American Standard Energy (ASEN) 10-Q 2011 Q3 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended: September 30, 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	27-2302281
(State or Other Jurisdiction of Incorporation or Organization)	(I.R.S. Employer Identification No.)

4800 North Scottsdale Road, Suite 1400

Scottsdale, Arizona 85251

(Address of Principal Executive Office)

Registrant’s Telephone Number, Including Area Code:  (480) 371-1929

N/A

(Former Name, Former Address and Former Fiscal Year, If Changed Since Last Report)

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 ¨

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 ¨ No ¨

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 definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act:

Large accelerated filer ¨	Accelerated filer  ¨
Non-accelerated filer ¨	Smaller reporting company  x
(Do not check if a smaller reporting company)

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

Yes ¨ No x

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date:

As of November 11, 2011, there were 39,511,947 shares of common stock, par value $0.001 per share, outstanding.

TABLE OF CONTENTS

	PART I-Financial Information
Item 1.	Financial Statements (unaudited)	3
	Consolidated Balance Sheets	3
	Consolidated Statements of Operations	4
	Consolidated Statements of Cash Flows	5
	Consolidated Statements of Stockholders’ Equity	6
	Notes to Consolidated Financial Statements	7
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	21
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	29
Item 4.	Controls and Procedures	30
	PART II-Other Information
Item 1A.	Risk Factors	31
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	46
Item 5.	Other Information	46
Item 6.	Exhibits	47

2

PART I – FINANCIAL INFORMATION

Item 1. Financial Statements

American Standard Energy Corp. and Subsidiary

Consolidated Balance Sheets (Unaudited)

	September 30,			December 31,
	2011			2010
Current assets:
Cash and cash equivalents	$	7,214,076		$	519,996
Oil and gas sales receivables - related parties		1,440,581			701,754
Oil and gas sales receivables		738,044			89,630
Stock subscriptions receivable and other current assets		24,741			1,565,548
Commodity derivatives		134,548			-
Total current assets		9,551,990			2,876,928
Oil and natural gas properties at cost, successful efforts method
Proved		34,900,401			29,983,274
Unproved		48,658,531			9,954,354
Accumulated depletion and depreciation		(12,280,284	)		(10,044,746	)
Total oil and natural gas properties, net		71,278,648			29,892,882
Debt issuance costs, net of amortization of $6,226		671,577			-
Deposit on properties		1,500,000			-
Other assets, net of accumulated depreciation of $5,791 and $1,023		25,991			29,670
Total assets	$	83,028,206		$	32,799,480
Current liabilities:
Accounts payable - trade	$	3,371,939		$	2,424,936
Accounts payable - related parties		-			2,856,312
Accrued withholding tax		1,338,308			-
Accrued penalties for delayed registration		1,980,438			-
Other accrued liabilities		60,097			209,413
Total current liabilities		6,750,782			5,490,661
Revolving credit facility, net of discount of $10,816,889		1,183,111			-
Asset retirement obligations		274,129			242,632
Commodity derivatives		286,698			-
Warrant derivative lialilities		13,594,953			-
Total liabilities		22,089,673			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, 39,718,709 issued and 39,511,917 shares outstanding at September 30, 2011 and 28,343,905 shares issued and outstanding at December 31, 2010		39,796			28,344
Additional paid-in capital		70,281,431			28,841,004
Treasury stock, 206,762 shares at cost		(1,116,514	)		-
Accumulated deficit		(8,266,180	)		(1,803,161	)
Total stockholders' equity		60,938,533			27,066,187
Total liabilities and stockholders' equity	$	83,028,206		$	32,799,480

3

American Standard Energy Corp. and Subsidiary

Consolidated Statements of Operations

(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
Operating revenues:
Oil & natural gas revenues	$	2,995,287		$	1,787,571		$	8,566,143		$	5,170,309
Operating costs and expenses:
Oil and natural gas production costs		663,367			471,940			1,759,918			1,402,730
Exploration expense		-			-			-			247,463
General and administrative		4,533,808			989,045			12,053,093			4,507,190
Impairment of oil and natural gas properties		-			46,553			-			46,553
Depreciation, depletion and amortization		679,417			344,150			2,251,704			1,130,533
Accretion of discount on asset retirement obligations		5,063			3,705			11,713			11,877
Total operating costs and expenses		5,881,655			1,855,393			16,076,428			7,346,346
Loss from operations		(2,886,368	)		(67,822	)		(7,510,285	)		(2,176,037	)
Other income (expense), net:
Realized and unrealized gain (loss) on commodity derivatives		(134,871	)		-			(134,871	)		-
Interest expense, including accretion of debt discount		(111,900	)		-			(111,900	)		-
Unrealized gain on warrant derivatives		1,294,037			-			1,294,037			-
Total other income, net		1,047,266			-			1,047,266			-
Income tax benefit (expense)		-			96,228			-			-
Net income (loss)	$	(1,839,102	)	$	28,406		$	(6,463,019	)	$	(2,176,037	)
Weighted average common shares outstanding	$	37,638,531		$	22,174,702		$	34,456,657		$	22,174,702
Loss per share basic and diluted (1)		(0.05	)		0.00			(0.19	)		(0.10	)

(1) Proforma presentation for 2010

4

American Standard Energy Corp. and Subsidiary

Consolidated Statements of Cash Flows (Unaudited)

	Nine Months Ended September 30,
	2011			2010
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(6,463,019	)	$	(2,176,037	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization		2,251,704			1,130,533
Amortization of debt discount		101,092			-
Unrealized loss on commodity derivative		152,150			-
Unrealized gain on warrant derivatives		(1,294,037	)		-
Exploration expenses		-			247,463
Accretion of asset retirement obligations		11,713			11,877
Impairment of oil and natural gas properties		-			46,553
Non-cash stock compensation expense		7,056,724			3,707,562
Accrued penalties for delayed registration		1,980,438			-
Changes in operating assets and liabilities:
Oil and natural gas sales receivables		(2,394,319	)		(175,382	)
Other current assets		(16,891	)		-
Accounts payable and accrued liabilities		1,231,663			1,205,981
Accounts payable - related parties		(2,126,467	)		-
Net cash provided by operating activities		490,751			3,998,550
CASH FLOWS FROM INVESTING ACTIVITIES:
Oil and natural gas property additions		(41,777,541	)		(9,903,947	)
Deposit on properties		(1,500,000	)		-
Net cash used in investing activities		(43,277,541	)		(9,903,947	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Changes in parent net investment		-			3,724,561
Cash payment to Geronimo - deemed distribution		(10,000,000	)		-
Proceeds from the sale of stock , net		46,334,474			2,340,008
Proceeds from stock subscription receivable		1,557,698			-
Proceeds from revolving credit facility		12,000,000			-
Debt issuance costs paid		(411,302	)		-
Net cash provided by financing activities		49,480,870			6,064,569
Net increase in cash and cash equivalents		6,694,080			159,172
Cash and cash equivalents at beginning of period		519,996			-
Cash and cash equivalents at end of period	$	7,214,076		$	159,172
NON-CASH INVESTING AND FINANCING ACTIVITIES:
Additions and revisions to asset retirement cost and related obligation	$	19,784		$	(10,353	)
Property acquired from Geronimo	$	2,350,050		$	-
Founders shares remitted for accrued withholding tax	$	1,116,514		$	-
Non-Cash Deemed Dividend	$	(318,360	)	$	-
Discount on debt - derviative warrants	$	10,917,981		$	-
Accrued debt issuance costs	$	266,501		$	-

