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EX-31.1 - EXHIBIT 31.1 - American Standard Energy Corp.v305529_ex31-1.htm
EX-31.2 - EXHIBIT 31.2 - American Standard Energy Corp.v305529_ex31-2.htm
EX-32.1 - EXHIBIT 32.1 - American Standard Energy Corp.v305529_ex32-1.htm
EX-99.5 - EXHIBIT 99.5 - American Standard Energy Corp.v305529_ex99-5.htm
EX-32.2 - EXHIBIT 32.2 - American Standard Energy Corp.v305529_ex32-2.htm

 

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, 2011

 

Or

 

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

 

For the transition period from                to

 

Commission File Number: 000-54471

 

 

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   o    No   x

 

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act.    Yes   o    No   x

 

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.     Yes   x    No   o

 

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12-months (or for such shorter period that the registrant was required to submit and post such files).  Yes   S    No   o

 

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 filer  o   Accelerated filer                    £
Non-Accelerated filer   o   Smaller reporting company   S

 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act)  Yes   o    No   x

 

 

The number of shares of Common Stock held by non-affiliates as of June 30, 2011 was 17,649,316 shares, all of one class of common stock, $0.001 par value, having an aggregate market value of approximately $142,076,992 based upon the closing price of registrant’s common stock on such date of $8.05 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

 

As of March 16, 2012, there were 45,297,456 shares of common stock, $0.001 par value, outstanding.

 

DOCUMENTS INCORPORATED BY REFERENCE

None.

 

 
 

 

TABLE OF CONTENTS

 

PART I      
       
Item 1. Business     4
Item 1A. Risk Factors     10
Item 1B. Unresolved Staff Comments     31
Item 2. Properties     31
Item 3. Legal Proceedings     39
Item 4. Mine Safety Disclosures     39
         
PART II        
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities     40
Item 6. Selected Financial Data     42
Item 7. Management’s Discussion and Analysis of Financial Conditions and Results of Operations     43
Item 7A. Quantitative and Qualitative Disclosures About Market Risk     54
Item 8. Financial Statements and Supplementary Data     55
Item 9 Changes in and Disagreements with Accountants on Accounting and Financial Disclosures     55
Item 9A. Controls and Procedures     55
Item 9B. Other Information     58
         
PART III        
Item 10. Directors, Executive Officers and Corporate Governance     58
Item 11. Executive Compensation     62
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters     71
Item 13. Certain Relationships and Related Transactions, and Director Independence     72
Item 14. Principal Accounting Fees and Services     74
         
PART IV        
Item 15. Exhibits, Financial Statement Schedules     75
         
Signatures       78

 

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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.”  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 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 document are based on 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.

 

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PART I

 

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, 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 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 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 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 gas bearing shale formations.

 

As of December 31, 2011, we held working interests in approximately 40,100 net acres in the Permian Basin, Bakken, and Eagle Ford regions. After closing a significant acquisition, as of March 15, 2012, we held working interests in approximately 112,400 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.  

 

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., and 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.

 

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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 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 72,300 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 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.

 

Randall Capps is the sole owner of XOG and Geronimo and the majority owner of CLW.  As of December 31, 2011, he was the beneficial owner of approximately 49% of our common stock. 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.

 

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 and Eagle Bine 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.

 

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As of December 31, 2011, we held working interests in approximately 40,100 net acres in the Permian Basin, Bakken and Eagle Ford 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 in the section “Oil and Gas Properties Wells, Operation and Acreage” beginning on page 38 herein. As of March 15, 2012 we held working interests in approximately 112,400 net acres in the Permian Basin, Bakken and Eagle Ford, the Niobrara, the Eagle Bine regions 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 also bearing any related exploration, development, and operating costs. As of March 15, 2012:

 

·Permian Basin. We have leased a portfolio of both producing and undeveloped properties in the Permian Basin of West Texas, consisting of approximately 29,000 net acres, one of which includes 221 gross (178.2 net) producing wells as well as approximately 10,200 undeveloped acres on with leases expiring in 1-4 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.  Mr. Capps is the largest beneficial holder of our common stock through his direct and indirect ownership of our common stock.

 

 

 
· Bakken Shale.  We hold primarily minority working interests in the Bakken Shale covering approximately 42,200 net acres located in nine counties in North Dakota. We have participated in 140 gross (2.1 net) wells in the Williston Basin, prospecting either the Bakken Shale or Three Forks Shale formations through March 15, 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.

  

  ·

Eagle Ford Shale.  We currently hold both majority working interests and minority working interests in the Eagle Ford Shale formation covering approximately 7,400 net acres and 28 gross (7.1 net) wells. Of the total wells in the Eagle Ford, we hold working interests in 1,200 net acres in a project where we have participated in 23 gross (2.3 net) wells in La Salle and Frio counties on a non-operated basis. These wells were drilled by Cheyenne Petroleum, referred to herein as Cheyenne, a privately-held operator based in Oklahoma City, OK. This acreage is subject to an area of mutual interest agreement, referred to herein as the AMI, between Cheyenne and several minority working interest partners, including our company. Cheyenne has informed us that it intends to have an aggregate of 35 wells in operation by the end of 2012, including the 23 wells that are currently in some stage of drilling, completion or production as of March 15, 2012, to hold all of the acreage in the AMI by production. Cheyenne installed high-pressure gas takeaway facilities and sour gas treatment facilities in the area subject to the AMI in late 2011 and early 2012. This enabled Cheyenne to resume production of the wells temporarily shut in during 2011 to enable production beginning in early 2012.

 

We also currently hold majority working interests in a combined 6,200 net acres located in Wilson, Gonzales and Maverick counties within the Eagle Ford. This acreage is partially developed, with 5 gross (4.25 net) producing wells. We will continue to participate in an evaluation of the most efficient manner to develop these assets for future potential oil and gas production.

 

·Niobrara.  We currently hold majority working interests in approximately 25,700 net acres located in the Niobrara Shale in Nebraska and Wyoming. All of this acreage is undeveloped and unproven as of March 15, 2012. We do not currently anticipate the near-term development of this acreage. There are three 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.

 

·Eagle Bine. We currently hold majority working interests in approximately 3,000 net acres located in the Eagle Bine are in Anderson County, Texas. All of this acreage is undeveloped and unproven as of March 15, 2012. We do not currently anticipate the near-term development of this acreage. We hold three years remaining on the lease, with an option to extend the lease for one additional year. 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.

 

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·Additional Acreage: We also hold additional acreage in Oklahoma, Arkansas, and on the Gulf Coast of Texas with a total of approximately 5,000 net acres. The acreage includes 16 gross (2.9 net) gas wells in Arkansas, 1 gross (.06 net) producing well in Oklahoma and 28 gross (26.1 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 expect 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 three 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. We are actively contracting for third party completion services on wells drilled in 2011 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 2012.  

 

In the Bakken and Eagle Ford, we expect to continue to participate in third party drilling activities on a non-operated basis. In the Eagle Ford, we primarily participate in a drilling program with Cheyenne , which had defined a 20 net well program through the end of 2012 to hold all of the acreage under an AMI by production. This program has been largely detailed on a predetermined drilling and completion schedule which provides us with a satisfactory forecast of costs and other demands associated with anticipated drilling, production, and other activities. In the Bakken, we have over 1,000 leases, 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.

 

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 and Montana require permits for drilling operations, drilling bonds and reports concerning operations and impose other requirements relating to the exploration and production of crude oil and natural gas. Such states may also have statutes or regulations addressing 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.

 

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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 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 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 all 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 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 its 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 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, referred to hereafter as CERCLA and comparable state statutes impose strict, joint and several liability on owners and operators of sites and on persons who disposed of or arranged for the disposal of “hazardous substances” found at such sites. It is not uncommon for the neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. The Federal Resource Conservation and Recovery Act , referred to hereafter as RCRA and comparable state statutes govern the disposal of “solid waste” and “hazardous waste” and authorize the imposition of substantial fines and penalties for noncompliance. Although CERCLA currently excludes petroleum from its definition of “hazardous substance,” 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, 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. The OPA establishes a liability limit for onshore facilities of $350.0 million, while the liability limit for offshore facilities is the payment of all removal costs plus up to $75.0 million in other damages, but these limits 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, 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 the species or its habitat. ESA provides for criminal penalties for willful violations of ESA. 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 will be in substantial compliance with such statutes, any change in these statutes or any reclassification of a species as endangered 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.

 

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The Clean Air Act, as amended, 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 addressing other air emission-related issues, we do not believe that such requirements will have a material adverse effect on our operations.

 

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” and including carbon dioxide and methane, may be contributing to warming of the Earth’s atmosphere. See “Climate Change” below.

 

The Federal Water Pollution Control Act of 1972, or the Clean Water Act , referred to hereafter as the CWA, imposes restrictions and controls on the discharge of produced waters and other pollutants into navigable waters. Permits must be obtained to discharge pollutants into state and federal waters and to conduct construction activities in waters and wetlands. The 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 coastal and offshore waters without an individual or general National Pollutant Discharge Elimination System discharge permit.

 

The EPA had regulations under the authority of the CWA that required certain oil and gas exploration and production projects to obtain permits for construction projects with storm water discharges. However, the Energy Policy Act of 2005 nullified most of the EPA regulations that required storm water permitting of oil and gas construction projects. There are still some state and federal rules that regulate the discharge of storm water from some oil and gas construction projects. Costs may be associated with the treatment of wastewater and/or developing and implementing storm water pollution prevention plans. The 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 any environmental damage caused by the release and for natural resource damages resulting from the release.

 

Climate Change

 

Significant studies and research 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 has 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 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 and favor use of alternative energy sources, which could negatively impact operating costs and demand for crude oil products. As such, our business could be materially adversely affected by domestic and international legislation targeted at controlling climate change.

 

Competition

 

The oil and 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.

 

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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 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 gas operators in three large oil and 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 report 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.

 

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 wholly-owned subsidiaries, Nevada ASEC and ASEN 2, were incorporated on April 2, 2010 and January 25, 2012. 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.

 

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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.

 

THE POSSIBILITY OF A GLOBAL FINANCIAL CRISIS MAY SIGNIFICANTLY IMPACT THE COMPANY’S BUSINESS AND FINANCIAL CONDITION FOR THE FORESEEABLE FUTURE.

 

The credit crisis and related turmoil in the global financial system may adversely impact our business and financial condition, and we may face challenges if conditions in the financial markets remain challenging. Our ability to access the capital markets may be restricted at a time when we would prefer or be required to raise financing. Such constraints could have a material negative impact on our flexibility to react to changing economic and business conditions. The economic situation could also have a material negative impact on the operators upon whom we are dependent on for drilling our wells, and our lenders, causing us to fail to meet our obligations to them or for them to fail to meet their obligations to the Company. Additionally, market conditions could have a material negative impact on any crude oil hedging arrangements we may employ in the future if our counterparties are unable to perform their obligations or seek bankruptcy protection.

 

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.

 

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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 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 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 gas industry or the oil and gas production in the geographic areas in which we operate.

 

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

 

We expect to be able to fund our 2012 capital budget partially with operating cash flows, in conjunction with our credit facility entered into on September 21, 2011 and other financings. We will require additional capital 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 2012 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.

 

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.

 

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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.

 

WE ARE DEPENDENT ON CERTAIN KEY PERSONNEL.  THE LOSS OF SUCH PERSONNEL COULD IMPAIR OUR ABILITY TO FULFILL OUR BUSINESS PLAN.

  

We are dependent on the services of Scott Feldhacker, our Chief Executive Officer, Richard MacQueen, our President and Scott Mahoney, our Chief Financial Officer. The loss of services of any of these individuals could impair our ability to complete acquisitions of producing assets and leaseholds, perform relevant managerial and legal services and maintain key relationships with XOG and other market participants which could have a material adverse effect on our business, financial condition and results of operations.

 

RANDALL CAPPS, THE FATHER-IN-LAW OF OUR CHIEF EXECUTIVE OFFICER, IS THE HOLDER OF A MAJORITY OF OUR COMMON STOCK AND IS A DIRECTOR OF THE COMPANY.  THE INTERESTS OF MR. CAPPS MAY NOT BE ALIGNED WITH OUR INTERESTS OR THE INTERESTS OF OUR OTHER STOCKHOLDERS.  ACCORDINGLY, ANY LOSS OF OUR RELATIONSHIP WITH MR. CAPPS, OR A DISAGREEMENT WITH MR. CAPPS COULD HAVE A MATERIAL ADVERSE EFFECT ON OUR OPERATIONS, PROSPECTS, REVENUES AND RESULTS OF OPERATIONS.

 

Randall Capps is a member of our board of directors and, as of March 15, 2012, beneficially owns 24,493,077 shares of common stock or approximately 54% of the Company’s outstanding common stock. Mr. Capps is the sole owner of XOG and Geronimo and is the majority owner of CLW. This significant ownership allows Mr. Capps 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 one of our directors, Mr. Capps is 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. Capps and his affiliates, including XOG, Geronimo and CLW, on the one hand, and the Company and our other stockholders, on the other hand. As a result of these conflicts, Mr. Capps and his affiliates 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.

 

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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.

 

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.

 

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 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;

 

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  · 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 63.5% of our estimated proved reserves as of December 31, 2011 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 $45 per Bbl in February 2009 before rebounding to over $105 per Bbl in March 2012. Natural gas prices declined from over $13 per MMBtu (million British thermal units) in mid-2008 to approximately $2.5 per MMBtu in March 2012. 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;

 

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  ·

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 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, 2011 and 2010, 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.

 

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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.

 

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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 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 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.

 

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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.

 

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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 29.2% of our total proved reserves were classified as proved undeveloped as of December 31, 2011. 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.

  

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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, 2011, we had leases representing approximately 3,000 net acres expiring in 2012, and 5,000 net acres expiring in 2013. 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, 2011 and 2010, we recorded non-cash impairment charges of $1,027,552 and $ 46,553, 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.

 

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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 recently 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 new legislation was signed into law by the President on July 21, 2010 and requires the Commodities Futures Trading Commission (the “CFTC”) and the SEC to promulgate rules and regulations implementing the new legislation within 360 days from the date of enactment. The CFTC has also proposed regulations to set position limits for certain futures and option contracts in the major energy markets, although it is not possible at this time to predict whether or when the CFTC will adopt those rules or include comparable provisions in its rulemaking under the new legislation. The financial reform legislation may also require us to comply with margin requirements and with certain clearing and trade-execution requirements in connection with its derivative activities, although the application of those provisions to us is uncertain at this time. The financial reform legislation may also require the counterparties to our derivative instruments to spin off some of their derivative activities to a separate entity, which may not be as creditworthy as the current counterparty. The new legislation and any new regulations could significantly increase the cost of derivative contracts (including 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 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. 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 commodity prices decline as a consequence of the legislation and regulations. 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.

 

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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 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 discharge 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 stricter 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.

 

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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 and municipal laws and regulations. Environmental legislation provides for, among other things, restrictions and prohibitions on spills, releases or emissions of various substances produced in association with oil and gas operations. The legislation also requires 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 is evolving in a manner 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 discharge. 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, 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 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 recent trend in environmental legislation and regulation generally is toward stricter standards. These laws and regulations including the Comprehensive Environmental, Response, Compensation, and Liability Act (“CERCLA”), the Federal Resource Conservation and Recovery Act (“RCRA”) and the Endangered Species Act (“ESA”) 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 its 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 the applicable penalty 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.

 

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Additionally, hydraulic fracturing, the process of creating or expanding cracks, or fractures, in formations underground where water, sand and other additives are pumped under high pressure into the formation, 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 oil and gas commissions, the EPA recently asserted federal regulatory authority over hydraulic fracturing involving diesel fuels under the Safe Drinking Water Act’s Underground Injection Control Program and has begun the process of drafting guidance documents for permitting authorities and the industry on the process for obtaining a permit for hydraulic fracturing involving diesel fuel. At the same time, the EPA has commenced a study of the potential environmental impacts of hydraulic fracturing activities, with results of the study anticipated to be available by late 2012. Also, for the second consecutive session, 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. We cannot predict whether 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. If additional levels of regulation or permitting requirements were 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, New York and Pennsylvania), have considered, or are considering, legislation or regulations similar to the federal legislation described above. Recently, for example, the Wyoming Oil and Gas Conservation Commission passed a rule requiring disclosure of hydraulic fracturing fluid content. At this time, it is not possible to estimate the potential impact on our business of additional federal or state regulatory actions affecting hydraulic fracturing. 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. 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. In some cases, federal agencies have cancelled oil and natural gas leases 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. Interim results of the study are expected in 2012, with final results expected in 2014. The agency also announced that one of its enforcement initiatives for 2011 to 2013 would be to focus on environmental compliance by the energy extraction sector. This 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.

