American Standard Energy 10K 2012 Annual report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

Form 10-K

x	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2012

o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from ____________ to ______________

Commission File Number: 000-54471

AMERICAN STANDARD ENERGY CORP.

(Exact name of registrant as specified in its charter)

Delaware				20-2791397
(State or other Jurisdiction of Incorporation)				(IRS Employer Identification No.)

4800 North Scottsdale Road, Suite 1400

Scottsdale, AZ 85251

(Address of principal executive offices)

Tel. No.: (480) 371-1929

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act: None

Securities registered pursuant to Section 12(g) of the Act:Common Stock, par value $0.001 per share

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes¨ Nox

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act. Yes¨ Nox

Note — Checking the box above will not relieve any registrant required to file reports pursuant to Section 13 or 15(d) of the Exchange Act from their obligations under those Sections.

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yeso Nox

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12-months (or for such shorter period that the registrant was required to submit and post such files). Yeso Nox

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filero		Accelerated filero
Non-Accelerated filero		Smaller reporting companyx

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act)

Yeso Nox

The number of shares of common stock held by non-affiliates as of June 29, 2012 was 16,071,070 shares, all of one class of common stock, $0.001 par value per share, having an aggregate market value of approximately $25,392,291 based upon the closing price of registrant’s common stock on such date of $1.58 per share as quoted on the Over the Counter Bulletin Board. For purposes of the foregoing calculation, all directors, executive officers, and 5% beneficial owners have been deemed affiliated with the registrant.

As of August 12, 2013, there were 51,617,371 shares of common stock, $0.001 par value, outstanding.

TABLE OF CONTENTS

PART I		1

Item 1.BUSINESS		1

Item 1A. RISK FACTORS		12

Item 1B. UNRESOLVED STAFF COMMENTS.		45

Item 2. PROPERTIES		45

Item 3. LEGAL PROCEEDINGS		53

Item 4. MINE SAFETY DISCLOSURES		53

PART II		53

Item 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES		53

Item 6. SELECTED FINANCIAL DATA		55

Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		56

Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		82

Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA		83

Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE		83

Item 9A. CONTROLS AND PROCEDURES		83

Item 9B. OTHER INFORMATION		84

PART III		84

Item 10. DIRECTORS, EXECUTIVE OFFICES AND CORPORATE GOVERNANCE		84

Item 11. EXECUTIVE COMPENSATION		91

Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT		102

Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE		104

Item 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES		107

PART IV		108

Item 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES		108

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This Annual Report on Form 10-K contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended, that involve risks and uncertainties, principally in the sections entitled “Description of Business,” “Risk Factors,” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” Forward-looking statements provide current expectations of future events based on certain assumptions. All statements other than statements of historical fact contained in this Annual Report on Form 10-K, including statements regarding future events, our future financial performance, business strategy and plans and objectives of management for future operations, are forward-looking statements. We have attempted to identify forward-looking statements by terminology including “anticipates,” “believes,” “can,” “continue,” “could,” “estimates,” “expects,” “intends,” “may,” “plans,” “potential,” “predicts,” “should,” or “will” or the negative of these terms or other comparable terminology. Although we do not make forward-looking statements unless we believe we have a reasonable basis for doing so, we cannot guarantee their accuracy. These statements are only predictions and involve known and unknown risks, uncertainties and other factors, including the risks outlined under “Risk Factors” or elsewhere in this Annual Report on Form 10-K, which may cause our or our industry’s actual results, levels of activity, performance or achievements to differ materially from those expressed or implied by these forward-looking statements. Moreover, we operate in a very competitive and rapidly changing environment. New risks emerge from time to time and it is not possible for us to predict all risk factors, nor can we address the impact of all factors on our business or the extent to which any factor, or combination of factors, may cause our actual results to differ materially from those contained in any forward-looking statements. All forward-looking statements included in this Annual Report on Form 10-K are based upon information available to us on the date hereof, and we assume no obligation to update any such forward-looking statements.

You should not place undue reliance on any forward-looking statement, each of which applies only as of the date of this Annual Report on Form 10-K. Except as required by law, we undertake no obligation to update or revise publicly any of the forward-looking statements after the date of this Annual Report on Form 10-K to conform our statements to actual results or changed expectations.

PART I

Unless specifically set forth to the contrary, when used in this report the terms “ASEC”, “we”“, “our”, the “Company” and similar terms refer to American Standard Energy Corp., a Delaware corporation, and its wholly owned subsidiaries American Standard Energy Corp., a Nevada corporation, and ASEN 2, Corp., a Delaware corporation.

Item 1. BUSINESS

We are an independent oil and natural gas production company engaged in the acquisition and development of leaseholds of oil and natural gas properties. Our leasehold acreage is located in the Permian Basin of West Texas and Eastern New Mexico, referred to herein as the Permian Basin, the Eagle Ford Shale Formation of South Texas, referred to herein as Eagle Ford, the Bakken Shale Formation in North Dakota, referred to herein as Bakken, the Niobrara Shale Formation of Wyoming and Nebraska, herein referred to as the Niobrara, the Eagle Bine Shale Formation in South East Texas, herein referred to as the Eagle Bine, and the Gulf Coast of South Texas, herein referred to as the Gulf Coast.

In the Permian Basin, the Niobrara, the Eagle Bine and parts of the Eagle Ford, we own a number of leases where we hold the majority working interest. We have historically contracted and expect to continue to contract with third-party operators, consultants, and other contractor service providers to operate and drill our majority leasehold acreage. Within this acreage, we have historically contracted to drill conventional, vertical wells. We may consider contracting with third parties to selectively drill unconventional, horizontal wells in areas that may be prospective for oil and natural gas bearing shale formations.

We also hold minority interest leasehold acreage in the Bakken and parts of the Permian Basin. In the minority working interest leaseholds, we have historically participated and expect to continue to participate on a non-operated basis in the drilling and production of acreage operated by independent oil and gas operating companies.

While we rely on the expertise and resources of the respective operators that are drilling our minority working interest acreage, we believe that our overall diversification across a large number of small working interests provides a way to participate in two large shale formations that are being actively developed with less risk than a concentrated acreage position.

By participating in drilling activities with larger operators, we seek to leverage their resources and expertise to efficiently gain exposure to potential new oil and gas production and proven reserves. In the Permian Basin, some of these operators have historically drilled and operated traditional, vertical wells. In the Eagle Ford and Bakken, we have participated in wells where the operators have historically drilled unconventional, horizontal wells into prospective oil and natural gas bearing shale formations.

As of December 31, 2012, we held working interests in approximately 96,300 net acres in the Permian Basin, Bakken, Eagle Ford, Niobrara and Gulf Coast regions. These working interests grant us the right as the lessee of the property to explore, develop and produce oil, natural gas and other minerals, while bearing our portion of related exploration, development and operating costs.

Corporate History

We were incorporated as National Franchise Directors, Inc. under the laws of the state of Delaware on March 4, 2005. On October 25, 2005, we changed our name to Famous Uncle Al’s Hot Dogs & Grille, Inc. for the purpose of obtaining all existing and future restaurant franchising rights from Famous Uncle Al’s Hot Dogs, Inc. On October 28, 2010, we changed our name to American Standard Energy Corp. to reflect our new operations.

American Standard Energy Corp., a Nevada corporation, referred to herein as Nevada ASEC, was incorporated on April 2, 2010 for the purposes of acquiring certain oil and natural gas leaseholds from Geronimo Holding Corporation referred to herein as Geronimo, XOG Operating, LLC referred to herein as XOG, and CLW South Texas 2008, LP referred to herein as CLW (Geronimo, XOG and CLW, collectively referred to herein as the XOG Group) and making capital investments in, and acquiring working interests of, existing or planned hydrocarbon production with a special focus on productive oil and natural gas prospects. On October 1, 2010, we entered into a Share Exchange Agreement by and among our then-controlling stockholder, Nevada ASEC (then a privately-held oil exploration and production company) and the former stockholders of Nevada ASEC. Pursuant to the Share Exchange Agreement, we (i) sold our former restaurant franchise rights and related operations to the former controlling stockholder in exchange for the cancellation of 25,000,000 shares of our common stock and (ii) acquired 100% of the outstanding shares of common stock of Nevada ASEC from the former Nevada ASEC stockholders and received $25,000 of additional consideration. In exchange, the Nevada ASEC stockholders received approximately 22,000,000 shares of our common stock on the closing date of the Share Exchange Agreement. As a result, the former stockholders of Nevada ASEC acquired control of the Company and the transaction was accounted for as a recapitalization with Nevada ASEC as the accounting acquirer of the Company. Accordingly, the financial statements of Nevada ASEC became the historical financial statements of the Company. As a result of the transactions consummated pursuant to the Share Exchange Agreement, Nevada ASEC became our wholly-owned subsidiary.

On May 1, 2010, the XOG Group contributed certain oil and gas properties to Nevada ASEC in return for 80% of the common stock of Nevada ASEC. XOG continued to serve as operator of such properties. The May 2010 acquisition of the oil and natural gas properties from the XOG Group was a transaction under common control and, accordingly, Nevada ASEC recognized the assets and liabilities acquired from the XOG Group at their historical carrying values and no goodwill or other intangible assets were recognized. The oil and gas properties contributed by the XOG Group to Nevada ASEC consisted of seven completed and operating wells within the Permian Basin region of West Texas as well as approximately 10,600 acres of undeveloped leasehold rights in three primary regions: (i) the Bakken, (ii) the Eagle Ford and (iii) certain positions in the Permian Basin leased from the University of Texas.

On December 1, 2010, we entered into an agreement with Geronimo whereby we acquired certain leasehold interests in oil and natural gas properties located in North Dakota consisting of 26 wells located in Burke, Divide, Dunn, McKenzie, Mountrail, and Williams Counties referred to herein as the Bakken 1 Properties for $500,000 cash and 1,200,000 shares of the Company’s common stock valued at $3.96 million. The acquisition was accounted for as a transaction under common control and accordingly, we recorded the Bakken 1 Properties at their historical carrying values and no goodwill or other intangible assets were recognized. As a result, the historical assets, liabilities and operations of the Bakken 1 Properties are included retrospectively in our consolidated financial statements for all periods presented.

On February 11, 2011, we acquired certain developed oil and natural gas properties on approximately 2,374 net acres located in Texas, Oklahoma and Arkansas, of which approximately 2,200 net acres are located within the Permian Basin and on which 24 wells are located referred to herein as the Group 1 & 2 Properties, from Geronimo for $7,000,000 cash. The acquisition was accounted for as a transaction under common control and accordingly, we recorded the assets and liabilities acquired from Geronimo at their historical carrying values. As a result, the historical assets, liabilities and operations of the Group 1 & 2 Properties are included retrospectively in our consolidated financial statements for all periods presented.

On March 1, 2011, we acquired certain undeveloped mineral rights leaseholds held on approximately 10,147 net acres in the Bakken Shale Formation in North Dakota referred to herein as the Bakken 2 Properties from Geronimo in exchange for $3,000,000 cash and the issuance of 883,607 shares of the Company’s common stock valued at $5,787,626. Certain of these mineral rights with a historical cost basis of $1,257,000 were acquired by Geronimo subsequent to December 31, 2010, and, as a result, were not under common control at that date and have been excluded from the historical consolidated financial statements as of December 31, 2010. These subsequently-acquired undeveloped mineral rights were first reflected in our March 31, 2011 interim consolidated financial statements, and are incorporated into our financial statements for the year ended December 31, 2011.

On April 8, 2011, we acquired undeveloped leasehold acreage consisting of approximately 2,780 net acres located in Mountrail County of North Dakota’s Williston Basin referred to herein as the Bakken 3 Properties from Geronimo for $1.86 million, which includes a $1.0 million down payment made on March 25, 2011. This acquisition was accounted for as a transaction under common control.

On August 22, 2011, we acquired approximately 13,324 net undeveloped leasehold acres in the Bakken/Three Forks referred to herein as the Bakken 4 Properties area from Geronimo for approximately $14.6 million. A cash deposit of $13.5 million was made on April 15, 2011, and the Company subsequently issued 208,200 shares of common stock upon closing, which were valued at an aggregate of $1,093,050 based on a per share price of $5.25 on the closing date. The acquisition was recorded at fair value.

On March 5, 2012, we acquired leasehold working interests in approximately 61,500 net acres across the Permian Basin, Eagle Ford shale formation and the Eagle Bine in Texas, the Williston Basin in North Dakota, and the Niobrara shale formation in Wyoming and Nebraska referred to herein as the XOG Properties, from the XOG Group in exchange for the delivery by the Company to the XOG Group of $10 million in cash, less the $1.5 million cash deposit previously paid by the Company, a note in the principal amount of $35 million made by the Company in favor of Geronimo and 5,000,000 shares of the common stock of the Company valued at $2.70 per share, based on the closing price of the common stock on March 5, 2012. The promissory note with a principal amount of $35 million issued to Geronimo was converted into 35,400 shares of Series A Cumulative Convertible Preferred Stock, par value $0.001 per share (“Series A Preferred Stock”) on June 30, 2012. Randall Capps, a member of the Company’s board of directors, and the father–in-law of our Chief Executive Officer, Scott Feldhacker, is the sole owner of XOG and Geronimo and the majority owner of CLW.

In connection with the Second Amendment as described in Note E to the consolidated financial statements, Long Term Debt, ASEN 2 and Antler Bar entered into an Asset Purchase Agreement dated September 11, 2012. Pursuant to the Asset Purchase Agreement, ASEN 2 sold its interests in approximately 1,200 leasehold acres of the Auld Shipman project in La Salle and Frio counties, Texas (the “Auld Shipman Property”) to Antler Bar in exchange for the forgiveness of the Transferred Indebtedness and for the assumption by Antler Bar of all liabilities related to the Auld Shipman Property. The transactions under the Second Amendment and Asset Purchase Agreement closed on September 13, 2012.

On September 21, 2012, the Company entered into a purchase and sale agreement with U.S. Energy Corp. (“U.S. Energy”) to divest interests in producing Bakken and Three Forks formation wells and approximately 400 net acres in McKenzie, Williams and Mountrail Counties, North Dakota. The effective date of the transaction was July 1, 2012. Under the purchase and sale agreement, U.S. Energy acquired working interests in 23 drilling units for $2.5 million with an estimated 307,000 BOE in proved reserves. As of September 21, 2012, there were 27 gross producing wells in the acreage. Of these wells, 25 were producing from the Bakken formation and 2 were producing from the Three Forks formation. All acreage was held by production at the time of sale and produced approximately 47 barrels of oil equivalent per day as of the effective date of the sale.

On November 16, 2012, American Standard Energy, Corp. (“Nevada ASEC”), a Nevada corporation and a wholly owned subsidiary of American Standard Energy Corp., a Delaware corporation (the “Company”) entered into a purchase and sale agreement (the “Agreement”) with Texian Oil - I, LP, a Texas limited partnership (the “Purchaser”) pursuant to which Nevada ASEC sold certain leasehold properties and related interests in approximately 503.11 net acres located in Gaines, Glasscock, Andrews, Crane, Yoakum and Scurry Counties, Texas, Lea County, New Mexico and Grady County, Oklahoma in exchange for the delivery by the Purchaser to Nevada ASEC of $5.3 million in cash (the “Purchase Price”), subject to certain post-closing adjustments. Nevada ASEC satisfied all post-closing requirements. Accordingly no escrow account was required and Nevada ASEC received the full Purchase Price upon closing. The transaction closed on November 21, 2012, with an effective date of October 1, 2012.

Effective February 18, 2013, Saber Oil, LLC purchased the 35,400 shares of the Series A Preferred Stock from Geronimo. J. Steven Person and H.H. Wommack, III, each a director of the Company, are principals in Saber Oil, LLC. In connection with the purchase of the Series A Preferred Stock, each of Randall Capps, Geronimo, XOG and CLW granted an irrevocable proxy to Saber Oil, LLC to vote all of the shares of common stock of the Company beneficially owned by Mr. Capps and the XOG Group. The irrevocable proxies granted to Saber Oil, LLC have voting rights, in the aggregate, of 55.55% of the Company’s issued and outstanding common stock (based upon 51,721,798 shares of common stock outstanding, as set forth in the Form 10-Q filed with the Securities and Exchange Commission on November 15, 2012).

Business Overview

Our wholly-owned subsidiary, Nevada ASEC, was formed for the original purpose of acquiring the oil and natural gas properties from the XOG Group and making capital investments in, and acquiring of working interests of existing or exploratory hydrocarbon production with a special focus on productive oil and natural gas prospects. We anticipate that our continuing focus will be on acquiring and developing additional assets within the Permian Basin, Bakken, Eagle Ford, Niobrara, Eagle Bine and Gulf Coast regions described below. Notwithstanding this focus, we also expect to pursue the acquisition of property and assets within other geographic areas that meet our general investment guidelines and targets.

As of December 31, 2012, we held working interests in approximately 96,300 net acres in the Permian Basin, Bakken, Eagle Ford, Niobrara and Gulf Coast regions. A summary of the total gross and net oil and natural gas productive wells and the total gross and net developed acreage by geographic area is set forth in the section “Oil and Natural Gas Properties Wells, Operation and Acreage” beginning on page 51 herein. Our working interests in these regions grant us the right, as the lessee of the property, to explore for, develop and produce oil, natural gas and other minerals, while also bearing any related exploration, development, and operating costs.

As of August 1, 2013:

Permian Basin.We have leased a portfolio of both producing and undeveloped properties in the Permian Basin of West Texas, consisting of approximately 26,500 net acres, one of which includes 208 gross (181.5 net) producing wells as well as approximately 9,800 undeveloped acres with leases expiring in 1-5 years. We have a contractual relationship with XOG Operating and Cambrian Management, referred to herein as Cambrian, both seasoned exploration and production operators based in Midland, Texas. XOG has been operating, developing and exploiting the Permian Basin, as well as operating in 14 other states, for 30 years. Cambrian has acted as a third party completion consulting firm and contract operator for certain types of vertical wells in the Permian Basin since 2001.

The XOG relationship has provided acquisition opportunities for us beginning in 2010 and is expected to provide us with additional opportunities for land acquisition and joint ventures with various operators; however, XOG is not obligated to provide any opportunities to us and there can be no assurance that any opportunity will be available to us in the future. Randall Capps is the sole owner of XOG, a member of our board of directors and the father-in-law of our Chief Executive Officer, Scott Feldhacker.

Bakken Shale. We hold primarily minority working interests in the Bakken Shale covering approximately 40,200 net acres located in nine counties in North Dakota. We have participated in 133 gross (2.3 net) wells in the Williston Basin, prospecting either the Bakken Shale or Three Forks Shale formations through December 31, 2012. The Company has elected to participate in a wide range of wells by county and operator in the Williston Basin. Our objective is to participate in some of the overall potential growth in production and proved reserves of the Williston Basin as the majority working interest operators in which we hold minority working interests, conduct exploratory and in-fill drilling activities. We have historically participated, and anticipate continuing to participate, in these drilling activities through minority working interest participations.

Niobrara. We currently hold majority working interests in approximately 16,300 net acres located in the Niobrara Shale in Nebraska and Wyoming. All of this acreage is undeveloped and unproven as of December 31, 2012. We do not currently anticipate the near-term development of this acreage. There are two years remaining on our lease, with an option to extend the lease for five additional years. In the event we drill one or more wells and commence commercial production, we would continue to hold the lease for the duration of production. We will continue to participate in the evaluation of the drilling and exploration activities in close proximity to our acreage for future potential development.

Additional Acreage: We also hold additional acreage in Arkansas, and on the Gulf Coast of Texas with a total of approximately 5,300 net acres. The acreage includes 15 gross (4.5 net) gas wells in Arkansas, and 36 gross (27.20 net) producing wells on the Gulf Coast of Texas. The Gulf Coast assets are majority working interest leases. We participate in the Arkansas and Oklahoma wells on a non-operated, minority working interest basis.

Operations

We have structured our operations and staffing model in such a way that we believe limits significant fixed operating expenses. We maintain a limited in-house employee base outside of the executive team and some administrative personnel. We attempt to limit fixed overhead and staff, as the majority of operational duties have been outsourced to select consultants and independent contractors, including contract operators for our producing wells, consultants to oversee drilling, completion and initial production for leases where we control majority working interests and elect to drill a well, as well as contract geologists and contract reserve engineers. We currently have two employees other than our two executive officers.

For each producing well, we have historically entered into a contract operating agreement with an operator who is responsible for the management and day-to-day operation of one or more of our crude oil and/or natural gas wells. In instances where we are a minority working interest partner, the operator is generally a significant or majority working-interest owner in the well. We believe that the use of experienced operators should allow us to streamline production and development activities, reducing fixed overhead and non-leasehold capital investments.

Drilling Projects

For our majority working interest acreage in the Permian Basin, we expect to continue our relationship with XOG, Cambrian, among other contract operators for drilling and operating services through contract operating agreements. The company plans to begin a transition where it will become the operator of certain assets in the Permian. We are actively contracting for third party completion services on wells drilled in 2012 by third party drilling service providers on our acreage. We expect that we will resume the drilling of our majority interest acreage in the Permian Basin in 2013.

In the Bakken, we expect to continue to participate in third party drilling activities on a non-operated basis. We have over 1,000 leases in this region, with a wide range of minority working interests across multiple counties, with multiple operators in various stages of permitting, planned drilling, and active development. In the Bakken, we are uncertain at this time as to the future development plans of the majority working interest operators on this acreage. However, we do actively monitor the drilling of third party operators in proximity to our acreage, as well as the permitted status of the leaseholds.

Divestitures

On September 11, 2012, ASEN 2, Corp., a Delaware corporation and wholly owned subsidiary of the Company (“ASEN 2”), and Antler Bar, an affiliate of Pentwater Equity Opportunities Master Fund Ltd. and PWCM Master Fund Ltd. (collectively, “Pentwater”) who is the holder of a $25 million secured convertible promissory note issued by ASEN 2, entered into an Asset Purchase Agreement (the “Asset Purchase Agreement”). Pursuant to the Asset Purchase Agreement, ASEN 2 sold its interests in approximately 1,200 leasehold acres of the Auld Shipman project in La Salle and Frio counties, Texas (the “Auld Shipman Property”) to Antler Bar in exchange for the forgiveness of indebtedness of $2,750,000 and for the assumption by Antler Bar of all liabilities related to the Auld Shipman Property of $5,982,772.

On September 21, 2012, the Company entered into a purchase and sale agreement with U.S. Energy Corp. to divest working interests in producing Bakken and Three Forks formation wells and approximately 400 net acres in McKenzie, Williams and Mountrail Counties, North Dakota. The effective date of the transaction was July 1, 2012.

On November 16, 2012, the Company entered into a purchase and sale agreement with Texian Oil to divest certain leasehold properties and related interests in approximately 503 net acres located in Gaines, Glasscock, Andrews, Crane, Yoakum and Scurry Counties, Texas, Lea County, New Mexico and Grady County, Oklahoma. The transaction closed on November 21, 2012, with an effective date of October 1, 2012.

Marketing and Customers

As a non-operator, we rely on outside operators for the transportation, marketing/sales and account reporting for all production. The operators of our wells are responsible for the marketing and sales of all production to regional purchasers of petroleum products.

Governmental Regulation and Environmental Matters

The Company’s operations are subject to various rules, regulations and limitations impacting the oil and natural gas exploration and production industry as a whole.

Regulation of Crude Oil and Natural Gas Production

Our crude oil and natural gas exploration, production and related operations, when developed, are subject to extensive rules and regulations promulgated by federal, state, tribal and local authorities and agencies. For example, North Dakota, Montana and other states require permits for drilling operations, drilling and abandonment bonds, and reports concerning operations, and they may impose other requirements relating to the exploration and production of crude oil and natural gas. Such states may also have statutes or regulations addressing resource conservation matters, including provisions for the unitization or pooling of crude oil and natural gas properties, the establishment of maximum rates of production from wells, and the regulation of spacing, plugging and abandonment of such wells.

While our operating partners are expected to be in compliance with the extensive rules and regulations promulgated by federal, state, tribal and local authorities and agencies with regard to exploration and production including acquiring proper permits for drilling operations, drilling bonds and reports concerning operations, the Company strives to comply with all regulatory burdens it shares as a function of its interest in oil and natural gas leaseholds and the potential pooling of oil and natural gas properties. Failure to comply with any such rules and regulations can result in substantial penalties. The regulatory burden on the oil and natural gas industry may increase the Company’s cost of doing business and may affect the Company’s profitability. Although the Company believes it is currently in substantial compliance with applicable laws and regulations, because such rules and regulations are frequently amended or reinterpreted, the Company is unable to predict the future cost or impact of complying with such laws. Significant expenditures may be required to comply with governmental laws and regulations and may have a material adverse effect on the Company’s financial condition and results of operations.

Environmental Matters

Our and our operators’ operations and properties are subject to extensive and changing federal, state, tribal and local laws and regulations relating to environmental protection, including the generation, storage, handling, emission, transportation and discharge of materials into the environment, and relating to safety and health. The recent trend in environmental legislation and regulation generally is toward stricter standards, and this trend will likely continue. These laws and regulations may:

require the acquisition of a permit or other authorization before construction or drilling commences and for certain other activities;

limit or prohibit construction, drilling and other activities on certain lands lying within wilderness and other protected areas; and

impose substantial liabilities for pollution resulting from such operations.

The permits required for our operations may be subject to revocation, modification and renewal by issuing authorities. Governmental authorities have the power to enforce their regulations, and violations are subject to fines or injunctions, or both. In the opinion of management, we are in substantial compliance with current applicable environmental laws and regulations, and we have no material commitments for capital expenditures to comply with existing environmental requirements. Nevertheless, changes in existing environmental laws and regulations or in interpretations thereof could have a significant impact on our Company, as well as the crude oil and natural gas industry in general.

The Comprehensive Environmental, Response, Compensation, and Liability Act, as amended, referred to hereafter as CERCLA, and comparable state statutes can impose strict, no-fault, retroactive, joint and several liability on owners and operators of certain sites and on persons who disposed of or arranged for the disposal of “hazardous substances” found at such sites. It is also not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances released into the environment. In addition, the Resource Conservation and Recovery Act, as amended, referred to hereafter as RCRA, and comparable state statutes govern the disposal of “solid waste” and “hazardous waste” and authorize response orders and the imposition of substantial fines and penalties for noncompliance. Although CERCLA currently excludes petroleum from its definition of “hazardous substance,” other substances present in our operations are subject to CERCLA, and state laws affecting our operations may impose clean-up liability relating to petroleum and petroleum-related products. In addition, although RCRA classifies certain crude oil field wastes as “non-hazardous,” such exploration and production wastes could be reclassified as hazardous wastes thereby making such wastes subject to more stringent handling and disposal requirements.

The Oil Pollution Act of 1990, as amended, referred to hereafter as OPA, and regulations issued under OPA impose strict, joint and several liability on “responsible parties” 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” includes the owner or operator of an onshore facility and the lessee or permittee of the area in which an offshore facility is located. OPA established a liability limit for onshore facilities of $350.0 million, while the per-event liability limit for offshore facilities is the payment of all removal costs plus up to $75.0 million in other damages. However, these limits may change and may not apply if a spill is caused by a party’s gross negligence or willful misconduct; the spill resulted from violation of a federal safety, construction or operating regulation; or if a party fails to report a spill or to cooperate fully in a cleanup. We are not aware of any action or event that would subject us to liability under OPA, and we believe that compliance with OPA’s requirements will not have a material adverse effect on us.

The Endangered Species Act, as amended, referred to hereafter as ESA, seeks to ensure that activities do not jeopardize endangered or threatened animal, fish and plant species, nor destroy or modify the critical habitat of such species. Under ESA, exploration and production operations, as well as actions by federal agencies, may not significantly impair or jeopardize a protected species or its habitat. ESA provides for criminal penalties for willful violations. Other statutes that provide protection to animal and plant species and that may apply to our operations include, but are not necessarily limited to, the Fish and Wildlife Coordination Act, the Fishery Conservation and Management Act, the Migratory Bird Treaty Act and the National Historic Preservation Act. Although we believe that our operations are in substantial compliance with such statutes, any change in these statutes, any reclassification of a species as endangered or expansions of critical habitat designations, could subject our Company (directly or indirectly through our operating partners) to significant expenses to modify our operations or could force discontinuation of certain operations altogether.

The Clean Air Act, as amended, referred to hereafter as CAA, and comparable state laws restrict the emission of air pollutants from many sources, including compressor stations. These laws and any implementing regulations may require us or our operating partners to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions, impose stringent air permit requirements, or use specific equipment or technologies to control emissions. While we may be required (directly or indirectly through our operating partners) to incur certain capital expenditures in the next few years for air pollution control equipment in connection with maintaining or obtaining operating permits or addressing other air emission-related issues, we do not believe that such requirements will have a material adverse effect on our operations.

In 2012, the United States Environmental Protection Agency, referred to hereafter as EPA, finalized rules under CAA establishing new air emission controls for oil and natural gas production and natural gas processing operations. EPA’s regulations include standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The rules established specific new requirements regarding emissions from compressors, dehydrators, storage tanks and other production equipment. In addition, the rules revised leak detection requirements for natural gas processing plants. These rules may continue to require a number of modifications to the operations of our operating partners, including the installation of new equipment to control emissions from compressors. Proposed legislation also addresses whether oil and gas production facilities that are separate but connected by pipelines and other means, may be tested as one, instead of multiple, air emissions sources. Although we cannot predict the cost to comply with new requirements at this point, compliance with changing air regulations could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact our business.

The Federal Water Pollution Control Act of 1972 or Clean Water Act, as amended, referred to hereafter as CWA, and comparable state laws impose restrictions and controls on the discharge of produced waters and other pollutants into navigable and other waters. Permits must be obtained to discharge pollutants into state and federal waters and to conduct construction activities in waters and wetlands. CWA and certain state regulations prohibit the discharge of produced water, sand, drilling fluids, drill cuttings, sediment and certain other substances related to the oil and gas industry into certain waters without an individual or general National Pollutant Discharge Elimination System discharge permit. In addition, the CWA and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. Some states also maintain groundwater protection programs that require permits for discharges, withdrawals, or operations that may impact groundwater conditions. Costs may be associated with the treatment of wastewater and/or developing and implementing storm water pollution prevention plans. CWA and comparable state statutes provide for civil, criminal and administrative penalties for unauthorized discharges of oil and other pollutants and impose liability on parties responsible for those discharges, for the costs of cleaning up environmental damage caused by releases and for natural resource damages resulting from releases.

The underground injection of oil and natural gas wastes is regulated by the Underground Injection Control program authorized by the Safe Drinking Water Act as amended, referred to hereafter as SDWA. The primary objective of injection well operating requirements is to ensure the mechanical integrity of the injection apparatus and to prevent migration of fluids from the injection zone into underground sources of drinking water. Substantially all of the oil and natural gas production in which we have an interest is developed from unconventional sources that require hydraulic fracturing as part of the completion process. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into rock formations, to stimulate gas production. Legislation to amend the SDWA to repeal the exemption for hydraulic fracturing from the definition of “underground injection” and require SDWA permitting and regulatory control of hydraulic fracturing, as well as legislation to require disclosure of the chemical constituents of the fluids used in the fracturing process, have been proposed in Congress. Congress continues to consider legislation to amend the SDWA to subject hydraulic fracturing operations to greater regulation under the Underground Injection Control Program and require disclosure of chemicals used in the hydraulic fracturing process.

Scrutiny of hydraulic fracturing activities continues in other ways. The federal government is currently undertaking several studies of hydraulic fracturing’s potential impacts. Numerous states, including Montana, Texas, Wyoming and North Dakota where our properties are located, have also proposed or adopted legislative or regulatory restrictions on, or new duties associated with, hydraulic fracturing. We cannot predict what further state and federal agency “fracking” requirements will continue to appear and what their provisions would be. If additional levels of regulation and permits are required through the adoption of new laws and regulations at the federal and state levels, this could lead to delays, increased operating costs and process prohibitions that would materially adversely affect our revenue and results of operations.

The National Environmental Policy Act as amended, referred to hereafter as NEPA, establishes a national environmental policy and goals for the protection, maintenance and enhancement of the environment and provides a process for implementing these goals within federal agencies. A major federal agency action having the potential to significantly impact the environment requires review under NEPA. Many of the activities of our third-party operating partners are covered under categorical exclusions which results in a shorter NEPA review process. The Council on Environmental Quality, in 2012, issued final guidance that may result in longer review processes and lead to delays and increased costs that could materially adversely affect our revenues and results of operations.

Climate Change

Significant studies and research in recent years have been devoted to climate change and global warming, and climate change has developed into a major political issue in the United States and globally. Certain research suggests that greenhouse gas emissions contribute to climate change and pose a threat to the environment. Recent scientific research and political debate have focused in part on carbon dioxide and methane incidental to crude oil and natural gas exploration and production. Many states and the federal government have enacted legislation and adopted regulations directed at controlling greenhouse gas emissions, and future legislation and regulation could impose additional restrictions or requirements in connection with our drilling and production activities, favor use of alternative energy sources, increase operating costs, and reduce demand for crude oil or other natural gas products. As such, our business could be materially adversely affected by domestic and international actions targeted at controlling climate change.

Changes in environmental laws and regulations sometimes occur, and any changes that result in more stringent and costly waste handling, storage, transport, disposal or cleanup requirements for any substances used or produced in our operations could materially adversely affect our operations and financial position, as well as those of the oil and gas industry in general. For instance, recent scientific studies have suggested that emissions of certain gases commonly referred to as “greenhouse gases,” including carbon dioxide and methane, may be contributing to warming of the Earth’s atmosphere.

Competition

The oil and natural gas industry is very competitive and the Company competes with numerous other oil and gas exploration and production companies. Many of these companies have substantially greater resources than those of the Company. Also, many of these companies are integrated in their approach, which includes not only exploration and production but transportation, sales of resources and refining capabilities on a regional, national or worldwide basis. The operations of other companies may be able to pay more for exploratory prospects and productive crude oil and natural gas properties. The larger or integrated competitors may have the resources to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit.

The larger or integrated companies may also be able to better absorb the burden of existing and any changes to federal, state and local laws and regulations, which would adversely affect the Company’s competitive position.

The Company’s ability to discover reserves and acquire additional properties in the future will be dependent upon its ability and resources to evaluate and select suitable properties and to consummate transactions in this highly competitive industry. In addition, the Company may be at a disadvantage in producing oil and natural gas properties and bidding for exploratory prospects because the Company has fewer financial and human resources than other companies in this industry. Should a larger and better financed company decide to directly compete with the Company and be successful in its efforts, the Company’s business could be adversely affected.

Competitive Advantage

The Company believes that, through our majority working interest leaseholds in the Permian Basin, the Eagle Ford, the Eagle Bine and the Niobrara, we hold a large quantity of acreage for the future exploration of potential oil and natural gas reserves. As the majority working interest owner, we would be able to, if successful, capture the majority of the economic benefit of the production produced and sold from those leaseholds. Through our minority working interest acreage in the Bakken, Eagle Ford and select Permian Basin leaseholds, we are able to participate in the drilling and production activities of many larger oil and natural gas operators in three large oil and natural gas basins.

We believe this model provides balanced diversification and acceleration of potential exposure to drilling and production related activities. As a non-operator, we rely on and typically benefit from the resources dedicated by the majority working interest partners to ensure their drilling and production activities are successful. As a result, we are able to participate in a greater number of drilling activities than a company of our size without a non-operated leasehold portfolio. We also believe that by participating in a greater number of overall wells being drilled, we are better able to diversify our risks of potential unsuccessful drilling activities. We feel that smaller capital investments in a larger number of wells may reduce our risk of loss overall, making us less reliant on the success of any one well to our overall growth plans and financial resources.

Available Information

We file annual, quarterly and periodic reports, proxy statements and other information with the Securities and Exchange Commission (the “SEC” or the “Commission”) in accordance with the Securities Exchange Act of 1934. You may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room, 100 F Street, N.E., Room 1580, Washington, D.C. 20549, at prescribed rates. The public may obtain information on the operations of the Public Reference Room by calling the SEC at 1-800-SEC-0330. Also, the SEC maintains a website that contains reports, proxy and information statements and other information regarding issuers, including us, that file electronically with the SEC. The public can obtain any document that we file with the SEC at http://www.sec.gov.

Our website address is www.asenergycorp.com.

Item 1A. RISK FACTORS

You should carefully consider the risks described below together with all of the other information included in this Annual Report on Form 10-K before making an investment decision with regard to our securities. The statements contained in or incorporated herein that are not historic facts are forward-looking statements that are subject to risks and uncertainties that could cause actual results to differ materially from those set forth in or implied by forward-looking statements. If any of the following risks actually occurs, our business, financial condition or results of operations could be harmed. In that case, you may lose all or part of your investment in the Company.

RISKS RELATING TO OUR BUSINESS

OUR LIMITED OPERATING HISTORY MAY NOT SERVE AS AN ADEQUATE BASIS TO JUDGE OUR FUTURE PROSPECTS AND RESULTS OF OPERATIONS.

Our two wholly-owned subsidiaries, Nevada ASEC and ASEN 2, were incorporated on April 2, 2010 and January 25, 2012, respectively. Accordingly, we have a limited operating history on which to base an evaluation of our business and prospects. Our prospects must be considered in light of the risks, expenses and difficulties frequently encountered by companies in their early stages of development. We cannot assure you that we will be successful in addressing the risks we may encounter, and our failure to do so could have a material adverse effect on our business, prospects, financial condition and results of operations. Our future operating results will depend on many factors, including:

our ability to raise adequate working capital;

the successful development and exploration of our properties;

demand for oil and natural gas;

the performance level of our competition;

our ability to attract and maintain key management and employees; and

our ability to efficiently explore, develop and produce sufficient quantities of marketable natural gas or oil in a highly competitive and speculative environment while maintaining quality and controlling costs.

The business of acquiring, exploring for, developing and producing hydrocarbon reserves is inherently risky. We have a limited operating history for you to consider in evaluating our business and prospects. Our operations are therefore subject to all of the risks inherent in acquiring, exploring for, developing and producing hydrocarbon reserves, particularly in light of our limited experience in undertaking such activities. We may never overcome these obstacles.

Our business is speculative and dependent upon the implementation of our business plan and our ability to enter into agreements with third parties for the rights to exploit potential oil and natural gas reserves on terms that will be commercially viable for us. To achieve profitable operations in the future, we must, alone or with others, successfully manage the factors stated above, as well as continue to develop ways to enhance our production efforts. Despite our best efforts, we may not be successful in our exploration or development efforts, or obtain required regulatory approvals. There is a possibility that some of our wells may never produce oil or natural gas.

WE ARE DEPENDENT ON THE SKILL, ABILITY AND DECISIONS OF THIRD-PARTY OPERATORS. THE FAILURE OF ANY THIRD-PARTY OPERATOR TO PERFORM THEIR SERVICES OR COMPLY WITH LAWS COULD RESULT IN MATERIAL ADVERSE CONSEQUENCES TO OUR PROPERTY INTERESTS AND SUBSTANTIAL PENALTIES.

We do not operate any of our properties. The success of the drilling, development, production and marketing of the oil and natural gas from our properties is dependent upon the decisions of our third-party operators who drill, develop, produce and market the oil and natural gas present on our leasehold properties. Such third-party operators failure to comply with various laws, rules and regulations affecting our properties could result in adverse consequences to us, our properties and our production. The failure of any third-party operator to make decisions, perform their services, discharge their obligations, deal with regulatory agencies, and comply with laws, rules and regulations, including environmental laws and regulations in a proper manner with respect to properties in which we have an interest could result in material adverse consequences to our interest in such properties, including substantial penalties and compliance costs. Such adverse consequences could result in substantial liabilities to us or could reduce the value of our properties, which could negatively affect our results of operations.

OUR THIRD-PARTY OPERATORS MAY BE UNABLE TO RENEW OR MAINTAIN CONTRACTS WITH INDEPENDENT PURCHASERS, WHICH WOULD HARM OUR BUSINESS AND FINANCIAL RESULTS.

Independent purchasers buy our oil and natural gas and our third-party operators negotiate such contracts. Upon expiration of our independent purchasers’ contracts, we are subject to the risk that the oil and natural gas purchasers will cease buying our oil and gas production output. It is not always possible for our third-party operators to obtain replacement oil and natural gas purchasers immediately as the industry is extremely competitive. If these contracts are not renewed, it could result in a significant negative impact on our business as we would be unable to sell the oil or natural gas produced on our leasehold properties.

WE MAY BE UNABLE TO OBTAIN ADDITIONAL CAPITAL REQUIRED TO IMPLEMENT OUR BUSINESS PLAN, WHICH COULD RESTRICT OUR ABILITY TO GROW.

We will require additional capital to fund our 2013 capital budget and to continue to grow our business via the drilling program through our third-party operators associated with our current properties and expansion of our exploration and development and leasehold acquisition programs. We may be unable to obtain additional capital if and when required.

Future acquisitions and future exploration and development activity will require additional capital that may exceed operating cash flow. In addition, our administrative costs (such as salaries, insurance expenses and general overhead expenses, as well as legal compliance costs and accounting expenses) will require cash resources.

We may pursue sources of additional capital through various financing transactions or arrangements, including joint venturing of projects, debt financing, equity financing or other means. We may not be successful in identifying suitable financing transactions in the time period required or at all, and we may not obtain the required capital by other means. If we are not successful in raising additional capital, our resources may be insufficient to fund our planned expansion of operations in 2013 or thereafter.

Any additional capital raised through the sale of equity may dilute the ownership percentage of our stockholders. Raising any such capital could also result in a decrease in the nominal fair market value of our equity securities because our assets would be owned by a larger pool of outstanding equity. The terms of securities we issue in future capital transactions may be more favorable to new investors and may include preferences, superior voting rights, the issuance of other derivative securities and issuances of incentive awards under equity employee incentive plans, all of which may have a dilutive effect to existing investors.

Our ability to obtain financing, if and when necessary, may be impaired by such factors as the capital markets (both generally and in the oil and gas industry in particular), our limited operating history, the location of our oil and natural gas properties, prices of oil and natural gas on the commodities markets (which will impact the amount of asset-based financing available to us) and the departure of key employees. Further, if oil or natural gas prices decline, our revenues will likely decrease and such decreased revenues may increase our requirements for capital. If the amount of capital we are able to raise from financing activities, together with revenues from our operations, are not sufficient to satisfy our capital needs (even if we reduce our operations), we may be required to cease operations, divest our assets at unattractive prices or obtain financing on unattractive terms.

IF WE ARE UNABLE TO CONTINUE AS A GOING CONCERN, INVESTORS MAY FACE A COMPLETE LOSS OF THEIR INVESTMENT.

The report of independent registered public accounting firm on our financial statements contains explanatory language that substantial doubt exists about our ability to continue as a going concern. If we are unable to obtain sufficient financing in the near term or achieve profitability, then we would, in all likelihood, experience severe liquidity problems and may have to curtail our operations. If we curtail our operations, we may be placed into bankruptcy or undergo liquidation, the result of which will adversely affect the value of our common shares.

THE FUTURE OF THE COMPANY IS DEPENDENT ON THE SUCCESSFUL ACQUISITION AND DEVELOPMENT OF PRODUCING AND RESERVE-RICH PROPERTIES AND ON OUR RELATIONSHIP WITH XOG.

We intend to continue to supplement our current portfolio with additional sites and leaseholds. Our ability to meet our growth and operational objectives will depend on the success of our acquisitions and our relationship with XOG, and there is no assurance that the integration of future assets and leaseholds will be successful. XOG is currently contracted to operate our existing wells in the Permian Basin region and provides us with a source of leasehold acquisitions. The loss of our relationship with XOG would make it more difficult to locate attractive leasehold acquisition targets. The possibility exists that future transactions between the Company and its affiliates may not be considered arms-length when executed due to the common ownership of our largest stockholder, Randall Capps, and his controlling ownership of the XOG Group. Randall Capps is also a Director on the Company’s Board of Directors and the father-in-law of our Chief Executive Officer, Scott Feldhacker.

OUR LACK OF DIVERSIFICATION WILL INCREASE THE RISK OF AN INVESTMENT IN THE COMPANY, AND OUR FINANCIAL CONDITION AND RESULTS OF OPERATIONS MAY DETERIORATE IF WE FAIL TO DIVERSIFY.

Our business focus is on the oil and natural gas industry. Larger companies have the ability to manage their risk by greater geographic and industry diversification. However, we may lack comparable diversification, in terms of both the nature and geographic scope of our business. As a result, we will likely be impacted more acutely by factors affecting the oil and natural gas industry or the regions in which we operate, than we would if we were a more diversified business. If we do not diversify the nature and geographic scope of our operations, our financial condition and results of operations could deteriorate in connection with downturns in the oil and natural gas industry or the oil and natural gas production in the geographic areas in which we operate.

STRATEGIC RELATIONSHIPS UPON WHICH WE MAY RELY ARE SUBJECT TO CHANGE, WHICH MAY DIMINISH OUR ABILITY TO CONDUCT OPERATIONS.

Our ability to acquire additional leaseholds successfully, to increase our oil and natural gas reserves, to participate in drilling opportunities through our third party operators and to identify and enter into commercial arrangements with customers will depend on developing and maintaining close working relationships with XOG and industry participants, and our ability to select and evaluate suitable properties and to consummate transactions in a highly competitive environment. Our inability to maintain close working relationships with XOG and other industry participants or continue to acquire suitable leaseholds may impair our ability to execute our business plan.

To continue to develop our business, we will endeavor to use the business relationships of members of our management to enter into strategic relationships, which may take the form of joint ventures with other private parties and contractual arrangements with other oil and gas companies, including those that supply equipment and other resources which we may use in our business. We may not be able to establish these strategic relationships, or if established, we may not be able to maintain them adequately. In addition, the dynamics of our relationships with strategic partners may require the Company to incur expenses or undertake activities we would not otherwise be inclined to in order to fulfill our obligations to these partners or maintain our relationships. For example, we may hold minority interests in a lease that has significant existing or prospective value due to current production or future reserve prospects. We may be subject to contracts with a third-party operator that compel us to make certain financial commitments on that lease, otherwise we may be at risk of forfeiting existing or future rights to petroleum production from that lease if we fail to meet those financial obligations. Such provisions may be included in any third party joint operating agreement, or JOA, drilling program under an area of mutual interest (AMI), or other joint venture projects which are common in our industry. If our strategic relationships are not established or maintained, the Company’s business prospects may be limited, which could diminish our ability to conduct our operations.

WE MUST REACH AGREEMENTS WITH THIRD-PARTY PROFESSIONALS AND EXPERTS TO SUPPLY US WITH THE EXPERTISE, SERVICES AND INFRASTRUCTURE NECESSARY TO OPERATE OUR BUSINESS, AND THE LOSS OF ACCESS TO THESE EXPERTS, THESE SERVICES AND INFRASTRUCTURE COULD CAUSE OUR BUSINESS TO SUFFER, WHICH, IN TURN, COULD DECREASE OUR REVENUES AND INCREASE OUR COSTS.

