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EXCEL - IDEA: XBRL DOCUMENT - Black Ridge Oil & Gas, Inc.Financial_Report.xls
EX-32.1 - CERTIFICATION - Black Ridge Oil & Gas, Inc.ex3201.htm
EX-31.1 - CERTIFICATION - Black Ridge Oil & Gas, Inc.ex3101.htm
EX-31.2 - CERTIFICATION - Black Ridge Oil & Gas, Inc.ex3102.htm
EX-32.2 - CERTIFICATION - Black Ridge Oil & Gas, Inc.ex3202.htm
EX-23.1 - CONSENT - Black Ridge Oil & Gas, Inc.ex2301.htm


UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

FORM 10-Q
(Mark One)

x QUARTERLY REPORT UNDER SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934

For Quarterly Period Ended June 30, 2011
or

o TRANSITION REPORT UNDER SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934

For the Transition period from _______________ to ______________

Commission File Number 000-53952

ANTE5, INC.
(Name of registrant in its charter)

Delaware
(State or other jurisdiction of incorporation or
organization)
27-2345075
(I.R.S. Employer Identification No.)
 

10275 Wayzata Blvd. Suite 310, Minnetonka, Minnesota 55305
(Address of principal executive offices) (Zip Code)

Issuer’s telephone Number: (952) 426-1241


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

Yes
 x
No
 o

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

Yes
 x
No
 o

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

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

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

Yes
 o
No
 x

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

The number of shares of registrant’s common stock outstanding as of August 12, 2011 was 47,358,965.



 
 

 
 


PART I - FINANCIAL INFORMATION
 
   
ITEM 1.
FINANCIAL STATEMENTS (Unaudited)
1
 
1
 
2
 
3
 
4
16
27
28
   
PART II - OTHER INFORMATION
 
29
29
29
29
29
30
 
31
 
 
ANTE5, INC.
 
   
June 30,
   
December 31,
 
   
2011
   
2010
 
ASSETS
 
(Unaudited)
       
             
Current assets:
           
Cash and cash equivalents
  $ 2,236,014     $ 8,577,610  
Accounts receivable
    258,451       15,840  
Prepaid expenses
    167,450       8,431  
Current portion of contingent consideration receivable
    250,000       287,000  
Total current assets
    2,911,915       8,888,881  
                 
Contingent consideration receivable,
net of current portion and allowance of $878,650
    6,136,657       6,185,000  
                 
Property and equipment:
               
Oil and natural gas properties, full cost method of accounting
               
Proved properties
    5,517,373       -  
Unproved properties
    13,132,727       4,343,389  
Other property and equipment
    40,533       15,706  
Total property and equipment
    18,690,633       4,359,095  
Less, accumulated depreciation, amortization and depletion
    (109,692 )     (13,725 )
Total property and equipment, net
    18,580,941       4,345,370  
                 
Total assets
  $ 27,629,513     $ 19,419,251  
                 
                 
LIABILITIES AND STOCKHOLDERS' EQUITY
               
                 
Current liabilities:
               
Accounts payable
  $ 3,946,687     $ 325,584  
Accounts payable, related parties
    222,716       76,777  
Accrued expenses
    -       47,267  
Royalties payable
    319,281       323,600  
Current portion of deferred tax liability
    81,200       119,400  
Total current liabilities
    4,569,884       892,628  
                 
Asset retirement obligations
    3,340       -  
                 
Deferred tax liability, net of current portion
    2,279,600       2,573,600  
                 
Total liabilities
    6,852,824       3,466,228  
                 
Stockholders' equity:
               
Preferred stock, $0.001 par value, 20,000,000 shares
authorized, no shares issued and outstanding
    -       -  
Common stock, $0.001 par value, 100,000,000 shares authorized,
41,204,465 and 37,303,614 shares issued and outstanding at
June 30, 2011 and December 31, 2010, respectively
    41,204       37,304  
Additional paid-in capital
    21,940,226       16,654,223  
Accumulated (deficit)
    (1,204,741 )     (738,504 )
Total stockholders' equity
    20,776,689       15,953,023  
                 
Total liabilities and stockholders' equity
  $ 27,629,513     $ 19,419,251  
                 
 
See accompanying notes to financial statements.
 

 
 
(Unaudited)
 
   
For the Three
   
April 9, 2010
   
For the Six
   
April 9, 2010
   
Months Ended
   
(Inception) to
   
Months Ended
   
(Inception) to
   
June 30, 2011
   
June 30, 2010
   
June 30, 2011
   
June 30, 2010
                       
Oil and gas sales
  $ 250,590     $ -     $ 347,530     $ -  
                                 
Operating expenses:
                               
Production expenses
    11,352       -       16,975       -  
Production taxes
    27,573       -       37,003       -  
General and administrative
    489,109       339,530       857,986       339,530  
Depletion of oil and gas properties
    68,382       -       104,530       -  
Accretion of discount on asset retirement obligations
    146       -       266       -  
Depreciation and amortization
    2,960       619       6,082       619  
Total operating expenses
    599,522       340,149       1,022,842       340,149  
                                 
Net operating loss
    (348,932 )     (340,149 )     (675,312 )     (340,149 )
                                 
Other income (expense):
                               
Interest income
    256       2,056       1,412       2,056  
Interest (expense)
    (25,490 )     (8,540 )     (25,490 )     (8,540 )
Loss on disposal of equipment
    (1,061 )     -       (1,061 )     -  
Indemnification expenses
    (97,986 )     -       (97,986 )     -  
Total other income (expense)
    (124,281 )     (6,484 )     (123,125 )     (6,484 )
                                 
Loss before provision for income taxes
    (473,213 )     (346,633 )     (798,437 )     (346,633 )
                                 
Provision for income taxes
    57,900       -       332,200       -  
                                 
Net (loss)
  $ (415,313 )   $ (346,633 )   $ (466,237 )   $ (346,633 )
                                 
Weighted average number of common shares outstanding - basic and fully diluted
    40,505,760       21,292,333       39,180,194       21,292,333  
                                 
Net (loss) per share - basic and fully diluted
  $ (0.01 )   $ (0.02 )   $ (0.01 )   $ (0.02 )
See accompanying notes to financial statements.
 

 
 
(Unaudited)
 
   
For the Six
   
April 9, 2010
 
   
Months Ended
   
(Inception) to
 
   
June 30, 2011
   
June 30, 2010
 
CASH FLOWS FROM OPERATING ACTIVITIES
           
Net (loss)
  $ (466,237 )   $ (346,633 )
Adjustments to reconcile net (loss)
to net cash used in operating activities:
               
Depletion of oil and gas properties
    104,530       -  
Depreciation and amortization
    6,082       619  
Accretion of discount on asset retirement obligations
    266       -  
Loss on disposal of equipment
    1,061       -  
Loss on sale of debt securities
    -       8,363  
Common stock warrants granted
    18,506       -  
Common stock warrants granted, related parties
    3,266       -  
Common stock options granted, related parties
    312,262       58,425  
Decrease (increase) in assets:
               
Accounts receivable
    (242,611 )     (5,841 )
Prepaid expenses
    (159,019 )     -  
Contingent consideration receivable
    85,343       100,210  
Increase (decrease) in liabilities:
               
Accounts payable
    (76,732 )     139,760  
Accounts payable, related parties
    145,939       -  
Accrued expenses
    (47,267 )     13,304  
Royalties payable
    (4,319 )     (8,254 )
Deferred tax liability
    (332,200 )     -  
Net cash used in operating activities
    (651,130 )     (40,047 )
                 
CASH FLOWS FROM INVESTING ACTIVITIES
               
Cash acquired in spin-off from Ante4, Inc.
    -       258,712  
Proceeds from sale of short term investments
    -       1,300,000  
Purchases and increases in oil and gas properties
    (5,665,533 )     -  
Purchases of other property and equipment
    (40,533 )     -  
Net cash provided by (used in) investing activities
    (5,706,066 )     1,558,712  
                 
CASH FLOWS FROM FINANCING ACTIVITIES
               
Principal payments on line of credit
    -       (1,303,933 )
Proceeds from the exercise of common stock options
    15,600       -  
Net cash provided by (used in) financing activities
    15,600       (1,303,933 )
                 
NET CHANGE IN CASH
    (6,341,596 )     214,732  
CASH AT BEGINNING OF PERIOD
    8,577,610       -  
CASH AT END OF PERIOD
  $ 2,236,014     $ 214,732  
                 
                 
SUPPLEMENTAL INFORMATION:
               
Interest paid
  $ 3,718     $ -  
Income taxes paid
  $ -     $ -  
                 
NON-CASH INVESTING AND FINANCING ACTIVITIES:
               
Purchase of oil and gas properties paid subsequent to period-end
  $ 3,697,835     $ -  
Purchase of oil and gas properties through issuance of common stock
  $ 4,940,269     $ -  
Capitalized asset retirement obligations
  $ 3,074     $ -  
See accompanying notes to financial statements.
 

 
Ante5, Inc.
 (Unaudited)

Note 1 – Organization and Nature of Business

Ante5, Inc. (the “Company”) became an independent company in April 2010 when the spin-off from our former parent company, Ante4, Inc. (now Voyager Oil & Gas, Inc.), became effective.  We became a publicly traded company when our shares began trading on July 1, 2010.  Since October 2010, we have been engaged in the business of acquiring oil and gas leases and participating in the drilling of wells in the Bakken and Three Forks trends in North Dakota and Montana.  Our strategy is to participate in the exploration, development and production of oil and gas reserves as a non-operating working interest owner in a growing, diversified portfolio of oil and gas wells.  We aggressively seek to accumulate mineral leases to position us to participate in the drilling of new wells on a continuous basis.  Occasionally we also purchase working interests in producing wells.

We also inherited assets from our former parent company prior to our spin off.  These historical assets relate to our former parent company’s business as WPT Enterprises, Inc., when it created internationally branded products through the development, production and marketing of televised programming based on gaming themes.  The primary historical gaming asset is our license agreement with a subsidiary of PartyGaming, PLC, an international online casino gaming company.  We are entitled to royalty payments from that license agreement.  We manage our historical assets to monetize them.  Our common stock is currently traded on the OTC QB and OTC BB under the trading symbol “ANFC”.

The Company’s focus is the acquisition, exploration, development and production of crude oil and natural gas properties, primarily in the Bakken and Three Forks trends in North Dakota and Montana.  We believe that our prospective success revolves around our ability to acquire mineral rights and participate in drilling activities by virtue of our ownership of such rights and through the relationships we have developed with our operating partners.

As a non-operating working interest partner, we participate in drilling activities primarily on a heads-up basis.  Before a well is spud, an operator is required to offer all mineral lease owners in the designated well spacing unit the right to participate in the drilling and production of the well.  Drilling costs and revenues from oil and gas sales are split pro-rata based on acreage ownership in the designated drilling unit.  We rely on our operator partners to identify specific drilling sites, permit, and engage in the drilling process.  As a non-operator we are focused on maintaining a low overhead structure.

