PINX:ANFC Quarterly Report 10-Q Filing - 6/30/2012

Effective Date 6/30/2012

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 

FORM 10-Q

(Mark One)

 

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

 

For Quarterly Period Ended June 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)

 

Delaware

(State or other jurisdiction of incorporation or organization)

27-2345075

(I.R.S. Employer Identification No.)

 

10275 Wayzata Blvd. Suite 310, Minnetonka, Minnesota 55305

(Address of principal executive offices) (Zip Code)

 

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

 

 

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

Yes S No £

 

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

Yes S No £

 

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

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

 

 

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

Yes £ No S

 

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

 

The number of shares of registrant’s common stock outstanding as of August 13, 2012 was 47,979,990.

 

 

 
 

TABLE OF CONTENTS

 

PART I - FINANCIAL INFORMATION    
       
ITEM 1. FINANCIAL STATEMENTS (Unaudited)   1
       
  Condensed Balance Sheets at June 30, 2012 (Unaudited) and December 31, 2011   2
       
  Unaudited Condensed Statements of Operations for the Three and Six Months Ended June 30, 2012 and 2011   3
       
  Unaudited Condensed Statements of Cash Flows for the Six Months Ended June 30, 2012 and 2011   4
       
  Notes to the Condensed Financial Statements (Unaudited)   5
       
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS   18
       
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK   30
       
ITEM 4. CONTROLS AND PROCEDURES   30
     
PART II - OTHER INFORMATION    
       
ITEM 1. LEGAL PROCEEDINGS   31
       
ITEM 1A. RISK FACTORS   31
       
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS   31
       
ITEM 3. DEFAULTS UPON SENIOR SECURITIES   31
       
ITEM 4. MINE SAFETY DISCLOSURES   31
       
ITEM 5. OTHER INFORMATION   31
       
ITEM 6. EXHIBITS   31
       
  SIGNATURES   32

 

 
 

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

CONDENSED BALANCE SHEETS

 

   June 30,   December 31, 
   2012   2011 
ASSETS  (Unaudited)     
           
Current assets:          
Cash and cash equivalents  $872,332   $1,401,141 
Accounts receivable   1,236,622    673,003 
Prepaid expenses   93,051    40,599 
Current portion of contingent consideration receivable   2,136,000    2,309,752 
Total current assets   4,338,005    4,424,495 
           
Property and equipment:          
Oil and natural gas properties, full cost method of accounting          
Proved properties   25,335,616    10,867,443 
Unproved properties   12,839,032    13,236,057 
Other property and equipment   85,917    78,489 
Total property and equipment   38,260,565    24,181,989 
Less, accumulated depreciation, amortization and depletion   (4,152,696)   (3,325,497)
Total property and equipment, net   34,107,869    20,856,492 
           
Contingent consideration receivable, net of current portion and allowance of $878,650   3,536,603    3,698,850 
Debt issuance costs   267,408    52,049 
Total other assets   3,804,011    3,750,899 
           
Total assets  $42,249,885   $29,031,886 
           
LIABILITIES AND STOCKHOLDERS' EQUITY          
           
Current liabilities:          
Accounts payable  $10,731,626   $2,820,936 
Accounts payable, related party       9,206 
Royalties payable, related party   283,631    300,431 
Total current liabilities   11,015,257    3,130,573 
           
Asset retirement obligations   54,593    3,900 
Revolving credit facilities   5,825,000     
Deferred tax liability   630,530    1,012,095 
           
Total liabilities   17,525,380    4,146,568 
           
Stockholders' equity:          
Preferred stock, $0.001 par value, 20,000,000 shares authorized, no shares issued and outstanding        
Common stock, $0.001 par value, 100,000,000 shares authorized, 47,979,990 and 47,402,965 shares issued and outstanding, respectively   47,980    47,403 
Additional paid-in capital   29,275,586    28,058,674 
Accumulated (deficit)   (4,599,061)   (3,220,759)
Total stockholders' equity   24,724,505    24,885,318 
           
Total liabilities and stockholders' equity  $42,249,885   $29,031,886 

 

See accompanying notes to financial statements. 

 

2
 

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

CONDENSED STATEMENTS OF OPERATIONS

(Unaudited)

 

   For the Three Months
Ended June 30,
   For the Six Months
Ended June 30,
 
   2012   2011   2012   2011 
                 
Oil and gas sales  $1,380,524   $250,590   $2,046,730   $347,530 
                     
Operating expenses:                    
Production expenses   121,732    11,352    265,883    16,975 
Production taxes   158,378    27,573    233,810    37,003 
General and administrative   1,237,883    489,109    1,951,774    857,986 
Depletion of oil and gas properties   527,712    68,382    814,615    104,530 
Accretion of discount on asset retirement obligations   1,208    146    2,005    266 
Depreciation and amortization   5,734    2,960    12,584    6,082 
Total operating expenses   2,052,647    599,522    3,280,671    1,022,842 
                     
Net operating (loss)   (672,123)   (348,932)   (1,233,941)   (675,312)
                     
Other income (expense):                    
Interest income   200    256    242    1,412 
Interest (expense)   (172,903)   (25,490)   (526,168)   (25,490)
Loss on disposal of equipment       (1,061)       (1,061)
Indemnification expenses       (97,986)       (97,986)
Total other income (expense)   (172,703)   (124,281)   (525,926)   (123,125)
                     
Loss before provision for income taxes   (844,826)   (473,213)   (1,759,867)   (798,437)
                     
Provision for income taxes   227,381    57,900    381,565    332,200 
                     
Net (loss)  $(617,445)  $(415,313)  $(1,378,302)  $(466,237)
                     
Weighted average number of common shares outstanding - basic and fully diluted   47,789,762    40,505,760    47,596,363    39,180,194 
                     
Net (loss) per share - basic and fully diluted  $(0.01)  $(0.01)  $(0.03)  $(0.01)

 

 

See accompanying notes to financial statements. 