We have certain contemplated strategic vendor relationships that will be critical to our strategy. As a non-operator, we must actively secure the services of drilling companies, hydrofracking and completion companies, contract operators, engineers and other service providers. In our majority working interest leases in the Permian Basin, we rely on the contractual relationship with XOG for much of these services. We also rely on the consulting expertise of Cambrian Management Ltd., an unaffiliated third-party consulting firm with expertise in the drilling and completion of specific wells in the Permian Basin. We cannot assure that these relationships can be maintained or obtained on terms favorable to us. Our success depends substantially on obtaining relationships with additional strategic partners, such as investment banks, accounting firms, legal firms and operational entities. If we are unable to obtain or maintain relationships with strategic partners, our business, prospects, financial condition and results of operations may be materially adversely affected.

CERTAIN OF OUR UNDEVELOPED LEASEHOLD ACREAGE IS SUBJECT TO LEASES THAT WILL EXPIRE OVER THE NEXT SEVERAL YEARS UNLESS PRODUCTION IS ESTABLISHED ON SUCH ACREAGE OR THE LEASES ARE EXTENDED.

Our leases on certain undeveloped leasehold acreage may expire over the next one to eight years. A portion of our acreage is not currently held by production. Unless production in paying quantities is established on acres containing these leases during their initial terms or we obtain extensions of the leases, these leases will expire. If our leases expire, we will lose our right to develop the related properties covered by such leases.

SABER OIL, LLC, IS THE HOLDER OF IRREVOCABLE PROXIES ALLOWING SABER OIL, LLC VOTING RIGHTS, IN THE AGGREGATE, OF 55.55% OF THE COMPANY’S ISSUED AND OUTSTANDING COMMON STOCK(based upon 51,721,798 shares of common stock outstanding, as set forth in the Form 10-Q filed with the Securities and Exchange Commission on November 15, 2012). AND IS THE SOLE OWNER OF THE SERIES A PREFERRED STOCK OF THE COMPANY. TWO PRINCIPALS OF SABER OIL, LLC, J. STEVEN PERSON AND H.H. WOMMACK, III, ARE DIRECTORS OF THE COMPANY. THE INTERESTS OF SABER OIL, LLC MAY NOT BE ALIGNED WITH OUR INTERESTS OR THE INTERESTS OF OUR OTHER STOCKHOLDERS. ACCORDINGLY, ANY LOSS OF OUR RELATIONSHIP WITH SABER OIL, LLC, OR A DISAGREEMENT WITH SABER OIL, LLC COULD HAVE A MATERIAL ADVERSE EFFECT ON OUR OPERATIONS, PROSPECTS, REVENUES AND RESULTS OF OPERATIONS.

Each of J. Steven Person and H.H. Wommack, III is a member of our board of directors and is a principal of Saber Oil, LLC. Saber Oil, LLC is the holder of irrevocable proxies allowing Saber Oil, LLC voting rights over 55.55% of the outstanding common stock of the Company(based upon 51,721,798 shares of common stock outstanding, as set forth in the Form 10-Q filed with the Securities and Exchange Commission on November 15, 2012). This voting right over a majority of our issued and outstanding common stock allows Saber Oil, LLC to be able to exert significant control over decisions requiring stockholder approval, including the election of directors and approval of the sale of assets and other business combinations. Additionally, as members of our directors, Mr. Person and Mr. Wommack are aware of our business plans and may disagree with management’s day-to-day operations of the Company. Conflicts of interest may arise between Mr. Person, Mr. Wommack and Saber Oil, LLC, on the one hand, and the Company and our other stockholders, on the other hand. As a result of these conflicts, Mr. Person, Mr. Wommack and Saber Oil, LLC may favor their own interests over the interests of our stockholders.

RANDALL CAPPS AND HIS AFFILIATED ENTITIES, THE XOG GROUP, ARE NOT LIMITED IN THEIR ABILITY TO COMPETE WITH US, WHICH COULD LIMIT OUR ABILITY TO ACQUIRE OR DEVELOP ADDITIONAL ASSETS OR BUSINESSES.

Mr. Capps and his affiliates are not limited in their ability to compete with us and are under no obligation to offer opportunities to us. In addition, Mr. Capps and his affiliates may compete with us with respect to any future acquisition opportunities.

Neither our charter documents nor any other agreement prohibits Mr. Capps or the XOG Group from owning assets or engaging in businesses that compete directly or indirectly with us. In addition, Mr. Capps and the XOG Group may acquire, develop or dispose of additional oil and natural gas properties or other assets in the future, without any obligation to offer us the opportunity to purchase or develop any of those assets. Competition from Mr. Capps and the XOG Group could adversely impact our business prospects and results of operations.

WE NEED TO CONTINUE TO DEVELOP AND MAINTAIN A DIVERSE PORTFOLIO OF LEASEHOLDS AND PRODUCING PROPERTIES, OTHERWISE WE WILL BE UNABLE TO EFFECTIVELY COMPETE IN THE INDUSTRY.

To remain competitive, we must continue to enhance and improve our oil and natural gas reserves and producing properties and leaseholds. We need to seek available properties and leaseholds in various locations including the Bakken, Eagle Ford and Permian Basin formations, among others. These efforts may require us to choose one available property in lieu of another which increases risk to our potential holdings. If we are unable to maintain a diverse portfolio of leasehold properties, we will be unable to compete effectively and may be negatively impacted financially if our leasehold properties in a certain location are unable to produce.

WE INCURRED A SUBSTANTIAL LOSS ON THE SALE OF OUR AULD SHIPMAN PROPERTY. THERE CAN BE NO ASSURANCES THAT WE WILL NOT INCUR LOSSES ON FUTURE DISPOSITIONS OF PROPERTY.

On September 11, 2012, pursuant to the Asset Purchase Agreement, ASEN 2 sold its interests in approximately 1,200 leasehold acres of the Auld Shipman project in La Salle and Frio counties, Antler Bar in exchange for the forgiveness of the certain indebtedness and for the assumption by Antler Bar, an affiliate of Pentwater, of all liabilities related to the Auld Shipman property. We recognized a loss on the sale of the Auld Shipman oil and natural gas leases during the quarter ended September 30, 2012 of $22,451,718. There can be no assurances that we will not sell additional oil and natural gas leases for a loss in the future, which would adversely affect our results of operations.

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 by our third party operators 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. The operators we contract or partner with may be required to shut-in wells or delay initial production for lack of a viable market or because of inadequacy or unavailability of pipeline or gathering system capacity. When that occurs, we will be unable to realize revenue from those wells until the production can be tied to a gathering system. This can result in considerable delays from the initial discovery of a reservoir to the actual production of the oil and natural gas and realization of revenues.

WE HAVE IDENTIFIED MATERIAL WEAKNESSES IN OUR INTERNAL CONTROL OVER FINANCIAL REPORTING.

The Company has identified material weaknesses in the Company’s internal controls. A "material weakness" is a control deficiency, or combination of control deficiencies, such that there is a reasonable possibility that a material misstatement of the annual or interim statements will not be prevented or detected on a timely basis. Accordingly, a material weakness increases the risk that the financial information we report contains material errors. Although we have taken actions to remediate the past material weaknesses in our internal controls over financial reporting, these measures may not be sufficient to ensure that our internal controls are always effective in the future. In addition, any future material weaknesses, or any failure to effectively address a material weakness or other control deficiency or implement required new or improved controls, or difficulties encountered in their implementation, could limit our ability to obtain financing, harm our reputation, disrupt our ability to process key components of our results of operations and financial position timely and accurately and cause us to fail to meet our reporting obligations under rules promulgated by the SEC.

Scott Mahoney, our former chief financial officer resigned effective November 24, 2012. Following Mr. Mahoney’s resignation through January 2013, the Company employed a third-party company to perform the functions of the chief financial officer. Currently, Brian Ringel, the controller of the Company, is performing the functions of the chief financial officer on an interim basis, however, the Company has not formally appointed anyone to fill this executive office. Not having a chief financial officer could adversely impact the Company, the results of our operations, our financial performance and our stock price.

RISKS RELATED TO THE OIL AND NATURAL GAS INDUSTRY

CRUDE OIL AND NATURAL GAS PRICES ARE VERY VOLATILE. A PROTRACTED PERIOD OF DEPRESSED OIL AND NATURAL GAS PRICES MAY ADVERSELY AFFECT OUR BUSINESS, FINANCIAL CONDITION, RESULTS OF OPERATIONS OR CASH FLOWS.

The oil and natural gas markets are very volatile, and we cannot predict future oil and natural gas prices. The prices we receive for our oil and natural gas production heavily influences our revenue, profitability, access to capital and future rate of growth. Historically, oil and natural gas prices have been volatile and are subject to fluctuations in response to changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control. Any substantial decline in the price of oil and natural gas will likely have a material adverse effect on our operations, financial condition and level of expenditures for the development of our oil and natural gas reserves. The prices we receive for our production and the levels of our production and reserves depend on numerous factors beyond our control. These factors include, but are not limited to, the following:

changes in global supply and demand for oil and natural gas by both refineries and end users;

the ability of the members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;

the price and volume of imports of foreign oil and natural gas;

political and economic conditions, including embargoes, in oil-producing countries or affecting other oil-producing activity;

the level of global oil and gas exploration and production activity;

the level of global oil and gas inventories;

weather conditions;

technological advances affecting energy consumption;

domestic and foreign governmental regulations and taxes;

proximity and capacity of oil and gas pipelines and other transportation facilities;

the price and availability of competitors’ supplies of oil and gas in captive market areas;

the introduction, price and availability of alternative forms of fuel to replace or compete with oil and natural gas;

speculation in the price of commodities in the commodity futures market;

the availability of drilling rigs and completion equipment; and

the overall economic environment.

Further, oil and natural gas prices do not necessarily fluctuate in direct relationship to each other. Because approximately 69% of our estimated proved reserves as of December 31, 2012 were oil, our financial results are more sensitive to fluctuations in oil prices. The price of oil has been extremely volatile, and we expect this volatility to continue for the foreseeable future. The slowdown in economic activity caused by the worldwide economic recession has reduced worldwide demand for energy. This may result in lower crude oil and natural gas prices. Crude oil prices declined from record high levels in early July 2008 of over $140 per Bbl to below $40 per Bbl in February 2009 before rebounding to over $97 per Bbl in April 2013. Natural gas prices declined from over $13 per MMBtu (million British thermal units) in mid-2008 to approximately $4 per MMBtu in April 2013. Such a decline could occur again in the future due to global economic conditions.

Lower oil and natural gas prices may not only decrease our revenues on a per unit basis but also may reduce the amount of oil and natural gas that we can produce economically and therefore potentially lower our reserve bookings. A substantial or extended decline in oil or natural gas prices may result in impairments of our proved oil and gas properties and may materially and adversely affect our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures. To the extent commodity prices received from production are insufficient to fund planned capital expenditures; we will be required to reduce spending or borrow to cover any such shortfall. Lower oil and natural gas prices may also reduce the amount of our borrowing base under our credit agreement, which is determined at the discretion of the lenders based on the collateral value of proved reserves that have been mortgaged to the lenders, and is subject to regular redeterminations.

These factors and the volatility of the energy markets make it extremely difficult to predict future oil and natural gas price movements with any certainty.

DRILLING FOR AND PRODUCING OIL AND NATURAL GAS ARE HIGH RISK ACTIVITIES WITH MANY UNCERTAINTIES. THE OCCURRENCE OF ANY OF THESE UNCERTAINTIES MAY ADVERSELY AFFECT OUR FINANCIAL CONDITION.

Our future success will depend on the success of our exploration, 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 viable oil or natural gas production. Our decision to purchase, explore, develop or otherwise exploit prospects or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. Our cost associated with 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 drilling, including the following:

delays imposed by or resulting from compliance with regulatory requirements;

pressure or irregularities in geological formations;

shortages of or delays in obtaining qualified personnel or equipment, including drilling rigs and CO2;

equipment failures or accidents;

adverse weather conditions, such as freezing temperatures, hurricanes and storms;

unexpected operational events;

reductions in oil and natural gas prices;

proximity to and capacity of transportation facilities;

title problems; and

limitations in the market for oil and natural gas.

The presence of one or a combination of these factors at our properties could adversely affect our business, financial condition or results of operations.

ESTIMATES OF OIL AND NATURAL GAS RESERVES THAT MAY BE INACCURATE AND ACTUAL QUANTITY OF OUR PROVED OIL AND NATURAL GAS RESERVES MAY BE LOWER THAN THE COMPANY’S PROJECTIONS.

We make estimates of oil and natural gas reserves, upon which we have and will base our management decisions. We make these reserve estimates using various assumptions, including assumptions as to oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes, timing of operations and availability of funds. Some of these assumptions are inherently subjective, and the accuracy of our reserve estimates rely in part on the ability of our management team, engineers and other advisors to make accurate assumptions.

Determining the amount of oil and natural gas recoverable from various formations where we have exploration and production activities involves great uncertainty. The process of estimating oil and natural gas reserves is complex and will require us to make significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each property. These assumptions are dependent on many variables, and therefore changes often occur as these variables evolve. As a result, our reserve estimates will be inherently imprecise. Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves may vary substantially from our estimates. Although we have estimated our reserves and the costs associated with these reserves in accordance with industry standards, estimated costs may not be accurate, development may not occur as scheduled and actual results may not occur as estimated. If actual production results vary substantially from our reserve estimates, this could materially reduce our revenues and could result in the impairment of our oil and natural gas properties.

THE PRESENT VALUE OF FUTURE NET REVENUES FROM OUR PROVED RESERVES WILL NOT NECESSARILY BE THE SAME AS THE CURRENT MARKET VALUE OF OUR ESTIMATED OIL AND NATURAL GAS RESERVES.

You should not assume that the present value of future net revenues from our proved reserves is the current market value of our estimated oil and natural gas reserves. In accordance with SEC requirements for the years ended December 31, 2012 and 2011, we based the estimated discounted future net revenues from our proved reserves on the 12-month unweighted arithmetic average of the first-day-of-the-month price for the preceding twelve months without giving effect to derivative transactions. Actual future net revenues from our oil and natural gas properties will be affected by factors such as:

actual prices we receive for oil and natural gas;

actual cost of development and production expenditures;

the amount and timing of actual production; and

changes in governmental regulations or taxation.

The timing of both our production and our incurring expenses in connection with the development and production of oil and natural gas properties will affect the timing and amount of actual future net revenues from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net revenues may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general.

Actual future prices and costs may differ materially from those used in the present value estimates included in this Annual Report on Form 10-K. Any significant future price changes will have a material effect on the quantity and present value of our proved reserves.

THE COMPANY WILL RELY ON TECHNOLOGY TO CONDUCT ITS BUSINESS, AND SUCH TECHNOLOGY COULD BECOME INEFFECTIVE OR OBSOLETE WHICH WOULD RESULT IN SUBSTANTIAL COSTS TO THE COMPANY.

Our industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. We rely on technology, including geographic and seismic analysis techniques and economic models, to develop our reserve estimates and to guide our exploration, development and production activities. We must continually enhance and update our technology to maintain its efficacy and to avoid obsolescence. The costs of doing so may be substantial and may be higher than the costs that we anticipate for technology maintenance and development. In addition, other natural gas and crude oil companies may have greater financial, technical and personnel resources that allow them to enjoy technological advantages and may in the future allow them to implement new technologies before we can. We may not be able to respond to these competitive pressures and implement new technologies on a timely basis or at an acceptable cost. If we are unable to maintain the efficacy of our technology, our ability to manage our business and to compete may be impaired and our business, financial condition and results of operations could be materially adversely affected. Further, even if we are able to maintain technical effectiveness, our technology may not be the most efficient means of reaching our objectives, in which case we may incur higher operating costs than if our technology was more efficient.

A DECLINE OF OIL AND NATURAL GAS PRICES OR A PROLONGED PERIOD OF REDUCED OIL AND NATURAL GAS PRICES COULD RESULT IN A DECREASE IN OUR EXPLORATION AND DEVELOPMENT EXPENDITURES, WHICH COULD NEGATIVELY IMPACT OUR FUTURE PRODUCTION.

If oil and natural gas prices decline or reduce to lower levels for a prolonged period of time, we may be unable to continue to fund capital expenditures at historical levels due to the decreased cash flows that will result from such reduced oil and natural gas prices. Additionally, a decline in oil and natural gas prices or a prolonged period of lower oil and natural gas prices could result in a reduction of our borrowing base under our credit facility, which will further reduce the availability of cash to fund our operations, should we desire to borrow under our credit agreement. As a result, we may have to reduce our capital expenditures in future years. A decrease in our capital expenditures will likely result in a decrease in our production levels.

CONTINUED WEAKNESS IN ECONOMIC CONDITIONS OR UNCERTAINTY IN FINANCIAL MARKETS MAY HAVE MATERIAL ADVERSE IMPACTS ON OUR BUSINESS THAT WE CANNOT PREDICT.

U.S. and global economies and financial systems have experienced episodes of turmoil and upheaval characterized by extreme volatility in prices of securities, diminished liquidity and credit availability, inability to access capital markets, the bankruptcy, failure, collapse or sale of financial institutions, and continue to be affected by continued high levels of unemployment and an unprecedented level of intervention by the U.S. federal and other governments. Continued weakness in the U.S. or global economies could materially adversely affect our business and financial condition. For example:

the demand for oil and natural gas in the U.S. may decline from present levels and may remain at low levels if economic conditions remain weak, and negatively impact our revenues, margins, profitability, operating cash flows, liquidity and financial condition;

the tightening of credit or lack of credit availability to our customers could adversely affect our ability to collect our trade receivables;

our ability to access the capital markets may be restricted at a time when we would like, or need, to raise capital for our business, including for exploration and/or development of our reserves; and

our commodity hedging arrangements could become ineffective if our counterparties are unable to perform their obligations or seek bankruptcy protection.

THE OIL AND GAS INDUSTRY IS SUBJECT TO SUBSTANTIAL COMPETITION. IF WE ARE UNABLE TO COMPETE EFFECTIVELY, OUR FINANCIAL CONDITION MAY BE ADVERSELY AFFECTED.

The oil and gas industry is highly competitive. Other oil and gas companies may seek to acquire oil and natural gas leases and other properties and services the Company requires to operate its business in the planned areas. This competition is increasingly intense as prices of oil and natural gas have risen in recent years. Additionally, other companies engaged in our line of business may compete with us from time to time in obtaining capital from investors. Competitors include larger companies who may have access to greater financial, technical and personnel resources and may conduct their own refining and petroleum marketing operations, which may give them a competitive advantage. Furthermore, these companies may also be better able to withstand the financial pressures of unsuccessful drilling attempts, sustained periods of volatility in financial markets and generally adverse global and industry-wide economic conditions, and may be better able to absorb the burdens resulting from changes in relevant laws and regulations, which would adversely affect our competitive position. Existing or potential competitors may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer. The cost to attract and retain qualified personnel has increased over the past few years due to competition and may increase substantially in the future. In addition, existing or potential competitors may be strengthened through the acquisition of additional assets and interests. If we are unable to compete effectively or respond adequately to competitive pressures, our results of operation and financial condition may be materially adversely affected.

OUR BUSINESS OF EXPLORING FOR OIL AND GAS IS RISKY AND MAY NOT BE COMMERCIALLY SUCCESSFUL, AND THE ADVANCED TECHNOLOGIES THE COMPANY USES CANNOT ELIMINATE EXPLORATION RISK.

Our future success will depend on the success of our exploratory drilling program through our third party operators. Oil and gas exploration and development involves a high degree of risk. These risks are more acute in the early stages of exploration.

Our expenditures on exploration may not result in new discoveries of oil or natural gas in commercially viable quantities. Projecting the costs of implementing an exploratory drilling program is difficult due to a variety of factors, including:

the inherent uncertainties of drilling in less known formations;

the costs associated with encountering various and unexpected drilling conditions, such as over-pressured zones;

equipment failures or accidents and shortages or delays in the availability of oilfield services or drilling rigs and other equipment;

changes in drilling plans and locations as a result of prior exploratory wells or additional seismic data and interpretations thereof;

adverse weather conditions, including hurricanes; and

compliance with governmental requirements.

Even when used and properly interpreted, three-dimensional (3-D) seismic data and visualization techniques only assist geoscientists in identifying subsurface structures and hydrocarbon indicators. Such data and techniques do not allow the interpreter to know conclusively if hydrocarbons are present or economically producible. In addition, the use of three-dimensional (3-D) seismic data becomes less reliable when used at increasing depths. We could incur losses as a result of expenditures on unsuccessful wells. If exploration costs exceed our estimates, or if our exploration efforts do not produce results which meet our expectations, our exploration efforts may not be commercially successful, which could adversely impact our ability to generate revenues from our operations.

WE MAY NOT BE ABLE TO DEVELOP OIL AND NATURAL GAS RESERVES ON AN ECONOMICALLY VIABLE BASIS, AND OUR RESERVES AND PRODUCTION MAY DECLINE AS A RESULT.

If we succeed in discovering oil or natural gas reserves, we cannot assure that these reserves will be capable of the production levels we project or that such levels will be in sufficient quantities to be commercially viable. On a long-term basis, our viability depends on our ability to find or acquire, develop and commercially produce additional oil and natural gas reserves. Without the addition of reserves through acquisition, exploration or development activities, our reserves and production will decline over time as reserves are produced. Our future performance will depend not only on our ability to develop then-existing properties, but also on our ability to identify and acquire additional suitable producing properties or prospects, to find markets for the oil and natural gas we develop and to distribute effectively our production into the markets.

Future oil and natural gas exploration may involve unprofitable efforts, not only from dry wells, but from wells that are productive but do not produce sufficient net revenues to return a profit after drilling, operating and other costs. Completion of a well does not assure a profit on the investment or recovery of drilling, completion and operating costs. In addition, drilling hazards or environmental damage could greatly increase the cost of operations, and various field operating conditions may adversely affect the production from successful wells. These conditions include delays in obtaining governmental approvals or consents, shut-downs of connected wells resulting from extreme weather conditions, problems in storage and distribution and adverse geological and mechanical conditions. While we will endeavor to effectively manage these conditions, we cannot assure you we will do so optimally, and we will not be able to eliminate them completely in any case. Therefore, these conditions could diminish our revenue and cash flow levels and could result in the impairment of our oil and natural gas properties.

THE UNAVAILABILITY OR HIGH COST OF ADDITIONAL DRILLING RIGS, EQUIPMENT, SUPPLIES, PERSONNEL AND OILFIELD SERVICES COULD ADVERSELY AFFECT OUR ABILITY TO EXECUTE OUR EXPLORATION AND DEVELOPMENT PLANS WITHIN OUR BUDGET AND ON A TIMELY BASIS.

Shortages or the high cost of drilling rigs, equipment, supplies, personnel or oilfield services could delay or adversely affect our development and exploration operations or cause us to incur significant expenditures that are not provided for in our capital budget, which could have a material adverse effect on our business, financial condition or results of operations.

OUR DEVELOPMENT AND EXPLORATION OPERATIONS REQUIRE SUBSTANTIAL CAPITAL, AND WE MAY BE UNABLE TO OBTAIN NEEDED CAPITAL OR FINANCING ON SATISFACTORY TERMS, WHICH COULD LEAD TO A LOSS OF PROPERTIES AND A DECLINE IN OUR OIL AND NATURAL GAS RESERVES, AND ULTIMATELY OUR PROFITABILITY.

Our industry is capital intensive. We expect to continue to make substantial capital expenditures in our business and operations for the exploration, development, production and acquisition of natural gas and crude oil reserves. To date, we have financed capital expenditures primarily with bank borrowings under our credit facility, cash generated by operating activities, from proceeds from our private placement offerings of our common stock and proceeds from stock subscription receivables. We intend to finance our future capital expenditures utilizing similar financing sources. Our cash flows from operations are subject to a number of variables, including:

our proved reserves;

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

the prices at which oil and natural gas are sold;

the costs to produce oil and natural gas; and

our ability to acquire, locate and produce new reserves.

If our revenues or the borrowing base under our credit facility decreases as a result of lower natural gas and crude oil prices, operating difficulties, declines in reserves or for any other reason, then we may have limited ability to obtain the capital necessary to sustain our operations at current levels. We may, from time to time, need to seek additional financing. If we raise funds by issuing equity securities, this could have a dilutive effect on existing stockholders. There can be no assurance as to the availability or terms of any additional financing. Our inability to obtain additional financing, or sufficient financing on favorable terms, would adversely affect our financial condition and profitability.

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 review our proved oil and natural gas properties for impairment whenever events and 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 available under our revolving credit facility. 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 ability to borrow under our revolving credit facility and our results of operations for the periods in which such charges are taken.We had impairments of $28,640,726 and $1,027,552 for the years ended December 31, 2012 and 2011.

WE OUTSOURCE THE OPERATION OF ALL OF OUR DRILLING LOCATIONS, AND, THEREFORE, IN CERTAIN SITUATIONS WE WILL NOT BE ABLE TO CONTROL, AND IN OTHER SITUATIONS WE WILL HAVE LIMITED INPUT REGARDING, THE TIMING OF EXPLORATION OR DEVELOPMENT EFFORTS, ASSOCIATED COSTS, OR THE RATE OF PRODUCTION OF ANY NON-OPERATED ASSETS.

We enter into contract operating agreements with operators who are responsible for the management and day-to-day operation of our crude oil and/or natural gas wells. As a result, we may have limited ability to exercise influence over the operations of the drilling locations operated by our partners. Dependence on the operators could prevent us from realizing our target returns. The success and timing of exploration and development activities operated by our partners will depend on a number of factors that will be largely outside of our control, including:

the timing and amount of capital expenditures;

the operator’s expertise and financial resources;

approval of other participants in drilling wells;

selection of technology; and

the rate of production of reserves, if any.

This limited ability to exercise control over the operations of our drilling locations may cause a material adverse effect on our results of operations and financial condition.

THE DEVELOPMENT OF OUR PROVED UNDEVELOPED RESERVES MAY TAKE LONGER AND MAY REQUIRE HIGHER LEVELS OF CAPITAL EXPENDITURES THAN WE CURRENTLY ANTICIPATE. THEREFORE, OUR UNDEVELOPED RESERVES MAY NOT BE ULTIMATELY DEVELOPED OR PRODUCED.

Approximately 22% of our total proved reserves were classified as proved undeveloped as of December 31, 2012. Development of these reserves may take longer and require higher levels of capital expenditures than we currently anticipate. Delays in the development of our reserves or increases in costs to drill and develop such reserves will reduce the PV-10 value of our estimated proved undeveloped reserves and future net revenues estimated for such reserves and may result in some projects becoming uneconomic. In addition, delays in the development of reserves could cause us to have to reclassify our proved reserves as unproved reserves.

UNLESS WE REPLACE OUR OIL AND NATURAL GAS RESERVES, OUR RESERVES AND PRODUCTION WILL DECLINE, WHICH WOULD ADVERSELY AFFECT OUR BUSINESS, FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

Unless we conduct successful development, exploitation and exploration activities or acquire properties containing proved reserves, our proved reserves will decline as those reserves are produced. Producing oil and natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our future oil and natural gas reserves and production, and therefore our cash flows and income, are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, exploit, find or acquire additional reserves to replace our current and future production at acceptable costs. If we are unable to replace our current and future production, the value of our reserves will decrease, and our business, financial condition and results of operations would be adversely affected.

DRILLING NEW WELLS COULD RESULT IN NEW LIABILITIES, WHICH COULD ENDANGER THE COMPANY’S INTERESTS IN ITS PROPERTIES AND ASSETS. ADDITIONALLY, WE MAY NOT BE INSURED FOR, OR OUR INSURANCE MAY BE INADEQUATE TO PROTECT US AGAINST, THESE RISKS.

There are risks associated with the drilling of oil and natural gas wells, including encountering unexpected formations or pressures, premature declines of reservoirs, blow-outs, craterings, sour gas releases, fires and spills, among others. The occurrence of any of these events could significantly reduce our revenues or cause substantial losses, impairing our future operating results. We may become subject to liability for pollution, blow-outs or other hazards. We do our best to insure the Company with respect to these hazards; however, such insurance has limitations on liability that may not be sufficient to cover the full extent of such liabilities. The payment of such liabilities could reduce the funds available to us or could, in an extreme case, result in a total loss of our properties and assets. Moreover, we may not be able to maintain adequate insurance in the future at rates that are considered reasonable. Oil and natural gas production operations are also subject to all the risks typically associated with such operations, including premature decline of reservoirs and the invasion of water into producing formations.

DECOMMISSIONING COSTS ARE UNKNOWN AND MAY BE SUBSTANTIAL. UNPLANNED COSTS COULD DIVERT RESOURCES FROM OTHER PROJECTS.

We may become responsible for costs associated with abandoning and reclaiming wells, facilities and pipelines which the Company uses for production of oil and natural gas reserves. Abandonment and reclamation of these facilities and the costs associated therewith is often referred to as “decommissioning.” We accrue a liability for decommissioning costs associated with our wells, but have not established any cash reserve account for these potential costs in respect of any of our properties. If decommissioning is required before economic depletion of our properties or if our estimates of the costs of decommissioning exceed the value of the reserves remaining at any particular time to cover such decommissioning costs, we may have to draw on funds from other sources to satisfy such costs. The use of other funds to satisfy such decommissioning costs could impair our ability to focus capital investment in other areas of our business.

THE COMPANY MAY HAVE DIFFICULTY DISTRIBUTING ITS PRODUCTION, WHICH COULD HARM THE COMPANY’S FINANCIAL CONDITION.

In order to sell the oil and natural gas that are produced from our properties, the operators of our wells may have to make arrangements for storage and distribution to the market. We will rely on local infrastructure and the availability of transportation for storage and shipment of our products, but infrastructure development and storage and transportation facilities may be insufficient for our needs at commercially acceptable terms in the localities in which we operate. This situation could be particularly problematic to the extent that our operations are conducted in remote areas that are difficult to access, such as areas that are distant from shipping and/or pipeline facilities. These factors may affect our ability to explore and develop properties and to store and transport our oil and natural gas production and may increase our expenses.

Furthermore, weather conditions or natural disasters, actions by companies doing business in one or more of the areas in which we operate, or labor disputes may impair the distribution of oil and/or natural gas and in turn diminish our financial condition or ability to maintain our operations.

OUR POTENTIAL DRILLING LOCATION INVENTORIES ARE SCHEDULED TO BE DRILLED OVER SEVERAL YEARS, MAKING THEM SUSCEPTIBLE TO UNCERTAINTIES THAT COULD MATERIALLY ALTER THE OCCURRENCE OR TIMING OF THEIR DRILLING. IN ADDITION, WE MAY NOT BE ABLE TO RAISE THE SUBSTANTIAL AMOUNT OF CAPITAL THAT WOULD BE NECESSARY TO DRILL A SUBSTANTIAL PORTION OF OUR POTENTIAL DRILLING LOCATIONS.

Our management has identified and scheduled drilling locations as an estimation of our future multi-year drilling activities on our existing acreage. These potential drilling locations, including those without proved undeveloped reserves, represent a significant part of our growth strategy. Our ability to drill and develop these locations is subject to a number of uncertainties, including the availability of capital, seasonal conditions, regulatory approvals, oil and natural gas prices, costs and drilling results. Because of these uncertainties, we do not know if the numerous potential drilling locations we have identified will ever be drilled or if we will be able to produce oil or natural gas from these or any other potential drilling locations. Pursuant to existing SEC rules and guidance, subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years of the date of booking. These rules and guidance may limit our potential to book additional proved undeveloped reserves as we pursue our drilling program.

CERTAIN ACREAGE MUST BE DRILLED BEFORE LEASE EXPIRATION, GENERALLY WITHIN ONE TO THREE YEARS, IN ORDER TO HOLD THE ACREAGE BY PRODUCTION. IN THE HIGHLY COMPETITIVE MARKET FOR ACREAGE, FAILURE TO DRILL SUFFICIENT WELLS IN ORDER TO HOLD ACREAGE WILL RESULT IN A SUBSTANTIAL LEASE RENEWAL COST, OR IF RENEWAL IS NOT FEASIBLE, LOSS OF OUR LEASE AND PROSPECTIVE DRILLING OPPORTUNITIES.

Unless production is established covering the undeveloped acres on which some of the locations are identified, the leases for such acreage will expire. As of December 31, 2012 we had leases representing approximately 5,300 net acres expiring in 2013 and 16,230 net acres expiring in 2014. The cost to renew such leases may increase significantly, and we may not be able to renew such leases on commercially reasonable terms or at all. As such, our actual drilling activities may materially differ from our current expectations, which could adversely affect our business. During the years ended December 31, 2012 and 2011, we recorded non-cash impairment charges of $2,268,528 and $1,027,552, respectively, for unproved property leases that expired during the period.

OUR DERIVATIVE ACTIVITIES COULD RESULT IN FINANCIAL LOSSES OR COULD REDUCE OUR INCOME.

To achieve more predictable cash flows and to reduce our exposure to adverse fluctuations in the prices of oil and natural gas, we currently, and may in the future, enter into derivative arrangements for a portion of our oil and natural gas production, including collars and fixed-price swaps. We have not designated any of our derivative instruments as hedges for accounting purposes and record all derivative instruments on our balance sheet at fair value. Changes in the fair value of our derivative instruments are recognized in earnings. Accordingly, our earnings may fluctuate significantly as a result of changes in the fair value of our derivative instruments.

Derivative arrangements also expose us to the risk of financial loss in some circumstances, including when:

production is less than the volume covered by the derivative instruments;

the counterparty to the derivative instrument defaults on its contract obligations; or

there is an increase in the differential between the underlying price in the derivative instrument and actual price received.

In addition, some of these types of derivative arrangements limit the benefit we would receive from increases in the prices for oil and natural gas and may expose us to cash margin requirements.

THE RECENT ADOPTION OF DERIVATIVES LEGISLATION BY THE UNITED STATES CONGRESS COULD HAVE AN ADVERSE EFFECT ON OUR ABILITY TO USE DERIVATIVE INSTRUMENTS TO REDUCE THE EFFECT OF COMMODITY PRICE, INTEREST RATE AND OTHER RISKS ASSOCIATED WITH OUR BUSINESS.

The United States Congress in 2010 adopted comprehensive financial reform legislation that establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. The legislation, known as the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Act”), was signed into law by the President on July 21, 2010, and requires the Commodity Futures Trading Commission (the “CFTC”), the SEC and other regulators to promulgate rules and regulations implementing the new legislation. In its rulemaking under the Act, the CFTC has issued final regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. Certain bona fide hedging transactions would be exempt from these position limits. The position limits rule was vacated by the United States District Court for the District of Columbia in September of 2012 although the CFTC has stated that it will appeal the District Court’s decision. The CFTC also has finalized other regulations, including critical rulemakings on the definition of “swap”, “security-based swap”, “swap dealer” and “major swap participant”. The Act and CFTC Rules also will require us in connection with certain derivatives activities to comply with clearing and trade-execution requirements (or take steps to qualify for an exemption to such requirements). In addition new regulations may require us to comply with margin requirements although these regulations are not finalized and their application to us is uncertain at this time. Other regulations also remain to be finalized, and the CFTC recently has delayed the compliance dates for various regulations already finalized. As a result it is not possible at this time to predict with certainty the full effects of the Act and CFTC rules on us and the timing of such effects. The Act may also require the counterparties to our derivative instruments to spin off some of their derivatives activities into a separate entity, which may not be as creditworthy as the current counterparty. The Act and any implementing regulations could significantly increase the cost of derivative contracts (including from swap recordkeeping and reporting requirements and through requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures or to make distributions. Finally, the legislation was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on us, our financial condition and our results of operations.

INCREASED COSTS OF CAPITAL COULD ADVERSELY AFFECT OUR BUSINESS.

Our business and operating results can be harmed by factors such as the availability, terms and cost of capital, increases in interest rates or a reduction in credit rating. Changes in any one or more of these factors could cause our cost of doing business to increase, limit our access to capital, limit our ability to pursue acquisition opportunities, reduce our cash flows available for drilling and place us at a competitive disadvantage. Recent and continuing disruptions and volatility in the global financial markets may lead to an increase in interest rates or a contraction in credit availability impacting our ability to finance our operations. We require continued access to capital. A significant reduction in the availability of credit could materially and adversely affect our ability to achieve our planned growth and operating results.

WE MAY BE SUBJECT TO RISKS IN CONNECTION WITH ACQUISITIONS AND THE INTEGRATION OF SIGNIFICANT ACQUISITIONS MAY BE DIFFICULT.

We periodically evaluate acquisitions of reserves, properties, prospects and leaseholds and other strategic transactions that appear to fit within our overall business strategy. The successful acquisition of producing properties requires an assessment of several factors, including:

recoverable reserves;

future oil and natural gas prices and their appropriate differentials;

development and operating costs; and

potential environmental and other liabilities.

The accuracy of these assessments is inherently uncertain. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and potential recoverable reserves. Inspections may not always be performed on every well, and environmental problems are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. We often are not entitled to contractual indemnification for environmental liabilities and acquire properties on an “as is” basis.

Significant acquisitions and other strategic transactions may involve other risks, including:

diversion of our management’s attention to evaluating, negotiating and integrating significant acquisitions and strategic transactions;

the challenge and cost of integrating acquired operations, information management and other technology systems and business cultures with those of ours while carrying on our ongoing business;

difficulty associated with coordinating geographically separate organizations; and

the challenge of attracting and retaining personnel associated with acquired operations.

The process of integrating operations could cause an interruption of, or loss of momentum in, the activities of our business. Members of our senior management may be required to devote considerable amounts of time to this integration process, which will decrease the time they will have to manage our business. If our senior management is not able to effectively manage the integration process, or if any significant business activities are interrupted as a result of the integration process, our business could suffer.

IF WE FAIL TO REALIZE THE ANTICIPATED BENEFITS OF A SIGNIFICANT ACQUISITION, OUR RESULTS OF OPERATIONS MAY BE LOWER THAN WE EXPECT.

The success of a significant acquisition will depend, in part, on our ability to realize anticipated growth opportunities from combining the acquired assets or operations with those of ours. Even if a combination is successful, it may not be possible to realize the full benefits we may expect in estimated proved reserves, production volume, cost savings from operating synergies or other benefits anticipated from an acquisition or realize these benefits within the expected time frame. Anticipated benefits of an acquisition may be offset by operating losses relating to changes in commodity prices, or in oil and natural gas industry conditions, or by risks and uncertainties relating to the exploratory prospects of the combined assets or operations, or an increase in operating or other costs or other difficulties. If we fail to realize the benefits we anticipate from an acquisition, our results of operations may be adversely affected.

THE COMPANY’S BUSINESS MAY SUFFER IF IT CANNOT OBTAIN OR MAINTAIN NECESSARY LICENSES.

Our operations require licenses, permits and in some cases renewals of licenses and permits from various governmental authorities. The Company’s ability to obtain, sustain or renew such licenses and permits on acceptable terms is subject to changes in regulations and policies and to the discretion of the applicable governments, among other factors. Our inability to obtain, or the loss of or denial of extension of, any of these licenses or permits could result in our inability to utilize certain of our leasehold properties or wells and would therefore diminish our ability to produce revenue.

CHALLENGES TO OUR LEASEHOLDS PROPERTIES MAY IMPACT THE COMPANY’S FINANCIAL CONDITION.

Title to oil and natural gas properties is often not capable of conclusive determination without incurring substantial expense. To mitigate title problems, common industry practice is to obtain a title opinion from a qualified oil and gas attorney prior to the drilling operations of a well. While the Company intends to make appropriate inquiries into the title of properties and other development rights and obtain a title opinion when we acquire leaseholds, title defects may exist. In addition, we may be unable to obtain adequate insurance for title defects, on a commercially reasonable basis or at all. If title defects do exist, it is possible that we may lose all or a portion of our right, title and interests in and to the leasehold properties to which the title defects relate. If our property rights are reduced, our ability to conduct our exploration, development and production activities may be impaired.

OUR OPERATIONS ARE SUBJECT TO VARIOUS GOVERNMENTAL REGULATIONS THAT REQUIRE COMPLIANCE THAT CAN BE BURDENSOME AND EXPENSIVE.

Our operations are subject to various federal, state and local governmental regulations that may be changed from time to time in response to economic and political conditions. Matters subject to regulation include discharges from drilling operations, drilling bonds, reports concerning operations, the spacing of wells, unitization and pooling of properties, and taxation. From time to time, regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of oil and natural gas wells below actual production capacity to conserve supplies of oil and natural gas. In addition, the production, handling, storage, transportation and disposal of oil and natural gas, by-products 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 primarily relating to protection of human health and the environment. These laws and regulations have continually imposed increasingly strict requirements for water and air pollution control and solid waste management, and compliance with these laws may cause delays in the additional drilling and development of our properties. Significant expenditures may be required to comply with governmental laws and regulations applicable to us. We believe the trend of more expansive and more strict environmental legislation and regulations will continue. While historically we have not experienced any material adverse effect from regulatory delays, there can be no assurance that such delays will not occur in the future.

ENVIRONMENTAL RISKS MAY ADVERSELY AFFECT THE COMPANY’S BUSINESS.

All phases of the oil and gas business present environmental risks and hazards and are subject to environmental regulation pursuant to a variety of federal, state, tribal and local laws and regulations. Environmental legislation provides for, among other things, restrictions and prohibitions on spills, releases and emissions of various substances produced in association with oil and gas operations. Laws also require that wells and facility sites be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. Compliance with such legislation can require significant expenditures, and a breach may result in the imposition of fines and penalties, some of which may be material. Environmental legislation and regulations are evolving in a manner that we expect may result in stricter standards and enforcement, larger fines and liability, and potentially increased capital expenditures and operating costs. The discharge of oil, natural gas or other pollutants into the air, soil or water may give rise to liabilities to governments and third parties and may require the Company to incur costs to remedy such discharges. The application of environmental laws to our business may cause us to curtail our production or increase the costs of our production, development or exploration activities.

UNUSUAL WEATHER PATTERNS OR NATURAL DISASTERS, WHETHER DUE TO CLIMATE CHANGE OR OTHERWISE, COULD NEGATIVELY IMPACT OUR FINANCIAL CONDITION.

Our business depends, in part, on normal weather patterns across the United States. Natural gas demand and prices are particularly susceptible to seasonal weather trends. Warmer than usual winters can result in reduced demand and high season-end storage volumes, which can depress prices. In addition, at least some of our operations are constantly at risk of extreme adverse weather conditions such as hurricanes and tornadoes. Any unusual or prolonged adverse weather patterns in our areas of operations or markets, whether due to climate change or otherwise, could have a material and adverse impact on our business, financial condition and cash flow. In addition, our business, financial condition and cash flow could be adversely affected if the businesses of our key vendors, purchasers, contractors, suppliers or transportation service providers were disrupted due to severe weather, such as hurricanes or floods, whether due to climate change or otherwise.

Increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods and other climatic events. If any such effects were to occur, they could have a material adverse effect on our financial condition and results of operations. Changes in climate due to global warming trends could adversely affect our operations by limiting or increasing the costs associated with equipment or product supplies. In addition, flooding and adverse weather conditions such as increased frequency and/or severity of hurricanes could impair our ability to operate in affected regions of the country. Repercussions of severe weather conditions may include: curtailment of services; weather-related damage to facilities and equipment, resulting in suspension of operations; inability to deliver equipment, personnel and products to job sites in accordance with contract schedules; and loss of productivity. These constraints could delay our operations and materially increase our operating and capital costs. Unusually warm winters may decrease the demand for our oil or natural gas.

GOVERNMENT REGULATIONS AND LEGAL UNCERTAINTIES COULD ADVERSELY AFFECT THE DEVELOPMENT AND EXPLORATION OF OIL, GAS, AND OTHER NATURAL RESOURCES, THEREBY HINDERING OUR ABILITY TO PRODUCE REVENUE.

A number of potential legislative and regulatory proposals under consideration by federal, state, tribal, local and foreign governmental organizations may lead to laws or regulations concerning various aspects of oil, natural gas and other natural resources including within the primary geographic areas in which we hold properties. The adoption of new laws or the application of existing laws may decrease the growth in the demand or increase the cost of exploring for and developing natural resources, which could in turn decrease the usage and demand for our production or increase our cost of doing business.

The overall trend in federal and state environmental legislation and regulation generally is toward stricter standards. These laws and regulations including the CERCLA, RCRA, CWA, CAA and ESA may require the acquisition of permits or other authorizations before construction or drilling commences and for certain other activities; limit or prohibit construction, drilling and other activities on certain lands lying within wilderness and other protected areas; and impose substantial liabilities for pollution resulting from operations. If operations of our properties are found to be in violation of any of the laws and regulations to which we are subject, we may be subject to compliance orders and applicable penalties associated with the violation, including civil and criminal penalties, damages, fines and the curtailment of operations. Any penalties, damages, fines or curtailment of operations, individually or in the aggregate, could adversely affect our ability to operate our business and our financial results. In addition, many of these laws and regulations have not been fully interpreted by the regulatory authorities or the courts, and their provisions are open to a variety of interpretations. Any action against us for violation of these laws or regulations, even if we successfully defend against it, could cause us to incur significant legal expenses and divert management’s attention from the operation of our business.

Additionally, hydraulic fracturing, the process of creating or expanding cracks, or fractures, in formations underground whereby water, sand and other additives are pumped under high pressure into resource-bearing rock, is currently used in completing greater than 90% of all oil and natural gas wells drilled in the United States. While hydraulic fracturing is typically regulated by state agencies, EPA has federal regulatory authority over hydraulic fracturing involving diesel fuels under the SDWA’s Underground Injection Control Program. Also, legislation has been introduced in Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process. Moreover, numerous states and some localities have lately adopted extensive “fracking” regulations beyond mere fluid disclosure, often adding many layers of permits, notice, and other steps and protections to the process of drilling and operating new production wells. We cannot predict what additional hydraulic fracturing federal, state or local laws or regulations will be enacted and, if so, what actions any such laws or regulations would require or prohibit. As additional levels of regulation or permitting requirements continue to be imposed through the adoption of new laws and regulations, our operations with respect to our leasehold properties could be subject to delays, increased operating and compliance costs and process prohibitions. Restrictions on hydraulic fracturing could also reduce the amount of oil, natural gas liquids and natural gas that we are ultimately able to produce in commercial quantities from our leasehold properties.

FEDERAL AND STATE LEGISLATION AND REGULATORY INITIATIVES RELATING TO HYDRAULIC FRACTURING COULD RESULT IN INCREASED COSTS AND ADDITIONAL OPERATING RESTRICTIONS OR DELAYS IN THE COMPLETION OF OIL AND NATURAL GAS WELLS.

Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations. Legislation was proposed in the last Congress to amend the federal Safe Drinking Water Act to require the disclosure of chemicals used by the oil and natural gas industry in the hydraulic fracturing process. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into rock formations to stimulate oil and natural gas production. We expect that third parties will be engaged to provide hydraulic fracturing or other well stimulation services in connection with many of the wells for the operators. If similar legislation is ultimately adopted, it could establish an additional level of regulation at the federal or state level that could lead to operational delays or increased operating costs and could result in additional regulatory burdens that could make it more difficult to perform hydraulic fracturing and increase our costs of compliance and doing business.

