XOTC:ASEN Quarterly Report 10-Q Filing - 6/30/2012

Effective Date 6/30/2012

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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: June 30, 2012

 

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   x   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   x
   
Non-accelerated filer   ¨ Smaller reporting company  ¨ 
(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 August 9, 2012, there were 50,921,798 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 22
     
Item 3. Quantitative and Qualitative Disclosures About Market Risk 29
     
Item 4. Controls and Procedures 30
     
  PART II-Other Information  
     
Item 1. Legal Proceedings 30
     
Item 1A. Risk Factors 30
     
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds 31
     
Item 6. Exhibits 32

 

 
 

 

PART I - FINANCIAL INFORMATION

 

Item 1. Financial Statements

 

American Standard Energy Corp. and Subsidiaries

Consolidated Balance Sheets

(Unaudited)

 

  June 30,    December 31, 
   2012   2011 
Current assets:          
Cash and cash equivalents  $671,624   $733,049 
Oil and natural gas sales receivables - related parties   1,810,253    1,556,414 
Oil and natural gas sales receivables   3,429,411    639,714 
Commodity derivatives   308,058    - 
Other current assets   22,406    308,208 
Total current assets   6,241,752    3,237,385 
           
Oil and natural gas properties at cost, successful efforts method          
Proved   103,130,318    76,919,789 
Unproved   87,040,155    25,212,635 
Accumulated depletion and depreciation   (17,292,893)   (14,310,006)
Total oil and natural gas properties, net   172,877,580    87,822,418 
           
Debt issuance costs, net of amortization of $378,492 and $69,184   1,764,850    720,175 
Prepaid drilling costs   1,151,916    2,590,356 
Commodity derivatives   92,897    - 
Deposit on properties with affiliate   -    1,500,000 
Other assets, net of accumulated depreciation of $10,630 and $7,380   21,153    24,403 
Total assets  $182,150,148   $95,894,737 
           
Current liabilities:          
Accounts payable - trade  $10,668,786   $3,373,262 
Accounts payable and accrued liabilities - related parties   2,874,895    8,574,017 
Accrued compensation expense and withholding taxes   3,135,413    1,338,308 
Commodity derivatives   -    243,996 
Other accrued liabilities   51,470    36,665 
Total current liabilities   16,730,564    13,566,248 
           
Term loan and revolving credit facility, net of discount of $8,554,960 and $9,907,057   13,572,796    7,262,832 
Pentwater note, net of discount of $4,212,726   15,931,010    - 
Asset retirement obligations   907,292    394,177 
Commodity derivatives   -    421,964 
Warrant derivative liabilities   586,431    15,298,658 
Total liabilities   47,728,093    36,943,879 
           
Commitments and contingencies          
           
Stockholders' equity          
Preferred stock, $.001 par value; 1,000,000 shares authorized; 34,500 issued
and outstanding
   35    - 
Common stock, $.001 par value; 100,000,000 shares authorized, 51,128,491
shares issued and 50,921,798 shares outstanding at June 30, 2012 and
40,178,060 shares issued and 39,971,367 shares outstanding at December 31, 2011
   51,128    40,178 
Additional paid-in capital   190,517,192    75,504,243 
Treasury stock, 206,693 shares at cost   (1,116,514)   (1,116,514)
Accumulated deficit   (55,029,786)   (15,477,049)
Total stockholders' equity   134,422,055    58,950,858 
           
Total liabilities and stockholders' equity  $182,150,148   $95,894,737 

 

3
 

 

American Standard Energy Corp. and Subsidiaries

Consolidated Statements of Operations

(Unaudited)

 

 Three Months Ended June 30,   Six Months Ended June 30, 
   2012   2011   2012   2011 
Operating revenues:                    
Oil and natural gas revenues  $7,008,257   $3,182,364   $12,103,075   $5,570,856 
Gain (loss) on sale of oil and natural gas leases   16,013    -    (94,930)   - 
    7,024,270    3,182,364    12,008,145    5,570,856 
Operating costs and expenses:                    
Oil and natural gas production costs   2,422,053    289,207    4,812,985    1,096,551 
General and administrative (including non-cash stock-based compensation of $0 and $3,594,499 for the three months ended June 30, 2012 and 2011 and $33,805,391 and $4,159,220 for the six months ended June 30, 2012 and 2011)   1,454,170    5,793,647    38,386,228    7,519,285 
Impairment of oil and natural gas properties   317,913    -    317,913    - 
Depreciation, depletion and amortization   1,381,494    963,097    2,668,225    1,572,287 
Accretion of discount on asset retirement obligations   7,927    2,485    14,825    6,650 
                     
Total operating costs and expenses   5,583,557    7,048,436    46,200,176    10,194,773 
                     
Income (loss) from operations   1,440,713    (3,866,072)   (34,192,031)   (4,623,917)
                     
Other income (expense), net:                    
Realized and unrealized gain on commodity derivatives   1,238,011    -    967,046    - 
Interest expense (including accretion of debt discount of $1,729,132 and $2,551,924 for the three and six months ended June 30, 2012)   (2,022,468)   -    (3,641,067)   - 
Realized and unrealized income (expense) on warrant derivatives   571,463    -    (2,686,685)   - 
Total other income (expense), net   (212,994)   -    (5,360,706)   - 
                     
Income (loss)  before income taxes   1,227,719    (3,866,072)   (39,552,737)   (4,623,917)
                     
Income tax benefit   -    -    -    - 
                     
Net income (loss)  $1,227,719   $(3,866,072)  $(39,552,737)  $(4,623,917)
                     
Weighted average common shares outstanding for basic   46,427,292    37,841,757    43,971,371    35,062,347 
Weighted average common shares outstanding for diluted   47,340,335    37,841,757    43,971,371    35,062,347 
Earnings (loss) per share - basic  $0.03   $(0.10)  $(0.90)  $(0.13)
Earnings (loss) per share - diluted  $0.03   $(0.10)  $(0.90)  $(0.13)

 

4
 

 

American Standard Energy Corp. and Subsidiaries

Consolidated Statements of Cash Flows

(Unaudited)

 

  Six Months Ended June 30, 
   2012   2011 
CASH FLOWS FROM OPERATING ACTIVITIES:          
Net loss  $(39,552,737)  $(4,623,917)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:          
Depreciation, depletion and amortization   2,668,225    1,572,287 
Accretion of debt discount   2,551,924    - 
Amortization of debt issue costs   309,309    - 
Unrealized gain on commodity derivative   (1,066,915)   - 
Unrealized income on warrant derivatives   (376,235)   - 
Interest capitalized to note balance   934,066    - 
Interest capitalized to oil and natural gas properties   (1,351,459)   - 
Accretion of asset retirement obligations   14,825    6,650 
Loss on sale of oil and natural gas leases   94,930    - 
Warrant modification consideration   3,062,920    - 
Stock-based compensation expense   33,805,391    4,159,219 
Common stock issued for services   229,000    - 
Impairment of oil and natural gas properties   317,913    - 
Accrual for stock penalties expense   -    1,408,072 
Changes in operating assets and liabilities:          
Oil and natural gas sales receivables   (3,043,536)   (3,749,565)
Other current assets   12,527    (981,861)
Accounts payable and accrued liabilities   4,332,410    (2,680,914)
           
Net cash provided by (used in) operating activities   2,942,558    (4,890,029)
           
CASH FLOWS FROM INVESTING ACTIVITIES:          
Oil and natural gas property additions   (24,985,590)   (7,748,057)
Prepaid drilling costs   (1,151,916)   - 
Proceeds from sale of oil and natural gas leases   629,639    - 
Deposit on properties with affiliate   -    (13,500,000)
Net cash used in investing activities   (25,507,867)   (21,248,057)
           
CASH FLOWS FROM FINANCING ACTIVITIES:          
Cash payment to Geronimo - deemed distribution   -    (10,000,000)
Proceeds from the sale of stock, net   -    34,352,471 
Proceeds from stock subscription receivable   -    1,557,698 
Proceeds from draws on term loan   3,857,867    - 
Proceeds from Pentwater note   20,000,000    - 
Debt issuance costs paid   (1,353,983)   - 
Net cash provided by financing activities   22,503,884    25,910,169 
Net decrease in cash and cash equivalents   (61,425)   (227,917)
Cash and cash equivalents at beginning of period   733,049    519,996 
Cash and cash equivalents at end of period  $671,624   $292,079 
           
Supplemental disclosure of cash flow information          
Cash paid during the period for interest  $1,226,711   $- 
           
NON-CASH INVESTING AND FINANCING ACTIVITIES:          
Accounts payable and accrued liabilities for oil and natural gas properties additions  $9,063,649   $- 
Reclassification of pre-paid drilling costs to oil and natural gas properties  $2,590,356   $- 
Additions and revisions to asset retirement cost and related obligation  $498,290   $51,750 
Issuance of Geronimo Note for purchase of oil and natural gas properties  $35,000,000   $- 
Reclassification of warrants' value previously recorded as a liability  $14,335,992   $- 
Discount on debt - Pentwater warrants  $5,412,553   $- 
Property acquired from Geronimo for shares of common stock  $13,500,000   $- 
Conversion of Geronimo Note to preferred stock with related party  $35,778,078   $- 
Stock issued for settlement of related party payables  $10,000,000   $- 
Deemed contribution for properties acquired  $-   $1,257,000 
Deemed distribution for working capital not acquired in property acquisitions  $-   $688,050 

  

5
 

 

American Standard Energy Corp. and Subsidiaries

Consolidated Statements of Stockholders' Equity

Six months ended June 30, 2012

(Unaudited) 

 

   Preferred Stock   Common Stock       Treasury Stock         
   Shares   Value   Shares   Value   Additional
paid-in
capital
   Shares   Value   Accumulated
(deficit)
   Total
stockholders'
equity
 
                                     
Balance at December 31, 2011   -   $-    40,178,060   $40,178   $75,504,243    (206,693)  $(1,116,514)  $(15,477,049)  $58,950,858 
                                              
