UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 

FORM 10-Q

(Mark One)

 

☒  QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934

 

For Quarterly Period Ended September 30, 2015

or

 

☐  TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934

 

For the Transition period from _______________ to ______________

 

Commission File Number 000-53952

 

 

(Exact name of registrant as specified in its charter)

 

Nevada

(State or other jurisdiction of incorporation or organization)

27-2345075

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

 

 

10275 Wayzata Blvd. Suite 100, Minnetonka, Minnesota 55305

(Address of principal executive offices) (Zip Code)

 

(952) 426-1241

(Registrant’s telephone number, including area code)

 

 

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  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  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

 

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

Yes  No 

 

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

 

The number of shares of registrant’s common stock outstanding as of November 10, 2015 was 47,979,990.

 

 

     
 

 

TABLE OF CONTENTS

 

 

PART I - FINANCIAL INFORMATION  
   
ITEM 1 .   FINANCIAL STATEMENTS (Unaudited) 3
    Condensed Balance Sheets as of September 30, 2015 (Unaudited) and December 31, 2014 3
    Unaudited Condensed Statements of Operations for the Three and Nine Months Ended September 30, 2015 and 2014 4
    Unaudited Condensed Statements of Cash Flows for the Nine Months Ended September 30, 2015 and 2014 5
    Notes to the Condensed Financial Statements (Unaudited) 6
ITEM 2 .   MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 22
ITEM 3 .   QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK 37
ITEM 4 .   CONTROLS AND PROCEDURES 37
       
PART II - OTHER INFORMATION
   
ITEM 1.   Legal Proceedings 38
ITEM 1A.   RISK FACTORS 38
ITEM 2.   UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS 38
ITEM 3.   DEFAULTS UPON SENIOR SECURITIES 38
ITEM 4.   MINE SAFETY DISCLOSURES 38
ITEM 5.   OTHER INFORMATION 38
ITEM 6 .   EXHIBITS 38
    SIGNATURES 39

 

  2  
 

 

PART I – FINANCIAL INFORMATION

 

ITEM 1. FINANCIAL STATEMENTS .

 

BLACK RIDGE OIL & GAS, INC.

CONDENSED BALANCE SHEETS

 

    September 30,     December 31,  
    2015     2014  
ASSETS     (Unaudited)          
                 
Current assets:                
Cash and cash equivalents   $ 58,599     $ 94,682  
Derivative instruments, current     2,693,561       3,571,803  
Accounts receivable     3,861,923       5,740,171  
Prepaid expenses     49,107       41,387  
Total current assets     6,663,190       9,448,043  
                 
Property and equipment:                
Oil and natural gas properties, full cost method of accounting:                
Proved properties     128,083,460       112,418,105  
Unproved properties     803,718       591,121  
Other property and equipment     139,004       139,004  
Total property and equipment     129,026,182       113,148,230  
Less, accumulated depreciation, amortization, depletion and allowance for impairment     (78,895,166 )     (18,902,524 )
Total property and equipment, net     50,131,016       94,245,706  
                 
Derivative instruments, long-term           4,007,942  
Debt issuance costs, net     463,792       701,019  
                 
Total assets   $ 57,257,998     $ 108,402,710  
                 
                 
LIABILITIES AND STOCKHOLDERS' EQUITY                
                 
Current liabilities:                
Accounts payable   $ 8,438,772     $ 10,291,262  
Accrued expenses     65,207       57,435  
Total current liabilities     8,503,979       10,348,697  
                 
Asset retirement obligations     353,095       286,804  
Revolving credit facilities and long term debt, net of discounts of $1,461,093 and $2,072,483, respectively     57,458,543       51,834,603  
Deferred tax liability           6,593,040  
                 
Total liabilities     66,315,617       69,063,144  
                 
Commitments and contingencies (See note 16)            
                 
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     34,117,590       33,651,714  
Retained earnings (accumulated deficit)     (43,223,189 )     5,639,872  
Total stockholders' equity     (9,057,619 )     39,339,566  
                 
Total liabilities and stockholders' equity   $ 57,257,998     $ 108,402,710  

 

See accompanying notes to financial statements.

 

  3  
 

 

BLACK RIDGE OIL & GAS, INC.

CONDENSED STATEMENTS OF OPERATIONS

(Unaudited)

               

 

    For the Three Months     For the Nine Months  
    Ended September 30,     Ended September 30,  
    2015     2014     2015     2014  
                         
Oil and gas sales   $ 3,359,684     $ 5,492,326     $ 11,296,220     $ 15,076,743  
Gain (loss) on settled derivatives     7,456,284       (70,253 )     9,436,903       (449,135 )
Gain (loss) on the mark-to-market of derivatives     (3,297,358 )     2,147,798       (4,886,184 )     1,052,639  
Total revenues     7,518,610       7,569,871       15,846,939       15,680,247  
                                 
Operating expenses:                                
Production expenses     887,187       670,404       3,030,707       1,773,458  
Production taxes     330,186       588,923       1,171,530       1,585,755  
General and administrative     754,788       690,189       2,295,241       2,095,071  
Depletion of oil and gas properties     1,778,580       2,275,703       7,346,356       5,994,180  
Impairment of oil and gas properties     30,995,000             52,634,000        
Accretion of discount on asset retirement obligations     8,039       5,833       23,900       15,486  
Depreciation and amortization     4,010       8,214       12,286       24,327  
Total operating expenses     34,757,790       4,239,266       66,514,020       11,488,277  
                                 
Net operating income (loss)     (27,239,180 )     3,330,605       (50,667,081 )     4,191,970  
                                 
Other income (expense):                                
Other income                 6,707        
Interest income           972             972  
Interest (expense)     (1,681,307 )     (1,440,274 )     (4,795,727 )     (3,816,297 )
Total other income (expense)     (1,681,307 )     (1,439,302 )     (4,789,020 )     (3,815,325 )
                                 
Income (loss) before provision for income taxes     (28,920,487 )     1,891,303       (55,456,101 )     376,645  
                                 
Provision for income taxes           (700,587 )     6,593,040       (110,849 )
                                 
Net income (loss)   $ (28,920,487 )   $ 1,190,716     $ (48,863,061 )   $ 265,796  
                                 
                                 
Weighted average common shares outstanding - basic     47,979,990       47,979,990       47,979,990       47,979,990  
Weighted average common shares outstanding - fully diluted     47,979,990       49,588,039       47,979,990       49,824,437  
                                 
Net loss per common share - basic   $ (0.60 )   $ 0.02     $ (1.02 )   $ 0.01  
Net loss per common share - fully diluted   $ (0.60 )   $ 0.02     $ (1.02 )   $ 0.01  

 

See accompanying notes to financial statements.

 

  4  
 

 

BLACK RIDGE OIL & GAS, INC.