5

American Standard Energy Corp. and Subsidiary

Consolidated Statements of Stockholders' Equity (Unaudited)

Nine months ended September 30, 2011

	Common Stock					Additional paid-in			Treasury Stock						Accumulated			Total stockholders'
	Shares			Value		capital			Shares			Value			(deficit)			equity
Balance at December 31, 2010		28,343,905		$	28,344	$	28,841,004			-		$	-		$	(1,803,161	)	$	27,066,187
February 2011, common stock sold in private placement offering at $3.50 per share, less offering costs totaling $774,687		4,401,930			4,402		14,627,666			-			-			-			14,632,068
Property acquired from XOG Group recorded at historical cost		-			-		1,257,000			-			-			-			1,257,000
Shares issued for acquisition of properties from XOG Group recorded at historical cost		883,607			884		(884	)		-			-			-			-
Cash paid and deemed distribution for acquisition of properties from Geronimo recorded at historical cost		-			-		(10,000,000	)		-			-			-			(10,000,000	)
Deemed distribution for working capital not acquired in acquisition of properties		-			-		(318,360	)		-			-			-			(318,360	)
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
Founder's Stock withheld for taxes at $5.40 per share		-			-		-			(206,762	)		(1,116,514	)		-			(1,116,514	)
Forfeited unvested founder's stock		(76,808	)		-		-			-			-			-			-
Stock option expense		-			-		7,056,724			-			-			-			7,056,724
Net loss		-			-		-			-			-			(6,463,019	)		(6,463,019	)
Balance at September 30, 2011		39,718,709		$	39,796	$	70,281,431			(206,762	)		(1,116,514		$	(8,266,180	)	$	60,938,533

6

American Standard Energy Corp. and Subsidiary

Notes to Consolidated Financial Statements

September 30, 2011 and December 31, 2010

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.  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 American Standard Energy Corp., a Nevada Corporation, 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 through September 30, 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 the Company in exchange for 80% of the Company’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 $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.

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 March 31, 2011 interim 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 J for a recent acquisition 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.

Certain information and footnote disclosures normally included in the consolidated financial statements prepared in accordance with U.S. GAAP have been condensed or omitted in this Form 10-Q pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”). These condensed consolidated financial statements should be read in connection with the consolidated financial statements and notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2010, and the Company’s recast financial information for the year ended December 31, 2010 filed with the Company’s Current Report on Form 8-K filed on June 14, 2011.

The accompanying condensed consolidated financial statements have been prepared on the accrual basis of accounting whereby revenues are recognized when earned, and expenses are recognized when incurred. These condensed consolidated financial statements as of September 30, 2011 and for the three and nine months ended September 30, 2011 and 2010 are unaudited. In the opinion of management, such financial statements include the adjustments and accruals, all of which are of a normal recurring nature, which are necessary for a fair presentation of the results for the interim periods. These interim results are not necessarily indicative of results for a full year.

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.

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

The Company sells its oil and natural gas production to purchasers generally on an unsecured basis. Allowances for doubtful accounts are determined based on management's assessment of the creditworthiness of the purchaser. 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 September 30, 2011 and December 31, 2010. 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 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 September 30, 2011 and December 31, 2010 were $48,658,531 and $9,954,354, respectively.  The unproved properties balance at September 31, 2011 consisted of approximately $24,450,000 of drilling in progress on unproved wells and approximately $24,208,000 of unproved leasehold costs.  The unproved properties balance at December 31, 2010 consisted of approximately $1,432,000 of drilling in progress on unproved wells and approximately $8,523,000 of unproved leasehold costs.

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 nine months ended September 30, 2011 and 2010, the Company recorded impairment of $-0- and $46,553, 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.

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 September 30, 2011 and December 31, 2010, 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 $677,803. The capitalized costs will be amortized over the term of the facility. The amortization for the three months ended September 30, 2011 was $6,226.

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 three and nine months ended September 30, 2011 and 2010, was approximately $-0-, $36,129, $93,060 and $384,342, 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 nine months ended September 30, 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.

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 three and nine months ended September 30, 2011 and 2010 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. 

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).

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 three and nine months ended September 30, 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 $188,144 and $591,269 for the three and nine months ended September 30, 2011, respectively, and $201,563 and $369,531 related to the amortization of these shares during the three and nine months ended September 30, 2010. 

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 September 30, 2011.  The officers of the Company have remitted to the Company 206,762 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 September 30, 2011.  The Company is working with its tax advisors to remit the appropriate tax to the IRS in the fourth quarter.  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, 2011.  This amount is included in general and administrative expenses for the nine months ended September 30, 2011 and in accrued withholding taxes as of September 30, 2011.

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 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) a 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.

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; 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 $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 will be 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 are required to pay in common stock 1% of the aggregate purchase price. Shares to be distributed are 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.  As of September 30, 2011, total shares to be given relating to the February 1, 2011 and March 31, 2011 placements are approximately 264,116 and 183,658, 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 three and nine months ended September 30, 2011, the Company accrued $572,365 and $1,980,438 of delinquent registration fees 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 have vested as of September 30, 2011 and 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 three months ended September 30, 2011 and 2010, the Company recorded non-cash stock compensation expense of $197,434 in each period. For the nine months ended September 30, 2011 and 2010, the Company recorded non-cash stock compensation expense of $592,302 and $361,962, 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.

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 nine months ended September 30, 2011 and 2010, the Company recorded non-cash stock compensation expense of $5,873,153 and $2,976,069, respectively, related to other share based compensation which is included in general and administrative expenses. For the three months ended September 30, 2011 and 2010, the Company recorded non-cash stock compensation expense of $2,511,926 and $109,671 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 September 30, 2011, as well as activity during the nine months then ended:

	Options Available for Grant						Weighted Average Exercise
	Under 2010 Plan			Outstanding Options			Price
Balance at December 31, 2010		2,275,000			3,725,000			1.60
Additional options authorized under amended plan		6,000,000			-			-
Granted		(7,540,000	)		7,540,000			7.46
Forfeited		-			(520,000	)		6.08
Balance at September 30, 2011		735,000			10,745,000			5.50

The options outstanding as of September 30, 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
$1.50 - $3.00		3,605,000		1.61		8.82		1,610,000	$	1.57
$7.00 - $8.00		7,140,000		7.46		9.76		1,190,000		7.48
		10,745,000		5.50		9.45		2,800,000		4.08

The aggregate intrinsic value of options outstanding and options exercisable was $11,327,500 and $7,003,900, respectively, at September 30, 2011.

