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EX-31.2 - CERTIFICATION - Black Ridge Oil & Gas, Inc.brog_10q-ex3102.htm
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EX-31.1 - CERTIFICATION - Black Ridge Oil & Gas, Inc.brog_10q-ex3101.htm
EX-32.1 - CERTIFICATION - Black Ridge Oil & Gas, Inc.brog_10q-ex3201.htm

 

 

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 March 31, 2013

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

 

(Name of registrant in its charter)

 

Nevada

(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  T 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 T 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  T

 

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 May 13, 2013 was 47,979,990.

 

 

 
 

TABLE OF CONTENTS

 

PART I - FINANCIAL INFORMATION  
     
ITEM 1. FINANCIAL STATEMENTS (Unaudited) 1
     
  Condensed Consolidated Balance Sheets at March 31, 2013 (Unaudited) and December 31, 2012 2
     
  Unaudited Condensed Consolidated Statements of Operations for the Three Months Ended March 31, 2013 and  2012 3
     
  Unaudited Condensed Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2013 and 2012 4
     
  Notes to the Condensed Consolidated Financial Statements (Unaudited) 5
     
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 19
     
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

 

 

 

1
 

 

BLACK RIDGE OIL & GAS, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

 

   March 31,   December 31, 
   2013   2012 
ASSETS  (Unaudited)     
           
Current assets:          
Cash and cash equivalents  $1,350,313   $1,417,340 
Accounts receivable   1,132,160    856,233 
Settlement receivable   2,500,000    2,500,000 
Prepaid expenses   77,011    1,397,450 
Total current assets   5,059,484    6,171,023 
           
Property and equipment:          
Oil and natural gas properties, full cost method of accounting          
Proved properties   39,834,838    35,248,983 
Unproved properties   8,040,576    9,055,513 
Other property and equipment   85,917    85,917 
Total property and equipment   47,961,331    44,390,413 
Less, accumulated depreciation, amortization, depletion and allowance for impairment   (6,498,720)   (5,793,184)
Total property and equipment, net   41,462,611    38,597,229 
           
Debt issuance costs   594,629    657,702 
           
Total assets  $47,116,724   $45,425,954 
           
           
LIABILITIES AND STOCKHOLDERS' EQUITY          
           
Current liabilities:          
Accounts payable  $4,568,317   $2,953,526 
Settlement payable   160,000    160,000 
Settlement accounts payable, related party   116,234    116,234 
Accrued expenses   102,113    61,666 
Total current liabilities   4,946,664    3,291,426 
           
Asset retirement obligations   50,199    67,145 
Revolving credit facility   5,748,844    5,748,844 
Deferred tax liability   4,298,908    4,732,696 
           
Total liabilities   15,044,615    13,840,111 
           
Commitments and contingencies ( See note 14)        
           
Stockholders' equity:          
Preferred stock, $0.001 par value, 20,000,000 shares authorized, no shares issued and outstanding        
Common stock, $0.001 par value, 500,000,000 shares authorized, 47,979,990 shares issued and outstanding   47,980    47,980 
Additional paid-in capital   30,019,665    29,847,212 
Retained earnings   2,004,464    1,690,651 
Total stockholders' equity   32,072,109    31,585,843 
           
Total liabilities and stockholders' equity  $47,116,724   $45,425,954 

 

See accompanying notes to financial statements.

 

2
 

 

BLACK RIDGE OIL & GAS, INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

 

   For the Three Months 
   Ended March 31, 
   2013   2012 
         
Oil and gas sales  $1,911,299   $666,206 
           
Operating expenses:          
Production expenses   268,806    144,151 
Production taxes   219,342    75,432 
General and administrative   603,578    713,891 
Depletion of oil and gas properties   699,725    286,903 
Accretion of discount on asset retirement obligations   1,152    797 
Depreciation and amortization   5,811    6,850 
Total operating expenses   1,798,414    1,228,024 
           
Net operating income (loss)   112,885    (561,818)
           
Other income (expense):          
Interest income   120    42 
Interest (expense)   (232,980)   (353,265)
Total other income (expense)   (232,860)   (353,223)
           
Loss before provision for income taxes   (119,975)   (915,041)
           
Provision for income taxes   433,788    154,184 
           
Net income (loss)  $313,813   $(760,857)
           
           
Weighted average common shares outstanding - basic   47,979,990    47,402,965 
Weighted average common shares outstanding - fully diluted   48,493,840    47,402,965 
           
Net income (loss) per common share - basic  $0.01   $(0.02)
Net income (loss) per common share - fully diluted  $0.01   $(0.02)

 

See accompanying notes to financial statements.

 

 

3
 

 

BLACK RIDGE OIL & GAS, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

 

   For the Three Months 
   Ended March 31, 
   2013   2012 
CASH FLOWS FROM OPERATING ACTIVITIES          
Net income (loss)  $313,813   $(760,857)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:          
Depletion of oil and gas properties   699,725    286,903 
Depreciation and amortization   5,811    6,850 
Amortization of debt issuance costs   63,073    45,984 
Accretion of discount on asset retirement obligations   1,152    797 
Common stock warrants   10,088    228,888 
Common stock warrants, related parties       40,393 
Common stock options, related parties   162,365    237,461 
Deferred income taxes   (433,788)   (154,184)
Decrease (increase) in current assets:          
Accounts receivable   (275,927)   249,336 
Prepaid expenses   7,141    (478)
Contingent consideration receivable       207,033 
Increase (decrease) in current liabilities:          
Accounts payable   952    122,902 
Accounts payable, related parties       6,212 
Accrued expenses   40,447    38,089 
Royalties payable, related party       (10,352)
Net cash provided by operating activities   594,852    544,977 
           
CASH FLOWS FROM INVESTING ACTIVITIES          
Proceeds from sale of oil and gas properties   199,800     
Purchases of oil and gas properties and development capital expenditures   (861,679)   (2,436,964)
Purchases of other property and equipment       (3,660)
Net cash used in investing activities   (661,879)   (2,440,624)
           
CASH FLOWS FROM FINANCING ACTIVITIES          
Advances from revolving credit facilities       2,000,000 
Debt issuance costs paid       (46,919)
Net cash provided by financing activities       1,953,081 
           
NET CHANGE IN CASH   (67,027)   57,434 
CASH AT BEGINNING OF PERIOD   1,417,340    1,401,141 
CASH AT END OF PERIOD  $1,350,313   $1,458,575 
           
           
SUPPLEMENTAL INFORMATION:          
Interest paid  $104,280   $ 
Income taxes paid  $   $ 
           
NON-CASH INVESTING AND FINANCING ACTIVITIES:          
Net change in accounts payable for purchase of oil and gas properties  $1,613,839   $4,176,755 
Prepaid expenses applied to purchase of oil and gas properties  $1,313,298   $ 
Deposits on purchase of oil and gas properties owed in common stock  $   $438,539 
Capitalized asset retirement costs, net of revision in estimate  $(18,098)  $24,746 

 

See accompanying notes to financial statements.