CONDENSED STATEMENTS OF CASH FLOWS

(Unaudited)

       

 

    For the Nine Months  
    Ended September 30,  
    2015     2014  
CASH FLOWS FROM OPERATING ACTIVITIES                
Net income (loss)   $ (48,863,061 )   $ 265,796  
Adjustments to reconcile net income (loss) to net cash provided by operating activities:                
Depletion of oil and gas properties     7,346,356       5,994,180  
Depreciation and amortization     12,286       24,327  
Amortization of debt issuance costs     287,227       229,936  
Accretion of discount on asset retirement obligations     23,900       15,486  
Loss (gain) on the mark-to-market of derivatives     4,886,184       (1,052,639 )
Accrued payment in kind interest applied to long term debt     962,550       787,344  
Amortization of original issue discount on debt     127,378       102,566  
Amortization of debt discounts, warrants     484,012       468,670  
Common stock options issued to employees and directors     465,876       433,294  
Deferred income taxes     (6,593,040 )     110,849  
Impairment of oil and natural gas properties     52,634,000        
Decrease (increase) in current assets:                
Accounts receivable     1,878,248       (1,233,582 )
Prepaid expenses     (7,720 )     (45,916 )
Increase (decrease) in current liabilities:                
Accounts payable     153,024       223,779  
Accrued expenses     7,772       61,423  
Net cash provided by operating activities     13,804,992       6,385,513  
                 
CASH FLOWS FROM INVESTING ACTIVITIES                
Proceeds from sale or swap of oil and gas properties     127,348       1,360,920  
Purchases of oil and gas properties and development capital expenditures     (17,968,423 )     (17,410,744 )
Advances to operators           (5,742,272 )
Purchases of other property and equipment           (11,131 )
Net cash used in investing activities     (17,841,075 )     (21,803,227 )
                 
CASH FLOWS FROM FINANCING ACTIVITIES                
Advances from revolving credit facilities and long term debt     14,000,000       24,150,000  
Repayments on revolving credit facilities     (9,950,000 )     (9,600,000 )
Debt issuance costs     (50,000 )     (254,394 )
Net cash provided by financing activities     4,000,000       14,295,606  
                 
NET CHANGE IN CASH     (36,083 )     (1,122,108 )
CASH AT BEGINNING OF PERIOD     94,682       1,150,347  
CASH AT END OF PERIOD   $ 58,599     $ 28,239  
                 
                 
SUPPLEMENTAL INFORMATION:                
Interest paid   $ 3,292,793     $ 2,411,463  
Income taxes paid   $     $  
                 
NON-CASH INVESTING AND FINANCING ACTIVITIES:                
Net change in accounts payable for purchase of oil and gas properties   $ (2,005,514 )   $ 3,821,375  
Advances to operators applied to development of oil and gas properties   $     $ 4,285,575  
Capitalized asset retirement costs, net of revision in estimate   $ 42,391     $ 61,815  

 

See accompanying notes to financial statements.

 

  5  
 

 

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Financial Statements

(Unaudited)

 

Note 1 – Organization and Nature of Business

 

Effective April 2, 2012, Ante5, Inc. changed its corporate name to Black Ridge Oil & Gas, Inc., and continues to be quoted on the OTCQB under the trading symbol “ANFC”. Black Ridge Oil & Gas, Inc. (formerly Ante5, Inc.) (the “Company”) became an independent company in April 2010. 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 rights and 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 wells, 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 (the “SEC”). 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, 2014, which were included in our Annual Report on Form 10-K filed with the SEC. The Company follows the same accounting policies in the preparation of interim reports.

 

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.

 

Environmental Liabilities

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 which would have a material effect on the Company.

 

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. No cash equivalents were on hand at September 30, 2015 and December 31, 2014.

 

  6  
 

 

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Financial Statements

(Unaudited)

 

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 $-0- and $-0- in excess of FDIC and SIPC insured limits at September 30, 2015 and December 31, 2014, respectively. The Company has not experienced any losses in such accounts.

 

Advances to Operators

The Company participates in the drilling of crude oil and natural gas wells with other working interest partners. Due to the capital intensive nature of crude oil and natural gas drilling activities, the working interest partner responsible for conducting the drilling operations may request advance payments from other working interest partners for their share of the costs. The Company expects such advances to be applied by working interest partners against joint interest billings for its share of the drilling operations within 120 days from when the advance is paid.

 

Debt Issuance Costs

Costs relating to obtaining our revolving credit facilities are capitalized and amortized over the term of the related debt using the straight-line method. The unamortized balance of debt issuance costs at September 30, 2015, and December 31, 2014, was $463,792 and $701,019, respectively. Amortization of debt issuance costs charged to interest expense were $287,227 and $229,936 for the nine months ended September 30, 2015 and 2014, 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 September 30, 2015. We depreciate our website development costs on a straight line basis over the estimated useful life of the assets, which is currently three years. We have recognized depreciation expense on these website costs of $257 and $14,165 for the nine months ended September 30, 2015 and 2014, respectively. As of September 30, 2015, all website development costs have been fully depreciated.

 

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.

 

Basic and Diluted Loss Per Share

The basic net loss per share is computed by dividing the net loss (the numerator) by the weighted average number of common shares outstanding for the period (the denominator). Diluted net loss per common share is computed by dividing the net loss 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.

 

  7  
 

 

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Financial Statements

(Unaudited)

 

The reconciliation of the denominators used to calculate basic EPS and diluted EPS for the three and nine months ended September 30, 2015 and 2014 are as follows:

 

    Three Months Ended     Nine Months Ended  
    September 30,     September 30,  
    2015     2014     2015     2014  
Weighted average common shares outstanding – basic     47,979,990       47,979,990       47,979,990       47,979,990  
Plus: Potentially dilutive common shares:                                
Stock options and warrants           1,608,049             1,844,447  
Weighted average common shares outstanding – diluted     47,979,990       49,588,039       47,979,990       49,824,437  

 

Stock options and warrants excluded from the calculation of diluted EPS because their effect was anti-dilutive were 15,757,209 and 8,249,542 for the three months ended September 30, 2015 and 2014, respectively, and 15,757,209 and 8,249,542 for the nine months ended September 30, 2015 and 2014, respectively.

 

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 $12,286 and $24,327 for the nine months ended September 30, 2015 and 2014, 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.

 

  8  
 

 

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Financial Statements

(Unaudited)

 

Full Cost Method

The Company follows the full cost method of accounting for oil and gas operations whereby all costs related to the exploration and development of oil and gas properties are initially capitalized into a single cost center ("full cost pool"). Such costs include land acquisition costs, geological and geophysical expenses, carrying charges on non-producing properties, costs of drilling directly related to acquisition, and exploration activities. Internal costs that are capitalized are directly attributable to acquisition, exploration and development activities and do not include costs related to the production, general corporate overhead or similar activities. Costs associated with production and general corporate activities are expensed in the period incurred. Capitalized costs are summarized as follows for the nine months ended September 30, 2015 and 2014, respectively:

 

    Nine Months Ended  
    September 30,  
    2015     2014  
Capitalized Certain Payroll and Other Internal Costs   $     $ 54,820  
Capitalized Interest Costs     352,572       216,895  
Total   $ 352,572     $ 271,715  

 

Proceeds from sales of proved properties 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.