We commenced our oil and gas business in the fall of 2010 and, although we had successful discoveries late in 2010, we had no proven oil reserves at the end of 2010.  We completed our initial reservoir engineering calculations in the quarter ended June 30, 2011.  Our goal is to deploy our capital to maximize our oil and gas production and reserves.


Note 2 – Basis of Presentation and Significant Accounting Policies

The interim condensed financial statements included herein, presented in accordance with United States generally accepted accounting principles and stated in US dollars, have been prepared by the Company, without audit, pursuant to the rules and regulations of the Securities and Exchange Commission. Certain information and footnote disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles have been condensed or omitted pursuant to such rules and regulations, although the Company believes that the disclosures are adequate to not make the information presented misleading.

These statements reflect all adjustments, which in the opinion of management, are necessary for fair presentation of the information contained therein. Except as otherwise disclosed, all such adjustments are of a normal recurring nature. It is suggested that these interim condensed financial statements be read in conjunction with the audited financial statements for the year ended December 31, 2010, which were included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2010.  The Company follows the same accounting policies in the preparation of interim reports.

Ante5, Inc.
Notes to Condensed Financial Statements
 (Unaudited)

Former Development Stage Company
Prior to 2011, the Company was considered a development stage company as defined by FASB ASC 915-10-05.  As a development stage enterprise, the Company had disclosed the deficit accumulated during the development stage and the cumulative statements of operations and cash flows from inception to the current balance sheet date.  An entity remains in the development stage until such time as, among other factors, revenues have been realized.  The Company’s realized revenues and oil & gas operations in 2011 met this criteria, as such, the Company is no longer a development stage company and, accordingly, the cumulative statements of operations and cash flows from inception to the current balance sheet date have not been presented.

Comparative Periods
The Company was spun-off from an unrelated business in April of 2010.  As a result, the comparative financial statements for the three and six month periods ended June 30, 2010 are based on a short period.

Use of Estimates
The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amount of revenues and expenses during the reporting period. Actual results could differ from those estimates.

The oil and gas industry is subject, by its nature, to environmental hazards and clean-up costs.  At this time, management knows of no substantial losses from environmental accidents or events for which the Company may be currently liable.

Cash and Cash Equivalents
Cash equivalents include money market accounts which have maturities of three months or less.  For the purpose of the statements of cash flows, all highly liquid investments with an original maturity of three months or less are considered to be cash equivalents.  Cash equivalents are stated at cost plus accrued interest, which approximates market value.  Cash and cash equivalents consist of the following:

    June 30,     December 31,  
    2011     2010  
Cash
  $ 108,193     $ 131,859  
Money market funds
    2,127,821       8,445,751  
Total
  $ 2,236,014     $ 8,557,610  

Cash in Excess of FDIC Insured Limits
The Company maintains its cash in bank deposit accounts which, at times, may exceed federally insured limits.  Accounts are guaranteed by the Federal Deposit Insurance Corporation (FDIC) up to $200,000.  At June 30, 2011, the Company had approximately $1,926,800 in excess of FDIC insured limits.  The Company has not experienced any losses in such accounts.

Website Development Costs
The Company accounts for website development costs in accordance with ASC 350-50, “Accounting for Website Development Costs” (“ASC 350-50”), wherein website development costs are segregated into three activities:

 
1)
Initial stage (planning), whereby the related costs are expensed.

 
2)
Development (web application, infrastructure, graphics), whereby the related costs are capitalized and amortized once the website is ready for use. Costs for development content of the website may be expensed or capitalized depending on the circumstances of the expenditures.

 
3)
Post-implementation (after site is up and running: security, training, admin), whereby the related costs are expensed as incurred. Upgrades are usually expensed, unless they add additional functionality.

All website development costs from inception through the date of this report have been incurred pursuant to the initial planning stage. As a result, all costs have been expensed as incurred.
 
Ante5, Inc.
Notes to Condensed Financial Statements
 (Unaudited)
 
Income Taxes
Ante5 recognizes deferred tax assets and liabilities based on differences between the financial reporting and tax basis of assets and liabilities using the enacted tax rates and laws that are expected to be in effect when the differences are expected to be recovered.  Ante5 provides a valuation allowance for deferred tax assets for which it does not consider realization of such assets to be more likely than not.

Segment Reporting
Under FASB ASC 280-10-50, the Company operates as a single segment and will evaluate additional segment disclosure requirements as it expands its operations.

Fair Value of Financial Instruments
Under FASB ASC 820-10-05, the Financial Accounting Standards Board establishes a framework for measuring fair value in generally accepted accounting principles and expands disclosures about fair value measurements.  This Statement reaffirms that fair value is the relevant measurement attribute.  The adoption of this standard did not have a material effect on the Company’s financial statements as reflected herein.  The carrying amounts of cash, accounts payable and accrued expenses reported on the balance sheets are estimated by management to approximate fair value primarily due to the short term nature of the instruments.  The Company had no items that required fair value measurement on a recurring basis.

Non-Oil & Gas Property and Equipment
Property and equipment that are not oil and gas properties are recorded at cost and depreciated using the straight-line method over their estimated useful lives of three to seven years.  Expenditures for replacements, renewals, and betterments are capitalized.  Maintenance and repairs are charged to operations as incurred.  Long-lived assets, other than oil and gas properties, are evaluated for impairment to determine if current circumstances and market conditions indicate the carrying amount may not be recoverable.  The Company has not recognized any impairment losses on non-oil and gas long-lived assets.  Depreciation expense was $6,082 for the six months ended June 30, 2011.

Revenue Recognition and Gas Balancing
The Company recognizes oil and gas revenues from its interests in producing wells when production is delivered to, and title has transferred to, the purchaser and to the extent the selling price is reasonably determinable.  The Company uses the sales method of accounting for gas balancing of gas production and would recognize a liability if the existing proven reserves were not adequate to cover the current imbalance situation.

Full Cost Method
The Company follows the full cost method of accounting for oil and gas operations whereby all costs related to the exploration and development of oil and gas properties are initially capitalized into a single cost center ("full cost pool").  Such costs include land acquisition costs, geological and geophysical expenses, carrying charges on non-producing properties, costs of drilling directly related to acquisition, and exploration activities.

Proceeds from property sales will generally be credited to the full cost pool, with no gain or loss recognized, unless such a sale would significantly alter the relationship between capitalized costs and the proved reserves attributable to these costs.  A significant alteration would typically involve a sale of 25% or more of the proved reserves related to a single full cost pool.  As of June 30, 2011, the Company has had no property sales.

The Company assesses all items classified as unevaluated property on a quarterly basis for possible impairment or reduction in value.  The assessment includes consideration of the following factors, among others: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; the assignment of proved reserves; and the economic viability of development if proved reserves are assigned.  During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to amortization.  As of June 30, 2011, the Company had no impairment or reduction in value within costs subject to the depletion calculation.
 
Ante5, Inc.
Notes to Condensed Financial Statements
 (Unaudited)
 
Capitalized costs associated with impaired properties and properties having proved reserves, estimated future development costs, and asset retirement costs under FASB ASC 410-20-25 are depleted and amortized on the unit-of-production method based on the estimated gross proved reserves as determined by independent petroleum engineers.  The costs of unproved properties are withheld from the depletion base until such time as they are either developed or abandoned.

Capitalized costs of oil and gas properties (net of related deferred income taxes) may not exceed an amount equal to the present value, discounted at 10% per annum, of the estimated future net cash flows from proved oil and gas reserves plus the cost of unproved properties (adjusted for related income tax effects).  Should capitalized costs exceed this ceiling, impairment is recognized.  The present value of estimated future net cash flows is computed by applying the arithmetic average first day price of oil and natural gas for the preceding twelve months to estimated future production of proved oil and gas reserves as of the end of the period, less estimated future expenditures to be incurred in developing and producing the proved reserves and assuming continuation of existing economic conditions.  Such present value of proved reserves' future net cash flows excludes future cash outflows associated with settling asset retirement obligations.  Should this comparison indicate an excess carrying value, the excess is charged to earnings as an impairment expense.
 
Impairment
FASB ASC 360-10-35-21 requires that assets to be held and used be reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable.  Oil and gas properties accounted for using the full cost method of accounting (which the Company uses) are excluded from this requirement but continue to be subject to the full cost method's impairment rules.

FASB ASC 310-40 requires that impaired loans be measured based on the present value of expected future cash flows discounted at the loan’s effective interest rate or, as a practical expedient, at the loan’s observable market price or the fair value of the collateral if the loan is collateral dependent.  The Company considers the contingent consideration receivable received pursuant to a sale of substantially all of the assets of Ante4, Inc., as received in the spin-off on April 16, 2010, to be accounted for in accordance with ASC 310-40.  As such, we test for impairment annually using the present value of expected future net cash flows.

Basic and Diluted Loss Per Share
The basic net loss per common share is computed by dividing the net loss by the weighted average number of common shares outstanding. Diluted net loss per common share is computed by dividing the net loss adjusted on an “as if converted” basis, by the weighted average number of common shares outstanding plus potential dilutive securities.  For the six months ended June 30, 2011, potential dilutive securities had an anti-dilutive effect and were not included in the calculation of diluted net loss per common share.
 
Ante5, Inc.
Notes to Condensed Financial Statements
 (Unaudited)
Stock-Based Compensation
The Company adopted FASB guidance on stock based compensation upon inception at April 9, 2010. Under FASB ASC 718-10-30-2, all share-based payments to employees, including grants of employee stock options, are to be recognized in the income statement based on their fair values.  Pro forma disclosure is no longer an alternative.  Stock options issued for services and compensation totaled $312,262 for the six months ended June 30, 2011, using the Black-Scholes options pricing model and an effective term of 6 years based on the weighted average of the vesting period and the stated term of the option grants and the discount rate on 5 year U.S. Treasury securities at the grant date.

Uncertain Tax Positions
Effective upon inception at April 9, 2010, the Company adopted new standards for accounting for uncertainty in income taxes.  These standards prescribe a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return.  These standards also provide guidance on de-recognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition.

Various taxing authorities periodically audit the Company’s income tax returns.  These audits include questions regarding the Company’s tax filing positions, including the timing and amount of deductions and the allocation of income to various tax jurisdictions.  In evaluating the exposures connected with these various tax filing positions, including state and local taxes, the Company records allowances for probable exposures.  A number of years may elapse before a particular matter, for which an allowance has been established, is audited and fully resolved.  Ante5, Inc. has not yet undergone an examination by any taxing authorities.  Ante5 has indemnified Voyager Oil and Gas (Ante4), however, for any unrecognized liabilities which is limited to $2,500,000, and terminates on or about April 15, 2012.  In July of 2011 the Internal Revenue Service completed an examination of federal income tax returns of Voyager Oil and Gas (Ante4) for the years ended January 3, 2010 and December 28, 2008.  As a result of the examination Voyager Oil and Gas paid $11,417 of federal taxes and, based on the federal examination, filed amended state returns in California and paid an additional $48,666 in state taxes.  In addition, Voyager Oil and Gas paid an additional $37,903 in California payroll taxes related to an underpayment by Ante4 from 2010.  Ante5, Inc. reimbursed Voyager for $11,417 of these payments in June of 2011 and the remaining $86,569 was paid in July of 2011, and presented in accounts payable on the balance sheet at June 30, 2011, based on our indemnification agreement.

