Mr. Barksdale’s experience in operating, managing, financing and investing in more than 100 wells in Louisiana, Mexico and Texas, combined with his over ten years of capital markets experience and contacts and relationships, provides our Board of Directors with management and operational direction.

In 2004, the National Association of Securities Dealers, Inc. (“NASD”) alleged that Mr. Barksdale solicited an attorney to make contributions to officials of an issuer with which Stephens Inc. was engaging in municipal securities business when Mr. Barksdale was employed as an investment banker of Stephens Inc. Without admitting or denying the allegations, Mr. Barksdale entered into an acceptance, waiver and consent decree that provided for a 30-day suspension from associating with any NASD member and a $5,000 fine.

Michael R. Uffman has served as our Chief Financial Officer since November 2012. His extensive investment banking background includes years of experience advising companies on equity and debt capital markets, investor relations, and assisting in the acquisition and divestiture of assets, all in the exploration and production space. Throughout his career, Mr. Uffman has assisted clients raise more than $5 billion in the energy space. From January 2012 until December 2012, Mr. Uffman served as a Managing Director of Global Hunter Securities, LLC, a full service, natural resource focused investment banking firm. From July 2010 to December 2011, Mr. Uffman served as Director of Oil and Gas Business Development for Louisiana Economic Development, which is responsible for strengthening Louisiana’s business environment and creating a more vibrant economy in the state. From May 2007 to June 2010, Mr. Uffman served as Director of Energy Investment Banking for Dahlman Rose & Company, a research-driven investment bank focused internationally on the commodity supply chain. From 2002 to 2007, Mr. Uffman served as Vice President of Energy Investment Banking at Capital One Southcoast, Inc., an energy investment banking boutique. From 2000 to 2002, Mr. Uffman served in External Audit at KPMG, LLP.

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

Tommy W. Folsom has been Executive Vice President and Director of Exploration and Production of RMR Operating, LLC, our wholly owned subsidiary (“RMR Operating”), since August 2012 and served as our Executive Vice President and Director of Exploration and Production from September 2011 to August 2012. Mr. Folsom is the founder of Enerstar Resources O & G, LLC (“Enerstar”), an oil company involved in the drilling, re-completion, re-entry and acquisition of properties and leases in the United States, and has served as its President since its formation in 1994. From 1996 to August 2011, Mr. Folsom served as the Operations Manager of Murchison Oil and Gas, Inc., a privately-held independent oil and gas company engaged in the acquisition, development and production of oil and gas resources in the United States.

David M. Heikkinenhas 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 investment bank headquartered in New Orleans, Louisiana that provides financial advisory services. From January 1994 to February 2000, Mr. Heikkinen held various engineering roles with Shell Offshore Inc. and Shell International Exploration and Production. We believe our Board of Directors benefits from Mr. Heikkinen’s extensive capital markets experience in the oil and gas industry.

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 Cullen Agricultural Holding Corp. (“CAH”) since October 2009. CAH is a development stage agricultural company which was formed in connection with the business combination between Triplecrown Acquisition Corp. and Cullen Agricultural Technologies, Inc. in October 2009. In July 2007, Mr. Vassilakos founded Petrina Advisors, Inc., a privately held advisory firm providing investment banking services, and has served as its president since its formation. Mr. Vassilakos also founded and, since December 2006, serves as the vice president of Petrina Properties Ltd., a privately held real estate holding company. From February 2002 through June 2007, Mr. Vassilakos served as vice president of Elmsford Furniture Corp., a privately held furniture retailer in the New York area. From July 2000 through January 2002, Mr. Vassilakos was an Associate within the Greek Coverage Group of Citigroup’s UK Investment Banking Division. From July 1998 through July 2000, Mr. Vassilakos was an Analyst within the Industrial Group of Salomon Smith Barney’s New York Investment Banking Division. Mr. Vassilakos has also served on the board of directors of Cross Border since May 2012. We believe that Mr. Vassilakos brings extensive public company and capital markets experience, as well as his professional contacts and experience, to our Board of Directors.

Richard Y. Roberts has been a director since October 2011. Since March 2006, Mr. Roberts has been a principal of Roberts, Raheb & Gradler LLC, a regulatory and legislative consulting firm that he co-founded. He was a partner with Thelen Reid & Priest LLP, a national law firm, from January 1997 to March 2006. From

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August 1995 to January 1997, Mr. Roberts was a consultant at Princeton Venture Research, Inc., a private consulting firm. From 1990 to 1995, Mr. Roberts was a commissioner of the SEC. Mr. Roberts is currently a director of CAH. He was a director of Nyfix, Inc. from September 2005 to December 2009, a director of Endeavor Acquisition Corp. from July 2005 to December 2007, a director of Victory Acquisition Corp. from January 2007 to April 2009 and a director of Triplecrown Acquisition Corp. from June 2007 to October 2009. We believe that Mr. Roberts’ experience at the SEC, and his experience as a director of other public companies, as well as his professional contacts and relationships, provides our Board of Directors with necessary insight into the requirements and needs of an emerging public company.