 

3
 

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

CONDENSED STATEMENTS OF CASH FLOWS

(Unaudited)

 

   For the Six Months
Ended June 30,
 
   2012   2011 
CASH FLOWS FROM OPERATING ACTIVITIES          
Net (loss)  $(1,378,302)  $(466,237)
Adjustments to reconcile net (loss) to net cash provided by (used in) operating activities:          
Depletion of oil and gas properties   814,615    104,530 
Depreciation and amortization   12,584    6,082 
Amortization of debt issuance costs   80,463    3,718 
Accretion of discount on asset retirement obligations   2,005    266 
Loss on disposal of equipment       1,061 
Common stock issued for terminated oil and gas acquisition   438,539     
Common stock warrants   259,069    18,506 
Common stock warrants, related parties   45,719    3,266 
Common stock options, related parties   474,162    312,262 
Decrease (increase) in assets:          
Accounts receivable   (563,619)   (242,611)
Prepaid expenses   (52,452)   (95,816)
Contingent consideration receivable   335,999    85,343 
Increase (decrease) in liabilities:          
Accounts payable   44,749    (76,732)
Accounts payable, related party   (9,206)   145,939 
Accrued expenses       (47,267)
Royalties payable, related party   (16,800)   (4,319)
Deferred tax liability   (381,565)   (332,200)
Net cash provided by (used in) operating activities   105,960    (584,209)
           
CASH FLOWS FROM INVESTING ACTIVITIES          
Proceeds from the sale of oil and gas properties   736,625     
Purchases of oil and gas properties and development capital expenditures   (6,893,144)   (5,665,533)
Purchases of other property and equipment   (7,428)   (40,533)
Net cash used in investing activities   (6,163,947)   (5,706,066)
           
CASH FLOWS FROM FINANCING ACTIVITIES          
Advances from revolving credit facilities   7,825,000     
Repayments on revolving credit facilities   (2,000,000)    
Debt issuance costs paid   (295,822)   (66,921)
Proceeds from the exercise of stock options       15,600 
Net cash provided by (used in) financing activities   5,529,178    (51,321)
           
NET CHANGE IN CASH   (528,809)   (6,341,596)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD   1,401,141    8,577,610 
CASH AND CASH EQUIVALENTS AT END OF PERIOD  $872,332   $2,236,014 
           
SUPPLEMENTAL INFORMATION:          
Interest paid  $140,917   $ 
Income taxes paid  $   $ 
           
NON-CASH INVESTING AND FINANCING ACTIVITIES:          
Purchase of oil and gas properties accrued within accounts payable  $10,288,091   $3,697,835 
Purchase of oil and gas properties through issuance of common stock  $   $4,940,269 
Capitalized asset retirement costs  $48,688   $3,074 

 

See accompanying notes to financial statements. 

 

4
 

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

 

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

 

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.

 

5
 

BLACK RIDGE OIL & GAS, INC.

(Formerly Ante5, Inc.)

Notes to Condensed Financial Statements

(Unaudited)

 

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.

 

Cash and Cash Equivalents

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

 

   June 30,
2012
   December 31,
2011
 
Cash  $355,416   $474,314 
Money market funds   516,916    926,827 
Total  $872,332   $1,401,141 

 

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 $369,332 and $650,165 in excess of FDIC and SIPC insured limits at June 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 straight-line method. The unamortized balance of debt issuance costs at June 30, 2012, and December 31, 2011, was $267,408 and $52,049, respectively. Amortization of debt issuance costs charged to interest expense was $80,463 and $3,718 for the six months ended June 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:

 

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

 

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

 

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

 

6
 

BLACK RIDGE OIL & GAS, INC.

(Formerly Ante5, Inc.)

Notes to Condensed Financial Statements

(Unaudited)

 

We have capitalized a total of $56,660 of website development costs from inception through June 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 $9,187 and $-0- for the six months ended June 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.

 

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 $12,584 and $6,082 for the six months ended June 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.

 

7
 

BLACK RIDGE OIL & GAS, INC.

(Formerly Ante5, Inc.)

Notes to Condensed Financial Statements

(Unaudited)

 

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 six months ended June 30, 2012 and 2011, respectively:

 

   For the Six
Months Ended
June 30,
2012
   For the Six Month Ended
June 30,
2011
 
Capitalized Certain Payroll and Other Internal Costs  $66,098   $105,578 
Capitalized Interest Costs        
Total  $66,098   $105,578 

 

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.

 

8
 

BLACK RIDGE OIL & GAS, INC.

(Formerly Ante5, Inc.)

Notes to Condensed Financial Statements

(Unaudited)

 

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.

 

Basic and Diluted Loss per Share

The basic net loss per common share is computed by dividing the net loss by the weighted average number of common shares outstanding. Diluted net loss per common share is computed by dividing the net loss adjusted on an “as if converted” basis, by the weighted average number of common shares outstanding plus potential dilutive securities. For the three and six months ended June 30, 2012 and 2011, potential dilutive securities had an anti-dilutive effect and were not included in the calculation of diluted net loss per common share.