 

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CERTAIN UNITED STATES FEDERAL INCOME TAX DEDUCTIONS CURRENTLY AVAILABLE WITH RESPECT TO OIL AND 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.

 

President Obama’s Proposed Fiscal Year 2012 Budget includes proposals that would, if enacted into law, 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, (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 the Company. Any such changes could have an adverse effect on our financial position, results of operations and cash flows.

 

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, directly or indirectly, be 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 requires 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 emissions, and several counties 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.

 

The EPA has issued greenhouse gas monitoring and reporting regulations that went into effect January 1, 2010, and require reporting by regulated facilities by March 2011 and annually thereafter. In November 2010, the EPA issued a final rule 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 when due in 2012. 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 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, the EPA issued an “Endangerment Finding” under section 202(a) of the Clean Air Act, concluding greenhouse gas pollution threatens the public health and welfare of current and future generations. The finding serves as a first step to issuing regulations that would require permits for and reductions in greenhouse gas emissions for certain facilities. EPA has proposed such greenhouse gas regulations and may issue final rules this year.

 

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 to restrict or reduce emissions of greenhouse gases could require us to incur increased operating and compliance costs, and could have an adverse effect on demand for the oil and natural gas that we produce.

 

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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 will be 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.

 

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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.

 

If an event of default under our revolving credit facility occurs and remains uncured, the lenders thereunder:

 

    would not be required to lend any additional amounts to us; and

 

    could elect to declare all borrowings outstanding, together with accrued and unpaid interest and fees, to be due and payable.

 

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

 

As of December 31, 2011, we had $12,000,000 outstanding under our revolving credit facility, $5,169,889 outstanding under our term loan facility and $0 available for future secured borrowings under our revolving credit facility. 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. 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. 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.

 

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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 $6,896,945 million for 2010 to $12,407,774 million for 2011. Our growth has largely resulted from our acquisition of new leasehold interests. Since October 2010, we have acquired leasehold interests in approximately 101,000 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 the Company anticipates to develop may be 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.

 

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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 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.

 

Rule 3a51-1 of the Securities Exchange Act of 1934, as amended, establishes the definition of a “penny stock,” for purposes relevant to us, as any equity security that has a minimum bid price of less than $5.00 per share or with an exercise price of less than $5.00 per share, subject to a limited number of exceptions which are not available to us. This classification would severely and adversely affect any market liquidity for our common stock.

 

For any transaction involving a penny stock, unless exempt, the penny stock rules require that a broker or dealer approve a person’s account for transactions in penny stocks and the broker or dealer receive from the investor a written agreement to the transaction setting forth the identity and quantity of the penny stock to be purchased.  In order to approve a person’s account for transactions in penny stocks, the broker or dealer must obtain financial information and investment experience and objectives of the person and make a reasonable determination that the transactions in penny stocks are suitable for that person and that that person has sufficient knowledge and experience in financial matters to be capable of evaluating the risks of transactions in penny stocks.

 

The broker or dealer must also deliver, prior to any transaction in a penny stock, a disclosure schedule required by the SEC relating to the penny stock market, which, in highlight form, sets forth:

 

  · The basis on which the broker or dealer made the suitability determination; and

 

  · That the broker or dealer received a signed, written agreement from the investor prior to the transaction.

 

Disclosure also has to be made about the risks of investing in penny stocks in both public offerings and in secondary trading and commission payable to both the broker-dealer and the registered representative, current quotations for the securities and the rights and remedies available to an investor in cases of fraud in penny stock transactions. Finally, monthly statements have to be sent disclosing recent price information for the penny stock held in the account and information on the limited market in penny stocks.

  

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Because of these regulations, broker-dealers may not wish to engage in the above-referenced necessary paperwork and disclosures and/or may encounter difficulties in their attempt to sell shares of our common stock, which may affect the ability of selling stockholders or other holders to sell their shares in any secondary market and have the effect of reducing the level of trading activity in any secondary market. These additional sales practice and disclosure requirements could impede the sale of our common stock, if and when our common stock becomes publicly traded. In addition, the liquidity for our common stock may decrease, with a corresponding decrease in the price of our common stock. Our common stock, in all probability, will be subject to such penny stock rules for the foreseeable future and our stockholders will, in all likelihood, find it difficult to sell their common stock.

 

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, 2011, we had warrants to purchase 10,179,889 shares of our common stock and options to purchase 10,745,000 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 March 15, 2012 we held working interests in approximately 112,400 net acres in the Permian Basin, Bakken and Eagle Ford, the Niobrara, the Eagle Bine regions 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 also bearing any related exploration, development, and operating costs. As of March 15, 2012:

 

·Permian Basin. We have leased a portfolio of both producing and undeveloped properties in the Permian Basin of West Texas, consisting of approximately 29,000 net acres, one of which includes 221 gross (178.2 net) producing wells as well as approximately 10,200 undeveloped acres on with leases expiring in 1-4 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.  Mr. Capps is the largest beneficial holder of our common stock through his direct and indirect ownership of our common stock.

 

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·Bakken Shale.  We hold primarily minority working interests in the Bakken Shale covering approximately 42,200 net acres located in nine counties in North Dakota. We have participated in 140 gross (2.1 net) wells in the Williston Basin, prospecting either the Bakken Shale or Three Forks Shale formations through March 15, 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.

  

·Eagle Ford Shale.  We currently hold both majority working interests and minority working interests in the Eagle Ford Shale formation covering approximately 7,400 net acres and 28 gross (7.1 net) wells. Of the total wells in the Eagle Ford, we hold working interests in 1,200 net acres in a project where we have participated in 23 gross (2.3 net) wells in La Salle and Frio counties on a non-operated basis. These wells were drilled by Cheyenne Petroleum, referred to herein as Cheyenne, a privately-held operator based in Oklahoma City, OK. This acreage is subject to an area of mutual interest agreement, referred to herein as the AMI, between Cheyenne and several minority working interest partners, including our company. Cheyenne has informed us that it intends to have an aggregate of 35 wells in operation by the end of 2012, including the 23 wells that are currently in some stage of drilling, completion or production as of March 15, 2012, to hold all of the acreage in the AMI by production. Cheyenne installed high-pressure gas takeaway facilities and sour gas treatment facilities in the area subject to the AMI in late 2011 and early 2012. This enabled Cheyenne to resume production of the wells temporarily shut in during 2011 to enable production beginning in early 2012.

 

We also currently hold majority working interests in a combined 6,200 net acres located in Wilson, Gonzales and Maverick counties within the Eagle Ford. This acreage is partially developed, with 5 gross (4.25 net) producing wells. We will continue to participate in an evaluation of the most efficient manner to develop these assets for future potential oil and gas production.

 

·Niobrara.  We currently hold majority working interests in approximately 25,700 net acres located in the Niobrara Shale in Nebraska and Wyoming. All of this acreage is undeveloped and unproven as of March 15, 2012. We do not currently anticipate the near-term development of this acreage. There are three 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.

 

·Eagle Bine. We currently hold majority working interests in approximately 3,000 net acres located in the Eagle Bine are in Anderson County, Texas. All of this acreage is undeveloped and unproven as of March 15, 2012. We do not currently anticipate the near-term development of this acreage. We hold three years remaining on the lease, with an option to extend the lease for one additional year. 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 Oklahoma, Arkansas, and on the Gulf Coast of Texas with a total of approximately 5,000 net acres. The acreage includes 16 gross (2.9 net) gas wells in Arkansas, 1 gross (.06 net) producing well in Oklahoma and 28 gross (26.1 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.

 

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Reserves

 

Below is a summary of oil and gas reserves as of the fiscal-year ended December 31, 2011 based on average fiscal-year prices.

 

   Reserves 
Reserves category  Oil
(mbbls)
   Natural gas
(mmcf)
   Synthetic oil
(mbbls)
   Synthetic gas (mmcf) 
PROVED                    
Developed:                    
North America   1,368.5    6,334.0    0    0 
U.S.A   1,368.5    6,334.0    0    0 
                     
Undeveloped:                    
North America   805.6    1,171.9    0    0 
U.S.A   805.6    1,171.9    0    0 
                     
TOTAL PROVED   2,174.1    7,505.9    0    0 

 

As of December 31, 2011, 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, 2011. The estimates of proved reserves at December 31, 2011 are based on reports prepared by DeGolyer and MacNaughton, (the “D&M Engineering Report”) and an additional report for our Eagle Ford assets operated by Cheyenne Petroleum prepared by Cawley Gillespie & Associates (the “CG&A Engineering Report”) which are included herein as Exhibit 99.5.

  

Proved reserves and future net revenue to the evaluated interests were based on economic parameters and operating conditions considered applicable as of December 31, 2011 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.

 

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The following table provides a roll-forward of the total proved reserves for the years ended December 31, 2011 and 2010, as well as disclosures of proved developed and proved undeveloped reserves at December 31, 2011 and 2010. 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, 2011   2,290,830    14,511,630    4,709,436 
Revisions   (1,431,844)   (8,333,408)   (2,820,745)
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   2,174,128    7,505,882    3,425,109 
                
Proved developed reserves   1,368,461    6,334,000    2,424,128 
Proved undeveloped reserves   805,669    1,171,884    1,000,983 
                
Total proved reserves   2,174,130    7,505,884    3,425,111 
                
Total Proved Reserves:               
Balance, January 1, 2010   2,047,616    13,508,944    4,299,107 
Revisions   173,505    1,527,388    428,070 
Discoveries   126,366    15,370    128,928 
Production   (56,657)   (540,072)   (146,669)
                
Balance, December 31, 2010   2,290,830    14,511,630    4,709,436 
                
Proved developed reserves   759,642    9,370,893    2,321,457 
Proved undeveloped reserves   1,531,188    5,140,737    2,387,979 
                
Total proved reserves   2,290,830    14,511,630    4,709,436 

 

Total proved reserves as of December 31, 2010 were 4,709,436 BOE including 2,387,979 BOE in proved undeveloped reserves. Our 2010 reserves include reserves acquired in the Group 1&2 acquisition in February 2011.  This transaction was between our Company and XOG Group while we were under common control.  As a result, our proved reserves were recast to include the reserves acquired as if our Company has owned those reserves at December 31, 2010.  Subsequently, we evaluated our proved undeveloped reserves and determined that 1,868,367 BOE in undeveloped reserves were unlikely to be developed in the next three years by the operators of record on which these reserves were located.  As a result, the Company has excluded these locations and the associated reserves from proved reserves as of December 31, 2011.  If these reserves were excluded from all periods presented, total proved reserves as of December 31, 2011 and 2010 would be 3,425,111 BOE and 2,841,069 BOE, respectively.  

 

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.

 

Bryant M. Mook, B.Sc. M.Eng., Petroleum Engineer and Geological Advisor, was our third party reserve engineer for the preparation of our reserve report, effective December 31, 2010.  Mr. Mook has been a petroleum engineering and geological advisor for more than 35 years with multi-disciplinary experience in the oil and gas industry.  He 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.

 

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Our Chief Financial Officer, Scott Mahoney, was responsible for overseeing the preparation of the reserve estimates. Mr. Mahoney has significant accounting and financial experience, although not specific to the oil and gas industry.  Accordingly, in July 2011, we hired DeGolyer and MacNaughton of Houston, Texas as our new third-party engineering firm to prepare our reserve estimates going forward. Cawley, Gillespie and Associates of Houston, Texas was also retained on a specific project to provide third-party engineering for our Eagle Ford assets being developed with Cheyenne Petroleum in La Salle and Frio Counties, Texas.

 

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, 2011.  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 the Auld Shipman project in the Eagle Ford within our reserve report, effective December 31, 2011.  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, 2011, there were 805,669 barrels of oil and 1,171,884 mcf of natural gas in our proved undeveloped reserves.  In 2011, the Company evaluated the probability that the operators would drill the undeveloped acreage included in our December 31, 2010 year end reserve reports. The Company found that the operators of this acreage had not committed to drilling the drillable locations within five years, and therefore we excluded these reserves from our December 31, 2011 reserve report. This resulted in proved undeveloped reserves as of December 31, 2010 in the amount of 1.25 million barrels of oil and 3,710.2 mcf of natural gas to be excluded from proved reserves as of December 31, 2011.

 

During 2011, 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, 2011, much of our drilling investments in the Bakken, Eagle Ford and Permian Basin remained unproved. Furthermore, as much of our drilling in 2011 was exploratory, we were not able to provide sufficient production data at year end to generate significant proven undeveloped reserves in the areas where we drilled or participated in exploratory wells. We believe these exploratory drilling activities may yield additional proven reserves in 2012.  In addition, in 2011 we evaluated many of our non-operated proven undeveloped reserves and eliminated them from our reserve reporting due solely to the fact that the operators of this non-operated acreage did not have a clear timetable to drill the undeveloped locations. As a result, we removed these proven undeveloped reserves from our 2011 year-end reserve reports.

 

Oil and Gas Production, Production Prices and Production Costs

 

Oil and Gas Production

 

The following table summarizes the production of oil and natural gas by geographical area for the fiscal year ended December 31, 2011:

 

Product  Permian Basin   Eagle Ford   Williston Basin   Total 
Oil (Bbls)   61,928    2,083    36,944    100,955 
Gas (Mcf)   538,646    8,842    10,400    557,888 
Product (Mcf)   4,708    1,775    15,864    22,347 
BOE   151,814    3,599    39,055    194,468 

 

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The following table summarizes gross and net productive oil wells by state as of December 31, 2011.  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, 2011 
   Gross   Net 
Permian Basin (Texas and New Mexico)   47    33.9 
Bakken (North Dakota)   121    2.1 
Eagle Ford (Texas)   23    2.3 
Other (Texas, Oklahoma, Arkansas)   18    4.1 
Total   209    42.4 

 

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, 2011:

 

Product  Permian Basin   Eagle Ford   Williston Basin   Total 
Oil (Bbls)  $91.22   $87.17   $89.37   $89.25 
Gas (Mcf)   6.44    4.02    6.42    5.63 
Product (Mcf)   1.54    20.33    3.17    8.35 
BOE  $58.04   $68.27   $85.79   $63.80 

 

  

  (a) 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 2011 and 2010 as adjusted for location, grade and quality:

 

   As of December 31, 
   2011   2010 
         
Prices utilized in the reserve estimates:          
Texas oil and natural gas properties          
Oil per Bbl(a)  $92.21   $75.43 
Gas per MCF(a)  $6.06   $6.38 
North Dakota oil and natural gas properties          
Oil per Bbl(a)  $90.25   $70.82 
Gas per MCF(a)  $7.10   $4.39 

 

  (a) The pricing used to estimate our 2011 and 2010 reserves was based on a 12-month unweighted average realized 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, 
   2011   2010 
         
Unproved property acquisition costs  $15,258,281   $7,729,953 
Exploration   46,958,052    5,787,926 
Development   80,409    4,308,484 
           
Total  $62,296,742   $17,826,363 

 

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Average production costs per BOE including ad valorem and severance taxes were $15.77 in 2011.  Excluding severance taxes, production costs per BOE were $11.08. Average production costs per BOE including ad valorem and severance taxes were $14.75 in 2010.  Excluding severance taxes, production costs per BOE were $12.26.

 

Dry Holes

 

Through March 15, 2012, 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, 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.

 

In the fiscal year ended December 31, 2010, operators drilled and completed 0 gross (0.0 net) exploratory wells on our leaseholds located in the Permian Basin.  We participated in 2 gross (0.2 net) exploratory wells in the Eagle Ford shale formation in La Salle County, Texas.  Lastly, we participated in 23 gross (0.27 net) exploratory wells in the Bakken in Mountrail, McKenzie, Williams and Dunn Counties in North Dakota.

 

Productive and Dry Development Wells Drilled

 

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.

 

In the fiscal year ended December 31, 2010, operators drilled and completed 2 gross (2.0 net) development wells on our leaseholds located in in the Permian Basin. We contracted with XOG to oversee the drilling, completion and initial production for these wells drilled in Upton County, Texas.  We participated in no development wells in either the Eagle Ford or Bakken in 2010.

 

Present Activities

 

As of March 15, 2012, our third party operators are in the process of completing 8 gross (8.0 net) exploratory wells on our majority working interest acreage in Andrews, Reagan, Crockett and Schleicher Counties in the Permian Basin.  We also participated in the drilling and completing of 2 gross (0.2 net) exploratory wells in La Salle Counties in the Eagle Ford. Lastly, we participated in 6 gross (0.1 net) exploratory wells and 6 gross (0.1 net) development wells in the Bakken.

