Sow Good Inc. - Quarter Report: 2012 September (Form 10-Q)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)

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

For Quarterly Period Ended September 30, 2012

or

£ 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

(Formerly Ante5, Inc.)

(Name of registrant in its charter)

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.

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).

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.

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

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 November 9, 2012 was 47,979,990.

TABLE OF CONTENTS 

BLACK RIDGE OIL & GAS, INC. (Formerly Ante5, Inc.)

CONDENSED BALANCE SHEETS

See accompanying notes to financial statements.

BLACK RIDGE OIL & GAS, INC. (Formerly Ante5, Inc.)

CONDENSED STATEMENTS OF OPERATIONS

(Unaudited)

See accompanying notes to financial statements.

BLACK RIDGE OIL & GAS, INC. (Formerly Ante5, Inc.)

CONDENSED STATEMENTS OF CASH FLOWS

(Unaudited)

See accompanying notes to financial statements.

BLACK RIDGE OIL & GAS, INC.

(Formerly Ante5, Inc.)

Notes to Condensed Financial Statements

(Unaudited)

Note 1 – Organization and Nature of Business

Effective April 2, 2012, Ante5, Inc. changed its corporate name to Black Ridge Oil & Gas, Inc., and continues to trade its common stock on the OTC QB and OTC BB under the trading symbol “ANFC”. Black Ridge Oil & Gas, Inc. (Formerly Ante5, Inc.) (the “Company”) became an independent company in April 2010 when the spin-off from our former parent company, Ante4, Inc. (now Emerald Oil, Inc. and also formerly known as 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.

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. 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, 2011, which were included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2011. The Company follows the same accounting policies in the preparation of interim reports.

Reclassifications

In the current year, the Company separately classified debt issuance costs in the Balance Sheets. For comparative purposes, amounts in the prior year have been reclassified to conform to current year presentation.

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.

BLACK RIDGE OIL & GAS, INC.

(Formerly Ante5, Inc.)

Notes to Condensed Financial Statements

(Unaudited)

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:

Cash in Excess of FDIC and SIPC 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) and the Securities Investor Protection Corporation (SIPC) up to $250,000 and $500,000, respectively, under current regulations. The Company had approximately $1,275,098 and $650,165 in excess of FDIC and SIPC insured limits as of September 30, 2012 and December 31, 2011, respectively. The Company has not experienced any losses in such accounts.

Debt Issuance Costs

Costs relating to obtaining certain debts are capitalized and amortized over the term of the related debt using the effective interest method. The unamortized balance of debt issuance costs at September 30, 2012, and December 31, 2011, was $674,983 and $52,049, respectively. Amortization of debt issuance costs charged to interest expense was $148,299 and $9,295 for the nine months ended September 30, 2012 and 2011, respectively. When a loan is paid in full, any unamortized financing costs are removed from the related accounts and charged to interest expense.

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:

We have capitalized a total of $56,660 of website development costs from inception through September 30, 2012. We depreciate our website development costs on a straight line basis over the estimated useful life of the assets, which is currently three years. We have recognized depreciation expense on these website costs of $13,908 and $-0- for the nine months ended September 30, 2012 and 2011, respectively.

Income Taxes

The Company 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. The Company provides a valuation allowance for deferred tax assets for which it does not consider realization of such assets to be more likely than not.

Net Income (Loss) Per Common Share 

Basic earnings per share (“EPS”) are computed by dividing net income (the numerator) by the weighted average number of common shares outstanding for the period (the denominator). Diluted EPS is computed by dividing net income by the weighted average number of common shares and potential common shares outstanding (if dilutive) during each period. Potential common shares include stock options, warrants and restricted stock. The number of potential common shares outstanding relating to stock options, warrants and restricted stock is computed using the treasury stock method.

BLACK RIDGE OIL & GAS, INC.

(Formerly Ante5, Inc.)

Notes to Condensed Financial Statements

(Unaudited)

The reconciliation of the denominators used to calculate basic EPS and diluted EPS for the three and nine months ended September 30, 2012 and 2011 are as follows:

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 and 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 $18,395 and $8,951 for the nine months ended September 30, 2012 and 2011, 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 nine months ended September 30, 2012 and 2011, respectively:

BLACK RIDGE OIL & GAS, INC.

(Formerly Ante5, Inc.)

Notes to Condensed Financial Statements

(Unaudited)

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. 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.

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 the Company, 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.

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 $1,137,513 and $535,579 for the nine months ended September 30, 2012 and 2011, respectively, including $438,539 and $43,120, respectively, of common stock valued at the fair market value based on the Company’s closing trading price on the date of grant, and $698,974 and $492,359, 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. In addition, $307,564 and $54,428 were amortized during the nine months ended September 30, 2012 and 2011, respectively, pursuant to warrants granted in consideration for credit facilities. The fair value of warrants is determined similar to the method used in determining the fair value of employee stock options and the fair value is amortized over the life of the related credit facility and accelerated upon termination of a credit facility.

BLACK RIDGE OIL & GAS, INC.

(Formerly Ante5, Inc.)

Notes to Condensed Financial Statements

(Unaudited)

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. Black Ridge Oil & Gas, Inc. (formerly Ante5, Inc.) has not yet undergone an examination by any taxing authorities. The Company had indemnified Emerald Oil, Inc. (formerly known as Voyager Oil and Gas formerly known as Ante4), however, for any unrecognized liabilities which was limited to $2,500,000, and terminated 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 Emerald Oil, Inc. (formerly known as Voyager Oil and Gas formerly known as Ante4) for the years ended January 3, 2010 and December 28, 2008. As a result of the examination we reimbursed Emerald Oil, Inc. (formerly known as Voyager Oil and Gas formerly known as Ante4) 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 Emerald Oil, Inc. (formerly known as Voyager Oil and Gas formerly known as Ante4) 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 October 2012, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2012-04, “Technical Corrections and Improvements” in Accounting Standards Update No. 2012-04. The amendments in this update cover a wide range of Topics in the Accounting Standards Codification. These amendments include technical corrections and improvements to the Accounting Standards Codification and conforming amendments related to fair value measurements. The amendments in this update will be effective for fiscal periods beginning after December 15, 2012. The adoption of ASU 2012-04 is not expected to have a material impact on our financial position or results of operations.

In August 2012, the FASB issued ASU 2012-03, “Technical Amendments and Corrections to SEC Sections: Amendments to SEC Paragraphs Pursuant to SEC Staff Accounting Bulletin (SAB) No. 114, Technical Amendments Pursuant to SEC Release No. 33-9250, and Corrections Related to FASB Accounting Standards Update 2010-22 (SEC Update)” in Accounting Standards Update No. 2012-03. This update amends various SEC paragraphs pursuant to the issuance of SAB No. 114. The adoption of ASU 2012-03 is not expected to have a material impact on our financial position or results of operations.