The following table presents the future non-cash stock compensation expense for the Company’s outstanding restricted stock grants and stock options at September 30, 2011, which it expects to recognize during the vesting periods ending December 31:

2011	$	3,262,520
2012		10,688,961
2013		9,462,065
2014		8,646,931
2015		2,352,000
Total	$	34,412,477

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 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 nine months ended September 30, 2011 was $37,534,600.

14

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, 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 loan agreement, the Borrower needs to be in compliance with several debt covenants, including interest coverage ratio, current ratio, and leverage ratio.  The Company was in compliance with its application debt covenants at September 30, 2011.

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.  This is a non-cash liability which is expected to amortize over the term of the credit facility. The outstanding amount on the revolving credit facility at September 30, 2011 was $12 million.  The accretion of interest expense on the debt discount as of September 30, 2011 was $101,092 and accordingly, the September 30, 2011 debt balance net of the discount was $1,183,111. 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 September 30, 2011:

Debt proceeds	$	12,000,000
Debt discount		(10,816,889	)
Net revolving facility	$	1,183,111

The term loan draws are subject to approval by the bank on a case by case basis. Each drilling program is submitted for bank approval and the bank will approve the program and advance funds for development. 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 zero at September 30, 2011.

In connection with the Credit Agreement, the Company issued to Macquarie Americas Corp. a five year warrant to purchase five million (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 G for discussion of the subsequent valuation of the warrants.

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 nine months ended September 30, 2011 and the year ended December 31, 2010 is as follows:

	2011			2010
Balance at beginning of period	$	242,632		$	237,378
Liabilities incurred from new wells		36,346			12,273
Accretion expense		11,713			15,607
Revisions due to increase in well life estimates		(16,562	)		(22,626	)
Balance at end of period	$	274,129		$	242,632

15

Note F. 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 September 30, 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 81,965 Bbls of anticipated crude oil production and 734,519 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 $152,150 and $-0- at September 30, 2011, and December 31, 2010, respectively.

The Company recognizes all gains and losses from changes in commodity derivative fair values immediately in earnings. As of September 30, 2011, the Company had a realized gain on commodity derivatives of $17,279 and an unrealized loss of $152,150 included in other income (expense).

A summary of our commodity derivatives at September 30, 2011 is as follows:

Period of time	Barrels of Oil		Weighted Average Oil Prices		Estimated Fair Market Value
October 1, 2011 through October 31, 2014		81,965	$	81.7	$	(35,290	)
Period of time	MMBtu of Natural Gas		Weighted Average Gas Prices		Estimated Fair Market Value
September 28, 2011 through September 26, 2014		734,519	$	4.4	$	(116,860	)
Total fair market value					$	(152,150	)

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

	As of September 30, 2011
	Derivative Assets			Derivative Liabilities
	Balance Sheet			Balance Sheet
	Classification	Fair Value		Classification	Fair Value
Commodity Contracts	Current Assets	$	134,548	Current Liabilities	$	-
Commodity Contracts	Noncurrent Assets		-	Noncurrent Liabilities		(286,698	)
Total commodity derivatives		$	134,548		$	(286,698	)

16

The following table summarizes the unrealized and realized gain and loss from derivative cash settlements and changes in fair value of derivative contracts as presented in the accompanying statements of operations.

	For the Three			For the Nine
	Months Ended			Months Ended
	September 30, 2011			September 30, 2011
Cash settlement gain:
Oil  and natural gas contracts	$	17,279		$	17,279
Total cash settlement gain		17,279			17,279
Unrealized loss on changes in fair value:
Oil  and natural gas contracts		(152,150	)		(152,150	)
Total net unrealized loss on change in fair value		(152,150	)		(152,150	)
Total unrealized and realized derivative loss	$	(134,871	)	$	(134,871	)

Note G.    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, 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.

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 three and nine months ended September 30, the fair value of the liability of the warrant derivative instruments decreased by $1,294,037, from their initial fair values. Such changes were recorded as unrealized gains on fair value of derivative warrant instruments in the accompanying consolidated statements of operations.

Activity for derivative warrant instruments during the nine months ended September 30, 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  September 30, 2011
Derivative warrant instruments for Series A and Series B Warrants	$	3,971,009	$	-	$	373,996		$	4,345,005
Derivative warrant instruments for Macquarie warrants		-		10,917,981		(1,668,033	)		9,249,948
	$	3,971,009	$	10,917,981	$	(1,294,037	)	$	13,594,953

17

The fair value of the derivative warrant instruments is estimated using a probability-weighted scenario analysis model with the following assumptions as of September 30, 2011:

	September 30, 2011
Common stock issuable upon exercise of warrants		6,130,435
Estimated market value of common stock on measurement date	$	4.75	(1)
Exercise price	$	$7.50 - $9.00
Expected volatility (2)		66.1% - 73.6	%
Expected term (in months)		8.3 - 60
Risk-free rate (3)		0.06% - 0.96	%
Expected dividend yields		-

(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 H.    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 September 30, 2011:

	Level 1		Level 2		Level 3
Assets:
Commodity Derivatives	$	-	$	134,548	$	-
Liabilities:
Commodity Derivatives	$	-	$	286,698	$	-
Warrant derivatives	$	-	$	-	$	13,594,953

The Company uses Level 2 inputs to measure the fair value 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.

18

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

	For the Three Months					For the Nine Months
	Ended September 30,					Ended September 30,
	2011			2010		2011			2010
Beginning balance	$	-		$	-	$	-		$	-
Additions		(14,888,990	)		-		(14,888,990	)		-
Net decrease in liabilities		1,294,037			-		1,294,037			-
Transfers in (out) of Level 3		-			-		-			-
Ending balance	$	(13,594,953	)	$	-	$	(13,594,953	)	$	-

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 September 30, 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 nine months ended September 30, 2011 and 2010, the Company recorded impairments of $-0- and $46,553.

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 September 30, 2011 and December 31, 2010.

Acquisitions.   Assets acquisitions are recorded at fair value.  The Company closed an asset acquisition on August 22, 2011, which was recorded at fair value as described in Note J.