In addition to possible future regulatory changes at the federal level, several states (including Arkansas, Colorado, Louisiana, North Dakota, Texas and Wyoming) , have implemented legislation or regulations mandating the disclosure of chemical additives used in hydraulic fracturing. At this time, it is not possible to estimate the potential impact on our business of additional federal, state, or local regulatory actions affecting hydraulic fracturing. Some local municipalities have adopted or are considering adopting land use restrictions, such as city ordinances, that may restrict or prohibit the performance of well drilling in general and/or hydraulic fracturing in particular. In addition, a number of states in which we plan to conduct hydraulic fracturing operations are currently conducting, or may in the future conduct, regulatory reviews that potentially could restrict or limit our access to shale formations located in their states. In most states, our third party operators 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. The requirements for such permits vary depending on the location where such drilling and completion activities will be conducted. 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. Recently, moratoriums on the issuance of permits have been imposed upon inland drilling and completion activities. For example, 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. Wyoming and Colorado have enacted additional regulations applicable to our business activities and Arkansas is presently considering similar regulations. Some of the drilling and completion activities may take place on federal land, requiring leases from the federal government to conduct such drilling and completion activities. The Bureau of Land Management (BLM) has announced its intention to publish in 2013 proposed rules that would impose new requirements for hydraulic fracturing operations conducted on federal lands.

In March 2010, the United States Environmental Protection Agency announced that it would conduct a wide-ranging study on the effects of hydraulic fracturing on drinking water resources. A progress report of the study was released in December of 2012, with final results expected in 2014. The agency also announced that one of its enforcement initiatives for 2011 to 2013 would be to focus on environmental compliance by the energy extraction sector. This study and enforcement initiative could result in additional regulatory scrutiny that could make it difficult to perform hydraulic fracturing and increase our costs of compliance and doing business.

CERTAIN UNITED STATES FEDERAL INCOME TAX DEDUCTIONS CURRENTLY AVAILABLE WITH RESPECT TO OIL AND NATURAL GAS EXPLORATION AND DEVELOPMENT MAY BE ELIMINATED AS A RESULT OF PROPOSED LEGISLATION, AND THEREFORE SLOW THE DEMAND FOR INVESTMENT IN THE COMPANY’S INDUSTRY.

Both the Obama Administration’s budget proposal for fiscal year 2013 and other recently proposed legislation would, if enacted, make significant changes to United States tax laws, including the elimination of certain key U.S. 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 current deductions for intangible drilling and development costs (“IDCs”), (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 U.S. federal income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to oil and natural gas exploration and development, and any such change could increase the taxable income allocable to our shareholders and negatively impact the value of an investment in the Company.

POSSIBLE REGULATION RELATED TO GLOBAL WARMING AND CLIMATE CHANGE COULD HAVE AN ADVERSE EFFECT ON OUR OPERATIONS AND DEMAND FOR OIL AND NATURAL GAS.

In addition to other climate-related risks set forth in this “Risk Factors” section, we are and will be, directly and indirectly, subject to the effects of climate change and may be, directly or indirectly, affected by government laws and regulations related to climate change. We cannot predict with any degree of certainty what effect, if any, possible climate change and new and developing government laws and regulations related to climate change will have on our operations, whether directly or indirectly. While we believe that it is difficult to assess the timing and effect of climate change and pending legislation and regulation related to climate change on our business, we believe that climate change and government laws and regulations related to climate change may affect, directly or indirectly, (i) the cost of the equipment and services we purchase, (ii) our ability to continue to operate as we have in the past, including drilling, completion and operating methods, (iii) the timeliness of delivery of the materials and services we need and the cost of transportation paid by us and our vendors and other providers of services, (iv) insurance premiums, deductibles and the availability of coverage, and (v) the cost of utility services, particularly electricity, in connection with the operation of our properties. In addition, climate change may increase the likelihood of property damage and the disruption of our operations, especially in coastal states. As a result, our financial condition could be negatively impacted by significant climate change and related governmental regulation, and that impact could be material.

REGULATION AND RECENT COURT DECISIONS RELATED TO GREENHOUSE GAS EMISSIONS COULD HAVE AN ADVERSE EFFECT ON OUR OPERATIONS AND DEMAND FOR OIL AND NATURAL GAS.

Studies over recent years have indicated that emissions of certain gases may be contributing to warming of the Earth’s atmosphere. In response to these studies, governments have begun adopting domestic and international climate change regulations that require reporting and reductions of the emission of greenhouse gases. Methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of oil, natural gas and refined petroleum products, are considered greenhouse gases. Internationally, the United Nations Framework Convention on Climate Change, and the Kyoto Protocol, address greenhouse gas emission, and multiple nations, including the European Union have established greenhouse gas regulatory systems. In the United States, at the state level, many states either individually or through multi-state regional initiatives have begun implementing legal measures to reduce emissions of greenhouse gases, primarily through the planned development of emission inventories or regional greenhouse gas cap and trade programs, or have begun considering adopting greenhouse gas regulatory programs.

EPA issued greenhouse gas monitoring and reporting regulations that began to require reporting by certain regulated facilities in 2012 and annually thereafter. EPA has adopted rules requiring companies to report certain greenhouse gas emissions from oil and natural gas facilities. Our oil and natural gas operations are subject to such greenhouse gas reporting requirements, and we will monitor our emissions to make such required reports. While we believe that we will be able to substantially comply with such reporting requirements without any material adverse effect to our financial condition, since such reporting requirements with respect to greenhouse gas emissions are still relatively new in the oil and gas industry, there can be no assurance that our reports will initially be in substantial compliance or that such requirements will not develop into more stringent and costly obligations that may have a significant impact on our operating costs. Beyond measuring and reporting, EPA issued an “Endangerment Finding” under section 202(a) of the CAA, concluding that greenhouse gas pollution threatens the public health and welfare of current and future generations. The finding served as a first step to issuing regulations that require permits for and reductions in greenhouse gas emissions for certain facilities. EPA has recently moved ahead on greenhouse gas regulations as well as requiring delegated states to address this issue for certain CAA permits and facilities.

In the courts, several decisions have been issued that may increase the risk of claims being filed by governments and private parties against companies that have significant greenhouse gas emissions. Such cases may seek to challenge air emissions permits that greenhouse gas emitters apply for and seek to force emitters to reduce their emissions or seek damages for alleged climate change impacts to the environment, people, and property.

Any laws or regulations that may be adopted, or significant adverse judicial holdings reached, restricting or requiring regulated parties to reduce emissions of greenhouse gases could require us to incur increased operating and compliance costs, and could have an adverse effect on the ability to develop certain natural resources and on demand for the oil and natural gas that we produce.

RISKS RELATED TO OUR INDEBTEDNESS

WE MAY NOT BE ABLE TO GENERATE ENOUGH CASH FLOW TO MEET OUR DEBT OBLIGATIONS.

We expect our earnings and cash flow to vary significantly from year to year due to the nature of our industry. As a result, the amount of debt that we can manage in some periods may not be appropriate for us in other periods. Additionally, our future cash flow may be insufficient to meet our debt obligations and other commitments. Any insufficiency could negatively impact our business. A range of economic, competitive, business and industry factors will affect our future financial performance, and, as a result, our ability to generate cash flow from operations and to pay our debt obligations. Many of these factors, such as oil and natural gas prices, economic and financial conditions in our industry and the global economy and initiatives of our competitors, are beyond our control. If we do not generate enough cash flow from operations to satisfy our debt obligations, we may have to undertake alternative financing plans, such as:

selling assets;

reducing or delaying capital investments;

seeking to raise additional capital; or

refinancing or restructuring our debt.

If for any reason we are unable to meet our debt service and repayment obligations, we would be in default under the terms of the agreements governing our debt, which would allow our creditors at that time to declare all outstanding indebtedness to be due and payable. In addition, our lenders could compel us to apply all of our available cash to repay our borrowings or they could prevent us from making payments on our senior unsecured notes. If amounts outstanding under our revolving credit facility or our senior unsecured notes were to be accelerated, we cannot be certain that our assets would be sufficient to repay in full the money owed to the lenders or to our other debt holders.

OUR REVOLVING CREDIT FACILITY CONTAINS OPERATING AND FINANCIAL RESTRICTIONS THAT MAY RESTRICT OUR BUSINESS AND FINANCING ACTIVITIES.

Our revolving credit facility contains a number of restrictive covenants that will impose significant operating and financial restrictions on us, including restrictions on our ability to, among other things:

incur certain indebtedness;

guaranty indebtedness of another person or entity;

merge with or into another person or entity;

make certain acquisitions or investments;

create or incur certain liens;

make investments;

create any subsidiaries;

enter into a joint venture;

declare dividends or distributions or redeem any of our common stock; or

engage in certain business activities.

As a result of these covenants, we are limited in the manner in which we conduct our business, and we may be unable to engage in favorable business activities or finance future operations or capital needs.

Our ability to comply with some of the covenants and restrictions contained in our revolving credit facility may be affected by events beyond our control. If market or other economic conditions deteriorate, our ability to comply with these covenants may be impaired. A failure to comply with the covenants, ratios or tests in our revolving credit facility or any future indebtedness could result in an event of default under our revolving credit facility or our future indebtedness, which, if not cured or waived, could have a material adverse effect on our business, financial condition and results of operations.

As an event of default under our revolving credit facility has occurred and remains uncured due to our failure to make an interest payment on July 1, 2013, the lenders thereunder could elect to declare all borrowings outstanding, together with accrued and unpaid interest and fees, to be due and payable. As of the date hereof, we have not received such notice of default from Macquarie.

OUR LEVEL OF INDEBTEDNESS MAY INCREASE AND REDUCE OUR FINANCIAL FLEXIBILITY. A SUBSTANTIAL PORTION OF OUR ASSETS SECURE OUR INDEBTEDNESS.

As of December 31, 2012, we had $13.1 million outstanding under our revolving credit facility, $2,841,352 outstanding under our term loan facility and $0 available for future secured borrowings under our revolving credit facility. As of December 31, 2012, we also had a $25 million secured convertible promissory note issued to Pentwater of which approximately $22 million is outstanding. The promissory note with a principal amount of $35 million issued to Geronimo was converted into shares of Series A Preferred Stock on June 30, 2012, which accrue cumulative dividends semi-annually at a rate of 7.5% per annum. In the future, we may incur significant indebtedness in order to make future acquisitions or to develop our properties.

Our level of indebtedness could affect our operations in several ways, including the following:

a significant portion of our cash flows could be used to service our indebtedness;

a high level of debt would increase our vulnerability to general adverse economic and industry conditions;

the covenants contained in the agreements governing our outstanding indebtedness limit our ability to borrow additional funds, dispose of assets, pay dividends and make certain investments;

our debt covenants may also affect our flexibility in planning for, and reacting to, changes in the economy and in our industry;

a high level of debt may place us at a competitive disadvantage compared to our competitors that are less leveraged and therefore, may be able to take advantage of opportunities that our indebtedness would prevent us from pursuing;

a high level of debt may make it more likely that a reduction in our borrowing base following a periodic redetermination could require us to repay a portion of our then-outstanding bank borrowings; and

a high level of debt may impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general corporate or other purposes.

A high level of indebtedness increases the risk that we may default on our debt obligations. A debt default could significantly diminish the market value and marketability of our common stock and could result in the acceleration of the payment obligations under all or a portion of our consolidated indebtedness.

Nevada ASEC, as borrower, failed to comply with the current ratio covenant and incurred general and administrative expenses in excess of the limit contained in the Credit Agreement, in each case for the calendar quarter ended September 30, 2012. The covenant violations were waived by Macquarie on November 13, 2012. For the quarter ended December 31, 2012, Nevada ASEC was in default under the Credit Agreement for (i) failing to deliver the required reserve report, (ii) failing to deliver the annual financial statements within 120 days of the end of the fiscal year, (iii) failing to comply with the current ratio covenant, (iv) failing to comply with the interest coverage ratio covenant, (v) having accounts payable, accrued expenses and obligations that are more than 90 days past due and exceed $250,000, and (vi) allowing G&A expenses to exceed $700,000. The defaults were waived by Macquarie on May 15, 2013. For the quarter ended March 31, 2013, Nevada ASEC was in default under the Credit Agreement for (i) failing to comply with the current ratio covenant, (ii) failing to comply with the interest coverage ratio covenant and (iii) allowing G&A expenses to exceed $700,000. The defaults were waived by Macquarie on May 15, 2013.

Simultaneously with the receipt of the waivers received from Macquarie, the Credit Agreement was amended to (i) reduce the borrowing base available under the "Revolving Loan" from $12 million to $0, (ii) provide that the amount available to be drawn under the "Revolving Loan" is $0, (iii) provide that the amount available to be drawn under the "Term Loan" is $0, (iv) accelerate the repayment of the "Revolving Loan" by changing the maturity date with respect to such repayment from September 21, 2015 to May 17, 2013, (v) modify the amortization of the outstanding principal amount with respect to the repayment of the "Term Loan" by providing that such amortization shall begin on the last business day of May 2013 instead of March 21, 2013, and such repayment shall be made pursuant to Schedule 1.9(b) attached thereto, and (vi) provide provisions for the payment of joint interest billings in relation to the "Double Down 24-13 #1H Well" that supersedes the terms and conditions of that certain letter agreement, dated as of February 15, 2013, by and among Nevada ASEC, lender and administrative agent.

Additionally, as a result of certain reporting covenant defaults under the Purchase Agreement, the Company and ASEN 2 entered into the Second Amendment and Asset Purchase Agreement, each as defined herein.

On June 30, 2013, Pentwater agreed to defer the July 1, 2013 and the August 1, 2013 interest payments due and owing by ASEN 2 pursuant to that certain Amended and Restated Secured Convertible Promissory Note issued by Pentwater.

Our ability to meet our debt obligations and to reduce our level of indebtedness depends on our future performance. General economic conditions, oil and natural gas prices and financial, business and other factors affect our operations and our future performance. Many of these factors are beyond our control. We may not be able to generate sufficient cash flows to pay the interest on our debt and future working capital, and borrowings or equity financing may not be available to pay or refinance such debt. Factors that will affect our ability to raise cash through an offering of our capital stock or a refinancing of our debt include financial market conditions, the value of our assets and our performance at the time we need capital.

In addition, our bank borrowing base is subject to periodic redeterminations. We could be forced to repay a portion of our bank borrowings due to redeterminations of our borrowing base. If we are forced to do so, we may not have sufficient funds to make such repayments. If we do not have sufficient funds and are otherwise unable to negotiate renewals of our borrowings or arrange new financing, we may have to sell significant assets. Any such sale could have a material adverse effect on our business and financial results.

We have pledged substantially all of our assets to secure our obligations under our various credit agreements and notes. In the event that we were to fail in the future to make any required payment under agreements governing our indebtedness or fail to comply with the financial and operating covenants contained in those agreements, we would be in default regarding that indebtedness. A debt default would enable the lenders to foreclose on the assets securing such debt and could significantly diminish the market value and marketability of our common stock and could result in the acceleration of the payment obligations under all or a portion of our consolidated indebtedness.

WE HAVE EXPERIENCED RAPID GROWTH SINCE OUR INCEPTION. IF WE FAIL TO MANAGE THIS OR ANY FUTURE GROWTH, OUR BUSINESS AND OPERATING RESULTS COULD BE HARMED.

Our business has grown dramatically since our inception. For example, our revenue increased from $9,798,365 for 2011 to $19,738,523 for 2012, excluding discontinued operations. Our growth has largely resulted from our acquisition of new leasehold interests. Since January 1, 2011, we have acquired leasehold interests in approximately 90,000 acres. Additionally, we continue to evaluate and pursue appropriate acquisition opportunities to the extent we believe that such opportunities would be in the best interests of our company and our stockholders.

This significant growth has placed considerable demands on our management and other resources and continued growth could place additional demands on such resources. Our ability to compete effectively and to manage future growth, if any, will depend on the sufficiency and adequacy of our current resources and infrastructure and our ability to continue to identify, attract and retain competent personnel. There can be no assurance that our personnel, systems, procedures and controls will be adequate to support our operations and properly oversee our assets. The failure to support our operations effectively and properly oversee our assets could cause harm to our assets and have a material adverse effect on their fair values and our business, financial condition and results of operations.

Also, there can be no assurance that we will be able to sustain our recent growth. Our growth may be limited by a number of factors including increased competition for leasehold interests in oil and gas producing regions, insufficient capitalization for future acquisitions and the lack of attractive acquisition targets. In addition as we continue to grow larger, we will likely need to make additional and larger acquisitions to continue to grow at our current pace.

WE COULD BE EXPOSED TO UNKNOWN PRE-EXISTING LIABILITIES OF THE ASSETS PURCHASED, WHICH COULD CAUSE US TO INCUR SUBSTANTIAL FINANCIAL OBLIGATIONS AND HARM OUR BUSINESS.

In connection with the acquisition, we may have assumed liabilities of XOG and Geronimo of which we are not aware and may have little or no recourse against XOG and Geronimo with respect thereto. If we were to discover that there were intentional misrepresentations made to us by XOG and Geronimo, or their representatives as to these or other matters, we would explore all possible legal remedies to compensate us for any loss, including our rights to indemnification under the purchase and sale agreement that we entered into with XOG and Geronimo upon the closing of the acquisition. However, there is no assurance that in such case legal remedies would be available or collectible. If such unknown liabilities exist and we are not fully indemnified for any loss that we incur as a result thereof, we could incur substantial financial obligations, which could negatively impact our financial condition and harm our business.

RISKS RELATED TO THE COMPANY’S SECURITIES

THE COMPANY’S COMMON STOCK IS QUOTED ON THE OTC BULLETIN BOARD WHICH MAY HAVE AN UNFAVORABLE IMPACT ON OUR STOCK PRICE AND LIQUIDITY.

Our common stock is quoted on the OTCBB, which is a significantly more limited trading market than the New York Stock Exchange or The NASDAQ Stock Market. The quotation of the Company’s shares on the OTCBB may result in a less liquid market available for existing and potential stockholders to trade shares of our common stock, could depress the trading price of our common stock and could have a long-term adverse impact on our ability to raise capital in the future.

When fewer shares of a security are being traded on the OTCBB, volatility of prices may increase and price movement may outpace the ability to deliver accurate quote information. Due to lower trading volumes in shares of our common stock, there may be a lower likelihood of one’s orders for shares of our common stock being executed, and current prices may differ significantly from the price one was quoted at the time of one’s order entry.

THE COMPANY’S COMMON STOCK IS THINLY TRADED, SO YOU MAY BE UNABLE TO SELL AT OR NEAR ASKING PRICES OR AT ALL IF YOU NEED TO SELL YOUR SHARES TO RAISE MONEY OR OTHERWISE DESIRE TO LIQUIDATE YOUR SHARES.

Currently, the Company’s common stock is quoted in the OTCBB and the trading volume is limited by the fact that many major institutional investment funds, including mutual funds, as well as individual investors follow a policy of not investing in OTCBB stocks and certain major brokerage firms restrict their brokers from recommending OTCBB stocks because they are considered speculative, volatile and thinly traded. The OTCBB market is an inter-dealer market much less regulated than the major exchanges and our common stock is subject to abuses, volatility and shorting. Thus, there is currently no broadly followed and established trading market for the Company’s common stock. An established trading market may never develop or be maintained. Active trading markets generally result in lower price volatility and more efficient execution of buy and sell orders. Absence of an active trading market reduces the liquidity of the shares traded there.

The trading volume of our common stock has been and may continue to be limited and sporadic. As a result of such trading activity, the quoted price for the Company’s common stock on the OTCBB may not necessarily be a reliable indicator of its fair market value. Further, if we cease to be quoted, holders would find it more difficult to dispose of our common stock or to obtain accurate quotations as to the market value of the Company’s common stock and as a result, the market value of our common stock likely would decline.

THE COMPANY’S COMMON STOCK IS SUBJECT TO PRICE VOLATILITY UNRELATED TO ITS OPERATIONS.

The market price of the Company’s common stock could fluctuate substantially due to a variety of factors, including market perception of our ability to achieve our planned growth, quarterly operating results of other companies in the same industry, trading volume in our common stock, changes in general conditions in the economy and the financial markets or other developments affecting the Company’s competitors or the Company itself. In addition, the stock market is subject to extreme price and volume fluctuations. This volatility has had a significant effect on the market price of securities issued by many companies for reasons unrelated to their operating performance and could have the same effect on our common stock.

OUR BOARD OF DIRECTORS’ ABILITY TO ISSUE UNDESIGNATED PREFERRED STOCK AND THE EXISTENCE OF ANTI-TAKEOVER PROVISIONS MAY DEPRESS THE VALUE OF OUR COMMON STOCK.

Our authorized capital includes one million shares of undesignated preferred stock. Our board of directors has the power to issue any or all of the shares of preferred stock, including the authority to establish one or more series and to fix the powers, preferences, rights and limitations of such class or series, without seeking stockholder approval. Further, as a Delaware corporation, we are subject to provisions of the Delaware General Corporation Law regarding “business combinations.” Our board may, in the future, consider adopting additional anti-takeover measures. The authority of our board of directors to issue undesignated stock and the anti-takeover provisions of Delaware law, as well as any future anti-takeover measures adopted by us, may, in certain circumstances, delay, deter or prevent takeover attempts and other changes in control of us that are not approved by our board. As a result, our stockholders may lose opportunities to dispose of their shares at favorable prices generally available in takeover attempts or that may be available under a merger proposal and the market price, voting and other rights of the holders of common stock may also be affected.

WE DO NOT EXPECT TO PAY DIVIDENDS IN THE FORESEEABLE FUTURE.

We do not intend to declare dividends on our common stock for the foreseeable future, as we anticipate that we will reinvest any future earnings in the development and growth of our business. Therefore, our stockholders will not receive any funds unless they sell their common stock, and stockholders may be unable to sell their shares on favorable terms or at all.

WE ARE SUBJECT TO THE PENNY STOCK RULES ADOPTED BY THE SECURITIES AND EXCHANGE COMMISSION (“SEC”) THAT REQUIRE BROKERS TO PROVIDE EXTENSIVE DISCLOSURE TO ITS CUSTOMERS PRIOR TO EXECUTING TRADES IN PENNY STOCKS. THESE DISCLOSURE REQUIREMENTS MAY CAUSE A REDUCTION IN THE TRADING ACTIVITY OF OUR COMMON STOCK, WHICH IN ALL LIKELIHOOD WOULD MAKE IT DIFFICULT FOR OUR STOCKHOLDERS TO SELL THEIR SECURITIES.

Our common stock is defined as “penny stock” under the Exchange Act and its rules. The SEC has adopted regulations that define “penny stock” to include common stock that has a market price of less than $5.00 per share, subject to certain exceptions. These rules include the following requirements:

broker-dealers must deliver, prior to the transaction, a disclosure schedule prepared by the SEC relating to the penny stock market;

broker-dealers must disclose the commissions payable to the broker-dealer and its registered representative;

broker-dealers must disclose current quotations for the securities; and

a broker-dealer must furnish its customers with monthly statements disclosing recent price information for all penny stocks held in the customer’s account and information on the limited market in penny stocks.

Additional sales practice requirements are imposed on broker-dealers who sell penny stocks to persons other than established customers and accredited investors. For these types of transactions, the broker-dealer must make a special suitability determination for the purchaser and must have received the purchaser’s written consent to the transaction prior to sale. If our common stock remains subject to these penny stock rules these disclosure requirements may have the effect of reducing the level of trading activity in the secondary market for our common stock. As a result, fewer broker-dealers may be willing to make a market in our stock, which could affect a shareholder’s ability to sell their shares.

FUTURE SALES OF COMMON STOCK IN THE PUBLIC MARKET OR THE ISSUANCE OF COMMON STOCK OR THE EXERCISE OF OUR CONVERTIBLE SECURITIES WOULD CAUSE DILUTION TO OUR EXISTING STOCKHOLDERS AND COULD ADVERSELY AFFECT THE TRADING PRICE OF OUR COMMON STOCK.

Our Certificate of Incorporation currently authorizes our board of directors to issue shares of common stock in excess of the common stock outstanding. Any additional issuances of any of our authorized but unissued shares will not require the approval of stockholders and may have the effect of further diluting the equity interest of stockholders. We may issue common stock in the future for a number of reasons, including to attract and retain key personnel, as purchase price for possible acquisitions, to lenders, investment banks, or investors in order to achieve more favorable terms from these parties and align their interests with our common equity holders, to management and/or employees to reward performance, to finance our operations and growth strategy, to adjust our ratio of debt to equity, to satisfy outstanding obligations or for other reasons. As of December 31, 2012, we had warrants to purchase 14,593,640 shares of our common stock and options to purchase 7,219,608 shares of our common stock outstanding. If we issue securities or if any of the convertible securities currently outstanding are exercised, our existing stockholders may experience dilution. Future sales of the common stock, the perception that such sales could occur or the availability for future sale of shares of the common stock or securities convertible into or exercisable for our common stock could adversely affect the market prices of our common stock prevailing from time to time. The sale of shares issued upon the exercise of our derivative securities could also further dilute the holdings of our then existing stockholders. In addition, future public sales of shares of the common stock could impair our ability to raise capital by offering equity securities.

Item 1B. UNRESOLVED STAFF COMMENTS.

Not applicable.

Item 2. PROPERTIES

Office Locations

The Company leases its 4,092 square foot primary office facilities in Scottsdale, Arizona under a non-cancellable operating lease agreement, dated September 30, 2010, for a 66-month term. The lease provides for no lease payments during the first six months and a reduced square footage charge for the first year. The initial rental is $23.00 per square foot, beginning February 1, 2011, and increasing $.50 per square foot annually thereafter.

Leasehold Holdings

As of August 1, 2013 we held working interests in approximately 96,300 net acres in the Permian Basin, Bakken, Eagle Ford, Niobrara, and Gulf Coast regions. A summary of the total gross and net oil and gas productive wells and the total gross and net developed acreage by geographic area is set forth under “Oil and Gas Properties Wells, Operation and Acreage”. Our working interests in these regions grant us the right, as the lessee of the property, to explore for, develop and produce oil, natural gas and other minerals, while also bearing any related exploration, development, and operating costs.

As of August 1, 2013:

Reserves

Below is a summary of oil and gas reserves as of the fiscal-year ended December 31, 2012 based on average fiscal-year prices.

	Reserves
Reserves category	Oil (mbbls)		Natural gas (mmcf)		Synthetic oil (mbbls)		Synthetic gas (mmcf)
PROVED
Developed:
North America		1,130.6		4,028.9		0		0
U.S.A		1,130.6		4,028.9		0		0

Undeveloped:
North America		465.6		312.9		0		0
U.S.A		465.6		312.9		0		0

TOTAL PROVED		1,596.2		4,341.8		0		0

As of December 31, 2012, our proved oil and natural gas reserves are all located in the United States, primarily in the Permian Basin of West Texas, the Eagle Ford shale formation of South Texas and the Williston Basin of North Dakota. The reservoir engineering reports used herein are calculated as of December 31, 2012. The estimates of proved reserves at December 31, 2012 are based on reports prepared by DeGolyer and MacNaughton, (the “D&M Engineering Report”) and an additional report for our Bakken Shale prepared by Cawley Gillespie & Associates (the “CG&A Engineering Report”) which are included herein as Exhibits 99.6 and 99.7, respectively.

Proved reserves and future net revenue to the evaluated interests were based on economic parameters and operating conditions considered applicable as of December 31, 2012 and are pursuant to the financial reporting standards of the Securities and Exchange Commission (“SEC”) and prepared in accordance with the SPE 2007 Standards promulgated by the Society of Petroleum Engineers. The reserves projections in this evaluation are based on the use of the available data and accepted industry-engineering methods.

The following table provides a roll-forward of the total proved reserves for the years ended December 31, 2012 and 2011, as well as disclosures of proved developed and proved undeveloped reserves at December 31, 2012 and 2011. Barrels of oil equivalent (“BOE”) are determined using a ratio of 6 Mcf of natural gas to 1 Bbl of crude oil.

				Natural
	Oil			Gas			Total
	(Bbls)			(Mcf)			(Boe)
Total Proved Reserves:
Balance, January 1, 2012		2,174,130			7,505,884			3,425,111
Revisions		(723,111	)		(1,283,692	)		(937,061	)
Discoveries		745,713			552,538			837,803
Purchases of reserves		214,509			262,160			258,202
Sales of mineral interest		(601,354	)		(2,134,101	)		(957,037	)
Production		(213,711	)		(560,947	)		(307,202	)

Balance, December 31, 2012		1,596,176			4,341,842			2,319,816

Proved developed reserves		1,130,625			4,028,905			1,802,109
Proved undeveloped reserves		465,551			312,937			517,707

Total proven reserves		1,596,176			4,341,842			2,319,816

Total Proved Reserves:
Balance, January 1, 2011		2,290,830			14,511,630			4,709,436
Revisions		(1,431,842	)		(8,333,406	)		(2,820,743	)
Discoveries		1,414,818			1,872,750			1,726,943
Purchases of reserves		4,471			2,190			4,836
Production		(104,147	)		(547,280	)		(195,361	)

Balance, December 31, 2011		2,174,130			7,505,884			3,425,111

Proved developed reserves		1,368,461			6,334,000			2,424,128
Proved undeveloped reserves		805,669			1,171,884			1,000,983

Total proven reserves		2,174,130			7,505,884			3,425,111

Total proved reserves as of December 31, 2011 were 3,425,111 BOE including 1,000,983 BOE in proved undeveloped reserves. Total proved reserves as of December 31, 2012 were 2,319,816 BOE with 517,707 BOE in proved undeveloped reserves.

Qualifications of Technical Persons and Internal Controls Over Reserves Estimation Process

Our policies regarding internal controls over the recording of reserves estimates requires reserves to comply with the SEC definitions and guidance and be prepared in accordance the SPE 2007 Standards promulgated by the Society of Petroleum Engineers. Our procedures require that our reserve report be prepared by a third-party registered independent engineering firm at the end of every year based on information we provide to such engineer. We accumulate historical production data for our wells, calculate historical lease operating expenses and differentials, update working interests and net revenue interests, obtain updated authorizations for expenditure (“AFEs”) and obtain geological and geophysical information from operators. This data is forwarded to our third-party engineering firm for review and calculation. Our Chief Executive Officer and Chief Financial Officer provide a final review of our reserve report and the assumptions relied upon in such report.

We retained DeGolyer and MacNaughton of Houston, Texas as our third-party engineering firm to prepare our reserve estimates going forward. Cawley, Gillespie and Associates of Houston, Texas was also retained to provide third-party engineering for our Bakken Shale assets.

DeGolyer and MacNaughton of Houston, TX, was our third party reserve engineer for the preparation of the majority of our reserve report, effective December 31, 2012. DeGolyer and MacNaughton was established in 1936 and is one of the oldest and largest third party reserve engineering firms in the US today. This firm meets or exceeds the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers and is proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.

Cawley, Gillespie and Associates, of Fort Worth, Texas, was our third party reserve engineer for the preparation of our reserve report for our Bakken Shale assets, effective December 31, 2012. Cawley, Gillespie and Associates was established in 1960 and is one of the largest third party reserve engineering firms in the US today. This firm meets or exceeds the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers and is proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.

Proved Undeveloped Reserves

As of December 31, 2012, there were 465,551 barrels of oil and 312,937 mcf of natural gas in our proved undeveloped reserves. During 2012, we focused primarily on the acquisition of leasehold properties from the XOG Group, the participation in non-operated exploratory drilling activities in the Bakken and the Eagle Ford, and the initiation of a self-directed drilling program in the Permian Basin. As of December 31, 2012, much of our drilling investments in the Bakken and Permian Basin remained unproved.

Oil and Natural Gas Production, Production Prices and Production Costs

Oil and Natural Gas Production

The following table summarizes the production of oil and natural gas by geographical area for the fiscal year ended December 31, 2012:

Product	Williston Basin		Eagle Ford		Gulf Coast & Arkansas		Permian Basin		Total
Oil (Bbls)		89,460		2,178		16,502		105,571		213,711
Natural Gas (Mcf)		37,603		6,717		185,058		331,569		560,947
BOE		95,727		3,297		47,345		160,833		307,202

The following table summarizes gross and net productive oil wells by state as of December 31, 2012. A net well represents our percentage ownership of a gross well. The following table includes wells which were awaiting completion, in the process of completion or awaiting flowback subsequent to fracture stimulation.

	As of December 31, 2012
	Gross		Net
Permian Basin (Texas and New Mexico)		208		181.5
Bakken (North Dakota)		133		2.3
Other (Texas, Oklahoma, Arkansas)		15		31.7
Total		356		215.5

��

Production Prices

The following table summarizes the average sales price per unit of oil and natural gas by geographical area for the fiscal year ended December 31, 2012:

Product	Williston Basin		Eagle Ford		Gulf Coast & Arkansas		Permian Basin		Total
Oil (Bbls)	$	86.52	$	95.14	$	95.56	$	85.95	$	90.79
Natural Gas (Mcf)		5.21		2.76		2.43		4.98		3.85
Product (Mcf)		5.61		11.43		-		9.61		8.88
BOE	$	50.48	$	60.09	$	55.07	$	57.83	$	55.87

We used the 12 month first day of the month unweighted average prices realized as a basis for all oil calculations and Henry Hub for gas.

The following table summarizes the weighted average prices utilized in the reserve estimates for 2012 and 2011 as adjusted for location, grade and quality:

	As of December 31,
	2012		2011

Prices utilized in the reserve estimates:
Texas oil and natural gas properties
Oil per Bbl(a)	$	84.40	$	92.21
Gas per MCF(b)	$	5.28	$	6.06
North Dakota oil and natural gas properties
Oil per Bbl(a)	$	90.95	$	90.25
Gas per MCF(b)	$	4.35	$	7.10

(a) The pricing used to estimate our 2012 and 2011 reserves was based on a 12-month unweighted average first-day-of-the-month West Texas Intermediate posted price as adjusted for location, grade and quality.

(b) The pricing used to estimate our 2012 and 2011 reserves was based on a 12-month unweighted average first-day-of-the-month Henry Hub spot price as adjusted for location, grade and quality

Oil and natural gas reserve quantity estimates are subject to numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. The accuracy of such estimates is a function of the quality of available data and of engineering and geological interpretation and judgment.

Costs Incurred for Oil and Natural Gas Producing Activities

	Years Ended December 31,
	2012		2011

Property acquisition costs	$	57,507,963	$	19,123,787
Development		42,695,713		43,172,955

Total	$	100,203,676	$	62,296,742

Average production costs per BOE including ad valorem and severance taxes were $22.44 in 2012. Excluding severance taxes, production costs per BOE were $16.65. Average production costs per BOE including ad valorem and severance taxes were $16.38 in 2011. Excluding severance taxes, production costs per BOE were $10.65.

Dry Holes

Through August 1, 2013, we have experienced no dry holes as of result of our non-operated drilling activities.

Drilling Activity and other Exploratory and Development Activities

Productive and Exploratory Wells Drilled

In the fiscal year ended December 31, 2012, operators drilled and completed 12 gross (11.0656 net) exploratory wells on our leaseholds located in the Permian Basin, including 4 gross (4 net) wells in Andrews County, 3 gross (3 net) wells in Crockett County, 2 gross (2 net) wells in Schleicher County, 2 gross (2 net) wells in Reagan County and 1 gross (.0656 net) well in Eddy County, New Mexico. Lastly, we participated in 66 gross (1.4143 net) wells in the Bakken play in North Dakota.

In the fiscal year ended December 31, 2011, operators drilled and completed 8 gross (8.0 net) exploratory wells on our leaseholds located in the Permian Basin, including 2 gross (2.0 net) wells in Andrews County and 2 gross (2.0 net) wells in Reagan County. We participated in 18 gross (1.8 net) exploratory wells in the Eagle Ford shale formation in South Texas, including 16 gross (1.6 net) wells in La Salle County, and 2 gross (0.2 net) wells in Frio County. Lastly, we participated in 96 gross (1.65 net) exploratory wells in Mountrail, McKenzie, Williams, Dunn, Burke, and Divide Counties in North Dakota.

Productive and Dry Development Wells Drilled

In the fiscal year ended December 31, 2012, operators drilled and completed 0 gross (0 net) development wells on our leaseholds.

In the fiscal year ended December 31, 2011, we participated on a non-operated basis in 2 gross (0.1 net) development wells on minority working interest acreage in Glasscock County, Texas with Trilogy Operating Company. We participated in 0 gross (0.0 net) development wells in the Eagle Ford shale formation in South Texas. Lastly, we participated in 0 gross (0.0 net) development wells in the Williston Basin in North Dakota. All of our drilling the Eagle Ford and Bakken in 2010 and 2011 has been exploratory. We have only just begun to receive notification of development well in-fill drilling on some of our minority working interest acreage in the Bakken in early 2012.

Present Activities

As of July 1, 2013, our third party operators are in the process of drilling and completing Bakken and Three Forks horizontal wells in the Bakken play in North Dakota as well as a Third Bone Springs horizontal well in Eddy County, New Mexico. Since January 1, 2013 we have agreed to participate in 30 gross (.45 net) horizontal wells in North Dakota and 1 gross (.07 net) horizontal well in New Mexico.

Oil and Gas Properties, Wells, Operations and Acreage

The following table summarizes as of December 31, 2012, the total gross and net productive wells, expressed separately for oil and gas and the total gross and net developed acreage (i.e. , acreage assignable to productive wells) by geographic area.

	Oil Wells				Gas Wells				Total Wells
	Gross		Net		Gross		Net		Gross		Net
Permian		183		170		25		11		208		181
Bakken		133		2.3		-		-		133		2.3
Niobrara		-		-		-		-		-		-
Eagle Bine		-		-		-		-		-		-
Other		21		16.4		30		15.3		51		31.7
Total		337		188.7		55		26.3		392		215

The following table summarizes as of December 31, 2012, the amount of undeveloped leasehold acreage expressed in both gross and net acres by geographic area and the minimum remaining terms of leases and concessions.

	HBP Acreage				Total Acreage				Acreage Subject to Expiration				Expiration Date Range
	Gross		Net		Gross		Net		Gross		Net
Permian		23,987		16,791		37,959		26,571		13,972		9,780		Second Quarter 2016
Eagle Ford		8,591		6,014		8,591		6,014		-		-
Niobrara		-		-		55,700		16,342		55,700		16,342		First Quarter 2019
Bakken		49,016		4,534		434,205		40,164		385,189		35,630		Range from 2013-2017
Eagle Bine		-		-		2,497		1,873		2,497		1,873		First Quarter 2014
Other		7,103		5,327		7,103		5,327		-		-
Total		88,697		32,666		546,055		96,291		457,358		63,625

In the Bakken, our non-operated minority interest acreage is primarily not held by production today, with 35,630 of our 40,164 acres undeveloped or subject to drilling in progress. Our acreage exposure is very granular, with over 600 leases with a typical working interest ranging from 1-10%. We hold approximately 5,240 and 14,360 net acres that expire in 2013 and 2014, respectively. The majority of our Bakken acreage has maturity dates in 2013-2016, with the majority of the leases having 1-2 year extension options.

In the Permian, we have acquired approximately 9,190 net acres in Crockett and Edwards Counties that were not held by production at March 15, 2012. The leasehold acreage in both counties has three year lease maturities, with an option to extend the leases by one year. We own the majority working interests in the acreage in both counties, and we have the ability to direct and contract for the drilling and potential production of these assets to hold by production in the future.

In the Bakken, we have acquired an additional 9,800 net acres in Billings, Burke, Divide, Dunn, Hettinger, McKenzie, Mountrail, Stark and Williams Counties, North Dakota, and Sheridan, Montana. The expiration of these leases ranges from 2014 to 2016, and in some instances, the acreage has additional options to extend the lease maturity. We do not own the majority working interest in this acreage, nor do we have any ability to influence the potential development of this acreage within the terms of the lease.

Employees

We currently have a full-time staff of two executive officers and two additional employees who manage all day to day operations of the Company.

Item 3. LEGAL PROCEEDINGS

The Company is a defendant in a lawsuit for claims in the amount of approximately $645,000. The complaint was filed in the United States District Court, Southern District of New York and is entitled: Northland Securities, Inc., plaintiff v. American Standard Energy Corp., defendant and is assigned Civil Action No. 12cv8604. In the action Northland Securities alleges a claim for breach of an agreement dated June 6, 2011, under which Northland Securities alleges that the Company owes Northland a fee in connection with the Company’s issuance of a convertible note. Northland Securities also alleges a claim for breach of an agreement dated June 22, 2011, under which Northland Securities alleges that the Company owes Northland a fee in connection with our Macquarie debt facility. The Company is vigorously defending this action.

The Company's management is unaware of any other material existing or pending legal proceedings or claims against the Company.

Item 4. MINE SAFETY DISCLOSURES

Not applicable.

PART II

Item 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Our shares of common stock are trading on the Over the Counter Bulletin Board (“OTCBB”) under the trading symbol “ASEN.” The OTCBB is a significantly more limited market than the New York Stock Exchange or NASDAQ system. The quotation of our shares on the OTCBB may result in a less liquid market available for existing and potential stockholders to trade shares of our common stock, could depress the trading price of our common stock and could have a long-term adverse impact on our ability to raise capital in the future.

The following table sets forth, for the period indicated, the high and low closing prices for our common stock on the OTCBB as reported by various OTCBB market makers. The quotations do not reflect adjustments for retail mark-ups, mark-downs, or commissions and may not necessarily reflect actual transactions.

Quarter Ended	High ($)		Low ($)
Fourth Quarter ended December 31, 2012	$	0.62	$	0.15
Third Quarter ended September 30, 2012	$	1.42	$	0.62
Second Quarter ended June 30, 2012	$	2.51	$	1.31
First Quarter ended March 31, 2012	$	3.25	$	1.80
Fourth Quarter ended December 31, 2011	$	4.75	$	3.05
Third Quarter ended September 30, 2011	$	8.15	$	4.65
Second Quarter ended June 30, 2011	$	8.25	$	6.75
First Quarter ended March 31, 2011	$	8.40	$	3.75

Holders

As of August 1, 2013, there were approximately 214 holders of record of our common stock.

Transfer Agent and Registrar

Standard Registrar & Transfer Co., Inc. is currently the transfer agent and registrar for our common stock. Its address is 12528 South 1840 East, Draper, UT 84020. Its phone number is (801) 571-8844.

Dividend Policy

We have never declared or paid dividends on our common stock. We intend to retain earnings, if any, to support the development of our business and therefore do not anticipate paying cash dividends for the foreseeable future. Payment of future dividends, if any, will be at the discretion of the Company’s board of directors after taking into account various factors, including current financial condition, operating results and current and anticipated cash needs.

Securities Authorized for Issuance under Equity Compensation Plans

The following is certain information about our equity compensation plans as of December 31, 2012:

Plan Category	Number of securities to be issued upon exercise of outstanding options, warrants and rights		Weighted average exercise price of outstanding options, warrants and rights		Number of securities remaining available for future issuance under equity compensation plans (1)
Equity Compensation Plans approved by security holders		7,219,608	$	2.07		8,979,240

(1) Excluding securities reflected in the second column.

In 2010, we adopted our Stock Incentive Plan (the "2010 Plan") and ratified an amendment to such plan in August 2011. The maximum number of shares of our common stock that may be issued pursuant to grants or awards under the 2010 Plan, as amended, is 12,000,000 shares to employees, officers, directors and outside advisors. As of December 31, 2012, 7,045,000 options were issued and outstanding under the 2010 Plan.

In 2011, we adopted a new Stock Incentive Plan (the “2011 Plan”), under which we approved and reserved 10,000,000 stock options for issuance to our employees, officers, directors and outside advisors. As of December 31, 2012, 174,608 options were issued and outstanding under the 2011 Plan.

Item 6. SELECTED FINANCIAL DATA

Results of Operations

The following table presents selected financial and operating information for all periods presented:

	Years Ended December 31,
	2012			2011
Income Statement Information:
Production volumes:
Oil (Bbls)		213,711			75,883
Natural Gas (Mcf)		560,947			500,223
BOE (1)		307,202			159,254
BOE per day		839			436

Sales Prices
Oil (per Bbl)	$	82.05		$	89.66
Natural Gas (per Mcf)	$	3.93		$	5.99
BOE Price	$	64.25		$	61.53

Operating Revenues
Oil	$	17,534,018		$	6,804,024
Natural Gas		2,204,505			2,994,341
	$	19,738,523		$	9,798,365

Operating Expenses
Oil and natural gas production costs	$	6,894,872		$	2,608,978
General and administrative		37,976,747			16,387,633
Impairment of oil and natural gas properties		28,640,726			1,027,552
Depreciation, depletion and amortization		5,919,933			2,807,893
Accretion of discount on asset retirement obligations		44,072			20,951
Loss on sale of oil and natural gas leases		312,819			-
		79,789,169			22,853,007

Loss from operations	$	(60,050,646	)	$	(13,054,642	)

	As of or for the
	Years Ended December 31,
	2012			2011
Balance Sheet Information:
Total assets	$	129,464,843		$	95,894,737
Term loan and revolving credit facility, net of discount		10,760,417			7,262,832
Pentwater note, net of discount		19,528,038			-
Total liabilities		45,672,155			36,943,879
Total stockholders' equity		83,792,688			58,950,858

Statement of Cash Flow Information:
Net cash provided by operating activities		8,693,211			4,402,749
Net cash used in investing activities		(29,320,878	)		(58,462,398	)
Net cash provided by financing activities		20,612,240			54,272,702

Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion is intended to assist you in understanding our business and results of operations together with our financial condition. This section should be read in conjunction with our historical combined and consolidated financial statements and notes, as well as the selected historical combined and consolidated financial data included elsewhere in this report. Statements in our discussion may be forward-looking statements. These forward-looking statements involve risks and uncertainties. We caution that a number of factors could cause future production, revenues and expenses to differ materially from our expectations. Please see “Cautionary Note Regarding Forward-Looking Statements.”

Overview

In the Permian Basin, the Niobrara, the Eagle Bine and parts of the Eagle Ford, we own a number of leases where we hold the majority working interest. We have historically contracted, and expect to continue to contract, with third-party operators, consultants, and other contractor service providers to operate and drill our majority leasehold acreage. Within this acreage, the Company has historically contracted to drill conventional, vertical wells. The Company may consider contracting with third parties to selectively drill unconventional, horizontal wells in areas that may be prospective for oil and natural gas bearing shale formations.

We also hold minority interest leasehold acreage in the Bakken, parts of the Permian Basin, and parts of the Eagle Ford. In the minority working interest leaseholds, the Company has historically participated, and expects to continue to participate, on a non-operated basis in the drilling and production of acreage operated by independent oil and natural gas operating companies.

While we do rely on the expertise and resources of the respective operators that are drilling our minority working interest acreage, we believe that our overall diversification across a large number of small working interests provides a way to participate in two large shale formations that are being actively developed with less risk than a concentrated acreage position.

By participating in drilling activities with larger operators, we seek to leverage their resources and expertise to efficiently gain exposure to potential new oil and natural gas production and proven reserves. In the Permian Basin, some of these operators have historically drilled and operated traditional, vertical wells. In the Eagle Ford and Bakken, we have participated in wells where the operators have historically drilled unconventional, horizontal wells into prospective oil and natural gas bearing shale formations.

As of December 31, 2012, we held working interests in approximately 96,300 net acres in the Permian Basin, Bakken, Eagle Ford, Niobrara, Eagle Bine and Gulf Coast regions. These working interests grant us the right, as the lessee of the property, to explore for, develop and produce oil, natural gas and other minerals, while bearing our portion of related exploration, development and operating costs.