 

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Oil and Gas Properties, Wells, Operations and Acreage

 

The following table summarizes as of December 31, 2011, 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   45    33.8    21.2    14.6    66.2    48.4 
Eagle Ford   15    1.5    -    -    15.0    1.5 
Bakken   79    1.3    -    -    121.0    2.0 
Total   139    36.6    21.2    14.6    202.2    51.9 

 

   HBP Acreage   Total Acreage 
   Gross   Net   Gross   Net 
Permian   7,537    6,100    8,737    6,500 
Eagle Ford   6,857    686    12,000    1,200 
Bakken   134,700    3,830    358,810    32,400 
Total   149,094    10,616    379,547    40,100 

 

 

 

The following table summarizes as of March 15, 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   172    138.7    49    39.1    221.0    177.8 
Eagle Ford   22    3.8    6    3.3    28.0    7.1 
Bakken   140    2.1    -    -    140.0    2.1 
Niobrara   -    -    -    -    -    - 
Eagle Bine   -    -    -    -    -    - 
Other   16    12.6    32    17.2    48.0    29.8 
Total   350    157.2    87    59.6    437.0    216.8 

 

   HBP Acreage   Total Acreage 
   Gross   Net   Gross   Net 
Permian   28,226    19,855    38,752    29,019 
Eagle Ford   10,100    3,311    19,858    7,427 
Bakken   134,700    3,830    456,110    42,201 
Niobrara   0    0    51,498    25,749 
Eagle Bine   0    0    3,052    3,052 
Other   5,632    4,949    5,310    4,950 
Total   178,658    31,945    574,580    112,398 

  

The following table summarizes as of December 31, 2011, 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   7,537    6,100    8,737    6,500    1,200    400   Second Quarter 2012
Eagle Ford   6,857    686    12,000    1,200    5,143    514   First Quarter 2012
Bakken   134,700    3,830    358,810    32,400    224,110    28,570   Range from 2012-2016
Total   149,094    10,616    379,547    40,100    230,453    29,484      

 

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In the Permian Basin, we have approximately 1,000 net acres in Crockett and Schleicher County that have lease expiration dates in April 2012.  We are currently evaluating our options to selectively drill some of these leases to hold this acreage by production.

 

In the Eagle Ford, our area of mutual interest (“AMI”) requires 35 gross wells to be producing by the second quarter of 2013. We expect Cheyenne to drill 15 incremental wells in 2012 to hold all of the acreage within the AMI by the end of 2012.

 

In the Bakken, our non-operated minority interest acreage is primarily not held by production today, with 28,570 of our 32,400 acres undeveloped or subject to drilling in progress.  Our acreage exposure is very granular, with over 700 leases with a typical working interest ranging from 1-10%. We hold approximately 1,000 and 3,800 net acres that expire in 2012 and 2013, respectively. The majority of our Bakken acreage has maturity dates in 2012-2014, with the majority of the leases having 1-2 year extension options.   

 

The following table summarizes as of March 15, 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   28,226    19,855    38,752    29,019    10,526    9,164    2012-2016 
Eagle Ford   10,100    3,311    19,858    7,427    9,758    4,116    2013-2017 
Bakken   134,700    3,830    456,110    42,201    321,410    38,371    2012-2017 
Niobrara   0    0    51,498    25,749    51,498    25,749    2020 
Eagle Bine   0    0    3,052    3,052    3,052    3,052    2016 
Other   5,632    4,949    5,632    4,949    0    0    - 
Total   178,658    31,945    574,902    112,397    396,244    80,452    - 

 

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 Eagle Ford, we have acquired approximately 3,620 net acres in Maverick County that were not held by production at March 15, 2012. This leasehold acreage in Maverick has a five year lease maturity. We own the majority working interests in this acreage, 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 three officers and two additional employees who manage all day to day operations of the Company.  

 

Item 3. LEGAL PROCEEDINGS

 

Currently there are no outstanding judgments against the Company or any consent decrees or injunctions to which the Company is subject or by which its assets are bound and there are no claims, proceedings, actions or lawsuits in existence, or to the Company’s knowledge threatened or asserted, against the Company or with respect to any of the assets of the Company that would materially and adversely affect the business, property or financial condition of the Company, including but not limited to environmental actions or claims. However, from time to time, we may become involved in various lawsuits and legal proceedings which arise in the ordinary course of business.  Litigation is subject to inherent uncertainties, and an adverse result in these or other matters may arise from time to time that may harm our business.

 

Item 4. MINE SAFETY DISCLOSURES

 

Not applicable.

 

39
 

 

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.

 

During the two year period ended December 31, 2011, there were no reported trades for the Company’s common stock until October 15, 2010. 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, 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 
           
Fourth Quarter ended December 31, 2010  $3.75   $2.50 

 

Holders

 

As of March 19, 2012, there were approximately 232 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

 

40
 

 

The following is certain information about our equity compensation plans as of December 31, 2011:

 

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   10,745,000   $5.67    11,255,000 

 

 

(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, 2011, 10,745,000 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. No shares have been issued under this plan.

 

41
 

 

Item 6.SELECTED FINANCIAL DATA

 

Results of Operations

 

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

 

   Year Ended December 31, 
   2011   2010   2009 
             
Production volumes:               
Oil (Bbls)   100,955    56,657    56,003 
Natural Gas (Mcf)   561,080    540,072    610,462 
BOE (1)   194,468    146,669    157,747 
BOE per day   533    401.83    432.18 
                
Sales Prices               
Oil (per Bbl)  $89.93   $74.45   $57.58 
Natural Gas (per Mcf)  $5.93   $4.89   $4.00 
BOE Price  $63.80   $47.02   $35.92 
                
Operating Revenues               
Oil  $9,079,267   $4,218,075   $3,224,862 
Natural Gas   3,328,507    2,643,310    2,441,848 
Gain on sale of oil and natural gas leases   -    35,560    - 
   $12,407,774   $6,896,945   $5,666,710 
                
Operating Expenses               
Oil and natural gas production costs  $3,067,087   $2,163,887   $1,786,280 
Exploration expense   -    247,463    240,382 
General and administrative   16,387,633    5,674,985    553,542 
Impairment of oil and natural gas properties   1,027,552    46,553    253,258 
Depreciation, depletion and amortization   3,313,250    1,556,288    1,490,926 
Accretion of discount on asset retirement obligations   20,951    15,607    12,399 
   $23,816,473   $9,704,783   $4,336,787 
                
Income (loss) from operations  $(11,408,699)  $(2,807,838)  $1,329,923 
Loss from continuing operations per share  $(0.32)  $(0.12)   $0.07 

 

 

   As of December 31, 
   2011   2010   2009 
Balance Sheet Information:               
Total assets  $95,894,737   $32,799,480   $14,812,013 
Term loan and revolving credit facility (2)   17,169,889    -    - 
Total liabilities   36,943,879    5,733,293   408,206 
Stockholders’ equity   58,950,858    27,066,187    14,403,807 
                
Statement of Cash Flow Information:               
Net cash provided by operating activities  $4,402,749   $3,739,625   $2,936,683 
Net cash used in investing activities   (58,462,398)   (12,878,375)   (2,393,249)
Net cash provided by (used in) financing activities   54,272,702    9,658,746    (543,434)

 

(1)A BOE means one barrel of oil equivalent using the ratio of 6 Mcf of gas to one barrel of oil
(2)For a detailed description of our long term debt, see Note D on page F-15

 

 

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

 

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

 

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, 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 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 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 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 gas bearing shale formations.

 

As of December 31, 2011, we held working interests in approximately 40,100 net acres in the Permian Basin, Bakken, and Eagle Ford regions. After closing a recent acquisition, as of March 15, 2012, we held working interests in approximately 112,400 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:

 

  · developments generally impacting the Middle East, including Iraq, Iran, Libya and Egypt;

 

  · the extent to which members of the Organization of Petroleum Exporting Countries and other oil exporting nations are able to continue to manage oil supply through export quotas;

 

  · the overall global demand for oil;

 

  · overall North American natural gas supply and demand fundamentals;

 

  · the impact of the decline of the United States economy;

 

  · weather conditions; and

   

  · liquefied natural gas deliveries to the United States.

 

43
 

 

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 December 31, 2011, and through the filing date of this report, the Company has commodity derivative contracts in place through the third quarter of 2014 for a total of approximately 107,340 Bbls of anticipated crude oil production and 655,074 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 substantially higher during the comparable periods of 2011 measured against 2010. The following table sets forth the average NYMEX oil and natural gas prices for the years ended December 31, 2011 and 2010, as well as the high and low NYMEX price for the same periods:

 

   Years Ended December 31, 
   2011   2010 
Average NYMEX prices:          
Oil (Bbl)  $95.03   $79.48 
Natural gas (MMBtu)  $3.99   $4.37 
High / Low NYMEX prices:          
Oil (Bbl):          
High  $113.93   $91.48 
Low  $79.20   $64.78 
Natural gas (MMBtu):          
High  $4.92   $7.51 
Low  $2.84   $3.18 

 

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.

 

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. 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.

 

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. The Company is evaluating the accounting treatment for this transaction.

 

44
 

 

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.

 

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.

 

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.

 

March Asset Acquisition. 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”) 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 prince of $2.70 on the closing date of the acquisition. The March 2012 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 March 2012 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 March 2012 Note matures on March 21, 2016. The Company may prepay the March 2012 Note at any time without penalty.

 

45
 

 

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.

 

Results of Operations

 

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

 

   Year Ended December 31, 
   2011   2010   2009 
             
Production volumes:               
Oil (Bbls)   100,955    56,657    56,003 
Natural Gas (Mcf)   561,080    540,072    610,462 
BOE (1)   194,468    146,669    157,747 
BOE per day   533    401.83    432.18 
                
Sales Prices               
Oil (per Bbl)  $89.93   $74.45   $57.58 
Natural Gas (per Mcf)  $5.93   $4.89   $4.00 
BOE Price  $63.80   $47.02   $35.92 
                
Operating Revenues               
Oil  $9,079,267   $4,218,075   $3,224,862 
Natural Gas   3,328,507    2,643,310    2,441,848 
Gain on sale of oil and natural gas leases   -    35,560    - 
   $12,407,774   $6,896,945   $5,666,710 
                
Operating Expenses               
Oil and natural gas production costs  $3,067,087   $2,163,887   $1,786,280 
Exploration expense   -    247,463    240,382 
General and administrative   16,387,633    5,674,985    553,542 
Impairment of oil and natural gas properties   1,027,552    46,553    253,258 
Depreciation, depletion and amortization   3,313,250    1,556,288    1,490,926 
Accretion of discount on asset retirement obligations   20,951    15,607    12,399 
   $23,816,473   $9,704,783   $4,336,787 
                
Income (loss) from operations  $(11,408,699)  $(2,807,838)  $1,329,923 

 

 

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

 

46
 

 

   Year Ended December 31,   Increase   % Increase 
   2011   2010   (Decrease)   (Decrease) 
                 
Production volumes:                    
Oil (Bbls)   100,955    56,657    44,298    78%
Natural Gas (Mcf)   561,080    540,072    21,008    4%
BOE (1)   194,468    146,669    47,799    33%
BOE per day   533    401.83    130.96    33%
                     
Sales Prices                    
Oil (per Bbl)  $89.93   $74.45   $15.48    21%
Natural Gas (per Mcf)  $5.93   $4.89   $1.04    21%
BOE Price  $63.80   $47.02   $16.78    36%
                     
Operating Revenues                    
Oil  $9,079,267   $4,218,075   $4,861,192    115%
Natural Gas   3,328,507    2,643,310    685,197    26%
Gain on sale of oil and natural gas leases   -    35,560    (35,560)   -100%
   $12,407,774   $6,896,945   $5,510,829    80%
                     
Operating Expenses                    
Oil and natural gas production costs  $3,067,087   $2,163,887   $903,200    42%
Exploration expense   -    247,463    (247,463)   -100%
General and administrative   16,387,633    5,674,985    10,712,648    189%
Impairment of oil and natural gas properties   1,027,552    46,553    980,999    2107%
Depreciation, depletion and amortization   3,313,250    1,556,288    1,756,962    113%
Accretion of discount on asset retirement obligations   20,951    15,607    5,344    34%
   $23,816,473   $9,704,783   $14,111,690    145%
                     
Income (loss) from operations  $(11,408,699)  $(2,807,838)  $(8,600,861)   306%

 

 

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

 

47
 

 

   Year Ended December 31,   Increase   % Increase 
   2010   2009   (Decrease)   (Decrease) 
                 
Production volumes:                    
Oil (Bbls)   56,657    56,003    654    1%
Natural Gas (Mcf)   540,072    610,462    (70,390)   -12%
BOE (1)   146,669    157,747    (11,078)   -7%
BOE per day   401.83    432.18    (30.35)   -7%
                     
Sales Prices                    
Oil (per Bbl)  $74.45   $57.58   $16.87    29%
Natural Gas (per Mcf)  $4.89   $4.00   $0.89    22%
BOE Price  $47.02   $35.92   $11.10    31%
                     
Operating Revenues                    
Oil  $4,218,075   $3,224,862   $993,213    31%
Natural Gas   2,643,310    2,441,848    201,462    8%
Gain on sale of oil and natural gas leases   35,560    -    35,560    0%
   $6,896,945   $5,666,710   $1,230,235   $21%
                     
Operating Expenses                    
Oil and natural gas production costs  $2,163,887   $1,786,280   $377,607    21%
Exploration expense   247,463    240,382    7,081    3%
General and administrative   5,674,985    553,542    5,121,443    925%
Impairment of oil and natural gas properties   46,553    253,258    (206,705)   -82%
Depreciation, depletion and amortization   1,556,288    1,490,926    65,362    4%
Accretion of discount on asset retirement obligations   15,607    12,399    3,208    26%
   $9,704,783   $4,336,787   $5,367,996   $124%
                     
Income (loss) from operations  $(2,807,838)  $1,329,923   $(4,137,761)  $-314%

 

 

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

 

 

   Revenues   Production 
   2011   2010   2009   2011   2010   2009 
Oil   73%   61%   57%   52%   39%   36%
Natural Gas   27%   38%   43%   48%   61%   64%
Gain on sale of oil and natural gas leases   -    1%   -    -    -    - 
Total   100%   100%   100%   100%   100%   100%

  

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Year Ended December 31, 2011 Compared to Years Ended December 31, 2010 and December 31, 2009

 

Oil revenues.    The Company’s oil revenues were $9,079,267 for the year ended December 31, 2011, an increase of $4,861,192 (115%) from $4,218,075 for the year ended December 31, 2010. Higher average oil prices increased revenues approximately $877,304 while increased production increased revenues by approximately $3,983,888. The increase in production volumes was due primarily to new well development primarily in the Bakken. In 2011 we participated in 96 gross (1.65 net) exploratory wells in the Bakken compared to 23 gross (0.27 net) exploratory wells in the Bakken in 2010. The Company’s oil revenues increased by $993,213 (30.8%) in 2010 from $3,224,862 in 2009 primarily related to higher average oil prices in 2010 compared to 2009.

 

Natural gas revenues.     The Company’s natural gas revenues were $3,328,507 for the year ended December 31, 2011, an increase of $685,197 (26%) from $2,643,310 for the year ended December 31, 2010. This increase was due to slightly higher average prices which accounted for approximately $560,571 of the increase in gas revenues. Higher volumes of natural gas sold increased revenue by approximately $124,626. The Company’s natural gas revenues increased in 2010 by $201,462 (8.25%) from $2,441,848 in 2009. Higher average prices increased revenue and offset the slight decrease in gas production from 2009 to 2010. The decrease in production was mainly due to depletion on existing wells.

 

Oil and natural gas production expenses.     Production expenses for the year ended December 31, 2011 increased $903,200 (42%) to $3,067,087, compared to $2,163,887 for the year ended December 31, 2010. The increase is due to an increase in production taxes of $313,000 due to increased revenues for the period and a slight increase in lease operating expenses primarily due to an increase in 132 gross wells (26.9 net wells) partially offset by less rework in the current period versus 2010. Production expenses increased $377,607 (21%) in December 31, 2010 from $1,786,280 for the year ended December 31, 2009 mainly due to newly developed wells and well repair costs incurred during the year ended December 31, 2010.