Note I.  Major Customers

The Company's producing oil and natural gas properties are located in Texas, New Mexico, Arkansas, Oklahoma and North Dakota.  At September 30, 2011, the Company contracts with a number of various operators and notes that there are two operators in which revenues received were greater than 10% of total revenues.  Revenue from XOG is approximately 56% in 2011 and revenue from Clark is approximately 10% but is still passing through XOG until updated ownership documentation is complete with the operator.  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. In 2010, a significant portion of the Company’s oil production was sold primarily to one oil purchaser.  Similarly, a significant portion of the Company’s natural gas was sold to one gas purchaser. 

19

Note J.  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.

Additionally, at September 30, 2011, the Company has a $1.5 million deposit relating to property being evaluated for potential acquisition.

Note K.  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 three months ended September 30, 2011, sales through XOG were $1,744,009 and lease operating expenses were $336,338.  For the nine months ended September 30, 2011, sales through XOG were $6,583,498 and lease operating expenses were $1,022,401.

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 J.

Note L.  Commitments and Contingencies

Employment Agreements.  At September 30, 2011, the Company’s cash contractual obligations related to its employment agreements with executive officers for the three months ended December 31, 2011 and each of the following five years ending December 31 and thereafter are as follows:

2011	$	161,333
2012		662,000
2013		662,000
2014		220,667
Total	$	1,706,000

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 nine months ended September 30, 2011 and 2010, the Company recorded lease expense of $65,392 and $-0-, respectively.

At September 30, 2011, the future minimum lease commitments under the non-cancellable operating leases for the three months ended December 31, 2011 and each of the following four years ending December 31 and thereafter are as follows:

2011	$	20,654
2012		90,518
2013		97,356
2014		99,402
2015		101,448
Thereafter		42,625
Total	$	452,003

Drilling Commitments. At September 30, 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 $3,817,000.

20

Note M.  Subsequent Events

None.

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Cautionary Note Regarding Forward-Looking Statements

This report contains “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995, Section 27A of the Securities Act of 1933, as amended, (the “Securities Act”) and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”).  Forward-looking statements discuss matters that are not historical facts.Because they discuss future events or conditions, forward-looking statements may include words such as “believe,” “intend,” “could,” “should,” “would,” “may,” “seek,” “might,” “will,” “potential,” “expect,” “anticipate,” “project,” “estimate,” “predict,” “plan” and similar expressions, or the negative thereof.  In particular, statements, expressed or implied, concerning future operating results, the ability to replace or increase reserves, or to increase production, or the ability to generate income or cash flows are by nature, forward-looking statements.  These statements are based on certain assumptions and analyses made by the management of the Company in light of its experience and its perception of historical trends, current conditions and expected future developments as well as other factors it believes are appropriate in the circumstances.  However, forward-looking statements are not guarantees of performance and no assurance can be given that these expectations will be achieved.

Important factors that could cause actual results to differ materially from the expectations reflected in the forward-looking statements include, but are not limited to, any of the following:  market conditions, uncertainties inherent in oil and gas production operations and estimating reserves, unexpected future capital expenditures, the timing and extent of changes in commodity prices for crude oil, natural gas and related products,  interest rates, inflation, the availability of goods and services, drilling and other operational risks, availability of capital resources, success of our operational risk management activities, governmental relations, legislative or regulatory changes, political developments, acts of war and terrorism.  A more detailed discussion on risks relating to the oil and natural gas industry and to us is included in our Annual Report on Form 10-K for the year ended December 31, 2010 filed with the Securities and Exchange Commission (the “Commission”) on March 8, 2011, as amended by Amendment No. 1 to Form 10-K filed by the Company with the Commission on March 22, 2011.

In light of these risks, uncertainties and assumptions, we caution the reader that these forward-looking statements are subject to risks and uncertainties, many of which are beyond our control, which could cause actual events or results to differ materially from those expressed or implied by the statements.  All subsequent written and oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by the cautionary statements.  We undertake no obligations to update or revise our forward-looking statements, whether as a result of new information, future events or otherwise.

Overview

We are an independent, non-operator oil and natural gas company engaged in the acquisition of oil and natural gas leasehold properties.  We hold leasehold acreage positions in, are actively contracting with third-party operators to drill our majority leasehold acreage and are participating in drilling activities by third-party operators on our minority interest leasehold acreage for potential petroleum development. Our leaseholds are located in the Permian Basin of West Texas, referred to herein as the Permian Basin, the Eagle Ford Shale Formation of South Texas, referred to herein as Eagle Ford, and the Bakken Shale Formation in North Dakota, referred to herein as Bakken.  Our third-party operating partners are applying vertical and horizontal drilling, advanced fracture stimulation and enhanced recovery technologies for potential petroleum development.

We do not seek to operate the wells in which we own an interest; instead, we seek to partner with experienced operators that are familiar with the respective geological formations in which we own mineral interests. By partnering with established operators, we believe we are able to more effectively manage the cost of operations and maintain a lean cost model.

21

Recent Events

July 15, 2011 Private Placement - On July 15, 2011, the Company closed a private placement offering raising proceeds of $13,000,002 through the issuance of (i) 2,260,870 shares of common stock at a price of $5.75 per share and (ii) a five-year warrants exercisable into 1,130,435 Series A warrants with and exercise price of $9.00, 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. 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 $1.018 million in connection with this offering. The initial value of these warrants was  $3,971,009 which were recorded as a liability and netted against the proceeds of the transaction through additional paid-in capital.

August Asset Acquisition - 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 $13.5 million 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 it was not under common control at the time of the asset acquisition.

September 21, 2011 Credit Facility - On September 21, 2011, the Company entered into the Credit Agreement with the lenders party thereto and Macquarie 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 for the revolving credit facility is September 21, 2014 and the term loan is September 21, 2015.

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 Company guaranteed the Borrower’s obligations under the Credit Agreement and pledged to the administrative agent a security interest in the 100% of the capital stock of the Borrower as security for the Company’s obligations under the guaranty.

In connection with the Credit Agreement, the Company issued to Macquarie Americas Corp. a five year warrant to purchase five million (5,000,000) shares of the Company’s 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.

22

Year-to-year or other periodic comparisons of the results of our operations can be difficult and may not fully and accurately describe our condition. The following table shows selected operating data for each of the three and nine months ended September 30, 2011 and 2010.