Commodity Prices

Our results of operations are heavily influenced by commodity prices. Factors that may impact future commodity prices, including the price of oil and natural gas, include:

weather conditions in the United States and where the Company's property interests are located;

economic conditions, including demand for petroleum-based products, in the United States and the rest of the world;

actions by OPEC, the Organization of Petroleum Exporting Countries;

political instability in the Middle East and other major oil and natural gas producing regions;

governmental regulations;

domestic tax policy;

the price of foreign imports of oil and natural gas;

the cost of exploring for, producing and delivering oil and natural gas;

the discovery rate of new oil and natural gas reserves;

the rate of decline of existing and new oil and natural gas reserves;

available pipeline and other oil and natural gas transportation capacity;

the ability of oil and natural gas companies to raise capital;

the overall supply and demand for oil and natural gas; and

the availability of alternate fuel sources.

Although we cannot predict the occurrence of events that may affect future commodity prices or the degree to which these prices will be affected, the prices for any commodity that we produce will generally approximate current market prices in the geographic region of the production. From time to time, we will evaluate the benefits of hedging a portion of our commodity price risk to mitigate the impact of price volatility on our business. To mitigate a portion of the exposure to potentially adverse market changes in oil and natural gas prices and the associated impact on cash flows, the Company has entered into various derivative commodity contracts. The Company’s derivative contracts in place include swap arrangements for oil and natural gas. As of filing date of this Annual Report on Form 10-K, the Company has commodity derivative contracts in place through the third quarter of 2014 for a total of approximately 61,649 Bbls of anticipated crude oil production and 297,688 MMBtu of anticipated natural gas production.

Oil and natural gas prices have been subject to significant fluctuations during the past several years. In general, average oil and natural gas prices were lower during the comparable periods of 2012 measured against 2011. The following table sets forth the average NYMEX oil and natural gas prices for the years ended December 31, 2012 and 2011, as well as the high and low NYMEX price for the same periods:

	Years Ended December 31,
	2012		2011
Average NYMEX prices:
Oil (Bbl)	$	94.05	$	94.88
Natural gas (MMBtu)	$	2.75	$	4.00
High / Low NYMEX prices:
Oil (Bbl):
High	$	109.39	$	113.39
Low	$	77.72	$	75.40
Natural gas (MMBtu):
High	$	3.77	$	4.92
Low	$	1.82	$	2.84

Recent Events

Credit Agreement.On September 21, 2011, Nevada ASEC, referred to herein as the Borrower entered into a Credit Agreement (the “Credit Agreement”) with the lenders party thereto and Macquarie Bank Limited as administrative agent. The Credit Agreement provides to the Borrower a revolving credit facility in an amount not to exceed $100 million and a term loan facility in an amount not to exceed $200 million. The interest rate on revolving loans is 30, 60 or 90 day LIBOR, as selected by the Borrower, plus a margin of 2.75% to 3.25% per annum, based on the borrowing base utilization, and the interest rate on term loans is 30, 60 or 90 day LIBOR, as selected by the Borrower, plus a margin of 7.50%. The maturity date of the revolving credit facility is September 21, 2015 and the maturity date of the term loan facility is September 21, 2014. The Borrower also has the option to borrow at the Base Rate plus margins from 1.75% to 2.25%.

The Borrower’s obligations under the Credit Agreement are secured by the Borrower’s interest in certain oil and gas properties and the hydrocarbons produced from such properties, as well as the proceeds of the sale of such hydrocarbons. We guaranteed the Borrower’s obligations under the Credit Agreement and pledged to the administrative agent a security interest in 100% of the capital stock of the Borrower as security for our obligations under the guaranty.

For the quarter ended December 31, 2012, the Borrower was in default under the Credit Agreement for (i) failing to deliver the required reserve report, (ii) failing to deliver the annual financial statements within 120 days of the end of the fiscal year, (iii) failing to comply with the current ratio covenant, (iv) failing to comply with the interest coverage ratio covenant, (v) having accounts payable, accrued expenses and obligations that are more than 90 days past due and exceed $250,000, and (vi) allowing G&A expenses to exceed $700,000. The defaults were waived by Macquarie on May 15, 2013.

For the quarter ended March 31, 2013, the Borrower was in default under the Credit Agreement for (i) failing to comply with the current ratio covenant, (ii) failing to comply with the interest coverage ratio covenant and (iii) allowing G&A expenses to exceed $700,000. The defaults were waived by Macquarie on May 15, 2013.

Simultaneously with the receipt of the waivers received from Macquarie, the Credit Agreement was amended to (i) reduce the borrowing base available under the "Revolving Loan" from $12 million to $0, (ii) provide that the amount available to be drawn under the "Revolving Loan" is $0, (iii) provide that the amount available to be drawn under the "Term Loan" is $0, (iv) accelerate the repayment of the "Revolving Loan" by changing the maturity date with respect to such repayment from September 21, 2015 to May 17, 2013, (v) modify the amortization of the outstanding principal amount with respect to the repayment of the "Term Loan" by providing that such amortization shall begin on the last business day of May 2013 instead of March 21, 2013, and such repayment shall be made pursuant to the amortization schedule attached to the Credit Agreement, and (vi) provide provisions for the payment of joint interest billings in relation to the "Double Down 24-13 #1H Well" that supersedes the terms and conditions of that certain letter agreement, dated as of February 15, 2013, by and among Nevada ASEC, lender and administrative agent.

In connection with the Credit Agreement, we issued to Macquarie Americas Corp., referred to herein as Macquarie Americas a five year warrant to purchase five million (5,000,000) shares of our common stock at a per share exercise price of $7.50, subject to certain adjustments. In connection with the consent provided by Macquarie Bank to the issuance of the Pentwater Note and the transactions contemplated under the Modification Agreement, pursuant to the terms of the Credit Agreement, the Company agreed (i) to pay to Macquarie Bank a $1,100,000 modification fee and (ii) to amend and restate the Macquarie Warrant. Accordingly on February 9, 2012, the Company issued an amended and restated Macquarie Warrant (the “Amended Macquarie Warrant”) to Macquarie to purchase up to 2,333,000 shares of common stock, at an exercise price of $3.25 per share. The Amended Macquarie Warrant is not subject to further anti-dilution provisions other than customary reset provisions for stock splits, subdivision or combinations. The Amended Macquarie Warrant is exercisable on a cashless basis if there is no registration statement covering the underlying common stock. The Company granted the holder piggy-back registration rights on the underlying common stock. As the warrant modification fee was consideration given as part of the modification, it was expensed as a component of realized and unrealized expense on warrant derivatives in the consolidated statement of operations.

Convertible Note. On February 10, 2012, the Company and ASEN 2, Corp., a wholly-owned subsidiary of the Company entered into a Note and Warrant Purchase Agreement dated February 9, 2012 (the “Purchase Agreement”) with Pentwater Equity Opportunities Master Fund Ltd. and PWCM Master Fund Ltd. (collectively, “Pentwater”) in connection with a $20 million private financing. The initial funding made by Pentwater to ASEN 2 on February 10, 2012 (the “Pentwater Closing Date”) was in the amount of $10 million. The second funding for an additional $10 million, which closed on March 5, 2012, occurred concurrently with the closing of the purchase and sale agreement by and among the Company, Geronimo and XOG for the XOG Properties.

The borrowings under the Purchase Agreement are evidenced by a $20 million secured convertible promissory note (the “Pentwater Note”) convertible into shares of the Company’s common stock at a conversion price of $9.00 per share and five year warrants to purchase 3,333,333 shares of common stock at a per share cash exercise price of $2.50. The Warrants are also subject to a mandatory exercise at the Company’s option with respect to (i) 50% of the number of shares underlying the Warrants if the closing sale price of the common stock is equal to or greater than $5.00 per share for twenty consecutive trading days and (ii) 50% of the number of Warrant Shares if the closing sale price of the common stock is equal to or greater than $9.00 per share for twenty consecutive trading days.

From the Pentwater Closing Date through December 9, 2012, the outstanding borrowings under the Pentwater Note bear an interest rate of 11% per annum, payable as follows (i) interest at a rate of 9% per annum is payable on the first business day of each month, commencing on March 1, 2012 and (ii) interest at a rate of 2% per annum is capitalized and added to the then unpaid principal amount monthly in arrears on the first business day of each month commencing on March 1, 2012. On and after December 9, 2012 through the maturity date, the Pentwater Note bears an interest rate of 16% per annum, payable as follows: (i) interest at a rate of 11% per annum is payable on the first business day of each month commencing on December 1, 2012 and (ii) interest at a rate of 5% per annum is capitalized and added to the then unpaid principal amount monthly on the first business day of each month commencing on December 1, 2012. The Pentwater Note had a maturity date of February 9, 2015, which was amended on March 5, 2012 to December 1, 2013. ASEN 2 can prepay the Pentwater Note without penalty prior to December 31, 2012. If the prepayment occurs after December 31, 2012, ASEN 2 must pay to Pentwater 106% of the then outstanding principal amount of the Pentwater Note that is prepaid. At any time after February 9, 2013, the principal amount and interest of the Pentwater Note may be converted into shares of common stock at a conversion price of $9.00 per share.

On July 23, 2012, the Company, as guarantor, and ASEN 2 entered into a First Amendment to Note and Warrant Purchase Agreement (the “Purchase Agreement Amendment”) with Pentwater Equity Opportunities Master Fund Ltd. and PWCM Master Fund Ltd.. Pursuant to the Purchase Agreement Amendment, Pentwater advanced to ASEN 2 an additional $5 million and ASEN 2 delivered an Amended and Restated Secured Convertible Promissory Note in the amount of $25 million which is guaranteed by the Company. All other material terms of the original Note and Warrant Purchase Agreement and Secured Convertible Promissory Note dated February 9, 2012 remain unchanged and in full force and effect.

On September 11, 2012, the Company, as guarantor, and ASEN 2 entered into a Second Amendment to Note and Warrant Purchase Agreement, First Amendment to Amended and Restated Secured Convertible Promissory Note and Limited Waiver (the “Second Amendment”) with Pentwater. Pursuant to the Second Amendment, the parties agreed to amend the terms of the Purchase Agreement and Pentwater Note, as amended, in exchange for a waiver by Pentwater of certain reporting covenant defaults under the Purchase Agreement.

Pursuant to the terms of the Second Amendment, the Purchase Agreement was amended such that 100% of the net cash proceeds of any disposition of assets by ASEN 2 must be used to prepay the Note and any disposition by ASEN 2 of collateral securing ASEN 2’s obligations under the Note and the Purchase Agreement must be approved by Pentwater, other than dispositions of inventory in the ordinary course of business or of obsolete or worn out assets. The Second Amendment further provides that ASEN 2 must engage operational consultants with engineering expertise within thirty days from the date of the Second Amendment. Additionally, Pentwater shall have the right to nominate, and the Company shall take all steps necessary to elect, two directors to the Company’s board of directors to fill the vacancies left upon the resignation of certain directors. Thereafter, Pentwater shall be entitled to propose the nomination of two directors to the Company’s board each time the members of the board of directors appointed by Pentwater are up for election; provided that, in no event shall Pentwater be entitled to nominate and elect more than two directors to the Company’s board. The Purchase Agreement was further amended to prohibit the Company from amending or proposing an amendment to the bylaws or certificate of incorporation of the Company without Pentwater’s consent. Pursuant to the terms of the Second Amendment, the principal amount of the Note was increased by $89,059. As a condition to the effectiveness of the Second Amendment, Pentwater transferred a portion of the Note equal to $2,750,000 (the “Transferred Indebtedness”) to Antler Bar Investments LLC, an affiliate of Pentwater (“Antler Bar”). All other material terms of the Purchase Agreement and Note remain unchanged and in full force and effect.

In connection with the Second Amendment, ASEN 2 and Antler Bar entered into an Asset Purchase Agreement (the “Asset Purchase Agreement”) dated September 11, 2012. Pursuant to the Asset Purchase Agreement, ASEN 2 sold its interests in approximately 1,200 leasehold acres of the Auld Shipman project in La Salle and Frio counties, Texas (the “Auld Shipman Property”) to Antler Bar in exchange for the forgiveness of the Transferred Indebtedness and for the assumption by Antler Bar of all liabilities related to the Auld Shipman Property.

The transactions under the Second Amendment and Asset Purchase Agreement closed on September 13, 2012.

Warrant Restructure. On February 10, 2012, the Company, Pentwater and two affiliated entities of Pentwater, referred to herein as the Modification Investors, entered into a modification agreement, referred to herein as the Modification Agreement, pursuant to which the parties agreed to amend the terms of the Series B warrants, referred to herein as the Series B Warrants, issued to the Modification Investors in a $13 million private placement offering of the Company’s securities in July 2011, referred to herein as the July Offering, in which the Modification Investors invested $12 million. Pursuant to the terms of the Modification Agreement, the parties agreed to limit the dilutive effects of the Series B Warrants by including a floor of $3.00 per share in the calculation of the reset provision included in the Series B Warrants. Accordingly, the aggregate maximum number of shares of common stock underlying the Series B Warrants held by the Modification Investors is 1,913,043 shares.

As additional consideration for the modification of the Series B Warrants, the Company agreed to issue to the Modification Investors new five-year Series C warrants, referred to herein as Series C Warrants, to purchase 2.5 million shares of common stock, referred to herein as the Series C Warrant Shares, with a cash exercise price of $3.00 per share. The Series C Warrants include a provision under which the Series C Warrants must be exercised at the election of the Company by the Modification Investors for cash if the closing sales price of the common stock is $6.00 per share or greater for 20-consecutive trading days. As a result of the issuance of the Warrants and the Series C Warrants, the exercise prices and number of shares underlying the Series A warrants and Series B warrants held by the remaining investor in the July Offering were adjusted pursuant to their terms. As the Series C Warrants are consideration given as part of the modification, the fair value of these warrants on the modification date were expensed as component of realized and unrealized expense on warrant derivatives on the consolidated statement of operations.

On April 5, 2012, pursuant to the terms of a second modification agreement, the Company and the Modification Investors agreed to further amend the terms of the Series B warrant to extend the expiration date to be (i) May 24, 2012 with respect to 1,000,000 shares of common stock underlying the Series B warrants and (ii) with respect to the remaining 913,043 shares of common stock underlying the Series B Warrants (the “Subsequent Warrant Shares”), the date that is the earlier of (a) 300 days from April 5, 2012 and (b) ten business days after notice from the Company stating that the number of Subsequent Warrant Shares exercisable by the Modification Investors would result in ownership of less than 9.99% of the Company’s common stock after giving effect to such exercise. The Company may provide multiple notices prior to the expiration of the Subsequent Warrant Shares.

On July 23, 2012 the Company and ASEN 2, entered into a First Amendment to the Purchase Agreement with Pentwater. Pursuant to the Purchase Agreement Amendment, Pentwater advanced to ASEN 2 an additional $5 million and ASEN 2 delivered an Amended and Restated Secured Convertible Promissory Note (“Amended Note”) in the amount of $25 million which is guaranteed by the Company. All other material terms of the original Note and Warrant Purchase Agreement and Secured Convertible Promissory Note dated February 9, 2012 remain unchanged and in full force and effect.

In connection with the Purchase Agreement Amendment, the Company, Pentwater and two affiliated entities of Pentwater (collectively, the “Investor”) entered into a Modification Agreement, dated July 23, 2012 which provided for (i) the amendment of certain warrants (the “Purchase Warrants”) to purchase up to 3,333,333 shares of Common Stock, at an exercise price of $2.50 per share, issued to Pentwater pursuant to the a Purchase Agreement dated February 9, 2012, to decrease the exercise price to $2.25 and to change the expiration date to June 30, 2019; (ii) the amendment of certain Series C Warrants (the “Modification Warrants”) to purchase up to 2,500,000 shares of Common Stock, at an exercise price of $3.00 per share, issued to Investor pursuant to a Modification Agreement dated February 9, 2012, to decrease the exercise price to $2.25 and to change the expiration date to June 30, 2019; and (iii) the issuance of additional warrants (the “Additional Warrants” and together with the Purchase Warrants and Modification Warrants, the “Warrants”) to Pentwater to purchase up to 833,333 shares of Common Stock (the “Additional Warrant Shares” and together with the Purchase Warrant Shares and the Modification Warrant Shares, the “Warrant Shares”), at an exercise price of $2.25 per share with an expiration date of June 30, 2019. As the Series C Warrants were consideration given pursuant to the Modification Agreement, the fair value of $410,340 of these warrants on the modification date was expensed as a component of realized and unrealized expense on warrant derivatives in the consolidated statement of operations.

Macquarie Warrant Restructure. In connection with the consent provided by Macquarie Bank to the issuance of the Pentwater Note and the transactions contemplated under the Modification Agreement, pursuant to the terms of the Credit Agreement, the Company agreed (i) to pay to Macquarie Bank a $1,100,000 modification fee and (ii) to amend and restate the Macquarie Warrant. Accordingly, the Company issued an amended and restated Macquarie Warrant referred to herein as the Amended Macquarie Warrant, to Macquarie Americas to purchase two million three hundred thirty-three thousand (2,333,000) shares of common stock, at an exercise price of $3.25 per share. The Amended Macquarie Warrant is not subject to further anti-dilution provisions other than customary reset provisions for stock splits, subdivision or combinations. The Amended Macquarie Warrant is exercisable on a cashless basis if there is no registration statement covering the underlying common stock. The Company granted the holder piggy-back registration rights on the underlying common stock. As the warrant modification fee was consideration given as part of the modification, it was expensed as component of realized and unrealized expense on warrant derivatives on the consolidated statement of operations.

Founder’s Shares. On February 13, 2012, the board of directors of the Company approved the immediate vesting of a total of 1,568,877 restricted shares of the Company’s common stock previously issued to the chief executive officer, president and chief financial officer as founder’s shares which were to vest in equal portions annually through April 16, 2014. Pursuant to a Severance Agreement, dated November 24, 2012, between Scott Mahoney and the Company, the parties agreed to rescind the acceleration of the vesting of the founders shares that occurred on February 13, 2012. On December 28, 2012, Scott Feldhacker, the chief executive officer, and Richard MacQueen, the president, each executed Rescission Agreements that rescinded the acceleration of the vesting of the founders shares that occurred on February 13, 2012. On December 31, 2012, the board of directors of the Company took action by written consent to reinstate the original vesting schedule for the founders Shares in order to reduce tax liabilities for tax gross-up payments. Currently, all remaining un-vested founders shares will vest on April 16 of 2013 and 2014. The compensation expense for these shares was $1,797,993 for the year ended December 31, 2012.

March Asset Acquisition. On March 5, 2012, the Company acquired leasehold working interests in approximately 61,500 net developed and undeveloped acres across the Permian Basin, the Bakken, the Eagle Ford, the Niobrara, the Eagle Bine, and the Gulf Coast (collectively, the “XOG Properties”) in exchange for the delivery by the Company to the Sellers of $10 million in cash, less a $1.5 million cash deposit previously paid by the Company, a note in the principal amount of $35,000,000 (the “March 2012 Note”) made by the Company in favor of Geronimo and 5,000,000 shares of the common stock of the Company, which has a closing price of $2.70 on the closing date of the acquisition. The XOG Properties were purchased pursuant to the terms of a Purchase and Sale Agreement dated as of February 24, 2012, referred to hereafter as the PSA, by and among the Company, XOG and Geronimo.

The PSA provides that if certain defects are found with the March 2012 Properties, or if XOG or Geronimo breach any representation or warranty in the Agreement within one year from closing, XOG and Geronimo shall, at the option of the Company, in its sole and absolute discretion, either (i) provide additional or alternative oil and gas properties, subject to the Company’s applicable due diligence review and acceptance or (ii) for as long as the March 2012 Note is outstanding, decrease the principal amount of the Note in an amount equal to the loss resulting from such property defect or breach.

XOG and Geronimo have piggyback registration rights with respect to up to five million shares of common stock held by XOG or Geronimo.

Payment and Settlement Agreement. On June 30, 2012, the Company, ASEN 2, Nevada ASEC, and XOG Operating LLC (“XOG”), entered into a Payment and Settlement Agreement (the “Payment Agreement”) whereby the Company agreed to issue 4,444,445 shares (the “XOG Shares”) of the Company’s common stock to XOG at a price per share equal to $2.25 as payment of the $10,000,000 outstanding and owed to XOG pursuant to certain Joint Interest Billing Statements issued by XOG from January 1, 2012, through and including June 30, 2012 and delivered to the Company’s subsidiaries in connection with certain Joint Operating Agreements.

Pursuant to the terms of the Payment Agreement, the Company granted piggy-back registration rights with respect to XOG Shares if the Company files a registration statement in connection with an underwritten public offering within one year from the date of the Payment Agreement.

Exchange Agreement. On June 30, 2012, the Company entered into an Exchange Agreement with Geronimo Holding Corporation (“Geronimo”) pursuant to which the Company agreed to issue 35,400 shares (the “Geronimo Shares”) of the Company’s newly created Series A Cumulative Convertible Preferred Stock (“Series A Preferred Stock”) to Geronimo having the rights and preferences set forth in a Certificate of Designation in exchange for the cancelation of a $35 million principal amount note (the “Geronimo Note”) made by the Company in favor of Geronimo on March 5, 2012 in connection with a purchase and sale agreement (the “Purchase Agreement”) pursuant to which the Company acquired certain oil and natural gas leasehold properties, including any accrued and unpaid interest thereon.

The terms of the Purchase Agreement provided for a reduction or setoff of the principal amount of the Geronimo Note under certain conditions. Pursuant to the terms of the Exchange Agreement, in the event that the Company would have been entitled to any reduction in or setoff against the principal amount of the Geronimo Note pursuant to the terms of the Purchase Agreement, Geronimo is obligated to transfer a portion of the Geronimo Shares equal to one share of Series A Preferred Stock and any dividends accrued thereon for each $1,000 that would have resulted in a reduction in, or setoff against, the principal amount of the Geronimo Note.

The Exchange Agreement, Payment Agreement and the related transactions were approved by the Special Committee. The Special Committee also obtained a fairness opinion from Vantage Point Advisors that stated that the terms of the agreements were fair from a financial point of view to the holders of the Common Stock of the Company, other than the affiliated parties.

Randall Capps has controlling ownership of XOG, Geronimo and CLW and is a member of the Company’s Board of Directors and the father–in-law of our Chief Executive Officer, Scott Feldhacker. Through his ownership interest in the XOG Geronimo and CLW, Mr. Capps is the largest shareholder of our common stock. Effective February 18, 2013, Saber Oil, LLC purchased the 35,400 shares of the Series A Preferred Stock from Geronimo. J. Steven Person and H.H. Wommack, III, each a director of the Company, are principals in Saber Oil, LLC. In connection with the purchase of the Series A Preferred Stock, each of Randall Capps, Geronimo, XOG and CLW granted an irrevocable proxy to Saber Oil, LLC to vote the shares of common stock of the Company beneficially owned by Mr. Capps and each such entity. The irrevocable proxies granted to Saber Oil, LLC voting rights, in the aggregate, of 55.55% of the Company’s issued and outstanding common stock.

Stock Compensation Restructure. On March 30, 2012, the Board of Directors approved the restructuring of stock options as part of a comprehensive review of compensation, compensation expense, and shareholder dilution. As of December 31, 2011, 10,745,000 options to purchase common stock were outstanding. As part of a comprehensive review of compensation, compensation expense, and shareholder dilution, the Board of Directors approved the restructuring of stock options on March 30, 2012 (the “Modification Date”). Due to the modification, 2,400,000 options issued to certain officers were forfeited and 3,200,000 options were accelerated and became immediately vested. An additional 1,540,000 non-qualified options, 205,760 incentive stock options and 80,000 restricted share of common stock were granted to certain officers, directors, employees and a consultant. All modified options (including the newly issued options) were priced at the average of the open and closing share price of the Company’s common stock on March 30, 2012, which was $2.43 per share and became fully vested on the Modification Date.

For the year ended December 31, 2012 and 2011, the Company recorded non-cash stock-based compensation expense of $33,805,391 and $10,401,110, respectively, related to other share based compensation which is included in general and administrative expenses.

Resigning Directors.On September 12, 2012, Robert J. Thompson, James R. Leeton, Jr. and Scott David (the “Resigning Directors”) resigned as directors on the Company’s board of directors and from all committees of the board. The Board of Directors retained Scott David, without compensation, as an advisor to the Board of Directors, however, the Board of Directors has not requested Mr. David to provide any services as a an advisor. The Company and Mr. Thompson entered into a Retirement Agreement pursuant to which the parties agreed to terminate the Director Agreement entered into on May 23, 2011. Additionally, the Company agreed to provide certain retirement compensation in the amount of $100,000 which shall be payable as follows:

	·	$25,000 on the Resignation Date;
	·	$50,000 on January 2, 2013; and
	·	$25,000 on March 31, 2013.

Additionally, the Retirement Agreement provides for a payment to Mr. Thompson of $500 per month for a six month period commencing on October 1, 2012. The Company has not paid to Mr. Thompson the payments due under the Retirement Agreement on January 2, 2013 and March 31, 2013. Beginning January 2013, the Company has not paid to Mr. Thompson the $500 per month under the Retirement Agreement.

On September 12, 2012, the Company’s board of directors appointed Wayne Squires as a director and chairman of the board of directors to fill one of the vacancies left by the Resigning Directors.

On February 11, 2013, Scott Feldhacker, the chief executive officer of the Company, and Richard MacQueen, the president of the Company, resigned as directors of the Company’s board of directors.

Effective February 12, 2013, J. Steven Person, H.H. Wommack, III, Rusty Pickering and Michael Pedrotti accepted the nominations to bedirectors of the Company’s board of directors.

Results of Operations

The following tables present selected historical financial and operating information for the years ended December 31:

		Year Ended December 31,				Increase			% Increase
		2012		2011		(Decrease)			(Decrease)
Production volumes:
Oil (Bbls)			213,711		75,883		137,828			182	%
Natural Gas (Mcf)			560,947		500,223		60,723			12	%
BOE (1)			307,202		159,254		147,948			93	%
BOE per day			839		436		403			92	%

Sales Prices
Oil (per Bbl)		$	82.05	$	89.66	$	(7.62	)		(8	%)
Natural Gas (per Mcf)		$	3.93	$	5.99	$	(2.06	)		(34	%)
BOE Price		$	64.25	$	61.53	$	2.73			4	%

Operating Revenues
Oil		$	17,534,018	$	6,804,024	$	10,729,994			158	%
Natural Gas			2,204,505		2,994,341		(789,836	)		(26	%)
	��	$	19,738,523	$	9,798,365	$	9,940,158			101	%

										%
	Year Ended December 31,						Increase			Increase
	2012			2011			(Decrease)			(Decrease)
Operating Expenses
Oil and natural gas production costs	$	6,894,872		$	2,608,978		$	4,285,894			164	%
General and administrative		37,976,747			16,387,633			21,589,114			132	%
Impairment of oil and natural gas properties		28,640,726			1,027,552			27,613,174			0	%
Depreciation, depletion and amortization		5,919,933			2,807,893			3,112,040			111	%
Accretion of discount on asset retirement obligations		44,072			20,951			23,121			110	%
Loss on sale of oil and natural gas leases		312,819			-			312,819			0	%
	$	79,789,169		$	22,853,007		$	56,936,162			249	%

Loss from operations	$	(60,050,646	)	$	(13,054,642	)	$	(46,996,004	)		360	%

(1) A BOE means one barrel of oil equivalent using the ratio of 6 Mcf of gas to one barrel of oil.

	Revenues						Production
	2012			2011			2012			2011
Oil		89	%		69	%		70	%		48	%
Natural Gas		11	%		31	%		30	%		52	%
Total		100	%		100	%		100	%		100	%

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

Oil revenues. The Company’s oil revenues were $17,534,018 for the year ended December 31, 2012, an increase of $10,729,994 (158%) from $6,804,024 for the year ended December 31, 2011. Lower average oil prices decreased revenues approximately $1,628,281 while increased production increased revenues by approximately $12,358,275. The increase in production volumes was due primarily to new well development primarily in the Bakken.

Natural gas revenues. The Company’s natural gas revenues were $2,204,505 for the year ended December 31, 2012, a decrease of $789,836 (26%) from $2,994,341 for the year ended December 31, 2011. This decrease was due primarily to lower average prices which accounted for approximately $1,153,323 of the decrease in gas revenues. Slightly higher volumes of natural gas sold partially offset the lower prices and increased revenue by approximately $363,487.

Oil and natural gas production expenses.Production expenses for the year ended December 31, 2012 increased $4,285,894 (164%) to $6,894,872, compared to $2,608,978 for the year ended December 31, 2011. The increase is due to $4,031,705 in expenses related to new wells acquired in March 2012 as well as expenses related to production increases in existing wells.

General and administrative expenses.General and administrative (“G&A”) expenses were $37,976,747 for the year ended December 31, 2012, an increase of $21,589,114 (132%) from $16,387,633 for the year ended December 31, 2011. The primary factor for the increase in G&A expenses was the recognition of $33,805,391 in non-cash stock based compensation expense compared to $10,622,904 for the prior year. The increase was offset by lower G&A expense due to no penalties accruing related to registration obligations which was $2,019,943 for the year ended December 31, 2011.

Impairment of oil and natural gas properties. Impairment expense for the year ended December 31, 2012 was $28,640,726 compared to $1,027,552 for the year ended December 31, 2011. The Company impaired $2,268,528 related to its unproved leaseholds for the year ended December 31, 2012. The impairment consisted of several expired leases and an estimate of leases where expiration is probable in the foreseeable future. In addition to the unproved property impairment, the Company impaired approximately $26,372,198 of its proved properties as the carrying value of the properties was higher than the estimated fair value at December 31, 2012.

Depreciation, depletion and amortization expense.Depreciation, depletion and amortization (“DD&A”) expense of proved oil and natural gas properties was $5,919,933 for the year ended December 31, 2012, an increase of $3,112,040 (111%) from $2,807,893 for the year ended December 31, 2011. The increase in depletion expense was primarily due to an increase in production volumes in the Bakken and Permian Basins as a result of new wells coming into production during the year. This increase in depreciation is consistent with the increased production over the same period. This is demonstrated by the DD&A per BOE increasing by only 8% for the year ended December 31, 2012 as compared to the year ended December 31, 2011.

Other income (expense), net.Other income (expense) increased to ($15,677,549) for the year ended December 31, 2012 from ($2,265,189) at December 31, 2011. The increased expense was due primarily to interest expense of $11,447,200 for the year consisting of accretion of the debt discount of $8,149,389, amortization of debt issuance costs of $1,188,341 and interest expense of $4,001,968, incurred in the year ended December 31, 2012. This was offset by interest capitalalized to oil and natural gas properties of $1,892,497. The increase also includes the net expense of $2,808,736 consisting of an increase of $664,524 in marking the warrant derivatives to market, offset by a one-time expense relating to the modification of the warrant derivatives of $5,436,180. The Company also recorded $541,307 in net realized and unrealized gains on the commodity derivatives. The expense for the year ended December 31, 2011 was related to the unrealized loss on warrant derivatives of $409,668 relating to the Macquarie warrants and the Series A and Series B warrants and marking them to market and $670,659 net realized and unrealized loss on the commodity derivatives.

Income tax provision.Prior to their acquisition by the Company, Nevada ASEC and the Acquired Properties, respectively, were part of pass-through entities for taxation purposes. As a result, the historical financial statements of Nevada ASEC and the Acquired Properties do not present any tax expenses, liabilities or assets until their acquisition by the Company. Tax provisions subsequent to such dates are fully incorporated and presented in the accompanying consolidated financial statements. However, the income tax provision for the years ended December 31, 2012 and 2011 were $0 due to net operating losses and a related valuation allowance.

Capital Commitments, Capital Resources and Liquidity

Capital commitments.Our primary needs for cash are (i) to fund our share of the drilling and development costs associated with well development within its leasehold properties, (ii) the further acquisition of additional leasehold assets, and (iii) the payment of contractual obligations and working capital obligations. Funding for these cash needs will be provided by a combination of internally-generated cash flows from operations, supplemented by a combination of financing our bank credit facility, proceeds from the disposition of assets or alternative financing sources, as discussed in “Capital resources” below.

Oil and natural gas properties. Cash paid for oil and natural gas properties during the years ended December 31, 2012, and 2011 totaled $37,113,796, and $54,372,042, respectively. The 2012 costs related primarily to new drilling activities in the Permian and Eagle Ford and additional Bakken undeveloped leases. The 2011 costs related primarily to new drilling activities in the Permian and Eagle Ford and additional Bakken undeveloped leases.

Our 2013 capital budget for drilling (excluding any acquisitions) is approximately $15 million, assuming additional financing is made available. We expect to be able to fund our remaining 2013 capital budget partially with operating cash flows, and utilization of a new credit facility. However, the Company’s capital budget is largely discretionary, and if we experience sustained oil and natural gas prices significantly below the current levels or substantial increases in its drilling and completion costs, we may reduce our capital spending program to remain substantially within the Company’s operating cash flows.

While we believe that our available cash, cash flows and new credit facility will fund our 2013 capital expenditures, as adjusted from time to time, we cannot provide any assurances that we will be successful in securing alternative financing sources to fund such expenditures if needed. The actual amount and timing of our expenditures may differ materially from our estimates as a result of, among other things, actual drilling results, the obtaining of debt or equity financing capital, the timing of expenditures by third parties on projects that we do not operate, the availability of drilling rigs and other services and equipment, regulatory, technological and competitive developments and market conditions. In addition, under certain circumstances we would consider increasing, decreasing, or reallocating our 2013 capital budget.

Commodity derivatives.We began entering into derivative contracts during the three month period ended September 30, 2011, to achieve a more predictable cash flow by reducing our exposure to crude oil and natural gas price volatility. We have elected not to designate any subsequent derivative contracts as accounting hedges. As such, all commodity derivative positions are carried at their fair value on the balance sheet and are marked-to-market at the end of each period. Any realized gains or losses on these derivatives are recorded in realized and unrealized gain (loss) on commodity derivatives and are included as a component of other income (expense).

Capital resources.Our primary sources of liquidity during 2012 were cash flows generated from proceeds from borrowing on credit facility and term loan from which net cash proceeds of $28,857,868 were generated. We also received $8,802,668 in proceeds from the sale of oil and natural gas leases. We believe that funds from our cash flows and any financing under our credit facility should be sufficient to meet both our short-term working capital requirements and our 2013 capital expenditure plans.

Cash flow from operating activities.Our net cash provided by operating activities were $8,693,211 and $4,402,749 for the year ended December 31, 2012 and 2011, respectively. The increase in operating cash flow for the year ended December 31, 2012 was due primarily to increases in revenue offset by production costs and to a lesser extent, a decrease in accounts payable and accrued liabilities.

Cash flow used in investing activities.During the year ended December 31, 2012 and 2011, we invested $29,320,878 and $58,462,398, respectively, for additions to, and acquisitions of, oil and natural gas properties, inclusive of exploration costs. Cash flows used in investing activities were substantially lower in 2012 compared 2011 due to the Company’s decreased leasehold acquisition activities and the sale of certain oil and natural gas leases in the Bakken Shale, Permian Basin and Eagleford Formations.

Cash flow from financing activities.Net cash provided by financing activities was $20,612,240 and $54,272,702 for the year ended December 31, 2012 and 2011, respectively. Financing activity was comprised primarily of proceeds from the credit facility and term loan during the year ended December 31, 2012. Financing activity for 2011 was comprised primarily of net proceeds from the sale of common stock and warrants and proceeds from the credit facility during the year ended December 31, 2011.

February 2011 Private Placement. On February 1, 2011, we closed on a private placement offering of securities raising proceeds of $15,406,755 through the issuance of (i) 4,401,930 shares of our common stock at a price of $3.50 per share and (ii) two series of five-year warrants each exercisable into 1,100,482 shares of common stock at exercise prices of $5.00 and $6.50 per share, respectively, subject to certain adjustments. The Company also issued to the placement agents warrants to purchase up to 220,097 shares of common stock, the terms and exercise price correspond to the terms of warrants issued to investors in the private placement. The shares and warrants were sold to certain accredited investors. Subject to certain conditions, we have the right to call for the exercise of such warrants. We incurred costs of $0.8 million with this offering.

March 2011 Private Placement. On March 31, 2011, we closed a private placement offering of securities raising proceeds of $21,257,778 through the issuance of (i) 3,697,005 shares of common stock at a price of $5.75 per share and (ii) five-year warrants exercisable into 1,848,502 shares of common stock at exercise prices of $9.00 per share, subject to certain adjustments. The Company also issued to the placement agents warrants to purchase up to 96,957 shares of common stock at an exercise price of $9.00. The shares and warrants were sold to certain accredited investors. Subject to certain conditions, we have the right to call for the exercise of such warrants. We incurred costs of $1.5 million in connection with this offering.

July 2011 Private Placement. On July 15, 2011, we completed a closing of an offering of securities for total subscription proceeds of approximately $13 million through the issuance of (i) 2,260,870 shares of our common stock at a price of $5.75 per share, (ii) Series A warrants to purchase 1,130,435 shares of common stock at a per share exercise price of $9.00 subject to certain adjustment provisions, and (iii) Series B warrants to purchase a number of shares of common stock, which shall only be exercisable if (A) the market price (as defined below) of our common stock on the 30th trading day following the earlier of (i) the effective date of a registration statement to sell the shares of common stock and the Series A warrant shares, and (ii) the date on which the purchasers in the private placement can freely sell the shares of common stock pursuant to Rule 144 promulgated under the Securities Act without restriction, referred to herein as the Eligibility Date is less than the purchase price in the offering or $5.75, and (B) upon certain dilutive occurrences.

On February 10, 2012, the Company, Pentwater and two affiliated entities of Pentwater (the “Modification Investors”) entered into a modification agreement (the “Modification Agreement”) pursuant to which the parties agreed to amend the terms of the Series B warrants to include a floor of $3.00 per share in the calculation of the reset provision included in the Series B warrants. Accordingly, the aggregate maximum number of shares of Common Stock underlying the Series B Warrants held by the Modification Investors is 1,913,043 shares of which 1,800,000 were exercised.

As additional consideration for the modification of the Series B Warrants, the Company agreed to issue to the Modification Investors new five-year Series C warrants (“Series C Warrants”) to purchase 2.5 million shares of Common Stock with a cash exercise price of $3.00 per share. The Series C Warrants include a provision under which the Series C Warrants must be exercised at the election of the Company by the Modification Investors for cash if the closing sales price of the Common Stock is $6.00 per share or greater for 20-consecutive trading days. As a result of the issuance of the Warrants and the Series C Warrants, the exercise prices and number of shares underlying the Series A warrants and Series B warrants held by the remaining investor in the July Offering were adjusted pursuant to their terms.

In connection with the July 15, 2011 private placement offering, we granted to the investors registration rights pursuant to a Registration Rights Agreement, dated July 15, 2011, in which we agreed to register all of the related private placement common shares and common shares underlying the Series A warrants within forty-five (45) calendar days after July 15, 2011, and use its best efforts to have the registration statement declared effective within one hundred twenty (120) calendar days (or 150 calendar days upon a full review by the SEC). We will be required to pay to each investor an amount in cash equal to 3% of the investor’s purchase price in the event the Company fails to file the initial registration statement with the SEC, or otherwise, 1% of the aggregate purchase price paid by such investor, as applicable if we fail to comply with the terms of the Registration Rights Agreement and certain other conditions, on each monthly anniversary. Shares distributed were calculated based on the price of issuance of $3.50 per share for the February 1, 2011 private placement offering and $5.75 per share for the March 31, 2011 placement. In November 2011, the Company remitted 459,074 penalty shares, calculated by dividing the respective cash value of each private placements penalty by the respective unit price under which each private placement was funded. For the year ended December 31, 2011, the Company recognized $2,019,943 of delinquent registration penalties which are included in general and administrative expenses in the accompanying consolidated statement of operations.

The net proceeds from these private placements have been and will be used for operating purposes and to fund drilling and development activities, and acquisitions from the XOG Group.

In addition, we may also seek to utilize various financing sources, including the issuance of (i) fixed and floating rate debt, (ii) convertible securities, (iii) preferred stock, (iv) common stock and (v) other securities. We may also sell assets and issue securities in exchange for oil and natural gas related assets.

Credit Agreement.On September 21, 2011, Nevada ASEC, referred to herein as the Borrower, entered into a Credit Agreement (the “Credit Agreement”) with the lenders party thereto and Macquarie Bank Limited as administrative agent, referred to herein as Macquarie Bank. The Credit Agreement provides to the Borrower a revolving credit facility in an amount not to exceed $100 million and a term loan facility in an amount not to exceed $200 million. The interest rate on revolving loans is 30, 60 or 90 day LIBOR, as selected by the Borrower, plus a margin of 2.75% to 3.25% per annum, based on the borrowing base utilization, and the interest rate on term loans is 30, 60 or 90 day LIBOR, as selected by the Borrower, plus a margin of 7.50%. The maturity date of the revolving credit facility is September 21, 2015 and the maturity date of the term loan facility is September 21, 2014. The Borrower also has the option to borrow at the Base Rate plus margins from 1.75% to 2.25%.

In connection with the Credit Agreement, we issued to Macquarie Americas Corp., referred to herein as Macquarie Americas, a five year warrant (the “Macquarie Warrant”) to purchase five million (5,000,000) shares of our common stock at a per share exercise price of $7.50, subject to certain adjustments. The warrant provisions provided that it was exercisable on a cashless basis if there was no registration statement covering the underlying common stock and was also subject to customary anti-dilution provisions.

Convertible Note. On February 10, 2012, the Company and ASEN 2, Corp., a wholly-owned subsidiary of the Company closed on a Note and Warrant Purchase Agreement dated February 9, 2012 with Pentwater Equity Opportunities Master Fund Ltd. and PWCM Master Fund Ltd., referred herein to as Pentwater in connection with a $20 million private financing. The initial funding made by Pentwater to ASEN 2 on February 10, 2012, referred to as the Pentwater the Closing Date was in the amount of $10 million. The second funding for an additional $10 million, which closed on March 5, 2012, occurred concurrently with the closing of the purchase and sale agreement by and among the Company, Geronimo and XOG.

The borrowings under the Purchase Agreement are evidenced by a $20 million secured convertible promissory note, referred to herein as (the “Pentwater Note”) convertible into shares of the Company’s common stock at a conversion price of $9.00 per share and five year warrants to purchase 3,333,333 shares of common stock at a per share cash exercise price of $2.50. The Warrants are also subject to a mandatory exercise at the Company’s option with respect to (i) 50% of the number of shares underlying the Warrants if the closing sale price of the common stock is equal to or greater than $5.00 per share for twenty consecutive trading days and (ii) 50% of the number of Warrant Shares if the closing sale price of the common stock is equal to or greater than $9.00 per share for twenty consecutive trading days.

Pursuant to a Registration Rights Agreement dated February 9, 2010, we have agreed to register the Warrant Shares and Series C Warrant Shares, on a registration statement to be filed with the Securities and Exchange Commission (the “Registration Statement”) within one hundred twenty (120) days after the Subsequent Funding (as defined below) (the “Filing Date”) and to obtain effectiveness of such Registration Statement within one hundred eighty (180) days after the Filing Date (the “Effectiveness Date”). The Company has also agreed to keep the Registration Statement effective until the earlier of (i) the sale of all the Warrant Shares and Series C Warrant Shares covered by such Registration Statement or (ii) the date the Warrant Shares and Series C Warrant Shares may be sold pursuant to Rule 144. If the Company (i) does not file the Registration Statement by the Filing Date, (ii) does not obtain effectiveness of the Registration Statement by the Effectiveness Date or (iii) allows certain lapses in effectiveness (each an “Event”), the Company is obligated to pay to Pentwater liquidated damages equal to 0.5% of the borrowed principal amount under the Note for every thirty (30) days after the occurrence of an Event until cured, up to a maximum of 6%. The Company did not obtain effectiveness of the Registration Statement by the Effectiveness Date.

On July 23, 2012, the Company, as guarantor, and ASEN 2 entered into a First Amendment to Note and Warrant Purchase Agreement (the “Purchase Agreement Amendment”) with Pentwater Equity Opportunities Master Fund Ltd. and PWCM Master Fund Ltd. (collectively, “Pentwater”). Pursuant to the Purchase Agreement Amendment, Pentwater advanced to ASEN 2 an additional $5 million and ASEN 2 delivered an Amended and Restated Secured Convertible Promissory Note in the amount of $25 million which is guaranteed by the Company. All other material terms of the original Note and Warrant Purchase Agreement and Secured Convertible Promissory Note dated February 9, 2012 remain unchanged and in full force and effect.

The transactions under the Second Amendment and Asset Purchase Agreement closed on September 13, 2012.

Pentwater Warrant Restructure. On February 9, 2012, the Company, Pentwater and two affiliated entities of Pentwater, referred to herein as the Modification Investors, entered into a modification agreement, referred to herein as the Modification Agreement, pursuant to which the parties agreed to amend the terms of the Series B warrants, referred to herein as the Series B Warrants, issued to the Modification Investors in a $13 million private placement offering of the Company’s securities in July 2011, referred to herein as the July Offering, in which the Modification Investors invested $12 million. Pursuant to the terms of the Modification Agreement, the parties agreed to limit the dilutive effects of the Series B Warrants by including a floor of $3.00 per share in the calculation of the reset provision included in the Series B Warrants. Accordingly, the aggregate maximum number of shares of common stock underlying the Series B Warrants held by the Modification Investors is 1,913,043 shares.

Liquidity.Our principal sources of short-term liquidity are cash on hand and operational cash flow. At December 31, 2012, we had cash and cash equivalents of $717,622. Our short term cash commitments are primarily for drilling costs. These drilling costs are discretionary in nature; however, if the Company elects not to participate in such drilling costs, the Company could forfeit certain rights to receive revenues from production from the proposed well or to participate in and receive revenues from future wells in the related contract area.

The Company failed to make the interest payment due and owing on July 1, 2013 to Pentwater; however, the Company has received a 60-day deferment on the interest due July 1 and a 30-day deferment on the interest due August 1, 2013 under the Amended and Restated Secured Convertible Promissory Note issued by Pentwater. The Company has failed to make the interest payment due and owing July 1, 2013 to Macquarie but has not received a notice of default from Macquarie. Currently, the Company is evaluating options pursuant to which it can refinance its currently outstanding debt to each of Pentwater and Macquarie.

Contractual Obligations

Employment Agreements.At December 31, 2012, our contractual obligations include employment agreements with executive officers for the years ending December 31, 2013 through 2014 are as follows:

	2013		2014
Scott Feldhacker	$	306,000	$	102,000
Richard Macqueen		306,000		102,000
Total Contractual Obligations Related to Employment Contracts	$	612,000	$	204,000

On April 16, 2013, the Company and each of Mr. Feldhacker and Mr. MacQueen entered into a Separation Agreement dated as of April 16, 2013, as amended by that Amendment No. 1 to Separation Agreement, dated April 30, 2013, pursuant to which each of Mr. Feldhacker and Mr. MacQueen will retire two business days following the filing of the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2012 with the Securities and Exchange Commission

Operating Leases.We lease our 4,092 square foot primary office facilities in Scottsdale, Arizona under a non-cancellable operating lease agreement, dated December 31, 2010, for a 66-month term. The lease provides for no lease payments during the first six months and a reduced square footage charge for the first year. The initial rental is $23.00 per square foot, beginning February 1, 2011, and increasing $0.50 per square foot annually thereafter. For the year ended December 31, 2012, the Company recorded lease expense of $87,594.