 

4
 

BLACK RIDGE OIL & GAS, INC.

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

 

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

 

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

 

 

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, 2012, which were included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2012. The Company follows the same accounting policies in the preparation of interim reports.

 

Reclassifications

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

 

Use of Estimates

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

 

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

 

5
 

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Consolidated Financial Statements

(Unaudited)

 

Cash and Cash Equivalents

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

 

   March 31,   December 31, 
   2013   2012 
Cash  $513,804   $513,788 
Money market funds   836,509    903,552 
Total  $1,350,313   $1,417,340 

 

Cash in Excess of FDIC Insured Limits

The Company maintains its cash in bank deposit accounts which, at times, may exceed federally insured limits. Accounts are guaranteed by the Federal Deposit Insurance Corporation (FDIC) and the Securities Investor Protection Corporation (SIPC) up to $250,000 and $500,000, respectively, under current regulations. The Company had approximately $850,313 and $917,340 in excess of FDIC and SIPC insured limits at March 31, 2013 and December 31, 2012, respectively. The Company has not experienced any losses in such accounts.

 

Deferred Financing Costs

Costs relating to obtaining certain debts are capitalized and amortized over the term of the related debt using the straight-line method, which approximates the effective interest method. The unamortized balance of debt issuance costs at March 31, 2013, and December 31, 2012, was $594,629 and $657,702, respectively. Amortization of debt issuance costs charged to interest expense was $63,073 and $45,984 for the three months ended March 31, 2013 and 2012, 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.

 

We have capitalized a total of $56,660 of website development costs from inception through March 31, 2013. We depreciate our website development costs on a straight line basis over the useful life of the assets, which is currently three years. We have recognized depreciation expense on these website costs of $4,722 and $4,465 as of March 31, 2013 and 2012, 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.

 

6
 

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Consolidated Financial Statements

(Unaudited)

 

Net Income (Loss) Per Common Share

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

 

The reconciliation of the denominators used to calculate basic EPS and diluted EPS for the three months ended March 31, 2013 and 2012 are as follows:

 

   Three Months Ended 
   March 31, 
   2013   2012 
Weighted average common shares outstanding – basic   47,979,990    47,402,965 
Plus: Potentially dilutive common shares:          
Stock options and warrants   513,850     
Weighted average common shares outstanding – diluted   48,493,840    47,402,965 

 

Stock options and warrants excluded from the calculation of diluted EPS because their effect was anti-dilutive were 8,176,209 and 8,040,375 as of March 31, 2013 and 2012, respectively.

 

Segment Reporting

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

 

Fair Value of Financial Instruments

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

 

Non-Oil & Gas Property and Equipment

Property and equipment that are not oil and gas properties are recorded at cost and depreciated using the straight-line method over their estimated useful lives of three to seven years. Expenditures for replacements, renewals, and betterments are capitalized. Maintenance and repairs are charged to operations as incurred. Long-lived assets, other than oil and gas properties, are evaluated for impairment to determine if current circumstances and market conditions indicate the carrying amount may not be recoverable. The Company has not recognized any impairment losses on non-oil and gas long-lived assets. Depreciation expense was $5,811 and $6,850 for the three months ended March 31, 2013 and 2012, respectively.

 

Revenue Recognition

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 an 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.

Notes to Condensed Consolidated 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 three months ended March 31, 2013 and 2012, respectively:

 

   Three Months Ended 
   March 31, 
   2013   2012 
Capitalized Certain Payroll and Other Internal Costs  $10,540   $33,049 
Capitalized Interest Costs        
Total  $10,540   $33,049 

 

Proceeds from property sales will generally be credited to the full cost pool, with no gain or loss recognized, unless such a sale would significantly alter the relationship between capitalized costs and the proved reserves attributable to these costs. A significant alteration would typically involve a sale of 20% or more of the proved reserves related to a single full cost pool. The Company assesses all items classified as unevaluated property on a quarterly basis for possible impairment or reduction in value. The assessment includes consideration of the following factors, among others: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; the assignment of proved reserves; and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to amortization.

 

Capitalized costs associated with impaired properties and properties having proved reserves, estimated future development costs, and asset retirement costs under FASB ASC 410-20-25 are depleted and amortized on the unit-of-production method based on the estimated gross proved reserves as determined by independent petroleum engineers. The costs of unproved properties are withheld from the depletion base until such time as they are either developed or abandoned.

 

Capitalized costs of oil and gas properties (net of related deferred income taxes) may not exceed an amount equal to the present value, discounted at 10% per annum, of the estimated future net cash flows from proved oil and gas reserves plus the cost of unproved properties (adjusted for related income tax effects). Should capitalized costs exceed this ceiling, impairment is recognized. The present value of estimated future net cash flows is computed by applying the arithmetic average first day price of oil and natural gas for the preceding twelve months to estimated future production of proved oil and gas reserves as of the end of the period, less estimated future expenditures to be incurred in developing and producing the proved reserves and assuming continuation of existing economic conditions. Such present value of proved reserves' future net cash flows excludes future cash outflows associated with settling asset retirement obligations. Should this comparison indicate an excess carrying value, the excess is charged to earnings as an impairment expense.

 

Impairment

FASB ASC 360-10-35-21 requires that assets to be held and used be reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Oil and gas properties accounted for using the full cost method of accounting (which the Company uses) are excluded from this requirement but continue to be subject to the full cost method's impairment rules.

 

8
 

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Consolidated Financial Statements

(Unaudited)

 

FASB ASC 310-40 requires that impaired loans receivable 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, prior to the settlement of the contingent consideration receivable in September of 2012, we tested for impairment annually using the present value of expected future net cash flows.