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
Production volumes:
Oil (Bbls)		20,649			15,666			71,995			42,521
Natural Gas (Mcf)		183,356			104,582			416,630			424,494
BOE (1)		51,208			33,096			141,433			113,270
BOE per day		557			360			518			415
Sales Prices
Oil (per Bbl)	$	104.02		$	74.92		$	87.88		$	73.10
Natural Gas (per Mcf)	$	4.62		$	5.87		$	5.37		$	4.86
BOE Price	$	58.49		$	54.01		$	60.57		$	45.65
Operating Revenues
Oil	$	2,147,933		$	1,173,708		$	6,326,794		$	3,108,456
Natural Gas		847,354			613,863			2,239,349			2,061,853
	$	2,995,287		$	1,787,571		$	8,566,143		$	5,170,309
Operating Expenses
Oil and natural gas production costs	$	663,367		$	471,940		$	1,759,918		$	1,402,730
Exploration expense		-			-			-			247,463
General and administrative		4,533,808			989,045			12,053,093			4,507,190
Impairment of oil and natural gas properties		-			46,553			-			46,553
Depreciation, depletion and amortization		679,417			344,150			2,251,704			1,130,533
Accretion of discount on asset retirement obligations		5,063			3,705			11,713			11,877
	$	5,881,655		$	1,855,393		$	16,076,428		$	7,346,346
Operating loss	$	(2,886,368	)	$	(67,822	)	$	(7,510,285	)	$	(2,176,037	)

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

Results of operations

For the Three Months Ended September 30, 2011 and 2010

Our oil and natural gas revenues and production product mix are displayed in the following table for the Current and Comparable Quarters.

	Revenues						Production
	2011			2010			2011			2010
Oil		72	%		66	%		40	%		47	%
Natural Gas		28	%		34	%		60	%		53	%
Total		100	%		100	%		100	%		100	%

23

The following table shows our production volumes, product sales prices and operating revenue for the indicated periods.

	Three Months Ended September 30,				Increase			% Increase
	2011		2010		(Decrease)			(Decrease)
Production volumes:
Oil (Bbls)		20,649		15,666		4,983			32	%
Natural Gas (Mcf)		183,356		104,582		78,774			75	%
BOE (1)		51,208		33,096		18,112			55	%
BOE per day		557		360		197			55	%
Sales Prices
Oil (per Bbl)	$	104.02	$	74.92	$	29.10			39	%
Natural Gas (per Mcf)	$	4.62	$	5.87	$	(1.25	)		-21	%
BOE Price	$	58.49	$	54.01	$	4.48			8	%
Operating Revenues
Oil	$	2,147,933	$	1,173,708	$	974,225			83	%
Natural Gas		847,354		613,863		233,491			38	%
	$	2,995,287	$	1,787,571	$	1,207,716			68	%

Oil revenues     Our oil revenues were $2,147,933 for the three months ended September 30, 2011, an increase of $974,225 (83%) from $1,173,708 for the three months ended September 30, 2010. Higher average oil sales prices increased revenues approximately $456,000 while increased production volumes increased revenues by approximately $518,000.  The increase in production volumes was primarily due to new well development primarily in the Bakken.

Natural gas revenues     Our natural gas revenues were $847,354 for the three months ended September 30, 2011, an increase of $233,491 (38%) from $613,863 for the three months ended September 30, 2010. Increased natural gas production volumes increased revenues by approximately $364,000 while slightly lower average natural gas sales prices decreased revenues by approximately $131,000.

	2011			2010			(Decrease)			(Decrease)
Operating Expenses
Oil and natural gas production costs	$	663,367		$	471,940		$	191,427			41	%
Exploration expense		-			-			-			-
General and administrative		4,533,808			989,045			3,544,763			358	%
Depreciation, depletion and amortization		679,417			344,150			335,267			97	%
Impairment of oil and natural gas properties		-			46,553			(46,553	)		-100	%
Accretion of discount on asset retirement obligations		5,063			3,705			1,358			37	%
	$	5,881,655		$	1,855,393		$	4,026,262			217	%
Operating loss	$	(2,886,368	)	$	(67,822	)	$	(2,818,546	)		4156	%

Oil and natural gas production expenses.   Production expenses for the three months ended September 30, 2011 increased $191,427 (41%) to $663,367, compared to $471,940 for the three months ended September 30, 2010. The increase in lease operating expenses was primarily due to an increase in production taxes caused by increased revenues offset by slightly lower lease operating expenses due to less rework than in the previous period.

General and administrative expenses.   General and administrative (“G&A”) expenses were $4,533,808 for the three months ended September 30, 2011, an increase of $3,544,763 (358%) from $989,045 for the three months ended September 30, 2010. The primary factor for the increase in G&A expenses was the recognition of $572,266 in non-cash penalties related to the delayed registration of the February 1, 2011 and March 31, 2011 equity private placements and a $2,389,000 increase in non-cash stock compensation expense. We expect an increase in the non-cash stock compensation in future periods.  Additionally, there have been increased transactional costs such as legal and professional fees due to acquisitions and the S-1 registration filing.

24

Depreciation, depletion and amortization expense.   Depreciation, depletion and amortization (“DD&A”) expense of proved oil and natural gas properties was $679,417 for the three months ended September 30, 2011, an increase of $335,267 (97%) from $344,150 for the three months ended September 30, 2010. The increase in depletion expense was primarily due to an increase in production volumes and wells coming into production.  DD&A per BOE increased 196% for the three months ended September 30, 2011.  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. With the increased development and productivity in unconventional drilling in the Bakken and Eagleford, DD&A per BOE is expected to be higher than historical DD&A per BOE for the traditional Permian Basin producing assets.

Other income, net.   Other income increased to $1,047,266 for the three months ended September 30, 2011 from $-0- at September 30, 2010.  The increase was due to the unrealized gain on warrant derivatives of $1,294,037 relating primarily to the Macquarie warrants and marking them to market and $17,279 realized gain on commodity derivatives.  The increase was partially offset by interest expense for accretion of the debt discount of $101,092, interest expense of $10,808 and unrealized loss on commodity derivatives of $152,150.

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 three months ended September 30, 2011 and September 30, 2010 was $0 due to net operating losses and a related valuation allowance.

For the Nine Months Ended September 30, 2011 and 2010

Our oil and natural gas revenues and production product mix are displayed in the following table for the Current Period and Comparable Period.

	Revenues						Production
	2011			2010			2011			2010
Oil		74	%		60	%		51	%		38	%
Natural Gas		26	%		40	%		49	%		62	%
Total		100	%		100	%		100	%		100	%

The following table shows our production volumes, product sales prices and operating revenue for the indicated periods.

