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Note 1 - Nature of Business and Summary of Significant Accounting Policies | 12 Months Ended
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Dec. 31, 2011
Business Description and Accounting Policies [Text Block] | Note 1 – Nature of Business and Summary of Significant Accounting Policies 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 believe 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 completed our initial reservoir engineering calculations as of June 30, 2011. Our goal is to deploy our capital to maximize our oil and gas production and reserves. 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 these criteria and, 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 year ended December 31, 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:
| December 31, |  | December 31, |
| 2011 |  | 2010 |
Cash |  | $ | 474,314 |  |  | $ | 131,859 |
Money market funds |  |  | 926,827 |  |  |  | 8,445,751 |
Total |  | $ | 1,401,141 |  |  | $ | 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 $250,000 under current regulations. The Company had approximately $650,165 and $8,045,000 in excess of FDIC insured limits At December 31, 2011 and 2010, respectively. 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.
We have capitalized a total of $53,000 of website development costs from inception through December 31, 2011. We have recognized depreciation expense on these website costs of $3,507 and $-0- as of December 31, 2011 and 2010, respectively. 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 $14,043 and $2,105 for the year ended December 31, 2011 and the period from inception (April 9, 2010) to December 31, 2010, respectively. 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. Asset Retirement Obligations The Company records the fair value of a liability for an asset retirement obligation in the period in which the well is spud or the asset is acquired 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. 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. Internal costs that are capitalized are directly attributable to acquisition, exploration and development activities and do not include costs related to the production, general corporate overhead or similar activities. Costs associated with production and general corporate activities are expensed in the period incurred. Capitalized costs are summarized as follows for the year ended December 31, 2011 and the period from April 9, 2010 (inception) to December 31, 2010, respectively:
| For the |  | April 9, 2010 |
| Year Ended |  | (inception) to |
| December 31, |  | December 31, |
| 2011 |  | 2010 |
Capitalized Certain Payroll and Other Internal Costs |  | $ | 138,591 |  |  | $ | 9,975 |
Capitalized Interest Costs |  |  | - |  |  |  | - |
Total |  | $ | 138,591 |  |  | $ | 9,975 |
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 20% or more of the proved reserves related to a single full cost pool. On December 30, 2011, the Company sold a total of approximately 123 net acres at $2,750 per acre for total proceeds of $336,925. 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. 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. We recognized $2,392,742 of impairment costs during the year ended December 31, 2011. 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 2011 and 2010, potential dilutive securities had an anti-dilutive effect and were not included in the calculation of diluted net loss per common share. 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. Common stock and stock options issued for services and compensation totaled $753,860 and $77,500 for the year ended December 31, 2011 and the period from April 9, 2010 (inception) to December 31, 2010, respectively, using the Black-Scholes options pricing model and an effective term of 6 to 6.5 years based on the weighted average of the vesting periods and the stated term of the option grants and the discount rate on 5 to 7 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, subject to customary exceptions from these limitations. 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 we reimbursed Voyager Oil and Gas for their payments of $11,417 of federal taxes and, based on the federal examination, amended state returns in California that totalled an additional $48,666 in state taxes. In addition, we reimbursed Voyager Oil and Gas for their payments of an additional $37,903 in California payroll taxes related to an underpayment by Ante4 from 2010. 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 September 2011, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2011-08, Intangibles – Goodwill and Other (Topic 350): Testing Goodwill for Impairment. The guidance in ASU 2011-08 is intended to reduce complexity and costs by allowing an entity the option to make a qualitative evaluation about the likelihood of goodwill impairment to determine whether it should calculate the fair value of a reporting unit. The amendments also improve previous guidance by expanding upon the examples of events and circumstances that an entity should consider between annual impairment tests in determining whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount. Also, the amendments improve the examples of events and circumstances that an entity having a reporting unit with a zero or negative carrying amount should consider in determining whether to measure an impairment loss, if any, under the second step of the goodwill impairment test. The amendments in this ASU are effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011. Early adoption is permitted, including for annual and interim goodwill impairment tests performed as of a date before September 15, 2011, if an entity’s financial statements for the most recent annual or interim period have not yet been issued. The adoption of this guidance is not expected to have a material impact on the Company’s financial position or results of operations. In June 2011, the FASB issued 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.

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