Cashless exercise of warrants   -    -    1,325,986    1,326    (1,326)   -    -    -    - 
Shares issued in March 2012 for acquisition of properties from Geronimo recorded at fair value   -    -    5,000,000    5,000    13,495,000    -    -    -    13,500,000 
Series A preferred stock issued with Geronimo Note conversion   35,400    35    -    -    35,778,043    -    -    -    35,778,078 
Stock issued for settlement of related party payables   -    -    4,444,445    4,444    9,995,556    -    -    -    10,000,000 
Issuance of Restricted Stock   -    -    80,000    80    194,320    -    -    -    194,400 
Issued shares for consulting services   -    -    100,000    100    228,900    -    -    -    229,000 
Reclassification of warrants' value previously recorded as a liability   -    -    -    -    14,335,992    -    -    -    14,335,992 
Modification consideration (Series C warrants)   -    -    -    -    1,962,920    -    -    -    1,962,920 
Assigned value of warrants issued with Pentwater note   -    -    -    -    5,412,553    -    -    -    5,412,553 
Stock-based compensation expense   -    -    -    -    33,610,991    -    -    -    33,610,991 
Net loss   -    -    -    -    -    -    -    (39,552,737)   (39,552,737)
Balance at June 30, 2012   35,400   $35    51,128,491   $51,128   $190,517,192    (206,693)  $(1,116,514)  $(55,029,786)  $134,422,055 

  

6
 

 

American Standard Energy Corp. and Subsidiaries

Notes to Consolidated Financial Statements

June 30, 2012 and December 31, 2011

 

Note A. Organization and Basis of Presentation

 

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

 

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

 

A history of the Company’s property acquisitions from the XOG Group accounted for as a transaction under common control through June 30, 2012 is as follows:

 

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

 

  · On December 1, 2010, the Company acquired certain developed and undeveloped oil and natural gas properties located in North Dakota (the “Bakken 1 Properties”) from XOG Group for $500,000 in cash and 1,200,000 shares of the Company’s common stock valued at approximately $3,960,000 based on the December 1, 2010 closing price of the Company’s common stock.  The acquisition was accounted for as a transaction under common control and accordingly, the Company recorded the assets and liabilities acquired from the 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 the XOG Group for $7,000,000 in cash.  The acquisition was accounted for as a transaction under common control and accordingly, the Company recorded the assets and liabilities acquired from the 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.

 

  · 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 the XOG Group in exchange for $3,000,000 in 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 common 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 the XOG Group. Certain of these mineral rights with a historical cost basis of $1,257,000 were acquired by Geronimo subsequent to December 31, 2010, and, as a result, were not under common control at that date and have been excluded from the historical consolidated financial statements as of December 31, 2010.  These subsequently-acquired undeveloped mineral rights are reflected in our December 31, 2011 consolidated financial statements.

 

7
 

 

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

 

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

 

Note B. Summary of Significant Accounting Policies

 

Principles of Consolidation

 

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

 

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, 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 June 30, 2012 and for the three and six months ended June 30, 2012 and 2011 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.

 

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.

 

8
 

 

Oil and Gas Sales Receivable

 

Through the Company’s ownership of leasehold interests, oil and natural gas production is sold to purchasers generally on an unsecured basis. Allowances for doubtful accounts are determined based on management's assessment of the creditworthiness. Receivables are considered past due if full payment is not received by the contractual due date. Past due accounts will be generally written off against the allowance for doubtful accounts only after all collection attempts have been exhausted. Management concluded that no allowance for doubtful accounts was necessary at June 30, 2012 and December 31, 2011. Management believes that the lack of allowance for doubtful accounts is adequate; however, actual write-offs may exceed the recorded allowance.

  

Oil and Natural Gas Properties

 

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

 

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

 

Ordinary maintenance and repair costs are expensed as incurred.

 

Costs of significant nonproducing properties, wells in the process of being drilled and development projects are excluded from depletion until such time as the related project is developed and proved reserves are established or impairment is determined. These unproved oil and natural gas properties are periodically assessed for impairment by considering future drilling plans, the results of exploration activities, commodity price outlooks, planned future sales or expiration of all or a portion of such projects. Amounts capitalized to oil and natural gas properties excluded from depletion at June 30, 2012 and December 31, 2011 were $87,040,155 and $25,212,635, respectively. During the three and six months ended June 30, 2012 the Company recorded $202,692 impairment of unproved properties, respectively. No impairment of unproved properties was recorded for the three and six months ended June 30, 2011.

 

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 three and six months ended June 30, 2012 the Company recorded a $115,221 impairment of proved properties. No impairments of proved properties was recorded for the three and six months ended June 30, 2011.

 

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. As of June 30, 2012 the Company had no environmental liabilities.

 

Oil and Natural Gas Sales and Imbalances

 

Oil and natural gas revenues are recorded at the time of delivery of such products to pipelines for the account of the purchaser or at the time of physical transfer of such products to the purchaser. The Company follows the sales method of accounting for oil and natural gas sales, recognizing revenues based on the Company's share of actual proceeds from the oil and natural gas sold to purchasers. Oil and natural gas imbalances are generated on properties for which two or more owners have the right to take production "in-kind" and in doing so take more or less than their respective entitled percentage. The Company did not have any oil and natural gas imbalances as of June 30, 2012 and 2011.

 

9
 

 

Debt Issuance Costs

 

In September 2011, the Company entered into a $300 million credit facility with Macquarie Bank Limited (“Macquarie”). In February 2012, the Company entered into a $20 million convertible note with Pentwater Equity Opportunities Master Fund Ltd. and PWCM Master Fund Ltd. (collectively, “Pentwater”). The Company incurred costs related to these facilities that were capitalized on the Consolidated 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 $2,143,342 at June 30, 2012 for the combined Macquarie and Pentwater debt issuances. The capitalized costs will be amortized over the term of the facility using the effective interest rate method. The amortization for the three months ended June 30, 2012 and 2011 was $182,054 and $0, respectively. The amortization for the six months ended June 30, 2012 and 2011 was $309,309 and $0, respectively.

 

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 Simulation 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 natural gas properties. Subsequently, the asset retirement cost included in the carrying amount is allocated to expense through depreciation, depletion and amortization. Changes in the liability due to passage of time are recognized as an increase in the carrying amount of the liability and as corresponding accretion expense.

 

General and Administrative Expense

 

In addition to general and administrative (“G&A”) costs incurred directly by the Company, the accompanying financial statements include an allocated portion of the actual costs incurred by the XOG Group for G&A expenses. The amounts allocated to the properties are for the period prior to ownership by Nevada ASEC and ASEN 2.  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 natural gas assets of the XOG Group.  Using this method, G&A expense allocated to the Acquired Properties was immaterial for all periods presented.

 

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. 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 six months ended June 30, 2012 and 2011. The Company provides compensation benefits to employees and non-employee directors under share-based payment arrangements, including various employee stock option plans. See Note C for further discussion of the Company’s stock-based compensation plans.

 

Income Taxes

 

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

 

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.

 

10
 

 

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 natural gas sales receivable, other current assets, accounts payable and accrued liabilities approximates fair value because of the short maturity of these instruments.

 

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 (loss) 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 six months ended June 30, 2011 was computed on a pro forma basis as if the 883,607 common shares issued to the XOG Group in connection with the Company’s acquisition of the Acquired Properties during 2011, and the 285,716 shares purchased by Randall Capps in the February 2011 private placement were issued and outstanding for all periods presented.  As of June 30, 2012, 10,100,760 stock options and 15,259,275 shares of common stock underlying warrants were excluded from the calculation due to being anti-dilutive. As of June 30, 2011, 2,194,621 shares and 4,049,464 warrants were excluded from the calculation due to being anti-dilutive.

 

Derivative Instruments and Price Risk Management

 

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

 

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

 

Note C.  Stockholders' Equity

 

Founders Stock

 

On April 16, 2011, 548,655 shares of founder’s stock issued to management vested.  The Company estimated that $1,338,308 in federal and state withholding taxes is due related to this vesting, which has been recorded as an accrued liability on the accompanying balance sheet as of June 30, 2012 and December 31, 2011.  The holders of these shares have remitted to the Company 206,693 shares of the Company’s common stock valued with a market price of $5.40 per share when remitted to cover the withholding requirements.  The stock remittance is included in the accompanying statement of stockholders’ equity as treasury stock at June 30, 2012 and December 31, 2011.

 

On February 13, 2012, the Board of Directors of the Company approved the immediate vesting of a total of 1,568,877 restricted shares of the Company’s common stock previously issued to the Chief Executive Officer, President and Chief Financial Officer as founders stock which were to vest in equal portions annually through April 16, 2014. The Company recorded compensation expense for these shares of $1,797,993 for the six months ended June 30, 2012 and $403,125 for the six months ended June 30, 2011. For the three months ended June 30, 2012 and 2011, the Company recorded $0 and $201,563 in compensation expense, respectively.

 

The Company evaluated the taxable amount due and paid $558,256 to the IRS in April 2012.  In addition, in accordance with the founder’s stock agreements for each of the officers, the Company is required to reimburse a portion of these withholding taxes to the officers.  Based upon the agreements, the Company estimates that it will be required to reimburse a total of $3,135,413 to these officers by December 31, 2012.  Of this amount, $0 and $1,797,105 is included in general and administrative expenses for the three and six months ended June 30, 2012 and in accrued compensation due to officers as of June 30, 2012.

 

11
 

 

Restricted Stock

 

As part of a comprehensive review of compensation, compensation expense, and shareholder dilution, the Board of Directors granted 20,000 shares of restricted common stock to each of our three executive officers and one of our employees on March 30, 2012. The restricted stock was valued on the date of grant at $2.43 per share and recorded as stock-based compensation expense of $0 and $194,400 for the three and six months ended June 30, 2012.

 

Private Placements of Common Stock and Warrants

 

On February 1, 2011, the Company closed a private placement offering raising proceeds of $15,406,755 through the issuance of (i) 4,401,930 shares of common stock at a price of $3.50 per share and (ii) two series of five-year warrants each exercisable into 1,100,482 shares of common stock at exercise prices of $5.00 and $6.50 per share, respectively.  The Company also issued to the placement agents warrants to purchase up to 317,117 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. On February 9, 2012, the investors agreed to waive certain anti-dilution rights with respect to the warrants and certain participation rights.

 

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

 

On July 15, 2011, the Company closed a private placement offering of $12,980,003 through the issuance of (i) 2,260,870 shares of common stock at a price of $5.75 per share, (ii) Series A warrants to purchase 1,130,435 shares of common stock at a per share exercise price of $9.00 subject to certain adjustment provisions; and (iii) Series B warrants at a per share exercise price of $0.001 to purchase a number of shares of common stock, which became exercisable on the 30th trading day following the date on which the purchasers in the private placement were able to freely sell the shares of common stock pursuant to Rule 144 promulgated under the Securities Act of 1933, as amended, without restriction (the “Eligibility Date”) as the market price of the common stock was less than the purchase price in the offering or $5.75.