In July 2012, the FASB issued ASU 2012-02, “Intangibles – Goodwill and Other (Topic 350): Testing Indefinite-Lived Intangible Assets for Impairment” in Accounting Standards Update No. 2012-02. This update amends ASU 2011-08, Intangibles – Goodwill and Other (Topic 350): Testing Indefinite-Lived Intangible Assets for Impairment and permits an entity first to assess qualitative factors to determine whether it is more likely than not that an indefinite-lived intangible asset is impaired as a basis for determining whether it is necessary to perform the quantitative impairment test in accordance with Subtopic 350-30, Intangibles - Goodwill and Other - General Intangibles Other than Goodwill. The amendments are effective for annual and interim impairment tests performed for fiscal years beginning after September 15, 2012. Early adoption is permitted, including for annual and interim impairment tests performed as of a date before July 27, 2012, if a public entity’s financial statements for the most recent annual or interim period have not yet been issued or, for nonpublic entities, have not yet been made available for issuance. The adoption of ASU 2012-02 is not expected to have a material impact on our financial position or results of operations.

BLACK RIDGE OIL & GAS, INC.

(Formerly Ante5, Inc.)

Notes to Condensed Financial Statements

(Unaudited)

In December 2011, the FASB issued ASU 2011-12, “Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05. This update defers the requirement to present items that are reclassified from accumulated other comprehensive income to net income in both the statement of income where net income is presented and the statement where other comprehensive income is presented. The adoption of ASU 2011-12 is not expected to have a material impact on our financial position or results of operations.

In December 2011, the FASB issued ASU No. 2011-11 “Balance Sheet: Disclosures about Offsetting Assets and Liabilities” (“ASU 2011-11”). This Update requires an entity to disclose information about offsetting and related arrangements to enable users of its financial statements to understand the effect of those arrangements on its financial position. The objective of this disclosure is to facilitate comparison between those entities that prepare their financial statements on the basis of U.S. GAAP and those entities that prepare their financial statements on the basis of IFRS. The amended guidance is effective for annual reporting periods beginning on or after January 1, 2013, and interim periods within those annual periods. The Company is currently evaluating the impact, if any, that the adoption of this pronouncement may have on its results of operations or financial position.

Note 3 – Property and Equipment

Property and equipment at September 30, 2012 and December 31, 2011, consisted of the following:

The following table shows depreciation, depletion, and amortization expense by type of asset:

Note 4 – Oil and Gas Properties

The following table summarizes gross and net productive oil wells by state at September 30, 2012 and 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 drilling, awaiting completion, in the process of completion or awaiting flow back subsequent to fracture stimulation.

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 September 30, 2012 and 2011, our principal oil and gas assets included approximately 11,159 and 9,880 net acres, respectively, located in North Dakota.

BLACK RIDGE OIL & GAS, INC.

(Formerly Ante5, Inc.)

Notes to Condensed Financial Statements

(Unaudited)

The following table summarizes our capitalized costs for the purchase and development of our oil and gas properties for the nine months ended September 30, 2012 and 2011, respectively:

Acquisitions during the nine months ended September 30, 2012

On various dates during the nine months ended September 30, 2012, we purchased approximately 986 net mineral acres of oil and gas properties in North Dakota. In consideration for the assignment of these mineral leases, we paid the sellers a total of approximately $1,301,113. Of these acquisitions, 110 acres acquired on February 14, 2012 were acquired from the State of North Dakota. The operator of this well has filed a lawsuit against the state challenging the state’s ownership in these mineral rights. As a result, we have not capitalized any Authorization for Expenditure costs (“AFE”) or recognized any sales from this well. In the event the operator is successful in their litigation with the state, the state is required to refund our original purchase price for the lease.

2012 Divestitures

On various dates during the nine months ended September 30, 2012, we sold a total of approximately 283 net acres for total proceeds of $993,449. No gain or loss was recorded pursuant to the sales.

Acquisitions during the nine months ended September 30, 2011

On August 22, 2011, the Company acquired a total of 240 net mineral acres. In consideration for their assignment of these mineral leases, the Company paid a total of $720,667 of cash, including $667 of title fees.

On May 5, 2011, we closed an asset purchase agreement under which the Company acquired Sellers’ right, title, and interest in and to certain oil and gas mineral leases located in the Williston Basin in Dunn County, North Dakota covering a total of approximately 3,837 net acres. At the closing, the Company tendered a total of $2,685,900 of cash and delivered 2,302,200 shares of the Company’s common stock to the Sellers.

On April 5, 2011, we acquired 116 net acres of oil and gas mineral leases located in the Williston Basin in Dunn County, North Dakota. At the closing, the Company tendered a total of $145,025 of cash and delivered 55,689 shares of the Company’s common stock to the Sellers.

On March 16, 2011, we closed an asset purchase agreement with the Sellers under which we acquired 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 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.

On February 28, 2011, we closed an asset purchase agreement with the Sellers under which we acquired 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 Sellers a total of $821,270 of cash and issued to them 205,050 shares of our common stock.

BLACK RIDGE OIL & GAS, INC.

(Formerly 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.

2011 Divestitures

There were no divestitures during the nine months ended September 30, 2011.

Note 5 – 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 nine months ended September 30, 2012 and the year ended December 31, 2011:

Note 6 – Related Party

On June 1, 2012, our Board of Directors appointed our former CEO, Steven Lipscomb as Vice President. As a result of an incentive arrangement with Mr. Lipscomb that was approved by WPT Enterprises, Inc.’s Board of Directors in February 2009, Mr. Lipscomb will receive 5% of the settlement payments from the Peerless Media Ltd. litigation, net of attorneys’ fees and other costs, amounting to approximately $550,079, as such amounts are received by the Company. Additionally, as part of the incentive arrangement, Mr. Lipscomb received $26,468 in royalties during the nine months ended September 30, 2012, of which $16,116 were received while Mr. Lipscomb was Vice President of the Company.

We have subleased and now directly lease office space on a month to month basis where the lessor is an entity owned by our former CEO and current Chairman of the Board of Directors, Bradley Berman. The sublease agreement was cancelled and we entered into a direct lease on April 30, 2012 to expand and occupy approximately 1,142 square feet of office space. In accordance with this lease, our lease term remains on a month-to-month basis, provided that either party provide 90 day notice to terminate the lease, with base rents of $1,142 per month, plus common area operations and maintenance charges, and monthly parking fees of $240 per month, for the first year commencing on May 1, 2012, and increases of $24 per month for each of the subsequent four year periods. We have paid a total of $18,460 and $10,447 to this entity during the nine months ended September 30, 2012 and 2011, respectively.

During the nine months ended September 30, 2012 and 2011, we paid $0 and $10,562, respectively, for administrative services to an entity owned by our former CEO and current Chairman of the Board of Directors, Bradley Berman, of which $1,894 remained unpaid and reported within accounts payable on the balance sheet as of September 30, 2011. The Company no longer utilizes these related party administrative services.

BLACK RIDGE OIL & GAS, INC.

(Formerly Ante5, Inc.)