 

Stock-Based Compensation

The Company adopted FASB guidance on stock based compensation upon inception at April 9, 2010. Under FASB ASC 718-10-30-2, all share-based payments to employees, including grants of employee stock options, are to be recognized in the income statement based on their fair values. Pro forma disclosure is no longer an alternative. Expense related to common stock and stock options issued for services and compensation totaled $162,365 and $237,461 for the three months ended March 31, 2013 and 2012, 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, $10,088 and $269,281 of warrant related costs were amortized during the three months ended March 31, 2013 and 2012, respectively, pursuant to warrants granted in consideration for credit facilities. The fair value of warrants is determined similar to the method used in determining the fair value of employee stock options and the fair value is amortized over the life of the related credit facility and accelerated upon termination of a credit facility.

 

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

 

Recent Accounting Pronouncements

New accounting pronouncements are issued by FASB that are adopted by the Company as of the specified effective date. There have been no developments to recently issued accounting standards, including expected dates of adoption and estimated effects on our financial statements, from those disclosed in our Annual Report on Form 10-K for the year ended December 31, 2012.

 

 

9
 

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Consolidated Financial Statements

(Unaudited)

 

Note 3 – Property and Equipment

 

Property and equipment at March 31, 2013 and December 31, 2012, consisted of the following:

 

   March 31,   December 31, 
   2013   2012 
Oil and gas properties, full cost method:          
Evaluated costs  $39,834,838   $35,248,983 
Unevaluated costs, not subject to amortization or ceiling test   8,040,576    9,055,513 
    47,875,414    44,304,496 
Other property and equipment   85,917    85,917 
    47,961,331    44,390,413 
Less: Accumulated depreciation, amortization,  depletion and impairments   (6,498,720)   (5,793,184)
Total property and equipment, net  $41,462,611   $38,597,229 

 

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

 

   Three Months Ended 
   March 31, 
   2013   2012 
Depletion of costs for evaluated oil and gas properties  $699,725   $286,903 
Depreciation and amortization of other property and equipment   5,811    6,850 
Total depreciation, amortization and depletion  $705,536   $293,753 

 

 

Note 4 – Oil and Gas Properties

 

The following table summarizes gross and net productive oil wells by state at March 31, 2013 and 2012. 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.

 

   March 31, 2013   March 31, 2012 
   Gross   Net   Gross   Net 
North Dakota   72    2.51    37    1.12 
Montana   1    0.08         
Total   73    2.59    37    1.12 

 

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 March 31, 2013 and 2012, our principal oil and gas assets included approximately 12,971 and 11,259 net acres, respectively, located in North Dakota and Montana.

 

The following table summarizes our capitalized costs for the purchase and development of our oil and gas properties for the three months ended March 31, 2013 and 2012, respectively:

 

   Three Months Ended 
   March 31, 
   2013   2012 
Purchases of oil and gas properties and development costs for cash  $861,679   $2,436,964 
Purchase of oil and gas properties accrued at period-end   4,231,984    6,598,905 
Purchase of oil and gas properties accrued at beginning of period   (2,618,145)   (2,422,150)
Prepaid expenses applied to purchase of oil and gas properties   1,313,298     
Capitalized asset retirement costs, net of revision in estimate   (18,098)   24,746 
Total purchase and development costs, oil and gas properties  $3,770,718   $6,638,465 

 

10
 

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Consolidated Financial Statements

(Unaudited)

 

2013 Acquisitions

During the three months ended March 31, 2013, we purchased approximately 800 net mineral acres of oil and gas properties in North Dakota. In consideration for the assignment of these mineral leases, we paid the sellers a total of approximately $416,283.

 

2013 Divestitures

During the three months ended March 31, 2013, we sold a total of approximately 60 net mineral acres of oil and gas properties for total proceeds of $199,800. No gain or loss was recorded pursuant to the sales.

 

2012 Acquisitions

During the three months ended March 31, 2012, we purchased approximately 802 net mineral acres of oil and gas properties in North Dakota. In consideration for the assignment of these mineral leases, we paid the sellers a total of approximately $1,075,306.

 

2012 Divestitures

There were no sales of oil and gas properties during the three months ended March 31, 2012.

 

 

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 three months ended March 31, 2013 and 2012:

 

   Three Months Ended 
   March 31, 
   2013   2012 
Beginning asset retirement obligation  $67,145   $3,900 
Revision in estimate of asset retirement obligation   (20,123)    
Liabilities incurred for new wells placed in production   2,025    24,746 
Accretion of discount on asset retirement obligation   1,152    797 
Ending asset retirement obligation  $50,199   $29,443 

 

 

Note 6 – Related Party

 

A former officer of the Company, Steve Lipscomb, received a commission of 5% of a royalty stream from Peerless Media Ltd., recorded on the balance sheet as of December 31, 2011 as a contingent consideration receivable, as a result of an incentive arrangement with Mr. Lipscomb that was approved by Ante4’s Board of Directors in February 2009. Mr. Lipscomb received a total of $-0- and $16,603 during the three months ended March 31, 2013 and 2012, respectively, none of which were received by Mr. Lipscomb while an officer of the Company in 2012. As a result of the settlement of litigation related to the same agreement, Mr. Lipscomb was due 5% of the settlement payments from the litigation settlement amounting to approximately $548,827 of which $432,593 was paid in 2012 and the remaining $116,234 is due upon receipt by the Company of the final settlement payment from Peerless Media, Ltd.

 

11
 

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Consolidated Financial Statements

(Unaudited)

 

We have subleased and currently lease office space on a month to month basis where the lessor is an entity owned by our former CEO and current Chairman of the Board of Directors, Bradley Berman. The sublease agreement was cancelled and we entered into a direct lease on April 30, 2012 to expand and occupy approximately 1,142 square feet of office space. In accordance with this lease, our lease term remains on a month-to-month basis, provided that either party may provide 90 day notice to terminate the lease, with base rents of $1,142 per month, plus common area operations and maintenance charges, and monthly parking fees of $240 per month, for the first year commencing on May 1, 2012, and subject to increases of $24 per month for each of the subsequent four year periods. We have paid a total of $7,832 and $3,339 to this entity during the three months ended March 31, 2013 and 2012, respectively.