 

Pursuant to the terms of the Series B warrants, on the Eligibility Date the investors had the right to purchase a number of shares of common stock such that the aggregate average price per share purchased by the investors was equal to the market price (defined as the average of volume weighted average price for each of the previous 30 days as reported on the Over-The-Counter Bulletin Board during the 30 trading days preceding the measurement date).  Certain holders of Series B warrants agreed to limit their right to adjustments in certain circumstances such that the total number of shares of common stock underlying the Series B warrants was set at 2,239,029. See Note G.  Derivative warrant instruments (liabilities) and warrants. Exclusive of the non-cash warrant expense, the Company incurred costs of approximately $1.0 million in connection with this offering.

 

In connection with the February 1, 2011 and March 31, 2011 private placement offerings, the Company granted to the investors registration rights pursuant to Registration Rights Agreements, dated February 1, 2011 and March 31, 2011, in which the Company agreed to register all of the related private placement common shares and shares of common stock underlying the warrants within thirty (30) calendar days after February 1, 2011 and March 31, 2011, and use its best efforts to have the registration statement declared effective within one hundred twenty (120) calendar days of the applicable filing date.  Upon the Company’s failure to comply with the terms of the Registration Rights Agreement and certain other conditions, the Company was required to pay to each investor an amount in common stock equal to one percent (1%) per month of the aggregate purchase price paid by such investor, up to 6% of the aggregate stock purchase price.  As the Company did not register the shares within thirty calendar days of February 1, 2011 and March 31, 2011, the Company was required to pay in common stock 1% of the aggregate purchase price per month. Shares distributed were calculated based on the price of issuance of $3.50 per share for the February 1, 2011 private placement offering and $5.75 per share for the March 31, 2011 placement.  In November 2011, the Company remitted 459,074 additional shares, calculated by dividing the respective cash value of each private placements penalty by the respective unit price under which each private placement was funded. For the year ended December 31, 2011, the Company recognized $2,019,943 of delinquent registration penalties, of which $1,408,846 was recorded in the six months ended June 30, 2011 and $1,114,846 for the three months ended June 30, 2011. No additional penalties were incurred and no additional expense was recognized during the three and six months ended June 30, 2012.

 

Deferred Compensation Program

 

On April 15, 2010, the Nevada ASEC’s Board of Directors approved the 2010 Deferred Compensation Program which was ratified by the Company on August 29, 2011. Under this plan, the President and CEO are entitled to receive a one-time retainer fee consisting of options to purchase common stock in lieu of salary through December 31, 2010. The total number of shares underlying options granted under the plan was 1,600,000 in lieu of salary through December 31, 2010. The exercise price of the options was $1.50 and the options were to vest over 26.5 months.  These options have a ten-year life and had a grant date fair value of $1.09 per share. On March 30, 2012 the vesting on all remaining deferred compensation was accelerated and fully-vested at that date. For the three months ended June 30, 2012 and 2011, the Company recorded non-cash stock compensation expense of $0 and $197,434, respectively. For the six months ended June 30, 2012 and 2011, the Company recorded non-cash stock compensation expense of $394,868 in both periods, respectively, related to the amortization of the fair value of these options which is included in general and administrative expenses.

 

12
 

 

Other Share Based Compensation

 

On August 29, 2011, the Company's Board of Directors of common stock adopted the Amended and Restated 2010 Equity Incentive Plan initially approved on April 15, 2010.  The amended plan provides for 12,000,000 shares of common stock to be eligible for issuance to officers, other key employees, directors and consultants.  Since April 15, 2010, the Board of Directors authorized the grants of 11,265,000 stock options under the 2010 Plan.

 

As part of a comprehensive review of compensation, compensation expense, and shareholder dilution, the Board of Directors approved the restructuring of stock options on March 30, 2012 (the “Modification Date”). Due to the modification, 2,400,000 options issued to certain officers were forfeited and 3,200,000 options were accelerated and became immediately vested. An additional 1,550,000 non-qualified options, 205,760 incentive stock options and 80,000 restricted shares (previously discussed) of common stock were granted to certain officers, directors, employees and a consultant. All modified options (including the newly issued options) were priced at the average of the open and closing share price of the Company’s common stock on March 30, 2012, which was $2.43 per share and became fully vested on the Modification Date.

 

The Company recorded non-cash stock-based compensation expense of $0 and $3,195,503 for the three months ended June 30, 2012 and 2011. For the six months ended June 30, 2012 and 2011, the Company recorded non-cash stock-based compensation expense of $31,418,129 and $3,392,586, 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 June 30, 2012:

 

   Shares   Weighted Average
Exercise Price
   Weighted Average
Remaining Contract
Term
   Aggregate
Intrinsic Value
 
                 
Prior Outstanding as-of December 31, 2011   10,745,000   $5.67    8.48   $2,788,000 
                     
Grants:   1,755,760   $2.43    10.00    - 
                     
Exercises:   -    -           
                     
Forfeitures:   (2,400,000)  $7.51           
                     
Expirations:   -    -           
                     
Total Outstanding as-of June 30, 2012   10,100,760   $2.13    8.70   $2,720,000 
                     
Total Exercisable as-of June 30, 2012   10,093,260   $2.13    8.70   $2,720,000 
                     
Total Unvested as-of June 30, 2012   7,500   $2.13    8.70   $- 
                     
Total Vested as-of June 30, 2012   10,093,260   $2.13    8.70   $2,720,000 

 

Black-Scholes option valuation method and the assumptions noted in the following table for the six months ended June 30, 2012.  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.

 

   Range   Weighted Average 
         
Volatility:   77%   77%
           
Risk-Free Interest Rate:   0.88% - 1.01   0.94%
           
Expected Term (years):   4.34 - 5.00    4.51 
           
Dividend Rate:   0.00%   0.00%
           
Fair Value Per Share on Grant Date:   $1.36 - $1.44   $1.38 

 

The fair value of option grants during the six months ended June 30, 2012 was $585,899.

 

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Series A Cumulative Convertible Preferred Stock

 

On June 30, 2012, the Company entered into an Exchange Agreement with Geronimo pursuant to which the Company agreed to issue 35,400 shares (the “Geronimo Shares”) of the Company’s newly created Series A Cumulative Convertible Preferred Stock (“Series A Preferred Stock”) to Geronimo having the rights and preferences set forth in a Certificate of Designation in exchange for the cancelation of a Geronimo Note.

 

Pursuant to the Certificate of Designation, the Series A Preferred Stock accrues cumulative dividends semi-annually at a rate per share equal to 7.5% per annum. The holders of the Series A Preferred Stock shall receive dividends when and if declared by the Company’s Board of Directors in preference to and priority over dividends declared on the Common Stock. Dividends are payable by the Company in either additional shares of Series A Preferred Stock for dividends accrued on or before June 30, 2014 or cash. Holders of Series A Preferred Stock shall be entitled to receive $1,000 per share in the event of a liquidation with priority over the Common Stock.

 

The Series A Preferred Stock is convertible into shares of common stock at a rate of 333.333 shares of common stock per share of Series A Preferred Stock (the “Conversion Rate”) or an initial conversion price of $3.00 per share on or after the later of (i) March 6, 2013 and (ii) the date on which the Company increases the authorized but unissued shares of common stock to such number of shares as shall be sufficient to effect the conversion of all then outstanding shares of the Preferred Stock on a fully-diluted basis. The Company is entitled to decrease the Conversion Rate one time on or before June 30, 2014 to equal the quotient of $1,000 divided by the average closing sale price for the ten trading day period after the Company makes the election, the effect of which would be to increase the conversion price. The Company has the right, in its sole discretion, to cause all Series A Preferred Stock to be automatically converted into shares of common stock at the Conversion Rate if the closing sale price of the common stock equals or exceeds 150% of $3.00 for at least 10 trading days during any 20 consecutive trading day period. Holders of Series A Preferred Stock are not entitled to any voting rights, except as required by law.

 

Note D.  Long term debt

 

Macquarie Credit Facility. On September 21, 2011, Nevada ASEC (the “Borrower”), entered into a Credit Agreement (the “Credit Agreement”) with the lenders party thereto and Macquarie Bank Limited (“Macquarie”) as administrative agent. The Credit Agreement is fully and unconditionally guaranteed by the Company (the “Guarantor”).  The Guarantor has pledged as collateral 100% of its stock in the Borrower.   The Borrower’s obligations under the Credit Agreement are secured by, among other assets, the Borrower’s interest in certain oil and natural gas properties and the hydrocarbons produced from such properties, as well as the proceeds of the sale of such hydrocarbons.

 

The Credit Agreement provides to the Borrower a revolving credit facility in an amount not to exceed $100 million and a term loan facility in an amount not to exceed $200 million. The rate is equal to (i) the lesser of (A) Prime Rate plus the Applicable Margin and (B) the Highest Lawful Rate or (ii) the lesser of (A) the LIBOR Rate plus the Applicable Margin, and (B) the Highest Lawful Rate, as selected by the Borrower, plus a margin of 2.75% to 3.25% per annum (2.75% at June 30, 2012), based on the borrowing base utilization, and the interest rate on term loans is 30, 60 or 90 day LIBOR, as selected by the Borrower, plus a margin of 7.50%. The maturity date of the revolving credit facility is September 21, 2015 and the maturity date of the term loan facility is September 21, 2014.  As part of the Credit Agreement, the Borrower is required to comply with the financial covenants set forth in the Credit Agreement, including an interest coverage ratio, a current ratio, and a debt coverage ratio, as of the end of each calendar quarter.   

 

The initial borrowing base and amount drawn on the revolving credit facility was $12 million.  The debt was initially recorded net of a debt discount of $10,917,981 related to warrants issued to the lenders as disclosed below.  The debt discount will be amortized over the term of the credit facility. The outstanding amount on the revolving credit facility at June 30, 2012 was $13.1 million.  The borrowing base is re-determined semiannually based on the reserve reports by category, oil and natural gas future sales prices as determined by Macquarie, and amount of expenses necessary to produce the oil and natural gas.

 

The table below reflects the breakdown of the components of the revolving credit facility at June 30, 2012:

 

Cash proceeds from revolver  $13,100,000 
Cash proceeds from term loan   9,027,756 
Total cash proceeds  $22,127,756 
Discount on debt   (10,917,981)
Accretion of debt discount   2,363,021 
Net revolving facility and term loan  $13,572,796 

 

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The term loan draws are subject to approval by Macquarie on a case by case basis. Each drilling program is submitted for approval and Macquarie may approve the program in its reasonable discretion. After Macquarie approves a program, the lenders are obligated to advance funds for development, subject to the satisfaction of the conditions precedent to advances set forth in the Credit Agreement. Alternatively, the Company may elect to submit successfully completed wells to the bank for review and obtain advances of funds under the term loan. The outstanding balance on the term loan was $9,027,756 at June 30, 2012. Beginning on March 21, 2013, the Company will begin making monthly payments to amortize the term loan, each payment equal to the total outstanding term loan balance on that date divided by 18. Based on the outstanding balance of the term loan on June 30, 2012, the Company expects to pay $4,513,878 in each of the years 2013 and 2014.