Notes to Condensed Financial Statements

(Unaudited)

Note 7 – Litigation Settlement and Contingent Consideration Receivable

As a result of a transaction between Ante4, Inc. (“Ante4”) and Peerless Media Ltd. (“Peerless”) during fiscal year 2009, pursuant to which, Ante4 sold substantially all of its operating assets (the “Transaction”), Ante5, Inc., now Black Ridge Oil & Gas, 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 Peerless generated by Ante4’s former business and assets that were sold to Peerless in the Transaction, subject to a 5% commission presented as Royalties Payable on the balance sheet. Peerless had guaranteed a minimum payment to the Company of $3 million for such revenue over the three-year period following the closing of the Transaction on November 2, 2009. 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. The following is a summary of the contingency consideration receivable and related royalties payable through September 30, 2012:

On September 27, 2012, the Company entered into a settlement agreement with Peerless and ElectraWorks, Ltd. (“ElectraWorks”) to settle all claims regarding their performance of obligations with respect to the business purchased by Peerless from Ante4, Inc. in November 2009 (the "Litigation"). The Litigation was pending before Judicial Arbitration and Mediation Services (JAMS) in Los Angeles, California. Under the settlement agreement, Peerless/ElectraWorks will pay the Company $13.5 million in the following installments: (i) $5.5 million payable on November 2, 2012, (ii) $5.5 million payable on December 31, 2012, and (iii) $2.5 million payable on December 31, 2013. In addition, Peerless/ElectraWorks will make payments to the Company upon certain contingencies related to the passage of federal or state legislation permitting real money online poker and Peerless/ElectraWorks or one of their affiliates obtaining such a license. The maximum amount of these contingent payments is $6.5 million with the amount determined based on how such legislation is enacted. Under the settlement agreement the Company has released its rights to the royalty stream and no further payments are due from Peerless/ElectraWorks other than those set forth in the settlement agreement.

The Company will pay attorneys’ fees of $2 million as well as various costs out of the proceeds. In addition, as a result of an incentive arrangement with the Company’s former President, Chief Executive Officer and Secretary and current Vice President, Steve Lipscomb that was approved by WPT Enterprises, Inc.’s Board of Directors in February 2009, Mr. Lipscomb will receive 5% of the settlement payments, net of attorneys’ fees and other costs; as such amounts are received by the Company.

The Company has recorded a receivable of $13.5 million for the litigation settlement, of which $2.5 million, is considered a long term receivable, and payables of $2.0 million and $550,079 related to contingent attorney’s fees and amounts due Mr. Lipscomb, respectively. The contingent consideration receivable of $5,479,241 and the royalty payable of $273,963 as of the settlement date were relieved as a part of the settlement resulting in a net gain of $5,744,643. The Company has expensed non-contingent expenses and fees associated with pursuing the settlement as those expenses and fees were incurred amounting to $333,176 and $144,574 for the nine month periods ended September 30, 2012 and 2011, respectively.

BLACK RIDGE OIL & GAS, INC.

(Formerly Ante5, Inc.)

Notes to Condensed Financial Statements

(Unaudited)

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 has revolving credit facilities 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.

The following schedule summarizes the valuation of financial instruments at fair value on a recurring basis in the balance sheets as of September 30, 2012 and December 31, 2011:

There were no transfers of financial assets or liabilities between Level 1 and Level 2 inputs for the nine months ended September 30, 2012 or the year ended December 31, 2011.

Level 2 liabilities consist of Revolving credit facilities. No fair value adjustment was necessary during the nine months ended September 30, 2012 or the year ended December 31, 2011.

BLACK RIDGE OIL & GAS, INC.

(Formerly Ante5, Inc.)

Notes to Condensed Financial Statements

(Unaudited)

Note 9 –Revolving Credit Facilities

PrenAnte5, LLC Revolving credit facility

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 provided $10 million in financing to be made available for drilling projects on the Company’s North Dakota Bakken and Three Forks position. The facility terms stated it would 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 set the minimum total draw at $500,000 and required the Company, upon each draw, to provide the Lender with a compliance certificate that, along with other usual and customary financial covenants, stated that the Company has at least twelve months interest coverage on its balance sheet in cash. We received our first draw of $2,000,000 on February 24, 2012, and subsequently repaid the balance plus accrued interest of $51,722 on April 12, 2012 when we terminated the revolving credit facility.

Dougherty Funding, LLC Revolving credit facility

On April 4, 2012, the Company entered into a Secured Revolving Credit Agreement with Dougherty Funding, LLC as Lender which was subsequently amended on September 5, 2012 with an Amended and Restated Secured Revolving Credit Agreement (collectively the “Credit Facility”). Under the terms of the amended Credit Facility, up to $20,000,000 maximum is available from time to time (i) to fund, or to reimburse the Company for, the Company’s pro-rata share of development and production costs for oil wells that relate to the Company’s oil and gas leasehold interests for which there is a valid and enforceable Authorization for Expenditure and that are incurred from and after the date of the Credit Facility, and (ii) to reimburse the Company for amounts that the Company paid from its own funds or from funds that it borrowed under its previous credit facility from Prenante5, LLC as agent pursuant to the Revolving Credit and Security Agreement dated May 2, 2011 (the “Previous Credit Facility”). Of the $20 million Credit Facility, $16.5 million is currently available. If the Company has not successfully completed an equity offering of at least $10,000,000 by August 31, 2014, then advances will no longer be available under the Credit Facility.

Interest on the unpaid principal balance of the Credit Facility accrues and is payable monthly at 9.25% per year. The Company must also pay the Lender quarterly a commitment fee in an amount equal to 0.25% of the average line of credit available, but not advanced, for the previous quarter. The Company must make payments equal to 90% of the Company’s earnings before taxes, depreciation and amortization (excluding certain items as defined in the Credit Agreement) on a quarterly basis as a principal payment on the Loan.

The Credit Facility is secured by substantially all of the Company’s assets and has typical representations and warranties, covenants, and events of default, including, subject to certain exceptions, incurrence of additional indebtedness. The Credit Agreement requires that the Company meet certain conditions to obtain additional advances under the Credit Facility, including providing certain documentation related to the Company’s oil and gas properties. The Lender has the right to approve advances for properties which are not held by production. In addition, the Company must maintain available cash and specified cash equivalents in an amount that is not less than the greater of (i) $300,000 and (ii) 12 months’ then-regularly scheduled payments of interest on the outstanding amount of advances.

The Credit Facility will mature on August 1, 2015. The Credit Facility may be prepaid with thirty (30) days written notice at any time. In connection with the amended financing, the Company agreed to issue Dougherty Funding, LLC warrants to purchase up to 900,000 shares of the Company’s common stock, of which 585,000 shares have currently been issued, at an exercise price of $0.38. The warrants expire on August 31, 2015.

We took our first draw on April 12, 2012 of $2,450,000, and used $2,051,722 of the proceeds to repay and terminate our outstanding PrenAnte5 revolving credit facility, including interest of $51,722.

Revolving credit facility consisted of the following as of September 30, 2012 and December 31, 2011, respectively:

BLACK RIDGE OIL & GAS, INC.

(Formerly Ante5, Inc.)