 

 

Note 7 – Litigation Settlements and Contingent Consideration Receivable

 

Peerless Settlement

As a result of a transaction between Ante4, Inc. (“Ante4”) and Peerless Media Ltd. (“Peerless”) during fiscal year 2009, pursuant to which, Ante4 sold substantially all of its operating assets (the “Transaction”) and a spin-off on April 16, 2010 to Ante5, Inc., now Black Ridge Oil & Gas, Inc. (the “Company”), the Company was entitled to receive, in perpetuity, 5% of gross gaming revenue and 5% of other revenue of Peerless generated by Ante4’s former business and assets that were sold to Peerless in the Transaction, subject to a 5% commission presented as Royalties Payable on the balance sheet. Peerless had guaranteed a minimum payment to the Company of $3 million for such revenue over the three-year period following the closing of the Transaction on November 2, 2009. The Company prepared a discounted cash flow model to determine an estimated fair value of this portion of the purchase price as of November 2, 2009. This value was recorded on the balance sheet of Ante4. In connection with the spin-off described above, on April 16, 2010 Ante4 distributed this asset to its wholly-owned subsidiary, Ante5, Inc., which was spun-off and a registration statement was filed on Form 10-12/A, along with an Information Statement with the Securities and Exchange Commission for the purpose of spinning off the Ante5 shares from Ante4, Inc. to its stockholders of record on April 15, 2010. The following is a summary of the contingency consideration receivable and related royalties payable through December 31, 2012:

 

   Contingent       Net Contingent 
   Consideration   Royalties   Consideration 
   Receivable   Payable   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   (529,361)   26,468    (502,893)
Elimination of the contingent receivable due to settlement agreement   (5,479,241)   273,963    (5,205,278)
Balance, December 31, 2012  $   $   $ 

 

On September 27, 2012, the Company entered into a settlement agreement with Peerless and ElectraWorks, Ltd. (“ElectraWorks”) to settle all claims regarding Peerless’s performance of obligations with respect to the business purchased by Peerless from Ante4, Inc. in November 2009 (the "Litigation"). The Litigation was pending before Judicial Arbitration and Mediation Services (JAMS) in Los Angeles, California. Under the settlement agreement, Peerless/ElectraWorks will pay the Company $13.5 million, of which $11,000,000 was received by the Company in 2012 and the remaining $2.5 million is payable on or before December 31, 2013. In addition, Peerless/ElectraWorks will make payments to the Company upon certain contingencies related to the passage of federal or state legislation permitting real money online poker and Peerless/ElectraWorks or one of their affiliates obtaining such a license. The maximum amount of these contingent payments is $6.5 million with the amount determined based on how such legislation is enacted. Under the settlement agreement the Company has released its rights to the royalty stream and no further payments are due from Peerless/ElectraWorks other than those set forth in the settlement agreement.

 

12
 

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Consolidated Financial Statements

(Unaudited)

 

The Company is paying attorneys’ fees of $2 million, of which $1.84 million was paid in 2012, as well as various costs out of the proceeds. In addition, as a result of an incentive arrangement with Steve Lipscomb, a former officer of the Company that was approved by WPT Enterprises, Inc.’s Board of Directors in February 2009, Mr. Lipscomb is receiving 5% of the settlement payments, net of attorneys’ fees and other costs; as such amounts are received by the Company.

 

As of March 31, 2013, the Company has a settlement receivable of $2.5 million for the remaining litigation settlement and payables of $160,000 and $116,234 related to remaining contingent attorneys’ fees payable and amounts due Mr. Lipscomb, respectively. The contingent consideration receivable was relieved in 2012 as a part of the settlement. The Company has expensed non-contingent expenses and fees associated with pursuing the settlement as those expenses and fees were incurred amounting to $-0- and $11,018 for the three months ended March 31, 2013 and 2012, respectively.

 

 

Note 8 – Fair Value of Financial Instruments

 

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

 

The Company has revolving credit facilities that must be measured under the new fair value standard. The Company’s financial assets and liabilities are measured using inputs from the three levels of the fair value hierarchy. The three levels are as follows:

 

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

 

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

 

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

 

The following schedule summarizes the valuation of financial instruments at fair value on a recurring basis in the balance sheets as of March 31, 2013 and December 31, 2012:

 

   Fair Value Measurements at March 31, 2013 
   Level 1   Level 2   Level 3 
Assets               
Cash and cash Equivalents   1,350,313         
Total assets   1,350,313          
Liabilities               
Revolving credit facilities       5,748,844     
Total Liabilities       5,748,844     
   $1,350,313   $(5,748,844)  $ 

 

   Fair Value Measurements at December 31, 2012 
   Level 1   Level 2   Level 3 
Assets               
Cash and cash equivalents  $1,417,340   $   $ 
Total assets   1,417,340          
Liabilities               
Revolving credit facilities       5,748,844     
Total Liabilities       5,748,844     
   $1,417,340   $(5,748,844)  $ 

 

13
 

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Consolidated Financial Statements

(Unaudited)

 

There were no transfers of financial assets or liabilities between Level 1 and Level 2 inputs for the three months ended March 31, 2013 and 2012.

 

Level 2 liabilities consist of Revolving credit facilities. No fair value adjustment was necessary during the three months ended March 31, 2013 and 2012.

 

 

Note 9 – Revolving Credit Facilities

 

PrenAnte5, LLC Revolving credit facility

On May 2, 2011, we entered into a Revolving Credit and Security Agreement (the “Credit Agreement”) with certain lenders (collectively, the “Lenders” and individually a “Lender”) and Prenante5, LLC, as agent for the Lenders (PrenAnte5, LLC, in such capacity, the “Agent”). The facility provided $10 million in financing to be made available for drilling projects on the Company’s North Dakota Bakken and Three Forks position. The facility terms stated it would be available for a period of three years over which time we may draw on the line seven times, pay the line down three times, and terminate the facility without penalty one time. The facility set the minimum total draw at $500,000 and required the Company, upon each draw, to provide the Lender with a compliance certificate that, along with other usual and customary financial covenants, stated that the Company has at least twelve months interest coverage on its balance sheet in cash. We received our first draw of $2,000,000 on February 24, 2012, and subsequently repaid the balance plus accrued interest of $51,722 on April 12, 2012 when we terminated the revolving credit facility.

 

Dougherty Funding, LLC Revolving credit facility

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

 

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

 

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

 

14
 

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Consolidated Financial Statements

(Unaudited)

 

The Credit Facility will mature on August 1, 2015. The Credit Facility may be prepaid with thirty (30) days written notice at any time. On September 5, 2012, in connection with the amended financing, the Company agreed to issue Dougherty Funding, LLC warrants to purchase up to 900,000 shares of the Company’s common stock, of which 585,000 shares have currently been issued, at an exercise price of $0.38 per share. The remaining warrants to purchase 315,000 shares are available to be granted when the remaining $3.5 million of the credit facility becomes available. The warrants expire on August 31, 2015.