The assessment of the Company’s tax position relies on the judgment of management to estimate the exposures associated with the Company’s various filing positions.

Recent Accounting Pronouncements
In June 2011, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2011-05, “Comprehensive Income (Topic 220): Presentation of Comprehensive Income”, which is effective for annual reporting periods beginning after December 15, 2011.  ASU 2011-05 will become effective for the Company on January 1, 2012.  This guidance eliminates the option to present the components of other comprehensive income as part of the statement of changes in stockholders’ equity.  In addition, items of other comprehensive income that are reclassified to profit or loss are required to be presented separately on the face of the financial statements.  This guidance is intended to increase the prominence of other comprehensive income in financial statements by requiring that such amounts be presented either in a single continuous statement of income and comprehensive income or separately in consecutive statements of income and comprehensive income.  The adoption of ASU 2011-05 is not expected to have a material impact on our financial position or results of operations.

In May 2011, the FASB issued ASU 2011-04, “Fair Value Measurement (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs”, which is effective for annual reporting periods beginning after December 15, 2011.  This guidance amends certain accounting and disclosure requirements related to fair value measurements.  Additional disclosure requirements in the update include: (1) for Level 3 fair value measurements, quantitative information about unobservable inputs used, a description of the valuation processes used by the entity, and a qualitative discussion about the sensitivity of the measurements to changes in the unobservable inputs; (2) for an entity’s use of a nonfinancial asset that is different from the asset’s highest and best use, the reason for the difference; (3) for financial instruments not measured at fair value but for which disclosure of fair value is required, the fair value hierarchy level in which the fair value measurements were determined; and (4) the disclosure of all transfers between Level 1 and Level 2 of the fair value hierarchy.  ASU 2011-04 will become effective for the Company on January 1, 2012.  We are currently evaluating ASU 2011-04 and have not yet determined the impact that adoption will have on our financial statements.
 
In April 2011, the FASB issued ASU 2011-02, “Receivables (Topic 310): A Creditor’s Determination of Whether a Restructuring is a Troubled Debt Restructuring”. This amendment explains which modifications constitute troubled debt restructurings (“TDR”). Under the new guidance, the definition of a troubled debt restructuring remains essentially unchanged, and for a loan modification to be considered a TDR, certain basic criteria must still be met. For public companies, the new guidance is effective for interim and annual periods beginning on or after June 15, 2011, and applies retrospectively to restructuring occurring on or after the beginning of the fiscal year of adoption. The Company does not expect that the guidance effective in future periods will have a material impact on its financial statements.
 
Ante5, Inc.
Notes to Condensed Financial Statements
 (Unaudited)
 
Note 3 – Spin-Off

On April 16, 2010, the Company, formerly a wholly-owned subsidiary of Ante4, Inc., was spun-off. As a result, on June 14, 2010 the Company distributed a total of 21,292,333 shares to holders of record of Ante4, Inc. as of the close of trading on April 15, 2010 on a 1:1 basis.

The following table summarizes the fair value of assets acquired and liabilities assumed:

Assets acquired
     
Cash
  $ 258,712  
Accounts receivable
    33,708  
Investment in debt securities and related put rights
    3,708,363  
Contingent consideration receivable
    7,532,985  
Property and Equipment
    15,706  
Less: accumulated depreciation and depletion
    (11,620 )
Total assets acquired
    11,537,854  
Liabilities assumed
       
Accounts payable
    449,164  
Royalties payable
    415,000  
Line of credit
    2,437,336  
Notes payable
    500,000  
Deferred tax liability
    3,144,400  
Total fair value of assets, net of liabilities assumed
  $ 4,591,954  


Note 4 – Property and Equipment

Property and equipment at June 30, 2011 and December 31, 2010, consisted of the following:
 
   
June 30,
   
December 31,
 
   
2011
   
2010
 
Oil and gas properties, full cost method:
           
Unevaluated costs, not subject to amortization or ceiling test
  $ 13,132,727     $ 4,343,389  
Evaluated costs
    5,517,373       -  
      18,650,100       4,343,389  
Other property and equipment
    40,533       15,706  
      18,690,633       4,359,095  
Less: Accumulated depreciation, amortization and depletion
    (109,692 )     (13,725 )
Total property and equipment, net
  $ 18,580,941     $ 4,345,370  

The following table shows depreciation, depletion, and amortization expense by type of asset:
 
    June 30,     June 30,  
    2011     2010  
Depletion of costs for evaluated oil and gas properties
  $ 104,530     $ -  
Depreciation and amortization of other property and equipment
    6,082       619  
Total depreciation, amortization and depletion
  $ 110,612     $ 619  

Ante5, Inc.
Notes to Condensed Financial Statements
 (Unaudited)

Note 5 – Oil and Gas Properties

The following table summarizes gross and net productive oil wells by state at June 30, 2011.  A net well represents our percentage ownership of a gross well.  The following table does not include wells in which our interest is limited to royalty and overriding royalty interests.  The following table also does not include wells which were awaiting completion, in the process of completion or awaiting flow back subsequent to fracture stimulation.

   
June 30, 2011
 
   
Gross
   
Net
 
             
North Dakota
  11     0.45  
Total:
  11     0.45  

The Company’s oil and gas properties consist of all acreage acquisition costs (including cash expenditures and the value of stock consideration), drilling costs and other associated capitalized costs.  As of June 30, 2011 and December 31, 2010, our principal oil and gas assets included approximately 9,600 and 3,712 net acres, respectively, located in North Dakota.

In the third quarter of 2010, the Company acquired ownership interest in several mineral leases covering approximately 3,712 net acres.  In consideration for their assignment of these mineral leases, the Company paid the sellers a total of $2,969,648 of cash and issued to them 5,011,281 shares of our common stock, and assigned to the sellers a 2% overriding royalty interest in the mineral leases, effective on the closing.

In the first quarter of 2011, the Company has acquired at total of 1,974 net mineral acres.  In consideration for their assignment of these mineral leases, the Company paid a total of $2,410,032 of cash and issued 1,494,962 shares of our common stock.

In the second quarter of 2011, the company acquired a total of 3,953 net mineral acres.  In consideration for their assignment of these mineral leases, the Company paid a total of $2,830,925 of cash and issued 2,649,189 shares of our common stock.

The following table summarizes our capitalized costs for the purchase and development of our oil and gas properties for the six months ended June 30, 2011:

   
June 30, 2011
 
Purchases of oil and gas properties for cash
  $ 5,665,533  
Purchases of oil and gas properties for cash paid subsequent to June 30, 2011
    3,697,835  
Purchases of oil and gas properties through the issuance of common stock
    4,940,269  
Capitalized asset retirement obligations
    3,074  
Total purchase and development costs, oil and gas properties
  $ 14,306,711  

 
Note 6 – Related Party

Accounts Payable
As of June 30, 2011 we owed Voyager Oil and Gas (VOY), a Company that merged with our former parent company, Ante4, Inc., $120,000 related to sub-lease deposits to be repaid on office space leased in California, as well as, $48,666 in state taxes, based on an income tax examination related to the 2009 tax year.  In addition, VOY paid an additional $37,903 in California payroll taxes related to an underpayment by Ante4 from 2010.  The amounts have been included in accounts payable and total $206,569.  We have paid $86,569 of this amount subsequent to June 30, 2011.  We also incurred, and paid, VOY $11,417 on June 24, 2011 pursuant to a federal tax examination related to the 2009 federal tax year.

Option Awards
On February 22, 2011, we granted 500,000 stock options to James Moe, our chief financial officer.  The options vest annually over three years beginning on March 14, 2012 and are exercisable until February 21, 2021 at an exercise price of $1.65 per share.  The total estimated value using the Black-Scholes Pricing Model, based on a volatility rate of 108% and a call option value of $1.3661, was $683,070, and is being amortized over the implied service term, or vesting period, of the options.  The Company recognized $66,410 of compensation expense during the six months ended June 30, 2011.
 
Ante5, Inc.
Notes to Condensed Financial Statements
 (Unaudited)
Financing Arrangement
On May 2, 2011, we entered into a Revolving Credit and Security Agreement (the “Credit Agreement”) with certain lenders (collectively, the “Lenders” and individually a “Lender”) and Prenante5, LLC, as agent for the Lenders (PrenAnte5, LLC, in such capacity, the “Agent”).  The facility provides $10 million in financing to be made available for drilling projects on the Company’s North Dakota Bakken and Three Forks position.  The facility will be available for a period of three years over which time we may draw on the line seven times, pay the line down three times, and terminate the facility without penalty one time.  The facility sets the minimum total draw at $500,000 and requires Ante5, upon each draw, to provide the Lender with a compliance certificate that, along with other usual and customary financial covenants, states that Ante5 has at least twelve months interest coverage on its balance sheet in cash.

Morris Goldfarb, one of the Company’s directors, is participating as a Lender through the Agent with a commitment amount of $1.5 million in the facility.  In consideration for his participation through the agent, Mr. Goldfarb was issued 75,000 warrants (his pro-rata share as a Lender) with the same terms and conditions as the other warrants issued in connection with the closing of the Credit Agreement.  The warrants vest on the earlier of the 1 year anniversary of the grant date (May 2, 2012) or when 50% of the LOC has been advanced, and are exercisable until May 1, 2016 at an exercise price of $0.95 per share.  The total estimated value using the Black-Scholes Pricing Model, based on a volatility rate of 97% and a call option value of $0.7837, was $58,781, and is being amortized over the three year life of the credit agreement.  The Company recognized $3,266 of compensation expense during the six months ended June 30, 2011.

Other Related Party Transactions
Our former President and Chief Executive Officer, Steve Lipscomb, receives a commission of 5% of a royalty stream from Peerless Media Ltd., recorded on the balance sheet as a contingent consideration receivable, in perpetuity as a result of an incentive arrangement with Mr. Lipscomb that was approved by Ante4’s Board of Directors in February 2009.  Mr. Lipscomb has received a total of $4,320 in commissions during the six months ended June 30, 2011.  Mr. Lipscomb also has been retained as a consultant at a rate of $4,167 per month.  As of June 30, 2011 we owed Mr. Lipscomb $12,363 as reported within accounts payable on the balance sheet as of June 30, 2011.

We sublease office space on a month to month basis where the lessor is an entity owned by our CEO, Bradley Berman for approximately $1,053 per month.  We have paid a total of $6,647 to this entity during the six months ended June 30, 2011.

During the six months ended June 30, 2011, we paid $8,633 to an entity owned by our CEO, Bradley Berman for administrative services provided, of which, $3,451 remained unpaid and reported within accounts payable on the balance sheet as of June 30, 2011.