Notes to Condensed Financial Statements

(Unaudited)

The following presents components of interest expense by instrument type for the nine months ended September 30, 2012 and 2011, respectively:

Note 10 – Changes in Stockholders’ Equity

Preferred Stock

The Company has 20,000,000 authorized shares of $0.001 par value preferred stock. No shares have been issued to date.

Common Stock

The Company has 100,000,000 authorized shares of $0.001 par value common stock.

Potential Reverse Stock Split

Our Board approved resolutions authorizing the Company to implement a reverse stock split of the Company’s outstanding shares of Common Stock at a ratio of up to 1:10 and any related amendment to the Company’s certificate of incorporation. Our stockholders have also approved the amendment by written consent.

Our Board of Directors or a committee of the Board of Directors has the authority to decide whether to implement a reverse stock split and the exact amount of the split within the foregoing range, if it is to be implemented. If the reverse split is implemented, the number of issued and outstanding shares of Common Stock would be reduced in accordance with the exchange ratio selected by the Board of Directors or a committee thereof. The total number of authorized shares of Common Stock will be reduced proportionately as a result of the reverse stock split and the total number of shares of authorized preferred stock will remain unchanged at 20,000,000 shares.

Reincorporation into Nevada

Our Board approved resolutions authorizing the Company to reincorporate into Nevada. Our stockholders have also approved the reincorporation by written consent. We expect to complete the reincorporation by the end of the year.

Increase in Capitalization

In connection with the reincorporation, we intend to increase the number of authorized shares of our common stock from 100,000,000 to 500,000,000 shares. The number of our authorized shares of preferred stock will remain at 20,000,000.

Issuances of Common Stock

On April 30, 2012, the Company issued 577,025 shares of common stock in satisfaction of a subscription payable granted on March 22, 2012 as part of a deposit on the purchase of certain oil and gas mineral leases, which was subsequently terminated on June 1, 2012. The shares were non-refundable in the event that we decided not to close the purchase. As a result, the $438,839 fair value of the shares was expensed on June 1, 2012 and is presented within general and administrative expense in our condensed statements of operations.

Adjustments to Additional Paid In Capital

On September 30, 2012, the Company relieved two liabilities totaling $180,000 from accounts payable incurred prior to our spin-off from Ante4, Inc. on April 16, 2010. The original transactions did not have an impact on our statements of operations. As a result, the adjustment did not affect current period income.

BLACK RIDGE OIL & GAS, INC.

(Formerly Ante5, Inc.)

Notes to Condensed Financial Statements

(Unaudited)

Note 11 – Options and Warrants

Options

On August 3, 2012, the Company’s Board of Director’s granted 150,000 common stock options to a new employee. The options vest in five equal annual installments, commencing one year from the date of the grant, and are exercisable for 10 years from the date of the grant at an exercise price of $0.40 per share. The estimated value using the Black-Scholes Pricing Model, based on a volatility rate of 111% and a call option value of $0.3398, was $50,965 and is being amortized over the vesting period.

On August 10, 2012, the Company’s Board of Director’s granted 150,000 common stock options to another new employee. The options vest in five equal annual installments, commencing one year from the date of the grant, and are exercisable for 10 years from the date of the grant at an exercise price of $0.28 per share. The estimated value using the Black-Scholes Pricing Model, based on a volatility rate of 112% and a call option value of $0.2390, was $35,853 and is being amortized over the vesting period.

On August 31, 2012, the Company’s Board of Director’s granted 100,000 options to a new director. The options vest in three equal annual installments, commencing one year from the date of the grant, and are exercisable for 10 years from the date of the grant at an exercise price of $0.31 per share. The estimated value using the Black-Scholes Pricing Model, based on a volatility rate of 114% and a call option value of $0.2607, was $26,066 and is being amortized over the vesting period.

On September 25, 2012, an amendment (the “Plan Amendment”) to the 2012 Stock Incentive Plan of Black Ridge Oil & Gas, Inc. (the “Company”) became effective. The Plan Amendment allows for the one-time re-pricing and re-granting of stock options for certain option holders. The Plan Amendment did not alter any other terms of the Plan. Pursuant to the Plan Amendment, certain officers and employees of the Company agreed to the cancellation of their current stock option agreements in exchange for new stock option agreements. Under the new stock option agreements, covering 1,510,000 options, each optionee’s original number of stock options remains the same. Kenneth DeCubellis, Chief Executive Officer, and James Moe, Chief Financial Officer, grants of 1,000,000 and 500,000 shares, respectively, remain the same and will have a new exercise price of $0.27, along with another 10,000 options granted to an employee. These options will vest in five equal annual installments, commencing one year from the date of grant on September 25, 2013, and continuing on the next four anniversaries thereof until fully vested. The additional estimated value using the Black-Scholes Pricing Model, based on a volatility rate of 114% and a call option value of $0.2316 was $59,202 greater than the estimated value immediately preceding the modifications, and is being amortized in addition to the remaining unamortized value of the original option grants.

The Company recognized a total of $698,974, and $492,359 of compensation expense during the nine months ended September 30, 2012 and 2011, respectively, on common stock options issued to Employees and Directors that are being amortized over the implied service term, or vesting period, of the options. The remaining unamortized balance of these options is $1,743,076 as of September 30, 2012.

Options Exercised

No options were exercised during the nine month period ending September 30, 2012.

Options Forfeited

During the nine month period ending September 30, 2012, 466,333 options were forfeited.

BLACK RIDGE OIL & GAS, INC.

(Formerly Ante5, Inc.)

Notes to Condensed Financial Statements

(Unaudited)

Warrants

On September 5, 2012, we granted 585,000 warrants in connection with the amended Dougherty Funding, LLC Revolving Credit Facility. The estimated value using the Black-Scholes Pricing Model, based on a volatility rate of 113% and a call option value of $0.2069, was $121,054, and is being amortized over the approximate three year life of the amended facility. The remaining unamortized balance of those warrants is $118,278 as of September 30, 2012.

We recognized a total of $307,564 and $54,428 of finance expense during the nine months ended September 30, 2012 and 2011, respectively, on common stock warrants issued to lenders during 2011, including related party amounts of $45,719 and $8,164 during the nine months ended September 30, 2012 and 2011, respectively. Warrants are amortized over the remaining life of the respective loan. The fair value of the warrants related to the PrenAnte5 Revolving Credit Facility was being amortized over the life of the loan and the amortization was accelerated to fully amortize the fair value as of the early termination date of April 12, 2012.

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, 2012 will be approximately 41%. Income generated in the nine months ended September 30, 2012 will be used to offset previously recorded net operating losses. 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 September 30, 2012, net deferred tax assets were $4,712,873 after a valuation allowance of approximately $441,656 was applied to net deferred tax assets. This valuation allowance reflects an allowance on only a portion of the Company’s deferred tax assets which the Company believes it is more likely than not that the benefit of these assets will not be realized. We have not provided any valuation allowance against our deferred tax liabilities. As of September 30, 2012, the Company recognized deferred tax liabilities totaling $7,355,598 related to differences in the book and tax basis amounts of the Company’s oil and gas properties resulting from the expensing of intangible drilling costs and the accelerated depreciation utilized for tax purposes.