 

As a result of currently prevailing low commodity prices and their effect on the proved reserve values of properties in 2015, we recorded non-cash ceiling test impairments of $52,634,000 in the nine months ended September 30, 2015. The Company did not have any impairment of its proved oil and gas properties for the nine months ended September 30, 2014. The impairment charges affected our reported net income but did not reduce our cash flow. Continued write downs of oil and natural gas properties are expected to occur until such time as commodity prices have recovered, and remain at recovered levels, so as to meaningfully increase the trailing 12-month average price used in the ceiling calculation. In addition to commodity prices, our production rates, levels of proved reserves, future development costs, transfers of unevaluated properties and other factors will determine our actual ceiling test calculation and impairment analyses in future periods.

 

  9  
 

 

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Financial Statements

(Unaudited)

 

Stock-Based Compensation

The Company adopted FASB guidance on stock based compensation upon inception at April 9, 2010. Under FASB ASC 718-10-30-2, all share-based payments to employees, including grants of employee stock options, are recognized in the income statement based on their fair values. Expense related to common stock and stock options issued for services and compensation totaled $465,876 and $433,294 for the nine months ended September 30, 2015 and 2014, 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, $484,012 and $468,670 of warrant related debt discounts were amortized during the nine months ended September 30, 2015 and 2014, respectively, and treated as interest expense. 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 in the event of termination of the related credit facility.

 

Uncertain Tax Positions

Effective upon inception at April 9, 2010, the Company adopted 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 may 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. 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.

 

Derivative Instruments and Price Risk Management

The Company enters into derivative contracts, including price swaps, caps and floors, which require payments to (or receipts from) counterparties based on the differential between a fixed price and a variable price for a fixed quantity of crude oil without the exchange of underlying volumes. The notional amounts of these financial instruments are based on a portion of the expected production from existing wells. The Company has, and may continue to use exchange traded futures contracts and option contracts to hedge the delivery price of crude oil at a future date.

 

Any realized gains and losses are recorded to gain (loss) on settled derivatives and unrealized gains or losses as a result of mark-to market valuations are recorded to gain (loss) on the mark-to-market of derivatives on the statements of operations.

 

Recent Accounting Pronouncements

New accounting pronouncements are issued by the Financial Accounting Standards Board (“FASB”) that are adopted by the Company as of the specified effective date. If not discussed below, management believes 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, 2014.

 

In April 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2015-03, Interest–Imputation of Interest (Subtopic 835-30) (“ASU 2015-03”), which changes the presentation of debt issuance costs in financial statements. ASU 2015-03 requires an entity to present such costs in the balance sheet as a direct deduction from the related debt liability rather than as an asset. Amortization of the costs will continue to be reported as interest expense. It is effective for annual reporting periods beginning after December 15, 2016. Early adoption is permitted. The new guidance will be applied retrospectively to each prior period presented. The Company is currently in the process of evaluating the impact of adoption of ASU 2015-03 on its balance sheets.

 

In August 2014, the FASB issued ASU No. 2014-15, Presentation of Financial Statements - Going Concern (Subtopic 205-40) (“ASU 2014-15”), which addresses management's responsibility to evaluate whether there is substantial doubt about an entity's ability to continue as a going concern and in certain circumstances to provide related footnote disclosures. The standard is effective for the annual period beginning after December 15, 2016 and for annual and interim periods thereafter. Early adoption is permitted. The Company is currently in the process of evaluating the impact of adoption of ASU 2014-15 will have on its financial statements.

 

  10  
 

 

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Financial Statements

(Unaudited)

 

In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (“ASU 2014-09”), which supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, including most industry-specific revenue recognition guidance throughout the Industry Topics of the Codification. The core principle of ASU 2014-09 is to recognize revenues when promised goods or services are transferred to customers in an amount that reflects the consideration that is expected to be received for those goods or services. ASU 2014-09 is effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period, and early application is not permitted. ASU 2014-09 allows for either full retrospective or modified retrospective adoption. We do not expect the adoption of the new provisions to have a material impact on our financial condition or results of operations.

 

 

Note 3 – Joint Venture

 

On July 23, 2015, the Company signed a definitive agreement with an affiliate of Merced Capital (“Merced”) to form a joint venture that will acquire and develop Williston Basin non-operated assets. The joint venture will be funded by Merced with an initial investment target of $50 Million. Investments will be subject to Merced approval, and will be managed by the Company.

 

The joint venture assets will be managed by the Company in exchange for a management fee and reimbursement of third party expenses, and, after certain investor hurdles are met, the Company will receive a share of profits in the joint venture. The Company will also have the option to co-invest up to 25% on acquisitions and capital expenditures alongside the venture and any such co-investments will reside directly with the Company. Upon the sale of joint venture assets, the Company will also have the option to bid and acquire the assets.

 

We have not yet commenced operations pursuant this joint venture.

 

 

Note 4 – Dahl Federal Recognition

 

During the second quarter of 2015, we recognized well costs, revenues and expenses related to the Dahl Federal 2-15H (Dahl Federal) back to the inception of the well in 2012. The Company acquired the lease for mineral rights for the acreage related to the Dahl Federal from the State of North Dakota on February 7, 2012 for 110 acres or an 8.7% working interest in the Dahl Federal well that spud on January 6, 2012. The acreage we purchased lies within the riverbed of the Missouri River and there had been third-party litigation ongoing in the State of North Dakota pertaining to the state’s ownership claim to similar riparian acreage. We had signed an AFE for the well and the operator agreed to retroactively honor the AFE if the state was successful in defending its ownership claim. As the ownership of our acreage was not certain, we determined we could not recognize the well costs, revenues and expenses until the ownership questions were resolved. In April of 2015, after a North Dakota Supreme Court ruling in favor of the State and subsequent consensus by numerous parties as to the proper survey to be used in determining the high water mark of the Missouri River, the State of North Dakota began requesting payment of royalties for wells under similar circumstances from other operators. Because we believe the ownership questions have now been resolved, we capitalized all well costs since the well’s inception, and have recognized revenues and expenses from the Dahl Federal’s first production in May of 2012. We have capitalized $927,312 of well costs related to the original AFE and subsequent improvements. We recognized $1,241,214 of oil and gas revenues, $75,359 of operating expenses and $137,860 of production taxes during the nine months ended September 30, 2015 related to production prior to 2015 in addition to actual revenue and expenses for the period.