Note 7 – Contingent Consideration Receivable

As a result of a transaction between Ante4, Inc. (Ante4”) and Peerless Media Ltd. (“Buyer”) during fiscal year 2009, pursuant to which, Ante4 sold substantially all of its operating assets (the “Transaction”), Ante5, Inc. (the “Company”) as a result of the spin-off on April 16, 2010, is entitled to receive, in perpetuity, 5% of gross gaming revenue and 5% of other revenue of the Buyer generated by Ante4’s former business and assets that were sold to Buyer in the Transaction, subject to a 5% commission presented as Royalties Payable on the balance sheet. Buyer has guaranteed a minimum payment to us of $3 million for such revenue over the three-year period following the closing of the Transaction.  The Company prepared a discounted cash flow model to determine an estimated fair value of this portion of the purchase price as of November 2, 2009.  This value was recorded on the balance sheet of Ante4.  In connection with the spin-off described above, on April 16, 2010 Ante4 distributed this asset to its wholly-owned subsidiary, Ante5, Inc., which was spun-off and a registration statement was filed on Form 10-12/A, along with an Information Statement with the Securities and Exchange Commission for the purpose of spinning off the Ante5 shares from Ante4, Inc. to its stockholders of record on April 15, 2010.  We performed an impairment analysis as of December 31, 2010 which necessitated a write down and realization of an $878,650 valuation allowance, along with a corresponding adjustment of $80,057 to royalties payable.  The net amount resulted in the recognition of a $798,593 bad debt expense in the operating expense section of the statement of operations.  The following is a summary of the contingency consideration receivable and related royalties payable at June 30, 2011:
 
Ante5, Inc.
Notes to Condensed Financial Statements
 (Unaudited)
 
   
Contingent
         
Net Contingent
 
   
Consideration
   
Royalties
   
Consideration
 
   
Receivable
   
Payable
   
Receivable
 
Balance spun-off,
                 
April 16, 2010:
  $ 7,577,500     $ (415,000 )   $ 7,162,500  
Net royalties received and
                       
Commissions paid
    (226,850 )     11,343       (215,507 )
Fair value adjustment
    (878,650 )     80,057       (798,593 )
Balance, December 31, 2010
    6,472,000       (323,600 )     6,148,400  
Net royalties received and
                       
Commissions paid
    (85,343 )     4,319       (81,024 )
Balance, June 30, 2011
  $ 6,386,657     $ (319,281 )   $ 6,067,376  

The Company estimated its current portion of the contingent consideration receivable to be $250,000 based on the estimated net present value of royalties expected to be received in the 2011 calendar year.


Note 8 – Fair Value of Financial Instruments

The Company adopted FASB ASC 820-10 upon inception at April 9, 2010. Under FASB ASC 820-10-5, fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (an exit price). The standard outlines a valuation framework and creates a fair value hierarchy in order to increase the consistency and comparability of fair value measurements and the related disclosures. Under GAAP, certain assets and liabilities must be measured at fair value, and FASB ASC 820-10-50 details the disclosures that are required for items measured at fair value.

The Company does not have any financial instruments that must be measured under the new fair value standard.  The Company’s financial assets and liabilities are measured using inputs from the three levels of the fair value hierarchy.  The three levels are as follows:

Level 1 - Inputs are unadjusted quoted prices in active markets for identical assets or liabilities that the Company has the ability to access at the measurement date.

Level 2 - Inputs include quoted prices for similar assets and liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability (e.g., interest rates, yield curves, etc.), and inputs that are derived principally from or corroborated by observable market data by correlation or other means (market corroborated inputs).

Level 3 - Unobservable inputs that reflect our assumptions about the assumptions that market participants would use in pricing the asset or liability.


Note 9 – Changes in Stockholders’ Equity

Preferred Stock
On April 9, 2010 (inception) the Company authorized 20,000,000 shares of $0.001 par value preferred stock.  No shares have been issued to date.

Common Stock
On April 9, 2010 (inception) the Company authorized 100,000,000 shares of $0.001 par value common stock.
 
Ante5, Inc.
Notes to Condensed Financial Statements
 (Unaudited)
 
On February 11, 2011 we acquired additional oil and gas acreage from three unaffiliated sellers in two separate transactions encompassing mineral leases covering a total of approximately 117 net acres in Mountrail, Williams and Dunn counties in North Dakota for which we paid total cash of $215,975 and issued a total of 17,952 shares of our common stock.  The fair value of the common stock exchanged was $29,621 based on the closing stock price at the date of agreement.

On February 28, 2011, we closed an asset purchase agreement with certain sellers under which we acquired the sellers’ ownership interest in several mineral leases covering approximately 732 net acres of oil and gas properties in Williams, Mountrail, Dunn, Burke, Billings, Golden Valley, McKenzie and Stark counties in North Dakota.  In consideration for their assignment of these mineral leases, we paid the sellers a total of $821,270 of cash and issued to them 205,050 shares of our common stock.  The fair value of the common stock exchanged was $328,080 based on the closing stock price at the date of agreement.

On March 16, 2011, we closed an asset purchase agreement with certain sellers under which we acquired the sellers’ ownership interest in several mineral leases covering approximately 1,105 net acres of undeveloped oil and gas properties and 20 net acres of developed producing properties in Mountrail, Williams and Burke Counties in North Dakota in the Williston Basin.  In consideration for their assignment of the mineral leases, we paid the sellers a total of $1,372,787 of cash and issued to them 871,960 shares of our common stock, and issued an additional 400,000 shares of our common stock to an unaffiliated designee of the sellers.  The fair value of the common stock exchanged was $1,933,379 based on the closing stock price at the date of agreement.

On March 18, 2011 a total of 24,000 options were exercised for total proceeds of $7,800.  The shares were subsequently issued on April 4, 2011.

On April 5, 2011, the Company acquired a total of 116 net mineral acres of undeveloped oil and gas properties located in Mountrail and Williams Counties within North Dakota.  In consideration for the assignment of these mineral leases, the Company paid a total of $145,025 of cash and issued 55,689 shares of our common stock.  The fair value of the common stock exchanged was $70,725 based on the closing stock price at the date of agreement.

On April 28, 2011, the Company acquired a total of 3,837 net mineral acres of undeveloped oil and gas properties located in Dunn County, North Dakota.  In consideration for the assignment of these mineral leases, the Company paid a total of $2,685,900 of cash and issued 2,302,200 shares of our common stock.  The fair value of the common stock exchanged was $2,578,464 based on the closing stock price at the date of agreement.

On May 18, 2011 a total of 24,000 options were exercised by our CEO in exchange for total proceeds of $7,800.  No other options were exercised during the six month period ending June 30, 2011.

Stock Distribution
On June 14, 2010, Ante4, Inc. distributed 21,292,333 shares of the common stock of the Company among Ante4, Inc.’s shareholders pursuant to the spin-off of the Company from Ante4, Inc.  Each shareholder of record was issued one share of Ante5, Inc. common stock for each share of Ante4, Inc. common stock owned by the shareholder.


Note 10 – Warrants and Options

Options and Warrants Granted
On February 22, 2011, we granted 500,000 stock options to James Moe, our chief financial officer.  The options vest annually over three years beginning on March 14, 2012 and are exercisable until February 21, 2021 at an exercise price of $1.65 per share.  The total estimated value using the Black-Scholes Pricing Model, based on a volatility rate of 108% and a call option value of $1.3661, was $683,070, and is being amortized over the implied service term, or vesting period, of the options.  The Company recognized $66,410 of compensation expense during the six months ended June 30, 2011.
 
Ante5, Inc.
Notes to Condensed Financial Statements
 (Unaudited)
 
On May 2, 2011, we entered into a Revolving Credit and Security Agreement (the “Credit Agreement”) with certain lenders (collectively, the “Lenders” and individually a “Lender”) and Prenante5, LLC, as agent for the Lenders (PrenAnte5, LLC, in such capacity, the “Agent”).  The facility provides $10 million in financing to be made available for drilling projects on the Company’s North Dakota Bakken and Three Forks position.  The facility will be available for a period of three years over which time we may draw on the line seven times, pay the line down three times, and terminate the facility without penalty one time.  The facility sets the minimum total draw at $500,000 and requires Ante5, upon each draw, to provide the Lender with a compliance certificate that, along with other usual and customary financial covenants, states that Ante5 has at least twelve months interest coverage on its balance sheet in cash.

In connection with the closing of the Credit Agreement on May 2, 2011, the Company issued to each Lender a five-year warrant to purchase a number of shares of the Company’s common stock equal to an amount determined by multiplying 500,000 by such Lender’s commitment percentage.  The warrants vest on the earlier of the 1 year anniversary of the grant date (May 2, 2012) or when 50% of the LOC has been advanced, and are exercisable until May 1, 2016 at an exercise price of $0.95 per share.  The total estimated value using the Black-Scholes Pricing Model, based on a volatility rate of 97% and a call option value of $0.7837, was $391,872, and is being amortized over the three year life of the credit agreement.  The Company recognized a total of $21,772 of interest expense during the six months ended June 30, 2011.

In the event of a Lender default (i.e. failure to fund its pro rata commitment), the interest rate on such defaulting Lender’s advances (but not on any non-defaulting Lender’s advances) is automatically reduced from 19% to 12% per annum, and the Company has all other remedies available at law or in equity.  In addition, if the Lender default occurs prior to the earlier to occur of (i) May 2, 2012, or (ii) the date the defaulting Lender has made advances in an amount greater than fifty percent (50%) of its commitment amount, the Company is entitled to cancel all of the defaulting Lender’s then-outstanding warrant and shares of Company common stock issued or issuable upon the exercise of the warrant.

Options Exercised
On March 18, 2011 a total of 24,000 options were exercised for total proceeds of $7,800.  The shares were subsequently issued on April 4, 2011.

On May 18, 2011 a total of 24,000 options were exercised by our CEO in exchange for total proceeds of $7,800.  No other options were exercised during the six month period ending June 30, 2011.


Note 11 – Asset Retirement Obligation

The Company has asset retirement obligations associated with the future plugging and abandonment of proved properties and related facilities.  Under the provisions of FASB ASC 410-20-25, the fair value of a liability for an asset retirement obligation is recorded in the period in which it is incurred and a corresponding increase in the carrying amount of the related long lived asset.  The liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset.  If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized.  The Company has no assets that are legally restricted for purposes of settling asset retirement obligations.

The following table summarizes the Company’s asset retirement obligation transactions recorded in accordance with the provisions of FASB ASC 410-20-25 during the six months ended June 30, 2011:

    June 30, 2011  
Beginning Asset Retirement Obligation
 
$
-
 
Liabilities Incurred for New Wells Placed in Production
 
3,074
 
Accretion of Discount on Asset Retirement Obligations
 
266
 
Ending Asset Retirement Obligation
 
$
3,340
 

Ante5, Inc.
Notes to Condensed Financial Statements
 (Unaudited)
 
Note 12 – Income Taxes

The Company accounts for income taxes under ASC Topic 740, Income Taxes, which provides for an asset and liability approach of accounting for income taxes.  Under this approach, deferred tax assets and liabilities are recognized based on anticipated future tax consequences, using currently enacted tax laws, attributed to temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts calculated for income tax purposes.