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 September 30, 2012.

Note 13 – Subsequent Events

On October 5, 2012, the Company and other parties entered into a settlement agreement with Deloitte & Touche, LLP ("Deloitte & Touche") to settle all claims between the parties arising out of the case of WPT Enterprises, Inc. v. Deloitte & Touche, before the Superior Court of the State of California, County of Los Angeles (the "Litigation"). The claims in the Litigation were assigned to the Company as part of the Company’s distribution (spin-off) agreement with Ante4, Inc. On November 1, 2012, after satisfying obligations to various parties, including litigation counsel, the Company received $5.4 million under the settlement agreement as its share of the settlement proceeds. Upon receipt of the settlement amount, the parties have agreed to stipulate to the dismissal of the Litigation and to a mutual release of all claims.

On October 30, 2012 we received our first installment of $5,500,000 from the Peerless/ElectraWorks settlement.

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:

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 September 30, 2012, we controlled the rights to mineral leases covering approximately 11,159 net acres for prospective drilling to the Bakken and/or Three Forks formations. Looking forward, we are pursuing the following objectives:

Effective April 2, 2012, we changed our name to Black Ridge Oil & Gas, Inc. Our common stock is still traded on the OTCBB under the trading symbol “ANFC.”

Recent Developments

Peerless/ElectraWorks Settlement

We 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 was our license agreement with Peerless Media, Ltd. (“Peerless”) and ElectraWorks, Ltd. (“ElectraWorks”), subsidiaries of PartyGaming, PLC (collectively “PartyGaming”), an international online casino gaming company. On July 9, 2012, we formed a wholly-owned subsidiary in the state of Nevada called Poker Interest, LLC. Commensurate with the formation of this entity we assigned all rights and obligations obtained pursuant to an Asset Purchase Agreement, dated August 24, 2009 from Peerless to this newly formed entity. On September 27, 2012, the Company entered into a settlement agreement with Peerless/ElectraWorks to settle claims regarding their performance under the license agreement. Under the settlement agreement, Peerless/ElectraWorks will pay the Company $13.5 million in the following installments: (i) $5.5 million payable on November 2, 2012 (which was received on October 30, 2012), (ii) $5.5 million payable on December 31, 2012, and (iii) $2.5 million payable on December 31, 2013. In addition, Peerless/ElectraWorks will make payments to the Company upon certain contingencies related to the passage of federal or state legislation permitting real money online poker and Peerless/ElectraWorks or one of their affiliates obtaining such a license. The maximum amount of these contingent payments is $6.5 million with the amount determined based on how such legislation is enacted. Under the settlement agreement the Company has released its rights to the royalty stream and no further payments are due from Peerless/ElectraWorks other than those set forth in the settlement agreement.

Deloitte & Touche Settlement

On October 5, 2012, the Company and other parties entered into a settlement agreement with Deloitte & Touche, LLP ("Deloitte & Touche") to settle all claims between the parties arising out of the case of WPT Enterprises, Inc. v. Deloitte & Touche, before the Superior Court of the State of California, County of Los Angeles (the "Litigation"). The claims in the Litigation were assigned to the Company as part of the Company’s distribution (spin-off) agreement with Ante4, Inc. On November 1, 2012, after satisfying obligations to various parties, including litigation counsel, the Company received $5.4 million of net proceeds under the settlement agreement as its share of the settlement proceeds. The parties have agreed to stipulate to the dismissal of the Litigation and to a mutual release of all claims.

Reincorporation into Nevada

Our Board approved resolutions authorizing the Company to reincorporate into Nevada. Our stockholders have also approved the reincorporation by written consent. We expect to complete the reincorporation by the end of the year.

Increase in Capitalization

In connection with our reincorporation, we intend to increase the number of authorized shares of our common stock from 100,000,000 to 500,000,000 shares because we believe that for us to grow our business, increasing the number of authorized shares of common stock will allow us to acquire other businesses in the future or raise capital. This may require us to issue a significant number of additional shares of our common stock. The number of our authorized shares of preferred stock will remain at 20,000,000. This action has been approved by our stock holders, and will become effective upon completion of the reincorporation.

Potential Reverse Stock Split

Our Board approved resolutions authorizing the Company to implement a reverse stock split of the Company’s outstanding shares of Common Stock at a ratio of up to 1:10 and any related amendment to the Company’s certificate of incorporation. Our stockholders have also approved the amendment by written consent.

Our Board of Directors or a committee of the Board of Directors has the authority to decide whether to implement a reverse stock split and the exact amount of the split within the foregoing range, if it is to be implemented. If the reverse split is implemented, the number of issued and outstanding shares of Common Stock would be reduced in accordance with the exchange ratio selected by the Board of Directors or a committee thereof. The total number of authorized shares of Common Stock will be reduced proportionately as a result of the reverse stock split and the total number of shares of authorized preferred stock will remain unchanged at 20,000,000 shares.

We believe that a reverse split would, among other things, (i) better enable the Company to obtain a listing on a national securities exchange, (ii) facilitate higher levels of institutional stock ownership, where investment policies generally prohibit investments in lower-priced securities and (iii) better enable the Company to raise funds to finance its planned operations. There can be no assurance however that we will be able to obtain a listing on a national securities exchange even if we implement the reverse stock split.

AS OF THE DATE OF THIS FILING, OUR BOARD HAS NOT TAKEN ANY ACTION TO MAKE THE POTENTIAL REVERSE STOCK SPLIT EFFECTIVE.

Production History

The following table presents information about our produced oil and gas volumes during the nine months ended September 30, 2012 and 2011, respectively. As of September 30, 2012, we controlled approximately 11,159 net acres in the Bakken and Three Forks formations. In addition, the Company owned working interests in 64 gross wells representing 2.27 net wells that are preparing to drill, drilling, awaiting completion, complete or producing.

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 nine months ended September 30, 2012 and 2011, respectively.

Productive Oil Wells

The following table summarizes gross and net productive oil wells by state at September 30, 2012 and 2011, respectively. 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.

Exploratory Oil Wells

The following table summarizes gross and net exploratory wells as of September 30, 2012. The wells are at various stages of completion and the costs incurred are included in unevaluated oil and gas properties on our balance sheet.

Results of Operations for the Three Months Ended September 30, 2012 and 2011.

The following table summarizes selected items from the statement of operations for the three months ended September 30, 2012 and 2011, respectively.

Revenues:

We recognized $2,285,731 in revenues from sales of crude oil and natural gas for the three months ended September 30, 2012 compared to revenues of $900,511 for the three months ended September 30, 2011, an increase of $1,385,220 or 154%. These revenues are due to the drilling and development of producing wells. We had 57 gross producing wells as of September 30, 2012, and an additional six wells that were either in the drilling preparation, drilling, awaiting completion, or completing stages, compared to 21 gross producing wells, and an additional seven wells that were either in the drilling preparation, drilling, awaiting completion, or completing stages as of September 30, 2011.