Randell K. Ford has been a director since November 2011. Mr. Ford has worked in the oil and gas industry for over 40 years. Since 1993, Mr. Ford has been the President of R. K. Ford and Associates, Inc., a consulting firm based in the Permian Basin in Midland, Texas that specializes in drilling, engineering and completion of oil and gas wells. Mr. Ford has also been a partner in Western Drilling Inc., an onshore drilling services company, since March 2010. While serving as President, Division Drilling Engineer, Principal and various other oilfield service positions, Mr. Ford has drilled, managed, consulted or invested in over 4,000 wells located domestically in 18 states and internationally in 12 countries. Mr. Ford has also served on the board of directors of Cross Border since May 2012. We believe our Board of Directors benefits from Mr. Ford’s operational expertise, stemming from his over 40 years of experience in the oil and gas industry.

Director Independence

The standards relied upon the Board in determining whether a director is “independent” are those set forth in the rules of the NYSE MKT LLC (formerly, NYSE Amex). The NYSE MKT LLC generally defines “independent directors” as a person other than an executive officer or employee of a company, who does not have a relationship with the company that would interfere with the director’s exercise of independent judgment in carrying out the responsibilities of a director. Consistent with these standards, our Board of Directors has determined that Messrs. Heikkinen, Roberts and Vassilakos are our independent directors.

Board Committees

We do not have separate standing audit, nomination or compensation committees as we are not required to have such committees at this time. Our three independent directors, Messrs. Heikkinen, Roberts and Vassilakos, perform the functions of our audit, nominating and compensation committees.

Audit Committee Functions

Our independent directors, performing the functions of our audit committee, do not have an audit committee charter. Our Board has not determined that we have an “audit committee financial expert,” as defined in SEC rules, serving on the Board as we are not required to do so at this time. However, the Board believes that our independent directors have sufficient knowledge in financial and auditing matters to perform the functions of our audit committee. The Board accordingly does not believe it is necessary at this time to recruit a new director in order to name an audit committee financial expert.

Nominating Committee Functions

In the absence of a designated nominating committee, each of our independent directors participates in the consideration of director nominees. In the Board’s view, a standing nominating committee is not necessary since, given the Board’s current size and composition, our independent directors are capable of performing the same functions as necessary.

We will consider candidates for Board membership suggested by the Board members, as well as management and shareholders. We consider, among many factors, leadership experience, financial and

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accounting expertise, industry expertise and strategic planning expertise in choosing Board members. We also examine the skills, diversity, backgrounds and experience of director nominees. In evaluating and determining whether to recommend a person as a candidate for election as a director, the Board considers the following specific qualifications: relevant management and/or industry experience; high personal and professional ethics; integrity and values; a commitment to representing the long-term interests of our shareholders; independence; and an ability and willingness to devote sufficient time to carrying out their duties and responsibilities as directors.

Compensation Committee Functions

In the absence of a designated compensation committee, each of our independent directors participates in the determination of executive and director compensation. In the Board’s view, a standing compensation committee is not necessary because our independent directors are willing and able to perform the same functions as necessary.

Our policies with respect to the compensation of our executive officers are administered by our Board in consultation with our independent directors. Our compensation policies are intended to provide for compensation that is sufficient to attract, motivate and retain executives of outstanding ability and potential and to establish an appropriate relationship between executive compensation and the creation of shareholder value.

It is anticipated that performance-based and equity-based compensation will be an important foundation in executive compensation packages as we believe it is important to maintain a strong link between executive incentives and the creation of shareholder value. We believe that performance and equity-based compensation can be an important component of the total executive compensation package for maximizing shareholder value while, at the same time, attracting, motivating and retaining high-quality executives.

Board and Committee Meetings

The Board met seven times during the fiscal year ended May 31, 2012 and acted by unanimous written consent on numerous additional occasions. The Board’s independent directors did not meet separately from the Board meetings that were held during the fiscal year ended May 31, 2012, but performed the necessary functions as audit, nominating and compensation committees during these meetings as necessary.

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.