At December 31, 2012, the future minimum lease commitments under the non-cancellable operating leases for each of the following five years ending December 31 are as follows:

2013	$	97,356
2014		99,402
2015		101,448
2016		42,625
Total	$	340,831

Pentwater Note.From the Pentwater Closing Date through December 8, 2012, the outstanding borrowings under the Pentwater Note bear an interest rate of 11% per annum, payable as follows (i) interest at a rate of 9% per annum is payable on the first business day of each month, commencing on March 1, 2012 and (ii) interest at a rate of 2% per annum is capitalized and added to the then unpaid principal amount monthly in arrears on the first business day of each month commencing on March 1, 2012. On and after December 9, 2012 through the maturity date, the Pentwater Note bears an interest rate of 16% per annum, payable as follows: (i) interest at a rate of 11% per annum is payable on the first business day of each month commencing on December 1, 2012 and (ii) interest at a rate of 5% per annum is capitalized and added to the then unpaid principal amount monthly on the first business day of each month commencing on December 1, 2012. The Pentwater Note had a maturity date of February 9, 2015, which was amended on March 5, 2012 to December 1, 2013. ASEN 2 can prepay the Pentwater Note without penalty prior to December 31, 2012. If the prepayment occurs after December 31, 2012, ASEN 2 must pay to Pentwater 106% of the then outstanding principal amount of the Pentwater Note that is prepaid. At any time after February 9, 2013, the principal amount and interest of the Pentwater Note may be converted into shares of common stock at a conversion price of $9.00 per share. On July 23, 2012, the Company and ASEN 2 entered into a First Amendment to Note and Warrant Purchase Agreement (the “Purchase Agreement Amendment”) with Pentwater. In connection with the Purchase Agreement Amendment, Pentwater advanced to ASEN 2 an additional $5 million and ASEN 2 delivered an Amended and Restated Secured Convertible Promissory Note (the “Amended Pentwater Note”) in the amount of $25 million which is guaranteed by the Company. All other material terms of the original Note and Warrant Purchase Agreement and the Pentwater Note dated February 9, 2012 remain unchanged and in full force and effect.

The transactions under the Second Amendment and Asset Purchase Agreement closed on September 13, 2012.

Retirement Agreement. On September 12, 2012, Robert J. Thompson resigned as directors on the Company’s board of director and from all committees of the board. The Company and Mr. Thompson entered into a Retirement Agreement pursuant to which the parties agreed to terminate the Director Agreement entered into on May 23, 2011. Additionally, the Company agreed to provide certain retirement compensation in the amount of $100,000 which shall be payable as follows:

$25,000 on the Resignation Date;

$50,000 on January 2, 2013; and

$25,000 on March 31, 2013.

Geronimo Note. On March 5, 2012, the Company acquired leasehold working interests in approximately 72,300 net developed and undeveloped acres across the Permian Basin, the Bakken, the Eagle Ford, the Niobrara, the Eagle Bine, and the Gulf Coast (collectively, the “March 2012 Properties”) from a related party. In conjunction with this transaction, the Company entered into a $35,000,000 promissory note (the “Geronimo Note”) made by the Company in favor of Geronimo. The Geronimo Note bears an interest rate of 7% per annum, which shall be increased to 9% per annum upon an event of default, payable on the first business day of each month commencing on June 1, 2012. The Geronimo Note matures on March 21, 2016. The Company may prepay the Geronimo Note at any time without penalty. The Geronimo Note secures certain indemnification and other liabilities under the PSA. On June 30, 2012, the Company exchanged the Geronimo Note for convertible preferred stock. Please see Note E - Long Term Debt for additional information.

Macquarie Credit Facility. On September 21, 2011, the Company entered into a credit agreement which provided to the Company a revolving credit facility in an amount not to exceed $100 million and a term loan facility in an amount not to exceed $200 million. The interest rate on revolving loans is 30, 60 or 90 day LIBOR, as selected by the Borrower, plus a margin of 2.75% to 3.25% per annum (3.25% at December 31, 2012), based on the borrowing base utilization, and the interest rate on term loans is 30, 60 or 90 day LIBOR, as selected by the Borrower, plus a margin of 7.50%. The maturity date of the revolving credit facility is September 21, 2015 and the maturity date of the term loan facility is September 21, 2014.

In order to comply with the terms of the credit agreement, Nevada ASEC must maintain the following financial ratios:

Current Ratio. Commencing December 31, 2011, Nevada ASEC will maintain a Current Ratio (the ratio of (i) Nevada ASEC’s current assets to (ii) Nevada ASEC’s current liabilities) of at least 1.00 to 1.00.

Debt Coverage Ratio. Commencing on the last day of the fiscal quarter following any fiscal quarter in which there are, on any day that fiscal quarter, no outstanding advances under the Term Loan, Nevada ASEC shall maintain a Debt Coverage Ratio of no more than 3.50 to 1.00. “Debt Coverage Ratio” shall mean, as of the last day of any fiscal quarter, the ratio of (i) Nevada ASEC’s debt to (ii) Nevada ASEC’s EBITDA for the four (4) most recent fiscal quarters occurring in whole or in part after closing;provided that (x) for the first fiscal quarter after the closing date, the Debt Coverage Ratio will be calculated using Nevada ASEC’s EBITDA for that first fiscal quartermultiplied by four; (y) for the second fiscal quarter after the closing date, the Debt Coverage Ratio will be calculated using Nevada ASEC’s aggregate EBITDA for those first two fiscal quartersmultiplied by two; and (z) for the third fiscal quarter after the closing date, the Debt Coverage Ratio will be calculated using Nevada ASEC’s aggregate EBITDA for those first three fiscal quartersmultiplied by one and one-third (1.33).

Interest Coverage Ratio. Commencing December 31, 2011, Nevada ASEC will maintain an Interest Coverage Ratio (the ratio of (a) Nevada ASEC’s EBITDA for the period which is the lesser of (i) the actual number of fiscal quarters which has or have elapsed since the closing date and (ii) the four (4) most recent fiscal quarters to (b) Nevada ASEC’s aggregate interest expense for all debt for the same period) of at least 2.50 to 1.00.

The Borrower was in default under the Credit Agreement for failing to comply with the current ratio covenant for quarter ended March 31, 2012 and for failing to pay certain debts prior to December 31, 2011. The defaults were waived by Macquarie on May 10, 2012.

The Borrower failed to comply with the current ratio covenant and incurred general and administrative expenses in excess of the limit contained in the Credit Agreement, in each case for the calendar quarter ended September 30, 2012. The covenant violations were waived by Macquarie on November 13, 2012.

Pursuant to the terms of the credit agreement, the Company implemented the initial Hydrocarbon price risk management program. At the request of the administrative agent, the Company must dedicate a percentage of the volume of PDP Reserves volumes (not to exceed 85% of those volumes) projected to be produced prior to the earlier of (a) three years after the closing date or (b) the maturity date to a Hydrocarbon price risk management program approved by Administrative Agent in its reasonable discretion. Any gain or loss for volume adjustments will be for Nevada ASEC’s account.

The outstanding balance on the term loan was $2,841,352 at December 31, 2012. On March 21, 2013, the Company will begin making monthly payments to amortize the term loan, each payment equal to the total outstanding term loan balance on that date divided by 18. Based on the outstanding balance of the term loan on December 31, 2012, the Company expects to pay $1,420,676 in each of the years 2013 and 2014.

At December 31, 2012, our future contractual obligations under the Pentwater Note and Macquarie Credit facility, including interest, for the following three years ending December 31 are as follows:

2013		29,248,753
2014		1,915,447
2015		13,440,112
Total	$	44,604,312

Critical Accounting Policies and Practices

Our consolidated financial statements and related notes thereto contain information that is pertinent to our management’s discussion and analysis of financial condition and results of operations. Preparation of the Company’s consolidated financial statements in conformity with accounting principles generally accepted in the United States requires that management make estimates, judgments and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and the disclosure of contingent assets and liabilities. However, the accounting principles used by the Company generally do not change the Company’s reported cash flows or liquidity. Interpretation of the existing rules must be done and judgments made on how the specifics of a given rule apply to the Company.

In management’s opinion, the more significant reporting areas impacted by management’s judgments and estimates are revenue recognition, the choice of accounting method for oil and natural gas activities, oil and natural gas reserve estimation, asset retirement obligations, impairment of long-lived assets and valuation of stock-based compensation. Management’s judgments and estimates in these areas are based on information available from both internal and external sources, including engineers, geologists and historical experience in similar matters. Actual results could differ from the estimates, as additional information becomes known.

Liquidity

Our principal sources of short-term liquidity are cash on hand and operational cash flow. At December 31, 2012, we had cash and cash equivalents of $717,622. Our short term cash commitments are primarily for drilling costs. These drilling costs are discretionary in nature; however, if the Company elects not to participate in such drilling costs, the Company could forfeit certain rights to receive revenues from production from the proposed well or to participate in and receive revenues from future wells in the related contract area.

Going Concern

In addition to the deficiencies noted above, the capital expenditures required to maintain and/or grow production and reserves are substantial. The Company’s stock price has significantly declined over the past year which makes it more difficult to obtain equity financing on acceptable terms to address our liquidity issues. In addition, the Company is reporting negative working capital at December 31, 2012 and a third consecutive year of net losses for the year ended December 31, 2012, which is largely the result of non-cash stock based compensation and impairments of the Company’s oil and natural gas properties. Therefore, there is substantial doubt as to the Company’s ability to continue as a going concern for a period longer than the current fiscal year. The Company’s ability to continue as a going concern is dependent upon the success of its financial and strategic alternatives process, which may include the sale of some or all of the assets, a merger or other business combination involving the Company or the restructuring or recapitalization of the Company. Until the possible completion of the financial and strategic alternative process, the Company’s future remains uncertain and there can be no assurance that its efforts in this regard will be successful.

The accompanying consolidated financial statements have been prepared in accordance with generally accepted accounting principles applicable to going concern, which implies that the Company will continue to meet its obligations and continue its operations for the next twelve months. Realization value may be substantially different from carrying values as shown, and these consolidated financial statements do not include any adjustments relating to the recoverability or classification of recorded asset amounts or the amount and classification of liabilities that might be necessary as a result of this uncertainty.

Successful Efforts Method of Accounting

The Company utilizes the successful efforts method of accounting for its oil and natural gas properties. Under this method all costs associated with productive wells and nonproductive development wells are capitalized, while nonproductive exploration costs are expensed. Capitalized acquisition costs relating to proved properties are depleted using the unit-of-production method based on proved reserves. The depletion of capitalized exploratory drilling and development costs is based on the unit-of-production method using proved developed reserves on a field basis.

Proceeds from the sales of individual properties and the capitalized costs of individual properties sold or abandoned are credited and charged, respectively, to accumulated depletion. Generally, no gain or loss is recognized until the entire amortization base is sold. However, a gain or loss is recognized from the sale of less than an entire amortization base if the disposition is significant enough to impact the depletion rate of the remaining properties in the amortization base materially. Ordinary maintenance and repair costs are expensed as incurred.

Costs of unproved properties, wells in the process of being drilled and significant development projects are excluded from depletion until such time as the related project is developed and proved reserves are established or impairment is determined. These unproved oil and natural gas properties are periodically assessed for impairment by considering future drilling plans, the results of exploration activities, commodity price outlooks, planned future sales or expiration of all or a portion of such projects. Amounts capitalized to oil and natural gas properties, but excluded from depletion at December 31, 2012 and 2011 were approximately $83,895,000 and $25,213,000, respectively. Such costs are related to drilling in progress and wells recently drilled and in various stages of testing and completion.

The Company reviews its long-lived assets to be held and used, including proved oil and natural gas properties, whenever events or circumstances indicate that the carrying value of those assets may not be recoverable. An impairment loss is indicated if the sum of the expected undiscounted future cash flows is less than the carrying amount of the assets. In this circumstance, the Company would recognize an impairment loss for the amount by which the carrying amount of the asset exceeds the estimated fair value of the asset.

The Company reviews its oil and natural gas properties by amortization base or by individual well for those wells not constituting part of an amortization base. For each property determined to be impaired, an impairment loss equal to the difference between the carrying value of the properties and the estimated fair value (discounted future cash flows) of the properties would be recognized at that time. Estimating future cash flows involves the use of judgments, including estimation of the proved and unproved oil and natural gas reserve quantities, timing of development and production, expected future commodity prices, capital expenditures and production costs.

Asset Retirement Obligations

There are legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and the normal operation of a long-lived asset. The primary impact of this on the Company relates to oil and natural gas wells on which we have a legal obligation to plug and abandon. The Company records the fair value of a liability for an asset retirement obligation in the period in which it is incurred and, generally, a corresponding increase in the carrying amount of the related long-lived asset. The determination of the fair value of the liability requires the Company to make numerous judgments and estimates, including judgments and estimates related to future costs to plug and abandon wells, future inflation rates and estimated lives of the related assets.

Impairment of Long-Lived Assets

All of the Company’s long-lived assets are monitored for potential impairment when circumstances indicate that the carrying value of an asset may be greater than its future net cash flows, including cash flows from risk adjusted proved reserves. The evaluations involve a significant amount of judgment since the results are based on estimated future events, such as future sales prices for oil and natural gas, future costs to produce these products, estimates of future oil and natural gas reserves to be recovered and the timing thereof, the economic and regulatory climates and other factors. The need to test an asset for impairment may result from significant declines in sales prices or downward revisions to estimated quantities of oil and natural gas reserves. Any assets held for sale are reviewed for impairment when the Company approves the plan to sell. Estimates of anticipated sales prices are highly judgmental and subject to material revision in future periods. Because of the uncertainty inherent in these factors, the Company cannot predict when or if future impairment charges will be recorded.

Valuation of Stock-Based Compensation

The Company is required to expense all options and other stock-based compensation that vested during the year based on the fair value of the award on the grant date. The calculation of the fair value of stock-based compensation requires the use of estimates to derive the inputs necessary for using the various valuation methods utilized by us. The Company utilizes the Black-Scholes option pricing model to measure the fair value of stock options. Expected volatilities are based on implied volatilities from the historical volatility of companies similar to the Company. The expected term of the options granted used in the Black-Scholes model represent the period of time that options granted are expected to be outstanding. The Company utilizes the simplified method for calculating the expected life of its options as the Company does not have sufficient historical data to provide a basis upon which to estimate the term.

Recent Accounting Pronouncements

Recently Adopted

Fair Value Measurement — In May 2011, the FASB issued Fair Value Measurement (Topic 820) — Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs (ASU No. 2011-04), which provides clarifications regarding existing fair value measurement principles and disclosure requirements, and also specific new guidance for items such as measurement of instruments classified within stockholders’ equity. These requirements were effective for interim and annual periods beginning after December 15, 2011. The Company implemented the accounting and disclosure guidance effective January 1, 2012, and the implementation did not have a material impact on its financial statements. For required fair value measurement disclosures, see Note J.

Recently Issued

Balance Sheet Offsetting — In December 2011, the FASB issued Balance Sheet (Topic 210) — Disclosures about Offsetting Assets and Liabilities (ASU No. 2011-11), which requires disclosures regarding netting arrangements in agreements underlying derivatives, certain financial instruments and related collateral amounts, and the extent to which an entity’s financial statement presentation policies related to netting arrangements impact amounts recorded to the financial statements. These disclosure requirements do not affect the presentation of amounts in the balance sheets, and are effective for annual reporting periods beginning on or after January 1, 2013, and interim periods within those annual reporting periods. The Company does not expect the implementation of this disclosure guidance to have a material impact on its financial statements.

Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Not applicable.

Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Our consolidated financial statements and supplementary financial data are included in this Annual Report on Form 10-K beginning with page F-1.

Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

Item 9A. CONTROLS AND PROCEDURES

(a) Management’s Annual Report on Internal Control over Financial Reporting

As of the end of the period covered by this report, we carried out an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer (our principal executive officer) and Chief Financial Officer (our principal financial officer), of the effectiveness of our disclosure controls and procedures as defined in Rule 13a-15(e) of the Exchange Act. Based upon that evaluation our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures as defined in Rule 13a-15(e) of the Exchange Act were not effective as of the end of the period covered by this report to ensure that information required to be disclosed by the Company in the reports that the Company files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Our disclosure controls and procedures are expected to include controls and procedures designed to ensure that information required to be disclosed in reports filed or submitted under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure.

The Company has identified three material weaknesses in its internal controls, and as such did not maintain effective internal control over financial reporting. These weaknesses involve (1) the inadequate controls over the recording of impairment on proved properties, (2) inadequate controls over the write off of debt costs and debt discounts for payments on debt and (3) inadequate controls over the valuation of warrants.

(b) Changes in Internal Control over Financial Reporting

During the year ended December 31, 2012, management continued to implement a program to appropriately address the effectiveness of internal controls with the objective to be in compliance with Rule 13a-15(e) of the Exchange Act as follows:

Accounting Department.The Company has hired a Senior Accountant to assist in reviewing, monitoring and preparing financial reports.

Accounting Software and Supporting Records. The Company completed implementing an oil and gas accounting software system in January of 2012. This system is used as the core system for all financial data and internal controls since the Company’s formation and the acquisition of oil and gas properties.

Documentation of Internal Control Systems.The Company has completed the process of documenting all internal control systems and the Company has completed the process of implementing these controls to be fully compliant with SEC Rule 1-02 (4).

Changes in Internal Controls over Financial Reporting

The Company believes the steps listed above enhanced our internal control over financial reporting and reduce control deficiencies.

Item 9B. OTHER INFORMATION

Not applicable.

PART III

Item 10. DIRECTORS, EXECUTIVE OFFICES AND CORPORATE GOVERNANCE

Directors and Executive Officers

The following table sets forth the names, ages, positions and dates of appointment of our current directors and executive officers.

Name	Age	Position	Date Appointed
Scott Feldhacker (a)	45	Chief Executive Officer	October 1, 2010
Richard MacQueen (b)	46	President	October 1, 2010
Randall Capps	57	Director	October 11, 2010
William “Bill” Killian	48	Director	April 4, 2011
Wayne M. Squires	58	Chairman of the Board and Director	September 12, 2012
H.H. Wommack, III	57	Director	February 12, 2013
Charles “Rusty” Pickering	44	Director	February 12, 2013
Michael Pedrotti	51	Director	February 12, 2013
J. Steven Person	54	Director	February 12, 2013

(a)

On April 16, 2013, the Company and Mr. Feldhacker entered into a Separation Agreement dated as of April 16, 2013, as amended by that Amendment No. 1 to Separation Agreement, dated April 30, 2013, pursuant to which Mr. Feldhacker will retire two business days following the filing of the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2012 with the Securities and Exchange Commission.

(b)

On April 16, 2013, the Company and Mr. MacQueen entered into a Separation Agreement dated as of April 16, 2013, as amended by that Amendment No. 1 to Separation Agreement, dated April 30, 2013, pursuant to which Mr. MacQueen will retire two business days following the filing of the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2012 with the Securities and Exchange Commission.

The business background descriptions of our directors and officers are as follows:

SCOTT FELDHACKER — Chief Executive Officer

Scott Feldhacker is our founding chief executive officer and until February 2013 served on our board of directors. Mr. Feldhacker is co-founder of Nevada ASEC in April 2010. He was worked in the family oil and gas exploration and production (“E&P”) businesses with Randall Capps since 2001 by assisting with financial relationships, the structuring of both acquisitions and sales of producing assets, leaseholds and rights of way, new development, and field operation activities including auditing utility usage per leasehold. Since April 2011, Mr. Feldhacker also serves as an officer and director of McCaFe Energy Partners Inc., a development stage infrastructure, natural gas exploration and alternative energy investment company. Prior to founding Nevada ASEC, from January 2009 to December 2010, he co-founded and served as a managing member of Fusion Capital LLC, a consulting firm that consulted for both private and public companies in various industries including oil and gas E&P companies that provided general business consulting and advisory services including deal structuring of acquisition and divestures of assets and pre- and post-listing management guidance. From February 2005 to December 2010, Mr. Feldhacker co-founded and served as the Managing Member of DreamTick LLC, a consulting firm which placed its focus on emerging markets, consulting with private companies entering the U.S. capital markets via share exchanges and other structures, providing post-listing public company guidance, market awareness support and successfully assisting navigation to senior exchange listings. From 1995 to 2004, he gained entrepreneurial success over diverse industries as an owner and officer. In 1991, Mr. Feldhacker began as a Wealth Manager for Allmerica Financial then Mass Mutual Oppenheimer. Mr. Feldhacker attended University of Arizona from 1985 to 1986, Arizona State University from 1987 to 1988, and Santa Barbara City College from 1989 to 1991. Mr. Feldhacker began his post-secondary education in business management before switching to Engineering and Computer Science. Mr. Feldhacker left to accept an offer with Allmerica Financial in 1991.

RICHARD MACQUEEN — President

Richard MacQueen is our founding president and until February 2013 served on our board of directors. Mr. MacQueen is the co-founder of Nevada ASEC in April 2010. Prior to founding Nevada ASEC, from January 2009 to December 2010, he co-founded and served as a managing member of Fusion Capital LLC, a consulting firm that consulted for both private and public companies in various industries including oil and gas E&P companies that provided general business consulting and advisory services including deal structuring of acquisition and divestures of assets and pre- and post-listing management guidance. Since April 2011, Mr. MacQueen also serves as an officer and director of McCaFe Energy Partners Inc., a development stage infrastructure and natural gas exploration and alternative energy investment company. From February 2005 to December 2010, Mr. MacQueen co-founded and served as a member of DreamTick LLC, a consulting firm which placed its focus on emerging markets, consulting with private companies entering the U.S. capital markets via share exchanges and other structures, providing post-listing public company guidance, market awareness support and successfully assisting navigation to senior exchange listings. From July 2005 to June 2008, Mr. MacQueen served as the Western Regional Territory Manager for UltraRad Corp., a radiology software company he previously represented through his technical sales firm. From 2001 to 2005, Mr. MacQueen operated a technical sales firm which supported companies in the aerospace, medical, high speed low skew and automotive industries, including several Fortune 500 companies. Prior to 2011, Mr. MacQueen developed, owned and operated a restaurant chain covering three states throughout the Southwest. Mr. MacQueen attended Western Illinois University from 1984 to 1986 and Arizona State University (ASU) in the business track from 1988 to 1990. Mr. MacQueen left ASU to devote his time to the development of his restaurant business.

RANDALL CAPPS — Director

Mr. Capps is the largest stockholder of the Company and has more than 36 years of experience in the E&P oil and gas industry. His experience began with Texaco Inc. and more recently as owner of several E&P companies. Since August 2004, Mr. Capps has served as the managing member and sole owner of XOG Operating, LLC, a seasoned exploration and operation company based in Midland, Texas, which has developed and operated oil and gas properties in 14 states. Since August 1996, he has also served as the president and sole owner of Geronimo Holding Corporation, which holds oil and gas interests as well as several supporting oil and gas companies. Mr. Capps graduated from New Mexico State University with an undergraduate degree in business in 1977.

WILLIAM “BILL” KILLIAN — Director

From July 2010 to the present, Mr. Killian has served as the managing partner of Texas Operations at Texas Jack Waste Holdings and has oversight of all Texas operations for this solid waste management company focusing on growth and expansion. Mr. Killian previously served as general manager/managing partner of Pima Waste of Tucson from April 2006 through December 2009 prior to selling the company to Waste Management. He also served as general manager of West Valley Business Units at Allied Waste from 2002-2006, general manager/managing partner of City-Waste of Arizona from 2000 until its successful sale to Allied Waste in 2002 and as operations manager/general manager of Laidlaw/Allied Waste Lake Havasu from 1994-2000. Mr. Killian attended Mohave Community College in Lake Havasu, Arizona from 1995 to 1997. We believe that Mr. Killian’s extensive entrepreneurial and business experience brings important experience and leadership to the Board of Directors.

WAYNE M. SQUIRES— Director

Mr. Squires was appointed as a director in September 2012. He also serves as a member of the Audit Committee. Mr. Squires has 31 years of experience in the energy services. Mr. Squires currently serves as president and chief executive officer of Orion Drilling Company, LLC., a company he co-founded in 2003. He also co-founded Pioneer Drilling Company and was president from 1989 to 2000. His other experience includes being president of PRC Drilling Co.

H. H WOMMACK, III— Director

H. H. Wommack, III has 35 years of experience in the oil and gas industry. Mr. Wommack is currently president and sole board member of Pyote Water Systems, LLC, an owner and operator of salt water disposal wells in Texas and New Mexico. Mr. Wommack also serves on the board of C&J Energy Services, Inc., a publicly traded oilfield services company, and on the board of Globe Energy Services, L.L.C., a leading oilfield services company with operations in Texas, New Mexico, Oklahoma and Kansas. Mr. Wommack is President and CEO of Saber Oil and Gas Ventures, LLC, a company involved with domestic exploration, production and sale of natural gas and crude oil. From 1997 until December 2000, Mr. Wommack served as chairman of the board of directors of Basic Energy Services, Inc., a company engaged in the oil and gas service business, and from December 2000 until June 2009 served on Basic’s board of directors. H. H. Wommack, III is a principal of Saber Oil, LLC, which is the holder of irrevocable proxies allowing Saber Oil, LLC voting rights over 55.55% of the outstanding common stock of the Company beneficially owned by affiliates of Randall Capps.

CHARLES “RUSTY” PICKERING — Director

Rusty Pickering is the General Counsel and Chief Compliance and Corporate Development Officer for Chexar Networks, Inc. Prior to joining Chexar, Mr. Pickering was a senior partner in the Atlanta office of Nelson Mullins Riley & Scarborough, an AmLaw 200 Firm, where he spent over 17 years building a successful legal practice representing companies and private equity firms in the areas of public and private securities law, corporate governance, regulatory compliance, mergers and acquisitions, joint ventures, and technology licensing. Rusty has had significant experience representing financial technology companies, serving from 2000 – 2002 as the in-house General Counsel of a Nasdaq listed core banking system provider. Mr. Pickering received his BS in Biomedical Engineering from Tulane University and his JD cum laude from the University of Texas School of Law. He is a member of the State Bar of Georgia, a former Director of the Business & Finance Section of the Atlanta Bar, a former Director of the Entrepreneurs Foundation of the Southeast, President-Elect of the Tulane Alumni Association, an annual judge of the Georgia Tech Business Plan Competition, and an active member of the Association for Financial Technology.

MICHAEL S. PEDROTTI — Director

Mr. Pedrotti has 27 years of experience in the oil and gas exploration industry. He began his career as a petroleum landman with TXO Production Corp. (”TXO”) in 1985, working South Texas and the Texas Gulf Coast. After leaving TXO, he worked as an independent landman doing day work as well as working with independent geologists putting together prospects, raising drilling capital and bringing these prospects to a drill-ready stage. With early success in La Gloria Field in Brooks County, Texas, and Bold Forbes Field in Duval County, Texas, Mr. Pedrotti formed and was president of Pedrotti Oil and Gas, Inc. (1989-present). He then helped form and became president of each of LMP Petroleum, Inc. (1993-present) and LMP Exploration, Inc. (2003-2009). In 2004, Mr. Pedrotti caused the merger of LMP Exploration, Inc. into LMP Exploration Holdings and LMP Exploration Operating with private equity partners Greenhill Capital and Lime Rock Partners and was president of both of these companies. LMP Exploration Holdings drilled 29 wells in 3 years and sold all of its assets in January 2008. Mr. Pedrotti then began assembling a new prospect inventory and formed Venture Geo-Exploration Company, LLC in September 2010. In March 2011, Venture Geo-Exploration Company, LLC merged with Shore Petroleum Corp. to form SV Energy Company, LLC, where Mr. Pedrotti serves as CEO. In January of 2012, Mr. Pedrotti and Rajan Ahuja formed SV Resource Partners LLC (SVRP) with Greenhill Capital Partners for the purpose of acquiring producing oil and gas properties. Since inception, SVRP has acquired two fields, producing a combined 1,200 BOED. Mr. Pedrotti is both president and CEO of SVRP. Mr. Pedrotti is responsible for partner relations, capitalization, land, legal, and management of the day-to-day activities of the company. Mr. Pedrotti holds a bachelor of science degree in agriculture economics from Texas A&M University in College Station, Texas.

J. STEVEN PERSON — Director

J. Steven Person is currently the Chief Executive Officer of Cibolo Creek Partners, a real estate development company, and Vice President - Finance of Saber Oil & Gas Ventures, an E&P oil and gas company. Mr. Person served as the Vice President, Marketing of Southwest Royalties from 1989 until May 2004 when Southwest Royalties merged with and into Clayton Williams Energy, Inc. Mr. Person began in the investment industry with Dean Witter in 1983. Prior to joining Southwest Royalties, Mr. Person was a senior wholesaler with Capital Realty, Inc. While at Capital Realty, he was involved in the syndication of mortgage based securities through the major brokerage houses. Mr. Person serves on the board of directors of Globe Energy Services, an oil and gas service company. Mr. Person received a B.B.A. degree from Baylor University and an M.B.A. from Houston Baptist University.

Code of Ethics

We have adopted a Code of Ethics that applies to our principal executive officer, principal financial and accounting officer, controller and persons performing similar functions. We will provide to any person, without charge, upon request, a copy of such Code of Ethics, as amended. Requests should be addressed to the address appearing on the cover page of this Annual Report on Form 10-K, Attn: Corporate Secretary.

Corporate Governance

Term of Office

Our directors are appointed for a one-year term to hold office until the next annual meeting of our stockholders until their successors are duly appointed and qualified or until removed from office in accordance with our bylaws. Our officers are appointed by our board of directors and hold office until removed by our board of directors. Except as set forth in the section entitled "Executive Compensation," there are no agreements with respect to the election of directors. Our bylaws provide that officers are appointed annually by our board of directors and each executive officer serves at the discretion of our board of directors. We have entered into separation agreements, as amended, with each of our executive officers. Please refer to “Executive Compensation—Employment Agreements” for a discussion of the material terms of the separation agreements between the Company and each of the named executive officers identified in the “Executive Compensation–Summary Compensation Table.”

Director Independence

We use the definition of “independence” of The NASDAQ Stock Market to make this determination. NASDAQ Listing Rule 5605(a)(2) provides that an “independent director” is a person other than an officer or employee of the company or any other individual having a relationship which, in the opinion of the Company’s board of directors, would interfere with the exercise of independent judgment in carrying out the responsibilities of a director. The NASDAQ listing rules provide that a director cannot be considered independent if:

the director is, or at any time during the past three years was, an employee of the company;

the director or a family member of the director accepted any compensation from the company in excess of $120,000 during any period of 12 consecutive months within the three years preceding the independence determination (subject to certain exclusions, including, among other things, compensation for board or board committee service);

a family member of the director is, or at any time during the past three years was, an executive officer of the company;

the director or a family member of the director is a partner in, controlling stockholder of, or an executive officer of an entity to which the company made, or from which the company received, payments in the current or any of the past three fiscal years that exceed 5% of the recipient’s consolidated gross revenue for that year or $200,000, whichever is greater (subject to certain exclusions);

the director or a family member of the director is employed as an executive officer of an entity where, at any time during the past three years, any of the executive officers of the company served on the compensation committee of such other entity; or

the director or a family member of the director is a current partner of the company’s outside auditor, or at any time during the past three years was a partner or employee of the company’s outside auditor, and who worked on the company’s audit.

We have determined that Messrs. Squires, Pickering, Pedrotti, Wommack and Killian are “independent” directors as defined by applicable SEC rules and NASDAQ Stock Market listing standards.

Board Committees

Our board of directors has an Audit Committee, a Compensation Committee and a Corporate Governance and Nominating Committee. Each committee’s members and certain other information regarding each committee are described below.

Audit Committee

The Audit Committee is comprised entirely of “independent” directors as defined by applicable SEC rules and NASDAQ Stock Market listing standards. The current members of our Audit Committee are Messrs. Squires and Pickering. Neither Messrs. Squires nor Pickering meet the “financial expert” requirement as defined by SEC Rules. Therefore, one position on the Audit Committee remains vacant until the Board is able to recruit a director who will qualify as a “financial expert.”

Compensation Committee

The Compensation Committee is comprised entirely of “independent” directors as defined by applicable SEC rules and NASDAQ Stock Market listing standards. The current members of our Compensation Committee are Messrs. Wommack and Pedrotti.

Corporate Governance and Nominating Committee

The Corporate Governance and Nominating Committee (“CGNC”) is comprised entirely of “independent” directors as defined by applicable SEC rules and NASDAQ Stock Market listing standards. The current member of our Corporate Governance and Nominating Committee is Mr. Killian.

The CGNC of the Board of Directors has established the Fairness Committee as a standing sub-committee of the CGNC. The Fairness Committee is appointed by the CGNC to complete independent assessments of the fairness to non-related party stockholders, and other non-affiliated stakeholders, of proposed or completed transactions by the Company that might represent conflicts of interests between the company and its affiliates and other related parties. The current member of this subcommittee is Mr. Killian.

Board Leadership Structure and Role in Risk Oversight

Leadership of our board of directors is vested in a Chairman of the Board. Although our Chief Executive Officer currently does not serve as Chairman of the Board of Directors, we currently have no policy prohibiting our current or any future chief executive officer from serving as Chairman of the Board. The board of directors, in recognizing the importance of its ability to operate independently, determined that separating the roles of Chairman of the Board and Chief Executive Officer is advantageous for us and our shareholders.

Family Relationships

Scott Feldhacker, our Chief Executive Officer, is the son-in-law of Randall Capps. Mr. Capps is a member of our board of directors and the sole owner of XOG and Geronimo and the majority owner of CLW. Through these indirect and direct ownership interests, Mr. Capps is currently the majority holder of our common stock; provided, however, that Mr. Capps has granted proxies to Saber Oil, LLC for all of the Company's shares of common stock beneficially owned by his affiliates. For a list of specific transactions, see the section entitled“Transactions with Related Persons, Promoters, and Certain Control Persons.”

Involvement in Certain Legal Proceedings

To our knowledge, during the past ten years, none of our directors, executive officers, promoters, control persons, or nominees has:

been convicted in a criminal proceeding or been subject to a pending criminal proceeding (excluding traffic violations and other minor offenses);

had any bankruptcy petition filed by or against the business or property of the person, or of any partnership, corporation or business association of which he was a general partner or executive officer, either at the time of the bankruptcy filing or within two years prior to that time;

been subject to any order, judgment, or decree, not subsequently reversed, suspended or vacated, of any court of competent jurisdiction or federal or state authority, permanently or temporarily enjoining, barring, suspending or otherwise limiting, his involvement in any type of business, securities, futures, commodities, investment, banking, savings and loan, or insurance activities, or to be associated with persons engaged in any such activity;

been found by a court of competent jurisdiction in a civil action or by the SEC or the Commodity Futures Trading Commission to have violated a federal or state securities or commodities law, and the judgment has not been reversed, suspended, or vacated;

been the subject of, or a party to, any federal or state judicial or administrative order, judgment, decree, or finding, not subsequently reversed, suspended or vacated (not including any settlement of a civil proceeding among private litigants), relating to an alleged violation of any federal or state securities or commodities law or regulation, any law or regulation respecting financial institutions or insurance companies including, but not limited to, a temporary or permanent injunction, order of disgorgement or restitution, civil money penalty or temporary or permanent cease-and-desist order, or removal or prohibition order, or any law or regulation prohibiting mail or wire fraud or fraud in connection with any business entity; or

been the subject of, or a party to, any sanction or order, not subsequently reversed, suspended or vacated, of any self-regulatory organization (as defined in Section 3(a)(26) of the Exchange Act), any registered entity (as defined in Section 1(a)(29) of the Commodity Exchange Act), or any equivalent exchange, association, entity or organization that has disciplinary authority over its members or persons associated with a member.

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Securities Exchange Act of 1934 requires our officers and directors, and persons who beneficially own more than 10% of a registered class of our equity securities, to file reports of ownership and changes in ownership with the SEC. Officers, directors and greater than 10% owners are required by certain SEC regulations to furnish us with copies of all Section 16(a) forms they file.

Based solely on our review of the copies of such forms received by it, we believe that during 2012, there was compliance with the filing requirements applicable to its officers, directors and 10% common stockholders.

Item 11. EXECUTIVE COMPENSATION

The following sets forth information with respect to the compensation awarded or paid to our Chief Executive Officer and the two most highly compensated executive officers during the fiscal years ended December 31, 2012 and 2011 (collectively, the “named executive officers”) for all services rendered in all capacities to us and our subsidiaries in fiscal 2012 and 2011.

Summary Compensation Table

The following table sets forth information regarding each element of compensation that we paid or awarded to our named executive officers for fiscal years 2012 and 2011.

														Non-equity		Nonqualified
								Stock			Option			incentive plan		deferred
Name and Principal			Salary					Awards			Awards			compensation		compensation		All Other			Total
Position	Year		($)			Bonus ($)		($)			($)(1)			($)		earnings ($)		Compensation			($)
Scott Feldhacker		2012		304,808	(2)		-		46,800			59,379			-		-		642,763	(3)		1,053,750
Chief Executive Officer		2011		210,750			-		-			16,001,333			-		-		-			16,212,083

Richard MacQueen		2012		299,942	(2)		-		46,800			59,379			-		-		673,647	(4)		1,079,768
President		2011		210,750			-		-			16,001,333			-		-		-			16,212,083

Scott Mahoney		2012		190,806	(5)		-		0	(5)		0	(5)		-		-		98,241	(6)		289,047
Chief Financial Officer		2011		159,333			-		-			2,892,000			-		-		-			3,051,333

(1) The amounts reported in this column reflect the aggregate grant date fair value of option awards computed in accordance with FASB ASC Topic 718 for stock options granted in 2011 and 2012 to each named executive officer. The amounts do not reflect compensation actually received by the named executive officers. The amounts reported in this column for Messrs. Feldhacker and MacQueen for fiscal year 2011 reflect the grant date fair market value of option awards to purchase (i) 3,200,000 shares of our common stock granted pursuant to their respective employment agreements in 2011, and (ii) 600,000 shares of our common stock granted pursuant to their respective employment agreements and option awards to purchase 800,000 shares of our common stock pursuant to their respective deferred compensation plans in 2010. The amounts reported in this column for Messrs. Feldhacker and MacQueen for fiscal year 2012 reflect the grant date fair market value of option awards to purchase (i) 20,000 shares of restricted common stock granted as of March 30, 2012, (ii) 2,000,000 shares of our common stock granted pursuant to their respective employment agreements in 2011, which such grant was amended and restructured on March 30, 2012, and (iii) 600,000 shares of our common stock granted pursuant to their respective employment agreements and option awards to purchase 800,000 shares of our common stock pursuant to their respective deferred compensation plans in 2010. The amounts reported in this column for Mr. Mahoney reflect the grant date fair market value of option awards granted pursuant to his employment agreement. Please see “Employment Agreements” and “Deferred Compensation Plan” below.

(2) Mr. Feldhacker and Mr. MacQueen each received a base salary equal to $300,000. Salary amount reported in the table above includes vacation pay earned in 2012 and paid to the executive.

(3) The amount reported in this column reflect (i) the federal taxes in the amount of $246,588 paid by the Company in 2012 for the benefit of Mr. Feldhacker for the founders stock beneficially owned as of 2011 by Mr. Feldhacker, (ii) reimbursement of $13,002, the amount of monies withheld for federal tax withholding purposes for founders stock beneficially owned by Mr. Feldhacker in 2011, (iii) the gross-up payments in the amount of $377,173 paid by the Company to Mr. Feldhacker for the founders stock beneficially owned as of 2012 by Mr. Feldhacker, and (iv) a $500 per month car allowance.

(4) The amount reported in this column reflect (i) the federal taxes in the amount of $259,567 paid by the Company in 2012 for the benefit of Mr. MacQueen for the founders stock beneficially owned as of 2011 by Mr. MacQueen, (ii) reimbursement of $13,686, the amount of monies withheld for federal tax withholding purposes for founders stock beneficially owned by Mr. MacQueen in 2011, (iii) the gross-up payments in the amount of $394,394 paid by the Company to Mr. MacQueen for the founders stock beneficially owned as of 2012 by Mr. MacQueen, and (iv) a $500 per month car allowance.

(5) Mr. Mahoney received a salary equal to $190,806 through November 24, 2012 when Mr. Mahoney resigned. Pursuant to a Redemption of Common Stock agreement by and between the Company and Mr. Mahoney, effective April 25, 2013, Mr. Mahoney assigned all of his right, title and interest in all of his shares of common stock of the Company to the Company, such that as of the date of this filing Mr. Mahoney no longer owns any shares of common stock of the Company. Mr. Mahoney has acknowledged to the Company that all his options have been forfeited pursuant to the terms of the awards.

(6) The amount reported in this column reflect (i) the federal taxes in the amount of $26,051 paid by the Company in 2012 for the benefit of Mr. Mahoney for the founders stock beneficially owned as of 2011 by Mr. Mahoney, (ii) reimbursement of $1,374, the amount of monies withheld for federal tax withholding purposes for founders stock beneficially owned by Mr. Mahoney in 2011 (iii) the gross-up payments in the amount of $30,566 paid by the Company to Mr. Mahoney for the founders stock beneficially owned as of 2012 by Mr. Mahoney, (iv) a $500 per month car allowance, and (v) a $35,000 severance payment following his resignation.

Employment Agreements

Each of the named executive officers executed employment agreements on April 15, 2010 with Nevada ASEC, which we adopted on October 1, 2010 pursuant to the Share Exchange. All stock options and deferred stock option compensation plans were subject to a 2-for-1 forward split when we entered into the share exchange agreement (the “Share Exchange”) with Nevada ASEC on October 1, 2010. The founders’ stock grants were subject to a 2-for-1 forward split pursuant to the Share Exchange. The terms of the employment agreements for each named executive officer are summarized below on a post-split basis.

Scott Feldhacker

On April 15, 2010, Nevada ASEC entered into an employment agreement with Scott Feldhacker which we adopted on October 1, 2010 pursuant to the Share Exchange. The term of the employment agreement is four years. Unless earlier terminated, the agreement shall be automatically extended for an additional one-year period unless either party notifies the other in writing at least 30 days prior to the expiration of the original term of its or his election not to extend the agreement.

The agreement provides for a monthly base salary of $12,000 which began in January 2011. Effective as of April 1, 2011, the Compensation Committee approved an increase in Mr. Feldhacker’s monthly base salary to $18,750. Effective as of March 30, 2012, the Compensation Committee approved an increase in Mr. Feldhacker’s monthly base salary to $25,000. In accordance with his agreement, on April 15, 2010, Mr. Feldhacker was granted 600,000 stock options which vest at a rate of 20% annually, commencing on January 1, 2011 and thereafter on August 15 of each year of the term of the employment agreement. In addition, on April 1, 2011, Mr. Feldhacker received (i) 800,000 stock options, of which 400,000 options vest every six months beginning on October 15, 2011 and (ii) 2,400,000 stock options under the Equity Incentive Plan, of which 600,000 options vest every six months beginning on October 15, 2012. The agreement further provides that Mr. Feldhacker will be entitled to all benefits of employment provided to other employees of the Company in comparable positions during the employment term. In addition, Mr. Feldhacker is entitled to an automobile allowance of $500 per month.

On April 16, 2013, the Company and Mr. Feldhacker entered into a Separation Agreement dated as of April 16, 2013, as amended by that Amendment No. 1 to Separation Agreement, dated April 30, 2013 (collectively, the “Feldhacker Separation Agreement”), pursuant to which Mr. Feldhacker will retire two business days following the filing of the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2012 with the Securities and Exchange Commission (the “Feldhacker Employment Separation Date”), as Chief Executive Officer of the Company. The Feldhacker Separation Agreement provides that (1) the Company and Mr. Feldhacker will enter into a Consulting Agreement for a period of three months beginning on the day immediately following Feldhacker Employment Separation Date (the “Consulting Term”), and pursuant to which, Mr. Feldhacker will serve as a consultant to the Company, for which the Company will pay to Mr. Feldhacker $37,500 in the aggregate over the Consulting Term; (2) the Company has no obligation to pay Mr. Feldhacker any severance amounts; (3) Mr. Feldhacker will retain 242,347 shares of the Company common stock designated as “Founders Stock” that were to vest on April 16, 2013 and the 242,347 shares of the Company common stock designated as “Founders Stock” that were to vest on April 16, 2014, and such Founders Stock shall become vested immediately without any further action on the part of the Company or Mr. Feldhacker; (4) Mr. Feldhacker will retain the options granted under the Company’s 2010 Amended and Restated Equity Incentive Plan for 2,600,000 shares of common stock and the 41,152 options granted under the Company’s 2011 Equity Incentive Plan, subject to the terms of such Plans; and (5) Mr. Feldhacker will retain the options granted by the Company as deferred compensation in 2010 for 800,000 shares of common stock, which terminate on April 15, 2020.

The Feldhacker Separation Agreement also contains non-disparagement, non-solicitation, standstill and confidentiality provisions as well as a general release and covenant not to sue.

A Form 8-K was filed with the SEC on each of April 22, 2013 and May 6, 2013 regarding the execution of the Feldhacker Separation Agreement.

Richard MacQueen

On April 15, 2010, Nevada ASEC entered into an employment agreement with Richard MacQueen which we adopted on October 1, 2010 pursuant to the Share Exchange. The term of the employment agreement is four years. Unless earlier terminated, the agreement shall be automatically extended for an additional one-year period unless either party notifies the other in writing at least 30 days prior to the expiration of the original term of its election not to extend the agreement.

The agreement provides for a monthly base salary of $12,000 which began in January 2011. Effective as of April 1, 2011, the Compensation Committee approved an increase in Mr. MacQueen’s monthly base salary to $18,750. Effective as of March 30, 2012, the Compensation Committee approved an increase in Mr. Feldhacker’s monthly base salary to $25,000. In accordance with his agreement, on April 15, 2010, Mr. MacQueen was granted 600,000 stock options which vest at a rate of 20% annually, commencing on January 1, 2011 and thereafter on August 15 of each year of the term of the employment agreement. In addition, on April 1, 2011, Mr. MacQueen received (i) 800,000 stock options, of which 400,000 options vest every six months beginning on October 15, 2011 and (ii) 2,400,000 stock options, of which 600,000 options vest every six months beginning on October 15, 2012. The agreement further provides that Mr. MacQueen will be entitled to all benefits of employment provided to other employees of the Company in comparable positions during the employment term. In addition, Mr. MacQueen is entitled to an automobile allowance of $500 per month.