 

In connection with the Credit Agreement, the Company issued to Macquarie Americas Corp. a five year warrant to purchase 5,000,000 shares of the Company’s common stock at a per share exercise price of $7.50. The warrant is exercisable on a cashless basis if there is no registration statement covering the underlying common stock. The warrant is also subject to customary anti-dilution provisions. The fair value of the 5,000,000 warrants issued to Macquarie was calculated using the Monte Carlo valuation model based on factors present at the time of closing. Macquarie can exercise these warrants at any time until the warrants expire in July 2016. The exercise price of the warrants is $7.50 per warrant, subject to “down round” adjustments.  The fair value at issuance date of $10,917,981 was recorded as a discount on the debt as described above.  See Note G for discussion of the modification of the terms of these warrants in February 2012.

 

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

 

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

 

From the Pentwater Closing Date through December 8, 2012, the outstanding borrowings under the Pentwater Note bear an interest rate of 11% per annum, payable as follows (i) interest at a rate of 9% per annum is payable on the first business day of each month, commencing on March 1, 2012 and (ii) interest at a rate of 2% per annum is capitalized and added to the then unpaid principal amount monthly in arrears on the first business day of each month commencing on March 1, 2012. On and after December 9, 2012 through the maturity date, the Pentwater Note bears an interest rate of 16% per annum, payable as follows: (i) interest at a rate of 11% per annum is payable on the first business day of each month commencing on December 1, 2012 and (ii) interest at a rate of 5% per annum is capitalized and added to the then unpaid principal amount monthly on the first business day of each month commencing on December 1, 2012. The Pentwater Note had a maturity date of February 9, 2015, which was amended on March 5, 2012 to December 1, 2013. ASEN 2 can prepay the Pentwater Note without penalty prior to December 31, 2012. If the prepayment occurs after December 31, 2012, ASEN 2 must pay to Pentwater 106% of the then outstanding principal amount of the Pentwater Note that is prepaid. At any time after February 9, 2013, the principal amount and interest of the Pentwater Note may be converted into shares of common stock at a conversion price of $9.00 per share.

 

The convertible note was $20 million.  The debt was initially recorded net of a debt discount of $5,412,553 related to warrants issued as discussed above.  The debt discount will be amortized over the term of the Pentwater Note. The outstanding amount on the Pentwater Note at June 30, 2012 was $20 million with $143,736 in capitalized interest.

 

The table below reflects the breakdown of the components of the Pentwater Note at June 30, 2012:

 

Cash proceeds from Pentwater  $20,000,000 
Discount on debt   (5,412,553)
Accretion of debt discount   1,199,827 
Capitalized interest   143,736 
Net amount of Pentwater Note  $15,931,010 

 

Please see Note M for subsequent events related to the Pentwater Note.

 

15
 

 

Geronimo Note. On March 5, 2012, the Company acquired leasehold working interests in approximately 72,300 net developed and undeveloped acres across the Permian Basin, the Bakken, the Eagle Ford, the Niobrara, the Eagle Bine, and the Gulf Coast (collectively, the “March 2012 Properties”) from a related party. In conjunction with this transaction, the Company entered into a $35,000,000 promissory note (the “Geronimo Note”) made by the Company in favor of Geronimo. The Geronimo Note bears an interest rate of 7% per annum, which shall be increased to 9% per annum upon an event of default, payable on the first business day of each month commencing on June 1, 2012. The Geronimo Note matures on March 21, 2016. The Company may prepay the Geronimo Note at any time without penalty. On June 30, 2012, the Company entered into an Exchange Agreement with Geronimo pursuant to which the Company issued 35,400 shares (the “Geronimo Shares”) of newly created Series A Preferred Stock to Geronimo in exchange for the cancellation of the Geronimo Note. The terms of the Purchase Agreement provided for a reduction or setoff of the principal amount of the Geronimo Note under certain conditions. Pursuant to the terms of the Exchange Agreement, in the event that the Company would have been entitled to any reduction in or setoff against the principal amount of the Geronimo Note pursuant to the terms of the Purchase Agreement, Geronimo is obligated to transfer a portion of the Geronimo Shares equal to one share of Series A Preferred Stock and any dividends accrued thereon for each $1,000 that would have resulted in a reduction in, or setoff against, the principal amount of the Geronimo Note. Therefore, as of June 30, 2012, there is no amount outstanding for the Geronimo Note. This exchange was reflected as a contribution of Capital on June 30, 2012.

 

Note E.  Asset Retirement Obligations

 

The Company's asset retirement obligations represent the estimated present value of the estimated cash flows the Company will incur to plug, abandon and remediate its producing properties at the end of their productive lives, in accordance with applicable state laws. The Company has no assets that are legally restricted for purposes of settling asset retirement obligations.

 

The Company's asset retirement obligation activity for the six months ended June 30, 2012 and the year ended December 31, 2011 is as follows:

 

   June 30, 2012   December 31, 2011 
Balance at beginning of period  $394,177   $242,632 
Liabilities incurred from new wells   498,290    94,880 
Accretion expense   14,825    20,951 
Revisions due to increase in well life estimates   -    35,714 
Balance at end of period  $907,292   $394,177 

 

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 June 30, 2012, the Company has commodity derivative contracts in place through the third quarter of 2014 for a total of approximately 81,593 Bbls of anticipated crude oil production and 508,508 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 asset of $400,955 and net liability of $665,960 at June 30, 2012 and December 31, 2011, respectively.

 

The Company recognizes all gains and losses from changes in commodity derivative fair values immediately in earnings. For the three and six months ended June 30, 2012, the Company had a realized loss on commodity derivatives of ($35,032) and ($99,869), respectively, and an unrealized gain of $1,273,043 and $1,066,915, respectively, included in other income (expense).

 

A summary of our commodity derivatives at June 30, 2012 is as follows:

 

Period of time   Barrels of Oil   Weighted
Average Oil
Prices per Barrel
   Estimated Fair
Market Value
 
 July 1, 2012 through October 31, 2014    81,593   $84.05   $(46,904)

 

Period of time  MMBtu of
Natural Gas
   Weighted
Average Gas
Prices per MMBtu
   Estimated Fair
Market Value
 
July 1, 2012 through September 26, 2014   508,508   $4.4   $447,859 
                
Total fair market value            $400,955 

 

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

 

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   As of June 30, 2012
  Derivative Assets   Derivative Liabilities
  Balance Sheet        Balance Sheet     
  Classification   Fair Value   Classification    Fair Value 
Commodity Contracts   Current Assets   $308,058    Current Liabilities   $- 
Commodity Contracts   Noncurrent Assets    92,897    Noncurrent Liabilities    - 
Total commodity derivatives     $400,955        $  

 

Note G.    Derivative warrant instruments (liabilities) and warrants

 

As part of the July 15, 2011, private placement, the Company issued Series A Warrants to purchase common stock to certain accredited investors in connection with its sale of 2,260,870 share-based units for gross proceeds of approximately $13.0 million.  There are 1,043,478 Series A warrants with an exercise price of $9.00 per share, subject to “down round” adjustments with a floor price of $5.00.

 

Because there were adjustment events, the warrants described above were 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 such 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 until such time that these warrants are exercised, expire or are amended in a way that would no longer require liability accounting.

 

During the three and six months ended June 30, 2012 the fair value of the liability of the warrant derivative instruments decreased by $571,463 and $856,542, respectively, from the fair values of the prior period. Such changes were recorded as unrealized gains on fair value of derivative warrant instruments in the accompanying consolidated statements of operations. The fair value of these warrants is determined using a Monte Carlo Simulation Analysis and is affected by changes in inputs to that model including our stock price, expected stock volatility, the contractual term, and the risk-free interest rate.

 

The fair value of the derivative warrant instruments is estimated using a probability-weighted scenario analysis model with the following assumptions as of June 30, 2012:

 

   For the Six Months 
  Ended June 30,  
   2012 
Common stock issuable upon exercise of warrants   1,043,478 
Estimated market value of common stock on measurement date (1)  $1.58 
Exercise price  $9.00 
Expected volatility (2)   84%
Expected term (in months)   48.1 
Risk-free rate (3)   0.57%
Expected dividend yields   - 
Future financing event   25%

 

  (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.

 

Pentwater Warrant Restructure. On February 10, 2012, the Company, Pentwater and two affiliated entities of Pentwater, (“Modification Investors”), entered into a modification agreement (the “Modification Agreement”), pursuant to which the parties agreed to amend the terms of the Series B warrants issued to the Modification Investors in July 13, 2011 offering in which the Modification Investors invested $12 million. Pursuant to the terms of the Modification Agreement, the parties agreed to limit the dilutive effects of the Series B warrants by including a floor of $3.00 per share in the calculation of the reset provision included in the Series B Warrants. Accordingly, the aggregate number of shares of common stock underlying the Series B warrants held by the Modification Investors is 1,913,043 shares. Due to the elimination of the “down-round” provisions, these warrants qualify for equity presentation as of the modification date.

 

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As additional consideration for the modification of the Series B Warrants, the Company agreed to issue to the Modification Investors new five-year Series C warrants to purchase 2.5 million shares of common stock with a cash exercise price of $3.00 per share. The Series C warrants include a provision under which the Series C warrants must be exercised at the election of the Company by the Modification Investors for cash if the closing sales price of the common stock is $6.00 per share or greater for 20-consecutive trading days. As a result of the issuance of the Series B warrants and the Series C warrants, the exercise prices and number of shares underlying the Series A warrants and Series B warrants held by the remaining investor in the July 13, 2011 offering were adjusted pursuant to their terms. As the Series C Warrants were consideration given pursuant to the Modification Agreement, the fair value of these warrants on the modification date were expensed as a component of realized and unrealized expense on warrant derivatives in the consolidated statement of operations.