The Company acquired a lease for mineral rights from the State of North Dakota on February 14, 2012 for 110 acres or an 8.7% WI interest in the Dahl Federal 2-15H well that spud on March 7, 2012. The operator of the well informed us that they have filed a lawsuit against the state challenging the state’s ownership of these mineral rights. We have signed an Authorization for Expenditure “AFE” for the well and the operator has agreed to retroactively honor the AFE if they are not successful in their litigation with the State. As a result we have not capitalized any of the AFE costs or recognized any sales from this well. The well started production on May 21, 2012. Had we recognized the revenue from this well we would have recorded approximately an additional $187,000 in oil and gas sales for the three months ended September 30, 2012. In the event the operator is successful in their litigation with the state, the state is required to refund the Company the cost to purchase the lease.

Expenses:

Production expenses and taxes

Our production expenses of $161,793 and production taxes of $292,925 for the three months ended September 30, 2012, and $362,560 and $101,936 for the three months ended September 30, 2011, are comprised of certain production costs involved in the development of producing reserves in the Bakken formation. Combined, they represent approximately 20% and 52% of the oil and gas sales for the three months ended September 30, 2012 and 2011, respectively. Our production taxes are greater than the comparative period due to our rapid expansion and increased acreage holdings. The production expenses for the three month period ended September 30, 2011 were exceptionally high as a percentage of revenue primarily as a result of transportation costs associated with the disposal of byproducts of the drilling process, primarily at one well.

General and administrative expenses

General and administrative expenses for the three months ended September 30, 2012 were $1,003,743, compared to $474,570 for the three months ended September 30, 2011, an increase of $529,173, or 112%. The increase is primarily due to non-contingent legal and other costs associated with litigation settlement activity that have been expensed as incurred. Legal and other costs associated with the Peerless/ElectraWorks litigation were $301,107 and $45,358 for the three month periods ended September 30, 2012 and 2011, respectively, and legal and other costs associated with the Deloitte & Touche litigation were $26,256 and $10,200 for the same periods. The company also incurred increased compensation and professional fees as a result of hiring additional employees and professionals needed to support our expanding 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 recognized depletion expense of $919,138 for the three months ended September 30, 2012, compared to $327,363 for the three months ended September 30, 2011, an increase of $591,775, or 181%. The increase was primarily due to our expansion and development of oil and gas properties during 2011 and into 2012.

Depreciation

Depreciation expense for the three months ended September 30, 2012 was $5,811, compared to $2,869 for the three months ended September 30, 2011, an increase of $2,942, or 103%. The increased depreciation expense was due to the additional depreciation associated with the purchase of office equipment in the latter half of 2011 and website development in early 2012.

Net operating income (loss)

The net operating loss for the three months ended September 30, 2012 was $99,018, compared to a net operating loss of $368,941 for the three months ended September 30, 2011, a decrease of $269,923, or 73%. Our net operating income consisted primarily of oil and gas production costs, 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 three months ended September 30, 2012 was $5,466,723, compared to ($17,571) for the three months ended September 30, 2011, a net increase of $5,484,294. The net other income and (expenses) for the three months ended September 30, 2012 consisted of a net gain of $5,744,643 due to the settlement, net of expenses, of the Peerless/ElectraWorks arbitration, $209 of interest income earned on money market accounts, ($278,129) of interest expense, consisting of interest and finance charges on our draws from our Dougherty Funding, LLC Credit Agreement, including ($2,776) of amortized warrant costs related to $20 million financing facility and ($67,836) of amortized debt issuance costs for the three months ended September 30, 2012. Our net other income and (expenses) for the three months ended September 30, 2011 consisted of $252 of interest income earned on money market accounts, ($38,233) of interest expense, consisting of ($32,656) of expenses incurred on amortized warrant costs related to obtaining the PrenAnte5 financing facility, as well as, ($5,577) of amortized debt issuance costs related to obtaining the PrenAnte5 revolving credit and security agreement. We also recognized a gain on debt settlement of $20,410 related to the settlement of certain liabilities for legal fees incurred prior to our spin-off on April 16, 2010.

Income taxes

We had income tax expense of $2,012,195 for the three months ended September 30, 2012 compared to an income tax benefit of $48,300 for the three months ended September 30, 2012, a difference of $2,060,495. The difference is primarily due to additional income tax expense related to the Peerless/ElectraWorks settlement.

Net income (loss)

The net income for the three months ended September 30, 2012 was $3,355,510, compared to a net loss of $338,212 for the three months ended September 30, 2011, a difference of $3,693,722. Our net income consisted primarily of other income related to our settlement of the Peerless/ElectraWorks arbitration and revenue from our oil and gas sales netted against oil and gas production costs, professional fees, officer salaries and interest costs related to our credit facility as we aggressively expanded our oil and gas operations. Additionally, the Company had income tax expense of $2,012,195 in the 2012 period compared to an income tax benefit of $48,300 in the 2011 period, the difference driven primarily by the tax effect of our litigation settlement.

Results of Operations for the Nine Months Ended September 30, 2012 and 2011.

The following table summarizes selected items from the statement of operations for the nine months ended September 30, 2012 and 2011, respectively.

Revenues:

We recognized $4,332,461 in revenues from sales of crude oil and natural gas for the nine months ended September 30, 2012 compared to revenues of $1,248,041 for the nine months ended September 30, 2011, an increase of $3,084,420, or 247%. These revenues are due to the drilling and development of producing wells. We had 57 gross producing wells as of September 30, 2012, and an additional six wells that were either in the drilling preparation, drilling, awaiting completion, or completing stages, compared to 21 gross producing wells, and an additional seven wells that were either in the drilling preparation, drilling, awaiting completion, or completing stages as of September 30, 2011.

The Company acquired a lease for mineral rights from the State of North Dakota on February 14, 2012 for 110 acres or an 8.7% WI interest in the Dahl Federal 2-15H well that spud on March 7, 2012. The operator of the well informed us that they have filed a lawsuit against the state challenging the state’s ownership of these mineral rights. We have signed an AFE for the well and the operator has agreed to retroactively honor the AFE if they are not successful in their litigation with the State. As a result we have not capitalized any of the AFE costs or recognized any sales from this well. The well started production on May 21, 2012. Had we recognized the revenue from this well we would have recorded approximately an additional $324,000 in oil and gas sales for the nine months ended September 30, 2012. In the event the operator is successful in their litigation with the state, the state is required to refund the Company the cost to purchase the lease.

Expenses:

Production expenses and taxes

Our production expenses of $427,676 and production taxes of $526,735 for the nine months ended September 30, 2012, and $379,535 and $138,939 for the nine months ended September 30, 2011, are comprised of certain production costs involved in the development of producing reserves in the Bakken formation. Combined, they represent approximately 22% and 42% of the oil and gas sales for the nine months ended September 30, 2012 and 2011, respectively. Our production expenses and taxes are greater than the comparative period due to our rapid expansion and increased acreage holdings. The expenses during the nine months ended September 30, 2011 were greater as a percentage of sales primarily as a result of one well that experienced high costs transporting and disposing well water throughout the last half of 2011 and continuing into the first quarter of 2012. That well has decreased those costs during the second and third quarters of 2012 to normal operating levels. We anticipate costs related to well water disposal will continue at near normal levels.