 

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

 

Revolving credit facility consisted of the following as of March 31, 2013 and December 31, 2012, respectively:

 

   March 31,   December 31, 
   2013   2012 
Dougherty Funding, LLC Revolving Credit Facility  $5,748,844   $5,748,844 
           

 

The following presents components of interest expense by instrument type for the three months ended March 31, 2013 and 2012, respectively:

 

   Three Months Ended 
   March 31, 
   2013   2012 
Revolving Credit Facilities, interest  $159,819   $38,000 
Revolving Credit Facilities, finance charges   63,073    45,984 
Revolving Credit Facilities, warrant costs   10,088    269,281 
   $232,980   $353,265 

 

 

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 500,000,000 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.

 

 

15
 

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Consolidated Financial Statements

(Unaudited)

 

Note 11 –Options

 

Options

On January 24, 2013, the Company granted a total of 762,500 common stock options to officers and employees, including 400,000 options granted to Ken DeCubellis, the Company’s Chief Executive Officer, and 115,000 options granted to James Moe, the Company’s Chief Financial Officer. All of the options vest annually over five years beginning on the first anniversary of the grants and are exercisable until the tenth anniversary of the date of grant at an exercise price of $0.56 per share. The total estimated fair value using the Black-Scholes Pricing Model, based on a volatility rate of 110% and a call option value of $0.4725 was $360,307 and is being amortized over the vesting period.

 

The Company recognized a total of $162,365, and $237,461 of compensation expense during the three months ended March 31, 2013 and 2012, respectively, on common stock options issued to Employees and Directors that are being amortized over the implied service term, or vesting period, of the options. The remaining unamortized balance of these options is $1,792,457 as of March 31, 2013.

 

Options Exercised

No options were exercised during the three month periods ended March 31, 2013 and 2012.

 

Options Forfeited

No options were forfeited during the three month periods ended March 31, 2013 and 2012.

 

 

Note 12 – Warrants

 

Warrants

We recognized a total of $10,088 and $228,888 of finance expense during the three months ended March 31, 2013 and 2012, respectively, on common stock warrants issued to lenders, including related party amounts of $-0- and $40,393 during the three months ended March 31, 2013 and 2012, respectively. Warrants are amortized over the remaining life of the respective loan. The fair value of the warrants related to the PrenAnte5 Revolving Credit Facility was being amortized over the life of the loan and the amortization was accelerated to fully amortize the fair value as of the early termination date of April 12, 2012. The remaining unamortized balance of these warrants is $98,102 as of March 31, 2013.

 

Warrants Granted

No warrants were granted during the three month periods ended March 31, 2013 and 2012.

 

Warrants Exercised

No warrants were exercised during the three month periods ended March 31, 2013 and 2012.

 

 

Note 13 – 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.

 

16
 

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Consolidated Financial Statements

(Unaudited)

 

We currently estimate that our effective tax rate for the year ending December 31, 2013 will be approximately 37.4%. Losses incurred during the period from April 9, 2011 (inception) to March 31, 2013 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 March 31, 2013, net deferred tax assets were $3,647,468 after a valuation allowance applied to net deferred tax assets of approximately $463,827. 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 March 31, 2013, the Company recognized deferred tax liabilities totaling $7,946,376 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.

 

The tax benefit for the three months ended March 31, 2013 of $433,788 was primarily driven by a change in the Company’s effective tax rate from 41.0% to 37.4% due to a change in state apportionment factors.

 

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 March 31, 2013.

 

 

Note 14 – Commitments and Contingencies

 

The Company from time to time may be involved in various inquiries, administrative proceedings and litigation relating to matters arising in the normal course of business. The Company is not aware of any inquiries or administrative proceedings and is not currently a defendant in any material litigation and is not aware of any threatened litigation that could have a material effect on the Company.

 

The Company periodically maintains cash balances at banks in excess of federally insured amounts. The extent of loss, if any, to be sustained as a result of any future failure of a bank or other financial institution is not subject to estimation at this time.

 

The Company commits to its participation in upcoming well development by signing an Authorization for Expenditure (“AFE”). As of March 31, 2013 the Company had committed to AFE’s of approximately $3.2 million beyond amounts previously paid or accrued. Additionally, 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% working interest in the Dahl Federal 2-15H well that spud on January 6, 2012. The acreage we purchased lies within the riverbed of the Missouri River and there is currently third-party litigation ongoing in the State of North Dakota pertaining to the state’s ownership claim to similar riparian acreage.  We have signed an AFE for the well and the operator has agreed to retroactively honor the AFE if the state is successful in defending its ownership claim. As a result we have not capitalized any of the AFE costs or recognized any sales from this well. Our proportion of the well costs, based on the AFE and our working interest, is approximately $800,000. The well started production on May 21, 2012. Had we recognized the revenue and expenses from this well we would have recorded approximately an additional $600,000 in oil and gas sales and $157,000 of production taxes and operating expenses to date of which $132,000 of oil and gas revenue and $33,000 of production expenses and taxes would relate to the three months ended March 31, 2013. In the event the state is not successful in defending its ownership claim, the state is required to refund the Company the cost to purchase the lease.

 

On April 5, 2013, the Company entered into Change of Control Agreements with its Chief Executive Officer, Ken DeCubellis, and Chief Financial Officer, James Moe. The Change in Control Agreements provide for twelve months of severance in the event of termination as a result of a change in control of the Company.

 

 

17
 

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Consolidated Financial Statements

(Unaudited)

 

Note 15 – Subsequent Events

 

Acreage Swap

On May 8, 2013, the Company closed on an acreage swap agreement. In exchange for 950 net acres in the Company’s Rainbow Field drilling units in Williams County North Dakota, the Company will receive a 7.5% working interest (WI) in the drilling unit consisting of Sections 13 & 14 of Township 154 North, Range 99 West, in the Stockyard Creek Field, an 8.4% WI in the drilling unit consisting of Sections 14 & 15 of Township 154 North, Range 99 West, in the Stockyard Creek Field and a drilling carry on the retained 151 net non-operated acres in the Rainbow Field whereby the operator will pay all drilling and completion costs of the Company’s retained 10% working interest on the first well in the one drilling unit and the Company’s retained 2% working interest on the first well in a second drilling unit. The operator has assessed that the Rainbow Field acreage will support sixteen wells, eight in the middle Bakken and eight in the first bench of the Three Forks.