 

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

 

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

 

Activity for derivative warrant instruments during the six months ended June 30, 2012 was as follows:

 

   Fair value
as of
December
31, 2011
   Increase
(decrease) in fair
value of
derivative
liability
   Reclassification to equity
due to Modification
   Fair value as of
June
30, 2012
 
Derivative warrant instruments for Series A and Series B Warrants  $8,119,453   $(607,662)  $(6,925,360)  $586,431 
Derivative warrant instruments for Macquarie warrants   7,179,205    231,427    (7,410,632)   - 
   $15,298,658   $(376,235)  $(14,335,992)  $586,431 

 

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 June 30, 2012:

 

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   Level 1   Level 2   Level 3 
Liabilities:               
Commodity derivatives  $-   $400,955   $- 
Warrant derivatives  $-   $-   $586,431 

 

The Company uses Level 2 inputs to measure the fair value of its commodity derivatives.  Fair values are based upon interpolated data.  The Company derives internal valuation estimates taking into consideration the counterparties’ credit ratings, the Company’s credit rating, and the time value of money.  These valuations are then compared to the respective counterparties’ mark-to-market statements.  The considered factors result in an estimated exit-price that management believes provides a reasonable and consistent methodology for valuing derivative instruments.

 

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

 

   For the six months
ended
   For the year ended
 
   June 30,   December 31, 
   2012   2011 
Beginning balance  $(15,298,658)  $- 
Additions   -    (14,888,990)
Net decrease (increase) in liabilities   376,235    (409,668)
Transfers out of Level 3   14,335,992    - 
Ending balance  $(586,431)  $(15,298,658)

 

Generally, market quotes assume that all counterparties have near zero, or low, default rates and have equal credit quality.  However, an adjustment may be necessary to reflect the credit quality of a specific counterparty to determine the fair value of the instrument.

 

The methods described above may result in a fair value estimate that may not be indicative of net realizable value or may not be reflective of future fair values and cash flows.  While the Company believes that the valuation methods utilized are appropriate and consistent with accounting authoritative guidance and with other marketplace participants, the Company recognizes that third parties may use different methodologies or assumptions to determine the fair value of certain financial instruments that could result in a different estimate of fair value at the reporting date.

 

The fair value of the warrants was calculated using the Monte Carlo simulation 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 for the periods ended June 30, 2012 and December 31, 2011.

 

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

 

Certain assets and liabilities are reported at fair value on a nonrecurring basis in the Company's consolidated balance sheets. The following methods and assumptions were used to estimate the fair values:

 

Impairments of Long-Lived Assets.  The Company reviews its long-lived assets to be held and used, including proved oil and natural gas properties, whenever events or circumstances indicate that the carrying value of those assets may not be recoverable. An impairment loss is indicated if the sum of the expected undiscounted future net cash flows is less than the carrying amount of the assets. In this circumstance, the Company recognizes an impairment loss for the amount by which the carrying amount of the asset exceeds the estimated fair value of the asset. The Company reviews its oil and natural gas properties by amortization base or by individual well for those wells not constituting part of an amortization base. For each property determined to be impaired, an impairment loss equal to the difference between the carrying value of the properties and the estimated fair value (discounted future cash flows) of the properties is recognized at that time. Estimating future cash flows involves the use of judgments, including estimation of the proved and unproved oil and natural gas reserve quantities, timing of development and production, expected future commodity prices, capital expenditures and production costs.  During the six months ended June 30, 2012 and 2011, the Company recorded impairments of $0 and $0, respectively.

 

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 June 30, 2012 and 2011.

 

Acquisitions.   Acquisitions not under common control are recorded at fair value.  The Company closed acquisitions on August 22, 2011, November 1, 2011 and March 5, 2012 which were recorded at fair value as described in Note J.

 

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Long-Term Notes Payable and Debt. The carrying amount of the long-term notes payable to Pentwater as of June 30, 2012 approximates fair value because the Company’s current borrowing rate does not materially differ from market rates for similar bank borrowings.  The long-term notes payable have only been outstanding for a short period of time and as such, the carrying value approximates fair value.  The book value of our term loan and credit facility with Macquarie approximates fair value because of its floating rate structure.  The Company has classified the long-term notes payable and credit facility as Level 2 items within the fair value hierarchy.

 

Note I.  Major Customers

 

The Company's producing oil and natural gas properties are located in Texas, New Mexico, Arkansas, Oklahoma, North Dakota, Nebraska and Wyoming.  At June 30, 2012, the Company contracts with a number of operators and notes one operator, XOG, in which revenues received by the Company were greater than 10% of the Company’s total revenues.  During the first six months ended June 30, 2012 and 2011, revenue through XOG accounted for approximately 53% and 87%, respectively.  Although operators are not the end purchasers of oil and natural gas, the Company is of the opinion that the loss of any one purchaser other than XOG would not have a material adverse effect on the ability of the Company to sell its oil and natural gas production as such production can be sold to other purchasers.

 

Note J.  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 were valued at $1,093,050 using the stock price of $5.25 per share on the closing date. The acquisition was recorded at fair value as the XOG Group and the Company were not under common control at the time of the asset acquisition.

 

On November 1, 2011, the Company acquired approximately 391 net undeveloped leasehold acres in the Bakken/Three Forks area from the XOG Group for approximately $1.2 million dollars in cash. The acquisition was recorded at fair value as the XOG Group and the Company were not under common control at the time of the asset acquisition.

 

On March 5, 2012, the Company acquired the March 2012 Properties in exchange for the delivery by the Company to the Sellers of $10 million in cash, less a $1.5 million cash deposit previously paid by the Company, the Geronimo Note (as discussed in Note D) made by the Company in favor of Geronimo and 5,000,000 shares of the common stock of the Company, which had a closing price of $2.70 per share on the closing date of the acquisition. The Geronimo Note was subsequently converted into Series A Preferred Stock on June 30, 2012. The March 2012 Properties were purchased pursuant to the terms of a Purchase and Sale Agreement dated as of February 24, 2012, (the “PSA”), by and among the Company, XOG and Geronimo. The effective date of this purchase was December 1, 2011. The operating results from these March 2012 Properties have been included from their acquisition on March 5, 2012.

 

Minimal purchase price was allocated to well bores acquired. The Company allocated virtually all value to acreage for further development, despite the fact that some acquired properties were producing from legacy development.

 

Pro Forma Operating Results

 

The following table reflects the unaudited pro forma results of operations as though the acquisition of the March 2012 Properties had occurred on January 1, 2012 and 2011. The pro forma amounts are not necessarily indicative of the results that may be reported in the future:

 

    Six Months Ended June 30,  
    2012     2011  
Revenues   $ 13,117,958     $ 8,003,813  
                 
Net loss (1)   $ (40,318,538 )   $ (5,880,979 )
                 
Loss per share basic and diluted   $ (0.82 )   $ (0.15 )
                 
Shares used in computing income (loss) per share:                
                 
Basic and diluted (2)     48,971,371       40,062,347  

 

(1) Includes pro forma interest expense of $2,137,646.

(2) Includes pro forma shares of 5,000,000 issued for the transaction.

  

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    Three Months Ended June 30,  
    2012     2011  
Revenues   $ 7,024,270     $ 4,599,054  
                 
Net loss (1)   $ 1,227,719     $ (4,243,617
                 
Loss per share basic and diluted   $ 0.03     $ (0.10
                 
Shares used in computing income (loss) per share:                
                 
Basic and diluted (2)     46,427,292       42,841,757  

 

(1) Includes pro forma interest expense of $1,068,823.

(2) Includes pro forma shares of 5,000,000 issued for the transaction.

  

The amount of revenues and revenues in excess of direct operating expenses included in our consolidated statements of operations and attributable to the March 2012 Properties is shown in the table that follows. Direct operating expenses include lease operating expenses and production and other taxes.

 

   Three Months Ended
June 30, 2012
   Six Months Ended
June 30, 2012
 
Revenues  $1,010,247   $1,400,814 
           
Excess direct operating expenses over revenues  $(22,237)  $(238,962)

 

The PSA provides that if certain defects are found with the March 2012 Properties within 120 days from closing, or if XOG or Geronimo breaches any representation or warranty in the Agreement within one year from closing, XOG and Geronimo shall, at the option of the Company, in its sole and absolute discretion, either (i) provide additional or alternative oil and gas properties, subject to the Company’s applicable due diligence review and acceptance or (ii) for as long as the Geronimo Note is outstanding, decrease the principal amount of the Note in an amount equal to the loss resulting from such property defect or breach.

 

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

 

As further described in Note G, the Geronimo Note was exchanged for 35,400 shares of Series A Preferred Stock on June 30, 2012.

 

Note K.  Related Party Transactions

 

The XOG Group 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 and six months ended June 30, 2012, net sales through XOG were $3,213,795 and $6,408,699, respectively. For the three and six months ended June 30, 2011, net sales through XOG were $2,172,308 and $4,483,643, respectively. Lease operating expenses were $2,774,112 and $4,364,437 for the three and six months ended June 30, 2012, respectively, and $229,671 and $688,955 for the three and six months ended June 30, 2011, respectively. Net cash paid or settled to XOG (other than in connection with acquisitions and as further described below) for the three and six months ended June 30, 2012 was $12,534,032 and $20,141,747, respectively, of which $9,759,920 and $15,777,310 was for drilling costs, respectively. For the three and six months ended June 30, 2011 net cash paid or settled to XOG (other than in connection with acquisitions) was $327,986 and $2,417,374, respectively, of which $98,315 and $1,728,419 was for drilling costs, respectively.

 

On June 30, 2012, the Company, ASEN 2, Nevada ASEC, and XOG entered into a Payment and Settlement Agreement (the “Payment Agreement”) whereby we agreed to issue 4,444,445 shares of the Company’s common stock to XOG at a price per share equal to $2.25 as payment of the $10,000,000 outstanding and owed to XOG pursuant to certain Joint Interest Billing Statements issued by XOG from January 1, 2012, through and including June 30, 2012 and delivered to our subsidiaries in connection with certain Joint Operating Agreements. Pursuant to the terms of the Payment Agreement, we granted piggy-back registration rights with respect to XOG Shares if we file a registration statement in connection with an underwritten public offering within one year from the date of the Payment Agreement.

 

As further described in Note G, the Geronimo Note was exchanged for 35,400 shares of Series A Preferred Stock on June 30, 2012.

 

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.  Prior to July of 2011, Randall Capps had beneficial ownership in excess of 50% of the Company’s shares.  Subsequently, his beneficial ownership decreased to less than 50% until the acquisition in March 2012. He currently beneficially owns more than 50% of the Company’s common stock.  Mr. Capps is also the father-in-law of Scott Feldhacker, our chief executive officer and director.

 

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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 natural gas properties and undeveloped leases from the XOG Group as discussed in Note A and Note J. On March 5, 2012, the Company acquired the March 2012 Properties in exchange for the delivery by the Company to the Sellers of $10 million in cash, less a $1.5 million cash deposit previously paid by the Company, the Geronimo Note of $35,000,000 (as discussed in Note D) made by the Company in favor of Geronimo and 5,000,000 shares of the common stock of the Company, which had a closing price of $2.70 per share on the closing date of the acquisition.