On April 16, 2013, the Company and Mr. MacQueen entered into a Separation Agreement dated as of April 16, 2013, as amended by that Amendment No. 1 to Separation Agreement, dated April 30, 2013 (collectively, the “MacQueen Separation Agreement”) pursuant to which Mr. MacQueen will retire two business days following the filing of the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2012 with the Securities and Exchange Commission (the “MacQueen Employment Separation Date”), as President of the Company. The MacQueen Separation Agreement provides that (1) the Company and Mr. MacQueen will enter into a Consulting Agreement for a period of three months beginning on the day immediately following MacQueen Employment Separation Date (the “Consulting Term”), and pursuant to which, Mr. MacQueen will serve as a consultant to the Company, for which the Company will pay to Mr. MacQueen $37,500 in the aggregate over the Consulting Term; (2) the Company has no obligation to pay Mr. MacQueen any severance amounts; (3) Mr. MacQueen shall retain the 255,103 shares of the Company common stock designated as “Founders Stock” that were to vest on April 16, 2013 and the 255,103 shares of the Company common stock designated as “Founders Stock” that were to vest on April 16, 2014, and such Founders Stock shall become vested immediately without any further action on the part of the Company or Mr. MacQueen; (4) Mr. MacQueen will retain the options granted under the Company’s 2010 Amended and Restated Equity Incentive Plan for 2,600,000 shares of common stock and the 41,152 options granted under the Company’s 2011 Equity Incentive Plan, subject to the terms of such Plans; and (5) Mr. MacQueen will retain the options granted by the Company as deferred compensation in 2010 for 800,000 shares of common stock, which terminate on April 15, 2020. Beginning on May 1, 2013 through the MacQueen Employment Separation Date, the Company will pay to Mr. MacQueen a salary in the amount equal to $1.00.

The MacQueen Agreement also contains non-disparagement, non-solicitation, standstill and confidentiality provisions as well as a general release and covenant not to sue.

A Form 8-K was filed with the SEC on each of April 22, 2013 and May 6, 2013 regarding the execution of the MacQueen Separation Agreement

Scott Mahoney

On April 15, 2010, Nevada ASEC entered into an employment agreement with Scott Mahoney which we adopted on October 1, 2010 pursuant to the Share Exchange. The term of the employment agreement was four years. Unless earlier terminated, the agreement would have been automatically extended for an additional one-year period unless either party notified the other in writing at least 30 days prior to the expiration of the original term of its election not to extend the agreement.

The agreement provided for a monthly base salary of $12,000 which began in September 2010. Effective as of April 1, 2011, the Compensation Committee approved an increase in Mr. Mahoney’s monthly base salary to $16,667. In accordance with his agreement, on April 15, 2010, Mr. Mahoney was granted 400,000 stock options which vest at a rate of 20% annually, commencing on January 1, 2011 and thereafter on August 15 of each year of the term of the employment agreement. In addition, Mr. Mahoney was entitled to receive a minimum of 600,000 stock options per year under the Equity Incentive Plan on each anniversary of the date of his employment agreement, which would have vested semi-annually over one year beginning 180 days following the date of initial issuance. Mr. Mahoney was granted an additional 600,000 options on April 15, 2011, which award was subsequently amended on March 30, 2012 to restate the award for 1,500,000 options. The agreement further provided that Mr. Mahoney would have been entitled to all benefits of employment provided to other employees of the Company in comparable positions during the employment term. In addition, Mr. Mahoney was entitled to an automobile allowance of $500 per month.

Pursuant to the agreement, in the event Mr. Mahoney is terminated by the Company due to his disability or in the event of his death, Mr. Mahoney, or his estate in the case of his death, would have been entitled to the following: any unpaid base salary and any accrued vacation and holidays through the date of termination; any unpaid bonus accrued with respect to the fiscal year ending on or preceding the date of termination; reimbursement for any unreimbursed expenses properly incurred through the date of termination; and all other payments or benefits to which Mr. Mahoney may be have been entitled under the terms of any applicable employee benefit plan and all granted but unvested stock awards would have become immediately fully vested (collectively, the “Accrued Benefits”).

On November 24, 2012, the Company and Mr. Mahoney entered into a Separation Agreement (the “Mahoney Separation Agreement”) which provided that the Company would pay to Mr. Mahoney, and Mr. Mahoney’s consulting firm, Catalyst Corporate Solutions, L.L.C., certain compensation. The Mahoney Separation Agreement also contained non-disparagement, non-solicitation, standstill and confidentiality provisions as well as a general release and covenant not to sue. As of the date of this filing, the Company has paid a total of $60,000 to Mr. Mahoney and a total of $5,000 to Catalyst Corporate Solutions, L.L.C., pursuant to the Mahoney Separation Agreement.

On April 25, 2013, the Company and Mr. Mahoney entered into a confidential Settlement and Release Agreement which voided the Mahoney Separation Agreement, and under which the Company is no longer obligated to make any additional payments in any form to Mr. Mahoney.

Equity Incentive Plan

In connection with the acquisition of Nevada ASEC on October 1, 2010, we adopted our Equity Incentive Plan (the “2010 Plan”) and ratified an amendment to such 2010 Plan on August 29, 2011, subject to the effectiveness of the shareholder approval. The 2010 Plan is designed to attract, retain and motivate our officers, employees, non-management directors and consultants. The maximum number of shares of our common stock that may be issued pursuant to grants or awards under the 2010 Plan, as amended, is 12,000,000 shares.

The 2010 Plan is administered by the Compensation Committee. The Compensation Committee may make awards under the Plan in the form of stock options (both qualified and non-qualified) and restricted stock. The Compensation Committee has authority to designate the recipients of such awards, to grant awards, to determine the form of award and to fix all terms of awards granted all in accordance with the 2010 Plan. Incentive stock options intended to qualify under Section 422A of the Internal Revenue Code may be granted only to employees of the Company and must have an exercise price equal to 100% of the fair market value of our common stock on the grant date (110% in the case of incentive options granted to any 10% stockholder of the Company) and may not exceed a term of ten years (five years in the case of incentive options granted to any 10% stockholder of the Company). Non-qualified stock options and other awards may be granted on such terms as the Compensation Committee may determine.

On March 30, 2012, the Compensation Committee amended and restructured the previously owned equity grants awarded to the Company’s officers and directors. Accordingly, the Compensation Committee approved the acceleration of the vesting of certain options (the “2010 Options”) granted to our three executive officers, Scott Feldhacker to purchase 1,400,000 shares of common stock, Richard MacQueen to purchase 1,400,000 shares of common stock and Scott Mahoney to purchase 400,000 shares of common stock, under the 2010 Plan that originally vested periodically through 2014, such that the 2010 Options are immediately exercisable. The exercise price, number of shares and expiration date of the 2010 Options remain unchanged. The 2010 Options granted to Mr. Mahoney have been forfeited pursuant to the terms of the option awards and Mr. Mahoney has acknowledged such forfeiture.

In 2011, we adopted a new Stock Incentive Plan (the “2011 Plan”), pursuant to which we approved and reserved 10,000,000 shares of common stock for issuance to our employees, officers, directors and outside advisors.

Deferred Compensation Program

On April 15, 2010, the Company’s Board of Directors approved the 2010 Deferred Compensation Program. Under this plan, the President and CEO are entitled to receive a one-time fee consisting of common stock options in lieu of salary through June 30, 2011. The total number of options granted under the plan was 1,600,000 in lieu of salary through December 31, 2010. The exercise price of the options is $1.50 and the options vest over 26.5 months. These options have a ten year life and had a grant date fair value of $1.09 per share. 400,000 of these shares were exercised and converted to shares of stock as of June 30, 2011. The rescission of the exercise of such option was approved by our board on August 29, 2011 and the exercised shares were returned to the Company. On March 30, 2012, the Compensation Committee amended and restructured these options such that the options became immediately vested. For the years ended December 31, 2012 and 2011, the Company recorded non-cash stock compensation expense of $394,868 and $789,736, respectively, related to the amortization of the fair value of these options which is included in general and administrative expenses.

Restricted Stock Awards

On February 13, 2012, the Board approved the immediate vesting of a total of 1,568,877 restricted shares of the Company’s common stock previously issued to the chief executive officer, president and chief financial officer as founders shares which were to vest in equal portions annually through April 16, 2014. On December 28, 2012, Mr. Feldhacker and Mr. Macqueen each executed a Rescission Agreement to rescind the Founders Shares that were granted acceleration. On December 31, 2012, the Board by written consent reinstated the original vesting schedule for the Founders Shares.

Outstanding Equity Awards at Fiscal Year-End

	Option Awards									Stock Awards
Name	Number of securities underlying unexercised options exercisable (#)		Number of securities underlying unexercised options unexercisable (#)		Equity incentive plan awards: Number of securities underlying unexercised unearned options (#)		Option exercise price per share ($)		Option expiration date	Number of shares or units of stock that have not vested (#)			Market value of shares or units of stock that have not vested ($)

Scott Feldhacker	800,000	(1)		0		0	$	1.5	15-Apr-20		484,694	(3)		222,959
	600,000	(1)		0		0	$	1.5	15-Aug-20
	2,000,000	(1)		0		0	$	2.43	1-Apr-21
	41,152	(1)		0		0	$	2.43	30-Mar-22
Richard MacQueen	800,000	(1)		0		0	$	1.5	15-Apr-20		510,206	(4)		234,695
	600,000	(1)		0		0	$	1.5	15-Aug-20
	2,000,000	(1)		0		0	$	2.43	1-Apr-21
	41,152	(1)		0		0	$	2.43	30-Mar-22
Scott Mahoney	400,000	(2)		0		0	$	1.5	15-Aug-20		0			0
	1,500,000	(2)		0		0	$	2.43	15-Apr-21
	41,152	(2)		0		0	$	2.43	30-Mar-22

(1)

Vested in full on March 30, 2012.

(2)

Vested in full on March 30, 2012. As of the date of the filing of this Annual Report on Form 10-K, each of these options have expired due to Mr. Mahoney not exercising the options within three months of his resignation from the Company as required under the terms and conditions of each option award.

(3)

242,347 shares vested as of April 16, 2013. Pursuant to the Separation Agreement, as amended, by and between Mr. Feldhacker and the Company, 242,347 shares will vest two business days following the filing of the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2012.

(4)

255,103 shares vested as of April 16, 2013. Pursuant to the Separation Agreement, as amended, by and between Mr. MacQueen and the Company, 255,103 shares will vest two business days following the filing of the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2012.

Compensation of Directors

As of the date of the filing of this Annual Report on Form 10-K, the Compensation Committee recommended and the Board approved on May 3, 2013 that the compensation for each of the Board members will equal (i) $1,500 paid to each Board member for attending a Board meeting, whether in person or telephonically, (ii) $1,000 paid to each Board member for attending a Board committee meeting, whether in person or telephonically and (iii) $30,000 paid to each Board member on an annual basis as a retainer. The Board agreed and approved that the foregoing fees will be effective as of the reconstitution of the Board that occurred in February 2013, however, all fees will accrue but will not be paid to the Board members until the Company has been recapitalized.

The following table lists the compensation paid to our directors as of our last fiscal year ended December 31, 2012.

Name	Fees earned or paid in cash ($)			Stock awards ($)		Option awards ($)			Non-equity incentive plan compensation ($)		Nonqualified deferred compensation earnings ($)		All other compensation			Total ($)

Robert Thompson		49,000	(1)		-		437,381	(1)		-		-		26,500	(1)		512,881
Jim Leeton		16,000	(2)		-		74,770	(2)		-		-		-			90,770
William Killian		22,000	(3)		-		88,410	(3)		-		-		-			110,410
Scott David		16,000	(4)		-		74,588	(4)		-		-		-			90,588
Randall Capps		-			-		-			-		-		-			-
Wayne Squires		-			-		-			-		-		-			-

(1) Mr. Thompson received a monthly payment of $5000 from January through May 2012. His monthly payment increased to $6000, which he was paid from June through September 2012. Due to the Compensation Committee’s restructure of certain options on March 30, 2012, Mr. Thompson’s 300,000 options were amended to 700,000 options, which vested immediately and have an exercise price equal to $2.43. Mr. Thompson resigned as a director and pursuant to a Retirement Agreement, dated September 12, 2012, the Company agreed to pay to Mr. Thompson $25,000 on resignation date, $50,000 on January 2, 2013 and $25,000 on March 31, 2013. The Company also paid Mr. Thompson $500 per month from October through December 2012 for incidental expenses. As of the date of this Annual Form 10-K, the Company has not made any payments to Mr. Thompson that were due and payable in 2013.

(2) Mr. Leeton received a monthly payment equal to $2000 per month through the end of August 2012. Due to the Compensation Committee’s restructure of certain options on March 30, 2012, Mr. Leeton’s 30,000 options were amended to 80,000 options, which vested immediately and have an exercise price equal to $2.43. Mr. Leeton retired as a director on September 12, 2012, and due to such retirement, the options reported in the table above have expired pursuant to their terms.

(3) Mr. Killian received a monthly payment equal to $2000 per month, however such payment was not paid to Mr. Killian for December 2012. Due to the Compensation Committee’s restructure of certain options on March 30, 2012, Mr. Killian’s 30,000 options were amended to 90,000 options, which vested immediately and have an exercise price equal to $2.43.

(4) Mr. David received a monthly payment equal to $2000 per month through the end of August 2012. Due to the Compensation Committee’s restructure of certain options on March 30, 2012, Mr. David’s 30,000 options were amended to 80,000 options, which vested immediately and have an exercise price equal to $2.43. Mr. David retired as a director on September 12, 2012, and due to such retirement, the options reported in the table above have expired pursuant to their terms.

Directors are permitted to receive fixed fees and other compensation for their services as directors. The board of directors has the authority to fix the compensation of directors.

Director Agreements

Scott C. David

On April 4, 2011, we entered into a director agreement with Mr. David. Mr. David was appointed as a non-executive member of the Board of Directors (the “Board”) on April 1, 2011. The agreement provides for compensation and benefits as follows: a cash payment of $2,000 per month; an option to purchase 30,000 shares of the Company’s common stock upon execution of the agreement and upon each anniversary of the agreement during the directorship term; and reimbursement for all reasonable out-of-pocket expenses incurred by Mr. David by attending any in-person meetings.

The directorship term commenced on April 4, 2011 and terminates upon the earliest of the following to occur: (a) one (1) year from April 4, 2011, subject to a one (1) year renewal term upon re-election by a majority of the shareholders of the Company; (b) the death of Mr. David; (c) the termination of Mr. David from the position of member of the Board by mutual agreement of the company and Mr. David; (d) the removal of Mr. David from the Board by the shareholders of the Company; (e) the resignation by Mr. David from the Board if after April 4, 2011, the Chief Executive Officer of Mr. David’s current employer determines that Mr. David’s continued serviced on the Board conflicts with his fiduciary obligations to his current employer; and (f) the resignation by Mr. David from the Board if the board of directors or the Chief Executive Officer of his current employer requires Mr. David to resign and such resignation is not a fiduciary resignation as described in (e) above.

Additionally, the agreement provides that during the directorship term and for three (3) years thereafter, Mr. David will not interfere with the Company’s relationship, or endeavor to entice away from the Company, any person who on the date of termination of the directorship term is either an employee or customer of the Company, or otherwise had a material business relationship with the Company.

Mr. David resigned from the Board effective as of September 12, 2012.

William Killian

On April 4, 2011, we entered into a director agreement with Mr. Killian. Mr. Killian was appointed as a non-executive member of the Board on April 1, 2011. The agreement provides for compensation and benefits as follows: a cash payment of $2,000 per month; 30,000 stock options of the Company’s common stock upon execution of the agreement and upon each anniversary of the agreement during the directorship term; and reimbursement for all reasonable out-of-pocket expenses incurred by Mr. Killian by attending any in-person meetings.

The directorship term commenced on April 4, 2011 and terminated upon the earliest of the following to occur: (a) one (1) year from April 4, 2011, subject to a one (1) year renewal term upon re-election by a majority of the shareholders of the Company; (b) the death of Mr. Killian; (c) the termination of Mr. Killian from the position of member of the Board by mutual agreement of the company and Mr. Killian; (d) the removal of Mr. Killian from the Board by the shareholders of the Company; (e) the resignation by Mr. Killian from the Board if after April 4, 2011, the Chief Executive Officer of Mr. Killian’s current employer determines that Mr. Killian’s continued serviced on the Board conflicts with his fiduciary obligations to his current employer; and (f) the resignation by Mr. Killian from the Board if the board of directors or the Chief Executive Officer of his current employer requires Mr. Killian to resign and such resignation is not a fiduciary resignation as described in (e) above.

Additionally, the agreement provides that during the directorship term and for three (3) years thereafter, Mr. Killian will not interfere with the Company’s relationship, or endeavor to entice away from the Company, any person who on the date of termination of the directorship term is either an employee or customer of the Company, or otherwise had a material business relationship with the Company.

James R. Leeton, Jr.

On April 4, 2011, we entered into a director agreement with Mr. Leeton. Mr. Leeton was appointed as a non-executive member of the Board on March 15, 2011. The agreement provides for compensation and benefits as follows: a cash payment of $2,000 per month; an option to purchase 30,000 shares of the Company’s common stock upon execution of the agreement and upon each anniversary of the agreement during the directorship term; and reimbursement for all reasonable out-of-pocket expenses incurred by Mr. Leeton by attending any in-person meetings.

The directorship term commenced on April 4, 2011 and terminated upon the earliest of the following to occur: (a) one (1) year from April 4, 2011, subject to a one (1) year renewal term upon re-election by a majority of the shareholders of the Company; (b) the death of Mr. Leeton; (c) the termination of Mr. Leeton from the position of member of the Board by mutual agreement of the company and Mr. Leeton; (d) the removal of Mr. Leeton from the Board by the shareholders of the Company; (e) the resignation by Mr. Leeton from the Board if after April 4, 2011, the Chief Executive Officer of Mr. Leeton’s current employer determines that Mr. Leeton’s continued serviced on the Board conflicts with his fiduciary obligations to his current employer; and (f) the resignation by Mr. Leeton from the Board if the board of directors or the Chief Executive Officer of his current employer requires Mr. Leeton to resign and such resignation is not a fiduciary resignation as described in (e) above.

Additionally, the agreement provides that during the directorship term and for three (3) years thereafter, Mr. Leeton will not interfere with the Company’s relationship, or endeavor to entice away from the Company, any person who on the date of termination of the directorship term is either an employee or customer of the Company, or otherwise had a material business relationship with the Company.

Mr. Leeton resigned from the Board effective as of September 12, 2012.

Robert Thompson

On May 23, 2011, we entered into a director agreement with Mr. Thompson. Mr. Thompson was appointed as a non-executive member of the Board on December 1, 2010. On December 23, 2012, the Company announced that Mr. Thompson was elected as the Chairman of the Board. The agreement provides for a cash payment of $2,500 per month paid on the first of each month beginning December 2010. On December 1, 2011, Mr. Thompson’s monthly pay increased to $5,000. The agreement further references the stock option award for services rendered on December 1, 2010 pursuant to which Mr. Thompson was granted an option to purchase 300,000 shares of the Company’s common stock exercisable for 10 years from the grant date at an exercise price equal to the closing trading price of the Company’s stock as of the grant date. Of the shares underlying this option, 60,000 fully vested upon issuance, and the remaining shares underlying such option shall vest as to 30,000 shares on June 1 and December 1 of each year beginning June 1, 2011; provided, however, that if Mr. Thompson is no longer serving as a director, any unvested shares underlying such stock options shall be cancelled. In the event of a change in control the Company shall accelerate all stock awards that Mr. Thompson would have been entitled to receive through the expiration of the employment term whether or not vested as of the date of the change in control. During the directorship term, the Company shall reimburse Mr. Thompson for all reasonable out-of-pocket expenses incurred by Mr. Thompson in performance of his duties.

The directorship term commenced on May 23, 2011 and terminated upon the earliest of the following to occur: (a) five (5) years from May 23, 2011, subject to a one (1) year renewal term upon re-election by a majority of the shareholders of the Company; (b) the death of Mr. Thompson; (c) the termination of Mr. Thompson from the position of member of the Board by mutual agreement of the Company and Mr. Thompson; (d) the removal of Mr. Thompson from the Board by the shareholders of the Company; (e) the resignation by Mr. Thompson from the Board if after May 23, 2011 the Chief Executive Officer of Mr. Thompson’s current employer determines that Mr. Thompson’s continued serviced on the Board conflicts with his fiduciary obligations to his current employer; and (f) the resignation by Mr. Thompson from the Board if the board of directors or the Chief Executive Officer of his current employer requires Mr. Thompson to resign and such resignation is not a fiduciary resignation as described in (e) above.

100

Additionally, the agreement provides that during the directorship term and for three (3) years thereafter, Mr. Thompson will not interfere with the Company’s relationship, or endeavor to entice away from the Company, any person who on the date of termination of the directorship term is either an employee or customer of the Company, or otherwise had a material business relationship with the Company.

Mr. Thompson resigned from the Board effective September 12, 2012. Upon his resignation, Mr. Thompson and the Company entered into a final letter agreement pursuant to which the Company agreed to pay to Mr. Thompson total cash compensation equal to $100,000, which shall be paid as follows: $25,000 within five days of resignation, $50,000 on January 2, 2013, and $25,000 on March 31, 2013. The Company also agreed to pay to Mr. Thompson $500 per month for each of six months commencing October 1, 2012 for incidental expenses. Additional terms and conditions of the final letter agreement include that existing stock options which have vested will remain vested, the Company and Mr. Thompson will not disparage the other party’s reputation, and Mr. Thompson will retain the confidentiality of all trade secrets, proprietary data or other confidential information which were communicated to or otherwise learned or acquired by Mr. Thompson during his tenure as a member of the Board.

TAX CONSIDERATIONS

Section 162(m) of the Internal Revenue Code, or “Section 162(m),” disallows a tax deduction for any publicly held corporation for individual compensation exceeding $1 million in any taxable year for a company’s named executive officers, other than its chief financial officer, unless such compensation qualifies as “performance-based compensation” under such section. Section 162(m) does not apply to companies that are not publicly held and did not apply to compensation paid and awards granted by the company prior to its becoming a public company. Therefore, neither our Company Compensation Committee nor the Board of Directors took the deductibility limit imposed by Section 162(m) into consideration in setting compensation prior to the Company’s becoming publicly held.

Several awards granted after the Company became a public company may not comply with the “performance based compensation” exemption and, therefore, the Company may not be able to deduct amounts relating to such awards for Federal income tax purposes.

We expect that our Compensation Committee will seek to qualify the variable compensation paid to our named executive officers for an exemption from the deductibility limitations of Section 162(m). However, our Compensation Committee may, in its judgment, authorize compensation payments that do not comply with the exemptions in Section 162(m) when it believes that such payments are appropriate to attract and retain executive talent.

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Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

Common Stock

The following table sets forth certain information regarding our shares of common stock beneficially owned as of August 1, 2013, for (i) each stockholder known to be the beneficial owner of 5% or more of our outstanding shares of common stock, (ii) each named executive officer and director and (iii) all executive officers and directors as a group. A person is considered to beneficially own any shares: (i) over which such person, directly or indirectly, exercises sole or shared voting or investment power, or (ii) of which such person has the right to acquire beneficial ownership at any time within 60 days through an exercise of stock options or warrants. Unless otherwise indicated, voting and investment power relating to the shares shown in the table for our directors and executive officers is exercised solely by the beneficial owner or shared by the owner and the owner’s spouse or children.

For purposes of this table, a person or group of persons is deemed to have “beneficial ownership” of any shares of common stock that such person has the right to acquire within 60 days of August 1, 2013. For purposes of computing the percentage of outstanding shares of our common stock held by each person or group of persons named above, any shares that such person or persons has the right to acquire within 60 days of August 1, 2013 is deemed to be outstanding, but is not deemed to be outstanding for the purpose of computing the percentage ownership of any other person. The inclusion herein of any shares listed as beneficially owned does not constitute an admission of beneficial ownership.

The address for each beneficial owner, unless otherwise noted, is c/o American Standard Energy Corp. at 4800 North Scottsdale Road, Suite 1400, Scottsdale, AZ 85251.

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Name and Address of Beneficial Owner	Amount and Nature of Beneficial Ownership (#)(1)			Percentage of Class (%)(2)

Executive Officers and Directors

Scott Feldhacker		4,810,128	(3)		8.7	%
Chief Executive Officer

Richard MacQueen		4,922,671	(4)		9.0	%
President

Randall Capps		28,937,522	(5)		56.0	%
Director

William “Bill” Killian		124,014	(6)		*
Director

H.H. Wommack, III		40,533,428	(7)		64.0	%
Director

J. Steven Person		0			*
Director

Michael Pedrotti		0			*
Director

Charles “Rusty” Pickering		0			*
Director

All Executive Officers and Directors as a group (6 persons)		50,594,323	(8)		71.7	%

5% Shareholders

Geronimo Holding Corporation		21,642,821			41.9	%
1801 West Texas,
Midland, TX 79701

Saber Oil, LLC		40,533,428	(7)		64.0	%
400 West Illinois Avenue, Suite 950
Midland, Texas 79701

Pentwater Capital Management LP		5,086,517	(9)		9.9	%
227 West Monroe Suite 4000
Chicago, IL 60606

* less than 1%

(1)

Under Rule 13d-3, a beneficial owner of a security includes any person who, directly or indirectly, through any contract, arrangement, understanding, relationship, or otherwise has or shares: (i) voting power, which includes the power to vote, or to direct the voting of shares; and (ii) investment power, which includes the power to dispose or direct the disposition of shares. Certain shares may be deemed to be beneficially owned by more than one person (if, for example, persons share the power to vote or the power to dispose of the shares). In addition, shares are deemed to be beneficially owned by a person if the person has the right to acquire the shares (for example, upon exercise of an option) within 60 days of the date as of which the information is provided. In computing the percentage ownership of any person, the amount of shares outstanding is deemed to include the amount of shares beneficially owned by such person (and only such person) by reason of these acquisition rights.

(2)

Percentages are rounded to the nearest one-tenth of one percent. The percentage of class is based on 51,617,371 shares of Common Stock issued and outstanding as of August 1, 2013.

(3)

Includes (a) 3,441,152 shares of Common Stock underlying options that were exercisable within 60 days of August 1, 2013; (b) 61,224 shares of Common Stock held by Mr. Feldhacker’s wife; and (c) 1,307,752 shares of Common Stock, which include 484,694 shares of Common Stock designated as vested “Founders Stock”. Mr. Feldhacker is the son-in-law of Mr. Capps.

(4)

Includes (a) 3,441,152 shares of Common Stock underlying options that were exercisable within 60 days of August 1, 2013; (b) 102,041 shares of Common Stock held by Mr. MacQueen’s wife; and (c) 1,379,478 shares of Common Stock, which include 510,206 shares of Common Stock designated as vested “Founders Stock”.

(5)

Includes (a) 21,642,821 shares of Common Stock held by Geronimo; (b) 5,832,199 shares of Common Stock held by XOG; (c) 587,755 shares of Common Stock held by CLW; (d) 61,224 shares of Common Stock as legal guardian of Hayden Pitts; (e) 670,665 shares of Common Stock and 142,858 shares of Common Stock underlying warrants purchased in private placements. Mr. Capps is the sole owner of Geronimo and XOG and is the majority owner of CLW. Mr. Capps is the father-in-law of Mr. Feldhacker.

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(6)

Includes 34,014 shares of Common Stock and 90,000 shares of Common Stock underlying options that were exercisable as of the date of this annual report.

(7)

Effective February 18, 2013, Saber Oil, LLC purchased the 35,400 shares of the Series A Preferred Stock from Geronimo, which are convertible into 11,799,988 shares of Common Stock. In connection with the purchase of the Series A Preferred Stock, each of Randall Capps, Geronimo, XOG and CLW granted an irrevocable proxy to Saber Oil, LLC to vote all of the shares of common stock of the Company beneficially owned by Mr. Capps and the XOG Group. Mr. Wommack is the sole member and equity owner of Saber Oil, LLC and may therefore be deemed to be the beneficial owner of such shares. Mr. Wommack disclaims beneficial ownership of these shares of Common Stock, except to the extent of their pecuniary interest therein.

(8)

Does not include the 28,733,440 shares subject to irrevocable proxy held by Mr. Wommack as described in footnote 7.

(9)

Based on Schedule 13D filed by Pentwater Capital Management on November 5, 2012.

Changes in Control

Other than the right of first refusal granted to Saber Oil, LLC on the shares of Common Stock owned by affiliates of Randall Capps, which right of first refusal was granted in connection with the proxies for the Common Stock and sale of the Series A Preferred Stock to Saber Oil, LLC, we are not aware of any arrangements that may result in a change in control of the Company.

Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

The XOG Group.We are affiliated with and have a working relationship with XOG, a seasoned exploration and production operator based in Midland, Texas. As an operator, XOG has been operating, developing and exploiting the Permian Basin as well as operating in 14 other states for 30 years. XOG has been in the Bakken area for the past three years procuring mineral leasehold rights and participating in wells.

XOG is currently contracted to operate the existing wells currently held by us in the Permian Basin region. XOG historically performed this service for Geronimo and CLW. Randall Capps, our majority shareholder and director, has controlling ownership of Geronimo, XOG and CLW. Accordingly, these companies are considered related parties to the Company. As a result, all historical accounts payable related to accrued lease operating expenses and accrued drilling expenses presented are recorded as payables due to a related party. Additionally, as one of our operators, XOG is contractually obligated to sell the oil and natural gas on our behalf pursuant to joint operating agreements. For the year ended December 31, 2012, sales through XOG were $13,326,551 and lease operating expenses were $5,664,427.

Randall Capps is the sole owner of XOG and Geronimo and the majority owner of CLW. After the March 5, 2012 acquisition, through his direct ownership and his indirect ownership interest in the XOG Group, Mr. Capps’ ownership increased to approximately 54% of our outstanding common stock. Mr. Capps is also a member of the Company’s board of directors, and the father–in-law of our Chief Executive Officer, Scott Feldhacker.

104

We have acquired the following oil and natural gas properties from Geronimo, XOG and CLW:

Nevada ASEC was incorporated on April 2, 2010 for the purposes of acquiring certain oil and gas properties from Geronimo, XOG and CLW. On May 1, 2010, the XOG Group contributed certain oil and natural gas properties located in Texas and North Dakota to Nevada ASEC in return for 80% of the common stock of Nevada ASEC.

XOG continued to serve as operator of such properties. The oil and gas properties contributed by the XOG Group to Nevada ASEC consisted of seven completed and operating wells within the Permian Basin region of West Texas as well as approximately 10,600 acres of undeveloped leasehold rights in three primary regions: (i) the Bakken, (ii) the Eagle Ford and (iii) certain positions in the Permian Basin leased from the University of Texas.

On March 1, 2011, we acquired certain undeveloped mineral rights leaseholds held on approximately 10,147 net acres in the Bakken Shale Formation in North Dakota, referred to herein as the Bakken 2 Properties, from Geronimo in exchange for $3,000,000 cash and the issuance of 883,607 shares of the Company’s common stock valued at $5,787,626.

On April 8, 2011, we acquired undeveloped leasehold acreage consisting of approximately 2,780 net acres located in Mountrail County of North Dakota’s Williston Basin from Geronimo for $1.86 million paid in cash, which includes a $1.0 million down payment made on March 25, 2011.

On August 22, 2011, we acquired approximately 13,324 net undeveloped leasehold acres in the Bakken/Three Forks (the “Bakken 4 Properties”) area from Geronimo for approximately $14.6 million. A cash deposit of $13.5 million was made on April 15, 2011, and the Company subsequently issued 208,200 shares of common stock upon closing, which were valued at an aggregate of $1,093,050 based on a per share price of $5.25 on the closing date. The acquisition was recorded at fair value.

105

On March 5, 2012, we acquired leasehold working interests in approximately 72,300 net developed and undeveloped acres across the Permian Basin, Eagle Ford shale formation and the Eagle Bine in Texas, the Williston Basin in North Dakota, and the Niobrara shale formation in Wyoming and Nebraska referred to herein as the XOG Properties, from XOG and Geronimo (the “Sellers”) in exchange for the delivery by the Company to the Sellers of $10 million in cash, less the $1.5 million cash deposit previously paid by the Company, a note in the principal amount of $35,000,000 made by the Company in favor of Geronimo and 5,000,000 shares of the common stock of the Company valued at $2.70 per share based on the closing price of the common stock on March 5, 2012.

Overriding royalty and royalty interests. In some instances, XOG or Geronimo and CLW may hold overriding royalty and royalty interests (“ORRI”) in wells acquired by the Company. All revenues and expenses presented herein are net of any effects of ORRI.

Policies Related to Related Party Transactions

Conflicts of Interest and Fiduciary Duties

Conflicts of interest may arise as a result of the relationship between Randall Capps, who is a member of the Company’s board of directors and the majority stockholder of the Company, and the XOG Group, of which Mr. Capps owns all or a majority. All of our directors and officers have fiduciary duties to manage the Company in a manner beneficial to our stockholders. At the same time, Mr. Capps may also owe fiduciary duties to the equity holders of the XOG Group, to the extent the entities are not wholly-owned by Mr. Capps. The XOG Group is not restricted from competing with us. Our arrangement with Mr. Capps and the XOG Group may not prohibit Mr. Capps from engaging in any activities, including oil and natural gas exploration and production related activities, which are in direct competition with the Company. Therefore, affiliates of Mr. Capps, including the XOG Group, may compete with us for investment opportunities and may own an interest in entities that compete with us.

Each of J. Steven Person and H.H. Wommack, III is a member of our board of directors and is a principal of Saber Oil, LLC. Saber Oil, LLC is the holder of irrevocable proxies allowing Saber Oil, LLC voting rights over 55.55% of the outstanding common stock of the Company. This voting right over a majority of our issued and outstanding common stock allows Saber Oil, LLC to be able to exert significant control over decisions requiring stockholder approval, including the election of directors and approval of the sale of assets and other business combinations. Additionally, as members of our Board, Mr. Person and Mr. Wommack are aware of our business plans and may disagree with management’s day-to-day operations of the Company. Conflicts of interest may arise between Mr. Person, Mr. Wommack and Saber Oil, LLC, on the one hand, and the Company and our other stockholders, on the other hand. As a result of these conflicts, Mr. Person, Mr. Wommack and Saber Oil, LLC may favor their own interests over the interests of our stockholders.

106

Indemnification of Directors, Officers and Consultants

The Company’s Articles of Incorporation provide that no director, officer of or consultant to the corporation past, present or future, shall be personally liable to the corporation or any of its shareholders for damages for breach of fiduciary duty as a director or officer; provided, however, that the liability of a director for acts or omissions which involve intentional misconduct, fraud or knowing violation of law and for the payment of dividends is not so eliminated. The corporation shall advance or reimburse reasonable expenses incurred by an affected officer, director or consultant without regard to the above limitations, or any other limitation which may hereafter be enacted to the extent such limitation may be disregarded if authorized by the Articles of Incorporation. The Company’s bylaws provide for the indemnification of our directors and officers, as to those liabilities and on those terms and conditions as appropriate.

As of May 3, 2013, each member of the Board has executed an indemnification agreement with the Company. Each indemnification agreement provides that the Company shall defend and hold harmless each member of the Board, to the fullest extent permitted or required by the laws of the State of Delaware;provided, however, that, a member of the Board shall not be entitled to indemnification in connection with (i) any claim initiated by the Board member against the Company or any director or officer of the Company unless the Company has joined in or consented to the initiation of such Claim, or (ii) the purchase and sale by the Board member of securities in violation of Section 16(b) of the Securities Exchange Act of 1934, as amended. The Company acknowledges that its obligation arising under the indemnification agreements may be broader than now provided by applicable law and the Company’s Articles of Incorporation and intends that the indemnification agreements be interpreted as such.

Item 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

On October 1, 2010, the Company’s Board of Directors appointed BDO USA, LLP, as the Company’s independent registered public accounting firm.

a. Audit Fees: Aggregate fees billed by BDO USA, LLP for professional services rendered for the audit of our annual financial statements and reviews of our interim financial statements for the year ended December 31, 2012 were approximately $344,000.

b. Audit-Related Fees: Fees billed for additional acquisition related audit and review services related to the performance of the audit or review of our financial statements and not reported under “Audit Fees” above in the year ended December 31, 2012 were $21,500.

c. Tax Fees: Aggregate fees billed by BDO USA, LLP for tax services for the year ended December 31, 2012 were zero.

d. All Other Fees: Aggregate fees billed by BDO USA, LLP for professional services other than those described above were zero.

107

PART IV

Item 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a) Listing of Financial Statements

The following consolidated financial statements of the Company are included in “Financial Statements and Supplementary Data”:

Report of Independent Registered Public Accounting Firm

Consolidated Balance Sheets as of December 31, 2012 and 2011

Consolidated Statements of Operations for the years ended December 31, 2012 and 2011

Consolidated Statements of Stockholders' Equity for the years ended December 31, 2012 and 2011

Consolidated Statements of Cash Flows for the years ended December 31, 2012 and 2011

Notes to Consolidated Financial Statements

Unaudited Supplementary Information

(b) Exhibits

The exhibits to this report required to be filed pursuant to Item 15(b) are listed below and in the “Index to Exhibits” attached hereto.

No financial statement schedules are required to be filed as part of this report or they are not applicable.

Exhibits

Exhibit No.		Description
2.1		Share Exchange Agreement by and between the Company, American Standard and the American Standard Shareholders, dated October 1, 2010 (1)
3.1		Articles of Incorporation (incorporated by reference in the Registration Statement on Form SB-2 filed on April 3, 2006)
3.2		Certificate of Amendment of the Certificate of Incorporation (19)
3.3		Bylaws (incorporated by reference in the Registration Statement on Form SB-2 filed on April 3, 2006)
4.1		Certificate of Designation of Series A Cumulative Convertible Preferred Stock (24)
10.1		Scott Feldhacker Employment Agreement (1)
10.2		Richard Macqueen Employment Agreement (1)
10.3		Not used
10.4		Scott Mahoney Employment Agreement (1)
10.5		Scott Feldhacker Deferred Compensation Agreement (1)*
10.6		Richard Macqueen Deferred Compensation Agreement (1)*

108

10.7		2010 Equity Compensation Plan (1)*
10.8		Lease Purchase Agreement by and between American Standard Energy Corp. and Geronimo Holding Corp. dated April 28, 2010 (Bakken, ND) (1)
10.9		Lease Purchase Agreement by and between American Standard Energy Corp. and CLW South Texas 2008, LP dated April 28, 2010 (Eagle Ford, TX) (1)
10.10		Lease Purchase Agreement by and between American Standard Energy Corp. and XOG Operating LLC dated April 28, 2010 (University, TX) (1)
10.11		Lease Purchase Agreement by and between American Standard Energy Corp. and Geronimo Holding Corp. dated April 28, 2010 (Wolfberry, TX) (1)
10.12		Form of Subscription Agreement dated October 26, 2010 (2)
10.13		Form of Warrant dated October 26, 2010 (2)
10.14		Agreement for the purchase of Partial Leaseholds between Geronimo Holdings Corporation and American Standard Energy Corp. dated December 1, 2010 (4)
10.15		Form of Subscription Agreement dated December 27, 2010 (5)
10.16		Form of Warrant dated December 27, 2010 (5)
10.17		Securities Purchase Agreement dated February 1, 2011 (6)
10.18		Form of Warrant dated February 1, 2011 (6)
10.19		Registration Rights Agreement dated February 1, 2011 (6)
10.20		Agreement for the Purchase of Partial Leaseholds between Geronimo Holding Corporation and American Standard Energy Corp. dated February 10, 2011 (7)
10.21		Agreement for the Purchase of Partial Leaseholds between Geronimo Holding Corporation and American Standard Energy Corp. dated March 1, 2011 (8)
10.22		Amendment No.1 to Securities Purchase Agreement dated March 28, 2011 (originally dated February 1, 2011) (9)
10.23		Amendment No.1 to the Registration Rights Agreement dated March 28, 2011 (originally dated February 1, 2011) (9)
10.24		Securities Purchase Agreement dated March 31, 2011 (10)
10.25		Form of Warrant dated March 31, 2011 (10)
10.26		Registration Rights Agreement dated March 31, 2011 (10)
10.27		Agreement for the Purchase of Partial Leaseholds between Geronimo Holding Corporation and American Standard Energy Corp. dated April 8, 2011 (11)
10.28		Securities Purchase Agreement dated July 15, 2011 (12)
10.29		Form of Series A Warrant dated July 15, 2011 (12)
10.30		Form of Series B Warrant dated July 15, 2011 (12)
10.31		Registration Rights Agreement dated July 15, 2011 (12)
10.32		Form of Joint Operating Agreement (15)
10.33		Credit Agreement by and among American Standard Energy Corp., a Nevada corporation, and Macquarie Bank Limited and certain lender parties thereto, dated September 21, 2011 (14)
10.34		Pledge and Security Agreement by and among American Standard Energy Corp., a Delaware corporation, and Macquarie Bank Limited, as administrative agent, and certain lender parties thereto dated September 21, 2011 (14)
10.35		Guaranty Agreement by and among American Standard Energy Corp., a Delaware corporation, and Macquarie Bank Limited, as administrative agent, and certain lender parties thereto dated September 21, 2011 (14)
10.36		Letter Agreement dated December 30, 2011, by and between American Standard Energy Corp. and Scott Feldhacker (16)
10.37		Letter Agreement dated December 30, 2011, by and between American Standard Energy Corp. and Richard MacQueen (16)

109

10.38		Letter Agreement dated December 30, 2011, by and between American Standard Energy Corp. and Scott Mahoney (16)
10.39		Form of Warrant issued to Pentwater, dated February 9, 2012 (17)
10.40		Form of Series C Warrant issued to Pentwater, dated February 9, 2012 (17)
10.41		Amended and Restated Warrant issued to Macquarie Americas Corp., dated February 9, 2012 (17)
10.42		Note and Warrant Purchase Agreement by and among the Company, ASEN 2, and Pentwater, dated as of February 9, 2012 (17) +
10.43		Secured Convertible Promissory Note issued by ASEN 2 to Pentwater, dated February 9, 2012 (17)
10.44		Security Agreement by and among ASEN 2 to Pentwater, dated as of February 9, 2012 (17) +
10.45		Guaranty Agreement by and among the Company and Pentwater, dated as of February 9, 2012 (17)
10.46		Registration Rights Agreement by and among the Company and Pentwater, dated as of February 9, 2012 (17)
10.47		Modification Agreement by and among the Company, Pentwater and its affiliates, dated as of February 9, 2012 (17)
10.48		Amendment to Securities Purchase Agreement by and among the Company and certain holders thereto, dated February 9, 2012 (17)
10.49		Mortgage and Deed of Trust from ASEN 2 to Pentwater for LaSalle County, Texas (17) +
10.50		Mortgage and Deed of Trust from ASEN 2 to Pentwater for Frio County, Texas (17) +
10.51		Purchase and Sale Agreement by and among the Company, XOG Operating LLC, and Geronimo Holding Corporation, dated as of February 24, 2012 (18) +
10.52		Promissory Note issued by the Company to Geronimo Holding Corporation, dated March 5, 2012 (18)
10.53		Letter Agreement regarding Secured Convertible Promissory Note by and among Pentwater Equity Opportunities Master Fund Ltd., PWCM Master Fund Ltd. and ASEN 2, Corp., dated as of March 5, 2012 (18)
10.54		Amended 2010 Equity Compensation Plan (20)*
10.55		2011 Equity Incentive Plan (21)*
10.56		Modification Agreement by and among the Company, Pentwater and its affiliates, dated as of April 5, 2012 (23)
10.57		Exchange Agreement by and between the Company and Geronimo Holding Corporation dated as of June 30, 2012 (24)
10.58		Payment and Settlement Agreement by and among the Company, ASEN 2, Corp. and XOG Operating LLC, dated as of June 30, 2012 (24)
10.59		Form of Warrant issued to Pentwater, dated July 23, 2012 (25)
10.60		Form of Amended and Restated Series C Warrant issued to Investor, dated July 23, 2012 (25)
10.61		Form of Amended and Restated Warrant issued to Pentwater, dated July 23, 2012 (25)
10.62		First Amendment to Note and Warrant Purchase Agreement by and among the Company, ASEN 2, and Pentwater, dated as of July 23, 2012 (25)
10.63		Amended Secured Convertible Promissory Note issued by ASEN 2 to Pentwater, dated July 23, 2012 (25)
10.64		Modification Agreement by and among the Company, Pentwater and its affiliates, dated as of July 23, 2012 (25)

110

10.65		Second Amendment to Note and Warrant Purchase Agreement, First Amendment to Amended and Restated Secured Convertible Promissory Note and Limited Waiver by and among American Standard Energy Corp., ASEN 2 Corp., Pentwater Equity Opportunities Master Fund Ltd., and PWCM Master Fund Ltd., dated September 11, 2012 (26)
10.66		Asset Purchase Agreement by and between ASEN 2 Corp. and Antler Bar Investments, LLC, dated September 11, 2012 (26) +
10.67		Retirement Agreement by and between American Standard Energy Corp. and Robert Thompson dated September 12, 2012 (26)
10.68		Purchase and Sale Agreement by and between American Standard Energy Corp., a Nevada corporation, and Texian Oil – I, LP, dated November 16, 2012 (27) +
10.69		Severance Agreement by and between American Standard Energy Corp. and Scott Mahoney dated November 24, 2012 (28)
10.70		Separation Agreement dated April 16, 2013 between American Standard Energy Corp. and Scott Feldhacker (30)
10.71		Separation Agreement dated April 16, 2013 between American Standard Energy Corp. and Richard MacQueen (30)
10.72		Amendment No. 1 to Separation Agreement dated April 16, 2013 between American Standard Energy Corp. and Scott Feldhacker (31)
10.73		Amendment No. 1 to Separation Agreement dated April 16, 2013 between American Standard Energy Corp. and Richard MacQueen (31)
10.74		Fourth Amendment to Credit Agreement and Limited Waiver dated May 16, 2013 by and among the Company (as Borrower), the Lenders, Macquarie Bank Limited (as Administrative Agent) and the Company (solely in relation to Sections 3(f) and 6 thereto) (32)
17.1		Resignation Letter of Scott Feldhacker dated February 11, 2013 (29)
17.2		Resignation Letter of Richard MacQueen dated February 11, 2013 (29)
31.1		Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2		Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32.1		Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2		Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
99.1		Williamson Petroleum Consultants, Inc. Look Back Report to the Interests of American Standard Energy Corp. effective December 31, 2009 (1)
99.2		Williamson Petroleum Consultants, Inc. Look Back Report to the Interests of American Standard Energy Corp. effective December 31, 2008 (1)
99.3		American Standard Energy Corp. Company Corporate Profile Fact Sheet (3)
99.4		Reserve Report by Bryant M. Mook, B.Sc. M.Eng., Petroleum Engineer and Geological Advisor as of December 31, 2010 (13)
99.5		Reserve Report by DeGolyer and MacNaughton as of December 31, 2011 (22)
99.6		Reserve Report by DeGolyer and MacNaughton as of December 31, 2012
99.7		Total Proved Plus Probable Reserve Report by Cawley Gillespie & Associates, Inc. as of December 31, 2012
101.INS		XBRL Instance Document
101.SCH		XBRL Taxonomy Schema
101.CAL		XBRL Taxonomy Calculation Linkbase
101.DEF		XBRL Definition Linkbase
101.LAB		Taxonomy Label Linkbase
101.PRE		XBRL Taxonomy Presentation Linkbase

111

(1) Incorporated by reference to Form 8-K filed on October 4, 2010.

(2) Incorporated by reference to Form 8-K filed on October 26, 2010.

(3) Incorporated by reference to Form 8-K filed on November 17, 2010.