 

General and administrative expenses.     General and administrative (“G&A”) expenses were $16,387,633 for the year ended December 31, 2011, an increase of $10,712,648 (189%) from $5,674,985 for the year ended December 31, 2010. The primary factor for the increase in G&A expenses was the recognition of $2,019,943 in non-cash penalties related to the delayed registration of the February 1, 2011 and March 31, 2011 equity private placements and an increase in non-cash stock compensation expense of $6,693,548. The remainder of the increase relates to an increase of approximately $630,000 in payroll and taxes and an increase of approximately $1,400,000 in legal and professional fees due to acquisitions and the S-1 registration filing. G&A expenses for December 31, 2010 increased by $5,121,443 (925%) from $553,542 at December 31, 2009 primarily due to the recognition of $4,227,274 in non-cash stock compensation expense, as well as accounting, legal and consulting fees incurred related the formation of Nevada ASEC and the share exchange agreement with FDOG entered into on October 1, 2010.

 

In 2012 and beyond, the Company anticipates G&A expenses to decrease in both absolute terms and as a percentage of total revenues. The Company took on several activities that may be considered non-recurring, including three capital raises, four acquisitions, and an S-1 registration statement. These activities may have contributed significantly to an increase in legal and accounting expenses that may not be incurred at comparable levels in the future. In addition, non-cash stock compensation expenses may also decrease in the future as one-time historical grants are amortized and not re-incurred in the future.

 

Exploration expenses.    Exploratory expenses for the year ended December 31, 2011 were $0, compared to $247,463 for the year ended December 31, 2010.  This expense was primarily attributable to an unsuccessful exploratory well located in the Eagle Ford shale formation drilled in 2007 and reworked as a shale formation well in 2010.  The well was intended to generate petroleum production from the shale formation, but due to a mechanical failure during the drilling process this was unable to be completed. All intangible and tangible costs related to this well have been expensed. Exploration expenses in 2009 were relatively consistent with 2010.

 

Depreciation, depletion and amortization expense.     Depreciation, depletion and amortization (“DD&A”) expense of proved oil and natural gas properties was $3,313,250 for the year ended December 31, 2011, an increase of $1,756,962 (113%) from $1,556,288 for the year ended December 31, 2010. The increase in depletion expense was primarily due to an increase in production volumes in the Bakken. We have invested in new assets in new basins over the past year.  These assets differ significantly from legacy assets in the Permian Basin included in the 2010 DD&A calculation. Our Bakken production in 2011 was primarily new production, which typically experiences a much more rapid decline curve than our legacy Permian Basin production. The net effect was to increase depreciation and depletion rates on a per BOE basis.  DD&A per BOE increased 61% for the year ended December 31, 2011 as compared to the year ended December 31, 2010. With the increased development and productivity in unconventional drilling in the Bakken and Eagle Ford, DD&A per BOE is expected to be higher than historical DD&A for the year ended December 31, 2010 per BOE for the traditional Permian Basin producing assets. DD&A increased by $65,362 (4%) from $1,490,426 at December 31, 2009.

 

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Impairment of oil and natural gas properties. Impairment expense for the year ended December 31, 2011 was $1,027,522 compared to $46,533 at December 31, 2010. The Company impaired approximately $447,552 related to its unproved leaseholds for the year ended December 31, 2011. 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 $580,000 of its proved properties as the carrying value of the properties was higher than the estimated fair value at December 31, 2011. Impairment expense at December 31, 2010 decreased $206,705 (81.6%) from $253,258 at December 31, 2009 primarily due to higher estimated reserve values in the Bakken formation for the period ended December 31, 2010.

 

Other income, net.     Other income (expense) increased to ($2,265,189) for the year ended December 31, 2011 from $0 at December 31, 2010 and 2009.  The increase was due 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.  The increase also included interest expense for accretion of the debt discount of $1,010,924, and interest expense of $173,938 incurred in the year ended December 31, 2011.

 

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 year ended December 31, 2011, 2010 and 2009 was $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, 2011, 2010 and 2009 totaled $54,372,042, $13,021,284 and $2,393,249, respectively. The 2011 costs related primarily to new drilling activities in the Permian and Eagle Ford and additional Bakken undeveloped leases. The 2010 costs related primarily to purchases of additional Bakken leases and drilling in the Bakken, Permian and South Texas leases.  The 2009 costs related primarily to purchases of Bakken undeveloped leases, the drilling of four Bakken wells, and the drilling of one South Texas well.

 

Our 2012 capital budget for drilling (excluding any acquisitions) is approximately $125 million assuming additional financing is made available under our existing facility or new financing is obtained. We expect to be able to fund our remaining 2012 capital budget partially with operating cash flows, and utilization of our existing 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 credit facility will fund our 2012 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 2012 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 2011 were cash flows generated from proceeds from our private placement offerings of our common stock and proceeds from stock subscription receivables from which cash net proceeds of $47,892,172 were generated.  We also borrowed $17,169,889 under our credit facility. 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 2012 capital expenditure plans.

 

Cash flow from operating activities.   Our net cash provided by operating activities were $4,402,749, $3,739,625 and $2,936,683 for the year ended December 31, 2011, 2010 and 2009, respectively. The decrease in operating cash flow for the year ended December 31, 2011 was due primarily to increased general and administrative costs and the reduction in working capital through increases in oil and gas sales receivables and the non-cash accounts payable and accrued liabilities for oil and natural gas additions. The increase in operating cash flow from 2009 to 2010 was due primarily to changes in operating assets and liabilities.

 

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Cash flow used in investing activities.    During the year ended December 31, 2011, 2010 and 2009, we invested $58,462,398, $12,878,375 and $2,393,249, respectively, for additions to, and acquisitions of, oil and natural gas properties, inclusive of exploration costs. Cash flows used in investing activities were substantially higher in 2011, 2010 and 2009 due to the Company’s increased leasehold acquisition activities in the Bakken Shale Formation, Eagle Ford and Permian drilling activities, prepaid drilling costs and a $1.5 million deposit with XOG relating to the 2012 acquisition.

 

Cash flow from financing activities.    Net cash provided by (used in) financing activities was $54,272,702, $9,658,746 and ($543,434) for the year ended December 31, 2011, 2010 and 2009, respectively. Financing activity 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. Financing activities for 2010 comprised primarily of equity provided by the XOG Group to support leasehold acquisitions and new drilling activities and $5,374,907 of net proceeds from the sales of stock and warrants during the year.

 

February 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 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 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.

 

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.

 

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.

 

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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%.

 

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. At December 31, 2011, $17,169,889 was the outstanding borrowings under the Credit Agreement.

 

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 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.

 

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.

 

Liquidity.   Our principal sources of short-term liquidity are cash on hand, operational cash flow, and incremental borrowing under our Credit Agreement.  At December 31, 2011, we had cash and cash equivalents of $733,049. 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. See Note N in the Notes to Consolidated Financial Statements for a discussion of recent financings.

 

Contractual Obligations

 

Employment Agreements.   At December 31, 2011, our contractual obligations include employment agreements with executive officers for the years ending December 31, 2012 through 2014 are as follows:

 

   2012   2013   2014 
Scott Feldhacker  $231,000   $231,000   $77,000 
Richard Macqueen   231,000    231,000    77,000 
Scott Mahoney   206,000    206,000    68,667 
Total Contractual Obligations Related to Employment Contracts  $668,000   $668,000   $222,667 

 

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, 2011, the Company recorded lease expense of $90,214.

 

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At December 31, 2011, the future minimum lease commitments under the non-cancellable operating leases for each of the following five years ending December 31 are as follows:

 

2012   67,606 
2013   97,356 
2014   99,402 
2015   101,448 
2016   42,625 
Total  $408,437 

 

 

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.

 

  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, 2011 and 2010 were approximately $25,213,000 and $9,954,000, 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.

 

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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

 

Reserve Estimation.  In January 2010, the FASB issued an update to the Oil and Gas Topic, which aligns the oil and natural gas reserve estimation and disclosure requirements with the requirements in the SEC’s final rule,   Modernization of the Oil and Gas Reporting Requirements   (the “Final Rule”). The Final Rule was issued on December 31, 2008. The Final Rule is intended to provide investors with a more meaningful and comprehensive understanding of oil and natural gas reserves, which should help investors evaluate the relative value of oil and natural gas companies.

 

  The Final Rule permits the use of new technologies to determine proved reserves estimates if those technologies have been demonstrated empirically to lead to reliable conclusions about reserve volume estimates. The Final Rule also allows, but does not require, companies to disclose their probable and possible reserves to investors in documents filed with the SEC. In addition, the new disclosure requirements require companies to: (i) report the independence and qualifications of its reserves preparer or auditor; (ii) file reports when a third party is relied upon to prepare reserves estimates or conduct a reserves audit; and (iii) report oil and natural gas reserves using an average price based upon the prior 12-month period rather than a year-end price. The Final Rule became effective for fiscal years ending on or after December 31, 2009.

 

 

Item 7A.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

 

As the Company expands, the Company will be exposed to a variety of market risks including credit risk, commodity price risk and interest rate risk. We will address these risks through a program of risk management which may include the use of derivative instruments including hedging contracts. Such contracts involve incurring future gains or losses from changes in commodity prices or fluctuations in market interest rates.

 

Credit Risk.  The Company monitors its risk of loss due to non-performance by counterparties of their contractual obligations. Our principal exposure to credit risk is through our operating partners and their management of the sale of its oil and natural gas production, which they market to energy marketing companies and refineries. The Company also has exposure to credit counterparties for existing commodity hedging contracts in place through September 2014. The Company monitors its exposure to these counterparties primarily by reviewing credit ratings, financial statements, production, sales, marketing, engineering and reserve reports.

 

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Commodity Price Risk.  The Company is exposed to market risk as the prices of oil and natural gas are subject to fluctuations resulting from changes in supply and demand. To reduce our exposure to changes in the prices of oil and natural gas the Company has and may in the future continue to enter into commodity price risk management arrangements for a portion of its oil and natural gas production.

 

Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

 

Our consolidated financial statements and supplementary financial data are included in this report beginning with page F-1.

 

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

  

On July 28, 2010, Michael Cronin declined to stand for re-appointment as the independent registered public accounting firm for the Company. Mr. Cronin, as a sole practitioner, notified us that certain SEC and PCAOB independence rules state that an accountant is not independent if he or she serves as a lead partner for more than five consecutive years.  Mr. Cronin further advised us that his continued service would be in violation of the independence rules and cause his independence to be impaired.

 

The reports of Michael Cronin on our financial statements for the years ended December 31, 2009 and 2008, were unqualified and contained no adverse opinion or disclaimer of opinion and no report was qualified as to uncertainty, audit scope, or accounting principles.  Mr. Cronin did include an emphasis paragraph in the financial statements for the years ended December 31, 2009 and 2008 relating to a going concern uncertainty.   

 

There were no disagreements on any matter of accounting principles or practices, financial statement disclosure, or auditing scope or procedure, between us and Michael Cronin during the fiscal years ended December 2009 and 2008 or for the period through the date that Michael Cronin elected not to stand for re-appointment.  

  

(a) Engagement of New Independent Registered Public Accounting Firm.

 

i. On October 1, 2010, our Board of Directors appointed BDO USA, LLP (“BDO”), as our new independent registered public accounting firm. The decision to engage BDO was approved by the our Board of Directors on October 1, 2010.

 

ii. Prior to October 1, 2010, we did not consult with BDO regarding (1) the application of accounting principles to a specified transaction, (2) the type of audit opinion that might be rendered on our financial statements, (3) written or oral advice that would be an important factor considered by us in reaching a decision as to an accounting, auditing or financial reporting issue, or (4) any matter that was the subject of a disagreement between us and our predecessor auditor as described in Item 304(a)(1)(iv) or a reportable event as described in Item 304(a)(1)(v) of Regulation S-K.

  

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. The weaknesses involve (1) the inadequate controls over electronic spreadsheets used in financial reporting (2) the lack of adequate accounting personnel so that processes and controls can be completed on a more timely basis and (3) inadequate controls over the recording of stock compensation awards and expenses.

 

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(b) Changes in Internal Control over Financial Reporting

 

During the year ended December 31, 2011, 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 Controller and Director of External Reporting to review, monitor and prepare financial reports.

 

Accounting Software and Supporting Records.   The Company has implemented an oil and gas accounting software system.  This system will be 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 on May 1, 2010.  The Company has completed the process of incorporating the historic financial transactions of the XOG Group related to these properties into the new system. 

 

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 has taken remediation steps discussed in Remediation of Material Weakness in Internal Control over Financial Reporting above to enhance its internal control over financial reporting and reduce control deficiencies. The Company believes the steps listed above enhanced our internal control over financial reporting and reduce control deficiencies.

 

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Report of Independent Registered Public Accounting Firm

 

Board of Directors and Stockholders

American Standard Energy Corp.

Scottsdale, Arizona

 

We have audited American Standard Energy Corp.’s internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). American Standard Energy Corp.’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Item 9A, Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the company’s internal control over financial reporting based on our audit.

 

We conducted our audit 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 effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

 

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

 

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

 

A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the company’s annual or interim financial statements will not be prevented or detected on a timely basis. Material weaknesses were found regarding management’s failure to design and maintain controls over the use of excel spreadsheets to prepare the financial statements and lack of adequate accounting staff so that processes and controls could not be completed in a timely fashion so that adequate review procedures could be performed by the Company. Additionally, there was a material weakness found regarding lack of signed option agreements and incomplete or inappropriate documentation of option grants. These material weaknesses were considered in determining the nature, timing, and extent of audit tests applied in our audit of the 2011 financial statements, and this report does not affect our report dated March 20, 2012, on those financial statements.

 

In our opinion, American Standard Energy Corp. did not maintain, in all material respects, effective internal control over financial reporting as of December 31, 2011, based on the COSO criteria.

 

We do not express an opinion or any other form of assurance on management’s statements referring to any corrective actions taken by the company after the date of management’s assessment.

 

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of American Standard Energy Corp. as of December 31, 2011 and 2010, and the related consolidated statements of income, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2011 and our report dated March 20, 2012 expressed an unqualified opinion thereon.

 

/s/ BDO USA, LLP

Houston, Texas

March 20, 2012

 

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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 directors and executive officers.

 

Name   Age   Position   Date Appointed
Scott Feldhacker   44   Chief Executive Officer and Director   October 1, 2010
Richard MacQueen   45   President and Director   October 1, 2010
Scott Mahoney   37   Chief Financial Officer   October 1, 2010
Robert J. Thompson   69   Chairman of the Board   November 23, 2010
Randall Capps   56   Director   October 11, 2010
James R. Leeton, Jr.   60   Director   March 15, 2011
Scott David   46   Director   April 4, 2011
William “Bill” Killian   47   Director   April 4, 2011

 

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

 

SCOTT FELDHACKER Chief Executive Officer and Director

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. We believe Mr. Feldhacker’s extensive business and leadership experience makes him an important member of the Board of Directors.

 

 RICHARD MACQUEEN President and Director

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. Mr. MacQueen’s extensive business and entrepreneurial experience brings important experience and leadership to the Board of Directors.

 

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SCOTT MAHONEY Chief Financial Officer

Prior to joining Nevada ASEC as a founding executive, from September 2008 to April 2010, Mr. Mahoney was the founder and served as the managing partner of Catalyst Corporate Solutions, LLC, a consulting firm based in Phoenix, Arizona, focused on strategic financial and accounting consulting for companies in rapid growth.  In this capacity, Mr. Mahoney served as the interim Chief Financial Officer for Phoenix Group Metals, Phoenix Stair, ITX Technology Solutions, and Aspire Design from September 2008 to April 2010. Mr. Mahoney was responsible for all operational finance matters, strategic capital raises, and the structuring of mergers and acquisitions opportunities. Mr. Mahoney has more than 15 years of experience in the finance industry, primarily in commercial and investment banking. From April 2005 to September 2008, Mr. Mahoney worked for JP Morgan Chase, where he held a leadership role on more than $1.5 billion in debt facilities.  Prior to JPMorgan Chase, Mr. Mahoney worked for Key Bank’s Technology Investment Banking Group in Seattle, Washington, where he worked in a similar role with small and mid-cap publicly held companies primarily in the information technology services and software industries. Mr. Mahoney is a graduate of Thunderbird International School of Business and the University of New Hampshire.  Mr. Mahoney is also a Chartered Financial Analyst and has been nationally recognized by the Risk Management Association of America for white papers on equity research applied to non-public companies and specialty small-cap investing.