 

Stock-Based Compensation

The Company adopted FASB guidance on stock based compensation upon inception at April 9, 2010. Under FASB ASC 718-10-30-2, all share-based payments to employees, including grants of employee stock options, are to be recognized in the income statement based on their fair values. Pro forma disclosure is no longer an alternative. Common stock and stock options issued for services and compensation totaled $912,701 and $312,262 for the six months ended June 30, 2012 and 2011, respectively, including $438,539 and $-0-, respectively, of common stock valued at the fair market value based on the Company’s closing trading price on the date of grant, and $474,162 and $312,262, 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, $304,788 and $21,772 of warrants were amortized during the six months ended June 30, 2012 and 2011, respectively, pursuant to warrants granted in consideration for a revolving credit facility. The warrants are being amortized over the life of the loan, which was accelerated and terminated on April 12, 2012.

 

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 Voyager Oil and Gas (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 Voyager Oil and Gas (Ante4) for the years ended January 3, 2010 and December 28, 2008. As a result of the examination we reimbursed Voyager Oil and Gas for their payments of $11,417 of federal taxes and, based on the federal examination, amended state returns in California that totalled an additional $48,666 in state taxes. In addition, we reimbursed Voyager Oil and Gas for their payments of an additional $37,903 in California payroll taxes related to an underpayment by Ante4 from 2010.

 

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

 

9
 

BLACK RIDGE OIL & GAS, INC.

(Formerly Ante5, Inc.)

Notes to Condensed Financial Statements

(Unaudited)

 

Recent Accounting Pronouncements

In December 2011, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (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 June 30, 2012 and December 31, 2011, consisted of the following:

 

   June 30,
2012
   December 31,
2011
 
Oil and gas properties, full cost method:          
Evaluated costs  $25,335,616   $10,867,443 
Unevaluated costs, not subject to amortization or ceiling test   12,839,032    13,236,057 
    38,174,648    24,103,500 
Other property and equipment   85,917    78,489 
    38,260,565    24,181,989 
Less: Accumulated depreciation, amortization and depletion   (4,152,696)   (3,325,497)
Total property and equipment, net  $34,107,869   $20,856,492 

 

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

 

   June 30,
2012
   June 30,
2011
 
Depletion of costs for evaluated oil and gas properties  $814,615   $104,530 
Depreciation and amortization of other property and equipment   12,584    6,082 
Total depreciation, amortization and depletion  $827,199   $110,612 

 

10
 

BLACK RIDGE OIL & GAS, INC.

(Formerly Ante5, Inc.)

Notes to Condensed Financial Statements

(Unaudited)

 

Note 4 – Oil and Gas Properties

 

The following table summarizes gross and net productive oil wells by state at June 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.

 

   June 30, 2012   June 30, 2011 
   Gross   Net   Gross   Net 
North Dakota   48    1.83    11    0.45 

 

The Company’s oil and gas properties consist of all acreage acquisition costs (including cash expenditures and the value of stock consideration), drilling costs and other associated capitalized costs. As of June 30, 2012 and 2011, our principal oil and gas assets included approximately 11,213 and 9,600 net acres, respectively, located in North Dakota.

 

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

 

   For the Six
Months Ended
June 30,
2012
   For the Six
Months Ended
June 30,
2011
 
Purchases of oil and gas properties and development costs for cash  $6,893,144   $5,665,533 
Purchase of oil and gas properties paid subsequent to period-end   10,288,091    3,697,835 
Prior year purchase of oil and gas properties paid in current year   (2,422,150)    
Purchases of oil and gas properties through the issuance of common stock       4,940,269 
Capitalized asset retirement costs   48,688    3,074 
Total purchase and development costs, oil and gas properties  $14,807,773   $14,306,711 

 

Acquisitions during the six months ended June 30, 2012

 

On various dates during the six months ended June 30, 2012, we purchased approximately 978 net mineral acres of oil and gas properties in North Dakota. In consideration for the assignment of these mineral leases, we paid the seller a total of approximately $1,291,113. 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 six months ended June 30, 2012, we sold a total of approximately 221 net acres at an average of $3,329 per acre for total proceeds of $736,625. No gain or loss was recorded pursuant to the sale.

 

Acquisitions during the six months ended June 30, 2011

 

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.

 

11
 

BLACK RIDGE OIL & GAS, INC.

(Formerly Ante5, Inc.)

Notes to Condensed Financial Statements

(Unaudited)

 

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.

 

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 six months ended June 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 six months ended June 30, 2012 and the year ended December 31, 2011:

 

 

   June 30,
2012
   December 31,
2011
 
Beginning Asset Retirement Obligation  $3,900   $ 
Liabilities Incurred for New Wells Placed in Production   48,688    3,391 
Accretion of Discount on Asset Retirement Obligations  2,005   509 
Ending Asset Retirement Obligation  $54,593   3,900 

 

12
 

BLACK RIDGE OIL & GAS, INC.

(Formerly Ante5, Inc.)

Notes to Condensed Financial Statements

(Unaudited)

 

Note 6 – Related Party

 

On June 1, 2012, our Board of Directors appointed our former CEO, Steven Lipscomb as Vice President.

 

We sublease 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 amended on April 30, 2012 to expand to occupy approximately 1,142 square feet of office space. In accordance with this amendment, 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, plus common area maintenance charges, and monthly parking fees of $240 per month, for the first year commencing on May 1, 2012, and annual increases of $285 per month for each of the subsequent four year periods. We have paid a total of $10,844 and $6,647 to this entity during the six months ended June 30, 2012 and 2011, respectively.