 

  11  
 

 

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Financial Statements

(Unaudited)

 

Note 5 – Property and Equipment

 

Property and equipment at September 30, 2015 and December 31, 2014, consisted of the following:

 

    September 30,     December 31,  
    2015     2014  
Oil and gas properties, full cost method:                
Evaluated costs   $ 128,083,460     $ 112,418,105  
Unevaluated costs, not subject to amortization or ceiling test     803,718       591,121  
      128,887,178       113,009,226  
Other property and equipment     139,004       139,004  
      129,026,182       113,148,230  
Less: Accumulated depreciation, amortization, depletion and impairments     (78,895,166 )     (18,902,524 )
Total property and equipment, net   $ 50,131,016     $ 94,245,706  

 

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

 

    Nine Months Ended  
    September 30,  
    2015     2014  
Depletion of costs for evaluated oil and gas properties   $ 7,346,356     $ 5,994,180  
Depreciation and amortization of other property and equipment     12,286       24,327  
Total depreciation, amortization and depletion   $ 7,358,642     $ 6,018,507  

 

Impairment of Oil and Gas Properties

As a result of currently prevailing low commodity prices and their effect on the proved reserve values of properties in 2015, we recorded non-cash ceiling test impairments of $52,634,000 in the nine months ended September 30, 2015. The Company did not have any impairment of its proved oil and gas properties for the nine months ended September 30, 2014. The impairment charges affected our reported net income but did not reduce our cash flow. Continued write downs of oil and natural gas properties are expected to occur until such time as commodity prices have recovered, and remain at recovered levels, so as to meaningfully increase the trailing 12-month average price used in the ceiling calculation. In addition to commodity prices, our production rates, levels of proved reserves, future development costs, transfers of unevaluated properties and other factors will determine our actual ceiling test calculation and impairment analyses in future periods.

 

 

Note 6 – Oil and Gas Properties

 

The following table summarizes gross and net productive oil wells by state at September 30, 2015 and 2014. 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.

 

    September 30, 2015     September 30, 2014  
    Gross     Net     Gross     Net  
North Dakota     336       10.51       230       7.28  
Montana     5       0.37       1       0.08  
Total     341       10.88       231       7.36  

 

The Company’s oil and gas properties consist of all acreage acquisition costs (including cash expenditures and the value of stock consideration), drilling costs and other associated capitalized costs. As of September 30, 2015 and 2014, our principal oil and gas assets included approximately 8,509 and 9,919 net acres, respectively, located in North Dakota and Montana.

 

  12  
 

 

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Financial Statements

(Unaudited)

 

The following table summarizes our capitalized costs for the purchase and development of our oil and gas properties for the nine months ended September 30, 2015 and 2014, respectively:

 

    Nine Months Ended  
    September 30,  
    2015     2014  
Purchases of oil and gas properties and development costs for cash   $ 17,968,423     $ 17,410,744  
Purchase of oil and gas properties accrued at period-end     7,359,282       11,775,176  
Purchase of oil and gas properties accrued at beginning of period     (9,364,796 )     (7,953,801 )
Advances to operators applied to purchase of oil and gas properties           4,285,575  
Capitalized asset retirement costs, net of revision in estimate     42,391       61,815  
Total purchase and development costs, oil and gas properties   $ 16,005,300     $ 25,579,509  

 

2015 Acquisitions

During the nine months ended September 30, 2015, we purchased approximately nine net leasehold acres of oil and gas properties. In consideration for the assignment of these mineral leases, we paid the sellers a total of approximately $102,928.

 

2015 Divestitures

During the nine months ended September 30, 2015, we sold a total of approximately 14 net leasehold acres of oil and gas properties and three wellbores for total proceeds of $127,348. No gain or loss was recorded pursuant to the sales.

 

2014 Acquisitions

During the nine months ended September 30, 2014, we purchased approximately 319 net leasehold acres of oil and gas properties. In consideration for the assignment of these mineral leases, we paid the sellers a total of approximately $2,401,318.

 

2014 Divestitures

During the nine months ended September 30, 2014, we sold a total of approximately 490 net leasehold acres of oil and gas properties for total proceeds of $1,340,920. No gain or loss was recorded pursuant to the sales.

 

2014 Swap Transactions

During the nine months ended September 30, 2014, we traded approximately 52 net leasehold acres of oil and gas properties for 40 net mineral acres and $20,000 in cash. No gain or loss was recorded pursuant to the transaction.

 

Undeveloped Acreage Expirations

During the nine months ended September 30, 2015, we had leases encompassing 1,466 net acres expire with carrying costs of $1,443,848 that had been reserved and transferred to the full cost pool subject to depletion. We estimate that approximately 400 additional net acres with carrying costs of approximately $550,563 will expire prior to the commencement of production activities on the related leased property during 2015. The carrying costs of leases we estimate will expire during the remainder of 2015 had been reserved and transferred to the full cost pool subject to depletion in 2014.

 

 

Note 7 – Asset Retirement Obligation

 

The Company has asset retirement obligations (ARO) 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 ARO.

 

  13  
 

 

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Financial Statements

(Unaudited)

 

The following table summarizes the Company’s asset retirement obligation transactions recorded in accordance with the provisions of FASB ASC 410-20-25 during the nine months ended September 30, 2015 and 2014:

 

    Nine Months Ended  
    September 30,  
    2015     2014  
Beginning ARO   $ 286,804     $ 160,665  
Liabilities incurred for new wells placed in production     42,391       61,815  
Accretion of discount on ARO     23,900       15,486  
Ending ARO   $ 353,095     $ 237,966  

 

 

Note 8 – Related Party

 

We 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. Pursuant to the lease, we occupy approximately 2,813 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 ninety (90) day notice to terminate the lease, with base rents of $2,110 per month, plus common area operations and maintenance charges, and monthly parking fees of $240 per month, for the period from November 15, 2013 to October 31, 2014, and subject to increases of $117 per month beginning November 1, 2014 and for each of the subsequent three year periods. We have paid a total of $52,298 and $52,284 to this entity during the nine months ended September 30, 2015 and 2014, respectively.

 

 

Note 9 – Derivative Instruments

 

The Company is required to recognize all derivative instruments on the balance sheet as either assets or liabilities measured at fair value. The Company has not designated its derivative instruments as cash flow hedges for accounting purposes and, as such, marks its derivative instruments to fair value and recognizes the realized and unrealized changes in fair value in its statements of operations under the captions “Loss on settled derivatives” and “Loss on the mark-to-market of derivatives.”

 

The Company has utilized swap and collar derivative contracts. While the use of these derivative instruments limits the downside risk of adverse price movements, their use also limits the upside revenue potential of upward price movements.

 

For a fixed price swap contract, the counterparty is required to make a payment to the Company if the settlement price for any settlement period is less than the swap price and the Company is required to make a payment to the counterparty if the settlement price for any period is greater than the swap price. For a collar contract, the counterparty is required to make a payment to the Company if the settlement price for any settlement period is below the floor price, the Company is required to make a payment to the counterparty if the settlement price for any settlement period is above the ceiling price and no payment is required by either party if the settlement price for any settlement period is between the floor price and the ceiling price.

 

The Company’s derivative contracts are settled based on reported settlement prices on commodity exchanges, with crude oil derivative settlements based on NYMEX West Texas Intermediate (“WTI”) pricing.