	Nine Months Ended September 30,				Increase			% Increase
	2011		2010		(Decrease)			(Decrease)
Production volumes:
Oil (Bbls)		71,995		42,521		29,474			69	%
Natural Gas (Mcf)		416,630		424,494		(7,864	)		-2	%
BOE (1)		141,433		113,270		28,163			25	%
BOE per day		518		415		103			25	%
Sales Prices
Oil (per Bbl)	$	87.88	$	73.10	$	14.78			20	%
Natural Gas (per Mcf)	$	5.37	$	4.86	$	0.51			10	%
BOE Price	$	60.57	$	45.65	$	14.92			33	%
Operating Revenues
Oil	$	6,326,794	$	3,108,456	$	3,218,338			104	%
Natural Gas		2,239,349		2,061,853		177,496			9	%
	$	8,566,143	$	5,170,309	$	3,395,834			66	%

Oil revenues.  Our oil revenues were $6,326,794 for the nine months ended September 30, 2011, an increase of $3,218,338 (104%) from $3,108,456 for the nine months ended September 30, 2010. Higher average oil sales prices increased revenues approximately $628,000 while increased production volumes increased revenues by approximately $2,590,000.  The increases in production volumes were due primarily to new well development primarily in the Bakken.

Natural gas revenues. Our natural gas revenues were $2,239,349 for the nine months ended September 30, 2011, an increase of $177,496 (9%) from $2,061,853 for the nine months ended September 30, 2010. Higher average natural gas sales prices increased revenues approximately $220,000 while decreased production volumes decreased revenues by approximately $43,000.  The lower production was due to depletion of existing long lived wells.

25

	Nine Months Ended September 30,						Increase			% Increase
	2011			2010			(Decrease)			(Decrease)
Operating Expenses
Oil and natural gas production costs	$	1,759,918		$	1,402,730		$	357,188			25	%
Exploration expense		-			247,463			(247,463	)		-100	%
General and administrative		12,053,093			4,507,190			7,545,903			167	%
Depreciation, depletion and amortization		2,251,704			1,130,533			1,121,171			99	%
Impairment of oil and natural gas properties		-			46,553			(46,553	)		-100	%
Accretion of discount on asset retirement obligations		11,713			11,877			(164	)		-1	%
	$	16,076,428		$	7,346,346		$	8,730,082			119	%
Operating loss	$	(7,510,285	)	$	(2,176,037	)	$	(5,334,248	)		245	%

Oil and natural gas production expenses.   Production expenses for the nine months ended September 30, 2011 increased $357,188 (25%) to $1,759,918, compared to $1,402,730 for the nine months ended September 30, 2010. The increase is due 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.

General and administrative expenses.   General and administrative (“G&A”) expenses were $12,053,093 for the nine months ended September 30, 2011, an increase of $7,545,903 (167%) from $4,507,190 for the nine months ended September 30, 2010. The primary factor for the increase in G&A expenses was the recognition of $1,980,438 in non-cash penalties related to the delayed registration of the February 1, 2011 and March 31, 2011 equity private placements an increase in non-cash stock compensation expense of $3,349,162. 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.

Exploration expenses.  Exploratory expenses during the nine months ended September 30, 2011 were $0, compared to $247,463 for the nine months ended September 30, 2010.  This expense was primarily attributable to an unsuccessful exploratory well located in the Eagle Ford shale formation play 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.

Depreciation, depletion and amortization expense.   Depreciation, depletion and amortization (“DD&A”) expense of proved oil and natural gas properties was $2,251,704 for the nine months ended September 30, 2011, an increase of $1,121,171 (99%) from $1,130,533 for the nine months ended September 30, 2010. The increase in depletion expense was primarily due to an increase in production volumes in the Bakken that has a higher depreciation and depletion rate and new wells beginning to produce during the period.  DD&A per BOE increased 114% for the nine months ended September 30, 2011. 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. With the increased development and productivity in unconventional drilling in the Bakken and Eagleford, DD&A per BOE is expected to be higher than historical DD&A per BOE for the traditional Permian Basin producing assets.

Other income, net.   Other income increased to $1,047,266 for the nine months ended September 30, 2011 from $-0- at September 30, 2010.  The increase was to the unrealized gain on warrant derivatives of $1,294,037 relating to the Macquarie warrants and marking them to market and $17,279 realized gain on the commodity derivatives.  The increase was offset by interest expense for accretion of the debt discount of $101,092, interest expense of $10,808 and unrealized loss on commodity derivatives of $152,150.

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 nine months ended September 30, 2011, and September 30, 2010 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.

26

Oil and natural gas properties.Cash paid for oil and natural gas properties during the nine months ended September 30, 2011 and 2010 totaled $41,777,541 and $9,903,947, respectively. The 2011 costs related primarily to purchases of additional Bakken leases and drilling in the Bakken, Permian and South Texas leases.  The 2010 costs related primarily to purchases of Bakken undeveloped leases, the drilling of four Bakken wells, and the drilling of one South Texas well.

Our 2011 capital budget is approximately $100 million assuming additional financing is made available under our existing facility or new financing obtained. We expect to be able to fund our remaining 2011 capital budget partially with operating cash flows, stock used as consideration 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 its capital spending program to remain substantially within the Company’s operating cash flows.

We will actively seek to acquire oil and natural gas properties that provide opportunities for the addition of new reserves and production in both its core areas of operation and in emerging plays throughout the United States.

While we believe that our available cash, cash flows and credit facility will fund its 2011 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 2011 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 the first nine months of 2011 were cash flows generated from proceeds from our private placement offerings of its common stock and proceeds from stock subscription receivables from which cash net proceeds of $47,892,172 were generated.  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 2011 capital expenditure plans.

Cash flow from operating activities.Our net cash provided by operating activities were $490,751 and $3,998,550 for the nine months ended September 30, 2011 and 2010, respectively. The decrease in operating cash flow for the nine months ended September 30, 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 repayment of accounts payable and accrued liabilities.

Cash flow used in investing activities.  During the nine months ended September 30, 2011 and 2010, we invested $41,777,541 and $9,903,947, 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 due to the Company’s increased leasehold acquisition activities in the Bakken Shale Formation, Eagle Ford and Permian drilling activities, along with a $1.5 million deposit with the XOG Group relating to property being evaluated.

Cash flow from financing activities.  Net cash provided by financing activities was $49,480,870 and $6,064,569 for the nine months ended September 30, 2011 and 2010, 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 nine months ended September 30, 2011.

February Private Placement. On February 1, 2011, we closed on a private placement offering 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) 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 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.   At March 31, 2011, we closed a private placement offering 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) a 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.

27

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 “down round” 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 (the “Eligibility Date”) is less than the purchase price in the offering or $5.75; and (B) upon certain dilutive occurrences.

If 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).

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.

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, we 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’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 the 100% of the capital stock of the Borrower as security our obligations under the guaranty.

In connection with the Credit Agreement, we issued to Macquarie Americas Corp. 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.

Liquidity.  Our principal sources of short-term liquidity are cash on hand and operational cash flow.  At September 30, 2011, we had cash and cash equivalents of $7,214,076.