 

During the six months ended June 30, 2012 and 2011, we paid $-0- and $8,633 to an entity owned by our former CEO and current Chairman of the Board of Directors, Bradley Berman for administrative services provided, of which $3,451 remained unpaid and reported within accounts payable on the balance sheet as of June 30, 2011. The Company no longer utilizes these related party administrative services.

 

 

Note 7 – Contingent Consideration Receivable

 

As a result of a transaction between Ante4, Inc. (Ante4”) and Peerless Media Ltd. (“Buyer”) during fiscal year 2009, pursuant to which, Ante4 sold substantially all of its operating assets (the “Transaction”), Ante5, Inc., 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 the Buyer generated by Ante4’s former business and assets that were sold to Buyer in the Transaction, subject to a 5% commission presented as Royalties Payable on the balance sheet. Buyer has guaranteed a minimum payment to us of $3 million for such revenue over the three-year period following the closing of the Transaction 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 at June 30, 2012:

 

   Contingent
Consideration
Receivable
   Royalties
Payable
   Net Contingent
Consideration
Receivable
 
Balance spun-off, April 16, 2010:  $7,532,985   $(415,000)  $7,117,985 
                
Net royalties received and commissions paid   (182,335)   11,343    (170,992)
Fair value adjustment   (878,650)   80,057    (798,593)
Balance, December 31, 2010   6,472,000    (323,600)   6,148,400 
                
Net royalties received and commissions paid   (463,398)   23,169    (440,229)
Balance, December 31, 2011   6,008,602    (300,431)   5,708,171 
                
Net royalties received and commissions paid   (335,999)   16,800    (319,199)
Balance, June 30, 2012  $5,672,603   $(283,631)  $5,388,972 

 

The Company estimated its current portion of the contingent consideration receivable to be $2,136,000 based on the guaranteed minimum payment to us of $3 million, less payments previously received due on November 2, 2012 and estimated royalties thereafter based on historical receipts.

 

13
 

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

 

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

 

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

 

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

 

 

Note 9 –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 new Secured Revolving Credit Agreement with Dougherty Funding, LLC as Lender (the “Credit Facility”). Under the terms of the Credit Facility, up to $10,000,000 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”). Availability under the Credit Facility is subject to payoff of the Previous Credit Facility and release of liens thereunder and other conditions precedent.

 

14
 

BLACK RIDGE OIL & GAS, INC.

(Formerly Ante5, Inc.)

Notes to Condensed Financial Statements

(Unaudited)

 

Interest on the unpaid principal balance of the Credit Facility shall accrue and be payable monthly at the following per annum rates (i) unless, and except to the extent that, clause (ii) applies, 9.0%; and (ii) if the Company does not raise equity funds in excess of $10,000,000 and if the then outstanding unpaid principal balance of the Credit Facility exceeds $5,000,000, 9.5% on such balance in excess of $5,000,000. The Company must also pay the Lender quarterly a commitment fee in an amount equal to 0.25% of the average non-advanced revolving credit facility for the previous quarter.

 

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 March 31, 2014. The maturity date may be extended two times, each time for an additional one- year period, at the written request of the Company given to the Lender no earlier than sixty (60) days prior to the expiration of the then-existing maturity date provided that as of both the date of the Borrower’s written request and such then-existing maturity date, the Company meets specified conditions similar to those for initial draws under the Credit Facility and the Company pays to the Lender on the first business day of the extended period an extension fee in the amount of $100,000.

 

We took our fist 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. On May 22, 2012, we drew another $3,375,000 to fund continued exploration and drilling activities. In addition, we drew another $1,450,000 subsequent to the balance sheet date on July 17, 2012. We have an additional $2,725,000 available to us under this revolving credit facility.

 

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

 

   June 30,
2012
   December 31,
2011
 
PrenAnte5, LLC Revolving Credit Facility  $   $ 
           
Dougherty Funding, LLC Revolving Credit Facility   5,825,000     
           
Total revolving credit facility   5,825,000     
Less: current portion        
Revolving credit facility, less current portion  $5,825,000   $ 

 

The following presents components of interest expense by instrument type at June 30, 2012 and 2011, respectively:

 

   June 30,
2012
   June 30,
2011
 
PrenAnte5 Revolving Credit Facility, interest  $51,722   $ 
PrenAnte5 Revolving Credit Facility, finance charges   52,049    3,718 
PrenAnte5 Revolving Credit Facility, warrant costs   304,788    21,772 
Dougherty Revolving Credit Facility, interest   89,195     
Dougherty Revolving Credit Facility, finance charges   28,414     
   $526,168   $25,490 

 

15
 

BLACK RIDGE OIL & GAS, INC.

(Formerly Ante5, Inc.)

Notes to Condensed Financial Statements

(Unaudited)

 

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.

 

Increase in Capitalization

We intend to amend our Certificate of Incorporation 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.

 

Recent 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.

 

 

Note 11 – Warrants and Options

 

Options

 

We recognized a total of $474,162, and $325,628 of compensation expense during the six months ended June 30, 2012 and 2011, respectively, on common stock options issued to employees and directors during 2010 and 2011 that are being amortized over the implied service term, or vesting period, of the options. The remaining unamortized balance of these options is $2,038,089 as of June 30, 2012.

 

Warrants

 

We recognized a total of $304,788 and $21,772 of finance expense during the six months ended June 30, 2012 and 2011, respectively, on common stock warrants issued to lenders during 2011, including related party amounts of $45,719 and $3,266 during the six months ended June 30, 2012 and 2011, respectively. The warrants were being amortized over the remaining life of the loan, which was accelerated as of an early termination date of April 12, 2012. The remaining unamortized balance of these warrants is $-0- as of June 30, 2012.