 

ROBERT J. THOMPSON Chairman of the Board of Directors

Mr. Thompson has served as Chairman of the Board of Algae Biosciences Corporation from November 2007 to the present and as Chairman of the Board of QuoteMedia, Inc. from June 2000 to the present.  He has also served as Managing Director of CanAm Capital Partners, LLC, a corporate finance advisory firm, from May 2006 to the present and has been President of Corpus Investments Inc., a private equity firm, since December 2002. Mr. Thompson previously served as Chairman of the Board from 1991 through 2001 of C.M. Oliver Inc., a Canadian publicly traded investment dealer/broker involved since 1907, in investment banking activities throughout North America and Europe, particularly in the oil and gas and mineral resource sectors. His professional involvements concentrated on corporate finance and merger and acquisition advisory services. Mr. Thompson is a Canadian Chartered Accountant (C.A. designation basically equivalent to CPA).  Mr. Thompson also holds Canadian Certified Management Consultant designation (CMC). Mr. Thompson attended the University of British Columbia, enrolled in an accelerated B.Comm./C.A. combined program requiring students to complete 8 years of class work in 6 years.  He completed all courses with distinction.  He however did not submit a final B.Comm thesis and therefore did not receive the B.Comm degree.  Mr. Thompson also chairs the Company’s Compensation, Audit, and Nominating and Corporate Governance Committees. We believe that Mr. Thompson’s extensive financial experience, as well as his experience on the boards of directors of numerous companies, bring substantial leadership skill and experience to the Board of Directors.

 

RANDALL CAPPS Director

Mr. Capps is the largest stockholder of the Company and has more than 30 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 develops and operates 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 vast mineral rights and several supporting oil and gas companies.  Mr. Capps graduated from the University of Texas with an undergraduate degree in business in 1975. Mr. Capps’ thirty-plus years in the oil and gas industry brings important experience and leadership skills to the Board of Directors.

 

JAMES R. LEETON, JR. Director

Mr. Leeton has served as a partner at Bullock Scott, PC, a Midland, Texas based law firm from July 2005 to the present.  Mr. Leeton focuses his practice on oil and gas, banking and business law. Prior to joining Bullock Scott in 2005, Mr. Leeton was a partner at several law firms with an emphasis of practice in oil and gas related industries: Morgan & Leeton, PC (1988-2005), James R. Leeton, Jr. Attorney at Law (1985-1988), and Leeton & Leeton, PC (1978-1985).  Mr. Leeton was also employed as a Landman for ExxonMobil Corporation from 1977-1978. Mr. Leeton earned a Bachelor of Arts Degree from University of Texas, Austin and his Doctor of Jurisprudence from Texas Tech University. We believe that Mr. Leeton’s extensive legal experience in the oil and gas industry brings additional experience and expertise to the Board of Directors.

 

SCOTT DAVID Director

Since 1991, Mr. David has held progressive positions of responsibility within Shell Oil Company, most recently as Joint Venture Formation Manager with a focus on the retail sector in the downstream oil and gas industry.  Mr. David has held various positions over the years at Shell including Pricing Manager for the U.S. Wholesale gasoline business, Equity Investments Manager, Business Acquisitions Manager, and most recently Joint Ventures Formation Manager. Mr. David earned a Bachelor of Business Administration in Finance as well as a minor in Information Systems from Baylor University.  Mr. David also holds a Master of Business Administration with a concentration in Finance from St. Mary’s College. Mr. David’s extensive experience in the oil and gas industry makes him a valuable member of the Board of Directors.

 

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WILLIAM “BILL” KILLIAN Director

From July 2010 to the present, Mr. Killian has served as the General Manager 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.

 

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 Mr. Scott Mahoney, Chief Financial Officer at our address appearing on the cover page of this Annual Report on Form 10-K.

 

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.  However, we have entered into employment agreements with each of our executive officers for a term of four years and automatic extension period of one year (provided the agreement has not been terminated earlier).  Please refer to “Executive Compensation—Employment Agreements” for a discussion of the material terms of the employment 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.

 

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We have determined that Messrs. Thompson, David, Killian and Leeton 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. Thompson, David and Killian. Mr. Thompson is the chairperson of the Audit Committee and serves as its “audit committee financial expert” as defined by SEC rules.

 

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. Thompson, Killian and Leeton. Mr. Thompson is the chairperson of the Compensation Committee.

 

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 members of our Corporate Governance and Nominating Committee are Messrs. Thompson, David, Killian and Leeton. Mr. Thompson is the chairperson of the Corporate Governance and Nominating Committee.

 

The CGNC of the Board of Directors has established the Fairness Committee as a standing sub-committee of the NCGC.   The Fairness Committee is appointed by the NCGC 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 members of this subcommittee are Messrs. Thompson, David, Killian and Leeton.

 

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. Our board of directors has also determined that having the Chief Executive Officer serve as director could enhance understanding and communication between management and the board of directors, allows for better comprehension and evaluation of our operations, and ultimately improves the ability of the board of directors to perform its oversight role. The management of enterprise-level risk may be defined as the process of identification, management and monitoring of events that present opportunities and risks with respect to the creation of value for our shareholders. The board of directors has delegated to management the primary responsibility for enterprise-level risk management, while retaining responsibility for oversight of our executive officers in that regard.

 

  Family Relationships

 

Scott Feldhacker, our Chief Executive Officer and a member of our board of directors, 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 ownership interests and through his direct ownership interests, Mr. Capps is currently the majority holder of our common stock.   Additionally, our director Scott David is the first cousin of Richard MacQueen, our President and director. 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);

 

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  · 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 2011, there was compliance with the filing requirements applicable to its officers, directors and 10% common stockholders, except that the following reports were not timely filed:  Forms 4s were not filed timely by Randall Capps (i) with respect to 208,200 shares of common stock received by Geronimo as partial consideration on August 22, 2011 in exchange for certain leasehold properties and (ii) with respect to 17,603 shares of common stock issued on November 18, 2011 as damages for a delayed filing of a registration statement pursuant to a Registration Rights Agreement dated February 1, 2011.

 

Item 11.EXECUTIVE COMPENSATION

 

EXECUTIVE COMPENSATION SUMMARY

 

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, 2011 and 2010 (collectively, the “named executive officers”) for all services rendered in all capacities to us and our subsidiaries in fiscal 2011 and 2010.

 

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 2011 and 2010. 

 

                       Non-equity   Nonqualified         
               Stock   Option   incentive plan   deferred         
Name and Principal      Salary       Awards   Awards   compensation   compensation   All Other   Total 
Position  Year   ($)   Bonus ($)   ($)(1)   ($)(2)   ($)   earnings ($)   Compensation   ($) 
Scott Feldhacker   2011    210,750    -    -    16,001,333    -    -    -    16,212,083 
Chief Executive Officer   2010    -    -    1,425,000    1,489,000    -    -    -    2,914,000 
                                              
Richard MacQueen   2011    210,750    -    -    16,001,333    -    -    -    16,212,083 
President   2010    -    -    1,500,000    1,489,000    -    -    -    2,989,000 
                                              
Scott Mahoney   2011    159,333    -    -    2,892,000    -    -    -    3,051,333 
Chief Financial Officer   2010    50,000(3)   -    150,000    411,000    -    -    -    611,000 

 

 

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(1) The amounts reported in this column reflect the aggregate grant date fair value of restricted stock share or unit awards computed in accordance with FASB Topic ASC 718 for restricted stock granted in 2010 and 2011 to each named executive officer. The amounts do not reflect compensation actually received by the named executive officers.

 

(2)

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 2010 and 2011 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 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 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.

 

(3) Mr. Mahoney received no salary until September 1, 2010.  Commencing on September 1, 2010, Mr. Mahoney began receiving monthly salary of $12,500 pursuant to the terms of his employment agreement.

 

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.  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.

 

Pursuant to the agreement, in the event Mr. Feldhacker is terminated by the Company due to his disability or in the event of his death, Mr. Feldhacker, or his estate in the case of his death, shall be 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. Feldhacker may be entitled under the terms of any applicable employee benefit plan and all granted but unvested stock awards shall become immediately fully vested (collectively, the “Accrued Benefits”).

 

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If Mr. Feldhacker’s employment is terminated for “Cause”, Mr. Feldhacker will not be entitled to any of the Accrued Benefits or any other benefits under his employment agreement.  “Cause” shall mean, as determined by the Board (or its designee) (1) conduct by the executive in connection with his employment duties or responsibilities that is fraudulent, unlawful or grossly negligent; (2) the willful misconduct of the executive; (3) the willful and continued failure of the executive to perform the executive’s duties with the Company (other than any such failure resulting from incapacity due to physical or mental illness); (4) the commission by the executive of any felony or any crime involving moral turpitude; (5) violation of any material policy of the Company or any material provision of the Company’s code of conduct, employee handbook or similar documents; or (6) any material breach by the executive of any provision of the agreement or any other written agreement entered into by the executive with the Company.

 

In the event that Mr. Feldhacker’s employment is terminated without Cause or Mr. Feldhacker resigns for “Good Reason” (as such term is defined in his employment agreement), Mr. Feldhacker would be entitled to the Accrued Benefits through the date of termination or resignation, as applicable, plus an additional one (1) year of base salary, stock awards and medical benefits under his employment agreement. If Mr. Feldhacker resigns without Good Reason, he will be entitled only to the Accrued Benefits.

 

If the event of a “Change in Control” (i) the Company shall pay to Mr. Feldhacker the Accrued Benefits and (ii) all stock awards that Mr. Feldhacker would have been entitled to receive through the expiration of his employment term and such stock awards shall be fully vested as of the date of the Change in Control.  A “Change in Control” shall be deemed to have occurred if, during the term of the agreement: (i) the beneficial ownership of at least 50% of Nevada ASEC’s voting securities or all or substantially all of the assets of Nevada ASEC’s shall have been acquired, directly or indirectly by a single person or a group of affiliated persons, other than Mr. Feldhacker or a group in which Mr. Feldhacker is a member, or (ii) as the result of or in connection with any cash tender offer, exchange offer, sale of assets, merger, consolidation or other business combination with another corporation or entity and the new board of directors is comprised of majority directors chosen or elected by the members of the new/combined entity who were not members of Nevada ASEC before such cash tender offer, exchange offer, sale of assets, merger, consolidation or other business combination of Nevada ASEC with another corporation or entity.

 

The agreement contains customary confidentiality provisions and provides that Mr. Feldhacker will be subject to noncompetition and non-solicitation covenants for a period of one year following the termination of his employment period.

 

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.  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.

 

Pursuant to the agreement, in the event Mr. MacQueen is terminated by the Company due to his disability or in the event of his death, Mr. MacQueen, or his estate in the case of his death, shall be 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. MacQueen may be entitled under the terms of any applicable employee benefit plan and all granted but unvested stock awards shall become immediately fully vested (collectively, the “Accrued Benefits”).

 

If Mr. MacQueen’s employment is terminated for “Cause”, Mr. MacQueen will not be entitled to any of the Accrued Benefits or any other benefits under his employment agreement.  “Cause” shall mean, as determined by the Board (or its designee) (1) conduct by the executive in connection with his employment duties or responsibilities that is fraudulent, unlawful or grossly negligent; (2) the willful misconduct of the executive; (3) the willful and continued failure of the executive to perform the executive’s duties with the Company (other than any such failure resulting from incapacity due to physical or mental illness); (4) the commission by the executive of any felony or any crime involving moral turpitude; (5) violation of any material policy of the Company or any material provision of the Company’s code of conduct, employee handbook or similar documents; or (6) any material breach by the executive of any provision of the agreement or any other written agreement entered into by the executive with the Company.

 

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In the event that Mr. MacQueen’s employment is terminated without Cause or Mr. MacQueen resigns for “Good Reason” (as such term is defined in his employment agreement), Mr. MacQueen would be entitled to the Accrued Benefits through the date of termination or resignation, as applicable, plus an additional one (1) year of base salary, stock awards and medical benefits under his employment agreement.  If Mr. MacQueen resigns without Good Reason, he will be entitled only to the Accrued Benefits.

 

If the event of a “Change in Control” (i) the Company shall pay to Mr. MacQueen the Accrued Benefits and (ii) all stock awards that Mr. MacQueen would have been entitled to receive through the expiration of his employment term and such stock awards shall be fully vested as of the date of the Change in Control.  A “Change in Control” shall be deemed to have occurred if, during the term of the agreement: (i) the beneficial ownership of at least 50% of Nevada ASEC’s voting securities or all or substantially all of the assets of Nevada ASEC’s shall have been acquired, directly or indirectly by a single person or a group of affiliated persons, other than Mr. MacQueen or a group in which Mr. MacQueen is a member, or (ii) as the result of or in connection with any cash tender offer, exchange offer, sale of assets, merger, consolidation or other business combination with another corporation or entity and the new board of directors is comprised of majority directors chosen or elected by the members of the new/combined entity who were not members of Nevada ASEC before such cash tender offer, exchange offer, sale of assets, merger, consolidation or other business combination of Nevada ASEC with another corporation or entity. 

 

The agreement contains customary confidentiality provisions and provides that Mr. MacQueen will be subject to noncompetition and non-solicitation covenants for a period of one year following the termination of his employment period.

 

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 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 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 is 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 shall vest 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. The agreement further provides that Mr. Mahoney 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. Mahoney is 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, shall be 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 entitled under the terms of any applicable employee benefit plan and all granted but unvested stock awards shall become immediately fully vested (collectively, the “Accrued Benefits”).

 

If Mr. Mahoney’s employment is terminated for “Cause”, Mr. Mahoney will not be entitled to any of the Accrued Benefits or any other benefits under his employment agreement.  “Cause” shall mean, as determined by the Board (or its designee) (1) conduct by the executive in connection with his employment duties or responsibilities that is fraudulent, unlawful or grossly negligent; (2) the willful misconduct of the executive; (3) the willful and continued failure of the executive to perform the executive’s duties with the Company (other than any such failure resulting from incapacity due to physical or mental illness); (4) the commission by the executive of any felony or any crime involving moral turpitude; (5) violation of any material policy of the Company or any material provision of the Company’s code of conduct, employee handbook or similar documents; or (6) any material breach by the executive of any provision of the agreement or any other written agreement entered into by the executive with the Company.

 

In the event that Mr. Mahoney’s employment is terminated without Cause or Mr. Mahoney resigns for “Good Reason” (as such term is defined in his employment agreement), Mr. Mahoney would be entitled to the Accrued Benefits through the date of termination or resignation, as applicable, plus an additional one (1) year of base salary, stock awards and medical benefits under his employment agreement.  If Mr. Mahoney resigns without Good Reason, he will be entitled only to the Accrued Benefits.

 

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In the event of a “Change in Control” (i) the Company shall pay to Mr. Mahoney the Accrued Benefits and (ii) all stock awards that Mr. Mahoney would have been entitled to receive through the expiration of his employment term and such stock awards shall be fully vested as of the date of the Change in Control.  A “Change in Control” shall be deemed to have occurred if, during the term of the agreement: (i) the beneficial ownership of at least 50% of Nevada ASEC’s voting securities or all or substantially all of the assets of Nevada ASEC’s shall have been acquired, directly or indirectly by a single person or a group of affiliated persons, other than Mr. Mahoney or a group in which Mr. Mahoney is a member, or (ii) as the result of or in connection with any cash tender offer, exchange offer, sale of assets, merger, consolidation or other business combination with another corporation or entity and the new board of directors is comprised of majority directors chosen or elected by the members of the new/combined entity who were not members of Nevada ASEC before such cash tender offer, exchange offer, sale of assets, merger, consolidation or other business combination of Nevada ASEC with another corporation or entity. 

 

The agreement contains customary confidentiality provisions and provides that Mr. Mahoney will be subject to noncompetition and non-solicitation covenants for a period of one year following the termination of his employment period.

 

Bonus Pool

 

We set aside a bonus pool equal to 5% of our net income for discretionary awards payable in cash to our employees including our executive officers. Allocations of the bonus pool among participants are made by the Chief Executive Officer. There is no formal plan with respect to the bonus pool.

 

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.

 

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 have been returned to the Company.  For the years ended December 31, 2011 and 2010, the Company recorded non-cash stock compensation expense of $789,736 and $559,396, 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, our board of directors 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. 