Board Leadership Structure and Role in Risk Oversight

Mr. Barksdale serves both as our chief executive officer and chairman of the board. At this time, our Board believes that the Company is best served by having one person serve as both chief executive officer and the chairman because this structure provides unified leadership and direction. Given Mr. Barksdale’s extensive experience in operating, managing, financing and investing in oil and 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 the Board’s attention and prioritized as appropriate for the Company’s success. Our Board has not appointed a lead independent director.

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

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Code of Ethics

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

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PLAN OF DISTRIBUTION

We intend to sell the shares of common stock offered hereby on a “best efforts” basis directly to investors. No underwriters will be involved in the offering. In certain foreign jurisdictions, we may use a placement agent for the sale of shares of common stock, although we have not entered into any agreements with placement agents as of the date of this prospectus supplement.

If we enter into a placement agency agreement with a placement agent for the sale of shares of common stock, we will file a supplement to this prospectus supplement disclosing the terms and placement fees related to the placement agency agreement. Any placement agents that are engaged by us will not purchase or sell any shares of common stock under this prospectus supplement or accompanying prospectus and will not be required to arrange for the purchase or sale of any specific number or dollar amount of shares of common stock.

Notice to Investors

Laws in certain jurisdictions may restrict the distribution of this prospectus supplement and the accompanying prospectus and the offer and sale of the shares of common stock. Investors must inform themselves about, and observe, those restrictions. You must comply with all applicable laws and regulations in force in any applicable jurisdiction, and you must obtain any consent, approval or permission required for the purchase, offer or sale by you of the shares of common stock under the laws and regulations in force in the jurisdiction to which you are subject or in which you make such purchase, offer or sale, and we will not have any responsibility therefor.

Notice to Prospective Investors in the European Economic Area

In relation to each Member State of the European Economic Area, or EEA, which has implemented the Prospectus Directive (each, a “Relevant Member State”), with effect from, and including, the date on which the Prospectus Directive is implemented in that Relevant Member State (the “Relevant Implementation Date”), an offer to the public of the shares of common stock which are the subject of the offering contemplated by this prospectus supplement and the accompanying prospectus may not be made in that Relevant Member State, except that, with effect from, and including, the Relevant Implementation Date, an offer to the public in that Relevant Member State of the shares of common stock may be made at any time under the following exemptions under the Prospectus Directive, if they have been implemented in that Relevant Member State:

• to legal entities which are authorized or regulated to operate in the financial markets, or, if not so authorized or regulated, whose corporate purpose is solely to invest in the shares of common stock;

• to any legal entity which has two or more of: (i) an average of at least 250 employees during the last (or, in Sweden, the last two) financial year(s); (ii) a total balance sheet of more than €43,000,000 and (iii) an annual net turnover of more than €50,000,000, as shown in its last (or, in Sweden, the last two) annual or consolidated accounts;

• to fewer than 100 natural or legal persons or, if the Relevant Member State has implemented the relevant provision of the 2010 PD Amending Directive, 150 natural or legal persons (other than qualified investors as defined in the Prospectus Directive) subject to obtaining the prior consent of the representative for any such offer; or

• in any other circumstances falling within Article 3(2) of the Prospectus Directive provided that no such offer of the shares of common stock shall result in a requirement for the publication by us or any underwriter or agent of a prospectus pursuant to Article 3 of the Prospectus Directive.

As used above, the expression “offered to the public” in relation to the shares of common stock in any Relevant Member State means the communication in any form and by any means of sufficient information on the terms of the offer and the shares of common stock to be offered so as to enable an investor to decide to purchase

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or subscribe for the shares of common stock, as the same may be varied in that Member State by any measure implementing the Prospectus Directive in that Member State and the expression “Prospectus Directive” means Directive 2003/71/EC (and amendments thereto, including the 2010 PD Amending Directive, to the extent implemented in the Relevant Member State), and includes any relevant implementing measure in each Relevant Member State; and the expression “2010 PD Amending Directive” means Directive 2010/73/EU. The EEA selling restriction is in addition to any other selling restrictions set out in this prospectus supplement and the accompanying prospectus.

Notice to Prospective Investors in the United Kingdom

This prospectus supplement and the accompanying prospectus are only being distributed to and is only directed at: (i) persons who are outside the United Kingdom; (ii) investment professionals falling within Article 19(5) of the Financial Services and Markets Act 2000 (Financial Promotion) Order 2005 (the “Order”); or (iii) high net worth companies, and other persons to whom it may lawfully be communicated, falling within Article 49(2)(a) to (d) of the Order (all such persons falling within (i)-(iii) together being referred to as “relevant persons”). The shares of common stock are only available to, and any invitation, offer or agreement to subscribe, purchase or otherwise acquire such shares of common stock will be engaged in only with, relevant persons. Any person who is not a relevant person should not act or rely on this prospectus supplement and the accompanying prospectus or any of their contents.