 

Options Exercised

 

No options were exercised during the six month period ending June 30, 2012.

 

 

16
 

BLACK RIDGE OIL & GAS, INC.

(Formerly Ante5, Inc.)

Notes to Condensed Financial Statements

(Unaudited)

 

Note 12 – Income Taxes

 

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

 

We currently estimate that our effective tax rate for the year ending December 31, 2012 will be approximately 38%. Losses incurred during the period from April 9, 2010 (inception) to June 30, 2012 as well as any additional losses incurred during the remainder of 2012 could be used to offset future tax liabilities. Accounting standards require the consideration of a valuation allowance for deferred tax assets if it is “more likely than not” that some component or all of the benefits of deferred tax assets will not be realized. As of June 30, 2012, net deferred tax assets were $7,419,820 after a valuation allowance of approximately $681,315 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 June 30, 2012, the Company recognized deferred tax liabilities totaling $8,050,350 related to income taxes on a net contingent consideration receivable resulting from the sale of assets to Party Gaming during 2009 as well income taxes 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 June 30, 2012.

 

 

Note 13 – Subsequent Events

 

Subsequent to June 30, 2012, we granted a total of 300,000 common stock options to two new employees. The options vest annually over five years beginning on the first anniversary of the grants and are exercisable until the tenth anniversary of the grants at exercise prices from $0.28 to $0.40 per share.

 

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 Media Ltd. to this newly formed entity.

 

On July 17, 2012, we drew another $1,450,000 on our Dougherty Revolving Credit Facility to fund continued exploration and drilling activities.

 

 

17
 

ITEM 2: MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

 

Cautionary Statements

 

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

 

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

 

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

 

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

 

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.

 

18
 

Overview and Outlook

 

We are an oil and natural gas exploration and production company. Our properties are located in North Dakota. Our corporate strategy is the acquisition, exploration, development and production of crude oil and natural gas properties, primarily in the Bakken and Three Forks trends in North Dakota and Montana. As of June 30, 2012, we controlled the rights to mineral leases covering approximately 11,213 net acres for prospective drilling to the Bakken and/or Three Forks formations. Looking forward, we are pursuing the following objectives:

 

  acquire high-potential mineral leases;
     
  access appropriate capital markets to fund continued acreage acquisition and drilling activities;
     
  develop and maintain strategic industry relationships;
     
  attract and retain talented associates;
     
  operate a low overhead non-operator business model; and
     
  become a low cost producer of hydrocarbons.

 

We also inherited material interests from our former parent company prior to our spin off. These historical interests relate to our former parent company’s business as WPT Enterprises, Inc., when it created internationally branded products through the development, production and marketing of televised programming based on gaming themes. The primary historical gaming asset is our license agreement with a subsidiary of PartyGaming, PLC, an international online casino gaming company. We are entitled to royalty payments from that license agreement. We manage our historical interests to monetize them. 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 Media Ltd. to this newly formed entity. Effective April 2, 2012, we changed our name to Black Ridge Oil & Gas, Inc. Our common stock is still currently traded on the OTCBB under the trading symbol “ANFC.”

 

Recent Developments

 

Name Change

 

Our Board of Directors approved changing the corporate name to Black Ridge Oil & Gas, Inc. The name change became effective on April 2, 2012. The Company’s common stock continues to trade on the OTCBB using the ticker symbol “ANFC”.

 

Increase in Capitalization

 

We intend to amend our Certificate of Incorporation 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 filing of an amendment to our certificate of Incorporation.

 

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.

 

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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 six months ended June 30, 2012 and 2011, respectively. As of June 30, 2012, we controlled approximately 11,213 net acres in the Bakken and Three Forks formations. In addition, the Company owned working interests in 59 gross wells representing 2.23 net wells that are preparing to drill, drilling, awaiting completion, complete or producing.

 

   For the Six Months Ended June 30, 2012   For the Six Months Ended June 30, 2011 
Net Production:          
Oil (Bbl)   24,786    3,740 
Natural Gas (Mcf)   4,650    721 
Barrel of Oil Equivalent (Boe)   25,561    3,860 
           
Average Sales Prices:          
Oil (per Bbl)  $81.51   $91.98 
Effect of oil hedges on average price (per Bbl)  $   $ 
Oil net of hedging (per Bbl)  $81.51   $91.98 
Natural Gas (per Mcf)  $5.66   $4.95 
Effect of natural gas hedges on average price (per Mcf)  $   $ 
Natural gas net of hedging (per Mcf)  $5.66   $4.95 
           
Average Production Costs:          
Oil (per Bbl)  $10.62   $4.49 
Natural Gas (per Mcf)  $0.58   $0.28 
Barrel of Oil Equivalent (Boe)  $10.40   $4.40 

 

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 six months ended June 30, 2012 and 2011, respectively.

 

   For the Six Months Ended June 30, 2012   For the Six Months Ended June 30, 2011 
           
Depletion of oil and natural gas properties  $814,615   $104,530 

 

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Productive Oil Wells

 

The following table summarizes gross and net productive oil wells by state at June 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.

 

   June 30, 2012   June 30, 2011 
   Gross   Net   Gross   Net 
                     
North Dakota   48    1.83    11    0.45 

 

Exploratory Oil Wells

 

The following table summarizes gross and net exploratory wells as of June 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.