 

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Outstanding Equity Awards at Fiscal Year-End

 

      Option Awards     Stock Awards
                                                                         
      Number of           Number of                         Option               Market           Equity incentive plan awards:
      securities           securities         Equity incentive plan     Option         expiration     Number of shares         value           Market or payout value
Name     underlying           underlying         awards: Number of     exercise         date     or units of stock         of shares or units of stock           of unearned shares, units or
      unexercised           unexercised         securities underlying     price per               that have         that have           other rights that have 
      options           options         unexercised unearned     share               not vested (#)         not vested           not vested
      exercisable           unexercisable         options (#)     ($)                         ($)            
         (#)           (#)                                                          ($) (12)
Scott Feldhacker     400,000    (1)       400,000         0   $ 1.5         15-Apr-20     727,040          2,290,176           3,635,201
      240,000    (2)       360,000         0   $ 1.5         15-Aug-20                            
      400,000    (3)       2,800,000         0   $ 7.71         1-Apr-21                            
Richard MacQueen     400,000    (4)       400,000         0   $ 1.5         15-Apr-20     765,306          2,410,714           3,826,530
      240,000   (5)       360,000         0   $ 1.5         15-Aug-20                            
      400,000   (6)       2,800,000         0   $ 7.71         1-Apr-21                            
Scott Mahoney     160,000   (7)       240,000             $ 1.5         15-Apr-20     76,531          241,073           382,654
      300,000   (8)       300,000         0   $ 7.45         15-Apr-21                            
      0   (9)       0         600,000               15-Apr-22                            
      0   (10)       0         600,000               15-Apr-23                            
      0   (11)       0         600,000               15-Apr-24                            

 

   
(1) Vests in installments of 200,000 shares of common stock every six months beginning on January 1, 2011.
(2) Vests in installments of 120,000 shares of common stock beginning on January 1, 2011, August 15, 2011 and then in yearly installments thereafter.
(3) Vests in installments of 400,000 shares of common stock on October 15, 2011 and April 15, 2012; the remainder vests in installments of 600,000 shares of common stock every six months beginning on October 15, 2012.
(4) Vests in installments of 200,000 shares of common stock every six months beginning on January 1, 2011.
(5) Vests in installments of 120,000 shares of common stock beginning on January 1, 2011, August 15, 2011 and then in yearly installments thereafter.
(6) Vests in installments of 400,000 shares of common stock on October 15, 2011 and April 15, 2012; the remainder vests in installments of 600,000 shares of common stock every six months beginning on October 15, 2012.
(7) Vests in installments of 80,000 shares of common stock beginning on January 1, 2011, August 15, 2011 and then in yearly installments thereafter.
(8) Vests in installments of 300,000 shares of common stock on October 15, 2011 and April 15, 2012.
(9) Vests in installments of 300,000 shares of common stock on October 15, 2012 and April 15, 2013.
(10) Vests in installments of 300,000 shares of common stock on October 15, 2013 and April 15, 2014.
(11) Vests in installments of 300,000 shares of common stock on October 15, 2014 and April 15, 2015.
(12) Market values reflect the closing price of our common stock on the OTCBB on December 30, 2011 (the last business day of the fiscal year), which was $3.15 per share.

 

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Compensation of Directors

 

The following table lists the compensation paid to our directors as of our last fiscal year ended December 31, 2011.

 

Name  Fees earned or paid in cash ($)   Stock
awards ($)
   Option awards ($) (1)(2)   Non-equity incentive plan compensation ($)   Nonqualified deferred compensation earnings ($)   All other compensation   Total ($) 
                             
Robert Thompson   32,500    -    -    -    -    -    32,500 
Jim Leeton   19,000    -    155,400    -    -    -    174,400 
William Killian   18,000    -    149,700    -    -    -    167,700 
Scott David   18,000    -    149,700    -    -    -    167,700 
Randall Capps   -    -    -    -    -    -    - 

  

(1)  On March 15, 2011, Mr. Leeton was granted options to purchase 30,000 shares of our common stock which expire 120 months from March 15, 2011.
(2)   On April 1, 2011, Mr. David and Mr. Killian were each granted options to purchase 30,000 shares of our common stock which expire 120 months from April 1, 2010.

 

The following table lists the compensation paid to our directors as of our previous fiscal year ended December 31, 2010.

 

Name  Fees earned or paid in cash ($)   Stock
awards ($)
   Option awards ($) (1)   Non-equity incentive plan compensation ($)   Nonqualified deferred compensation earnings ($)   All other compensation   Total ($) 
Robert Thompson   2,500    -    627,179    -    -    -    629,679 
Jim Leeton   -    -    -    -    -    -    - 
William Killian   -    -    -    -    -    -    - 
Scott David   -    -    -    -    -    -    - 
Randall Capps   -    -    -    -    -    -    - 

 

(1)   On December 1, 2010, Mr. Thompson was granted options to purchase 300,000 shares of our common stock which expire 120 months from December 1, 2010.

 

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.

 

Mr. Thompson received $2,500 per month for his serves rendered as our director, which increased to $5,000 per month on December 1, 2011. Our other independent directors receive a monthly fee of $2,000 and are entitled to receive an annual option grant to purchase 30,000 shares of our common stock.

 

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.

 

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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 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. 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 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. 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.

 

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. 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.

 

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The directorship term commenced on May 23, 2011 and terminates 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.

 

 

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.

 

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.

 

Following this offering, 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 March 15, 2012, 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 March 15, 2012.  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 March 15, 2012 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.  

 

Name and Address of Beneficial Owner  Amount and Nature of
Beneficial Ownership(1)
   Percentage of Class(2) 
         
Executive Officers and Directors          
           
Scott Feldhacker   2,443,058(3)   5.2%
Chief Executive Officer and Director          
           
Richard MacQueen   2,489,272(4)   5.3%
President and Director          
           
Scott Mahoney   844,427(5)   1.8%
Chief Financial Officer          
           
Randall Capps   24,493,077(6)   53.9%
Director          
           
Scott David   30,000(7)   * 
Director          
           
William “Bill” Killian   30,000(7)   * 
Director          
           
James R. Leeton, Jr.   30,000(7)   * 
Director          
           
Robert J. Thompson   120,000(7)   * 
Director          
           
All Executive Officers and Directors as a group (8 persons)   30,479,834    61.3%
          
5% Shareholders          
           
Geronimo Holding Corporation   21,642,821    47.8%
1801 West Texas,          
Midland, TX 79701          
           
Pentwater Capital Management LP   3,572,996(8)   7.8%
227 West Monroe Suite 4000          
Chicago, IL 60606          

 


 * less than 1%

 

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  (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 45,297,456 shares of Common Stock issued and outstanding as of March 15, 2012.

 

  (3) Includes (a) 1,640,000 shares of Common Stock underlying options that were exercisable within 60 days of March 15, 2012; and (b) 803,058.  Mr. Feldhacker is the son-in-law of Mr. Capps.

 

  (4) Includes (a) 1,640,000 shares of Common Stock underlying options that were exercisable within 60 days of March 15, 2012; and (b) 849,272 shares of Common Stock.

 

  (5) Includes (a) 760,000 shares of Common Stock underlying options that were exercisable within 60 days of December 31, 2011; and (b) 84,427 shares of Common Stock.

  

  (6) Includes (a) 21,642,821 shares of Common Stock held by Geronimo; (b) 1,387,754 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) 653,062 shares of Common Stock and 142,858 shares of Common Stock underlying warrants purchased in private placements and (f) 17,142 Registration Shares.  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.
     
  (7) Reflects shares of Common Stock underlying options that were exercisable as of the date of this annual report.
     
  (8) Based on Schedule 13G filed by Pentwater Capital Management on February 14, 2012.

 

Changes in Control

 

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

 

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.

 

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, 2011, sales through XOG were $8,349,028 and lease operating expenses were $1,626,332.

 

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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.

 

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 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 our common stock, which were valued at $3,960,000 based on a closing price of $3.30 on the closing date.

 

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.

 

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.

 

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.

 

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Policies Related to Related Party Transactions

 

The Corporate Governance and Nominating Committee (“CGNC”) of the Board of Directors has established the Fairness Committee as a standing sub-committee of the NCGC.   The Fairness Committee is appointed by the NCGC 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 Fairness Committee ensures that any concerns about fairness that are identified are brought fully to the attention of the Board.

 

The Board of Directors may also establish a special committee of the Board comprised solely of directors disinterested in the the related party transaction (the “Special Committee”) to, among other things, conduct an independent review and investigation of any and all issues raised by related party transactions, including the fairness to the Company and the Company’s non-affiliated stockholders as of the time that each related party transaction is approved.

 

 

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.

 

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.

 

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, additional acquisition related audit and review services, and reviews of our interim financial statements for the year ended December 31, 2011 were approximately $1,081,886.

 

b. Audit-Related Fees: No fees were billed for assurance and related services reasonably 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, 2011.
   
c. Tax Fees: Aggregate fees billed by BDO USA, LLP for tax services for the year ended December 31, 2011 were zero.

 

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

   

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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, 2011 and 2010
 
Consolidated Statements of Operations for the years ended December 31, 2011, 2010 and 2009
 
Consolidated Statement of Stockholders' Equity for the years ended December 31, 2011, 2010 and 2009
 
Consolidated Statements of Cash Flows for the years ended December 31, 2011, 2010 and 2009
 
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.

 

(c)  Financial Statement Schedules

 

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 )
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)*
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)

 

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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)  
  Letter Agreement dated December 30, 2011, by and between American Standard Energy Corp. and Scott Mahoney (16)  

10.38

10.39

 

Form of Warrant issued to Pentwater, dated February 9, 2012 (17)

Form of Series C Warrant issued to Pentwater, dated February 9, 2012 (17)

 
10.40   Amended and Restated Warrant issued to Macquarie Americas Corp., dated February 9, 2012 (17)  
10.41   Note and Warrant Purchase Agreement by and among the Company, ASEN 2, and Pentwater, dated as of February 9, 2012  (17) +  
10.42   Secured Convertible Promissory Note issued by ASEN 2 to Pentwater, dated February 9, 2012 (17)  
10.43   Security Agreement by and among ASEN 2 to Pentwater, dated as of February 9, 2012 (17) +  
10.44   Guaranty Agreement by and among the Company and Pentwater, dated as of February 9, 2012 (17)  
10.45   Registration Rights Agreement by and among the Company and Pentwater, dated as of February 9, 2012 (17)  
10.46   Modification Agreement by and among the Company, Pentwater and its affiliates, dated as of February 9, 2012 (17)  
10.47   Amendment to Securities Purchase Agreement by and among the Company and certain holders thereto, dated February 9, 2012 (17)  
10.48   Mortgage and Deed of Trust from ASEN 2 to Pentwater for LaSalle County, Texas (17) +  
10.49   Mortgage and Deed of Trust from ASEN 2 to Pentwater for Frio County, Texas (17) +  
10.50   Purchase and Sale Agreement by and among the Company, XOG Operating LLC, and Geronimo Holding Corporation, dated as of February 24, 2012 (18) +  
10.51   Promissory Note issued by the Company to Geronimo Holding Corporation, dated March 5, 2012 (18)  
10.52   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)  
10.53   Amended 2010 Equity Compensation Plan (20)*  
10.54   2011 Equity Incentive Plan (21)*  
31.1 Rule 13a-14(a)/15d-14(a) certification of Scott Feldhacker

 

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31.2 Rule 13a-14(a)/15d-14(a) certification of Scott Mahoney
32.1 Certification pursuant to 18 USC, Section 1350 of Scott Feldhacker
32.2 Certification pursuant to 18 USC, Section 1350 Scott Mahoney
   
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
101 The following material from American Standard Energy Corp.’s Form 10-K for the fiscal year ended December 31, 2011, formatted in XBRL (Extensible Business Reporting Language): (i) the Consolidated Statements of Income; (ii) the Consolidated Balance Sheets; (iii) the Consolidated Statements of Cash Flows; and (iv) the Notes to the Consolidated Financial Statements.

 

  (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.

 

+ 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.

 

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SIGNATURES

 

    AMERICAN STANDARD ENERGY CORP.
     
March 20, 2012 By: /s/Scott Feldhacker
    Scott Feldhacker
   

Chief Executive Officer

(Principal Executive Officer)

 

March 20, 2012

 

 

/s/ Scott Mahoney

    Scott Mahoney, CFA

Chief Financial Officer

(Principal Financial and Accounting Officer)

 

 
 

 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  and Director   March 20, 2012
Scott Feldhacker        
         
/s/ Scott Mahoney   Chief Financial Officer, Principal Accounting Officer   March 20, 2012
Scott Mahoney        
         
/s/ Richard MacQueen   President and Director   March 20, 2012
Richard MacQueen        
         
     Chairman of the Board of Directors   March 20, 2012
Robert J. Thompson        
         
/s/ Randall Capps   Director   March 20, 2012
Randall Capps        
         
/s/ James R. Leeton, Jr.   Director   March 20, 2012
James R. Leeton, Jr.        
         
/s/ Scott David   Director   March 20, 2012
Scott David        
         
/s/ William Killian   Director   March 20, 2012
William Killian        

 

78
 

 

 American Standard Energy Corp. and Subsidiary

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, 2011 and 2010 F-3
   
Consolidated Statements of Operations for the years ended December 31, 2011, 2010 and 2009 F-4
   
Consolidated Statements of Cash Flows for the years ended December 31, 2011, 2010 and 2009 F-5
   
Consolidated Statements of Stockholders’ Equity for the years ended December 31, 2011, 2010 and 2009 F-6
   
Notes to Consolidated Financial Statements F-7 – F-22
   
Unaudited Supplementary Information F-23 – F-26
             

 

 
 

 

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. and subsidiary (the “Company”) as of December 31, 2011 and 2010 and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2011. 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. An audit 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.

 

As described in Notes A, K, L, and N, the Company engages in significant transactions with related parties.

 

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, 2011 and 2010, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2011, in conformity with accounting principles generally accepted in the United States of America.

 

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), American Standard Energy Corp.'s internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) and our report dated March 20, 2012 expressed an adverse opinion thereon.

 

/s/ BDO USA, LLP

 

Houston, Texas

 

March 20, 2012

  

F-2
 

  

PART I – FINANCIAL INFORMATION

 

Item 1. Financial Statements

  

American Standard Energy Corp. and Subsidiary  

Consolidated Balance Sheets  

 

   December 31,   December 31, 
   2011   2010 
Current assets:          
Cash and cash equivalents  $733,049   $519,996 
Oil and gas sales receivables    1,556,414    701,754 
Oil and gas sales receivables - related parties   639,714    89,630 
Stock subscriptions receivable and other current assets   308,208    1,565,548 
Total current assets   3,237,385    2,876,928 
           
Oil and natural gas properties at cost, successful efforts method          
Proved   76,919,789    29,881,328 
Unproved   25,212,635    9,954,354 
Accumulated depletion and depreciation   (14,310,006)   (10,044,746)
Total oil and natural gas properties, net   87,822,418    29,790,936 
           
Debt issuance costs, net of amortization of $69,184   720,175    - 
Prepaid drilling costs   2,590,356    101,946 
Deposit on properties with affiliate   1,500,000    - 
Other assets, net of accumulated depreciation of $7,380 and $1,023   24,403    29,670 
           
Total assets  $95,894,737   $32,799,480 
           
Current liabilities:          
Accounts payable - trade  $3,373,262   $925,654 
Accounts payable and accrued liabilities - related parties   8,574,017    2,856,312 
Accrued withholding tax   1,338,308    - 
Commodity derivatives   243,996    - 
Other accrued liabilities   36,665    1,708,695 
Total current liabilities   13,566,248    5,490,661 
           
Term loan and revolving credit facility, net of discount of $9,907,057   7,262,832    - 
Asset retirement obligations   394,177    242,632 
Commodity derivatives   421,964    - 
Warrant derivative liabilities   15,298,658    - 
Total liabilities   36,943,879    5,733,293 
           
Stockholders' equity          
Preferred stock, $.001 par value; 1,000,000 shares authorized; None issued and outstanding   -    - 
Common stock, $.001 par value; 100,000,000 shares authorized, 40,178,060 shares issued and 39,971,367 shares outstanding at December 31, 2011 and 28,343,905 shares issued and outstanding at December 31, 2010   40,178    28,344 
Additional paid-in capital   75,504,243    28,841,004 
Treasury stock, 206,693 shares at cost   (1,116,514)   - 
Accumulated deficit   (15,477,049)   (1,803,161)
Total stockholders' equity   58,950,858    27,066,187 
           
Total liabilities and stockholders' equity  $95,894,737   $32,799,480 

 

F-3
 

 

American Standard Energy Corp. and Subsidiary

Consolidated Statements of Operations

 