(4) Incorporated by reference to Form 8-K filed on December 6, 2010.

(5) Incorporated by reference to Form 8-K filed on December 27, 2010.

(6) Incorporated by reference to Form 8-K filed on February 2, 2011.

(7) Incorporated by reference to Form 8-K filed on February 16, 2011.

(8) Incorporated by reference to Form 8-K filed on March 7, 2011.

(9) Incorporated by reference to Form 8-K filed on April 1, 2011.

(10) Incorporated by reference to Form 8-K filed on April 1, 2011.

(11) Incorporated by reference to Form 8-K filed on April 14, 2011.

(12) Incorporated by reference to Form 8-K filed on July 13, 2011.

(13) Incorporated by reference to Form 10-K/A filed on March 22, 2011.

(14) Incorporated by reference to Form 8-K filed on October 4, 2011.

(15) Incorporated by reference to Form S-1/A filed on January 4, 2012.

(16) Incorporated by reference to Form 8-K filed on January 6, 2012.

(17) Incorporated by reference to Form 8-K filed on February 15, 2012.

(18) Incorporated by reference to Form 8-K filed on March 9, 2012.

(19) Incorporated by reference to Exhibit C filed with the Company’s Definitive Proxy Statement on Schedule 14C dated December 30, 2011.

(20) Incorporated by reference to Exhibit A filed with the Company’s Definitive Proxy Statement on Schedule 14C dated December 30, 2011.

(21) Incorporated by reference to Exhibit B filed with the Company’s Definitive Proxy Statement on Schedule 14C dated December 30, 2011.

(22) Incorporated by reference to Form 10-K filed on March 20, 2012.

(23) Incorporated by reference to Form 8-K filed on April 10, 2012.

(24) Incorporated by reference to Form 8-K filed on July 6, 2012.

(25) Incorporated by reference to Form 8-K filed on July 27, 2012.

(26) Incorporated by reference to Form 8-K filed on September 17, 2012.

(27) Incorporated by reference to Form 8-K filed on November 23, 2012.

(28) Incorporated by reference to Form 8-K filed on November 29, 2012.

(29) Incorporated by reference to Form 8-K filed on February 14, 2013.

(30) Incorporated by reference to Form 8-K filed on April 22, 2013.

(31) Incorporated by reference to Form 8-K filed on May 6, 2013.

(32) Incorporated by reference to Form 8-K filed on May 17, 2013.

+ Schedules and exhibits have been omitted pursuant to Item 601(b)(2) of Regulation S-K. American Standard Energy Corp. hereby undertakes to furnish supplementally to the Securities and Exchange Commission copies of any of the omitted schedules and exhibits upon request by the Securities and Exchange Commission.

* Denotes management compensation plan or arrangement.

112

SIGNATURES

		AMERICAN STANDARD ENERGY CORP.

August 12, 2013	By:	/s/ Scott Feldhacker
		Scott Feldhacker
		Chief Executive Officer (Principal Executive Officer)

August 12, 2013		/s/ Josh Haislip
		Josh Haislip Chief Financial Officer (Principal Financial and Accounting Officer)

113

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature	Title	Date

/s/ Scott Feldhacker	Chief Executive Officer	August 12, 2013
Scott Feldhacker

/s/ Josh Haislip	Chief Financial Officer, Principal Accounting Officer	August 12, 2013
Josh Haislip

/s/ Wayne Squires	Chairman of the Board of Directors	August 12, 2013
Wayne Squires

/s/ Randall Capps	Director	August 12, 2013
Randall Capps

/s/ J. Steven Person	Director	August 12, 2013
J. Steven Person

/s/ H.H. Womack, III	Director	August 12, 2013
H.H. Womack, III

/s/ William Killian	Director	August 12, 2013
William Killian

/s/ Rusty Pickering	Director	August 12, 2013
Rusty Pickering

/s/ Michael Pedrotti	Director	August 12, 2013
Michael Pedrotti

114

American Standard Energy Corp. and Subsidiaries

Consolidated Financial Statements

Index to Consolidated Financial Statements

Consolidated Financial Statements of American Standard Energy Corp.

Report of Independent Registered Public Accounting Firm	F-2

Consolidated Balance Sheets as of December 31, 2012 and 2011	F-3

Consolidated Statements of Operations for the years ended December 31, 2012 and 2011	F-4

Consolidated Statements of Cash Flows for the years ended December 31, 2012 and 2011	F-5

Consolidated Statements of Stockholders’ Equity for the years ended December 31, 2012 and 2011	F-6

Notes to Consolidated Financial Statements	F-7 – F-39

Unaudited Supplementary Information	F-40 – F-43

F-1

Report of Independent Registered Public Accounting Firm

Board of Directors and Stockholders

American Standard Energy Corp.

Scottsdale, Arizona

We have audited the accompanying consolidated balance sheets of American Standard Energy Corp. as of December 31, 2012 and 2011 and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the two years in the period ended December 31, 2012. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting.Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of American Standard Energy Corp. at December 31, 2012 and 2011, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2012, in conformity with accounting principles generally accepted in the United States of America.

The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern. As described in Note C to the consolidated financial statements, the Company has suffered recurring losses from operations, has a working capital deficiency and limited cash resources that raise substantial doubt about its ability to continue as a going concern. Management’s plans in regard to these matters are also described in Note C. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty. Our opinion is not modified with respect to this matter.

/s/ BDO USA, LLP

Houston, Texas

August 12, 2013

F-2

PART I - FINANCIAL INFORMATION

Item 1. Financial Statements

American Standard Energy Corp. and Subsidiaries

Consolidated Balance Sheets

	December 31,
	2012			2011
Current assets:
Cash and cash equivalents	$	717,622		$	733,049
Oil and gas sales receivables - related parties		2,115,654			1,556,414
Oil and gas sales receivables		2,545,345			639,714
Other current assets		130,129			308,208
Total current assets		5,508,750			3,237,385

Oil and natural gas properties at cost, successful efforts method
Proved		83,681,256			76,919,789
Unproved		83,895,328			25,212,635
Accumulated depletion and depreciation		(45,973,085	)		(14,310,006	)
Total oil and natural gas properties, net		121,603,499			87,822,418

Debt issuance costs, net of accumulated amortization of $1,257,526 and $69,184		1,324,797			720,175
Prepaid drilling costs		1,009,750			2,590,356
Deposit on properties with affiliate		-			1,500,000
Other assets, net		18,047			24,403

Total assets	$	129,464,843		$	95,894,737

Current liabilities:
Accounts payable - trade	$	11,285,642		$	3,373,262
Accounts payable and accrued liabilities - related parties		1,420,532			8,574,017
Accrued compensation expense and withholding taxes		-			1,338,308
Current portion of term loan and revolving credit facility, net of discount of $5,180,935		10,760,417			-
Current portion of Pentwater note, net of discount of $2,877,249 and $0		19,528,038			-
Commodity derivatives		40,889			243,996
Other accrued liabilities		707,685			36,665
Total current liabilities		43,743,203			13,566,248

Term loan and revolving credit facility, net of discount of $9,907,057		-			7,262,832
Asset retirement obligations		1,815,623			394,177
Commodity derivatives		113,329			421,964
Warrant derivative liabilities		-			15,298,658
Total liabilities		45,672,155			36,943,879

Commitments and contingencies

Stockholders' equity
Preferred stock, $.001 par value; 1,000,000 shares authorized; 35,400 shares issued and outstanding		35			-
Common stock, $.001 par value; 100,000,000 shares authorized, 51,928,491 shares issued and 51,721,798 shares outstanding at December 31, 2012 and 40,178,060 shares issued and 39,971,367 shares outstanding at December 31, 2011		51,928			40,178
Additional paid-in capital		194,075,756			75,504,243
Treasury stock, 206,693 shares at cost		(1,116,514	)		(1,116,514	)
Accumulated deficit		(109,218,517	)		(15,477,049	)
Total stockholders' equity		83,792,688			58,950,858

Total liabilities and stockholders' equity	$	129,464,843		$	95,894,737

F-3

American Standard Energy Corp. and Subsidiaries

Consolidated Statements of Operations

	Years Ended December 31,
	2012			2011
Operating revenues:
Oil revenues	$	17,534,018		$	6,804,024
Natural gas revenues		2,204,505			2,994,341
Total revenues		19,738,523			9,798,365
Operating costs and expenses:
Oil and natural gas production costs		6,894,872			2,608,978
General and administrative (including non-cash stock-based compensation of $33,805,391 and $10,401,110 for the years ended December 31, 2012 and 2011)		37,976,747			16,387,633
Impairment of oil and natural gas properties		28,640,726			1,027,552
Depreciation, depletion and amortization		5,919,933			2,807,893
Accretion of discount on asset retirement obligations		44,072			20,951
Loss on sale of oil and natural gas leases		312,819			-

Total operating costs and expenses		79,789,169			22,853,007

Loss from operations		(60,050,646	)		(13,054,642	)

Other income (expense), net:
Realized and unrealized gain (loss) on commodity derivatives		541,307			(670,659	)
Interest expense (including accretion of debt discount of $8,149,389 and $1,010,924 for the years ended December 31, 2012 and 2011)		(11,447,200	)		(1,184,862	)
Expense on warrant derivatives		(4,771,656	)		(409,668	)
Total other expense, net		(15,677,549	)		(2,265,189	)

Loss from continuing operations before income taxes		(75,728,195	)		(15,319,831	)

Income tax benefit		-			604,732

Loss from continuing operations		(75,728,195	)		(14,715,099	)

Gain (loss) from discontinued operations, net of tax of $0 and $604,732		(18,013,273	)		1,041,211

Net loss	$	(93,741,468	)	$	(13,673,888	)

Weighted average common shares outstanding for basic and diluted		46,587,776			35,413,541
Loss per share from continuing operations - basic and diluted	$	(1.63	)	$	(0.42	)
Income (loss) per share from discontinued operations - basic and diluted	$	(0.39	)	$	0.03
	$	(2.01	)	$	(0.39	)

F-4

American Standard Energy Corp. and Subsidiaries

Consolidated Statements of Cash Flows

	Years Ended December 31,
	2012			2011
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(93,741,468	)	$	(13,673,888	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization		5,919,933			3,313,250
Accretion of debt discount		8,149,389			1,010,924
Amortization of debt issue costs		1,188,342			-
Unrealized (gain) loss on commodity derivative		(511,742	)		665,960
Unrealized (income) loss on warrant derivatives		(664,525	)		409,668
Capitalized interest on notes		1,211,877			-
Accretion of asset retirement obligations		44,072			20,951
Loss on sale of oil and natural gas leases		20,274,817			-
Warrant modification consideration		5,436,180			-
Stock-based compensation expense		33,805,391			10,401,110
Common stock issued for services		229,000			-
Impairment of oil and natural gas properties		28,640,726			1,027,552
Accrual for stock penalties expense		-			2,019,943
Changes in operating assets and liabilities:
Oil and natural gas sales receivables		(2,464,871	)		(2,411,823	)
Other current assets		(82,668	)		(300,358	)
Accounts payable and accrued liabilities		1,258,758			1,919,460

Net cash provided by operating activities		8,693,211			4,402,749

CASH FLOWS FROM INVESTING ACTIVITIES:
Oil and natural gas property additions		(37,113,796	)		(54,372,042	)
Prepaid drilling costs		(1,009,750	)		(2,590,356	)
Proceeds from sales of oil and natural gas leases		8,802,668			-
Deposit on properties with affiliate		-			(1,500,000	)

Net cash used in investing activities		(29,320,878	)		(58,462,398	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Cash payment to Geronimo - deemed distribution		-			(10,000,000	)
Proceeds from the sale of stock, net		-			46,334,474
Proceeds from stock subscription receivable		-			1,557,698
Proceeds from draws on term loan		3,857,868			17,169,889
Proceeds from Pentwater note		25,000,000			-
Payments on term loan		(6,541,723	)		-
Debt issuance costs paid		(1,703,905	)		(789,359	)

Net cash provided by financing activities		20,612,240			54,272,702

Net (decrease) increase in cash and cash equivalents		(15,427	)		213,053

Cash and cash equivalents at beginning of period		733,049			519,996

Cash and cash equivalents at end of period	$	717,622		$	733,049

Supplemental disclosure of cash flow information
Cash paid during the period for interest	$	2,819,572		$	144,456

NON-CASH INVESTING AND FINANCING ACTIVITIES:
Accounts payable and accrued liabilities for oil and natural gas property additions	$	14,793,112		$	5,623,612
Liabilities assumed for Auld Shipman divestiture	$	5,982,772		$	-
Reclassification of pre-paid drilling costs to oil and natural gas properties	$	2,590,356		$	-
Additions and revisions to asset retirement cost and related obligation	$	1,377,374		$	130,594
Issuance of Geronimo Note for purchase of oil and natural gas properties	$	35,000,000		$	-
Conversion of Geronimo Note to preferred stock with majority, affiliated shareholder	$	35,778,079		$	-
Reclassification to equity of warrants' value previously recorded as a liability	$	14,634,133		$	-
Discount on debt - Pentwater warrants	$	6,300,515		$	10,917,981
Property acquired from Geronimo for shares of common stock	$	13,500,000		$	2,350,050
Stock issued for settlement of related party payables	$	10,000,000		$	-
Reduction of Pentwater note for Auld Shipman divestiture	$	2,750,000		$	-
Debt issuance costs capitalized to Pentwater note	$	89,059		$	-
Founders shares remitted for accrued withholding tax	$	-		$	1,116,514
Non-cash deemed dividend	$	-		$	459,495

F-5

American Standard Energy Corp. and Subsidiaries

Consolidated Statements of Stockholders' Equity

Year ended December 31, 2012 and 2011

	Preferred Stock				Common Stock						Additional paid-in			Treasury Stock						Accumulated			Total stockholders'
	Shares		Value		Shares			Value			capital			Shares			Value			(deficit)			equity
Balance at December 31, 2010		-	$	-		28,343,905		$	28,344		$	28,841,004			-		$	-		$	(1,803,161	)	$	27,066,187
February 2011, common stock sold in private placement offering at $3.50 per share, less offering costs totaling $774,687		-		-		4,401,930			4,402			14,627,666			-			-			-			14,632,068
Property acquired from XOG Group recorded at historical cost		-		-		-			-			1,257,000			-			-			-			1,257,000
Shares issued for acquisition of properties from XOG Group recorded at historical cost		-		-		883,607			884			(884	)		-			-			-			-
Cash paid and deemed distribution for acquisition of properties from Geronimo recorded at historical cost		-		-		-			-			(10,000,000	)		-			-			-			(10,000,000	)
Deemed distribution for working capital not acquired in acquisition of properties		-		-		-			-			(459,495	)		-			-			-			(459,495	)
March 2011, common stock sold in private placement offering at $5.75 per share, less offering costs totaling $1,537,375		-		-		3,697,005			3,697			19,716,706			-			-			-			19,720,403
July 2011, common stock and warrants sold in private placement offering at $5.75 per share, less offering costs totaling $998,000		-		-		2,260,870			2,261			8,008,733			-			-			-			8,010,994
Shares issued in August 2011 for acquisition of properties from XOG Group recorded at fair value		-		-		208,200			208			1,092,842			-			-			-			1,093,050
Shares issued for delayed registration penalties for shares of February and March 2011 private placements at $4.40 per share		-		-		459,074			460			2,019,483			-			-			-			2,019,943
Founder's Stock withheld for taxes at $5.40 per share		-		-		-			-			-			(206,693	)		(1,116,514	)		-			(1,116,514	)
Forfeited unvested Founder's Stock		-		-		(76,531	)		(78	)		78			-			-			-			-
Stock-based compensation expense		-		-		-			-			10,401,110			-			-			-			10,401,110
Net loss		-		-		-			-			-			-			-			(13,673,888	)		(13,673,888	)
Balance at December 31, 2011		-	$	-		40,178,060		$	40,178		$	75,504,243			206,693		$	(1,116,514	)	$	(15,477,049	)	$	58,950,858

Cashless exercise of warrants		-		-		2,125,986			2,126			(2,126	)		-			-			-			-
Shares issued in March 2012 for acquisition of properties from Geronimo recorded at fair value		-		-		5,000,000			5,000			13,495,000			-			-			-			13,500,000
Series A preferred stock issued with Geronimo Note conversion		35,400		35		-			-			35,778,044			-			-			-			35,778,079
Stock issued for settlement of related party payables		-		-		4,444,445			4,444			9,995,556			-			-			-			10,000,000
Issuance of Restricted Stock		-		-		80,000			80			194,320			-			-			-			194,400
Issued shares for consulting services		-		-		100,000			100			228,900			-			-			-			229,000
Reclassification of warrants' value previously recorded as a liability		-		-		-			-			14,634,133			-			-			-			14,634,133
Modification consideration (Series C warrants)		-		-		-			-			4,336,180			-			-			-			4,336,180
Assigned value of warrants issued with Pentwater note		-		-		-			-			6,300,515			-			-			-			6,300,515
Stock-based compensation expense		-		-		-			-			33,610,991			-			-			-			33,610,991
Net loss		-		-		-			-			-			-			-			(93,741,468	)		(93,741,468	)
Balance at December 31, 2012		35,400	$	35		51,928,491		$	51,928		$	194,075,756			206,693		$	(1,116,514	)	$	(109,218,517	)	$	83,792,688

F-6

American Standard Energy Corp. and Subsidiaries

Notes to Consolidated Financial Statements

Note A. Organization and Basis of Presentation

American Standard Energy Corp., a Nevada corporation (“Nevada ASEC”) was incorporated on April 2, 2010 for the purposes of acquiring certain oil and natural gas leasehold properties from Geronimo Holding Corporation (“Geronimo”), XOG Operating, LLC (“XOG”) and CLW South Texas 2008, LP (“CLW”) (collectively, the "XOG Group"). Randall Capps is the sole owner of XOG and Geronimo, and the majority owner of CLW. Nevada ASEC's principal business is the acquisition, development and exploration of oil and natural gas leasehold properties primarily in the Permian Basin of west Texas and eastern New Mexico, the Eagle Ford Shale formation of South Texas, the Bakken Shale formation in North Dakota and certain other oil and natural gas properties in Arkansas and Oklahoma.

Uncle Al’s Famous Hot Dogs & Grille, Inc. (“FDOG”) was incorporated as National Franchise Directors, Inc., under the laws of the State of Delaware on March 4, 2005. On October 1, 2010, FDOG entered into a Share Exchange Agreement (the “Agreement”), dated October 1, 2010, with its then controlling shareholder and Nevada ASEC, a privately-held oil exploration and production company owned substantially by the XOG Group. Pursuant to the Agreement, FDOG (1) spun-off its franchise rights and related operations to its controlling shareholder in exchange for and cancellation of 25,000,000 shares of FDOG’s common stock and (2) acquired 100% of the outstanding shares of common stock of Nevada ASEC and additional consideration of $25,000 from the Nevada ASEC shareholders. In exchange for the Nevada ASEC stock and the additional consideration, the Nevada ASEC shareholders were issued approximately 22,000,000 shares of FDOG’s common stock on the closing date of the Share Exchange Agreement. As a result, Nevada ASEC owners acquired control of FDOG and the transaction was accounted for as a recapitalization with Nevada ASEC as the accounting acquirer of FDOG. Accordingly, as a result of the recapitalization, the financial statements of Nevada ASEC became the historical financial statements of FDOG. In connection with the Share Exchange Agreement, FDOG changed its name to American Standard Energy Corp., a Delaware corporation (the “Company”). Nevada ASEC and ASEN 2, Corp. (“ASEN 2”) are wholly-owned subsidiaries of the Company. ASEN 2 was incorporated on January 25, 2012.

A history of the Company’s property acquisitions from the XOG Group accounted for as a transaction under common control through December 31, 2012 is as follows:

Formation acquisition - On May 1, 2010, the XOG Group contributed certain oil and gas properties to Nevada ASEC in return for 80% of the common stock of Nevada ASEC. XOG continued to serve as operator of such properties. The May 2010 acquisition of the oil and natural gas properties from the XOG Group was a transaction under common control and, accordingly, Nevada ASEC recognized the assets and liabilities acquired from the XOG Group at their historical carrying values and no goodwill or other intangible assets were recognized. The oil and gas properties contributed by the XOG Group to Nevada ASEC consisted of seven completed and operating wells within the Permian Basin region of West Texas as well as approximately 10,600 acres of undeveloped leasehold rights in three primary regions: (i) the Bakken, (ii) the Eagle Ford and (iii) certain positions in the Permian Basin leased from the University of Texas.

F-7

On March 5, 2012, we acquired leasehold working interests in approximately 61,500 net acres across the Permian Basin, Eagle Ford shale formation and the Eagle Bine in Texas, the Williston Basin in North Dakota, and the Niobrara shale formation in Wyoming and Nebraska referred to herein as the XOG Properties, from the XOG Group in exchange for the delivery by the Company to the XOG Group of $10 million in cash, less the $1.5 million cash deposit previously paid by the Company, a note in the principal amount of $35 million made by the Company in favor of Geronimo and 5,000,000 shares of the common stock of the Company valued at $2.70 per share, based on the closing price of the common stock on March 5, 2012. The promissory note with a principal amount of $35 million issued to Geronimo was converted into 35,400 shares of Series A Cumulative Convertible Preferred Stock, par value $0.001 per share (“Series A Preferred Stock”) on June 30, 2012. Randall Capps, a member of the Company’s board of directors, and the father –in-law of our Chief Executive Officer, Scott Feldhacker, is the sole owner of XOG and Geronimo and the majority owner of CLW.

All of the acquisitions described above are collectively referred to as the “Acquired Properties.”

F-8

The accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”). For the periods prior to the acquisition dates of the Acquired Properties, the financial statements have been prepared primarily on a “carve out” basis from the XOG Group’s combined financial statements using historical results of operations, assets and liabilities attributable to the Acquired Properties, including allocations of expenses from the XOG Group. This carve-out presentation basis reflects the fact that the Acquired Properties represented only a portion of the XOG Group and did not constitute separate legal entities. The consolidated financial statements including the carve outs may not be indicative of the Company’s future performance and may not reflect what its results of operations, financial position and cash flows would have been had the Company owned the Acquired Properties on a stand-alone basis during all of the periods presented. To the extent that an asset, liability, revenue or expense is directly associated with the Acquired Properties or the Company, it is reflected in the accompanying consolidated financial statements.

Prior to the Company’s acquisition of the Acquired Properties, the XOG Group provided corporate and administrative functions to the Acquired Properties including executive management, oil and natural gas property management, information technology, tax, insurance, accounting, legal and treasury services. The costs of such services were allocated to the Acquired Properties based on the most relevant allocation method to the service provided, primarily based on relative net book value of assets. Management believes such allocations are reasonable; however, they may not be indicative of the actual expense that would have been incurred had the Acquired Properties been operating as a separate entity for all of the periods presented. The charges for these functions are included in general and administrative expenses for all periods presented.

In addition to the above, see Note L for recent acquisitions from XOG Group accounted for at fair value.

Note B. Summary of Significant Accounting Policies

Principles of Consolidation

The consolidated financial statements of the Company include the accounts of the Company and its wholly-owned subsidiaries. All material intercompany balances and transactions have been eliminated.

Use of Estimates in the Preparation of Financial Statements

Preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from these estimates. Such estimates include the following:

Depreciation, depletion and amortization of oil and natural gas properties are determined using estimates of proved oil and natural gas reserves. There are numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures.

Impairment evaluation of proved and unproved oil and natural gas properties is subject to numerous uncertainties including, among others, estimates of future recoverable reserves, future prices, operating and development costs, and estimated cash flows.

F-9

Other significant estimates include, but are not limited to, the asset retirement costs and obligations, accrued revenue and expenses, and fair values of stock-based compensation, commodity derivatives and warrants.

Oil and Gas Sales Receivable

Through the Company’s operations, oil and natural gas production is sold to purchasers generally on an unsecured basis. Allowances for doubtful accounts are determined based on management's assessment of the creditworthiness of these purchasers. Receivables are considered past due if full payment is not received by the contractual due date. Past due accounts will be generally written off against the allowance for doubtful accounts only after all collection attempts have been exhausted. Management concluded that no allowance for doubtful accounts was necessary at December 31, 2012 and 2011. Management believes that the allowance for doubtful accounts is adequate; however, actual write-offs may exceed the recorded allowance.

Oil and Natural Gas Properties

The Company utilizes the successful efforts method of accounting for its oil and natural gas properties. Under this method, all costs associated with productive wells and nonproductive development wells are capitalized, while nonproductive exploration costs are expensed. Capitalized acquisition costs relating to proved properties are depleted using the unit-of-production method based on total proved reserves. The depletion of capitalized exploratory drilling and development costs (wells and related equipment) is based on the unit-of-production method using proved developed reserves on a field basis.

Proceeds from the sales of individual properties and the capitalized costs of individual properties sold or abandoned are credited and charged, respectively, to accumulated depletion. Generally, no gain or loss is recognized until the entire amortization base is sold. However, a gain or loss is recognized from the sale of less than an entire amortization base if the disposition is significant enough to materially impact the depletion rate of the remaining properties in the amortization base.

Ordinary maintenance and repair costs are expensed as incurred.

Costs of significant nonproducing properties, wells in the process of being drilled and development projects are excluded from depletion until such time as the related project is developed and proved reserves are established or impairment is determined. These unproved oil and natural gas properties are periodically assessed for impairment by considering future drilling plans, the results of exploration activities, commodity price outlooks, planned future sales or expiration of all or a portion of such projects. Amounts capitalized to oil and natural gas properties excluded from depletion at December 31, 2012 and 2011 were $83,895,328 and $25,212,635, respectively. During the years ended December 31, 2012 and 2011 the Company recorded unproved properties impairment of $2,268,528 and $447,552, respectively.

F-10

Management of the Company reviews its oil and natural gas properties for impairment by amortization base or by individual well for those wells not constituting part of an amortization base whenever events or circumstances indicate that the carrying value of those assets may not be recoverable. An impairment loss is indicated if the sum of the expected undiscounted future cash flows is less than the carrying amount of the assets. For each property determined to be impaired, an impairment loss equal to the difference between the carrying value of the properties and the estimated fair value (discounted future cash flows) of the properties is recognized at that time. Estimating future cash flows involves the use of judgments, including estimation of the proved and unproved oil and natural gas reserve quantities, timing of development and production, expected future commodity prices, capital expenditures and production costs. During the years ended December 31, 2012 and 2011 the Company recorded proved properties impairment of $26,372,198 and $580,000, respectively.

Environmental

The Company is subject to extensive federal, state and local environmental laws and regulations. These laws, which are often changing, regulate the discharge of materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations, and that have no future economic benefits, are expensed. Liabilities for expenditures of a noncapital nature are recorded when environmental assessment, compliance steps, and/or remediation are probable and the costs can be reasonably estimated. Such liabilities are generally undiscounted unless the timing of cash payments is fixed and readily determinable. As of December 31, 2012, the Company had no known environmental liabilities.

Oil and Natural Gas Sales and Imbalances

Oil and natural gas revenues are recorded at the time of delivery of such products to pipelines for the account of the purchaser or at the time of physical transfer of such products to the purchaser. The Company follows the sales method of accounting for oil and natural gas sales, recognizing revenues based on the Company's share of actual proceeds from the oil and natural gas sold to purchasers. Oil and natural gas imbalances are generated on properties for which two or more owners have the right to take production "in-kind" and in doing so take more or less than their respective entitled percentage. At December 31, 2012 and 2011 the Company did not have any oil and natural gas imbalances.

Debt Issuance Costs

In September 2011, the Company entered into a $300 million credit facility with Macquarie Bank Limited (“Macquarie”). In February 2012, the Company entered into a $20 million convertible note (“Pentwater Note”) with Pentwater Equity Opportunities Master Fund Ltd. and PWCM Master Fund Ltd. (collectively, “Pentwater”). On July 23, 2012, the Company amended and increased the Pentwater Note to $25 million. The Company incurred costs related to these facilities that were capitalized on the Consolidated Balance Sheets as “Debt Issuance Costs”. Included in the Debt Issuance Costs are direct costs paid to third parties for broker fees and legal fees. The total amount capitalized for Debt Issuance Costs is $2,582,372 at December 31, 2012 for the combined Macquarie and Pentwater debt issuances. The capitalized costs will be amortized over the term of the facility using the effective interest rate method. The amortization for the year ended December 31, 2012 and 2011 was $1,188,342 and $69,184, respectively.

F-11

Warrant Derivative Liabilities

Warrants that contain “down-round protection” and therefore, do not meet the scope exception for treatment as a derivative under Financial Accounting Standards Board’s Accounting Standards Codification (“ASC”) Topic 815 are measured at fair value and liability-classified under ASC 815, Derivatives and Hedging. Since “down-round protection” is not an input into the calculation of the fair value of the warrants, the warrants cannot be considered indexed to the Company’s own stock which is a requirement for the scope exception as outlined under ASC 815. The fair value of these warrants is determined using a Monte Carlo Stimulation Analysis and is affected by changes in inputs to that model including our stock price, expected stock price volatility, the contractual term, and the risk-free interest rate. The Company will continue to classify the fair value of the warrants as a liability until the warrants are exercised, expire or are amended in a way that would no longer require these warrants to be classified as a liability. See Note I. Derivative warrant instruments (liabilities).

Asset Retirement Obligations

The Company records the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related oil and natural gas properties. Subsequently, the asset retirement cost included in the carrying amount is allocated to expense through depreciation, depletion and amortization. Changes in the liability due to passage of time are recognized as an increase in the carrying amount of the liability and as corresponding accretion expense.

General and Administrative Expense

In addition to general and administrative (“G&A”) costs incurred directly by the Company, the accompanying financial statements include an allocated portion of the actual costs incurred by the XOG Group for G&A expenses. The amounts allocated to the properties are for the period prior to ownership by Nevada ASEC. These allocated costs are intended to provide the reader with a reasonable approximation of what historical administrative costs would have been related to the Acquired Properties had the Acquired Properties existed as a stand-alone company.

In the view of management, the most accurate and transparent method of allocating G&A expenses is by using the historical cost basis of the Acquired Properties divided by the cost basis of the total oil and gas assets of the XOG Group. Using this method, G&A expense allocated to the Acquired Properties for the years ended December 31, 2012 and 2011 was approximately $0 and $36,129, respectively.

Treasury Stock

The Company utilizes the cost method for accounting for its treasury stock acquisitions and dispositions.

F-12

Stock-Based Compensation

The Company accounts for stock-based compensation at fair value in accordance with the provisions of ASC Topic 718, “Stock Compensation”, which establishes accounting for stock-based payment transactions for employee services and goods and services received from non-employees. Under the provisions of ASC Topic 718, stock-based compensation cost is measured at the date of grant, based on the calculated fair value of the award, and is recognized as expense in the consolidated statements of operations pro ratably over the employee’s or non-employee’s requisite service period, which is generally the vesting period of the equity grant. The fair value of stock option awards is generally determined using the Black-Scholes option-pricing model. Restricted stock awards and units are valued using the market price of the Company’s common stock on the grant date. Additionally, stock-based compensation cost is recognized based on awards that are ultimately expected to vest, therefore, the compensation cost recognized on stock-based payment transactions is reduced for estimated forfeitures based on the Company’s historical forfeiture rates. Additionally, no stock-based compensation costs were capitalized for the years ended December 31, 2012 and 2011. The Company provides compensation benefits to employees and non-employee directors under share-based payment arrangements, including various employee stock option plans. See Note D for further discussion of the Company’s stock-based compensation plans.

Income Taxes

Prior to the Company’s acquisition of the Acquired Properties, the Acquired Properties were part of a pass-through entity for federal income tax purposes with taxes being the responsibility of the XOG Group owners. As a result, the accompanying financial statements do not present any income tax liabilities or assets related to the Acquired Properties prior to the Company’s acquisition of the Acquired Properties.

Subsequent to the Company’s acquisition of the properties from the XOG Group, the Company recognizes deferred tax assets and liabilities for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rate is recognized in income in the period that includes the enactment date. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized.

The Company evaluates uncertain tax positions for recognition and measurement in the consolidated financial statements. To recognize a tax position, the Company determines whether it is more likely than not that the tax positions will be sustained upon examination, including resolution of any related appeals or litigation, based on the technical merits of the position. A tax position that meets the more likely than not threshold is measured to determine the amount of benefit to be recognized in the consolidated financial statements. The amount of tax benefit recognized with respect to any tax position is measured as the largest amount of benefit that is greater than 50 percent likely of being realized upon settlement. The Company had no uncertain tax positions that required recognition in the accompanying financial statements. Any interest or penalties would be recognized as a component of income tax expense.

F-13

Fair Value of Financial Instruments

The fair value of a financial instrument is the amount at which the instrument could be exchanged in a current transaction between two willing parties. The carrying amount of cash, oil and natural gas sales receivable, stock subscription receivable and other current assets, accounts payable and accrued liabilities approximates fair value because of the short maturity of these instruments.

Reclassifications

Certain prior year information has been reclassified to conform to current year presentation.

Earnings (Loss) per Common Share

Basic earnings (loss) per share is computed on the basis of the weighted-average number of common shares outstanding during the periods. Diluted earnings per share is computed based upon the weighted-average number of common shares outstanding plus the assumed issuance of common shares for all potentially dilutive securities.

As of December 31, 2012 and 2011, 1,046,105 and 2,194,621 of the founders shares were excluded from the calculation due to being anti-dilutive.

Derivative Instruments and Price Risk Management

The Company uses derivative instruments from time to time to manage market risks resulting from fluctuations in the prices of crude oil and natural gas. The Company may periodically enter into derivative contracts, including price swaps, caps and floors, which require payments to (or receipts from) counterparties based on the differential between a fixed price and a variable price for a fixed quantity of crude oil or natural gas without the exchange of underlying volumes. The notional amounts of these financial instruments are based on expected production from existing wells. The Company has, and may continue to use exchange traded futures contracts and option contracts to hedge the delivery price of crude oil at a future date.

The Company has elected not to designate derivative contracts as accounting hedges under FASB ASC 815-20-25. As such, all derivative positions are carried at their fair value on the balance sheet and are marked-to-market at the end of each period. Any realized gains or losses on derivatives are recorded in realized and unrealized gain (loss) on commodity derivatives and are included as a component of other income (expense).

Note C. Liquidity

Going Concern – In addition to the deficiencies noted above, the capital expenditures required to maintain and/or grow production and reserves are substantial. The Company’s stock price has significantly declined over the past year which makes it more difficult to obtain equity financing on acceptable terms to address our liquidity issues. In addition, the Company is reporting negative working capital at December 31, 2012 and a third consecutive year of net losses for the year ended December 31, 2012, which is largely the result of non-cash stock based compensation and impairments of the Company’s oil and natural gas properties. Therefore, there is substantial doubt as to the Company’s ability to continue as a going concern for a period longer than the current fiscal year. The Company’s ability to continue as a going concern is dependent upon the success of its financial and strategic alternatives process, which may include the sale of some or all of the assets, a merger or other business combination involving the Company or the restructuring or recapitalization of the Company. Until the possible completion of the financial and strategic alternative process, the Company’s future remains uncertain and there can be no assurance that its efforts in this regard will be successful.

Note D. Stockholders' Equity

Founders Stock

On April 13, 2010, the Company issued 1,887,755 shares of its common stock to non-management individuals valued at $1.47 per share.

F-14

On April 13, 2010, the Company issued 2,193,877 shares of its common stock to management. These shares are restricted and vest over four years. The Company valued these shares at $1.47 per share. On April 16, 2011, 548,655 shares of founder’s stock issued to management vested. The Company estimated that $1,338,308 in federal and state withholding taxes was due related to this vesting and recorded an accrued liability on the accompanying balance sheet as of December 31, 2011 for this amount. The holders of these shares remitted to the Company 206,693 shares of the Company’s common stock valued with a market price of $5.40 per share when remitted to cover the withholding requirements. The stock remittance is included in the accompanying statement of stockholders’ equity as treasury stock at December 31, 2012 and 2011.

On February 13, 2012, the Board of Directors of the Company approved the immediate vesting of a total of 1,568,877 restricted shares of the Company’s common stock previously issued to the Chief Executive Officer, President and Chief Financial Officer as founders stock which were to vest in equal portions annually through April 16, 2014. The Company recorded compensation expense for these shares of $1,797,993 for the year ended December 31, 2012 and $787,413 for the year ended December 30, 2011.

The Company evaluated the taxable amount due and paid $558,256 to the Internal Revenue Service in April 2012. In addition, in accordance with the founder’s stock agreements for each of the officers, the Company is required to reimburse a portion of these withholding taxes to the officers. Based upon the agreements, the Company initially estimated that it would be required to reimburse a total of $3,135,413 to these officers by December 31, 2012. The Company accrued this amount during the first quarter of 2012. The Company reassessed its obligations, and there was a dispute with executives of the Company whether the tax liability existed. On April 16, 2013, the officers of the Company entered into separation agreements and the remaining withholding taxes will not be paid. Accordingly, the Company reversed the remaining unpaid accrual of $2,276,174 during the quarter ended December 31, 2012.

Restricted Stock

As part of a comprehensive review of compensation, compensation expense, and shareholder dilution, the Board of Directors granted 20,000 shares of restricted common stock to each of our three executive officers and one of our employees on March 30, 2012. The restricted stock was valued on the date of grant at $2.43 per share and recorded as stock-based compensation expense of $194,400 for the year ended December 31, 2012.

F-15

Private Placements of Common Stock and Warrants

On February 1, 2011, the Company closed a private placement offering raising proceeds of $15,406,755 through the issuance of (i) 4,401,930 shares of common stock at a price of $3.50 per share and (ii) 2 series of five-year warrants each exercisable into 1,100,482 shares of common stock at exercise prices of $5.00 and $6.50 per share, respectively, subject to certain adjustments. The Company also issued to the placement agents warrants to purchase up to 220,097 shares of common stock, the terms and exercise price are the same as investors under this private placement offering. The shares and warrants were sold to certain accredited investors. Subject to certain conditions, the Company has the right to call for the exercise of such warrants. The Company incurred costs of $0.8 million in connection with this offering.

Par value of common stock issued	$	4,402
Paid-in capital		14,627,666
Offering expenses		774,687
Total gross proceeds	$	15,406,755

On March 31, 2011, the Company closed a private placement offering of securities raising proceeds of $21,257,778 through the issuance of (i) 3,697,005 shares of common stock at a price of $5.75 per share and (ii) five-year warrants exercisable into 1,848,502 shares of common stock at exercise prices of $9.00 per share, subject to certain adjustments. The Company also issued to the placement agents warrants to purchase up to 96,957 shares of common stock at an exercise price of $9.00. The shares and warrants were sold to certain accredited investors. Subject to certain conditions, the Company has the right to call for the exercise of such warrants. The Company incurred costs of $1.5 million in connection with this offering.

Par value of common stock issued	$	3,697
Paid-in capital		19,716,706
Offering expenses		1,537,375
Total gross proceeds	$	21,257,778

On July 15, 2011, the Company closed a private placement offering of $12,980,003 through the issuance of (i) 2,260,870 shares of common stock at a price of $5.75 per share, (ii) Series A warrants to purchase 1,130,435 shares of common stock at a per share exercise price of $9.00 subject to certain adjustment provisions; and (iii) Series B warrants at a per share exercise price of $0.001 to purchase a number of shares of common stock, which became exercisable on the 30th trading day following the date on which the purchasers in the private placement were able to freely sell the shares of common stock pursuant to Rule 144 promulgated under the Securities Act of 1933, as amended, without restriction (the “Eligibility Date”) as the market price of the common stock was less than the purchase price in the offering or $5.75.

F-16

Pursuant to the terms of the Series B warrants, on the Eligibility Date the investors had the right to purchase a number of shares of common stock such that the aggregate average price per share purchased by the investors was equal to the market price (defined as the average of volume weighted average price for each of the previous 30 days as reported on the Over-The-Counter Bulletin Board during the 30 trading days preceding the measurement date). Certain holders of Series B warrants agreed to limit their right to adjustments in certain circumstances such that the total number of shares of common stock underlying the Series B warrants was set at 2,239,029. See Note I. Derivative warrant instruments (liabilities) and warrants. Exclusive of the non-cash warrant expense, the Company incurred costs of approximately $1.0 million in connection with this offering.

Par value of common stock issued	$	2,261
Paid-in capital		8,008,733
Derivative warrant instruments		3,971,009
Offering expenses		998,000
Total gross proceeds	$	12,980,003

In connection with the February 1, 2011 and March 31, 2011 private placement offerings, the Company granted to the investors registration rights pursuant to Registration Rights Agreements, dated February 1, 2011 and March 31, 2011, in which the Company agreed to register all of the related private placement common shares and shares of common stock underlying the warrants within thirty (30) calendar days after February 1, 2011 and March 31, 2011, and use its best efforts to have the registration statement declared effective within one hundred twenty (120) calendar days of the applicable filing date. Upon the Company’s failure to comply with the terms of the Registration Rights Agreement and certain other conditions, the Company was required to pay to each investor an amount in common stock equal to one percent (1%) per month of the aggregate purchase price paid by such investor, up to 6% of the aggregate stock purchase price. As the Company did not register the shares within thirty calendar days of February 1, 2011 and March 31, 2011, the Company was required to pay in common stock 1% of the aggregate purchase price per month. Shares distributed were calculated based on the price of issuance of $3.50 per share for the February 1, 2011 private placement offering and $5.75 per share for the March 31, 2011 placement. In November 2011, the Company remitted 459,074 additional shares, calculated by dividing the respective cash value of each private placements penalty by the respective unit price under which each private placement was funded. For the year ended December 31, 2011, the Company recognized $2,019,943 of delinquent registration penalties which were recorded in the year ended December 31, 2011. No additional penalties were incurred and no additional expense was recognized during the year ended December 31, 2012.

Deferred Compensation Program

On April 15, 2010, Nevada ASEC’s Board of Directors approved the 2010 Deferred Compensation Program which was ratified by the Company on August 29, 2011. Under this plan, the President and CEO are entitled to receive a one-time retainer fee consisting of options to purchase common stock in lieu of salary through December 31, 2010. The total number of shares underlying options granted under the plan was 1,600,000 in lieu of salary through December 31, 2010. The exercise price of the options was $1.50 and the options were to vest over 26.5 months. These options have a ten-year life and had a grant date fair value of $1.09 per share. On March 30, 2012 the vesting on all remaining deferred compensation was accelerated and fully-vested at that date. For the year ended December 31, 2012 and 2011, the Company recorded non-cash stock compensation expense of $394,868 and $789,736, respectively, related to the amortization of the fair value of these options which is included in general and administrative expenses.

F-17

Other Share Based Compensation

On August 29, 2011, the Company's Board of Directors adopted the Amended and Restated 2010 Equity Incentive Plan initially approved April 15, 2010. The amended plan provides for 12,000,000 shares to be eligible for issuance to officers, other key employees, directors and consultants. Since April 15, 2010, the Board of Directors authorized the grants of 11,265,000 stock options under the 2010 plan.

As part of management's employment agreements, 7,400,000 options were granted to officers of the Company on April 15, 2011 under the 2010 Equity Incentive Plan with an exercise price of $7.45. 120,000 options granted in 2010 and 400,000 options granted in 2011 were forfeited in August 2011, relating to the departure of an employee from the Company. 2,200,000 of these options vest semiannually in equal installments through April 2012, and the remaining 4,800,000 options vest over the subsequent 48 months thereafter in equal semiannual installments per their original vesting schedule. These options have a ten year life and had a grant date fair value ranging from $4.59 to $5.04 per share.

As part of a comprehensive review of compensation, compensation expense, and shareholder dilution, the Board of Directors approved the restructuring of stock options on March 30, 2012 (the “Modification Date”). Due to the modification, 2,400,000 options issued to certain officers were forfeited and 3,200,000 options were accelerated and became immediately vested. An additional 1,540,000 non-qualified options, 205,760 incentive stock options and 80,000 restricted shares (previously discussed) of common stock were granted to certain officers, directors, employees and a consultant. All modified options (including the newly issued options) were priced at the average of the open and closing share price of the Company’s common stock on March 30, 2012, which was $2.43 per share and became fully vested on the Modification Date.

An additional 2,881,152 options were forfeited in 2012 due to the departure and resignations of three Board members and one officer of the Company.

For the years ended December 31, 2012 and 2011, the Company recorded non-cash stock-based compensation expense of$31,418,129 and $8,855,320, respectively, related to other share based compensation which is included in general and administrative expenses.

F-18

The following table summarizes the stock options available and outstanding as of December 31, 2012:

	Options Available for Grant Under 2010 and 2011 Plans			Outstanding Options			Weighted Average Exercise Price
Balance at December 31, 2010		2,275,000			3,725,000			1.65
Additional options authorized under amended plan		6,000,000			-			-
Granted		(7,540,000	)		7,540,000			7.68
Forfeited		-			(520,000	)		6.08
Balance at December 31, 2011		735,000			10,745,000			5.67
Additional options authorized under 2011 plan		10,000,000			-			-
Granted		(1,755,760	)		1,755,760			2.43
Forfeited		-			(5,281,152	)		4.65
Balance at December 31, 2012		8,979,240			7,219,608			2.07

The options outstanding as of December 31, 2012 are summarized as follows:

		Options Outstanding and Exercisable
Range of Exercise Price		Number Outstanding		Weighted Average Exercise Price		Weighted Average Remaining Contractual Term
	$1.50 - $2.70		7,219,608		2.07		7.97

The aggregate intrinsic value of $1.50 - $2.70 options outstanding and exercisable was $0 and $5,378,250 at December 31, 2012 and 2011, respectively.

The fair value of each option award is estimated on the date of grant. The fair values of stock options were determined using the Black-Scholes option valuation method and the assumptions noted in the following table for 2012 and 2011. Expected volatilities are based on implied volatilities from the historical volatility of companies similar to the Company. The expected term of the options granted used in the Black-Scholes model represent the period of time that options granted are expected to be outstanding. The Company utilizes the simplified method for calculating the expected life of its options as the Company does not have sufficient historical data to provide a basis upon which to estimate the term.

	2012	2011
Expected volatility	77%	68.96%
Expected dividends	-	-
Expected term (in years)	4.09 - 4.75	5.5 – 6.5
Risk-free rate	0.88 – 1.01%	3.43%

The fair value of option grants during the year ended December 31, 2012 and 2011 was $585,899 and $35,608,467, respectively.

F-19

Series A Cumulative Convertible Preferred Stock

On June 30, 2012, the Company entered into an Exchange Agreement with Geronimo pursuant to which the Company agreed to issue 35,400 shares (the “Geronimo Shares”) of the Company’s newly created Series A Cumulative Convertible Preferred Stock (“Series A Preferred Stock”) to Geronimo having the rights and preferences set forth in a Certificate of Designation in exchange for the cancelation of the Geronimo Note. Effective February 18, 2013, Saber Oil, LLC purchased the 35,400 shares of the Series A Preferred Stock from Geronimo.

Pursuant to the Certificate of Designation, the Series A Preferred Stock accrues cumulative dividends semi-annually at a rate per share equal to 7.5% per annum. The holders of the Series A Preferred Stock shall receive dividends when and if declared by the Company’s Board of Directors in preference to and priority over dividends declared on the common stock. Dividends are payable by the Company in either additional shares of Series A Preferred Stock for dividends accrued on or before June 30, 2014 or cash. Holders of Series A Preferred Stock shall be entitled to receive $1,000 per share in the event of a liquidation with priority over the common stock.