 

   June 30, 2012   June 30, 2011 
   Gross   Net   Gross   Net 
North Dakota                    
Bakken and Three Forks Trends   2    0.07    5    0.10 

 

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

 

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

 

   For the three months ended June 30, 2012   For the three months ended June 30, 2011   Increase/ (Decrease) 
             
Oil and gas sales  $1,380,524   $250,590   $1,129,934 
                
Operating expenses:               
Production expenses   121,732    11,352    110,380 
Production taxes   158,378    27,573    130,805 
General and administrative   1,237,883    489,109    748,774 
Depletion of oil and gas properties   527,712    68,382    459,330 
Accretion of discount on asset retirement obligations   1,208    146    1,062 
Depreciation and amortization   5,734    2,960    2,774 
Total operating expenses:   2,052,647    599,522    1,453,125 
                
Net operating loss   (672,123)   (348,932)   323,191 
                
Total other income (expense)   (172,703)   (124,281)   48,422 
                
Loss before provision for income taxes   (844,826)   (473,213)   371,613 
                
Provision for income taxes   227,381    57,900    169,481 
                
Net (loss)  $(617,445)  $(415,313)  $202,132 

 

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Revenues:

 

We recognized $1,380,524 in revenues from sales of crude oil and natural gas for the three months ended June 30, 2012 compared to revenues of $250,590 for the three months ended June 30, 2011, an increase of $1,129,934, or 451%. These revenues are due to the drilling and development of producing wells. We had 48 gross producing wells as of June 30, 2012, and an additional 11 gross wells that were either in the drilling preparation, drilling, awaiting completion, or completing stages, compared to 11 gross producing wells, and an additional 13 gross wells that were either in the drilling preparation, drilling, awaiting completion, or completing stages as of June 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 $137,000 in Oil and Gas sales for the three months ended June 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 $121,732 and production taxes of $158,378 for the three months ended June 30, 2012, and $11,352 and $27,573 for the three months ended June 30, 2011, are comprised of certain production costs involved in the development of producing reserves in the Bakken formation. Combined, they represent approximately 20% and 16% of the oil and gas sales for the three months ended June 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.

 

General and administrative expenses

 

General and administrative expenses for the three months ended June 30, 2012 were $1,237,883, compared to $489,109 for the three months ended June 30, 2011, an increase of $748,774, or 153%. Our increase in general and administrative expenses was primarily due to 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. The Company also incurred increased compensation and professional fees as a result of hiring additional employees and professionals needed to support our expanding operations as we grew our oil and gas operations.

 

Depletion of oil and natural gas properties

 

Our depletion expense is driven by many factors, including certain exploration costs involved in the development of producing reserves, production levels and estimates of proved reserve quantities and future developmental costs. We recognized depletion expense of $527,712 for the three months ended June 30, 2012, compared to $68,382 for the three months ended June 30, 2011, an increase of $459,330, or 672%. 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 three months ended June 30, 2012 was $5,734, compared to $2,960 for the three months ended June 30, 2011, an increase of $2,774, or 94%. The increased depreciation expense was due to the additional depreciation associated with the purchase of office equipment in the latter half of 2011. We anticipate quarterly depreciation of approximately $6,000 during 2012 due primarily to additional depreciation on capitalized websites.

 

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Net operating loss

 

The net operating loss for the three months ended June 30, 2012 was $672,123, compared to $348,932 for the three months ended June 30, 2011, an increase of $323,191, or 93%. 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 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 three months ended June 30, 2012 was ($172,703), compared to ($124,281) for the three months ended June 30, 2011, an increase of $48,422, or 39%. The net other income and (expenses) for the three months ended June 30, 2012 consisted of $200 of interest income earned on money market accounts, ($172,903) of interest expense, consisting of ($55,294) of interest and finance charges on our $2,000,000 draw from our former PrenAnte5 Credit Agreement, including ($13,722) of interest, ($35,507) of amortized warrant costs related to obtaining this $10 million financing facility and ($6,065) of amortized debt issuance costs for the three months ended June 30, 2012; and ($117,609) of interest expense, consisting of ($89,195) of interest and ($28,414) of amortized debt issuance costs on our $5,825,000 of draws on our Dougherty Funding, LLC Credit Agreement for the three months ended June 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 three months ended June 30, 2011 consisted of $256 of interest income earned on money market accounts, ($25,490) of interest expense, consisting of ($21,772) of expenses incurred on amortized warrant costs related to obtaining the PrenAnte5 financing facility, as well as, ($3,718) 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.

 

Net loss

 

The net loss for the three months ended June 30, 2012 was $617,445, compared to $415,313 for the three months ended June 30, 2011, an increase of $202,132, or 49%. Our net loss consisted primarily of oil and gas production costs, professional fees, officer salaries and amortization of warrants and debt issuance fees related to our credit facilities, netted against our oil and gas income and change in provision for income taxes, as we aggressively expanded our oil and gas operations. Our net loss increased primarily due to 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 our increased oil and gas operations during the three months ended June 30, 2012 compared to our relatively new oil and gas operations during the three months ended June 30, 2011.

 

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Results of Operations for the Six Months Ended June 30, 2012 and 2011.