 

The parties have a mutual option to execute a swap of additional acreage in the second Rainbow Field drilling unit in exchange for additional carried interest in the drilling unit.

 

The operator is currently drilling the first four wells of a fourteen well development plan in the Stockyard Creek Field. This transaction is exclusive of the wells currently producing on the acreage.

 

Oil & Gas Property Divestiture

The Company sold 45 net acres of oil and gas properties in North Dakota for proceeds of $143,686 from April 1, 2013 through May 13, 2013.

 

 

 

 

18
 

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;
·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;
·litigation, disputes and legal claims involving outside parties; and
·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.

 

19
 

Overview and Outlook

 

We are an oil and natural gas exploration and production company. Our properties are located in North Dakota and Montana. 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 March 31, 2013, we controlled the rights to mineral leases covering approximately 12,971 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 believe the following are the key drivers to our business performance:

 

·the ability of the Company to acquire acreage at a price that is significantly below the acreage value when fully developed;
·the ability of operators to successfully drill wells on the acreage position we hold and incur customary costs;
·the sales price per barrel of oil;
·the number of producing wells we own and the performance of those wells; and
·our ability to raise capital to fund drilling costs and acreage acquisitions.

 

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

 

Operational Highlights

 

During the first quarter of 2013, we achieved the following financial and operating results:

 

·production reached 21,802 Boe, or 242 Boe per day, representing 171% production growth compared to the first quarter of 2012;
·participated in the completion of 7 gross (0.29 net) wells, with a 100% success rate in the Bakken and Three Forks plays increasing our total producing wells to 73 gross (2.59 net) wells;
·decreased our general and administrative expenses 69% on a per Boe basis compared to the first quarter of 2012;
·realized $0.6 million of cash flow from operating activities; and
·continued expansion of our activities in the Bakken and Three Forks plays by growing production and continuing to prove and acquire additional acreage.

 

Operationally, our first quarter of 2013 performance reflects continued success in executing our strategy of developing our acreage position and building production. We purchased 800 net mineral acres of oil and gas properties during the quarter. In addition, our production increased 171% to 21,802 Boe in the first quarter of 2013 as compared to first quarter of 2012 production of 8,046 Boe. The increase in production was driven by a 131% increase in producing net wells from 1.12 net wells at March 31, 2012 to 2.59 net wells at March 31, 2013.

 

Total revenues increased 187% in the first quarter of 2013 compared to the first quarter of 2012 driven by higher production and an increase in average realized prices on a Boe basis of 5.9% in the first quarter of 2013 compared to the same period in 2012. Significant changes in crude oil and natural gas prices can have a material impact on our results of operations and our balance sheet.

 

20
 

Recent Developments

 

Acreage Swap

 

On May 8, 2013, the Company closed on an acreage swap agreement. In exchange for 950 net acres in the Company’s Rainbow Field drilling units in Williams County North Dakota, Black Ridge will receive:

 

·7.5% working interest (WI) in the drilling unit consisting of Sections 13 & 14 of Township 154 North, Range 99 West, in the Stockyard Creek Field;
·8.4% WI in the drilling unit consisting of Sections 14 & 15 of Township 154 North, Range 99 West, in the Stockyard Creek Field;
·a drilling carry on the retained 151 net non-operated acres in the Rainbow Field whereby the operator will pay all drilling and completion costs of the Company’s retained 10% working interest on the first well in the one drilling unit and the Company’s retained 2% working interest on the first well in a second drilling unit. The operator has assessed that the Rainbow Field acreage will support sixteen wells, eight in the middle Bakken and eight in the first bench of the Three Forks.

 

The parties have a mutual option to execute a swap of additional acreage in the second Rainbow Field drilling unit in exchange for additional carried interest in the drilling unit.

 

The operator is currently drilling the first four wells of a fourteen well development plan in the Stockyard Creek Field. This transaction is exclusive of the wells currently producing on the acreage.

 

Potential Reverse Stock Split

 

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

 

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

 

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

 

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

 

Production History

 

The following table presents information about our produced oil and gas volumes during the three months ended March 31, 2013 and 2012, respectively. As of March 31, 2013, we controlled approximately 12,971 net acres in the Williston Basin. In addition, the Company owned working interests in 90 gross wells representing 3.17 net wells that are preparing to drill, drilling, awaiting completion, complete or producing.

 

21
 

 

   Three Months Ended 
   March 31, 
   2013   2012 
Net Production:          
Oil (Bbl)   20,496    7,621 
Natural Gas (Mcf)   7,837    2,548 
Barrel of Oil Equivalent (Boe)   21,802    8,046 
           
Average Sales Prices:          
Oil (per Bbl)  $90.70   $85.43 
Effect of oil hedges on average price (per Bbl)  $   $ 
Oil net of hedging (per Bbl)  $90.70   $85.43 
Natural Gas (per Mcf)  $6.68   $5.94 
Effect of natural gas hedges on average price (per Mcf)  $   $ 
Natural gas net of hedging (per Mcf)  $6.68   $5.94 
           
Average Production Costs:          
Oil (per Bbl)  $12.76   $18.60 
Natural Gas (per Mcf)  $0.94   $0.93 
Barrel of Oil Equivalent (Boe)  $12.33   $17.92 

 

Depletion of Oil and Natural Gas Properties

 

Our depletion expense is driven by many factors including certain exploration costs involved in the development of producing reserves, production levels and estimates of proved reserve quantities and future developmental costs. The following table presents our depletion expenses for the three months ended March 31, 2013 and 2012, respectively.

 

   Three Months Ended 
   March 31, 
   2013   2012 
Depletion of oil and natural gas properties  $699,725   $286,903 
           

Productive Oil Wells

 

The following table summarizes gross and net productive oil wells by state at March 31, 2013 and 2012, 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.

 

   March 31, 2013   March 31, 2012 
   Gross   Net   Gross   Net 
North Dakota   72    2.51    37    1.12 
Montana   1    0.08         
Total   73    2.59    37    1.12 

 

Exploratory Oil Wells

 

The following table summarizes gross and net exploratory wells as of March 31, 2013 and 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.

 

   March 31, 2013   March 31, 2012 
   Gross   Net   Gross   Net 
North Dakota   1    0.02    6    0.28 
Total   1    0.02    6    0.28 

 

 

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Results of Operations for the Three Months Ended March 31, 2013 and 2012.

 

The following table summarizes selected items from the statement of operations for the three months ended March 31, 2013 and 2012, respectively.