 

Note L.  Commitments and Contingencies

 

Employment Agreements.    At June 30, 2012, the Company’s cash contractual obligations related to its employment agreements with executive officers for each of the following three years ending December 31 are as follows:

 

2012   $409,000 
2013    818,000 
2014    272,667 
Total   $1,499,667 

 

Operating Leases.  The Company leases its 4,092 square-foot primary office facilities in Scottsdale, Arizona under a non-cancellable operating lease agreement, dated September 30, 2010, for a 66-month term.  The lease provided for no lease payments until February 1, 2011 and a reduced square footage charge for the first year.  The initial rental was $23.00 per square foot, beginning February 1, 2011, and increases $.50 per square foot annually thereafter.  For the six months ended June 30, 2012 and 2011, the Company recorded lease expense of $40,569 and $36,943, respectively.

 

At June 30, 2012, the future minimum lease commitments under the non-cancellable operating leases for each of the following five years ending December 31 are as follows:

 

2012   $40,068 
2013    97,356 
2014    99,402 
2015    101,448 
Thereafter    42,625 
Total   $380,899 

 

Drilling Commitments.  At June 30, 2012, the Company had various oil and natural gas wells in multiple stages of drilling and completion of which the balance of the Company’s unpaid drilling commitments was estimated to be approximately $8,719,132.

 

Note M. Subsequent Events

 

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

 

In connection with the Purchase Agreement Amendment, the Company, Pentwater and two affiliated entities of Pentwater (collectively, the “Investor”) entered into a Modification Agreement, dated July 23, 2012 which provided for (i) the amendment of certain warrants to purchase up to 3,333,333 shares of Common Stock, at an exercise price of $2.50 per share, issued to Pentwater pursuant to the a Purchase Agreement dated February 9, 2012, to decrease the exercise price to $2.25 and to change the expiration date to June 30, 2019; (ii) the amendment of certain warrants to purchase up to 2,500,000 shares of Common Stock, at an exercise price of $3.00 per share, issued to Investor pursuant to a Modification Agreement dated February 9, 2012, to decrease the exercise price to $2.25 and to change the expiration date to June 30, 2019; and (iii) the issuance of additional warrants to Pentwater to purchase up to 833,333 shares of Common Stock at an exercise price of $2.25 per share with an expiration date of June 30, 2019.

 

22
 

 

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, 2011 filed with the Securities and Exchange Commission (the “Commission”) on March 20, 2012.

 

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

 

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

 

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

 

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

 

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

 

As of June 30, 2012, we held working interests in approximately 112,400 net acres in the Permian Basin, Bakken, Eagle Ford, Niobrara, Eagle Bine and Gulf Coast regions. These working interests grant us the right as the lessee of the property to explore for, develop and produce oil, natural gas and other minerals, while bearing our portion of related exploration, development and operating costs.

 

Recent Events

 

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

 

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

 

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

 

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

 

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

 

Randall Capps has controlling ownership of XOG, Geronimo and CLW and is a member of the Company’s Board of Directors.  Through his ownership interest in the XOG Group, Mr. Capps is the largest shareholder of our common stock.  Prior to July of 2011, Randall Capps had beneficial ownership in excess of 50% of the Company’s shares.  Subsequently, his beneficial ownership decreased to less than 50% until the acquisition in March 2012. He currently beneficially owns more than 50% of the Company’s common stock.  Mr. Capps is also the father-in-law of Scott Feldhacker, our chief executive officer and director. 

 

23
 

 

Results of operations

 

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 six months ended June 30, 2012 and 2011.

 

   Three Months Ended June 30,   Six Months Ended June 30, 
   2012   2011   2012   2011 
                 
Production volumes:                    
Oil (Bbls)   78,332    28,624    125,167    52,887 
Natural Gas (Mcf)   218,213    132,891    346,028    241,274 
BOE (1)   114,701    50,772    182,838    93,099 
BOE per day   1,260    558    1,010    514 
                     
Sales Prices                    
Oil (per Bbl)  $77.13   $84.40   $84.10   $79.01 
Natural Gas (per Mcf)  $4.43   $5.77   $4.56   $5.77 
BOE Price  $61.24   $62.68   $65.68   $59.84 
                     
Operating Revenues                    
Oil  $6,041,560   $2,415,898   $10,526,611   $4,178,862 
Natural Gas   966,697    766,466    1,576,464    1,391,994 
Gain (loss) on sale of oil and natural gas leases   16,013    -    (94,930)   - 
   $7,024,270   $3,182,364   $12,008,145   $5,570,856 
                     
Operating Expenses                    
Oil and natural gas production costs  $2,422,053   $289,207   $4,812,985   $1,096,551 
General and administrative   1,454,170    5,793,647    38,386,228    7,519,285 
Impairment of oil and natural gas properties   317,913    -    317,913    - 
Depreciation, depletion and amortization   1,381,494    963,097    2,668,225    1,572,287 
Accretion of discount on asset retirement obligations   7,927    2,485    14,825    6,650 
    5,583,557    7,048,436    46,200,176    10,194,773 
                     
Income (loss) from operations  $1,440,713   $(3,866,072)  $(34,192,031)  $(4,623,917)

 

(1) A BOE mean 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 June 30, 2012 and 2011

 

Our oil and natural gas revenues and production product mix are displayed in the following table for the current and comparable quarters.

 

   Three Months Ended June 30, 
   Revenues   Production 
   2012   2011   2012   2011 
Oil   86%   76%   68%   56%
Natural Gas   14%   24%   32%   44%
Total   100%   100%   100%   100%

 

24
 

  

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

 

   Three Months Ended June 30,   Increase   % Increase 
   2012   2011   (Decrease)   (Decrease) 
                 
Production volumes:                    
Oil (Bbls)   78,332    28,624    49,709    174%
Natural Gas (Mcf)   218,213    132,891    85,323    64%
BOE (1)   114,701    50,772    63,929    126%
BOE per day   1,260    558    703    126%
                     
Sales Prices                    
Oil (per Bbl)  $77.13   $84.40   $(7.28)   -9%
Natural Gas (per Mcf)  $4.43   $5.77   $(1.34)   -23%
BOE Price  $61.24   $62.68   $(1.44)   -2%
                     
Operating Revenues                    
Oil  $6,041,560   $2,415,898   $3,625,662    150%
Natural Gas   966,697    766,466    200,231    26%
Gain on sale of oil and natural gas leases   16,013    -    16,013    - 
   $7,024,270   $3,182,364   $3,841,906    121%

 

Oil revenues

 

The Company’s oil revenues were $6,041,560 for the three months ended June 30, 2012, an increase of $3,625,662 (150%) from $2,415,898 for the three months ended June 30, 2011. This increase was due primarily to higher production related to acquired wells and new well development of $4,195,538. The increase in production was offset by a decrease in the average price per barrel during the period reducing revenue by $569,876.

 

Natural gas revenues

 

The Company’s natural gas revenues were $966,697 for the three months ended June 30, 2012, an increase of $200,231 (26%) from $766,466 for the three months ended June 30, 2011. This increase was due to higher volumes of natural gas sold from acquired wells and new wells in 2012 that accounted for an increase of approximately $492,113. The increase in production was offset by lower natural gas prices during the period reducing revenue by $291,882.

 

   Three Months Ended June 30,   Increase/   % Increase/ 
   2012   2011   (Decrease)   (Decrease) 
Operating Expenses                    
Oil and natural gas production costs  $2,422,053   $289,207   $2,132,846    737%
General and administrative   1,454,170    5,793,647    (4,339,477)   -75%
Impairment of oil and natural gas properties   317,913    -    317,913    - 
Depreciation, depletion and amortization   1,381,494    963,097    418,397    43%
Accretion of discount on asset retirement obligations   7,927    2,485    5,442    219%
   $5,583,557   $7,048,436   $(1,464,879)   -21%
                     
Income (loss) from operations  $1,440,713   $(3,866,072)  $5,306,785    -137%

 

Oil and natural gas production expenses.     Production expenses for the three months ended June 30, 2012 increased $2,132,846 (737%) to $2,422,053, compared to $289,207 for the three months ended June 30, 2011. The increase in lease operating expenses was primarily due to expenses of $1,019,346 related to new wells acquired in March of 2012, the increase was also due to the addition and development of a number of other new wells over the year and rework on several wells in the Permian.  

 

25
 

 

General and administrative expenses.     General and administrative (“G&A”) expenses were $1,454,170 for the three months ended June 30, 2012, a decrease of $4,339,477 (75%) from $5,793,647 for the three months ended June 30, 2011. The primary factor for the decrease in G&A expenses was due to the reduction in non-cash stock compensation expense in the second quarter of 2012. This was due to the acceleration of non-cash stock compensation expense in the first quarter of 2012 related to the modifications of the vesting term of the applicable awards.

 

Impairment of oil and natural gas properties. Impairment expense for the three months ended June 30, 2012 was $317,913 compared to $0 for June 30, 2011. The Company impaired approximately $202,692 related to its unproved properties in 2012. The impairment consisted of several expired leases and an estimate of leases where expiration is probable in the foreseeable future. In addition to the unproved property impairment, the Company impaired approximately $115,221 of its proved properties as the carrying value of the properties was higher than the estimated fair value at June 30 2012.

 

Depreciation, depletion and amortization expense.     Depreciation, depletion and amortization expense of proved oil and natural gas properties was $1,381,494 for the three months ended June 30, 2012, an increase of $418,397 (43%) from $963,097 for the three months ended June 30, 2011. The increase in depletion expense was primarily due to an increase in production volumes of producing properties and development wells coming into production.

 

Other income (expense), net.  Other income (expense) was ($212,994) for the three months ended June 30, 2012 and $0 for the three months ended June 30, 2011.  The increase was due in part to a net unrealized gain of $571,463 consisting of an increase in marking the warrant derivatives to market. The Company also recorded $1,238,011 in net realized and unrealized gains on the commodity derivatives.  Lastly, the increase also included interest expense for accretion of the debt discount of $1,729,132 and interest expense of $435,836 incurred in the three months ended June 30, 2012, net of $1,351,459 of interest capitalized to oil and natural gas properties.

 

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, ASEN 2 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 June 30, 2012 and 2011, was $0 due to a related valuation allowance.

 

For the Six Months Ended June 30, 2012 and 2011

 

Our oil and natural gas revenues and production product mix are displayed in the following table for the Current Period Six Months Ended June 30 and Comparable Period.