 

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

 

   For the three months ended June 30, 2012   For the three months ended June 30, 2011   Increase/ (Decrease) 
             
Oil and gas sales  $2,046,730   $347,530   $1,699,200 
                
Operating expenses:               
Production expenses   265,883    16,975    248,908 
Production taxes   233,810    37,003    196,807 
General and administrative   1,951,774    857,986    1,093,788 
Depletion of oil and gas properties   814,615    104,530    710,085 
Accretion of discount on asset retirement obligations   2,005    266    1,739 
Depreciation and amortization   12,584    6,082    6,502 
Total operating expenses:   3,280,671    1,022,842    2,257,829 
                
Net operating loss   (1,233,941)   (675,312)   558,629 
                
Total other income (expense)   (525,926)   (123,125)   402,801 
                
Loss before provision for income taxes   (1,759,867)   (798,437)   961,430 
                
Provision for income taxes   381,565    332,200    49,365 
                
Net (loss)  $(1,378,302)  $(466,237)  $912,065 

 

Revenues:

 

We recognized $2,046,730 in revenues from sales of crude oil and natural gas for the six months ended June 30, 2012 compared to revenues of $347,530 for the six months ended June 30, 2011, an increase of $1,699,200, or 489%. These revenues are due to the drilling and development of producing wells. We had 48 gross producing wells as of June 30, 2012, and an additional 11 gross wells that were either in the drilling preparation, drilling, awaiting completion, or completing stages, compared to 11 gross producing wells, and an additional 13 gross wells that were either in the drilling preparation, drilling, awaiting completion, or completing stages as of June 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 $137,000 in Oil and Gas sales for the six months ended June 30, 2012.

 

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Expenses:

 

Production expenses and taxes

 

Our production expenses of $265,883 and production taxes of $233,810 for the six months ended June 30, 2012, and $16,975 and $37,003 for the six months ended June 30, 2011, are comprised of certain production costs involved in the development of producing reserves in the Bakken formation. Combined, they represent approximately 24% and 16% of the oil and gas sales for the six months ended June 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 six months ended June 30, 2012 are greater than expected primarily as a result of transportation costs in the Bakken region due to congestion and delays in transporting the disposal of byproducts in the drilling process. In addition, we believe the well that is responsible for the majority of these additional costs is not currently producing at the pump jack’s full capacity. We anticipate these additional costs related to well water disposal will dissipate in the future as additional waste treatment facilities are opened.

 

General and administrative expenses

 

General and administrative expenses for the six months ended June 30, 2012 were $1,951,774, compared to $857,986 for the six months ended June 30, 2011, an increase of $1,093,788, or 127%. Our increase in general and administrative expenses was primarily due to increased compensation and professional fees as a result of hiring additional employees and professionals needed to support our expanding operations as we grew our oil and gas operations, 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.

 

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 $814,615 for the six months ended June 30, 2012, compared to $104,530 for the six months ended June 30, 2011, an increase of $710,085, or 679%. 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 six months ended June 30, 2012 was $12,584, compared to $6,082 for the six months ended June 30, 2011, an increase of $6,502, or 107%. The increased depreciation expense was due to the additional depreciation associated with the purchase of office equipment in the latter half of 2011. We anticipate quarterly depreciation of approximately $6,000 during 2012 due primarily to additional depreciation on capitalized websites.

 

Net operating loss

 

The net operating loss for the six months ended June 30, 2012 was $1,233,941, compared to $675,312 for the six months ended June 30, 2011, an increase of $558,629, or 83%. 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 related to the fair value of common stock granted as a non-refundable deposit on acreage acquisitions that we decided not to complete.

 

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Other income and (expenses)

 

Other income and (expenses) for the six months ended June 30, 2012 was ($525,926), compared to ($123,125) for the six months ended June 30, 2011, an increase of $402,801, or 327%. The net other income and (expenses) for the six months ended June 30, 2012 consisted of $242 of interest income earned on money market accounts, ($526,168) 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 ($51,722) of interest expense, ($304,788) of amortized warrant costs related to obtaining this $10 million financing facility and ($52,049) of amortized debt issuance costs for the six months ended June 30, 2012; and ($117,609) of interest expense, consisting of ($89,195) of interest and ($28,414) of amortized debt issuance costs on our $5,825,000 of draws on our Dougherty Funding, LLC Credit Agreement for the six months ended June 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 six months ended June 30, 2011 consisted of $1,412 of interest income earned on money market accounts, ($25,490) of interest expense, consisting of ($21,772) of expenses incurred on amortized warrant costs related to obtaining the PrenAnte5 financing facility, as well as, ($3,718) 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.

 

Net loss

 

The net loss for the six months ended June 30, 2012 was $1,378,302, compared to $466,237 for the six months ended June 30, 2011, an increase of $912,065, or 196%. Our net loss consisted primarily of oil and gas production costs, professional fees, officer salaries and amortization of warrants and debt issuance fees related to our credit facilities, netted against our oil and gas income and change in provision for income taxes, as we aggressively expanded our oil and gas operations. Our net loss increased primarily due to 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 our increased oil and gas operations during the six months ended June 30, 2012 compared to our relatively new oil and gas operations during the six months ended June 30, 2011.

 

Adjusted EBITDA

 

In addition to reporting net income (loss) as defined under GAAP, we also present Adjusted EBITDA. 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 EBITDA does not represent, and should not be considered an alternative to GAAP measurements. We believe this measure is useful in evaluating our fundamental core operating performance. Specifically, we believe the non-GAAP Adjusted EBITDA results provide useful information to both management and investors by excluding certain expenses that our management believes are not indicative of our core operating results. Although we use 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 EBITDA to Net Income, GAAP, is included below:

 

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Black Ridge Oil & Gas, Inc.