We currently estimate that our effective tax rate for the year ending December 31, 2011 will be approximately 40%.  Losses incurred during the period from April 9 (inception) to June 30, 2011 as well as additional losses incurred during the remainder of 2011 could be used to offset future tax liabilities.  Accounting standards require the consideration of a valuation allowance for deferred tax assets if it is “more likely than not” that some component or all of the benefits of deferred tax assets will not be realized.  As of June 30, 2011, net deferred tax assets were $-0- after a 100% valuation allowance applied to net deferred tax assets of approximately $454,000.  We have not provided a valuation allowance against our tax liability.  As of June 30, 2011, the Company recognized a deferred tax liability of $2,360,800 related to income taxes on a net contingent consideration receivable resulting from the sale of assets to Party Gaming during 2009.

In accordance with FASB ASC 740, the Company has evaluated its tax positions and determined there are no significant uncertain tax positions as of any date on or before June 30, 2011.


Note 13 – Subsequent Events

Common Stock
On July 26, 2011, we closed on a Securities Purchase Agreement (the “Purchase Agreement”) with multiple accredited investors (the “Purchasers”) to sell 6,142,500 units (“Units”) at a price of $1.00 per Unit, with each Unit consisting of one share of our common stock and a five-year warrant to purchase one-half of one share of the Company’s common stock for a total of 3,071,250 shares at an exercise price of $1.50 per share (the “Offering”).  The Company may redeem outstanding warrants prior to their expiration, at a price of $0.01 per share, provided that the volume weighted average sale price per share of Common Stock equals or exceeds $2.50 per share for ten (10) consecutive trading days ending on the third business day prior to the mailing of notice of such redemption and provided that a resale registration statement with respect to exercise of the warrants is declared effective.  Net proceeds to the Company from the sale of the Units, after deducting selling commissions and offering expenses, were approximately $5.6 million.

The Company agreed to pay the agents in connection with this offering an aggregate fee equal to 7.0% of the gross proceeds from the sale of the Units in the Offering.  Additionally, the Company will be required to issue warrants to the agents to purchase an aggregate of 307,125 shares of the Company’s common stock at an exercise price of $1.00 per share to the Agents (the “Agents’ Warrants”).
 
On July 7, 2011 a total of 12,000 options were exercised at various prices between $0.05 and $0.29 per share, resulting in the receipt of total proceeds of $1,680.
 
Acquisitions of Acreage
On August 9, 2011, the Company acquired a total of 636 net mineral acres of undeveloped oil and gas properties located in Mountrail, Williams, Dunn and Billings Counties within North Dakota.  In consideration for the assignment of these mineral leases, the Company paid a total of $1,413,659.
 
 

Cautionary Statements

We are including the following discussion to inform our existing and potential security holders generally of some of the risks and uncertainties that can affect our company and to take advantage of the “safe harbor” protection for forward-looking statements that applicable federal securities law affords.

From time to time, our management or persons acting on our behalf may make forward-looking statements to inform existing and potential security holders about our company. All statements other than statements of historical facts included in this report regarding our financial position, business strategy, plans and objectives of management for future operations and industry conditions are forward-looking statements. When used in this report, forward-looking statements are generally accompanied by terms or phrases such as “estimate,” “project,” “predict,” “believe,” “expect,” “anticipate,” “target,” “plan,” “intend,” “seek,” “goal,” “will,” “should,” “may” or other words and similar expressions that convey the uncertainty of future events or outcomes. Items making assumptions regarding actual or potential future sales, market size, collaborations, trends or operating results also constitute such forward-looking statements.

Forward-looking statements involve inherent risks and uncertainties, and important factors (many of which are beyond our control) that could cause actual results to differ materially from those set forth in the forward-looking statements include the following:

 
·
volatility or decline of our stock price;
 
·
low trading volume and illiquidity of our common stock, and possible application of the SEC’s penny stock rules;
 
·
we are subject to certain contingent liabilities of our former parent company, and we have an indemnification obligation for certain liabilities, if any, that our former parent company may incur to a third party arising from pre-spin-off operations;
 
·
potential fluctuation in quarterly results;
 
·
our failure to earn revenues or to monetize claims that we have for payments owed to us;
 
·
material defaults on monetary obligations owed us, resulting in unexpected losses;
 
·
inadequate capital to acquire working interests in oil and gas prospects and to participate in the drilling and production of oil and other hydrocarbons;
 
·
unavailability of oil and gas prospects to acquire;
 
·
failure to discover or produce commercial quantities of oil, natural gas or other hydrocarbons;
 
·
cost overruns incurred on our oil and gas prospects, causing unexpected operating deficits;
 
·
drilling of dry holes;
 
·
acquisition of oil and gas leases that are subsequently lost due to the absence of drilling or production;
 
·
dissipation of existing assets and failure to acquire or grow a new business;
 
·
lower royalty income than anticipated or the absence of royalty income due to default or for other reasons; and
 
·
litigation, disputes and legal claims involving outside parties.

We have based these forward-looking statements on our current expectations and assumptions about future events. While our management considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks and uncertainties, most of which are difficult to predict and many of which are beyond our control. Accordingly, results actually achieved may differ materially from expected results in these statements. Forward-looking statements speak only as of the date they are made.

Readers are urged not to place undue reliance on these forward-looking statements. We assume no obligation to update any forward-looking statements in order to reflect any event or circumstance that may arise after the date of this report, other than as may be required by applicable law or regulation. Readers are urged to carefully review and consider the various disclosures made by us in our reports filed with the United States Securities and Exchange Commission (the “SEC”) which attempt to advise interested parties of the risks and factors that may affect our business, financial condition, results of operation and cash flows. If one or more of these risks or uncertainties materialize, or if the underlying assumptions prove incorrect, our actual results may vary materially from those expected or projected.
 
 
Overview and Outlook

We are an oil and natural gas exploration and production company.  Our properties are located in North Dakota.  Our corporate strategy is the acquisition, exploration, development and production of crude oil and natural gas properties, primarily in the Bakken and Three Forks trends in North Dakota and Montana.  As of June 30, 2011, we controlled the rights to mineral leases covering approximately 9,600 net acres for prospective drilling to the Bakken and/or Three Forks formations.  Looking forward, we are pursuing the following objectives:

 
Acquire high-potential mineral leases;
 
Access appropriate capital markets to fund continued acreage acquisition and drilling activities;
 
Develop and maintain strategic industry relationships;
 
Attract and retain talented associates;
 
Operate a low overhead non-operator business model; and
 
Become a low cost producer of hydrocarbons.

We are formerly a wholly-owned subsidiary of Ante4, Inc., which spun us off to its shareholders of record on or about April 16, 2010.  Ante4 formerly operated as WPT Enterprises, Inc. when it created internationally branded entertainment and consumer products driven by the development, production and marketing of televised programming based on gaming themes.  On November 2, 2009, Ante4 closed a transaction with Peerless Media, Ltd., a subsidiary of PartyGaming, PLC.  In the transaction, Ante4 sold to PartyGaming substantially all of Ante4’s operating assets other than cash, investments and certain excluded assets.  As a result of closing the transaction, Ante4 no longer operated a substantial portion of the WPT business.  In connection with the transaction, Ante4 retained the rights to a future Royalty Stream from the operation of the WPT business by Peerless Media, and certain other assets. Ante4 then transferred substantially all of those assets to us when we were a wholly-owned subsidiary of Ante4.  As the owner of these historical assets, we have succeeded to Ante4’s rights to the Royalty Stream and other claims, which we intend to monetize and manage.

Production History

The following table presents information about our produced oil and gas volumes during the three and six months ended June 30, 2011.  As of June 30, 2011, we were selling oil and natural gas from a total of 11 gross wells (approximately 0.45 net wells).  All data presented below is derived from accrued revenue and production volumes for the relevant period indicated.  We entered into the oil & gas industry in October of 2010, as such, we do not have information to present for the comparative periods ended June 30, 2010.

   
For the Three
   
For the Six
 
   
Months Ended
   
Months Ended
 
   
June 30, 2011
   
June 30, 2011
 
Net Production:
           
Oil (Bbl)
    2,579       3,740  
Natural Gas (Mcf)
    161       721  
Barrel of Oil Equivalent (Boe)
   
2,606
      3,860  
                 
Average Sales Prices:
               
Oil (per Bbl)
  $ 96.47     $ 91.98  
Effect of oil hedges on average price (per Bbl)
  $ -     $ -  
Oil net of hedging (per Bbl)
  $ 96.47     $ 91.98  
Natural Gas (per Mcf)
  $ 5.89     $ 4.95  
Effect of natural gas hedges on average price (per Mcf)
  $ -     $ -  
Natural gas net of hedging (per Mcf)
  $ 5.89     $ 4.95  
                 
Average Production Costs:
               
Oil (per Bbl)
  $ 4.47     $ 4.49  
Natural Gas (per Mcf)
  $ 0.28     $ 0.28  
Barrel of Oil Equivalent (Boe)
  $ 4.44     $ 4.40  

 
Reserves
We completed our initial reservoir engineering calculations as of June 30, 2011.  Preparation of our reserve report is outlined in our Sarbanes-Oxley Act Section 404 internal control procedures.  Our procedures require that our reserve report be prepared by a third-party registered independent engineering firm at the end of every year based on information we provide to such engineer.  Because we had an immaterial number of producing wells as of December 31, 2010, it was impractical to complete an initial reserve report at that time.  We accumulate historical production data for our wells, calculate historical lease operating expenses and differentials, update working interests and net revenue interests, obtain updated authorizations for expenditure (“AFEs”) from our operations department and obtain geological and geophysical information from operators.  This data is forwarded to our third-party engineering firm for review and calculation.  Our Chief Executive Officer provides a final review of our reserve report and the assumptions relied upon in such report.

We have utilized Ryder Scott Company, LP (“Ryder Scott”), an independent reservoir engineering firm, as our third-party engineering firm with the preparation of our June 30, 2011 reserve report.  The selection of Ryder Scott is approved by our Audit Committee.  Ryder Scott is one of the largest reservoir-evaluation consulting firms and evaluates crude oil and natural gas properties and independently certifies petroleum reserves quantities for various clients throughout the United States and internationally.  Ryder Scott has substantial experience calculating the reserves of various other companies with operations targeting the Bakken and Three Forks formations and, as such, we believe Ryder Scott has sufficient experience to appropriately determine our reserves.  Ryder Scott utilizes proprietary technology, systems and data to calculate our reserves commensurate with this experience.

The proved reserves tables below summarize our estimated proved reserves as of June 30, 2011, based upon reports prepared by Ryder Scott.  The reports of our estimated proved reserves in their entirety are based on the information we provide to them.  Ryder Scott is a Colorado Registered Engineering Firm (F-1580).  Our primary contact at Ryder Scott is Thomas E. Venglar, Senior Petroleum Engineer. Mr. Venglar is a State of Colorado Licensed Professional Engineer (License #28846).

In accordance with applicable requirements of the SEC, estimates of our net proved reserves and future net revenues are made using average prices at the beginning of each month in the 12-month period prior to the date of such reserve estimates and are held constant throughout the life of the properties (except to the extent a contract specifically provides for escalation).