 

   Three Months Ended     
   March 31,   Increase / 
   2013   2012   (Decrease) 
Oil and gas sales  $1,911,299   $666,206   $1,245,093 
                
Operating expenses:               
Production expenses   268,806    144,151    124,655 
Production taxes   219,342    75,432    143,910 
General and administrative   603,578    713,891    (110,313)
Depletion of oil and gas properties   699,725    286,903    412,822 
Accretion of discount on               
asset retirement obligations   1,152    797    355 
Depreciation and amortization   5,811    6,850    (1,039)
Total operating expenses:   1,798,414    1,228,024    570,390 
                
Net operating income (loss)   112,885    (561,818)   674,703 
                
Total other income (expense)   (232,860)   (353,223)   120,363 
                
Loss before provision for income taxes   (119,975)   (915,041)   795,066 
                
Provision for income taxes   433,788    154,184    279,604 
                
Net income (loss)  $313,813   $(760,857)  $1,074,670 

 

Revenues:

 

We recognized $1,911,299 in revenues from sales of crude oil and natural gas for the three months ended March 31, 2013 compared to revenues of $666,206 for the three months ended March 31, 2012, an increase of $1,245,093, or 187%. These revenues are due to the drilling and development of producing wells. We had 73 gross producing wells as of March 31, 2013, and an additional 17 wells that were either in the drilling preparation, drilling, awaiting completion, or completing stages, compared to 37 gross producing wells, and an additional 13 wells that were either in the drilling preparation, drilling, awaiting completion, or completing stages as of March 31, 2012.

 

Expenses:

 

Production expenses

 

Production expenses were $268,806 and $144,151 for the three months ended March 31, 2013 and 2012, respectively, an increase of $124,655, or 86%. Our production expenses and taxes are greater than the comparative period due to our rapid expansion and increased acreage holdings. Production expenses decreased as a percentage of revenues from 22% in 2012 to 14% in 2013 as one well in the 2012 period experienced high costs of hauling and disposing well water. On a per unit basis, production expenses decreased from $17.92 per Boe in in the first quarter of 2012 to $12.33 per Boe in the first quarter of 2013. While the decrease in production expenses on a per unit basis from the first quarter of 2012 to the first quarter of 2013 was significant, the first quarter 2012 expense was high compared to the 2012 average production expense of $8.79 per Boe. The increase in production expenses per Boe in the first quarter of 2013 over the 2012 average was due primarily to workover expenses.

 

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Production taxes

 

Our production taxes of $219,342 and $75,432 for the three months ended March 31, 2013 and 2012, respectively, an increase of $143,910, or 191%. Production taxes are paid based on realized oil and natural gas sales. Production taxes represented 11.5% and 11.3% of oil and gas revenues in the first quarter of 2013 and 2012, respectively.

 

General and administrative expenses

 

General and administrative expenses for the three months ended March 31, 2013 were $603,578 compared to $713,891 for the three months ended March 31, 2012, a decrease of $110,313, or 15%. Our decrease in general and administrative expenses was primarily due to decreased option related compensation expense and decreased professional fees for legal and consulting services offset by increased compensation as a result of hiring additional employees to support our expanding 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 $699,725 for the three months ended March 31, 2013, compared to $286,903 for the three months ended March 31, 2012, an increase of $412,822, or 144%. The increase was due primarily due to our expansion of production and acquisitions of oil & gas properties during 2012 and the first quarter of 2013.

 

Depreciation

 

Depreciation expense for the three months ended March 31, 2013 was $5,811, compared to $6,850 for the three months ended March 31, 2012, a decrease of $1,039, or 15%. The decreased depreciation expense was due to leasehold improvements that have become fully depreciated.

 

Net operating income (loss)

 

The net operating income for the three months ended March 31, 2013 was $112,885, compared to a net loss of ($561,818) for the three months ended March 31, 2012, a difference of $674,703. Our net operating income (loss) consisted primarily of our oil and gas revenue netted against oil & gas production costs, professional fees, officer salaries and depletion expense incurred as we expanded our oil and gas business. The decrease is a result of our expenses, primarily general and administrative expenses, not growing as rapidly as our oil and gas revenue.

 

Other income and (expenses)

 

Other income and (expenses) for the three months ended March 31, 2013 was ($232,860) compared to ($353,223) for the three months ended March 31, 2012. The net other income and (expenses) for the three months ended March 31, 2013 consisted of $120 of interest income and $232,980 of interest expense including $10,088 of amortized warrant costs and $63,072 of amortized debt financing costs for the three months ended March 31, 2013. Our net other income and (expenses) for the three months ended March 31, 2012 consisted of $42 of interest income and $353,265 of interest expense including $269,281 of amortized warrant costs and $45,984 of amortized debt issuance costs for the three months ended March 31, 2013. Amortization of the warrants and deferred financing costs were accelerated during the three months ended March 31, 2013 due to the termination of the PrenAnte5 credit facility on April 12, 2012.

 

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Provision for income taxes

 

We had income tax benefits of $433,788 and $154,184 for the three months and March 31, 2013 and 2012, respectively, a difference of $279,604. The tax benefit in the three months ended March 31, 2012 was driven by a change in our effective tax rate from 41.0% to 37.4% due to a change in state apportionment factors.

 

Net income (loss)

 

The net income for the three months ended March 31, 2013 was $313,813, compared to a net loss of ($760,857) for the three months ended March 31, 2012, a difference of $1,074,670. Our net income or loss consisted primarily of our oil and gas revenues and income tax benefits netted against our oil & gas production costs, professional fees, officer salaries and interest expense. The difference is primarily due to an increase in revenues greater than the increase in operating expenses, primarily general and administrative expenses, and decreased interest expense due to the acceleration of amortization on warrant and debt financing costs in the 2012 period due to the termination of the PrenAnte5 credit facility on April 12, 2012.

 

 

 

 

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Non-GAAP Financial Measures

 

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, are included below:

 

   Three Months Ended 
   March 31, 
   2013   2012 
Net income (loss)  $313,813   $(760,857)
           
Add back:          
Interest expense, net, excluding amortization of warrant based financing costs   222,772    83,942 
Income tax provision   (433,788)   (154,184)
Depreciation, depletion, and amortization   705,536    293,753 
Accretion of abandonment liability   1,152    797 
Share based compensation   172,453    506,742 
           
Adjusted EBITDA  $981,938   $(29,807)

 

 

 

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Liquidity and capital resources

 

The following table summarizes our total current assets, liabilities and working capital at March 31, 2013 and December 31, 2012, respectively.