 

   Six Months Ended June 30, 
   Revenues   Production 
   2012   2011   2012   2011 
Oil   87%   75%   68%   57%
Natural Gas   13%   25%   32%   43%
Total   100%   100%   100%   100%

 

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

 

   Six Months Ended June 30,   Increase   % Increase 
   2012   2011   (Decrease)   (Decrease) 
                 
Production volumes:                    
Oil (Bbls)   125,167    52,887    72,280    137%
Natural Gas (Mcf)   346,028    241,274    104,754    43%
BOE (1)   182,838    93,099    89,739    96%
BOE per day   1,010    514    496    96%
                     
Sales Prices                    
Oil (per Bbl)  $84.10   $79.01   $5.09    6%
Natural Gas (per Mcf)  $4.56   $5.77   $(1.21)   -21%
BOE Price  $65.68   $59.84   $5.84    10%
                     
Operating Revenues                    
Oil  $10,526,611   $4,178,862   $6,347,749    152%
Natural Gas   1,576,464    1,391,994    184,470    13%
Loss on sale of oil and natural gas leases   (94,930)   -    (94,930)   - 
   $12,008,145   $5,570,856   $6,437,289    116%

 

26
 

 

Oil revenues.    The Company’s oil revenues were $10,526,611 for the six months ended June 30, 2012, an increase of $6,347,749 (152%) from $4,178,862 for the six months ended June 30, 2011. Higher average oil prices increased revenues approximately $636,551, while increased production increased revenues by approximately $5,711,198. The increase in production volumes was due primarily to acquired wells and new well development primarily in the Bakken, Eagle Ford, and Permian Basin.

 

Natural gas revenues.      The Company’s natural gas revenues were $1,576,464 for the six months ended June 30, 2012, an increase of $184,470 (13%) from $1,391,994 for the six months ended June 30, 2011. This increase was due to an increase in gas production of $604,362 from new well development and wells acquired in the first six months of 2012. Higher volumes of natural gas sold was partially offset by the impact of price declines of approximately $419,892.

 

   Six Months Ended June 30,   Increase/   % Increase/ 
   2012   2011   (Decrease)   (Decrease) 
Operating Expenses                    
Oil and natural gas production costs  $4,812,985   $1,096,551   $3,716,434    339%
General and administrative   38,386,228    7,519,285    30,866,943    411%
Impairment of oil and natural gas properties   317,913    -    317,913    - 
Depreciation, depletion and amortization   2,668,225    1,572,287    1,095,938    70%
Accretion of discount on asset retirement obligations   14,825    6,650    8,175    123%
   $46,200,176   $10,194,773   $36,005,403    353%
                     
Loss from operations  $(34,192,031)  $(4,623,917)  $(29,568,114)   639%

  

Oil and natural gas production expenses. Production expenses for the six months ended June 30, 2012 increased $3,716,434 (339%) to $4,812,985, compared to $1,096,551 for the six months ended June 30, 2011. The increase is due primarily to $2,290,290 in expenses related to new wells acquired in March 2012, the increase was also due to the addition and development of a number of other new wells over the year and rework on several wells in the Permian.

 

General and administrative expenses.     General and administrative (“G&A”) expenses were $38,386,228 for the six months ended June 30, 2012, an increase of $30,866,943 from $7,519,285 for the six months ended June 30, 2011. The primary factor for the increase in G&A expenses was an increase in non-cash stock based compensation expense of $33,805,391 for the six months ended June 30, 2012, compared to $4,159,219 for the six months ended June 30, 2011. In addition, the increase was due to the restricted stock agreements for each of the officers, wherein the Company is required 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 $2,355,361 to these officers by December 31, 2012 which is included in G&A in the first six months of 2012 compared to $226,320 in the first six months of 2011. The increases were offset by lower G&A expense due to incurring no penalties relating to the registration of warrants which was $293,226 for the 2011 period and slightly lower legal and engineering expenses for the comparative periods.

 

In 2012 and beyond, the Company anticipates G&A expenses to decrease in both absolute terms and as a percentage of total revenues. The Company does not expect further large increases in non-cash stock compensation expenses due to the acceleration of the vesting of equity awards in March of 2012.

 

Impairment of oil and natural gas properties. Impairment expense for the six months ended June 30, 2012 was $317,913 compared to $0 for June 30, 2011. The Company impaired approximately $202,692 related to its unproved properties in 2012. The impairment consisted of several expired leases and an estimate of leases where expiration is probable in the foreseeable future. In addition to the unproved property impairment, the Company impaired approximately $115,221 of its proved properties as the carrying value of the properties was higher than the estimated fair value at June 30 2012.

 

Depreciation, depletion and amortization expense.     Depreciation, depletion and amortization (“DD&A”) expense of proved oil and natural gas properties was $2,668,225 for the six months ended June 30, 2012, an increase of $1,095,938 (70%) from $1,572,287 for the six months ended June 30, 2011. The increase in depletion expense was primarily due to an increase in production volumes in the Bakken and Permian Basin as a result of the addition of new wells coming into production in the first six months of 2012. With the increased development and productivity in unconventional drilling in the Bakken and Eagle Ford, DD&A per BOE is expected to be higher than historical DD&A for the foreseeable future.

 

Other income (expense), net.  Other income (expense), net was ($5,360,706) for the six months ended June 30, 2012 and $0 for the six months ended June 30, 2011.  The increase was due in part to a net expense of $2,686,685 consisting of an increase of $376,235 in marking the warrant derivatives to market, offset by a one-time expense relating to the modification of the warrant derivatives of $3,062,920. The Company also recorded $967,046 in net realized and unrealized gains on the commodity derivatives.  Lastly, the increase also included interest expense for accretion of the debt discount of $2,551,924 and interest expense of $1,089,143 incurred in the six months ended June 30, 2012, net of $1,351,459 of interest capitalized to oil and natural gas properties.

 

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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, ASEN 2 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 six months ended June 30, 2012 and 2011 were $0 due to net operating losses and a related valuation allowance.

 

Capital Commitments, Capital Resources and Liquidity

 

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

 

Oil and natural gas properties.     Cash paid for oil and natural gas properties during the six months ended June 30, 2011 and 2011 totaled $24,985,590 and $7,748,057, respectively. The costs for the six months ended June 30, 2012 related primarily to purchases of additional acreage in March 2012 from Geronimo, as well as drilling expenses in the Permian Basin, Bakken and Eagle Ford.

 

Our 2012 capital budget is $65 million, of which $36 million we have spent in the first six months of 2012. We expect to be able to fund our remaining 2012 capital budget partially with operating cash flows, asset monetizations, utilization of our existing credit facility and the potential issuance of additional equity securities. However, the Company’s capital budget is largely discretionary, and if we experience sustained oil and natural gas prices significantly below the current levels or substantial increases in its drilling and completion costs, we may reduce our capital spending program to remain substantially within the Company’s operating cash flows.

 

We will selectively seek to acquire oil and natural gas properties that provide opportunities for the addition of new reserves and production in both our 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 our 2012 capital expenditures, as adjusted from time to time, we cannot provide any assurances that we will be successful in securing alternative financing sources to fund such expenditures if needed. The actual amount and timing of our expenditures may differ materially from our estimates as a result of, among other things, actual drilling results, the obtaining of debt or equity financing capital, the timing of expenditures by third parties on projects that we do not operate, the availability of drilling rigs and other services and equipment, regulatory, technological and competitive developments and market conditions. In addition, under certain circumstances we would consider increasing, decreasing, or reallocating our 2012 capital budget.

 

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

 

Capital resources.   Our primary sources of liquidity during the first six months of 2012 were cash flows generated from proceeds from our debt offerings of senior, convertible and subordinated debt from which cash proceeds of $23,857,867 were generated. Our primary sources of liquidity during the first six months of 2011 were cash flows generated from proceeds from our private placement offerings of our common stock and proceeds from stock subscription receivables from which cash net proceeds of $25,910,169 were generated. We believe that funds from our cash flows from operations, asset monetizations, and any financing under our credit facility should be sufficient to meet both our short-term working capital requirements and our 2012 capital expenditure plans.

 

Cash flow from operating activities.   Our net cash provided by (used in) operating activities was $2,942,558 and ($4,890,029) for the six months ended June 30, 2012 and 2011, respectively. The increase in operating cash flow for the six months ended June 30, 2012 as compared to June 30, 2011 was due primarily to increases in accounts payable and accrued liabilities. This was offset by oil and gas sales receivables and several other non-cash adjustments to our net loss. See cash flow statement for non-cash adjustments.

 

Cash flow used in investing activities.    During the six months ended June 30, 2012 and 2011, we invested cash of $25,507,867 and $21,248,057, 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 2012 due to the Company’s increased leasehold acquisition activities and drilling activities in the Bakken Shale Formation, Eagle Ford and Permian.

 

Cash flow from financing activities.    Net cash provided by financing activities was $22,503,884 and $25,910,169 for the six months ended June 30, 2012 and 2011, respectively. Financing activity was comprised primarily of net proceeds from a $20,000,000 convertible note issued in February 2012 and proceeds from the credit facility during the six months ended June 30, 2012.

 

Liquidity.    At June 30, 2012, we had cash and cash equivalents of $671,624. The Company had net income of $1,227,719 for the three months ended June 30, 2012 and incurred a net loss of $39,552,737 for the six months ended June 30, 2012. To address these concerns we expect to use operating cash flows, asset monetizations, utilization of our existing credit facility, and the potential issuance of additional equity securities to meet our cash obligations. As the Company’s capital budget is largely discretionary, and if we experience sustained oil and natural gas prices significantly below the current levels or substantial increases in its drilling and completion costs, we may reduce our capital spending program to remain substantially within the Company’s operating cash flows.

 

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Contractual Obligations

 

Employment Agreements.   At June 30, 2012, our contractual obligations include employment agreements with executive officers for the remaining 6 months ended December 31, 2012 and the years ending December 31, 2013 through 2014 are as follows:

 

   2012   2013   2014 
Scott Feldhacker  $153,000   $306,000   $102,000 
Richard Macqueen   153,000    306,000    102,000 
Scott Mahoney   103,000    206,000    68,667 
Total Contractual Obligations Related to Employment Contracts  $409,000   $818,000   $272,667 

 

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 until February 1, 2011 and a reduced square footage charge for the first year.  The initial rental was $23.00 per square foot, beginning February 1, 2011, and increases $0.50 per square foot annually thereafter.  For the six months ended June 30, 2012, the Company recorded lease expense of $40,569.