The reserves set forth in the Ryder Scott report for the properties are estimated by performance methods or analogy.  In general, reserves attributable to producing wells and/or reservoirs are estimated by performance methods such as decline curve analysis which utilizes extrapolations of historical production data.  Reserves attributable to non-producing and undeveloped reserves included in our report are estimated by analogy.  The estimates of the reserves, future production, and income attributable to properties are prepared using the economic software package PHDWin Petroleum Economic Evaluation Software, a copyrighted program of TRC Consultants, L.C.
 
 
To estimate economically recoverable crude oil and natural gas reserves and related future net cash flows, we consider many factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future of production rates.  Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be demonstrated to be economically producible based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined as of the effective date of the report.  With respect to the property interests we own, production and well tests from examined wells, normal direct costs of operating the wells or leases, other costs such as transportation and/or processing fees, production taxes, recompletion and development costs and product prices are based on the SEC regulations, geological maps, well logs, core analyses, and pressure measurements.

The reserve data set forth in the Ryder Scott report represents only estimates, and should not be construed as being exact quantities.  They may or may not be actually recovered, and if recovered, the actual revenues and costs could be more or less than the estimated amounts.  Moreover, estimates of reserves may increase or decrease as a result of future operations.

Reservoir engineering is a subjective process of estimating underground accumulations of crude oil and natural gas that cannot be measured in an exact manner.  There are numerous uncertainties inherent in estimating crude oil and natural gas reserves and their estimated values, including many factors beyond our control.  The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geologic interpretation and judgment.  As a result, estimates of different engineers, including those used by us, may vary.  In addition, estimates of reserves are subject to revision based upon actual production, results of future development and exploration activities, prevailing crude oil and natural gas prices, operating costs and other factors.  The revisions may be material.  Accordingly, reserve estimates are often different from the quantities of crude oil and natural gas that are ultimately recovered and are highly dependent upon the accuracy of the assumptions upon which they are based.  Our estimated net proved reserves, included in our SEC filings, have not been filed with or included in reports to any other federal agency.

We expect that our proved undeveloped reserves will continue to be converted to proved developed producing reserves as additional wells are drilled within our acreage.  For our initial reserve analysis we only included proved undeveloped reserves that were permitted or drilling.  We do not have any material amounts of proved undeveloped reserves that have remained undeveloped for five years or more.
 
SEC Pricing Proved Reserves(1)
 
                         
         
Natural
         
Pre-Tax
 
   
Crude Oil
   
Gas
   
Total
   
PV10%
 
   
(barrels)
   
(Mcf)
   
(BOE)(2)
   
Value(3)
 
PDP Properties
    178,438       80,584       191,869       6,120,624  
PDNP Properties
    -       -       -       -  
PUD Properties
    19,876       13,814       22,178       159,821  
Total Proved Properties
    198,314       94,398       214,047       6,280,445  
                                                
 
(1)
The SEC Pricing Proved Reserves table above values crude oil and natural gas reserve quantities and related discounted future net cash flows as of June 30, 2011 assuming a constant realized price of $81.08 per barrel of crude oil and a constant realized price of $4.00 per Mcf of natural gas. The values presented in both tables above were calculated by Ryder Scott.
 
 
(2)
BOE are computed based on a conversion ratio of one BOE for each barrel of crude oil and one BOE for every 6,000 cubic feet (i.e., 6 Mcf) of natural gas.
 
 
 
(3)
Pre-tax PV10% may be considered a non-GAAP financial measure as defined by the SEC and is derived from the standardized measure of discounted future net cash flows, which is the most directly comparable standardized financial measure. Pre-tax PV10% is computed on the same basis as the standardized measure of discounted future net cash flows but without deducting future income taxes. We believe Pre-tax PV10% is a useful measure for investors for evaluating the relative monetary significance of our crude oil and natural gas properties. We further believe investors may utilize our Pre-tax PV10% as a basis for comparison of the relative size and value of our reserves to other companies because many factors that are unique to each individual company impact the amount of future income taxes to be paid. Our management uses this measure when assessing the potential return on investment related to our crude oil and natural gas properties and acquisitions. However, Pre-tax PV10% is not a substitute for the standardized measure of discounted future net cash flows. Our Pre-tax PV10% and the standardized measure of discounted future net cash flows do not purport to present the fair value of our crude oil and natural gas reserves.  The pre-tax PV10% values of our Total Proved Properties in the tables above differ from the tables reconciling our pre-tax PV10% value on the following page of this Annual Report due to rounding differences in certain tables of Ryder Scott’s reserve report.
 
The tables above assume prices and costs discounted using an annual discount rate of 10% without future escalation, without giving effect to non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion and amortization, or federal income taxes. The “Pre-tax PV10%” values of our proved reserves presented in the foregoing tables may be considered a non-GAAP financial measure as defined by the SEC.

Uncertainties are inherent in estimating quantities of proved reserves, including many risk factors beyond our control. Reserve engineering is a subjective process of estimating subsurface accumulations of crude oil and natural gas that cannot be measured in an exact manner. As a result, estimates of proved reserves may vary depending upon the engineer valuing the reserves. Further, our actual realized price for our crude oil and natural gas is not likely to average the pricing parameters used to calculate our proved reserves. As such, the crude oil and natural gas quantities and the value of those commodities ultimately recovered from our properties will vary from reserve estimates.

Depletion of Oil and Natural Gas Properties

Our depletion expense is driven by many factors including certain exploration costs involved in the development of producing reserves, production levels and estimates of proved reserve quantities and future developmental costs.  The following table presents our depletion expenses for the three and six months ended June 30, 2011.

    For the Three    
For the Six
 
    Months Ended    
Months Ended
 
    June 30, 2011    
June 30, 2011
 
             
Depletion of oil and natural gas properties
  $ 68,382     $ 104,530  

Productive Oil Wells

The following table summarizes gross and net productive oil wells by state at June 30, 2011.  A net well represents our percentage ownership of a gross well.  The following table does not include wells in which our interest is limited to royalty and overriding royalty interests.  The following table also does not include wells which were awaiting completion, in the process of completion or awaiting flow back subsequent to fracture stimulation.

    June 30, 2011  
   
Gross
   
Net
 
             
North Dakota
    11       0.45  

Results of Operations for the Three Months Ended June 30, 2011 and the Period from April 9, 2010 (Inception) to June 30, 2010.

The following table summarizes selected items from the statement of operations for the three months ended June 30, 2011 and the period from April 9, 2010 (Inception) to June 30, 2010.

   
For the three
   
April 9, 2010
       
   
months ended
   
(Inception) to
   
Increase /
 
   
June 30, 2011
   
June 30, 2010
   
(Decrease)
 
                   
Oil and gas sales
  $ 250,590     $ -     $ 250,590  
                         
Operating expenses:
                       
Production expenses
    11,352       -       11,352  
Production taxes
    27,573       -       27,573  
General and administrative
    489,109       339,530       149,579  
Depletion of oil and gas properties
    68,382       -       68,382  
Accretion of discount on
                       
asset retirement obligations
    146       -       146  
Depreciation and amortization
    2,960       619       2,341  
Total operating expenses:
    599,522       (340,149 )     259,373  
                         
Net operating loss
    (348,932 )     (340,149 )     8,783  
                         
Total other income (expense)
    (124,281 )     (6,484 )     117,797  
                         
Loss before provision for income taxes
    (473,213 )     (346,633 )     126,580  
                         
Provision for income taxes
    57,900       -       57,900  
                         
Net (loss)
  $ (415,313 )   $ (346,633 )   $ 68,680  

The Company was established on April 9, 2010 (inception) and had limited operations during the period from April 9, 2010 (Inception) to June 30, 2010.  We did not begin acquiring oil and gas leases and participating in the drilling of wells in the Bakken and Three Forks trends in North Dakota and Montana until October of 2010.  As such, there were no comparative oil and gas related revenues and expenses during the period from April 9, 2010 (Inception) to June 30, 2010.

Revenues:

We recognized $250,590 in revenues from sales of crude oil and natural gas for the three months ended June 30, 2011.  These revenues are due to the drilling and development of producing wells.  We had eleven gross producing wells as of June 30, 2011, and an additional thirteen wells that were either in the drilling preparation, drilling, awaiting completion, or completing stages.

Expenses:

Production expenses and taxes

Our production expenses and taxes of $11,352 and $27,573 for the three months ended June 30, 2011 are comprised of certain production costs involved in the development of producing reserves in the Bakken formation.  Combined they represent approximately 16% of the oil and gas sales for the three month period ended June 30, 2011.

General and administrative expenses

General and administrative expenses for the three months ended June 30, 2011 were $489,109, compared to $339,530 for the period from April 9, 2010 (Inception) to June 30, 2010, an increase of $149,579, or 44%.  Our increase in general and administrative expenses was primarily due to increased compensation of employees and professionals needed to support our expanding operations as we grew our oil and gas operations.
 
 
Depletion of oil and natural gas properties

Our depletion expense is driven by many factors, including certain exploration costs involved in the development of producing reserves, production levels and estimates of proved reserve quantities and future developmental costs.  We obtained an independent engineering reserve report as of June 30, 2011 to calculate our depletion rate.  Our estimated depletion rate was determined based on the results of the engineering report.  We recognized depletion expense of $68,382 for the three months ended June 30, 2011.

Depreciation

Depreciation expense for the three months ended June 30, 2011 was $2,960, compared to $619 for the period from April 9, 2010 (Inception) to June 30, 2010, an increase of $2,341, or 378%.  The increased depreciation expense was due to the additional depreciation associated with the purchase of office equipment in 2011.  We anticipate quarterly depreciation of approximately $4,000 through the remainder of the year for 2011.

Net operating loss

The net operating loss for the three months ended June 30, 2011 was $348,932, compared to $340,149 for the period from April 9, 2010 (Inception) to June 30, 2010, an increase of $8,783, or 3%.  Our net operating loss consisted primarily of professional fees, officer salaries and depletion expense, netted against our oil and gas income, as we aggressively expanded our oil and gas business.

Other income and (expenses)

Other income and (expenses) for the three months ended June 30, 2011 was ($124,281), compared to ($6,484) for the period from April 9, 2010 (Inception) to June 30, 2010, an increase of $117,797, or 1,817%.  The net other income and (expenses) for the three months ended June 30, 2011 consisted of $256 of interest income earned on money market accounts, ($25,490) of interest expense, consisting of ($21,772) of expenses incurred on the issuances of 500,000 warrants, as well as, ($3,718) of professional fees incurred in obtaining a revolving credit and security agreement.  We also incurred a loss of ($1,061) on the disposal of assets, and ($97,686) of indemnification expenses related to payments made pursuant to previously unidentified tax obligations prior to our spin-off on April 16, 2010.  Our net other income and (expenses) for the period from April 9, 2010 (Inception) to June 30, 2010 consisted of $2,056 of interest income earned on money market accounts and ($8,540) of interest expense related to short term loan obligations that were subsequently repaid and satisfied in full.
 