Notice to Prospective Investors in Switzerland

The prospectus supplement and the accompanying prospectus do not constitute an issue prospectus pursuant to Article 652a or Article 1156 of the Swiss Code of Obligations (“CO”) and the shares of common stock will not be listed on the SIX Swiss Exchange. Therefore, the prospectus supplement and the accompanying prospectus may not comply with the disclosure standards of the CO and/or the listing rules (including any prospectus schemes) of the SIX Swiss Exchange.

Notice to Prospective Investors in Canada

The shares of common stock have not been and will not be qualified for sale in Canada or any province or territory of Canada pursuant to a prospectus and may not be offered or sold directly or indirectly in any province or Territory of Canada except pursuant to an exemption from the applicable prospectus filing requirements, and in compliance with the applicable securities rules of such province or territory.

Notice to Prospective Investors in Australia

No prospectus or other disclosure document (as defined in the Corporations Act 2001 (Cth) of Australia (“Corporations Act”) in relation to the shares of common stock has been or will be lodged with the Australian Securities & Investments Commission (“ASIC”). This document has not been lodged with ASIC and is only directed to certain categories of exempt persons. Accordingly, if you receive this document in Australia:

(a) You confirm and warrant that you are either:

(i) a “sophisticated investor” under section 708(8)(a) or (b) of the Corporations Act;

(ii) a “sophisticated investor” under section 708(8)(c) or (d) of the Corporations Act and that you have provided an accountant’s certificate to us which complies with the requirements of section 708(8)(c)(i) or (ii) of the Corporations Act and related regulations before the offer has been made;

(iii) a person associated with the company under section 708(12) of the Corporations Act; or

(iv) a “professional investor” within the meaning of section 708(11)(a) and (b) of the Corporations Act, and to the extent that you are unable to confirm or warrant that you are an exempt sophisticated

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investor, associated person or professional investor under the Corporations Act any offer made to you under this document is void and incapable of acceptance; and

(b) You warrant and agree that you will not offer any of the shares of common stock for resale in Australia within 12 months of the shares of common stock being issued unless any resale offer is exempt from the requirement to issue a disclosure document under section 708 of the Corporations Act.

Notice to Prospective Investors in New Zealand

The shares of common stock offered hereby have not been offered or sold, and will not be offered or sold, directly or indirectly in New Zealand and no offering materials or advertisements have been or will be distributed in relation to any offer of the shares of common stock in New Zealand, in each case other than:

• to persons whose principal business is the investment of money or who, in the course of and for the shares of common stock purposes of their business, habitually invest money; or

• to persons who in all the circumstances can properly be regarded as having been selected otherwise than as members of the public; or

• to persons who are each required to pay a minimum subscription price of at least NZ$500,000 for the shares of common stock before the allotment of the shares of common stock (disregarding any amounts payable, or paid, out of money lent by the Company or any associated person of the Company); or

• to persons who are eligible persons within the meaning of section 5(2CC) of the Securities Act 1978; or

• in other circumstances where there is no contravention of the Securities Act 1978 of New Zealand (or any statutory modification or re-enactment of, or statutory substitution for, the Securities Act 1978 of New Zealand).

Notice to Prospective Investors in the British Virgin Islands

No invitation will be made directly or indirectly to any person resident in the British Virgin Islands to subscribe for any of the shares of common stock but the shares may be acquired by British Virgin Islands persons who receive the offer outside of the British Virgin Islands and in a manner which does not contravene the laws of the jurisdictions in which such offer is received.

Notice to Prospective Investors in Jersey

The shares of common stock may not be offered to, sold to or purchased or held by, or for the account of, persons (other than financial institutions in the normal course of business) resident for income tax purposes in Jersey.

LEGAL MATTERS

Certain matters relating to Florida law regarding the validity of the common stock will be passed on by Carlton Fields, P.A.