 

At June 30, 2012, the future minimum lease commitments under the non-cancellable operating leases for the remaining six months ended December 31, 2012 and each of the following three years ending December 31 and thereafter are as follows:

 

2012   $40,068 
2013    97,356 
2014    99,402 
2015    101,448 
Thereafter    42,625 
Total   $380,899 

 

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

 

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

 

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

 

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

 

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

 

·Debt Coverage Ratio.  Commencing on the last day of the fiscal quarter following any fiscal quarter in which there are, on any day that fiscal quarter, no outstanding advances under the Term Loan, Nevada ASEC shall maintain a Debt Coverage Ratio of no more than 3.50 to 1.00.

 

“Debt Coverage Ratio” shall mean, as of the last day of any fiscal quarter, the ratio of (i) Nevada ASEC’s debt to (ii) Nevada ASEC’s EBITDA for the four (4) most recent fiscal quarters occurring in whole or in part after closing; provided that (x) for the first fiscal quarter after the closing date, the Debt Coverage Ratio will be calculated using Nevada ASEC’s EBITDA for that first fiscal quarter multiplied by four; (y) for the second fiscal quarter after the closing date, the Debt Coverage Ratio will be calculated using Nevada ASEC’s aggregate EBITDA for those first two fiscal quarters multiplied by two; and (z) for the third fiscal quarter after the closing date, the Debt Coverage Ratio will be calculated using Nevada ASEC’s aggregate EBITDA for those first three fiscal quarters multiplied by one and one-third (1.33).

 

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

 

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

 

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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.  The debt discount will be amortized over the term of the credit facility. The outstanding amount on the revolving credit facility at June 30, 2012 was $13.1 million. 

 

The outstanding balance on the term loan was $9,027,756 at June 30, 2012. Beginning on March 21, 2013, the Company will begin making monthly payments to amortize the term loan, each payment equal to the total outstanding term loan balance on that date divided by 18. Based on the outstanding balance of the term loan on June 30, 2012, the Company expects to pay $4,513,878 in each of the years 2013 and 2014.

 

At June 30, 2012, our future contractual obligations under the Pentwater Note and Macquarie Credit facility for the remaining six months ended December 31, 2012 and each of the following four years ending December 31 are as follows:

 

2012   $911,315 
2013    28,587,009 
2014    4,562,457 
2015    13,443,875 
Total   $47,504,656 

 

 

 Item 3. Quantitative and Qualitative Disclosures About Market Risk

 

As we expand, we are 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 such as 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 our 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 2011 and the first six months of 2012 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 loans.

 

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.

 

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As of December 31, 2011 the Company identified three material weaknesses in its internal controls, and as such did not maintain effective internal control over financial reporting. The weaknesses involve (1) the inadequate controls over electronic spreadsheets used in financial reporting (2) insufficient number of accounting personnel so that processes and controls can be completed on a more timely basis and (3) inadequate controls over the recording of stock compensation awards and expenses.

 

(b) Changes in Internal Control over Financial Reporting

 

During the six months ended June 30, 2012, management continued to implement a program to appropriately address the effectiveness of internal controls with the objective to be in compliance with Rule 13a-15(e) of the Exchange Act as follows:

 

Accounting Department.  The Company has hired a Senior Staff Accountant reporting to the Controller to assist the preparation of financial reporting.

 

Accounting Software and Supporting Records.   The Company has implemented an oil and gas accounting software system.  This system will be used as the core system for all financial data and internal controls since the Company’s formation and the acquisition of oil and gas natural properties on May 1, 2010.  The Company has completed the process of incorporating the historic financial transactions of the XOG Group related to these properties into the new system.

 

Internal Control Systems. The Company has taken remediation steps discussed above to enhance its internal control over financial reporting and reduce control deficiencies. The Company believes the steps listed above enhanced our internal control over financial reporting and reduce control deficiencies.

 

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PART II - Other Information

 

Item 1. Legal Proceedings

 

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

 

Item 1A. Risk Factors

 

In addition to the risk factors disclosed in Part 1, Item 1A, “Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, 2011, set forth below are certain factors that have affected, and in the future could affect, our operations or financial condition. We operate in a changing environment that involves numerous known and unknown risks and uncertainties that could impact our operations. The risks described below and in our Annual Report on Form 10-K for the year ended December 31, 2011 are not the only risks we face. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our financial condition and/or operating results.

 

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

 

Randall Capps is a member of our board of directors and, as of August 2, 2012, beneficially owns 28,937,522 shares of common stock or approximately 56.7% 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.

 

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

 

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

  

In addition to possible future regulatory changes at the federal level, several states (including Arkansas, Colorado, Texas, New York and Pennsylvania), have considered, or are considering, legislation or regulations similar to the federal legislation described above that have imposed, or could impose, more stringent permitting, transparency, disposal and well construction requirements on hydraulic fracturing operations. For example, in December 2011, the Railroad Commission of Texas and the Colorado Oil and Gas Conservation Commission finalized regulations requiring public disclosure of chemicals in fluids used in the hydraulic fracturing process. Local ordinances or other regulations also may regulate or prohibit the performance of well drilling in general and hydraulic fracturing in particular. Such laws and regulations may result in increased scrutiny or third-party claims, or otherwise result in operational delays, liabilities and increased costs.

 

32
 

 

Recently, the Wyoming Oil and Gas Conservation Commission also passed a rule requiring disclosure of hydraulic fracturing fluid content. At this time, it is not possible to estimate the potential impact on our business of additional federal or state regulatory actions affecting hydraulic fracturing. In addition, a number of states in which we plan to conduct hydraulic fracturing operations are currently conducting, or may in the future conduct, regulatory reviews that potentially could restrict or limit our access to shale formations located in their states. In most states, our third party operators are required to obtain permits from one or more governmental agencies in order to perform drilling and completion activities, including hydraulic fracturing. Such permits are typically required by state agencies, but can also be required by federal and local governmental agencies. The requirements for such permits vary depending on the location where such drilling and completion activities will be conducted. As with all governmental permitting processes, there is a degree of uncertainty as to whether a permit will be granted, the time it will take for a permit to be issued and the conditions which may be imposed in connection with the granting of the permit. Recently, moratoriums on the issuance of permits have been imposed upon inland drilling and completion activities. For example, subject to an Executive Order issued by Governor Paterson on December 13, 2010, the New York Department of Environmental Conservation will not issue permits for drilling and completion activities until it completes a final environmental impact study following public comment. Some of the drilling and completion activities may take place on federal land, requiring leases from the federal government to conduct such drilling and completion activities. In some cases, federal agencies have cancelled oil and natural gas leases on federal lands.

 

In March 2010, the United States Environmental Protection Agency announced that it would conduct a wide-ranging study on the effects of hydraulic fracturing on drinking water resources and that it will propose standards for the treatment or disposal of wastewater from certain gas production operations. 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.

 

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

 

As of June 30, 2012, we had $13,100,000 outstanding under our revolving credit facility, $9,027,756 outstanding under our term loan facility and $0 available for future secured borrowings under our revolving credit facility. As of June 30, 2012, we also had a $20 million secured convertible promissory note issued to Pentwater, which was subsequently increased to $25 million on July 23, 2012. The promissory note with a principal amount of $35 million issued to Geronimo was converted into shares of Series A Preferred Stock on June 30, 2012 which accrue cumulative dividends semi-annually at a rate of 7.5% per annum. In the future, we may incur significant indebtedness in order to make future acquisitions or to develop our properties.

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

33
 

 

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

 

On April 1, 2012, the Company issued 100,000 shares of common stock to a consultant for consulting services rendered pursuant to a Consulting Agreement. These shares were issued in reliance upon Section 4(2) of the Securities Act of 1933, as amended.

 

Item 6.  Exhibits

 

Exhibit No.   Description
     
4.1  

Certificate of Designation of Series A Cumulative Convertible Preferred Stock (1)

 

10.1   Exchange Agreement by and between the Company and Geronimo Holding Corporation dated as of June 30, 2012 (1)
     
10.2   Payment and Settlement Agreement by and among the Company, ASEN 2, Corp. and XOG Operating LLC, dated as of June 30, 2012 (1)
     
10.3  

Form of Warrant issued to Pentwater, dated July 23, 2012 (2) 

     
10.4  

Form of Amended and Restated Series C Warrant issued to Investor, dated July 23, 2012 (2) 

     
10.5   Form of Amended and Restated Warrant issued to Pentwater, dated July 23, 2012 (2)
     
10.6   First Amendment to Note and Warrant Purchase Agreement by and among the Company, ASEN 2, and Pentwater, dated as of July 23, 2012 (2)
     
10.7   Amended Secured Convertible Promissory Note issued by ASEN 2 to Pentwater, dated July 23, 2012 (2)
     
10.8   Modification Agreement by and among the Company, Pentwater and its affiliates, dated as of July 23, 2012 (2)

  

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 July 6, 2012.
(2) Incorporated by reference to Form 8-K filed on July 27, 2012.  

 

*To be filed by amendment   

 

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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: August 9, 2012 By: /s/ Scott Feldhacker
    Scott Feldhacker
    Chief Executive Officer and Director
    (Principal Executive Officer)
     
Date: August 9, 2012 By: /s/ Scott Mahoney
    Scott Mahoney, CFA
    Chief Financial Officer
    (Principal Financial Officer)

 

35

 

XOTC:ASEN Quarterly Report 10-Q Filling

XOTC:ASEN Stock - Get Quarterly Report SEC Filing of XOTC:ASEN stocks, including company profile, shares outstanding, strategy, business segments, operations, officers, consolidated financial statements, financial notes and ownership information.

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XOTC:ASEN Quarterly Report 10-Q Filing - 6/30/2012
Name |  Ticker |  Star Rating |  Market Cap |  Stock Type |  Sector |  Industry Star Rating |  Investment Style |  Total Assets |  Category |  Top Holdings |  Top Sectors |  Symbol |  Title Star Rating |  Category |  Total Assets |  Top Holdings |  Top Sectors |  Symbol |  Name Title |  Date |  Author |  Collection |  Interest |  Popularity Topic |  Sector |  Key Indicators |  User Interest |  Market Cap |  Industry Name |  Ticker |  Star Rating |  Market Cap |  Stock Type |  Sector |  Industry Star Rating |  Investment Style |  Total Assets |  Category |  Top Holdings |  Top Sectors |  Symbol / Ticker |  Title Star Rating |  Category |  Total Assets |  Symbol / Ticker |  Name Title |  Date |  Author |  Collection |  Popularity |  Interest Title |  Date |  Company |  Symbol |  Interest |  Popularity Topic |  Sector |  Key Indicators |  User Interest |  Market Cap |  Industry Name |  Ticker |  Popularity |  Our Choices Title |  Date |  Company |  Symbol |  Interest |  Popularity

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