 

   March 31,   December 31, 
   2013   2012 
Current Assets  $5,059,484   $6,171,023 
           
Current Liabilities  $4,946,664   $3,291,426 
           
Working Capital  $112,820   $2,879,597 

 

As of March 31, 2013 we had positive working capital of $112,820.

 

The following table summarizes our cash flows during the three month periods ended March 31, 2013 and 2012, respectively.

 

   Three Months Ended 
   March 31, 
   2013   2012 
Net cash provided by operating activities  $594,852   $544,977 
Net cash used in investing activities   (661,879)   (2,440,624)
Net cash provided by financing activities       1,953,081 
           
Net change in cash  $(67,027)  $57,434 

 

Our net cash flows from operations are primarily affected by production volumes and commodity prices. Net cash provided by operating activities was $594,852 and $544,977 for the three months ended March 31, 2013 and 2012, respectively, an increase of $49,875. The increase was due to increased revenues from higher production activity in part offset by higher production costs. Additionally, changes in working capital from operating activities resulted in a decrease in cash of $227,387 in the three months ended March 31, 2013 as compared to an increase in cash of $612,742 for the same period in the previous year.

 

Net cash used in investing activities was $661,879 and $2,440,624 for the three months ended March 31, 2013 and 2012, respectively, a decrease of $1,778,745. The decrease in cash used in investing activities is in part attributable to a decrease in cash spent for property acquisition as we purchased 800 acres of oil and gas properties for $416,283 in the first quarter of 2013 as compared to purchasing 802 acres of oil and gas properties for $1,075,306 in the first quarter of 2012. Additionally, cash spent for well development amounted to $245,596 during the first quarter of 2013 as $1,313,298 of prepaid expenses were applied to well development and accounts payable related to well development increased by $1,613,839.

 

Net cash provided from financing was $-0- and $1,953,081 for the three month period ended March 31, 2013 and 2012, respectively. We did not take any draws on our revolving credit facility in the first quarter of 2013 while funding current operational and investing activity through operating income and working capital. In the first quarter of 2012 we took our first draw of $2,000,000 on our PrenAnte5 revolving credit facility and paid debt issuance costs of $46,919.

 

27
 

Revolving Credit Facility

 

On April 4, 2012, the Company entered into a Secured Revolving Credit Agreement with Dougherty Funding, LLC as Lender which was subsequently amended on September 5, 2012 and December 14, 2012 with an Amended and Restated Secured Revolving Credit Agreement (collectively the “Credit Facility”). Under the terms of the amended Credit Facility, up to $20,000,000 maximum is available from time to time (i) to fund, or to reimburse the Company for, the Company’s pro-rata share of development and production costs for oil wells that relate to the Company’s oil and gas leasehold interests for which there is a valid and enforceable Authorization for Expenditure and that are incurred from and after the date of the Credit Facility, and (ii) to reimburse the Company for amounts that the Company paid from its own funds or from funds that it borrowed under its previous credit facility from Prenante5, LLC as agent pursuant to the Revolving Credit and Security Agreement dated May 2, 2011 (the “Previous Credit Facility”). Of the $20 million Credit Facility, $16.5 million is currently available. If the Company has not successfully completed an equity offering of at least $10,000,000 by August 31, 2014, then advances will no longer be available under the Credit Facility.

 

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

 

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

 

The Credit Facility will mature on August 1, 2015. The Credit Facility may be prepaid with thirty (30) days written notice at any time. In connection with the amended financing, the Company agreed to issue Dougherty Funding, LLC warrants to purchase up to 900,000 shares of the Company’s common stock, of which 585,000 shares have currently been issued, at an exercise price of $0.38. The remaining warrants to purchase 315,000 shares are available to be granted when the remaining $3.5 million of the credit facility becomes available. The warrants expire on August 31, 2015.

 

We took our first draw on April 12, 2012 of $2,450,000, and used $2,051,722 of the proceeds to repay and terminate our predecessor PrenAnte5 revolving credit facility, including interest of $51,722, and we have taken subsequent draws (net of repayments) of $3,298,844 through March 31, 2013 and have used the proceeds to pay for our development of oil and gas wells and.

 

Although our revenues are expected to grow as our wells are placed into production, our revenues are not expected to exceed our investment developing oil and gas wells and our operating costs throughout 2013. However, our availability under our Credit Facility provides ample funding for our property acquisition and development plans throughout 2013. Our prospects still must be considered in light of the risks, expenses and difficulties frequently encountered by companies in their early stage of development. Such risks for us include, but are not limited to, potential failure to earn revenues or to sufficiently monetize certain claims that we have for payments that are owed to us; an inability to identify investment and expansion targets; and dissipation of existing assets. To address these risks, we must, among other things, seek growth opportunities through investment and acquisitions in the oil and gas industry, effectively monitor and manage our claims for payments that are owed to us, implement and successfully execute our business strategy, respond to competitive developments, and attract, retain and motivate qualified personnel. We cannot assure that we will be successful in addressing such risks, and the failure to do so could have a material adverse effect on our business prospects, financial condition and results of operations.

 

28
 

Satisfaction of our cash obligations for the next 12 months.

 

As of March 31, 2013, our balance of cash and cash equivalents was $1,350,313. Our plan for satisfying our cash requirements for the next twelve months, in addition to our revenues from oil and gas sales is through draws on our credit facility, potential sale of shares of our stock, third party financing, and/or traditional bank financing.

 

Off-Balance Sheet Arrangements

 

We have no off-balance sheet arrangements.

 

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 March 31, 2013. 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 March 31, 2013 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 March 31, 2013 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 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS.

 

None.

 

 

ITEM 3. DEFAULTS UPON SENIOR SECURITIES.

 

None.

 

 

ITEM 4. MINE SAFETY DISCLOSURES.

 

Not applicable.

 

 

ITEM 5. OTHER INFORMATION.

 

None.

 

 

ITEM 6. EXHIBITS.

 

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

 

 

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: May 14, 2013 By: /s/ Kenneth DeCubellis  
    Kenneth DeCubellis,  
   

Chief Executive Officer

(Principal Executive Officer)

 
       

 

Dated: May 14, 2013 By: /s/ James A. Moe  
    James A. Moe,  
    Chief Financial Officer (Principal Financial Officer)  
       

 

 

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