General and administrative expenses

General and administrative expenses for the nine months ended September 30, 2012 were $2,955,517, compared to $1,332,556 for the nine months ended September 30, 2011, an increase of $1,622,961, or 122%. The increase in general and administrative costs is primarily related to non-contingent legal costs associated with litigation settlement activity that have been expensed as incurred, along with a one-time expense of $438,539 related to the fair value of common stock granted as a non-refundable deposit on acreage acquisitions that we decided not to complete. The acquisition agreement was terminated in June of 2012. Legal costs associated with the Peerless/ElectraWorks litigation were $332,515 and $144,574 for the nine month periods ended September 30, 2012 and 2011, respectively, and legal costs associated with the Deloitte & Touche litigation were $38,808 and $20,105 for the same periods. Additionally, general and administrative expenses increased for compensation and professional fees as a result of hiring additional employees and professionals needed to support our expanding operations as we grow 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 recognized depletion expense of $1,733,753 for the nine months ended September 30, 2012, compared to $431,893 for the nine months ended September 30, 2011, an increase of $1,301,860, or 301%. The increase was due primarily due to our expansion and acquisitions of oil and gas properties during 2011 and into 2012.

Depreciation

Depreciation expense for the nine months ended September 30, 2012 was $18,395, compared to $8,951 for the nine months ended September 30, 2011, an increase of $9,444, or 106%. The increased depreciation expense was due to the additional depreciation associated with the purchase of office equipment and website development in the latter half of 2011 and early 2012.

Net operating loss

The net operating loss for the nine months ended September 30, 2012 was $1,332,959, compared to $1,044,253 for the nine months ended September 30, 2011, an increase of $288,706, or 28%. Our net operating loss consisted primarily of oil and gas production costs, professional fees, officer salaries and depletion expense, netted against our oil and gas income, incurred as we expanded our oil and gas business, in addition to a one-time expense of $438,539 in the 2012 period related to the fair value of common stock granted as a non-refundable deposit on acreage acquisitions that we decided not to complete.

Other income and (expenses)

Other income and (expenses) for the nine months ended September 30, 2012 was $4,940,797, compared to ($140,696) for the nine months ended September 30, 2011, a net difference of $5,081,493. The net other income and (expenses) for the nine months ended September 30, 2012 consisted of a net gain of $5,744,643 due to the settlement, net of expenses, of the Peerless/ElectraWorks arbitration, $451 of interest income earned on money market accounts, ($804,297) of interest expense, consisting of ($408,559) of interest and finance charges on our $2,000,000 draw from our former PrenAnte5 Credit Agreement, including ($304,788) of amortized warrant costs related to obtaining this $10 million financing facility and ($52,049) of amortized debt issuance costs for the nine months ended September 30, 2012; and ($395,738) of interest expense and finance charges on our draws on our Dougherty Funding, LLC Credit Agreement, consisting of ($296,712) of interest, ($96,250) of finance charges expensed and ($2,776) of amortized warrant costs for the nine months ended September 30, 2012. Amortization of the warrants and debt issuance costs on the PrenAnte5 Credit Agreement were accelerated due to the Company’s repayment and voluntary termination of the revolving credit facility on April 12, 2012. Our net other income and (expenses) for the nine months ended September 30, 2011 consisted of $1,664 of interest income earned on money market accounts, ($63,723) of interest expense, consisting of ($54,428) of expenses incurred on amortized warrant costs related to obtaining the PrenAnte5 financing facility, as well as, ($9,295) of amortized debt issuance costs related to obtaining the PrenAnte5 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.

Income taxes

We had income tax expense of $1,630,630 for the nine months ended September 30, 2012 compared to an income tax benefit of $380,500 for the three months ended September 30, 2012, a difference of $2,011,130. The difference is primarily due to additional income tax expense related to the Peerless/ElectraWorks settlement.

Net income (loss)

The net income for the nine months ended September 30, 2012 was $1,977,208, compared to a net loss of $804,449 for the nine months ended September 30, 2011, a net difference of $2,781,657. Our net income in the 2012 period consisted primarily of settlement income, net of expenses, of $5,744,643 related to our settlement of the Peerless/ElectraWorks arbitration. Additionally, revenue from our oil and gas sales as well as oil and gas production costs, professional fees, officer salaries and interest costs related to our credit facility have increased as we aggressively expanded our oil and gas operations compared to our relatively new oil and gas operations during the nine months ended September 30, 2011. Decreasing the Company’s net income in the nine months ended September 30, 2102 period were a one-time expense of $438,539 related to the fair value of common stock granted as a non-refundable deposit on acreage acquisitions that we decided not to complete and non-contingent legal and other costs of $371,323 in the 2012 period compared to $164,679 in the 2011 period related litigation settlement activity. Additionally, the Company had income tax expense of $1,630,630 in the 2012 period compared to an income tax benefit of $380,500 in the 2011 period driven primarily by the tax effect of our litigation settlement.

Non-GAAP Financial Measures

In addition to reporting net income (loss) as defined under GAAP, we also present Adjusted Net Income (Loss) and Adjusted EBITDA. We define Adjusted Net Income (Loss) as net income excluding settlement income, net of settlement expenses, and tax. We define Adjusted EBITDA as net income before (i) interest expense, (ii) income taxes, (iii) depreciation, depletion and amortization, (iv) accretion of abandonment liability, and (v) non-cash expenses relating to share based payments recognized under ASC Topic 718. We believe the use of non-GAAP financial measures provides useful information to investors regarding our current financial performance; however, Adjusted Net Income (Loss) and Adjusted EBITDA do not represent, and should not be considered alternatives to GAAP measurements. We believe these measures are useful in evaluating our fundamental core operating performance. Specifically, we believe the non-GAAP Adjusted Net Income (Loss) and Adjusted EBITDA results provide useful information to both management and investors by excluding certain income and expenses that our management believes are not indicative of our core operating results. Although we use Adjusted Net Income (Loss) and Adjusted EBITDA to manage our business, including the preparation of our annual operating budget and financial projections, we believe that non-GAAP financial measures have limitations and do not reflect all of the amounts associated with our results of operations as determined in accordance with GAAP and that these measures should only be used to evaluate our results of operations in conjunction with the corresponding GAAP financial measures. A reconciliation of Adjusted Net Income (Loss) and Adjusted EBITDA to Net Income, GAAP, are included below:

Black Ridge Oil & Gas, Inc.

Reconciliation of Adjusted Net Income (Loss)

(Unaudited)

(a) Adjusted to reflect tax expense, computed based on our effective tax rate of approximately 41%, of $2,360,000 for the three and nine months ended September 30, 2012.

Our Adjusted EBITDA for the three and nine month periods ended September 30, 2012 includes settlement income, net of settlement expenses, of $5,744,643.