   Years Ended December 31, 
   2011   2010   2009 
Operating revenues:               
Oil & natural gas revenues  $12,407,774   $6,861,385   $5,666,710 
Gain on sale of oil and natural gas leases   -    35,560    - 
    12,407,774    6,896,945    5,666,710 
Operating costs and expenses:               
Oil and natural gas production costs   3,067,087    2,163,887    1,786,280 
Exploration expense   -    247,463    240,382 
General and administrative (including non cash stock-based compensation of $10,401,110, $4,227,274 and none)   16,387,633    5,674,985    553,542 
Impairment of oil and natural gas properties   1,027,552    46,553    253,258 
Depreciation, depletion and amortization   3,313,250    1,556,288    1,490,926 
Accretion of discount on asset retirement obligations   20,951    15,607    12,399 
                
Total operating costs and expenses   23,816,473    9,704,783    4,336,787 
                
Income (loss) from operations   (11,408,699)   (2,807,838)   1,329,923 
                
Other income (expense), net:               
Realized and unrealized loss on commodity derivatives   (670,659)   -    - 
Interest expense, including accretion of debt discount   (1,184,862)   -    - 
Unrealized expense on warrant derivatives   (409,668)   -    - 
Total other income (expense), net   (2,265,189)   -    - 
                
Income tax benefit   -    -    92,000 
                
Net income (loss)  $(13,673,888)  $(2,807,838)  $1,421,923 
                
Weighted average common shares outstanding  $35,413,541   $23,755,750   $18,695,849 
Loss per share basic and diluted (1)  $(0.39)  $(0.12)  $0.08 

 

(1)     Proforma presentation for 2010 and 2009, refer to Note B

 

F-4
 

 

American Standard Energy Corp. and Subsidiary    

Consolidated Statements of Cash Flows    

  

   Years Ended December 31, 
   2011   2010   2009 
CASH FLOWS FROM OPERATING ACTIVITIES:               
Net income (loss)  $(13,673,888)  $(2,807,838)  $1,329,923 
Adjustments to reconcile net loss to net cash provided by operating activities:               
Depreciation, depletion and amortization   3,313,250    1,556,288    1,490,926 
Amortization of debt discount   1,010,924    -    - 
Unrealized loss on commodity derivative   665,960    -    - 
Unrealized expense on warrant derivatives   409,668    -    - 
Exploration expenses   -    247,463    240,382 
Accretion of asset retirement obligations   20,951    15,607    12,399 
Gain on sale of oil and natural gas leases   -    (35,560)   - 
Common stock issued for services   -    26,500    - 
Impairment of oil and natural gas properties   1,027,552    46,553    253,258 
Non-cash stock-based compensation expense   10,401,110    4,227,274    - 
Penalties for delayed registration, paid for by common stock   2,019,943    -    - 
Changes in operating assets and liabilities:               
Oil and natural gas sales receivables   (2,411,823)   (104,466)   (266,341)
Other current assets   (300,358)   26,282    (100,617)
Accounts payable and accrued liabilities   1,919,460    541,522    (23,247)
                
Net cash provided by operating activities   4,402,749    3,739,625    2,936,683 
                
CASH FLOWS FROM INVESTING ACTIVITIES:               
Oil and natural gas property additions   (54,372,042)   (13,021,284)   (2,393,249)
Prepaid drilling costs   (2,590,356)   (101,946)   - 
Proceeds from sale of oil and natural gas leases   -    244,855    - 
Deposit on properties with affiliate   (1,500,000)   -    - 
                
Net cash used in investing activities   (58,462,398)   (12,878,375)   (2,393,249)
                
CASH FLOWS FROM FINANCING ACTIVITIES:               
Net proceed from changes in predecessor net investment   -    4,783,839    (543,434)
Cash payment to Geronimo - deemed distribution   (10,000,000)   (500,000)   - 
Proceeds from the sale of stock, net   46,334,474    3,506,985    - 
Proceeds from exercise of warrants   -    1,867,922    - 
Proceeds from stock subscription receivable   1,557,698    -    - 
Proceeds from revolving credit facility   17,169,889    -    - 
Debt issuance costs paid   (789,359)   -    - 
                
Net cash provided by financing activities   54,272,702    9,658,746    (543,434)
                
Net increase in cash and cash equivalents   213,053    519,996    - 
                
Cash and cash equivalents at beginning of period   519,996    -    - 
                
Cash and cash equivalents at end of period  $733,049   $519,996   $- 
                
Supplemental disclosure of cash flow information               
Cash paid during the period for interest  $144,456   $-   $- 
                
NON-CASH INVESTING AND FINANCING ACTIVITIES:               
Accounts payable and accrued liabilities for oil and natural gas properties additions  $5,623,612   $4,744,180   $(13,994)
Stock and warrants subscription receivable  $-   $1,557,698   $- 
Additions and revisions to asset retirement cost and related obligation  $130,594   $(10,353)  $(6,482)
Property acquired from Geronimo for shares of common stock  $2,350,050   $-   $- 
Founders shares remitted for accrued withholding tax  $1,116,514   $-   $- 
Non-Cash Deemed Dividend  $459,495   $-   $- 
Discount on debt - derviative warrants  $10,917,981   $-   $- 

 

F-5
 

 

American Standard Energy Corp. and Subsidiary

Consolidated Statements of Stockholders' Equity

Year ended December 31, 2011

 

   Common Stock       Treasury Stock             
   Shares   Value   Additional paid-in capital   Shares   Value   Accumulated (deficit)   Net Investment   Total stockholders' equity 
Balance at January 1, 2009   -   $-   $-    -   $-   $(325,246)  $13,942,564   $13,617,318 
Transfer from XOG Group   -    -    -    -    -    -    (543,434)   (543,434)
Net income   -    -    -    -    -    1,329,923    -    1,329,923 
                                         
Balance at December 31, 2009   -   $-   $-    -   $-   $1,004,677   $13,399,130   $14,403,807 
                                         
Transfer from XOG Group   -    -    -    -    -    -    4,783,839    4,783,839 
Initial capitalization of ASEC   17,526,526    17,527    18,165,442    -    -    -    (18,182,969)   - 
Shares of shell treated as issued in connection with reverse merger   3,540,290    3,540    (3,540)   -    -    -    -    - 
Issuance of common stock for compensation   4,081,632    4,082    3,342,012    -    -    -    -    3,346,094 
Stock-based compensation expense   -    -    881,180    -    -    -    -    881,180 
Issuance of common stock for cash   2,275,442    2,275    4,254,713    -    -    -    -    4,256,988 
Exercise of warrants   910,015    910    2,674,707    -    -    -    -    2,675,617 
Issuance of common stock for services   10,000    10    26,490    -    -    -    -    26,500 
Cash paid to Geronimo - deemed distribution   -    -    (500,000)   -    -    -    -    (500,000)
Net loss   -    -    -    -    -    (2,807,838)   -    (2,807,838)
                                         
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 

 

F-6
 

 

American Standard Energy Corp. and Subsidiary

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 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 ASEC and additional consideration of $25,000 from the ASEC shareholders. In exchange for the ASEC stock and the additional consideration, the XOG Group was 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 Company (the “Company”).  Nevada ASEC is a wholly-owned subsidiary of the Company.

 

A history of the Company’s property acquisitions from the XOG Group accounted for as a transaction under common control through December 31, 2011 is as follows:

 

  · Formation acquisition - On May 1, 2010, the XOG Group contributed certain developed and undeveloped oil and natural gas properties located in Texas and North Dakota (the “Formation Properties”) to Nevada ASEC in exchange for 80% of Nevada ASEC’s common stock. The exchange was accounted for as a transaction under common control and accordingly, the Company recognized the assets and liabilities acquired at their historical carrying values with no goodwill or other intangible assets recognized.  As a result, the historical assets, liabilities and operations of the Formation Properties are included in the accompanying consolidated financial statements retrospectively for all periods presented.

 

  · On December 1, 2010, the Company acquired certain developed and undeveloped oil and natural gas properties located in North Dakota (the “Bakken 1 Properties”) from XOG Group for $500,000 cash and 1,200,000 shares of the Company’s common stock valued at approximately $3,960,000 based on the December 1, 2010 closing price of the Company’s stock.  The acquisition was accounted for as a transaction under common control and accordingly, the Company recorded the assets and liabilities acquired from XOG Group at their historical carrying values.  As a result, the historical assets, liabilities and operations of the Bakken 1 Properties are included in the accompanying consolidated financial statements retrospectively for all periods presented.

 

  · On February 11, 2011, the Company acquired certain developed oil and natural gas properties located in Texas, Oklahoma and Arkansas (the “Group 1 & 2 Properties”) from XOG Group for $7,000,000 cash.  The acquisition was accounted for as a transaction under common control and accordingly, the Company recorded the assets and liabilities acquired from XOG Group at their historical carrying values.  As a result, the historical assets, liabilities and operations of the Group 1 & 2 Properties are included in the accompanying consolidated financial statements retrospectively for all periods presented.

 

F-7
 

 

  · On March 1, 2011, the Company acquired certain undeveloped mineral rights leaseholds held on properties in the Bakken Shale Formation in North Dakota (the “Bakken 2 Properties”) from XOG Group 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 based on the March 1, 2011 closing price of the Company’s stock.  The acquisition was accounted for as a transaction under common control and accordingly, the Company recorded the Bakken 2 Properties at their historical carrying values.  As a result, the historical cost basis of the Bakken 2 Properties is included in the accompanying consolidated financial statements from the period they were originally acquired by XOG Group. 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 are reflected in our December 31, 2011 consolidated financial statements.

 

  · On April 8, 2011, the Company acquired undeveloped leasehold acreage consisting of approximately 2,780 net acres located in Mountrail County of North Dakota’s Williston Basin (the “Bakken 3 Properties”) from XOG Group for $1.86 million. The acquisition was accounted for as a transaction under common control and accordingly, the Company recorded the assets and liabilities acquired from XOG Group at their historical carrying values. The historical assets, liabilities and operations of the Bakken 3 Properties have been included retrospectively in the consolidated financial statements of the Company from the acquisition dates by XOG Group during 2011.

 

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

 

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 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 K 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 subsidiary.  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.

 

F-8
 

  

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.

 

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. 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, 2011, 2010 and 2009. 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, 2011, 2010 and 2009 were $25,212,635, $9,954,354 and $1,322,628, respectively. During the years ended December 31, 2011, 2010 and 2009 the Company recorded unproved properties impairment of $447,552, $0, and $0, respectively.

 

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, 2011, 2010 and 2009 the Company recorded proved properties impairment of $580,000, $46,553 and $253,258, 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 and/or remediation is probable and the costs can be reasonably estimated. Such liabilities are generally undiscounted unless the timing of cash payments is fixed and readily determinable.

 

F-9
 

 

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, 2011, 2010 and 2009 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”). The Company incurred costs related to this facility that were capitalized on the Balance Sheet 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 $789,359. The capitalized costs will be amortized over the term of the facility. The amortization for the year ended December 31, 2011 was $69,184.

 

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.

 

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 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, 2011, 2010 and 2009 was approximately $36,129, $416,827 and $553,542, respectively.

 

Treasury Stock

 

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

 

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, 2011 and 2010. The Company provides compensation benefits to employees and non-employee directors under share-based payment arrangements, including various employee stock option plans. See Note C for further discussion of the Company’s stock-based compensation plans.

 

F-10
 

 

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.

 

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 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.

 

Weighted-average number of shares for the years ended December 31, 2011, 2010 and 2009 was computed on a pro forma basis as if the 17,520,526 and 883,607 common shares issued to the XOG Group in connection with the Company’s acquisition of the Acquired Properties during 2010 and 2011, respectively, and the 285,716 shares purchased by Randall Capps in the February 2011 private placement were issued and outstanding for all periods presented.  As of December 31, 2011, 2,194,621 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).

 

F-11
 

 

Note C.  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 and recorded non-cash stock compensation expense of $2,775,000 for the year ended December 31, 2010.

 

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 and recorded non-cash stock compensation expense of $787,413 and $571,094 for the years ended December 31, 2011 and 2010, respectively. On April 16, 2011, 548,655 shares of founder’s stock issued to management vested.  The Company has estimated that $1,116,513 in federal and state withholding taxes is due related to this vesting, which has been recorded as an accrued liability on the accompanying balance sheet as of December 31, 2011.  The officers of the Company have 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, 2011.  The Company is working with its tax advisors to evaluate the taxable amount due and expects to remit the appropriate tax to the IRS in the first quarter 2012.  In addition, in accordance with the restricted stock agreements for each of the officers, the Company is to reimburse a portion of these withholding taxes to the officers.  Based upon the agreement, the company estimates that it will be required to reimburse in total $221,794 to these officers by December 31, 2012.  This amount is included in general and administrative expenses for the year ended December 31, 2011 and in accrued withholding tax as of December 31, 2011. On February 13, 2012, the Company approved the immediate vesting of the remaining unvested founders shares.

 

Private Placements of Common Stock and Warrants

 

On October 1, 2010, the Company sold to accredited investors 1,591,842 shares of common stock for cash of $2,340,008.

 

On October 20, 2010, the Company closed a private placement offering raising proceeds of $3,034,900, net of offering costs, through the sale of 452,830 shares of the Company's common stock at a price of $2.65 per share and the issuance and exercise of four-month warrants exercisable into 679,245 shares of common stock at an exercise price of $2.75 per share.  The shares and warrants were acquired by two accredited investors.  All of the warrants were exercised in 2010.  The Company incurred costs of $33,022 related to this offering.

 

On December 23, 2010, the Company closed a private placement offering raising proceeds of $1,557,698, which were received in January 2011, through the sale of 230,770 shares of the Company’s common stock at a price of $3.25 per share and the issuance and exercise of four-month warrants exercisable into 230,770 shares of common stock at an exercise price of $3.50 per share.  The shares and warrants were sold to an accredited investor.  All of the warrants were exercised in 2010.  At December 31, 2010 the $1,557,698 was classified as a stock subscription receivable on the balance sheet.  

 

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.

 

F-12
 

 

 

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 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 of 1933, as amended, without restriction (the “Eligibility Date”) is less than the purchase price in the offering or $5.75; and (B) upon certain dilutive occurrences.

 

If made exercisable pursuant to (A) in the preceding sentence, the Series B warrants will become immediately exercisable and will have an exercise price of $0.001 per share to purchase a number of shares of our common stock such that the aggregate average price per share purchased by the investors is 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).  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 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.  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, they were required to pay in common stock 1% of the aggregate purchase price. 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.

 

Deferred Compensation Program

 

On April 15, 2010, the Nevada ASEC’s Board of Directors approved the Nevada ASEC 2010 Deferred Compensation Program. Under this plan, the President and CEO are entitled to receive a one-time retainer 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 on April 13, 2011.  The rescission of the exercise of such options was approved by our board on August 29, 2011. For the year ended December 31, 2011 and 2010, the Company recorded non-cash stock compensation expense of $789,736 and $559,396, respectively, related to the amortization of the fair value of these options which is included in general and administrative expenses.

 

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.

 

F-13
 

 

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.

 

For the years ended December 31, 2011 and 2010, the Company recorded non-cash stock-based compensation expense of $8,855,320 and $375,169, respectively, related to other share based compensation which is included in general and administrative expenses.

 

The following table summarizes the stock options available and outstanding as of December 31, 2011:

  

   Options Available for Grant Under 2010 Plan   Outstanding Options   Weighted Average Exercise Price 
Balance at December 31, 2009   6,000,000    -   $- 
Granted   (3,725,000)   3,725,000   $1.65 
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 

  

The options outstanding as of December 31, 2011 have been segregated into 2 ranges for additional disclosure as follows:

 

 

   Outstanding Options   Options Exercisable 
Range of Exercise Price  Number Outstanding   Weighted Average Exercise Price   Weighted Average Remaining Contractual Term   Number Exercisable   Weighted Average Exercise Price   Weighted Average Remaining Contractual Term 
$1.50 - $3.30   3,605,000    1.66    8.33    1,665,000   $1.65    8.33 
$7.00 - $8.00   7,140,000    7.69    8.55    1,195,556   $7.65    8.96 
    10,745,000    5.67    8.48    2,860,556   $4.16    8.59 

 

The aggregate intrinsic value of the $1.50 to $3.00 options outstanding and options exercisable was $5,378,250 at December 31, 2011. The aggregate intrinsic value of the $7.00 to $8.00 options outstanding and options exercisable was $0 and $0 at December 31, 2011 and 2010, respectively.

 

The following table presents the future non-cash stock compensation expense for the Company’s outstanding restricted stock grants and stock options at December 31, 2011:

  

2012  $11,674,375 
2013   8,613,486 
2014   8,354,095 
2015   2,336,000 
Total  $30,977,956 

 

The weighted average period over which the compensation costs not yet recognized is expected to be 2.04 years.