28

Contractual Obligations

Employment Agreements. At September 30, 2011, our contractual obligations include employment agreements with executive officers for the 3 months ended December 31, 2011 and the years ending December 31, 2012 through 2014 are as follows:

	2011		2012		2013		2014
Scott Feldhacker	$	57,750	$	231,000	$	231,000	$	77,000
Richard Macqueen		57,750		231,000		231,000		77,000
Scott Mahoney		45,833		200,000		200,000		66,667
Total Contractual Obligations Related to Employment Contracts	$	161,333	$	662,000	$	662,000	$	220,667

Operating Leases.  We lease our 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 $0.50 per square foot annually thereafter.  For the nine months ended September 30, 2011, the Company recorded lease expense of $65,392.

At September 30, 2011, the future minimum lease commitments under the non-cancellable operating leases for the three months ended December 31, 2011 and each of the following four years ending December 31 and thereafter are as follows:

2011	$	20,654
2012		90,518
2013		97,356
2014		99,402
2015		101,448
Thereafter		42,625
Total	$	452,003

Item 3. Quantitative and Qualitative Disclosures About Market Risk

As we expand, we 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, including the use of derivative instruments including hedging contracts. Such contracts may involve incurring future gains or losses from changes in commodity prices or fluctuations in market interest rates.

Credit Risk.   We monitor our 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.  We monitor our exposure to these counterparties primarily by reviewing credit ratings, financial statements, production, sales, marketing, engineering and reserve reports.

Commodity Price Risk.   We are 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 we may in the future enter into commodity price risk management arrangements for a portion of its oil and natural gas production. The price we receive for our crude oil and natural gas production materially influences our revenue, profitability, access to capital and future rate of growth. Crude oil and natural gas are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for crude oil and natural gas have been volatile, and our management believes these markets will likely continue to be volatile in the future. The prices we receive for our production depend on numerous factors beyond our control. Our revenue during 2010 and the first three quarters of 2011 generally would have increased or decreased along with any increases or decreases in crude oil or natural gas prices, but the exact impact on our income is indeterminable given the variety of expenses associated with producing and selling crude oil that also increase and decrease along with crude oil prices. 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 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).

Interest Rate Risk.   Changes in interest rates can affect the amount of interest we pay on borrowings under our revolving credit facility and term loan.

29

Item 4. Controls and Procedures

(a) Evaluation of Disclosure Controls and Procedures

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.

Management has concluded there are material weaknesses in both the design and operation of the Company’s internal controls and procedures for financial reporting.  A material weakness, as designed by SEC rules, is a control deficiency, or combination of control deficiencies, such that there is a reasonable possibility that a material misstatement of the annual or interim financial statements will not be prevented or detected on a timely basis. Our management has identified the material weaknesses described below.

At September 30, 2011, the Company had limited internal accounting staff and relied on external contract accountants to assist in financial statement preparation and reconciliation.   The Company’s historical operations have been derived on a carve-out basis from the books and records of related party entities that have not been previously audited.  The Company is in the process of incorporating the historical supporting records and documentation from XOG into the Company’s core financial records and documentation.

(b) Changes in Internal Control over Financial Reporting

During the quarter ended September 30, 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 is in the process of implementing 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 is currently in the process of incorporating the historic financial transactions of XOG Group related to these properties into the new system.  Management has also engaged a regional consulting firm in Midland, Texas to assist in the data transfer and supporting records for acquisitions made by the Company in the first quarter of 2011.

Documentation of Internal Control Systems. The Company is in the process of documenting all initial internal control systems and the Company is in the process of defining it plans to be fully compliant with SEC Rule 1-02 (4).  Management identified and a subsequent to the quarter close, engaged a public accounting firm to assist the Company to meet the SEC’s requirements for internal controls.

30

PART II – Other Information

Item 1A. Risk Factors

An investment in our securities involves a high degree of risk. You should carefully consider the risks described below together with all of the other information included in this filing 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

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

Our wholly-owned subsidiary, Nevada ASEC, was incorporated on April 2, 2010 and was initially funded by its founders, officers and accredited outside investors. Accordingly, Nevada ASEC has 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.

31

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.

32

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 are in the early stages of the acquisition of our portfolio of leaseholds and other natural resource holdings. We will 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 the Company’s Chief Executive Officer, Scott Feldhacker.

THE COMPANY’S LACK OF DIVERSIFICATION WILL INCREASE THE RISK OF AN INVESTMENT IN THE COMPANY, AND THE COMPANY’S FINANCIAL CONDITION AND RESULTS OF OPERATIONS MAY DETERIORATE IF THE COMPANY FAILS TO DIVERSIFY.

Our business focus is on the oil and gas industry and initially, our interest will be in a limited number of properties in the Bakken, Eagle Ford and Permian Basin regions. 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.

\

THE COMPANY MAY BE UNABLE TO OBTAIN ADDITIONAL CAPITAL REQUIRED TO IMPLEMENT ITS BUSINESS PLAN, WHICH COULD RESTRICT THE COMPANY’S ABILITY TO GROW.

We expect to be able to fund our 2011 capital budget partially with operating cash flows, in conjunction with additional stock offerings and our credit facility entered into on September 21, 2011. We will require additional capital to continue to grow our business via the drilling program 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. The Company 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 the Company’s planned expansion of operations in 2011 or thereafter.

33

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 the Company’s 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 the Company) 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 the Company’s 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 THE COMPANY MAY RELY ARE SUBJECT TO CHANGE, WHICH MAY DIMINISH THE COMPANY’S ABILITY TO CONDUCT ITS OPERATIONS.

Our ability to acquire additional leaseholds successfully, to increase our oil and natural gas reserves, to participate in drilling opportunities 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 Nevada ASEC’s 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 Nevada ASEC’s 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 Nevada ASEC’s strategic relationships are not established or maintained, the Company’s business prospects may be limited, which could diminish our ability to conduct our operations.

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

We have certain contemplated strategic vendor relationships that will be critical to our strategy. As a non-operator, we must actively secure the services of drilling companies, hydrofracing 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.

34

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.

THE COMPANY IS 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 LARGEST HOLDER 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 November 9, 2011, beneficially owns 19,475,474 shares of common stock or 49% 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.

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.

THE COMPANY NEEDS TO CONTINUE TO DEVELOP AND MAINTAIN A DIVERSE PORTFOLIO OF LEASEHOLDS AND PRODUCING PROPERTIES, OTHERWISE THE COMPANY 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. The Company needs 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.

35

MARKET CONDITIONS OR TRANSPORTATION IMPEDIMENTS MAY HINDER ACCESS TO OIL AND NATURAL GAS MARKETS OR DELAY PRODUCTION.

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

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 resources, may be more successful in the recruitment and retention of qualified employees and may conduct their own refining and petroleum marketing operations, which may give them a competitive advantage. 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.

GOVERNMENT REGULATIONS AND LEGAL UNCERTAINTIES COULD 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.