Liquidity and capital resources

The following table summarizes our total current assets, liabilities and working capital at September 30, 2012 and December 31, 2011, respectively.

As of September 30, 2012, we have positive working capital of $4,487,898.

Revolving Credit Facility

On April 4, 2012, the Company entered into a Secured Revolving Credit Agreement with Dougherty Funding, LLC as Lender which was subsequently amended on September 5, 2012 with an Amended and Restated Secured Revolving Credit Agreement (collectively the “Credit Facility”). Under the terms of the amended Credit Facility, up to $20,000,000 maximum is available from time to time (i) to fund, or to reimburse the Company for, the Company’s pro-rata share of development and production costs for oil wells that relate to the Company’s oil and gas leasehold interests for which there is a valid and enforceable Authorization for Expenditure and that are incurred from and after the date of the Credit Facility, and (ii) to reimburse the Company for amounts that the Company paid from its own funds or from funds that it borrowed under its previous credit facility from Prenante5, LLC as agent pursuant to the Revolving Credit and Security Agreement dated May 2, 2011 (the “Previous Credit Facility”). Of the $20 million Credit Facility, $16.5 million is currently available. If the Company has not successfully completed an equity offering of at least $10,000,000 by August 31, 2014, then advances will no longer be available under the Credit Facility.

Interest on the unpaid principal balance of the Credit Facility accrues and is payable monthly at 9.25% per year. The Company must also pay the Lender quarterly a commitment fee in an amount equal to 0.25% of the average line of credit available, but not advanced, for the previous quarter. The Company must make payments equal to 90% of the Company’s earnings before taxes, depreciation and amortization (excluding certain items as defined in the Credit Agreement) on a quarterly basis as a principal payment on the Loan.

The Credit Facility is secured by substantially all of the Company’s assets and has typical representations and warranties, covenants, and events of default, including, subject to certain exceptions, incurrence of additional indebtedness. The Credit Agreement requires that the Company meet certain conditions to obtain additional advances under the Credit Facility, including providing certain documentation related to the Company’s oil and gas properties. The Lender has the right to approve advances for properties which are not held by production. In addition, the Company must maintain available cash and specified cash equivalents in an amount that is not less than the greater of (i) $300,000 and (ii) 12 months’ then-regularly scheduled payments of interest on the outstanding amount of advances.

The Credit Facility will mature on August 1, 2015. The Credit Facility may be prepaid with thirty (30) days written notice at any time. In connection with the amended financing, the Company agreed to issue Dougherty Funding, LLC warrants to purchase up to 900,000 shares of the Company’s common stock, of which 585,000 shares have currently been issued, at an exercise price of $ 0.38. The warrants expire on August 31, 2015.

We took our first draw on April 12, 2012 of $2,450,000, and used $2,051,722 of the proceeds to repay and terminate our outstanding PrenAnte5 revolving credit facility, including interest of $51,722, and we have taken subsequent draws of $9,400,000 through September 30, 2012 and used the proceeds to pay for our development of oil and gas wells.

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 developing oil and gas wells and our operating costs in 2012 and throughout 2013. However, our recent Deloitte & Touche settlement and Peerless settlement, coupled with the availability under our Credit Facility, provide ample funding for our property acquisition and development plans for the remainder of 2012 and throughout 2013. Our prospects still must be considered in light of the risks, expenses and difficulties frequently encountered by companies in their early stage of development. Such risks for us include, but are not limited to, potential failure to earn revenues or to sufficiently monetize certain claims that we have for payments that are owed to us; an inability to identify investment and expansion targets; and dissipation of existing assets. 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 September 30, 2012, our balance of cash and cash equivalents was $1,775,098. Our plan for satisfying our cash requirements for the next twelve months, in addition to our revenues from oil and gas sales and collection of our settlement proceeds, is through potential sale of shares of our common stock, third party financing, and/or traditional bank financing.

Off-Balance Sheet Arrangements

In connection with the transfer of the WPT and other 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. Our obligation to indemnify Ante4 for operations before the merger and such tax liabilities is limited to $2.5 million in the aggregate and terminated on or about April 15, 2012, subject to customary exceptions from these limitations.

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.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

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.

ITEM 4. 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 September 30, 2012. 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 September 30, 2012 to ensure that the information required to be disclosed in our Exchange Act reports was recorded, processed, summarized and reported on a timely basis.

There have been no changes in the Company’s internal control over financial reporting during the three month period ended September 30, 2012 that materially affected or are reasonably likely to materially affect the Company’s internal control over financial reporting.

PART II - OTHER INFORMATION

Item 1. Legal Proceedings.

On September 27, 2012, the Company entered into a settlement agreement with Peerless and ElectraWorks, Ltd. (“ElectraWorks”) to settle all claims regarding their performance of obligations with respect to the business purchased by Peerless from Ante4, Inc. in November 2009 (the "Litigation"). The Litigation was pending before Judicial Arbitration and Mediation Services (JAMS) in Los Angeles, California. Under the settlement agreement, Peerless/ElectraWorks will pay the Company $13.5 million in the following installments: (i) $5.5 million payable on November 2, 2012, (ii) $5.5 million payable on December 31, 2012, and (iii) $2.5 million payable on December 31, 2013. In addition, Peerless/ElectraWorks will make payments to the Company upon certain contingencies related to the passage of federal or state legislation permitting real money online poker and Peerless/ElectraWorks or one of their affiliates obtaining such a license. The maximum amount of these contingent payments is $6.5 million with the amount determined based on how such legislation is enacted. Under the settlement agreement the Company has released its rights to the royalty stream and no further payments are due from Peerless/ElectraWorks other than those set forth in the settlement agreement.

The Company will pay attorneys’ fees of $2 million as well as various costs out of the proceeds. In addition, as a result of an incentive arrangement with the Company’s former President, Chief Executive Officer and Secretary and current Vice President, Steve Lipscomb that was approved by WPT Enterprises, Inc.’s Board of Directors in February 2009, Mr. Lipscomb will receive 5% of the settlement payments, net of attorneys’ fees and other costs; as such amounts are received by the Company.

On October 5, 2012, the Company and other parties entered into a settlement agreement with Deloitte & Touche, LLP ("Deloitte & Touche") to settle all claims between the parties arising out of the case of WPT Enterprises, Inc. v. Deloitte & Touche, before the Superior Court of the State of California, County of Los Angeles (the "Litigation"). The claims in the Litigation were assigned to the Company as part of the Company’s distribution (spin-off) agreement with Ante4, Inc. On November 1, 2012, after satisfying obligations to various parties, including litigation counsel, the Company received $5.4 million of net proceeds under the settlement agreement as its share of the settlement proceeds. The parties have agreed to stipulate to the dismissal of the Litigation and to a mutual release of all claims.

ITEM 1A. RISK FACTORS.

As a smaller reporting company, we are not required to provide the information required by this Item.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS.

None.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES.

None.

ITEM 4. MINE SAFETY DISCLOSURES.

Not applicable.

ITEM 5. OTHER INFORMATION.

None.

ITEM 6. EXHIBITS.

SIGNATURES

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.

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