Net loss

The net loss for the three months ended June 30, 2011 was $415,313, compared to $346,633 for the period from April 9, 2010 (Inception) to June 30, 2010, an increase of $68,680, or 20%.  Our net loss consisted primarily of professional fees, officer salaries and stock support services expense, netted against our oil and gas income and change in provision for income taxes, as we aggressively expanded our oil and gas operations.
 
 
Results of Operations for the Six Months Ended June 30, 2011 and the Period from April 9, 2010 (Inception) to June 30, 2010.

The following table summarizes selected items from the statement of operations for the six months ended June 30, 2011 and the period from April 9, 2010 (Inception) to June 30, 2010.

   
For the six
   
April 9, 2010
       
   
months ended
   
(Inception) to
   
Increase /
 
   
June 30, 2011
   
June 30, 2010
   
(Decrease)
 
                   
Oil and gas sales
  $ 347,530     $ -     $ 347,530  
                         
Operating expenses:
                       
Production expenses
    16,975       -       16,975  
Production taxes
    37,003       -       37,003  
General and administrative
    857,986       339,530       518,456  
Depletion of oil and gas properties
    104,530       -       104,530  
Accretion of discount on
                       
asset retirement obligations
    266       -       266  
Depreciation and amortization
    6,082       619       5,463  
Total operating expenses:
    (1,022,842 )     (340,149 )     682,693  
                         
Net operating loss
    (675,312 )     (340,149 )     335,163  
                         
Total other income (expense)
    (123,125 )     (6,484 )     116,641  
                         
Loss before provision for income taxes
    (798,437 )     (346,633 )     451,804  
                         
Provision for income taxes
    332,200       -       332,200  
                         
Net (loss)
  $ (466,237 )   $ (346,633 )   $ 119,604  

The Company was established on April 9, 2010 (inception) and had limited operations during the period from April 9, 2010 (Inception) to June 30, 2010.  We did not begin acquiring oil and gas leases and participating in the drilling of wells in the Bakken and Three Forks trends in North Dakota and Montana until October of 2010.  As such, there were no comparative oil and gas related revenues and expenses during the period from April 9, 2010 (Inception) to June 30, 2010.

Revenues:

We recognized $347,530 in revenues from sales of crude oil and natural gas for the six months ended June 30, 2011.  These revenues are due to the drilling and development of producing wells.  We had eleven gross producing wells as of June 30, 2011, and an additional thirteen wells that were either in the drilling preparation, drilling, awaiting completion, or completing stages.

Expenses:

Production expenses and taxes

Our production expenses and taxes of $16,975 and $37,003 for the six months ended June 30, 2011 are comprised of certain production costs involved in the development of producing reserves in the Bakken formation.  Combined they represent approximately 16% of the oil and gas sales for the six month period ended June 30, 2011.

General and administrative expenses

General and administrative expenses for the six months ended June 30, 2011 were $857,986, compared to $339,530 for the period from April 9, 2010 (Inception) to June 30, 2010, an increase of $518,456, or 153%.  Our increase in general and administrative expenses was primarily due to increased compensation of employees and professionals needed to support our expanding operations as we grew our oil and gas operations.
 
 
Depletion of oil and natural gas properties

Our depletion expense is driven by many factors, including certain exploration costs involved in the development of producing reserves, production levels and estimates of proved reserve quantities and future developmental costs.  We obtained an independent engineering reserve report as of June 30, 2011 to calculate our depletion rate.  Our estimated depletion rate was determined based on the results of the engineering report. We recognized depletion expense of $104,530 for the six months ended June 30, 2011.

Depreciation

Depreciation expense for the six months ended June 30, 2011 was $6,082, compared to $619 for the period from April 9, 2010 (Inception) to June 30, 2010, an increase of $5,463, or 883%.  The increased depreciation expense was due to the additional depreciation associated with the purchase of office equipment in 2011.  We anticipate quarterly depreciation of approximately $4,000 through the remainder of the year for 2011.

Net operating loss

The net operating loss for the six months ended June 30, 2011 was $675,312, compared to $340,149 for the period from April 9, 2010 (Inception) to June 30, 2010, an increase of $335,163, or 99%.  Our net operating loss consisted primarily of professional fees, officer salaries and depletion expense, netted against our oil and gas income, incurred as we expanded our oil and gas business.

Other income and (expenses)

Other income and (expenses) for the six months ended June 30, 2011 was ($123,125), compared to ($6,484) for the period from April 9, 2010 (Inception) to June 30, 2010, an increase of $116,641, or 1,799%.  The net other income and (expenses) for the six months ended June 30, 2011 consisted of $1,412 of interest income earned on money market accounts, ($25,490) of interest expense, consisting of ($21,772) of expenses incurred on the issuances of 500,000 warrants, as well as, ($3,718) of professional fees incurred in obtaining a revolving credit and security agreement.  We also incurred a loss of ($1,061) on the disposal of assets, and ($97,686) of indemnification expenses related to payments made pursuant to previously unidentified tax obligations prior to our spin-off on April 16, 2010.  Our net other income and (expenses) for the period from April 9, 2010 (Inception) to June 30, 2010 consisted of $2,056 of interest income earned on money market accounts and ($8,540) of interest expense related to short term loan obligations that were subsequently repaid and satisfied in full.

Net loss

The net loss for the six months ended June 30, 2011 was $466,237, compared to $346,633 for the period from April 9, 2010 (Inception) to June 30, 2010, an increase of $119,604, or 35%.  Our net loss consisted primarily of professional fees, officer salaries and stock support services expense, netted against our oil and gas income and change in provision for income taxes, as we aggressively expanded our oil and gas operations.
 
Liquidity and capital resources

The following table summarizes our total current assets, liabilities and working capital at June 30, 2011 and December 31, 2010.
 
 
   
June 30,
   
December 31,
 
   
2011
   
2010
 
Current Assets
  $ 2,911,915     $ 8,888,881  
                 
Current Liabilities
  $ 4,569,884     $ 892,628  
                 
Working Capital (Deficit)
  $ (1,657,969 )   $ 7,996,253  

While we have raised capital to meet our working capital and financing needs in the past, additional financing will be required in order to meet our current and projected cash requirements for the operation of our oil and gas business.  As of June 30, 2011, we had working capital (deficit) of ($1,657,969).

On July 26, 2011, we closed on a Securities Purchase Agreement (the “Purchase Agreement”) with multiple accredited investors (the “Purchasers”) to sell 6,142,500 units (“Units”) at a price of $1.00 per Unit, with each Unit consisting of one share of our common stock and a five-year warrant to purchase one-half of one share of the Company’s common stock for a total of 3,071,250 shares at an exercise price of $1.50 per share (the “Offering”).  The Company may redeem outstanding warrants prior to their expiration, at a price of $0.01 per share, provided that the volume weighted average sale price per share of Common Stock equals or exceeds $2.50 per share for ten (10) consecutive trading days ending on the third business day prior to the mailing of notice of such redemption and provided that a resale registration statement with respect to exercise of the warrants is declared effective.  Net proceeds to the Company from the sale of the Units, after deducting selling commissions and offering expenses, were approximately $5.6 million.

The Company agreed to pay the agents in connection with the offering an aggregate fee equal to 7.0% of the gross proceeds from the sale of the Units in the Offering.  Additionally, the Company will be required to issue warrants to purchase an aggregate of 307,125 shares of the Company’s common stock at an exercise price of $1.00 per share to the agents.
 
Revolving Credit Facility
Our revolving credit facility provides $10 million in financing to be made available for drilling projects on our North Dakota Bakken and Three Forks projects.  The facility is secured by substantially all of our assets and matures on May 2, 2014. We may draw on the facility seven times, repay amounts outstanding three times, and terminate the facility without penalty one time.  The facility provides that minimum advances must exceed $500,000 and requires Ante5, upon each draw, to provide the Lender with a compliance certificate that, along with other usual and customary financial covenants, states that Ante5 has at least twelve months interest coverage on its balance sheet in cash.

The facility is secured by substantially all our assets.  The facility requires us to maintain available cash in an amount not less than 12 months of the scheduled payment of interest on outstanding advances.

Interest on advances is payable quarterly.  Interest accrues on outstanding principal at the rate of 19% per annum, provided that we may in our sole discretion, elect to pay:
 
·
100% of the interest due and owing on each interest payment date in cash or
 
·
interest in cash at a rate per annum equal to 15% and to defer and add to the principal amount of the advances the balance of the interest due and owing, which we refer to as contingent interest.

If we elect the contingent interest option, each lender then has the option to either:
 
·
permit contingent interest to be deferred and added as an advance to the principal amount of such lender’s advances, or
 
·
be paid the contingent interest proposed for deferral in shares of our common stock having a value equal to the proposed deferral amount with respect to such lender’s advances.  The value of the shares of common stock issued will be equal to 85% of the average last sale price of the common stock that is quoted during the five trading days immediately preceding the last day of the calendar quarter for which the contingent interest payment is due.
 
In connection with the closing of the Credit Agreement on May 2, 2011, we issued to each Lender a five-year warrant to purchase a number of shares our common stock equal to an amount determined by multiplying 500,000 by such Lender’s commitment percentage, at an exercise price per share equal to $0.95 per share.  In the event of a Lender default (i.e. failure to fund its pro rata commitment), the interest rate on such defaulting Lender’s advances (but not on any non-defaulting Lender’s advances) is automatically reduced from 19% to 12% per annum, and we have all other remedies available at law or in equity.  In addition, if the Lender default occurs prior to the earlier to occur of (i) May 2, 2012, or (ii) the date the defaulting Lender has made advances in an amount greater than fifty percent (50%) of its commitment amount, we are entitled to cancel all of the defaulting Lender’s then-outstanding warrant and shares of our common stock issued or issuable upon the exercise of the warrant.

 
Morris Goldfarb, one of our directors, is participating as a Lender through the Agent with a commitment amount of $1.5 million in the facility.  In consideration for his participation through the Agent, Mr. Goldfarb was issued 75,000 warrants (his pro-rata share as a Lender) with an exercise price of $0.95 per share with the same terms and conditions as the other warrants issued in connection with the closing of the Credit Agreement.
 
Other
On March 18, 2011 a total of 24,000 options were exercised for total proceeds of $7,800.  The shares were subsequently issued on April 4, 2011.

On May 18, 2011 a total of 24,000 options were exercised by our CEO in exchange for total proceeds of $7,800.
 
We raised capital in 2010 for our oil and gas investments through a combination of private sales of our common stock and purchase money equity (shares of our common stock) issued to the sellers of oil and gas properties to us.  We anticipate additional capital or financing activities in 2011 and in future years to finance the costs of acquiring additional oil and gas acreage, which we intend to pursue.  We plan to utilize the proceeds to acquire properties and pay for the related drilling, completion and operating costs on our oil and gas prospects.  For drilling costs, we entered into a revolving credit agreement in May 2011.  We believe this facility will provide financing needed to fund our drilling needs for 2011.  However, we will continue to monitor our needs and increase or replace credit facility when necessary.  Should we not be able to secure additional financing when needed, we may not be able to grow and may be required to reduce the scope of our operations, any of which would have a material adverse effect on our business.  Our future capital requirements will depend on many factors, including the identification of additional oil and gas acreage and expansion opportunities, the frequency of drilling activities on our prospects, the cost and availability of third-party capital or financing, and our revenues, cash flow and operating costs.