 

  14  
 

 

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Financial Statements

(Unaudited)

 

As of September 30, 2015, the Company had outstanding derivative contracts with respect to future production as follows:

 

Crude Oil Swaps

 

Settlement Period   Oil (Barrels)     Fixed Price  
October 1, 2015 – December 31, 2015     6,000     $ 88.28  
October 1, 2015 – December 31, 2015     5,250     $ 89.70  
October 1, 2015 – December 31, 2015     3,000     $ 92.38  
October 1, 2015 – December 31, 2015     7,500     $ 90.16  
October 1, 2015 – December 31, 2015     36,000     $ 61.87  
April 1, 2016 – May 31, 2016     15,000     $ 62.88  
April 1, 2016 – May 31, 2016     10,000     $ 90.36  
April 1, 2016 – May 31, 2016     4,000     $ 88.15  

 

Crude Oil Costless Collars

 

          Floor/Ceiling        
Settlement Period   Oil (Barrels)     Price     Basis  
October 1, 2015 – December 31, 2015     9,000       $75.00/$95.60       NYMEX  
April 1, 2016 – May 31, 2016     3,334       $80.00/$89.50       NYMEX  

 

As of September 30, 2015, the Company had total volume on open commodity swaps of 86,750 barrels at a weighted average price of approximately $73.55 per barrel.

 

Derivative Liquidations

On September 24, 2015, the Company settled all its 2017 and 2018 derivative contracts and the majority of its 2016 derivative contracts prior to the expiration of their contractual maturities, resulting in the receipt of cash proceeds totaling $6,255,000. The resulting gain is included in gain (loss) on settled derivatives for the nine months ended September 30, 2015.

 

Derivative Gains and Losses

The following table presents realized and unrealized gains and losses on derivative instruments for the periods presented:

 

    Nine Months Ended  
    September 30,  
    2015     2014  
Gain (loss) on settled derivatives:                
Crude oil fixed price swaps   $ 8,579,756     $ (449,135 )
Crude oil collars     857,147        
Gain (loss) on settled derivatives, net   $ 9,436,903     $ (449,135 )
                 
Gain (loss) on the mark-to-market of derivatives:                
Crude oil fixed price swaps   $ (4,366,810 )   $ 1,012,502  
Crude oil collars     (519,374 )     40,137  
Gain (loss) on the mark-to-market of derivatives, net   $ (4,886,184 )   $ 1,052,639  

 

Balance Sheet Offsetting of Derivative Assets and Liabilities

In accordance with FASB issued ASU No. 2011-11, Balance Sheet (Topic 210)-Disclosures about Offsetting Assets and Liabilities, all of the Company’s derivative contracts are carried at their fair value in the condensed balance sheets under the captions “Derivative instruments” and “Noncurrent derivative instruments”. Derivative instruments from the same counterparty that are subject to contractual terms which provide for net settlement are reported on a net basis in the condensed balance sheets. The following tables present the gross amounts of recognized derivative assets and liabilities, the amounts offset under the netting arrangements with counterparties, and the resulting net amounts presented in the condensed balance sheets for the periods presented, all at fair value.

 

  15  
 

 

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Financial Statements

(Unaudited)

 

    September 30, 2015     December 31, 2014  
          Gross     Net           Gross     Net  
    Gross     amounts     amounts of     Gross     amounts     amounts of  
    amounts of     offset     assets     amounts of     offset     assets  
    recognized     on balance     on balance     recognized     on balance     on balance  
    assets     sheet     sheet     assets     sheet     sheet  
Commodity derivative assets   $ 2,694,001     $ (440 )   $ 2,693,561     $ 7,620,896     $ (41,151 )   $ 7,579,745  

 

 

      September 30, 2015       December 31, 2014  
              Gross       Net               Gross       Net  
      Gross       amounts       amounts of       Gross       amounts       amounts of  
      amounts of       offset       liabilities       amounts of       offset       liabilities  
      recognized       on balance       on balance       recognized       on balance       on balance  
      liabilities       sheet       sheet       liabilities       sheet       sheet  
Commodity derivative liabilities   $     $     $     $     $     $  

 

The following table reconciles the net amounts disclosed above to the individual financial statement line items in the condensed balance sheets:

 

    September 30,     December 31,  
    2015     2014  
Derivative assets   $ 2,693,561     $ 3,571,803  
Noncurrent derivative assets           4,007,942  
Net amount of assets on the balance sheet     2,693,561       7,579,745  
                 
Current portion of derivative liabilities            
Derivative liabilities            
Net amount of liabilities on the balance sheet            
Total derivative assets (liabilities), net   $ 2,693,561     $ 7,579,745  

 

 

Note 10 – 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.

 

  16  
 

 

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Financial Statements

(Unaudited)

 

The following schedule summarizes the valuation of financial instruments at fair value on a recurring basis in the balance sheets as of September 30, 2015 and December 31, 2014:

 

    Fair Value Measurements at September 30, 2015  
    Level 1     Level 2     Level 3  
Assets                        
Cash and cash equivalents   $ 58,599     $     $  
Derivative Instruments (crude oil swaps and collars)           2,693,561        
Total assets     58,599       2,693,561        
Liabilities                        
Revolving credit facilities and long term debt, net of discounts           57,458,543        
Total Liabilities           57,458,543        
    $ 58,599     $ (54,764,982 )   $  

 

    Fair Value Measurements at December 31, 2014  
    Level 1     Level 2     Level 3  
Assets                        
Cash and cash equivalents   $ 94,682     $     $  
Derivative Instruments (crude oil swaps and collars)           7,579,745        
Total assets     94,682       7,579,745        
Liabilities                        
Revolving credit facilities and long term debt, net of discounts           51,834,603        
Total Liabilities           51,834,603        
    $ 94,682     $ (44,254,858 )   $  

 

There were no transfers of financial assets or liabilities between Level 1 and Level 2 inputs for the nine months ended September 30, 2015 and 2014.

 

Level 2 liabilities include Revolving credit facilities. No fair value adjustment was necessary during the nine months ended September 30, 2015 and 2014.

 

 

Note 11 – Revolving Credit Facilities and Long Term Debt

 

The Company, as borrower, entered into a Credit Agreement dated August 8, 2013 and amendments thereto dated December 13, 2013, March 24, 2014, April 21, 2014, September 11, 2014, March 30, 2015 and August 10, 2015 (as amended, the “Senior Credit Agreement ) with Cadence Bank, N.A. (“Cadence”), as lender (the “Senior Credit Facility”). Under the terms of the Senior Credit Agreement, a senior secured revolving line of credit in the maximum aggregate principal amount of $50 million is available from time to time (i) for direct investment in oil and gas properties, (ii) for general working capital purposes, including the issuance of letters of credit, and (iii) to refinance the then existing debt under the Company’s former credit facility.