  

F-14
 

 

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 2011 and 2010.  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.

 

        2011   2010  
Expected volatility   68.96%   74.39% - 83.99%  
Expected dividends   -   -  
Expected term (in years)   5.5 - 6.5   6.0 - 7.3  
Risk-free rate     3.43%   2.77% - 3.86%  

 

The fair value of option grants during the year ended December 31, 2011 and 2010 was $35,608,467 and $4,295,323, respectively. 

  

Note D.  Long term debt

 

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 their stock in the Borrower.   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.

 

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 (2.75% at December 31, 2011), 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.  As part of the Credit Agreement, 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.  Further, the Credit Agreement also limits the amount of general and administrative expenses the Company is permitted to incur in any 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 quarter ended on December 31, 2011. The covenant violations were waived by Macquarie on March14, 2012.

 

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, 2011 was $12 million.  The borrowing base is re-determined semiannually based on the reserve reports by category, oil and gas future sales prices as determined by the lenders, and amount of expenses necessary to produce the oil and gas.

 

The table below reflects the breakdown of the components of the revolving credit facility at December 31, 2011:

 

 

Debt proceeds from revolver  $12,000,000 
Debt proceeds from term loan   5,169,889 
Total debt proceeds  $17,169,889 
Discount on debt   (10,917,981)
Amortization of debt discount   1,010,924 
Net revolving facility and term loan  $7,262,832 

  

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 $5,169,889 at December 31, 2011. 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, 2011, the Company expects to pay $2,584,944 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 H for discussion of the modification of the terms of these warrants in February 2012. 

 

Note E.  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.

 

The Company's asset retirement obligation activity for the years ended December 31, 2011 and 2010 is as follows:

  

   2011   2010   2009 
Balance at beginning of period  $242,632   $237,378   $231,461 
Liabilities incurred from new wells   94,880    12,273    5,108 
Accretion expense   20,951    15,607    12,399 
Revisions due to changes in well life estimates   35,714    (22,626)   (11,590)
Balance at end of period  $394,177   $242,632   $237,378 

 

F-15
 

 

Note F. Income taxes

 

The following table reconciles the Company’s provision for income taxes for the year ended December 31, 2011 and 2010, 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:

 

   2011   2010 
           
Loss before tax  $(13,673,888)  $(2,807,838)
Statutory rate   35%   34%
Expected benefit at federal statutory rate   (4,785,861.00)   (954,665)
Increase (decrease) resulting from:          
State income taxes, net of federal income tax effect   (255,042)   (220,475)
Pass-through income not subject to federal tax   -    (874,465)
Accretion of debt discount   372,679    - 
Book income not subject to tax   (164,221)   - 
Non-deductible stock compensation   -    448,192 
One time charge for conversion to taxable entity   -    845,248 
Change in valuation allowance   4,881,820    756,165 
Other perm items and adjustments   (49,375)   - 
Provision for income taxes  $-   $- 
           
Effective rate   0%   0%
           
           
The components of the Company's net deferred tax assets as of December 31, 2011 and 2010 are as follows:          
           
Deferred tax assets:          
Equity compensation  $4,957,972   $1,101,723 
Asset retirement obligations   145,292    1,295 
Unrealized loss on derivatives   396,532    - 
Net operating loss carry forward   23,801,479    2,742,764 
Other   516    - 
Valuation allowance   (7,082,769)   (2,158,748)
    22,219,022    1,687,034 
Deferred tax liability          
Differences between book and tax basis of property   (22,219,022)   (1,687,034)

 

The Company’s net operating loss carry forward (NOL) at December 31, 2011 was $64,563,585 and will expire beginning in the year 2030. The Company continually assesses both positive and negative evidence to determine whether it is more likely that 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, 2011, the Company has a valuation allowance of $7,082,769 related to its deferred tax assets.

 

As of December 31, 2011, the company had no unrecognized tax benefits. 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 G. 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.  As of December 31, 2011, and through the filing date of this report, the Company has commodity derivative contracts in place through the third quarter of 2014 for a total of approximately 74,726 Bbls of anticipated crude oil production and 655,074 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 $665,960 and $0 at December 31, 2011 and 2010, respectively.

 

The Company recognizes all gains and losses from changes in commodity derivative fair values immediately in earnings. For the year ended December 31, 2011, the Company had a realized loss on commodity derivatives of $4,699 and an unrealized loss of $665,960 included in other income (expense).

 

A summary of our commodity derivatives at December 31, 2011 is as follows:

 

Period of time  Barrels of Oil   Weighted
Average Oil
Prices
   Estimated Fair Market Value 
January 1, 2012 through October 31, 2014   74,726   $81.7   $443,054 

 

Period of time  MMBtu of
Natural Gas
   Weighted
Average Gas
Prices
   Estimated Fair Market Value 
January 1, 2012 through September 26, 2014   655,074   $4.4   $(1,109,014)
                
Total fair market value            $(665,960)

F-16
 

 

The following table details the fair value of derivatives recorded in the accompanying balance sheets, by category:

 

    As of December 31, 2011
    Derivative Assets   Derivative Liabilities
    Balance Sheet   Fair Value   Balance Sheet   Fair Value
 Classification  Classification
Commodity Contracts   Current Assets   $                  -   Current Liabilities   $     (243,996)
Commodity Contracts   Noncurrent Assets                      -   Noncurrent Liabilities         (421,964)
Total commodity derivatives       $                  -       $     (665,960)

 

Note H.    Derivative warrant instruments (liabilities)

 

As part of the July 15, 2011, private placement, the Company issued Series A and Series B 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.  There are 1,130,435 Series A warrants with an exercise price of $9.00 per share, subject to “down round” adjustments.  There are an undermined amount of Series B warrants at an exercise price of $0.001 per share.  Exercise of these warrants is subject to certain adjustment events.

 

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. See Note N for discussion of the modification of the terms of the Macquarie warrants in February 2012.

 

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 has concluded that these warrants are deemed to be derivative instruments and are 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, 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.

 

Activity for derivative warrant instruments during the year ended December 31, 2011 was 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-17
 

 

The fair value of the derivative warrant instruments is estimated using a probability-weighted scenario analysis model with the following assumptions as of December 31, 2011:

  

   For the Years
Ended December 31,
 
   2011 
Common stock issuable upon exercise of warrants   6,130,435 
Estimated market value of common stock on measurement date (1)  $3.15 
Exercise price  $7.50 - $9.00 
Expected volatility (2)   66.9% - 74%
Expected term (in months)   10.3 - 60 
Risk-free rate (3)   0.02% - 0.83% 
Expected dividend yields     - 
Future financing event   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 I.    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:

 

  · 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, 2011:

 

 

   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. The book value of our term loan and credit facility approximates fair value because of it’s floating rate structure.

 

F-18
 

 

The following table reflects the activity for warrant derivative liabilities measured at fair value using Level 3 inputs:

 

 

   For the Years 
   Ended December 31, 
   2011   2010 
Beginning balance  $-   $- 
Additions   (14,888,990)   - 
Net increase in liabilities   (406,668)   - 
Transfers in (out) of Level 3   -    - 
Ending balance  $(15,295,658)  $- 

 

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 December 31, 2011.

 

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, 2011, 2010 and 2009, the Company recorded impairments of $1,027,552, $46,553 and $253,258.

 

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 E for a summary of changes in ARO for the periods ended December 31, 2011, 2010 and 2009.

.

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 K.

 

Note J.  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, 2011, 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 2011, 2010 and 2009, revenue through XOG accounted for approximately 67%, 48% and 60%, 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.

 

F-19
 

 

Note K.  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 are from XOG Group for approximately $1.2 million dollars paid in cash. 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.

 

Note L.  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, 2011, sales through XOG were $8,349,028 and lease operating expenses were $1,626,332. Net cash paid to XOG in 2011 was $18,763,680 of which $17,137,348 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 and director.

 

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.

 

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 K.

 

Note M.  Commitments and Contingencies

 

Employment Agreements.    At December 31, 2011, the Company’s cash contractual obligations related to its employment agreements with executive officers for each of the following three years ending December 31 are as follows:

 

 

2012  $668,000 
2013   668,000 
2014   222,667 
Total  $1,558,667 

 

 

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 $90,214 and $14,495, respectively.

 

At December 31, 2011, the future minimum lease commitments under the non-cancellable operating leases for each of the following five years ending December 31 are as follows:

 

 

2012  $67,606 
2013   97,356 
2014   99,402 
2015   101,448 
2016   42,625 
Total  $408,437 

 

F-20
 

 

Drilling Commitments.  At December 31, 2011, 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 $14,548,000.

 

Note N.  Subsequent Events

 

Convertible Note. On February 10, 2012, the Company and ASEN 2, Corp., a wholly-owned subsidiary of the Company formed on January 25, 2012, closed on a Note and Warrant Purchase Agreement dated February 9, 2012, referred to herein as the Purchase Agreement, 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 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.

 

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. The Pentwater Note was issued with an original discount in the amount of $350,000.

 

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 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.

 

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.

 

F-21
 

 

Acceleration of Vesting of Founder’s Shares. On February 13, 2012, the board of directors of American Standard Energy Corp. (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 shares which were to vest in equal portions annually through April 16, 2014. At December 31, 2011, the unamortized compensation expense for these shares was $1,797,995 which will be expensed in the 1st quarter of 2012.

 

March Acquisition. 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”) 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 March 2012 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 Company is currently evaluating the accounting treatment for this transaction.

 

The March 2012 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 March 2012 Note matures on March 21, 2016. The Company may prepay the March 2012 Note at any time without penalty.

 

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 in such registration statement.

 

F-22
 

 

American Standard Energy Corp.

Unaudited Supplementary Information

 

Selected Quarterly Financial Data (Unaudited)

 

For the three-month periods ended:  

   March 31,   June 30,   September 30,   December 31, 
2011                
Revenues  $2,388,493   $3,182,364   $2,995,287   $3,841,630 
Expenses   3,146,337    7,048,436    5,881,655    7,740,045 
Loss from operations   (757,844)   (3,866,072)   (2,886,368)   (3,898,415)
Other income (expense)   -    -    1,047,266    (3,312,455)
Net income (loss)   (757,844)   (3,866,072)   (1,839,102)   (7,210,870)
Loss per share basic and diluted   (0.02)   (0.10)   (0.05)   (0.19)

 

For the three-month periods ended:

   March 31,   June 30,   September 30,   December 31, 
2010                
Revenues  $1,841,918   $1,540,820   $1,787,571   $1,726,636 
Expenses   1,218,570    4,272,383    1,855,393    2,358,437 
Loss from operations   623,348    (2,731,563)   (67,822)   (631,801)
Other income (expense)   -    -    -    - 
Income tax benefit (expense)   -    -    96,228    (96,228)
Net income (loss)   623,348    (2,731,563)   28,406    (728,029)
Loss per share basic and diluted (1)   (0.03)   (0.12)   0.00    (0.03)

 

(1)Proforma presentation for 2010, refer to Note B

 

Costs Incurred

 

Costs incurred for oil and natural gas producing activities during the year ended December 31, 2011 and 2010 was as follows:

 

   Years Ended December 31, 
   2011   2010 
         
Unproved property acquisition costs  $15,258,281   $7,729,953 
Exploration   46,958,052    5,787,926 
Development   80,409    4,308,484 
           
Total  $62,296,742   $17,826,363 

 

Reserve Quantity Information

 

The following information represents estimates of the proved reserves as of December 31, 2011 and 2010.  The Company’s proved reserves as of December 31, 2011 and 2010 have been prepared and presented under new SEC rules. These new rules are effective for fiscal years ending on or after December 31, 2009, and 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 previous rules required that reserve estimates be calculated using last-day-of-the-period pricing.

 

F-23
 

 

The following table summarizes the average prices utilized in the reserve estimates for 2011 and 2010 as adjusted for location, grade and quality: 

 

   As of December 31, 
   2011   2010 
         
Prices utilized in the reserve estimates:          
Texas oil and natural gas properties          
Oil per Bbl(a)  $92.21   $75.43 
Gas per MCF(b)  $6.06   $6.38 
North Dakota oil and natural gas properties          
Oil per Bbl(a)  $90.25   $70.82 
Gas per MCF(b)  $7.10   $4.39 

  

a) The pricing used to estimate our 2011 and 2010 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 2011 and 2010 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 SEC has released only limited interpretive guidance regarding reporting of reserve estimates under the new rules and may not issue further interpretive guidance on the new rules. Accordingly, while the estimates of the proved reserves and related estimated discounted future net cash flows at December 31, 2011 and 2010 included in this report have been prepared based on what we and our independent reserve engineers believe to be reasonable interpretations of the new SEC rules, those estimates could differ materially from any estimates prepared applying more specific SEC interpretive guidance.

 

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, 2011 and 2010 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.

 

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.

 

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 net proved reserves for the years ended December 31, 2011 and 2010, as well as disclosure of proved developed and proved undeveloped reserves at December 31, 2011 and 2010.

 

F-24
 

 

The following table provides a roll-forward of the total proved reserves for the years ended December 31, 2011 and 2010, as well as disclosures of proved developed and proved undeveloped reserves at December 31, 2011 and 2010. 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, 2011   2,290,830    14,511,630    4,709,436 
Revisions   (1,431,844)   (8,333,408)   (2,820,745)
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   2,174,128    7,505,882    3,425,109 
                
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:               
Balance, January 1, 2010   2,047,616    13,508,944    4,299,107 
Revisions   173,505    1,527,388    428,070 
Discoveries   126,366    15,370    128,928 
Production   (56,657)   (540,072)   (146,669)
                
Balance, December 31, 2010   2,290,830    14,511,630    4,709,436 
                
Proved developed reserves   759,642    9,370,893    2,321,457 
Proved undeveloped reserves   1,531,188    5,140,737    2,387,979 
                
Total proven reserves   2,290,830    14,511,630    4,709,436 

  

Total proved reserves as of December 31, 2010 were 4,709,436 BOE including 2,387,979 BOE in proved undeveloped reserves. Our 2010 reserves include reserves acquired in the Group 1&2 acquisition in February 2011.  This transaction was between our Company and XOG Group while we were under common control.  As a result, our proved reserves were recast to include the reserves acquired as if our Company has owned those reserves at December 31, 2010.  Subsequently, we evaluated our proved undeveloped reserves and determined that 1,868,367 BOE in undeveloped reserves were unlikely to be developed in the next three years by the operators of record on which these reserves were located.  As a result, the Company has excluded these locations and the associated reserves from proved reserves as of December 31, 2011.  If these reserves were excluded from all periods presented, total proven reserves as of December 31, 2011 and 2010 would be 3,425,111 BOE and 2,841,069 BOE, respectively.  

 

Standardized Measure of Discounted Future Net Cash Flows

 

The standardized measure of discounted future net cash flows is computed by applying at December 31, 2011 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.

  

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.

 

F-25
 

 

The following table provides the standardized measure of discounted future net cash flows at December 31, 2011 and 2010:

 

   2011   2010 
Future production revenues  $241,879,576   $249,528,763 
Future costs:          
Production   (72,479,264)   (69,359,315)
Development   (24,822,048)   (15,618,950)
Income taxes   (41,401,226)   (50,368,060)
10% annual discount factor   (53,375,271)   (64,504,117)
Standardized measure of discounted cash flows  $49,801,767   $49,678,321 

  

Changes in Standardized Measure of Discounted Future Net Cash Flows

 

The following table provides a roll forward of the standardized measure of discounted future net cash flows for the years ended December 31, 2011 and 2010:

 

 

   2011   2010 
Increase (decrease):          
Extensions and discoveries   23,024,041   $4,626,389 
Net changes in sales prices and production costs   27,230,290    19,421,293 
Oil and gas sales, net of production costs   (9,340,687)   (4,697,498)
Change in estimated future development costs   12,786,697    1,871,994 
Revision of quantity estimates   (67,025,217)   10,483,274 
Purchases of mineral interests   128,684    - 
Previously estimated development costs incurred in the current period   2,832,253    - 
Changes in income taxes   (904,315)   (6,290,341)
Accretion of discount   10,272,969    2,351,883 
Changes in production rates, timing and other   1,118,731    (1,607,493)
Net (decrease) increase   123,446    26,159,501 
Standardized measure of discounted future cash flows:          
Beginning of year   49,678,321    23,518,820 
End of year  $49,801,767   $49,678,321 

 

F-26