We anticipate that we may incur operating losses in the next twelve months.  Although our revenues are expected to grow as our wells are placed into production, our revenues are not expected to exceed our investment and operating costs in 2011.  Our prospects must be considered in light of the risks, expenses and difficulties frequently encountered by companies in their early stage of operations.  To address these risks, we must, among other things, seek growth opportunities through investment and acquisitions in the oil and gas industry, effectively monitor and manage our claims for payments that are owed to us, implement and successfully execute our business strategy, respond to competitive developments, and attract, retain and motivate qualified personnel.  We cannot assure that we will be successful in addressing such risks, and the failure to do so could have a material adverse effect on our business prospects, financial condition and results of operations.

Satisfaction of our cash obligations for the next 12 months.

As of June 30, 2011, our balance of cash and cash equivalents was $2,236,014.  Our plan for satisfying our cash requirements for the next twelve months is through sale of shares of our common stock, third party financing, and/or traditional bank financing.  We may realize proceeds from our Royalty Stream payable to us by Peerless Media, Ltd. or from our lawsuit against Deloitte Touche, although we are not currently relying on those revenue sources because of our disputes with them.  Furthermore, royalties in excess of the minimum guarantee on the Royalty Stream are contingent on revenues earned by Peerless Media under the World Poker Tour brand name.  There is no assurance as to whether, or when, we will be paid royalties under our agreement with Peerless Media, Ltd. See “Part II, Item 1. Legal Proceedings.”

Summary of product and research and development that we will perform for the term of our plan.

We are not anticipating significant research and development expenditures in the near future.
 
 
Expected purchase or sale of plant and significant equipment.

We do not anticipate the purchase or sale of any plant or significant equipment as such items are not required by us at this time.

Significant changes in the number of employees.

As of June 30, 2011, we had three employees, our chief executive officer, Bradley Berman, and our chief operating officer, Joshua Wert, and our chief financial officer, James Moe.  We added a fourth employee in July of 2011, and intend to hire additional employees as demand necessitates as we expand operations.  Currently, there are no organized labor agreements or union agreements and we do not anticipate any in the future.

Assuming we are able to expand our oil and gas business and continue to acquire more mineral leases, we may need to hire additional employees.  In the interim, we intend to use the services of independent consultants and contractors to perform various professional services when appropriate.  We believe the use of third-party service providers may enhance our ability to control general and administrative expenses and operate efficiently.
 
Off-Balance Sheet Arrangements

In connection with the transfer of the Ante5 assets to us, we assumed certain liabilities of Ante4 relating to the previous WPT business.  We also agreed to indemnify Ante4 and related individuals from (a) liabilities and expenses relating to operations of Ante4 prior to the effective date of the merger between Ante4 and Plains Energy Investments, Inc., (b) operation or ownership of Ante5’s assets after the merger effective date, and (c) certain tax liabilities of Ante4. Ante5’s obligation to indemnify Ante4 for operations before the merger and such tax liabilities is limited to $2.5 million in the aggregate and terminates on or about April 15, 2012.

Critical Accounting Policies and Estimates

Our management’s discussion and analysis of financial conditions and results of operations is based on our financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States, or GAAP.  The preparation of these financial statements required us to make estimates and judgments that affect the reported amounts of assets, liabilities and expenses.  On an ongoing basis, we evaluate these estimates and judgments, including those described below.  We base our estimates on our historical experience and on various other assumptions that we believe to be reasonable under the circumstances.  These estimates and assumptions form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources.  Actual results and experiences may differ materially from these estimates.

While our significant accounting policies are more fully described in notes to our financial statements appearing elsewhere in this Form 10-Q, we believe that the following accounting policies are the most critical to aid you in fully understanding and evaluating our reported financial results and affect the more significant judgments and estimates that we used in the preparation of our financial statements.

Stock-Based Compensation

We have accounted for stock-based compensation under the provisions of FASB Accounting Standards Codification (ASC) 718-10-55 (Prior authoritative literature: FASB Statement 123(R), Share-Based Payment).  This statement requires us to record any expense associated with the fair value of stock-based compensation.  We used the Black-Scholes option valuation model to calculate stock based compensation at the date of grant.  Option pricing models require the input of highly subjective assumptions, including the expected price volatility.  Changes in these assumptions can materially affect the fair value estimate.

Full Cost Method

We follow the full cost method of accounting for oil and gas operations whereby all costs related to the exploration and development of oil and gas properties are initially capitalized into a single cost center (“full cost pool”).  Such costs include land acquisition costs, geological and geophysical expenses, carrying charges on non-producing properties, costs of drilling directly related to acquisitions, and exploration activities.



Commodity Price Risk

The price we receive for our crude oil and natural gas production will heavily influence 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 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 will generally increase or decrease 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.


Evaluation of Disclosure Controls and Procedures

We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed by the Company is recorded, processed, summarized, and reported within the time periods specified in the rules and forms of the Securities and Exchange Commission.

Our management, under the direction of our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the design and operation of our disclosure controls and procedures (as such terms are defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of June 30, 2011.  As part of such evaluation, management considered the matters discussed below relating to internal control over financial reporting. Based on this evaluation our management, including the Company’s Chief Executive Officer and Chief Financial Officer, has concluded that the Company’s disclosure controls and procedures were effective as of June 30, 2011 to ensure that the information required to be disclosed in our Exchange Act reports was recorded, processed, summarized and reported on a timely basis.

Internal Control over Financial Reporting

The Company’s Chief Executive Officer and Principal Financial Officer, are responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act).  Our internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes of accounting principles generally accepted in the United States.  Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Therefore, even those systems determined to be effective can provide only reasonable assurance of achieving their control objectives.

Changes in Internal Controls over Financial Reporting

In our annual report on Form 10-K for the year ended December 31, 2010, we identified the following material weaknesses in our internal control over financial reporting: (1) Documentation of all proper accounting procedures was not yet complete, and (2) during the audit of our financial statements as of and for the period ended December 31, 2010, our independent registered public accounting firm suggested a tax adjusting journal entry that was made by us in connection with the preparation of our audited financial statements.  We have engaged an outside professional tax accounting firm to assist as with our tax accounting for the preparation of our financial statements.  This firm assisted us with our tax accounting for the preparation of our financial statements for the fiscal quarter ended June 30, 2011 included in this quarterly report as well as the quarter ended March 31, 2011.  Accordingly, we believe that we no longer have a material weakness in connection with our tax accounting.  Furthermore, as of June 30, 2011, we had completed the preparation and implementation of the documentation that we need to comply with the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework.  As a result, we believe that we no longer have a material weakness in connection with our documentation of proper accounting procedures.  There were no other changes in the Company’s internal control over financial reporting identified in connection with the evaluation of it that occurred during the three month period ended June 30, 2011 that materially affected or are reasonably likely to materially affect the Company’s internal control over financial reporting.


PART II - OTHER INFORMATION


PartyGaming

We have a dispute with Peerless Media, Ltd., a subsidiary of ElectraWorks, Ltd., the primary operating subsidiary of PartyGaming, PLC, regarding their performance of obligations with respect to the WPT Business purchased by it from Ante4 in November 2009.  Accordingly, we have initiated arbitration.  The arbitration was brought pursuant to the arbitration agreement contained in the Asset Purchase Agreement (“APA”) between Peerless, a wholly owned subsidiary of PartyGaming, Plc, now bwin.party digital entertainment Plc, and World Poker Tour Enterprises, Inc. (“WPTE”), a predecessor in interest to Ante5.  The arbitration arises out of alleged representations and assurances made by Peerless and Jim Ryan (“Ryan”) to WPTE during the negotiation phase of the asset purchase of WPTE, upon which WPTE purports to have relied to its detriment and which WPTE contends resulted in breach of contract as well as tortious harm.  Ante5 seeks legal and equitable relief, including punitive damages.

Arbitral proceedings are pending before Judicial Arbitration and Mediation Services (JAMS) in Los Angeles, California.  The arbitration demand was filed on March 18, 2011, and the arbitration commenced on March 28, 2011.  Ante5, Inc. is the claimant. Named respondents are Peerless Media, Ltd. (“Peerless”), and Ryan.  Ryan filed a complaint in the U.S. District Court for the Central District of California on April 11, 2011, for declaratory relief that he is not required to arbitrate Ante5’s claims against him.  The federal action is ongoing.  The parties are currently engaged in discovery. The arbitration hearing is scheduled for January 2012.

Deloitte & Touche

Under our distribution (spin-off) agreement with Ante4, Inc., we were assigned rights under the claims in the case of WPT Enterprises, Inc. v. Deloitte & Touche, LLP, currently pending before the Superior Court of the State of California, County of Los Angeles.  The case is being handled by our attorneys on a contingency fee arrangement. The complaint in the case was filed in June 2007 and alleges claims for, among other things, breach of contract and professional negligence against Deloitte & Touche, LLP ("Deloitte").  The plaintiffs, former shareholders of WPT Enterprises, Inc. ("WPTE"), allege that Deloitte caused them substantial harm when Deloitte refused to consent to the use of its audit opinion letter in connection with WPTE proposed stock offering. The case is currently scheduled for trial in March 2012.



On May 5, 2011 we entered into a Credit and Security Agreement with several lenders and Prenante5, LLC, as agent for the several lenders, relating to a $10 million credit facility for use in financing drilling projects in the Company’s North Dakota Bakken and Three Forks positions.  In connection with the closing of the Credit and Security Agreement, we issued warrants to acquire 500,000 shares of our common stock at a price of $0.95 per share to the lenders, with each lender receiving a number of warrants equal to 500,000 multiplied by such lender’s commitment percentage under the Credit and Security Agreement.  The warrants issued to the lenders have an aggregate fair market value of $10,000.



None.





None.



Exhibit
 
Description
     
23.1
 
Consent of Ryder Scott Company LP
31.1
 
Section 302 Certification of Chief Executive Officer
31.2
 
Section 302 Certification of Chief Financial Officer
32.1
 
Section 906 Certification of Chief Executive Officer
32.2
 
Section 906 Certification of Chief Financial Officer
99.1
 
Report of Ryder Scott Company LP
101.INS  
XBRL Instance Document
101.SCH  
XBRL Schema Document
101.CAL  
XBRL Calculation Linkbase Document
101.DEF  
XBRL Definition Linkbase Document
101.LAB  
XBRL Label Linkbase Document
101.PRE  
XBRL Presentation Linkbase Document
 
 


Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
 
 
ANTE5, INC.
 
       
       
Dated: August 15, 2011
By:
/s/Bradley Berman  
         Bradley Berman, Chairman of the Board and Chief  
   
     Executive Officer (Principal Executive Officer)
 
       

Dated: August 15, 2011
By:
/s/James A. Moe  
         James A. Moe, Chief Financial Officer (Principal  
   
     Financial Officer)
 
       
 
 
 
 
 
 
 31