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.

36

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. 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 gas by both refineries and end users;

· the actions of the Organization of Petroleum Exporting Countries;

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

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

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

· the level of global oil and gas inventories;

· weather conditions;

· technological advances affecting energy consumption;

· domestic and foreign governmental regulations;

· 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; and

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

Further, oil and natural gas prices do not necessarily fluctuate in direct relationship to each other. Because approximately 48.6% of our estimated proved reserves as of December 31, 2010 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 and resulted 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 $90 per Bbl in May 2011. Natural gas prices declined from over $13 per MMBtu (million British thermal units) in mid-2008 to approximately $4 per MMBtu in May 2011.

37

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, as well as special redeterminations.

TAXATION OF NATURAL RESOURCES COULD 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.

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 of drilling, completing and operating wells is often uncertain before drilling commences. Overruns in budgeted expenditures are common risks that can make a particular project uneconomical. Further, many factors may curtail, delay or cancel 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; and

· adverse weather conditions, such as freezing temperatures, hurricanes and storms.

38

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

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. Oil and gas exploration and development involves a high degree of risk. These risks are more acute in the early stages of exploration. Our ability to produce revenue and our resulting financial performance are significantly affected by the prices we receive for oil and natural gas produced from wells on our acreage. Especially in recent years, the prices at which oil and natural gas trade in the open market have experienced significant volatility and will likely continue to fluctuate in the foreseeable future due to a variety of influences including, but not limited to, the following:

· domestic and foreign demand for oil and natural gas by both refineries and end users;

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

· domestic and foreign reserves and supply of oil and natural gas;

· competitive measures implemented by competitors and domestic and foreign governmental bodies;

· political climates in nations that traditionally produce and export significant quantities of oil and natural gas and regulations and tariffs imposed by exporting and importing nations;

· weather conditions; and

· domestic and foreign economic volatility and stability.

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 the inherent uncertainties of drilling in less known formations, the costs associated with encountering various drilling conditions, such as over-pressured zones and lost equipment, and changes in drilling plans and locations as a result of prior exploratory wells or additional seismic data and interpretations thereof.

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.

39

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.

ESTIMATES OF OIL AND NATURAL GAS RESERVES THAT MAY BE INACCURATE AND ACTUAL REVENUES MAY BE LOWER THAN THE COMPANY’S FINANCIAL 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 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. 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. 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.

DRILLING NEW WELLS COULD RESULT IN NEW LIABILITIES, WHICH COULD ENDANGER THE COMPANY’S INTERESTS IN ITS PROPERTIES AND ASSETS.

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.

40

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

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

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

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

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

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.

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.

41

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. While the Company intends to make appropriate inquiries into the title of properties and other development rights 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. 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.

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.

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. If we are unable to maintain the efficacy of our technology, our ability to manage our business and to compete may be impaired. 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.

FEDERAL AND STATE LEGISLATION AND REGULATORY INITIATIVES RELATING TO HYDRAULIC FRACTURING COULD RESULT IN INCREASED COSTS AND ADDITIONAL OPERATING RESTRICTIONS OR DELAYS.

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, we are required to obtain permits from one or more governmental agencies in order to perform drilling and completion activities, including hydraulic fracturing. Such permits are typically required by state agencies, but can also be required by federal and local governmental agencies. 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.

42

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.

POSSIBLE REGULATION RELATED TO GLOBAL WARMING AND CLIMATE CHANGE 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.

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.

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.

43

Risks Related to the Company’s Securities

UPON EFFECTIVENESS OF THE OUTSTANDING REGISTRATION STATEMENT, THERE WILL BE A SIGNIFICANT NUMBER OF SHARES OF OUR COMMON STOCK ELIGIBLE FOR SALE, WHICH MAY DEPRESS THE MARKET PRICE OF OUR COMMON STOCK.

Once the outstanding registration statement is declared effectively by the SEC, the shares of common stock registered thereunder will become available for sale in the public market, which could decrease the market price of our common stock in general. Further, some or all of our shares may be offered from time to time in the open market pursuant to Rule 144 promulgated under the Securities Act, and these sales may have a depressive effect on the market for our common stock. Sales undertaken pursuant to the effectiveness of the registration statement or Rule 144 could depress the market price of the shares.

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

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.

44

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.

45

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.

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. 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 2.  Unregistered Sales of Equity Securities and Use of Proceeds

The disclosure set forth in Item 5 of Part II of this Report is incorporated herein by reference.

Item 5.  Other Information

On November 7, 2011, the Company authorized the issuance of an aggregate of 459,078 shares (the “Shares”) of its common stock to the investors who purchased the Company’s securities in the Company’s private placement offerings that were concluded in February 2011 and March 2011.  The Shares were issued in satisfaction of liquidated damages payments that were due in connection with such purchasers’ registration rights with respect to such securities.  The Shares were issued in reliance upon Section 4(2) of the Securities Act.

In connection with the issuance of the Shares, the Company entered into waiver agreements (the “Waiver Agreements”) with each of the investors who purchased the Company’s securities pursuant to that certain Securities Purchase Agreement (the “Purchase Agreement”) dated July 11, 2011 by and among the Company and the investors named therein (the “July Purchasers”).  Pursuant to the Waiver Agreements, each of the July Purchasers waived certain antidilution and exercise price adjustment rights set forth in warrants issued to the July Purchasers pursuant to the Purchase Agreement and certain additional antidilution and participation rights set forth in the Purchase Agreement.

The foregoing description of the Waiver Agreements is qualified in its entirety by reference to the form of Waiver Agreement  filed herewith as Exhibit 10.36 and are incorporated herein by reference in its entirety.

46

Item 6.  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)
3.3	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)
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	Not used
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	Form of Waiver Agreement

47

31.1	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes - Oxley Act of 2002. (Filed herewith)
31.2	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes - Oxley Act of 2002. (Filed herewith)
32.1	Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes - Oxley Act of 2002. (Filed herewith)
32.2	Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes - Oxley Act of 2002. (Filed herewith)

101 .INS	XBRL Instance Document
101 .SCH	XBRL Taxonomy Schema
101 .CAL	XBRL Taxonomy Calculation Linkbase
101 .DEF	XBRL Definition Linkbase
101 .LAB	Taxonomy Label Linkbase
101 .PRE	XBRL Taxonomy Presentation Linkbase

(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.

48

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	AMERICAN STANDARD ENERGY CORP.
Date: November 14, 2011	By:	/s/ Scott Feldhacker
		Scott Feldhacker
		Chief Executive Officer and Director (Principal Executive Officer)
Date: November 14, 2011	By:	/s/ Scott Mahoney
		Scott Mahoney, CFA
		Chief Financial Officer (Principal Financial Officer)

49