Reconciliation of Adjusted EBITDA

 

   Three Months Ended
June 30,
   Six Months Ended
June 30,
 
   2012   2011   2012   2011 
Net Loss  $(617,445)  $(415,313)  $(1,378,302)  $(466,237)
Add Back:                    
Interest Expense, net, excluding amortization of warrant based financing costs   137,196    3,462    221,138    2,306 
Income Tax Provision   (227,381)   (57,900)   (381,565)   (332,200)
Depreciation, Depletion, and Amortization   533,446    71,342    827,199    110,612 
Accretion of Abandonment Liability   1,208    146    2,005    266 
Common stock issued for terminated oil and gas acquisition   438,539        438,539     
Share Based Compensation   272,208    200,935    778,950    334,034 
                     
Adjusted EBITDA  $537,771   $(197,328)  $507,964   $(351,219)

 

Liquidity and capital resources

 

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

 

   June 30,
2012
   December 31,
2011
 
Current Assets  $4,338,005   $4,424,495 
           
Current Liabilities  $11,015,257   $3,130,573 
           
Working Capital  $(6,677,252)  $1,293,922 

 

While we have raised capital to meet our working capital and financing needs in the past, additional financing will be required in order to meet our current and projected cash requirements for the operation of our oil and gas business. As of June 30, 2012, we had negative working capital of $(6,677,252).

 

Revolving Credit Facility

 

On April 4, 2012, the Company entered into a new Secured Revolving Credit Agreement with Dougherty Funding LLC as Lender (the “Credit Facility”). Under the terms of the Credit Facility, up to $10,000,000 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”). Availability under the Credit Facility is subject to payoff of the Previous Credit Facility and release of liens thereunder and other conditions precedent.

 

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Interest on the unpaid principal balance of the Credit Facility shall accrue and be payable monthly at the following per annum rates (i) unless, and except to the extent that, clause (ii) applies, 9.0%; and (ii) if the Company does not raise equity funds in excess of $10,000,000 and if the then outstanding unpaid principal balance of the Credit Facility exceeds $5,000,000, 9.5% on such balance in excess of $5,000,000. The Company must also pay the Lender quarterly a commitment fee in an amount equal to 0.25% of the average non-advanced revolving credit facility for the previous quarter.

 

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 March 31, 2014. The maturity date may be extended two times, each time for an additional one- year period, at the written request of the Company given to the Lender no earlier than sixty (60) days prior to the expiration of the then-existing maturity date provided that (i) as of both the date of the Borrower’s written request and such then-existing maturity date, the Company meets specified conditions similar to those for initial draws under the Credit Facility and the Company pays to the Lender on the first business day of the extended period an extension fee in the amount of $100,000.

 

We took our fist 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 took our second draw of $3,375,000 on May 22, 2012 and used the proceeds to pay for development of oil and gas properties.

 

We anticipate that we may incur operating losses in the next twelve months. Although our revenues are expected to grow as our wells are placed into production, our revenues are not expected to exceed our investment and operating costs in 2012. Our prospects 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 June 30, 2012, our balance of cash and cash equivalents was $872,332. Our plan for satisfying our cash requirements for the next twelve months, in addition to our revenues from oil and gas sales, is through sale of shares of our common stock, third party financing, and/or traditional bank financing. We may realize proceeds from our Royalty Stream payable to us by Peerless Media, Ltd. or from our lawsuit against Deloitte Touche, although we are not currently relying on those revenue sources because of our disputes with them. Furthermore, royalties in excess of the minimum guarantee on the Royalty Stream are contingent on revenues earned by Peerless Media under the World Poker Tour brand name. There is no assurance as to whether, or when, we will be paid royalties under our agreement with Peerless Media, Ltd.

 

28
 

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.

 

29
 

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 June 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 June 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 June 30, 2012 that materially affected or are reasonably likely to materially affect the Company’s internal control over financial reporting.

 

 

30
 

PART II - OTHER INFORMATION

 

Item 1. Legal Proceedings.

 

None.

 

 

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.

 

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.

 

 

ITEM 3. DEFAULTS UPON SENIOR SECURITIES.

 

None.

 

 

ITEM 4. MINE SAFETY DISCLOSURES.

 

Not applicable.

 

 

ITEM 5. OTHER INFORMATION.

 

None.

 

 

ITEM 6. EXHIBITS.

 

Exhibit   Description
     
31.1   Section 302 Certification of Chief Executive Officer
31.2   Section 302 Certification of Chief Financial Officer
32.1   Section 906 Certification of Chief Executive Officer
32.2   Section 906 Certification of Chief Financial Officer
101.INS   XBRL Instance Document*
101.SCH   XBRL Schema Document*
101.CAL   XBRL Calculation Linkbase Document*
101.DEF   XBRL Definition Linkbase Document*
101.LAB   XBRL Labels Linkbase Document*
101.PRE   XBRL Presentation Linkbase Document*

 

 

*Pursuant to Rule 405(a)(2) of Regulation S-T, the Company will furnish the XBRL Interactive Data Files with detailed footnote tagging as Exhibit 101 in an amendment to this Form 10-Q within the permitted 30-day grace period for the first quarterly period in which detailed footnote tagging is required after the filing date of this Form 10-Q.

 

31
 

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.

 

 

  BLACK RIDGE OIL & GAS, INC.  
       
Dated: August 14, 2012 By: /s/ Kenneth DeCubellis  
    Kenneth DeCubellis,  
    Chief Executive Officer (Principal Executive Officer)  
       

 

 

Dated: August 14, 2012 By: /s/James A. Moe  
    James A. Moe,  
    Chief Financial Officer (Principal Financial Officer)  
       

 

 

 

 

32

 

PINX:ANFC Quarterly Report 10-Q Filling

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

PINX:ANFC Quarterly Report 10-Q Filing - 6/30/2012
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