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

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and includes an explanatory paragraph related to our 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. The consolidated financial statements of Cross Border as of December 31, 2012 and 2011 and for the years then ended have been incorporated herein by reference to our Current Report on Form 8-K/A filed with the SEC on April 12, 2013, 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 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 estimates are set forth 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, 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 August 20, 2013 and filed on August 20, 2013;

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

• Current Report on Form 8-K dated July 26, 2013 and filed on July 31, 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 17, 2013 and filed on July 23, 2013;

• Quarterly Report on Form 10-Q for the fiscal quarter ended February 28, 2013, filed on April 22, 2013;

• Current Report on Form 8-K dated May 2, 2013, and filed on May 6, 2013;

• Current Report on Form 8-K dated April 11, 2013, and filed on April 12, 2013;

• Current Report on Form 8-K dated February 28, 2013, and filed on March 6, 2013;

• Current Report on Form 8-K dated February 5, 2013, and filed on February 11, 2013;

• Current Report on Form 8-K dated January 28, 2013, and filed on February 1, 2013, as amended by Amendment No. 1 on Form 8-K/A filed on April 12, 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 on 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;

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• 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 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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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 natural gas liquids to one Bbl of oil.

“Boe/d” Boe per day.

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

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

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

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

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

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

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

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

• provide improved recovery systems.

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

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

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

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

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

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

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

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

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

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

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

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

“MBoe” One thousand barrels of oil equivalent.

“Mcf” One thousand cubic feet of natural gas.

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

“MMBoe” One million barrels of oil equivalent.

“MMBtu” One million British thermal units.

“MMcf” One million cubic feet of natural gas.

“natural gas” Natural gas and natural gas liquids.

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

“NYMEX” The New York Mercantile Exchange.

“oil” Oil and condensate.

“overriding royalty interest” An interest in an oil and/or natural gas property entitling the owner to a share of oil and natural gas production free of costs of production.

“PDP” Proved developed producing reserves.

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“PDNP” Proved developed non-producing reserves.

“play” A term applied to a portion of the exploration and production cycle following the identification by geologists and geophysicists of areas with potential natural gas and oil reserves.

“plugging and abandonment” Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another or to the surface. Regulations of many states require plugging of abandoned wells.

“producing well” A well found to be capable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well.

“production costs” Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. They become part of the cost of oil and natural gas produced. Examples of production costs (sometimes called lifting costs) are:

• costs of labor to operate the wells and related equipment and facilities;

• repairs and maintenance;

• materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities;

• property taxes and insurance applicable to proved properties and wells and related equipment and facilities; and

• severance taxes.

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

“proved developed reserves” Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

“proved properties” Properties with proved reserves.

“proved reserves” Those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. The area of the reservoir considered as proved includes (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or natural gas on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons, or LKH, as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty. Where direct observation from well penetrations has defined a highest known oil, or HKO, elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty. Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included

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in the proved classification when (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based, and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

“proved undeveloped reserves” Reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required.

“PUD” Proved undeveloped reserves.

“PV-10” When used with respect to oil and natural gas reserves, PV-10 means the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development and abandonment costs, using prices and costs in effect at the determination date, before income taxes, and without giving effect to non-property-related expenses, discounted to a present value using an annual discount rate of 10% in accordance with the guidelines of the SEC.

“reasonable certainty” If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery, or EUR, with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.

“recompletion” The process of re-entering an existing wellbore that is either producing or not producing and completing new reservoirs in an attempt to establish or increase existing production.

“reserves” Estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible as of a given date by application of development prospects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and natural gas or related substances to market, and all permits and financing required to implement the project.

“reservoir” A porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers and is separate from other reservoirs.

“sand” A geological term for a formation beneath the surface of the Earth from which hydrocarbons are produced. Its make-up is sufficiently homogenous to differentiate it from other formations.

“shale” Fine-grained sedimentary rock composed mostly of consolidated clay or mud. Shale is the most frequently occurring sedimentary rock.

“spacing” The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres, e.g., 40-acre spacing, and is often established by regulatory agencies.

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“standardized measure” The present value of estimated future cash inflows from proved oil and natural gas reserves, less future development, abandonment, production and income tax expenses, discounted at 10% per annum to reflect the timing of future cash flows and using the same pricing assumptions as were used to calculate PV-10. Standardized measure differs from PV-10 because standardized measure includes the effect of future income taxes.

“stratigraphic test well” A drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intention of being completed for hydrocarbon production.

“undeveloped acreage” Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.

“vertical well” An oil or natural gas wellbore that is drilled from the surface to the depth of interest without directional deviation.

“wellbore” The hole drilled by the bit that is equipped for oil or natural gas production on a completed well. Also called well or borehole.

“working interest” The right granted to the lessee of a property to explore for and to produce and own oil, natural gas, or other minerals. The working interest owners bear the exploitation, development, and operating costs on either a cash, penalty, or carried basis.

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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.

11,500,000 Shares

Common Stock

Prospectus Supplement

August 22, 2013