 

Availability under the Senior Credit Facility is at all times subject to the then-applicable borrowing base, determined by Cadence in a manner consistent with the normal and customary oil and gas lending practices of Cadence. Availability was initially set at $7 million and is subject to periodic redeterminations. The availability was $35 million as of December 31, 2014, and subsequently adjusted to $34 million on March 30, 2015. The availability remains at $34 million, of which $26.65 million was borrowed and outstanding as of September 30, 2015. Subject to availability under the borrowing base, the Company may borrow, repay and re-borrow funds in amounts of $250,000 or more. At the Company’s election, the unpaid principal balance of any borrowings under the Senior Credit Facility may bear interest at either (i) the Base Rate, as defined in the Senior Credit Facility, plus the applicable margin, which varies from 1.00% to 1.50% or (ii) the LIBOR rate, as defined in the Senior Credit Facility, plus the applicable margin, which varies from 3.00% to 3.50%. Interest is payable for Base Rate loans on the last business day of the month and for LIBOR loans on the last LIBOR business day of each LIBOR interest period. The Company is also required to pay a quarterly fee of 0.50% on any unused portion of the borrowing base, as well as a facility fee of 0.90% of the initial and any subsequent additions to the borrowing base.

 

  17  
 

 

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Financial Statements

(Unaudited)

 

The Senior Credit Facility’s maturity date of August 8, 2016, was subsequently amended to January 15, 2017 pursuant to the amendment on March 30, 2015. The Company may prepay the entire amount of Base Rate loans at any time, and may prepay the entire amount of LIBOR loans upon at least three business days’ notice to Cadence. The Senior Credit Facility is secured by first priority interests in mortgages on substantially all of the Company’s assets, including but not limited to the Company’s mineral interests in North Dakota and Montana.

 

The Company had borrowings of $26.65 million and $22.6 million outstanding under the Senior Credit Agreement as of September 30, 2015 and December 31, 2014, respectively.

 

Subordinated Credit Facility

The Company, as borrower, entered into a Second Lien Credit Agreement dated August 8, 2013 and amendments thereto dated December 13, 2013, March 24, 2014, April 21, 2014, September 11, 2014, March 30, 2015, and August 10, 2015 (as amended, the “Subordinated Credit Agreement”) by and among the Company, as borrower, Chambers Energy Management, LP, as administrative agent (“Chambers”), and the several other lenders named therein (the “Subordinated Credit Facility”). Under the Subordinated Credit Facility, term loans in the aggregate principal amount of up to $75 million are available from time to time (i) to repay the Previous Credit Facility, (ii) for fees and closing costs in connection with both the Senior Credit Facility and the Subordinated Credit Facility (together, the “Credit Facilities”), and (iii) general corporate purposes.

 

The Subordinated Credit Agreement provided initial commitment availability of $25 million, which was subsequently amended to the current availability of $30 million, with the remaining commitments subject to the approval of Chambers and other customary conditions. The Company may borrow the available commitments in amounts of $5 million or more and shall not request borrowings of such loans more than once a month, provided that the initial draw was at least $15 million. Loans under the Subordinated Credit Facility shall be funded net of a 2% OID. The unpaid principal balance of borrowings under the Subordinated Credit Facility bears interest at the Cash Interest Rate plus the PIK Interest Rate. The Cash Interest Rate is 9.00% per annum plus a rate per annum equal to the greater of (i) 1.00% and (ii) the offered rate for three-month deposits in U.S. dollars that appears on Reuters Screen LIBOR 01 as of 11:00 a.m. (London time) on the second full LIBOR business day preceding the first day of each calendar quarter. The PIK Interest Rate is equal to 4.00% per annum. Interest is payable on the last day of each month. The Company is also required to pay an annual nonrefundable administration fee of $50,000 and a monthly availability fee computed at a rate of 0.50% per annum on the average daily amount of any unused portion of the available amount under the commitment.

 

The Subordinated Credit Facility matures on June 30, 2017. Upon at least three business days’ written notice, the Company may prepay the entire amount under the loans, together with accrued interest. Each prepayment made prior to the second anniversary of the funding date, as defined in the Subordinated Credit Facility, shall be accompanied by a make-whole amount, as defined in the Subordinated Credit Agreement. Prepayments made on or after the second anniversary of the funding date shall be accompanied by an applicable premium, as set forth in the Subordinated Credit Agreement. The Subordinated Credit Facility is secured by second priority interests on substantially all of the Company’s assets, including but not limited to second priority mortgages on the Company’s mineral interests in North Dakota and Montana.

 

The first funding from the Subordinated Credit Facility occurred on September 9, 2013 at which time we drew $14.7 million, net of a $300,000 original issue discount, from the Subordinated Credit Agreement and used $10,226,057 of those proceeds to repay and terminate a previously outstanding revolving credit facility. We have drawn an additional $14.7 million, net of $300,000 original issue discounts, through September 30, 2015. The Company had borrowings of $30 million and $30 million outstanding under the Subordinated Credit Facility as of September 30, 2015 and December 31, 2014, respectively.

 

Intercreditor Agreements and Covenants

Cadence and Chambers have entered into an Intercreditor Agreement dated August 8, 2013 (the “Intercreditor Agreement”). The Intercreditor Agreement provides that any liens on the assets of the Company securing indebtedness under the Subordinated Credit Facility are subordinate to liens on the assets securing indebtedness under the Senior Credit Facility and sets forth the respective rights, obligations and remedies of the lenders under the Senior Credit Facility with respect to their first priority liens and the lenders under the Subordinated Credit Facility with respect to their second priority liens.

 

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BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Financial Statements

(Unaudited)

 