The Series A Preferred Stock is convertible into shares of common stock at a rate of 333.333 shares of common stock per share of Series A Preferred Stock (the “Conversion Rate”) or an initial conversion price of $3.00 per share on or after the later of (i) March 6, 2013 and (ii) the date on which the Company increases the authorized but unissued shares of common stock to such number of shares as shall be sufficient to effect the conversion of all then outstanding shares of the Preferred Stock on a fully-diluted basis. The Company is entitled to decrease the Conversion Rate one time on or before June 30, 2014 to equal the quotient of $1,000 divided by the average closing sale price for the ten trading day period after the Company makes the election, the effect of which would be to increase the conversion price. The Company has the right, in its sole discretion, to cause all Series A Preferred Stock to be automatically converted into shares of common stock at the Conversion Rate if the closing sale price of the common stock equals or exceeds 150% of $3.00 for at least 10 trading days during any 20 consecutive trading day period. Holders of Series A Preferred Stock are not entitled to any voting rights, except as required by law.

Note E. Long term debt

Macquarie Credit Facility. On September 21, 2011, Nevada ASEC (the “Borrower”), entered into a Credit Agreement (the “Credit Agreement”) with the lenders party thereto and Macquarie Bank Limited (“Macquarie”) as administrative agent. The Credit Agreement is fully and unconditionally guaranteed by the Company (the “Guarantor”). The Guarantor has pledged as collateral 100% of its stock in the Borrower. The Borrower’s obligations under the Credit Agreement are secured by, among other assets, the Borrower’s interest in certain oil and natural gas properties and the hydrocarbons produced from such properties, as well as the proceeds of the sale of such hydrocarbons.

F-20

The Credit Agreement provides to the Borrower a revolving credit facility in an amount not to exceed $100 million and a term loan facility in an amount not to exceed $200 million. The rate is equal to (i) the lesser of (A) Prime Rate plus the Applicable Margin and (B) the Highest Lawful Rate or (ii) the lesser of (A) the LIBOR Rate plus the Applicable Margin, and (B) the Highest Lawful Rate, as selected by the Borrower, plus a margin of 2.75% to 3.25% per annum (3.25% at December 31, 2012), based on the borrowing base utilization, and the interest rate on term loans is 30, 60 or 90 day LIBOR, as selected by the Borrower, plus a margin of 7.50%. The maturity date of the revolving credit facility is September 21, 2015 and the maturity date of the term loan facility is September 21, 2014. The Credit Agreement contains covenants that limit the Company’s ability to, among other things, incur additional debt other than the ASEN 2 loans, create certain liens, enter into transactions with affiliates unless in compliance with specific provisions, pay dividends on or repurchase stock of the Company or its subsidiaries, or merge with another entity. In addition, the Borrower is required to comply with the financial covenants set forth in the Credit Agreement, including an interest coverage ratio, a current ratio, and a debt coverage ratio, as of the end of each calendar quarter. The Company failed to comply with the current ratio covenant and incurred general and administrative expenses in excess of the limit contained in the Credit Agreement, in each case for the calendar year ended December 31, 2012. The covenant violations were waived by Macquarie on May 15, 2013.

On June 4, 2013, Nevada ASEC received a letter from Macquarie notifying Nevada ASEC that an event of default occurred under the Credit Agreement due to the non-payment of the amortization payment due and owing on May 31, 2013. Due to this default, the debt outstanding at December 31, 2012 under this agreement is classified as a current liability.

The initial borrowing base and amount drawn on the revolving credit facility was $12 million. The debt was initially recorded net of a debt discount of $10,917,981 related to warrants issued to the lenders as disclosed below. The debt discount will be amortized over the term of the credit facility. The outstanding amount on the revolving credit facility at December 31, 2012 was $13.1 million. The borrowing base is re-determined semiannually based on the reserve reports by category, oil and natural gas future sales prices as determined by Macquarie, and amount of expenses necessary to produce the oil and natural gas.

F-21

The table below reflects the breakdown of the components of the term loan and revolving credit facility at December 31, 2012:

Debt proceeds from revolver	$	13,100,000
Debt proceeds from term loan		2,841,352
Total debt proceeds	$	15,941,352
Discount on debt		(10,917,981	)
Amortization of debt discount		5,737,046
Net revolving facility and term loan	$	10,760,417

The term loan draws are subject to approval by Macquarie on a case by case basis. Each drilling program is submitted for approval and Macquarie may approve the program in its reasonable discretion. After Macquarie approves a program, the lenders are obligated to advance funds for development, subject to the satisfaction of the conditions precedent to advances set forth in the Credit Agreement. Alternatively, the Company may elect to submit successfully completed wells to the bank for review and reimbursement under the term loan. The outstanding balance on the term loan was $2,841,352 at December 31, 2012. Beginning on March 21, 2013, the Company will begin making monthly payments to amortize the term loan, each payment equal to the total outstanding term loan balance on that date divided by 18. Based on the outstanding balance of the term loan on December 31, 2012, the Company expects to pay $1,420,676 in each of the years 2013 and 2014.

In connection with the Credit Agreement, the Company issued to Macquarie Americas Corp. a five year warrant to purchase 5,000,000 shares of the Company’s common stock at a per share exercise price of $7.50. The warrant is exercisable on a cashless basis if there is no registration statement covering the underlying common stock. The warrant is also subject to customary anti-dilution provisions. The fair value of the 5,000,000 warrants issued to Macquarie was calculated using the Monte Carlo valuation model based on factors present at the time of closing. Macquarie can exercise these warrants at any time until the warrants expire in July 2016. The exercise price of the warrants is $7.50 per warrant, subject to “down round” adjustments. The fair value at issuance date of $10,917,981 was recorded as a discount on the debt as described above. See Note I for discussion of the modification of the terms of these warrants in February 2012.

Convertible Note. On February 10, 2012, the Company and ASEN 2, closed on a Note and Warrant Purchase Agreement dated February 9, 2012, (the “Purchase Agreement”), with Pentwater Equity Opportunities Master Fund Ltd. and PWCM Master Fund Ltd., (“Pentwater”) in connection with a $20 million private financing. The initial funding made by Pentwater to ASEN 2 on February 10, 2012 (“Pentwater Closing Date”), was in the amount of $10 million. The second funding for an additional $10 million, which closed on March 5, 2012, occurred concurrently with the closing of the purchase and sale agreement by and among the Company, Geronimo and XOG. ASEN 2’s obligations of Pentwater are guaranteed by the Company.

F-22

The borrowings under the Purchase Agreement were originally evidenced by a $20 million secured convertible promissory note (the “Pentwater Note”), convertible into shares of the Company’s common stock at a conversion price of $9.00 per share and five-year warrants to purchase 3,333,333 shares of common stock at a per share cash exercise price of $2.50. The Warrants are also subject to a mandatory exercise at the Company’s option with respect to (i) 50% of the number of shares underlying the Warrants if the closing sale price of the common stock is equal to or greater than $5.00 per share for twenty consecutive trading days and (ii) 50% of the number of Warrant Shares if the closing sale price of the common stock is equal to or greater than $9.00 per share for twenty consecutive trading days.

From the Pentwater Closing Date through December 8, 2012, the outstanding borrowings under the Pentwater Note bear an interest rate of 11% per annum, payable as follows (i) interest at a rate of 9% per annum is payable on the first business day of each month, commencing on March 1, 2012 and (ii) interest at a rate of 2% per annum is capitalized and added to the then unpaid principal amount monthly in arrears on the first business day of each month commencing on March 1, 2012. On and after December 9, 2012 through the maturity date, the Pentwater Note bears an interest rate of 16% per annum, payable as follows: (i) interest at a rate of 11% per annum is payable on the first business day of each month commencing on December 1, 2012 and (ii) interest at a rate of 5% per annum is capitalized and added to the then unpaid principal amount monthly on the first business day of each month commencing on December 1, 2012. The Pentwater Note had a maturity date of February 9, 2015, which was amended on March 5, 2012 to December 1, 2013. ASEN 2 can prepay the Pentwater Note without penalty prior to December 31, 2012. If the prepayment occurs after December 31, 2012, ASEN 2 must pay to Pentwater 106% of the then outstanding principal amount of the Pentwater Note that is prepaid. At any time after February 9, 2013, the principal amount and interest of the Pentwater Note may be converted into shares of common stock at a conversion price of $9.00 per share.

F-23

Pursuant to the terms of the Second Amendment, the Purchase Agreement was amended such that 100% of the net cash proceeds of any disposition of assets by ASEN 2 must be used to prepay the Note and any disposition by ASEN 2 of collateral securing ASEN 2’s obligations under the Note and the Purchase Agreement must be approved by Pentwater, other than dispositions of inventory in the ordinary course of business or of obsolete or worn out assets. The Second Amendment further provided that ASEN 2 must engage operational consultants with engineering expertise within thirty days from the date of the Second Amendment. Additionally, Pentwater has the right to nominate, and the Company shall take all steps necessary to elect, two directors to the Company’s board of directors to fill the vacancies left upon the resignation of certain directors. Thereafter, Pentwater shall be entitled to propose the nomination of two directors to the Company’s board each time the members of the board of directors appointed by Pentwater are up for election; provided that, in no event shall Pentwater be entitled to nominate and elect more than two directors to the Company’s board. The Purchase Agreement was further amended to prohibit the Company from amending or proposing an amendment to the bylaws or certificate of incorporation of the Company without Pentwater’s consent. Pursuant to the terms of the Second Amendment, the principal amount of the Note was increased by $89,059. Both of the Pentwater nominees were appointed to the Board on February 12, 2013.

As a condition to the effectiveness of the Second Amendment, Pentwater transferred a portion of the Note equal to $2,750,000 (the “Transferred Indebtedness”) to Antler Bar Investments LLC, an affiliate of Pentwater (“Antler Bar”). All other material terms of the Purchase Agreement and Note remain unchanged and in full force and effect.

F-24

The principal amount of the amended convertible note was $25 million. The debt was recorded net of a debt discount of $6,300,515 related to warrants issued as discussed above. The debt discount is being amortized over the term of the Pentwater Note. The outstanding amount on the Pentwater Note at December 31, 2012 was $21,983,739 with $421,548 in capitalized interest.

The table below reflects the breakdown of the components of the Pentwater Note at December 31, 2012:

Net cash proceeds from Pentwater	$	21,983,739
Discount on debt		(6,300,515	)
Accretion of debt discount		3,423,266
Capitalized interest		421,548
Net amount of Pentwater Note	$	19,528,038

Geronimo Note. On March 5, 2012, the Company acquired leasehold working interests in approximately 61,500 net developed and undeveloped acres across the Permian Basin, the Bakken, the Eagle Ford, the Niobrara, the Eagle Bine, and the Gulf Coast (collectively, the “March 2012 Properties”) from a related party. In conjunction with this transaction, the Company entered into a $35,000,000 promissory note (the “Geronimo Note”) made by the Company in favor of Geronimo. The Geronimo Note bears an interest rate of 7% per annum, which shall be increased to 9% per annum upon an event of default, payable on the first business day of each month commencing on June 1, 2012. The Geronimo Note matures on March 21, 2016. The Company may prepay the Geronimo Note at any time without penalty. On June 30, 2012, the Company entered into an Exchange Agreement with Geronimo pursuant to which the Company issued 35,400 shares (the “Geronimo Shares”) of newly created Series A Preferred Stock to Geronimo in exchange for the cancellation of the Geronimo Note. The terms of the Purchase and Sale Agreement provided for a reduction or setoff of the principal amount of the Geronimo Note under certain conditions. Pursuant to the terms of the Exchange Agreement, in the event that the Company would have been entitled to any reduction in or setoff against the principal amount of the Geronimo Note pursuant to the terms of the Purchase Agreement, Geronimo is obligated to transfer a portion of the Geronimo Shares equal to one share of Series A Preferred Stock and any dividends accrued thereon for each $1,000 that would have resulted in a reduction in, or setoff against, the principal amount of the Geronimo Note. Therefore, as of December 31, 2012, there is no amount outstanding for the Geronimo Note. This exchange was reflected as a contribution of Capital on June 30, 2012. Holders of preferred stock shall be entitled to receive $1,000 per share in the event of a liquidation with priority over the common stock.

Note F. Asset Retirement Obligations

The Company's asset retirement obligations represent the estimated present value of the estimated cash flows the Company will incur to plug, abandon and remediate its producing properties at the end of their productive lives, in accordance with applicable state laws. The Company has no assets that are legally restricted for purposes of settling asset retirement obligations.

F-25

The Company's asset retirement obligation activity for the years ended December 31, 2012 and 2011 is as follows:

	2012		2011
Balance at beginning of period	$	394,177	$	242,632
Liabilities incurred from new wells		1,299,242		94,880
Accretion expense		44,072		20,951
Revisions due to changes in well life estimates		78,132		35,714
Balance at end of period	$	1,815,623	$	394,177

Note G. Income taxes

The following table reconciles the Company’s provision for income taxes for the year ended December 31, 2012 and 2011, included in the consolidated statements of operations with the provision which would result from the application of the statutory federal tax rate to pre-tax financial loss:

	2012			2011

Loss before tax	$	(75,728,195	)	$	(15,319,831	)
Statutory rate		35	%		35	%

Income tax benefit at federal statutory rate		(26,504,868	)		(5,361,941	)
State income tax benefit, net of federal benefit		(1,462,651	)		(285,742	)
Nondeductible Stock Comp		-			-
Accretion of Debt Discount		3,009,687			372,679
Book Income not subject to tax		-			(164,221	)
Warrant Modification Consideration		2,007,660			-
Gain on Debt Settlement Recorded to Equity		139,617			-
Change in DTA due to Rate		(12,734	)		-
Other permanent items and adjustments		41,489			(47,327	)
Valuation Allowance		22,781,800			4,881,820
Income tax benefit	$	-		$	(604,732	)

Effective rate		0	%		3.95	%

F-26

The components of the Company's net deferred tax assets as of December 31, 2012 and 2011 are as follows:

	2012			2011
Deferred income tax assets:

Equity compensation		16,736,973			4,957,972
Differences between book and tax basis of property		2,761,291			-
Asset retirement obligations		685,753			145,292
Unrealized Loss on Derivatives		(37,168	)		396,532
Capitalized Interest		389,156			-
Net operating loss carry forward		15,980,610			23,801,479
Other		517			516
Less: Valuation Allowance		(36,517,132	)		(7,082,769	)
		-			22,219,022

Deferred income tax liabilities:

Differences between book and tax basis of property		-			(22,219,022	)

The Company’s net operating loss carry forward (NOL) at December 31, 2012 was $43,271,010 and will expire beginning in the year 2030. In preparing the 2011 US Federal tax return, the Company changed certain elections to capitalize certain costs that resulted in a reduction in the NOL generated resulting in a reduction in the reported deferred tax asset from 2011 to 2012. This reduction in the NOL deferred tax asset was offset by increases in the book/tax basis difference of properties. The net DTA position of the Company remain unchanged upon filing the 2011 tax return. The Company continually assesses both positive and negative evidence to determine whether it is more likely than not that deferred tax assets can be realized prior to their expiration. Management monitors Company-specific, oil and natural gas industry and worldwide economic factors and assesses the likelihood that the Company’s NOLs and other deferred tax attributes in the United States, state, and local tax jurisdictions will be utilized prior to their expiration. At December 31, 2012, the Company has a valuation allowance of $36,517,132 related to its deferred tax assets.

As of December 31, 2012, the company had no unrecognized tax benefits. 2012, 2011 and 2010 are the only taxable years that are open to examination by the major taxing jurisdictions to which the Company is subject.

Note H. Commodity derivatives

To mitigate a portion of the exposure to potentially adverse market changes in oil and natural gas prices and the associated impact on cash flows, the Company has entered into various derivative commodity contracts. The Company’s derivative contracts in place include swap arrangements for oil and natural gas. Through the filing date of this Annual Report on Form 10-K, the Company has commodity derivative contracts in place through the fourth quarter of 2014 for a total of approximately 61,649 Bbls of anticipated crude oil production and 297,688 MMBtu of anticipated natural gas production.

The Company’s oil and natural gas derivatives are measured at fair value and are included in the accompanying balance sheets as commodity derivative assets and liabilities. The Company derives internal valuation estimates taking into consideration the counterparties’ credit ratings, the Company’s credit rating, and the time value of money. These valuations are then compared to the respective counterparties’ mark-to-market statements. The pertinent factors result in an estimated exit-price that management believes provides a reasonable and consistent methodology for valuing derivative instruments. The derivative instruments utilized by the Company are not considered by management to be complex, structured, or illiquid. The oil and natural gas derivative markets are highly active. The fair value of oil and natural gas commodity derivative contracts was a net liability of $154,218 and $665,960 at December 31, 2012 and 2011, respectively.

F-27

The Company recognizes all gains and losses from changes in commodity derivative fair values immediately in earnings. For the year ended December 31, 2012, the Company had a realized gain on commodity derivatives of $29,566 and an unrealized gain of $511,742 included in other income (expense).

A summary of our commodity derivatives at December 31, 2012 is as follows:

Period of time		Barrels of Oil				Weighted Average Oil Prices				Estimated Fair Market Value
January 1, 2013 through October 31, 2014			77,879			$	82.62			$	(408,279	)

Period of time	MMBtu of Natural Gas		Weighted Average Gas Prices		Estimated Fair Market Value
January 1, 2013 through September 26, 2014		376,089	$	4.4	$	254,061

Total fair market value					$	(154,218	)

The following table details the fair value of derivatives recorded in the accompanying balance sheets, by category:

	As of December 31, 2012
	Derivative Assets			Derivative Liabilities
	Balance Sheet			Balance Sheet
	Classification	Fair Value		Classification	Fair Value
Commodity Contracts	Current Assets	$	-	Current Liabilities	$	(40,889	)
Commodity Contracts	Noncurrent Assets		-	Noncurrent Liabilities		(113,329	)
Total commodity derivatives		$	-		$	(154,218	)

Note I. Derivative warrant instruments (liabilities)

As part of the July 15, 2011, private placement, the Company issued Series A Warrants to purchase common stock to certain accredited investors in connection with its sale of 2,260,870 share-based units for gross proceeds of approximately $13.0 million. As of December 31, 2012, there were 1,043,478 Series A warrants with an original exercise price of $9.00 per share, subject to “down round” adjustments with a floor price of $5.00. On July 23, 2012, as a result of the Second Amendment described in Note E. Long Term Debt, the Series A Warrants to purchase common stock were adjusted to the floor price of $5.00 per share.

F-28

In September of 2011, the Company issued warrants that will allow Macquarie the right to purchase up to 5,000,000 shares of fully-paid and non-assessable common stock at a per share purchase price of $7.50, subject to certain “down round” adjustments events.

Because of the adjustment events, the Warrants are not deemed to be “indexed to the Company’s own stock” and, therefore, do not qualify for the scope exception in ASC 815-40-15-5. As such, the Company concluded that these warrants were deemed to be derivative instruments. The warrants were recorded as liabilities at fair value, and marked-to-market at each financial statement reporting date, pursuant to the guidance in ASC 815-10.

During the year ended December 31, 2012 the fair value of the liability of the warrant derivative instruments decreased by $1,144,832, from their fair values at December 31, 2011. Such changes were recorded as income on fair value of derivative warrant instruments in the accompanying consolidated statements of operations. The fair value of these warrants is determined using a Monte Carlo Simulation Analysis and is affected by changes in inputs to that model including our stock price, expected stock volatility, the contractual term, and the risk-free interest rate.

During the year ended December 31, 2011 the fair value of the liability of the warrant derivative instruments increased by $409,668, from their initial fair values. Such changes were recorded as unrealized losses on fair value of derivative warrant instruments in the accompanying consolidated statements of operations.

Pentwater Warrant Restructure. On February 10, 2012, the Company, Pentwater and two affiliated entities of Pentwater, (“Modification Investors”), entered into a modification agreement (the “Modification Agreement”), pursuant to which the parties agreed to amend the terms of the Series B warrants issued to the Modification Investors in the July 13, 2011 offering in which the Modification Investors invested $12 million. Pursuant to the terms of the Modification Agreement, the parties agreed to limit the dilutive effects of the Series B warrants by including a floor of $3.00 per share in the calculation of the reset provision included in the Series B Warrants. Accordingly, the aggregate number of shares of common stock underlying the Series B warrants held by the Modification Investors is 1,913,043 shares. Due to the elimination of the “down-round” provisions, these warrants qualify for equity presentation as of the modification date.

As additional consideration for the modification of the Series B Warrants, the Company agreed to issue to the Modification Investors new five-year Series C warrants to purchase 2.5 million shares of common stock with a cash exercise price of $3.00 per share. The Series C warrants include a provision under which the Series C warrants must be exercised at the election of the Company by the Modification Investors for cash if the closing sales price of the common stock is $6.00 per share or greater for 20-consecutive trading days. As a result of the issuance of the Series B warrants and the Series C warrants, the exercise prices and number of shares underlying the Series A warrants and Series B warrants held by the remaining investor in the July 13, 2011 offering were adjusted pursuant to their terms. As the Series C Warrants were consideration given pursuant to the Modification Agreement, the fair value of these warrants on the modification date were expensed as a component of realized and unrealized expense on warrant derivatives in the consolidated statement of operations.

F-29

Macquarie Warrant Restructure. In connection with the consent provided by Macquarie Bank to the issuance of the Pentwater Note and the transactions contemplated under the Modification Agreement, pursuant to the terms of the Credit Agreement, the Company agreed (i) to pay to Macquarie Bank a $1,100,000 modification fee and (ii) to amend and restate the Macquarie Warrant. Accordingly on February 9, 2012, the Company issued an amended and restated Macquarie Warrant (the “Amended Macquarie Warrant”) to Macquarie Americas to purchase up to 2,333,000 shares of common stock, at an exercise price of $3.25 per share. The Amended Macquarie Warrant is not subject to further anti-dilution provisions other than customary reset provisions for stock splits, subdivision or combinations. The Amended Macquarie Warrant is exercisable on a cashless basis if there is no registration statement covering the underlying common stock. The Company granted the holder piggy-back registration rights on the underlying common stock. As the warrant modification fee was consideration given as part of the modification, it was expensed as a component of realized and unrealized expense on warrant derivatives in the consolidated statement of operations.

Activity for derivative warrant instruments during the years ended December 31, 2011 and 2012 are as follows:

	Initial fair value as of July 15, 2011		Initial fair value as of September 21, 2011		Increase (decrease) in fair value of derivative liability			Fair value December 31, 2011
Derivative warrant instruments for Series A and Series B Warrants	$	3,971,009	$	-	$	4,148,444		$	8,119,453
Derivative warrant instruments for Macquarie warrants		-		10,917,981		(3,738,776	)		7,179,205
	$	3,971,009	$	10,917,981	$	409,668		$	15,298,658

F-30

	Fair value as of December 31, 2011		Increase (decrease) in fair value of derivative liability			Reclassification to equity due to Modification			Fair value December 31, 2012
Derivative warrant instruments for Series A and Series B Warrants	$	8,119,453	$	(895,952	)	$	(7,223,501	)	$	-
Derivative warrant instruments for Macquarie warrants		7,179,205		231,427			(7,410,632	)		-
	$	15,298,658	$	664,525		$	(14,634,133	)	$	-

The fair value of the derivative warrant instruments is estimated using a probability-weighted scenario analysis model with the following assumptions during the year ended December 31, 2012:

	For the Year Ended December 31,
	2012
Estimated market value of common stock on measurement date (1)	$ 1.07 - 3.00
Exercise price	$ 5.00 - 9.00
Expected volatility (2)	63% - 84	%
Expected term (in months)	44.8 - 53.9
Risk-free rate (3)	0.43% - 0.81	%
Expected dividend yields	-
Future financing event	25% - 50	%

(1)

The estimated market value of the stock is measured each period-end and is based on the reported public market prices.

(2)

The volatility factor was estimated by management using the historical volatilities of comparable companies in the same industry and region.

(3)

The risk-free rate of return associated with the remaining term.Source: The Federal Reserve Board

Note J. Fair value measurements

The Company follows fair value measurement authoritative guidance for all assets and liabilities measured at fair value. That guidance defines fair value as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. Market or observable inputs are the preferred sources of values, followed by assumptions based on hypothetical transactions in the absence of market inputs. The hierarchy for grouping these assets and liabilities is based on the significance level of the following inputs:

F-31

Level 1 — quoted prices in active markets for identical assets or liabilities

Level 2 — quoted prices in active markets for similar assets and liabilities, quoted prices for identical or similar instruments in markets that are not active, and model-derived valuations whose inputs are observable or whose significant value drivers are observable.

Level 3 — significant inputs to the valuation model are unobservable.

The following is a listing of the Company’s financial assets and liabilities that are measured at fair value on a recurring basis and where they are classified within the hierarchy as of December 31, 2012:

	Level 1		Level 2		Level 3
Assets:
Commodity derivatives	$	-	$	-	$	-
Liabilities:
Commodity derivatives	$	-	$	154,218	$	-
Warrant derivatives	$	-	$	-	$	-
Term loan and credit facility	$	-	$	10,760,417	$	-
Pentwater note	$	-	$	19,528,038	$	-

	Level 1		Level 2		Level 3
Assets:
Commodity derivatives	$	-	$	-	$	-
Liabilities:
Commodity derivatives	$	-	$	665,959	$	-
Warrant derivatives	$	-	$	-	$	15,298,658
Term loan and credit facility	$	-	$	7,262,832	$	-

The Company uses Level 2 inputs to measure the fair value of its commodity derivatives. Fair values are based upon interpolated data. The Company derives internal valuation estimates taking into consideration the counterparties’ credit ratings, the Company’s credit rating, and the time value of money. These valuations are then compared to the respective counterparties’ mark-to-market statements. The considered factors result in an estimated exit-price that management believes provides a reasonable and consistent methodology for valuing derivative instruments.

F-32

The following table reflects the activity for warrant derivative liabilities measured at fair value using Level 3 inputs:

	For the Years
	Ended December 31,
	2012			2011
Beginning balance	$	(15,298,658	)	$	-
Additions		-			(14,888,990	)
Net (increase) decrease in fair value of liabilities		664,525			(409,668	)
Transfers in (out) of Level 3		14,634,133			-
Ending balance	$	-		$	(15,298,658	)

Generally, market quotes assume that all counterparties have near zero, or low, default rates and have equal credit quality. However, an adjustment may be necessary to reflect the credit quality of a specific counterparty to determine the fair value of the instrument.

The methods described above may result in a fair value estimate that may not be indicative of net realizable value or may not be reflective of future fair values and cash flows. While the Company believes that the valuation methods utilized are appropriate and consistent with accounting authoritative guidance and with other marketplace participants, the Company recognizes that third parties may use different methodologies or assumptions to determine the fair value of certain financial instruments that could result in a different estimate of fair value at the reporting date.

The fair value of the warrants was calculated using the Monte Carlo valuation model based on factors present at the time of closing of the private placement offering on July 15, 2011 and the credit facility on September 21, 2011 and updated as of July 23, 2012.

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

Certain assets and liabilities are reported at fair value on a nonrecurring basis in the Company's consolidated balance sheets. The following methods and assumptions were used to estimate the fair values:

Impairments of Long-Lived Assets.The Company reviews its long-lived assets to be held and used, including proved oil and natural gas properties, whenever events or circumstances indicate that the carrying value of those assets may not be recoverable. An impairment loss is indicated if the sum of the expected undiscounted future net cash flows is less than the carrying amount of the assets. In this circumstance, the Company recognizes an impairment loss for the amount by which the carrying amount of the asset exceeds the estimated fair value of the asset. The Company reviews its oil and natural gas properties by amortization base or by individual well for those wells not constituting part of an amortization base. For each property determined to be impaired, an impairment loss equal to the difference between the carrying value of the properties and the estimated fair value (discounted future cash flows) of the properties is recognized at that time. Estimating future cash flows involves the use of judgments, including estimation of the proved and unproved oil and natural gas reserve quantities, timing of development and production, expected future commodity prices, capital expenditures and production costs. During the years ended December 31, 2012 and 2011, the Company recorded impairments of $28,640,726 and $1,027,552.

Asset Retirement Obligations (“ARO”).The initial recognition of AROs is based on fair value. The Company estimates the fair value of AROs based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors as the existence of a legal obligation for an ARO; amounts and timing of settlements; the credit-adjusted risk-free rate to be used; and inflation rates. See Note F for a summary of changes in ARO for the periods ended December 31, 2012 and 2011.

F-33

Acquisitions.Assets acquisitions not under common control are recorded at fair value. The Company closed asset acquisitions on August 22, 2011 and November 1, 2011, which were recorded at fair value as described in Note L.

Long-Term Notes Payable and Debt. The carrying amount of the long-term notes payable to Pentwater as of December 31, 2012 approximates fair value because the Company’s current borrowing rate does not materially differ from market rates for similar bank borrowings. The long-term notes payable have only been outstanding for a short period of time and as such, the carrying value approximates fair value. The book value of our term loan and credit facility with Macquarie approximates fair value because of its floating rate structure. The Company has classified the long-term notes payable and credit facility as Level 2 items within the fair value hierarchy.

Note K. Major Customers

The Company's producing oil and natural gas properties are located in Texas, New Mexico, Arkansas, Oklahoma and North Dakota. At December 31, 2012, the Company contracts with a number of various operators and notes one operator in which revenues received were greater than 10% of total revenues. During 2012 and 2011, revenue through XOG accounted for approximately 54% and 67% of total revenues, respectively. Although operators are not the end purchasers of oil and natural gas, the Company is of the opinion that the loss of any one purchaser would not have a material adverse effect on the ability of the Company to sell its oil and natural gas production as such production can be sold to other purchasers.

Note L. Asset Acquisitions

On August 22, 2011, the Company acquired approximately 13,324 net undeveloped leasehold acres in the Bakken/Three Forks (the “Bakken 4 Properties”) area from XOG Group for approximately $14.6 million. A cash deposit of $13,500,000 was made on April 15, 2011 and the Company subsequently issued 208,200 shares of common stock upon closing, which was valued at $1,093,050 using the stock price of $5.25 on the closing date. The acquisition was recorded at fair value as XOG Group and the Company were not under common control at the time of the asset acquisition.

On November 1, 2011, the Company acquired approximately 391 net undeveloped leasehold acres in the Bakken/Three Forks area from XOG Group for approximately $1.2 million dollars paid in cash. The acquisition was recorded at fair value as the XOG Group and the Company were not under common control at the time of the asset acquisition.

F-34

On March 5, 2012, the Company acquired the March 2012 Properties in exchange for the delivery by the Company to the Sellers of $10 million in cash, less a $1.5 million cash deposit previously paid by the Company, the Geronimo Note (as discussed in Note E) made by the Company in favor of Geronimo and 5,000,000 shares of the common stock of the Company, which had a closing price of $2.70 per share on the closing date of the acquisition. The Geronimo Note was subsequently converted into Series A Preferred Stock on June 30, 2012. The March 2012 Properties were purchased pursuant to the terms of a Purchase and Sale Agreement dated as of February 24, 2012, by and among the Company, XOG and Geronimo. The effective date of this purchase was December 1, 2011. The operating results from these March 2012 Properties have been included in the Company’s operations from their acquisition on March 5, 2012.

Minimal purchase price was allocated to wellbores acquired. The Company allocated virtually all value to acreage for further development, despite the fact that some acquired properties were producing from legacy development.

Pro Forma Operating Results

The following table reflects the unaudited pro forma results of operations as though the acquisition of the March 2012 Properties had occurred on January 1, 2011. The pro forma amounts are not necessarily indicative of the results that may be reported in the future:

	Year Ended December 31,
	2011			2012
Revenues	$	12,231,322		$	20,848,336

Net loss (1)	$	(14,930,950	)	$	(94,507,269	)

Loss per share basic and diluted	$	(0.37	)	$	(1.99	)

Shares used in computing income (loss) per share:

Basic and diluted (2)		40,413,541			47,475,754

(1) Includes pro forma interest expense of $2,137,646.

(2) Includes pro forma shares of 5,000,000 issued for the transaction.

The amount of revenues and revenues in excess of direct operating expenses included in our consolidated statements of operations and attributable to the March 2012 Properties is shown in the table that follows. Direct operating expenses include lease operating expenses and production and other taxes.

	Year Ended December 31, 2012
Revenues	$	3,322,637

Excess revenues over direct operating expenses	$	196,728

F-35

Note M. Dispositions and Discontinued Operations

In connection with the Second Amendment as described in Note E, Long Term Debt, ASEN 2 and Antler Bar entered into an Asset Purchase Agreement dated September 11, 2012. Pursuant to the Asset Purchase Agreement, ASEN 2 sold its interests in approximately 1,200 leasehold acres of the Auld Shipman project in La Salle and Frio counties, Texas (the “Auld Shipman Property”) to Antler Bar in exchange for the forgiveness of the Transferred Indebtedness and for the assumption by Antler Bar of all liabilities related to the Auld Shipman Property. The transactions under the Second Amendment and Asset Purchase Agreement closed on September 13, 2012. The loss primarily consists of the net reduction of oil and natural gas lease properties by $31,185,684 which was offset by the assumption of liabilities by Antler Bar in the amount of $5,982,772 and the reduction in debt of $2,750,000.

Under the purchase and sale agreement, U.S. Energy acquired working interests in 23 drilling units for $2.5 million with an estimated 307,000 BOE in proved reserves. As of September 21, 2012, there were 27 gross producing wells in the acreage. Of these wells, 25 were producing from the Bakken formation and 2 were producing from the Three Forks formation. All acreage was held by production at the time of sale and produced approximately 47 barrels of oil equivalent per day as of the effective date of the sale.

On November 16, 2012, the Company entered into a purchase and sale agreement with Texian Oil - I, LP, a Texas limited partnership (“Texian”) pursuant to which Nevada ASEC sold certain leasehold properties and related interests in approximately 503 net acres located in Gaines, Glasscock, Andrews, Crane, Yoakum and Scurry Counties, Texas, Lea County, New Mexico and Grady County, Oklahoma in exchange for the delivery by Texian to the Company of $5.3 million in cash. The transaction closed on November 21, 2012, with an effective date of October 1, 2012.

The following table represents the components of the Company’s discontinued operations relating to the Auld Shipman Property and Texian sale described above:

	Year Ended December 31,
	2012		2011
Operating Revenues
Oil	$	3,797,549	$	2,275,243
Natural Gas		385,372		334,166
	$	4,182,921	$	2,609,409

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	Year Ended December 31,
	2012			2011
Operating Expenses
Oil and natural gas production costs	$	1,235,109		$	458,109
General and administrative		-			-
Impairment of oil and natural gas properties		-			-
Depreciation, depletion and amortization		1,016,845			505,357
Accretion of discount on asset retirement obligations		-			-
Loss on sale of oil and natural gas leases		19,944,240			-
Provision for income taxes on discontinued operations		-			604,732
	$	22,196,194		$	1,568,198

Gain (loss) from discontinued operations	$	(18,013,273	)	$	1,041,211

Note N. Related Party Transactions

XOG.XOG is currently contracted to operate the existing wells held by the Company in the Permian Basin region. XOG historically performed this service for Geronimo and CLW. XOG, Geronimo, CLW and Randall Capps combine as the largest shareholder in the Company and these entities are considered related parties to the Company. As a result, accounts receivable and accounts payable due from/to XOG are classified as accounts receivable and payables due from/to a related party. For the year ended December 31, 2012, sales through XOG were $13,326,551 and lease operating expenses were $5,664,427. Net cash paid to XOG in 2012 was $26,855,653 of which $21,191,226 was for drilling costs.

Randall Capps has controlling ownership of XOG, Geronimo and CLW, and is a member of the Company’s board of directors. Through his ownership interest in the XOG Group, Mr. Capps is the largest shareholder of our common stock. Mr. Capps is also the father-in-law of Scott Feldhacker, our chief executive officer.

Saber Oil, LLC. Effective February 18, 2013, Saber Oil, LLC purchased the 35,400 shares of Series A Cumulative Convertible Preferred Stock from Geronimo. J. Steven Person and H.H. Wommack, III, each a director of the Company, are principals in Saber Oil, LLC. In connection with the purchase of the Series A preferred stock, each of Randall Capps, Geronimo, XOG and CLW granted an irrevocable proxy to Saber Oil, LLC to vote the shares of common stock of the Company beneficially owned by Mr. Capps and each such entity. The irrevocable proxies granted to Saber Oil, LLC voting rights, in the aggregate, of 55.55% of the Company’s issued and outstanding common stock.

Overriding Royalty and Royalty Interests. In some instances, the XOG Group may hold overriding royalty and royalty interests (“ORRI”) in wells acquired by the Company. All revenues and expenses presented herein are net of any ORRI effects.

F-37

XOG Group Acquisitions.The Company has made significant acquisitions of oil and gas properties and undeveloped leases from the XOG Group as discussed in Note A and Note L.

Note O. Commitments and Contingencies

Employment Agreements.At December 31, 2012, the Company’s cash contractual obligations related to its employment agreements with executive officers for each of the following two years ending December 31 are as follows:

2013	$	612,000
2014		204,000
Total	$	816,000

On April 16, 2013, the Company and Mr. Feldhacker and Mr. Macqueen entered into a Separation Agreement dated as of April 16, 2013, pursuant to which Mr. Feldhacker and Mr. Macqueen will retire two business days following the filing of the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2012 with the Securities and Exchange Commission.

Operating Leases.The Company leases its 4,092 square foot primary office facilities in Scottsdale, Arizona under a non-cancellable operating lease agreement, dated September 30, 2010, for a 66-month term. The lease provides for no lease payments during the first six months and a reduced square footage charge for the first year. The initial rental is $23.00 per square foot, beginning February 1, 2011, and increasing $.50 per square foot annually thereafter. For the years ended December 31, 2011 and 2010, the Company recorded lease expense of $87,594 and $90,214, respectively.

At December 31, 2011, the future minimum lease commitments under the non-cancellable operating leases for each of the following four years ending December 31 are as follows:

2013	$	97,356
2014		99,402
2015		101,448
2016		42,625
Total	$	340,831

Drilling Commitments.At December 31, 2012, the Company had various oil and natural gas wells in multiple stages of drilling and completion of which the balance of the Company’s unpaid approval for expenditures was estimated to be approximately $3,012,575.

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Note P. Warrant valuation adjustment (unaudited)

During the quarter ended December 31, 2012, the Company discovered that the expense on warrant derivatives reported in its quarters ended March 31, June 30, and September 30, 2012 consolidated financial statements was recorded incorrectly. In the first quarter ended March 31, 2012 the Company obtained a valuation for the warrants that had been recorded as a liability. However, it was discovered that the warrant valuation contained a calculation error which understated the value of the warrant used to record the related expense. This error was identified and recorded as an out-of-period adjustment in the quarter ended December 31, 2012. If the correct valuation was recorded in the first quarter of 2012, the expense on warrant valuation would have increased by $1.9 million, resulting in the increase of net loss by $1.9 million and the loss per share would have been increased by $0.5 per share. The Additional paid in capital and accumulated deficit would have been $146,478,612 and $58,217,154, respectively, as of March 31, 2012. There was no effect on operations for the second and third quarters of 2012. The Company plans to restate the first quarter of 2012 with the filing of the first quarter of 2013.

Note Q. Subsequent Events

Equity

Debt

Management

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Supplemental Information on Oil and Gas (Unaudited)

Capitalized Costs

Capitalized costs and accumulated depreciation, depletion and impairment relating to the Company’s oil and natural gas producing activities are summarized below as of the dates indicated:

	Years Ended December 31,
	2012			2011
Oil and natural gas properties
Unproved	$	83,895,328		$	25,212,635
Proved		83,681,256			76,919,789
Total oil and natural gas properties		167,576,584			102,132,424
Less accumulated depreciation, depletion, amortization and impairment		(45,973,085	)		(14,310,006	)
Net oil and natural gas properties capitalized	$	121,603,499		$	87,822,418

Costs Incurred

Costs incurred for oil and natural gas producing activities during the year ended December 31, 2012 and 2011 was as follows:

	Years Ended December 31,
	2012		2011

Property acquisition costs	$	57,507,963	$	19,123,787
Development		42,695,713		43,172,955

Total	$	100,203,676	$	62,296,742

Results of Operations

Results of operations for the Company’s oil and natural gas producing activities are summarized below for the period indicated:

	Years Ended December 31,
	2012			2011
Oil and natural gas revenue	$	19,738,523		$	9,798,365
Less operating expenses:
Oil and natural gas production expenses		(5,114,461	)		(1,837,011	)
Production and ad valorem taxes		(1,780,411	)		(771,967	)
Depreciation, depletion and amortization		(5,919,933	)		(2,807,893	)
Accretion expense		(44,072	)		(20,951	)
Results of operations from oil and gas producing activities	$	6,879,646		$	4,360,543

Reserve Quantity Information

The following information represents estimates of the proved reserves as of December 31, 2012 and 2011. The Company’s proved reserves as of December 31, 2012 and 2011 have been prepared and presented under SEC rules. These rules require SEC reporting companies to prepare their reserves estimates using revised reserve definitions and revised pricing based on a 12-month unweighted average of the first-day-of-the-month pricing.

The following table summarizes the average prices utilized in the reserve estimates for 2012 and 2011 as adjusted for location, grade and quality:

	As of December 31,
	2012		2011

Prices utilized in the reserve estimates:
Texas oil and natural gas properties
Oil per Bbl(a)	$	84.40	$	92.21
Gas per MCF(b)	$	5.28	$	6.06
North Dakota oil and natural gas properties
Oil per Bbl(a)	$	90.95	$	90.25
Gas per MCF(b)	$	4.35	$	7.10

a) The pricing used to estimate our 2012 and 2011 reserves was based on a 12-month unweighted average first-day-of-the-month West Texas Intermediate posted price as adjusted for location, grade and quality.

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b) The pricing used to estimate our 2012 and 2011 reserves was based on a 12-month unweighted average first-day-of-the-month Henry Hub spot price as adjusted for location, grade and quality.

The Company’s proved oil and natural gas reserves are located primarily in the Permian Basin of West Texas and in the Bakken Shale formation located primarily in North Dakota. The estimates of the proved reserves at December 31, 2012 and 2011 are based on reports prepared by an independent petroleum engineer. Proved reserves were estimated in accordance with the guidelines established by the SEC and the FASB.

Results of subsequent drilling, testing and production may cause either upward or downward revision of previous estimates. Further, the volumes considered to be commercially recoverable fluctuate with changes in prices and operating costs. Reserve estimates are inherently imprecise and estimates of new discoveries are more imprecise than those of currently producing oil and natural gas properties. Accordingly, these estimates are expected to change as additional information becomes available in the future.

The following table provides a roll-forward of the total proved reserves for the years ended December 31, 2012 and 2011, as well as disclosures of proved developed and proved undeveloped reserves at December 31, 2012 and 2011. Barrels of oil equivalent (BOE) are determined using a ratio of 6 Mcf of natural gas to 1 Bbl of crude oil.

F-41

				Natural
	Oil			Gas			Total
	(Bbls)			(Mcf)			(Boe)
Total Proved Reserves:
Balance, January 1, 2012		2,174,130			7,505,884			3,425,111
Revisions		(723,111	)		(1,283,692	)		(937,061	)
Discoveries		745,713			552,538			837,803
Purchases of reserves		214,509			262,160			258,202
Sales of mineral interest		(601,354	)		(2,134,101	)		(957,037	)
Production		(213,711	)		(560,947	)		(307,202	)

Balance, December 31, 2012		1,596,176			4,341,842			2,319,816

Proved developed reserves		1,130,625			4,028,905			1,802,109
Proved undeveloped reserves		465,551			312,937			517,707

Total proven reserves		1,596,176			4,341,842			2,319,816

Total Proved Reserves:
Balance, January 1, 2011		2,290,830			14,511,630			4,709,436
Revisions		(1,431,842	)		(8,333,406	)		(2,820,743	)
Discoveries		1,414,818			1,872,750			1,726,943
Purchases of reserves		4,471			2,190			4,836
Production		(104,147	)		(547,280	)		(195,361	)

Balance, December 31, 2011		2,174,130			7,505,884			3,425,111

Proved developed reserves		1,368,461			6,334,000			2,424,128
Proved undeveloped reserves		805,669			1,171,884			1,000,983

Total proven reserves		2,174,130			7,505,884			3,425,111

Standardized Measure of Discounted Future Net Cash Flows - Unaudited

The standardized measure of discounted future net cash flows is computed by applying at December 31, 2012 the 12-month unweighted average of the first-day-of-the-month pricing for oil and natural gas (with consideration of price changes only to the extent provided by contractual arrangements) to the estimated future production of proved oil and natural gas reserves less estimated future expenditures (based on year-end costs) to be incurred in developing and producing the proved reserves, discounted using a rate of 10% per year to reflect the estimated timing of the future cash flows.

Future income taxes are calculated by comparing undiscounted future cash flows to the tax basis of oil and natural gas properties plus available carry forwards and credits and applying the current tax rates to the difference.

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Discounted future cash flow estimates like those shown herein are not intended to represent estimates of the fair value of oil and natural gas properties. Estimates of fair value would also consider probable and possible reserves, anticipated future oil and natural gas prices, interest rates, changes in development and production costs and risks associated with future production. Because of these and other considerations, any estimate of fair value is necessarily subjective and imprecise.

The following table provides the standardized measure of discounted future net cash flows at December 31, 2012 and 2011:

	2012			2011
Future production revenues	$	158,904,681		$	241,879,576
Future costs:
Production		(63,806,038	)		(72,479,264	)
Development		(13,011,520	)		(24,822,048	)
Income taxes		-			(41,401,226	)
10% annual discount factor		(38,590,513	)		(53,375,271	)
Standardized measure of discounted cash flows	$	43,496,610		$	49,801,767

Changes in Standardized Measure of Discounted Future Net Cash Flows - Unaudited

The following table provides a roll forward of the standardized measure of discounted future net cash flows for the years ended December 31, 2012 and 2011:

	2012			2011
Increase (decrease):
Extensions and discoveries	$	13,879,095		$	23,024,041
Net changes in sales prices and production costs		(8,477,047	)		27,230,290
Oil and gas sales, net of production costs		(12,843,651	)		(9,340,687	)
Change in estimated future development costs		(422,675	)		12,786,697
Revision of quantity estimates		(9,006,491	)		(67,025,217	)
Sales of mineral interests		(24,452,170	)		-
Purchases of mineral interests		3,083,987			128,684
Previously estimated development costs incurred in the current period		3,677,216			2,832,253
Changes in income taxes		22,614,049			(904,315	)
Accretion of discount		6,978,542			10,272,969
Changes in production rates, timing and other		(1,336,012	)		1,118,731
Net (decrease) increase		(6,305,157	)		123,446
Standardized measure of discounted future cash flows:
Beginning of year	$	49,801,767		$	49,678,321
End of year	$	43,496,610		$	49,801,767

F-43

Positive
Negative
Uncertain
Constraining
Legalese
Litigous
Readability	H.S. sophomore Avg

American Standard Energy (ASEN) Inactive 10-K2012 FY Annual report

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