The Credit Facilities, as amended, require customary affirmative and negative covenants for credit facilities of the respective types and sizes for companies operating in the oil and gas industry, as well as customary events of default. Furthermore, the Credit Facilities contain financial covenants that require the Company to satisfy certain specified financial ratios. The Senior Credit Agreement requires the Company to maintain, as of the last day of each fiscal quarter of the Company, (i) a collateral coverage ratio (reserve value plus consolidated working capital to adjusted indebtedness) of at least 0.65 to 1.00 through the quarter ending June 30, 2014, 0.70 to 1.00 for the quarters ending September 30, 2014 and December 31, 2014, was waived for the quarters ending March 31, 2015 and June 30, 2015, and 0.70 to 1.00 for the quarter ending September 30, 2015, and 0.80 to 1.00 for the quarter ending December 31, 2015 and thereafter, (ii) a ratio of current assets, including debt facility available to be drawn, to current liabilities of a minimum of 1.0 to 1.0, except for the quarter ending June 30, 2014, which was waived, (iii) a net debt to EBITDAX, as defined in the Senior Credit Agreement, ratio of 3.75 to 1.00 for the quarter ended March 31, 2014, 4.25 to 1.00 for the quarters ended June 30, 2014 and September 30, 2014, 4.00 to 1.00 for the quarter ended December 31, 2014, was waived for the quarters ended March 31, 2015 and June 30, 2015, and 3.50 to 1.00 for the quarter ending September 30, 2015, and 3.65 to 1.00 for the quarter ending December 31, 2015, and 3.50 to 1.00 for the quarter ending March 31, 2016 and thereafter, in each case calculated on a modified trailing four quarter basis, (iv) a maximum senior leverage ratio of not more than 2.5 to 1.0 calculated on a modified trailing four quarter basis, and (v) a minimum interest coverage ratio of not less than 3.0 to 1.0. The Subordinated Credit Agreement requires the Company to maintain, as of the last day of each fiscal quarter of the Company, (i) a collateral coverage ratio (reserve value plus consolidated working capital to adjusted indebtedness) of at least 0.65 to 1.00 through the quarter ending June 30, 2014, 0.70 to 1.00 for the quarters ending September 30, 2014 and December 31, 2014, was waived for the quarters ending March 31, 2015 and June 30, 2015, and 0.70 to 1.00 for the quarter ending September 30, 2015, and 0.80 to 1.00 for the quarter ending December 31, 2015 and thereafter, (ii) a consolidated net leverage ratio (adjusted total indebtedness less the amount of unrestricted cash equivalents to consolidated EBITDA) of no more than 3.75 to 1.00 for the quarter ending March 31, 2014, 4.25 to 1.00 for the quarters ending June 30, 2014 and September 30, 2014, 4.00 to 1.00 for the quarter ending December 31, 2014, was waived for the quarters ending March 31, 2015 and June 30, 2015, and 3.50 to 1.00 for the quarter ending September 30, 2015, and 3.65 to 1.00 for the quarter ending December 31, 2015, and 3.50 to 1.00 for the quarter ending March 31, 2016 and thereafter, calculated on a modified trailing four quarter basis, (iii) a consolidated cash interest coverage ratio (consolidated EBITDA to consolidated cash interest expense) of no less than 2.5 to 1.0, calculated on a modified trailing four quarter basis and (iv) a ratio of consolidated current assets to consolidated current liabilities of at least 1.0 to 1.0, except for the quarter ending June 30, 2015 when the covenant was waived. In addition, each of the Credit Facilities requires that the Company enter into hedging agreements based on anticipated oil production from currently producing wells as agreed to by the lenders. The Company is in compliance with all covenants, as amended, for the period ending September 30, 2015.

 

Debt Discount, Detachable Warrants

In connection with the Subordinated Credit Facility, the Company agreed to issue to the lenders detachable warrants to purchase up to 5,000,000 shares of the Company’s common stock at an exercise price of $0.65 per share. The warrants expire on August 8, 2018. Proceeds from the loan were allocated between the debt and equity based on the relative fair values at the time of issuance, resulting in a debt discount of $2,473,576 at issuance that is presented as a debt discount on the balance sheet and is being amortized using the effective interest method over the life of the credit facility, which matures on June 30, 2017. A total of $484,012 and $468,670 was amortized during the nine months ended September 30, 2015 and 2014, respectively. The remaining unamortized balance of the debt discount attributable to the warrants is $1,161,737 as of September 30, 2015.

 

Amounts outstanding under revolving credit facilities and long term debts consisted of the following as of September 30, 2015 and December 31, 2014, respectively:

 

    September 30,     December 31,  
    2015     2014  
Senior Revolving Credit Facility, Cadence Bank, N.A.   $ 26,650,000     $ 22,600,000  
Subordinated Credit Agreement, Chambers     30,000,000       30,000,000  
PIK Interest on Subordinated Credit Agreement, Chambers     2,269,636       1,307,086  
                 
Total credit facilities and long term debts     58,919,636       53,907,086  
Less: Unamortized OID     (299,356 )     (426,734 )
Less: Unamortized debt discount attributable to warrants     (1,161,737 )     (1,645,749 )
Total credit facilities and long term debts, net of discounts     57,458,543       51,834,603  
Less: current maturities            
                 
Long term portion of credit facilities and long term debts   $ 57,458,543     $ 51,834,603  

 

Net proceeds of $29.4 million were received from our $30 million in advances due to $600,000 of OID pursuant to the Subordinated Credit Agreement at issuance that is presented as a debt discount on the balance sheet and is being amortized using the effective interest method over the life of the credit facility, which matures on June 30, 2017. A total of $127,378 and $102,566 was amortized during the nine months ended September 30, 2015 and 2014, respectively. The remaining unamortized balance of the debt discount attributable to the OID is $299,356 as of September 30, 2015.

 

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BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Financial Statements

(Unaudited)

 

The following presents components of interest expense for the nine months ended September 30, 2015 and 2014, respectively:

 

    Nine Months Ended  
    September 30,  
    2015     2014  
Accrued PIK interest   $ 962,551     $ 787,344  
Amortization of OID     127,378       102,566  
Interest and commitment fees     3,287,131       2,444,676  
Amortization of debt issuance costs     287,227       229,936  
Amortization of warrant costs     484,012       468,670  
Less interest capitalized to the full cost pool of our proved oil & gas properties     (352,572 )     (216,895 )
    $ 4,795,727     $ 3,816,297  

 

 

Note 12 – 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.

 

 

Note 13 – Options

 

Options Granted

On September 30, 2015, the Company granted 1,000,000 options to purchase its common stock to its employees and certain of its directors. The options vest annually over five years beginning on the first anniversary of the grant and are exercisable until the tenth anniversary of the date of grant at an exercise price of $0.172 per share. The total estimated fair value using the Black-Scholes Pricing Model, based on a volatility rate of 106% and a call option value of $0.1434 was $143,379 and is being amortized over the vesting period.

 

The Company recognized a total of $465,876, and $433,294 of compensation expense during the nine months ended September 30, 2015 and 2014, 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 $1,650,044 as of September 30, 2015.

 

Options Exercised

No options were exercised during the nine months ended September 30, 2015 and 2014.

 

Options Expired/Forfeited

On September 30, 2015, 1,000,000 fully vested options with a strike price of $1.00 per share were voluntarily cancelled by a director of the Company. The fair market value of the options had been fully amortized prior to forfeiture. No options expired or were forfeited during the nine months ended September 30, 2014.

 

 

Note 14 – Warrants

 

Warrants Granted

No warrants were granted during the nine months ended September 30, 2015 and 2014.

 

We recognized a total of $484,012 and $468,670 of finance expense during the nine months ended September 30, 2015 and 2014, respectively, on common stock warrants issued to lenders, respectively. All warrants granted pursuant to debt financings are amortized over the remaining life of the respective loan.

 

Warrants Exercised

No warrants were exercised during the nine months ended September 30, 2015 and 2014.

 

  20  
 

 

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Financial Statements

(Unaudited)

 

Note 15 – Income Taxes

 

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

 

We currently estimate that our effective tax rate for the year ending December 31, 2015 will be approximately 12%. Losses incurred during the period from April 9, 2011 (inception) to September 30, 2015 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 September 30, 2015, net deferred tax assets were $15,417,147, after an offsetting reduction in deferred tax liabilities of $1,066,200, primarily 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, was applied. A valuation allowance of approximately $15,417,147 was applied to the remaining net deferred tax assets. This valuation allowance reflects an allowance on only a portion of the Company’s deferred tax assets which the Company believes it is more likely than not that the benefit of these assets will not be realized. We have not provided any valuation allowance against our deferred tax liabilities, which were netted against our deferred tax assets.

 

The tax benefit for the nine months ended September 30, 2015 of $6,593,040 was primarily driven by the Company’s loss before provision for income taxes.

 

In accordance with FASB ASC 740, the Company has evaluated its tax positions and determined there are no significant uncertain tax positions as of any date on, or before September 30, 2015.

 

 

Note 16 – 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 September 30, 2015, the Company had committed to AFE’s of approximately $1.6 million beyond amounts previously paid or accrued.

 

 

Note 17 – Subsequent Events

 

Debt Facilities

During the period from October 1, 2015 to November 10, 2015, the Company drew an additional $0.25 million, net of repayments, on the senior secured facility.

 

Borrowing Base Redetermination

The borrowing base on our Senior Secured Facility was adjusted by our lender as part of a regularly scheduled redetermination from $34 million to $33 million effective October 1, 2015. The borrowing base will adjust down to $32 million on November 16, 2015 if certain commodity hedging is not put in place. The next scheduled borrowing base amount determination date is April 1, 2016.

 

  21  
 

 

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 collect payments owed to us;
· material defaults on monetary obligations owed us, resulting in unexpected losses;
· inability to effectively manage our hedging activities;
· inadequate capital to acquire working interests in oil and gas prospects and to participate in the drilling and production of oil and other hydrocarbons;
· inability to meet financial covenants and restrictions associated with our debt agreements;
  · inability to maintain adequate liquidity to meet our financial obligations;
· unavailability of oil and gas prospects to acquire;
· decline in oil prices;
· 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.

 

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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 September 30, 2015, we owned an interest in 341 gross (10.88 net) producing oil and gas wells and controlled the rights to mineral leases covering approximately 8,509 net acres for prospective drilling to the Bakken and/or Three Forks formations. The following table provides a summary of important information regarding our assets:

 

As of September 30, 2015     As of December 31, 2014  
      Productive Wells     Average Daily     Proved        
Net Acres (1)     Gross     Net     Production (2)     Reserves     PV-10 (3)  
                  (Boe per day)     (000'sBoe)     ($000)  
  8,509       341       10.88       1,075       5,356       100,335  

 

(1) Includes leases encompassing approximately 400 net acres that we estimate will expire over the remainder of 2015.

(2) Represents average daily production over the three months ended September 30, 2015.

(3) PV-10 is a non-GAAP financial measure calculated using mandated pricing that is historical in nature. The pricing used to calculate PV-10 as of December 31, 2014 assumed a WTI oil price of $94.99, a Henry Hub gas price of $4.35. Market prices as of September 30, 2015 are considerably lower. For further information and reconciliation to the most directly comparable GAAP measure, see “Item 2. Properties-Proved Reserves” in our Annual Report on Form 10-K for the fiscal year ended December 31, 2014.

 

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;
· our ability to raise capital to fund drilling costs and acreage acquisitions; and
· maintain a strong balance sheet and adequate liquidity to achieve our objectives.

 

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

 

Recent Developments

 

Derivative Liquidation

 

During the third quarter of 2015, we settled all of our 2017 and 2018 derivative contracts and the majority of our 2016 derivative contracts prior to the expiration of their contractual maturities, resulting in cash proceeds totaling $6,255,000. The resulting gain is included in our gain on settled derivatives for the three and nine months ended September 30, 2015.

 

  23  
 

 

Operational Highlights

 

During the third quarter of 2015, we achieved the following financial and operating results:

 

· production reached 1,075 Boe per day, representing 41% growth compared to the third quarter of 2014 and a 4% decrease compared to the second quarter of 2015;
· participated in the completion of 50 gross (1.92 net) wells increasing our total producing wells to 341 gross (10.88 net) wells;
· attained adjusted EBITDA from operations of $9.0 million, which includes a $6.3 million gain from the liquidation of derivatives prior to their maturity;
· reduced general and administrative expenses to $7.63 per Boe, compared to $9.85 per Boe in the third quarter of 2014, representing a 23% decrease on a per Boe basis;
· realized $8.3 million of cash flow from operating activities;
· continued development of our core acreage including our Corral Creek and Teton projects; and
  · ended the quarter with $26.65 million drawn on our senior secured revolving credit facility, a net reduction of $3.1 million from the end of the second quarter of 2015.

 

Operationally, our third quarter of 2015 performance reflects continued success in executing our strategy of developing our acreage position and building production. Our production increased 41% to 98,933 Boe in the third quarter of 2015, as compared to third quarter of 2014 production of 70,043 Boe. The increase in production was driven by a 48% increase in net producing wells from 7.36 net wells at September 30, 2014 to 10.88 net wells at September 30, 2015.

 

Total revenues decreased 1% in the third quarter of 2015, compared to the third quarter of 2014 primarily driven by a large decrease in realized prices which was offset by realized gains on derivatives. Realized prices on a Boe basis decreased 57% before the effect of settled derivatives but increased 41% after the effect of settled derivatives in the third quarter of 2015 as compared to the third quarter of 2014. Realized gains on settled derivatives amounted to $7.5 million in the third quarter of 2015, including $6.3 million received as a result of liquidating derivatives prior to their maturity. Additionally, we had a loss on the mark-to-market of derivatives of $3.3 million for third quarter of 2015, as compared to a gain on the mark-to-market derivatives of $2.1 million for the third quarter of 2014. Significant changes in crude oil and natural gas prices can have a material impact on our results of operations and our balance sheet.

 

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. However, there can be no assurance 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.

 

  24  
 

 

Production History

 

The following table presents information about our produced oil and gas volumes during the three and nine month periods ended September 30, 2015 and 2014, respectively. As of September 30, 2015, we controlled approximately 8,509 net acres in the Williston Basin. In addition, the Company owned working interests in 341 gross wells representing 10.88 net wells that are producing and an additional 27 gross wells representing 0.26 net wells that are preparing to drill, drilling, awaiting completion or completing.

 

    Three Months Ended     Nine Months Ended  
    September 30,     September 30,  
    2015     2014     2015     2014  
Net Production:                                
Oil (Bbl)     86,533       62,603       249,593       164,570  
Natural gas (Mcf)     74,279       44,639       244,974       106,458  
Barrel of oil equivalent (Boe)     98,933       70,043       290,422       182,313  
                                 
Average Sales Prices:                                
Oil (per Bbl)   $ 37.83     $ 84.17     $ 43.86     $ 87.71  
Effect of oil hedges on average price (per Bbl)   $ 13.88 (a)   $ (1.12 )   $ 12.75 (a)   $ (2.73 )
Oil net of hedging (per Bbl)   $ 51.71 (a)   $ 83.05     $ 56.61 (a)   $ 84.98  
Natural gas (per Mcf)   $ 1.14     $ 4.99     $ 1.43     $ 6.03  
Realized price on a Boe basis, net of settled derivatives   $ 46.10 (a)   $ 77.41     $ 49.85 (a)   $ 80.23  
                                 
Average Production Costs:                                
Oil (per Bbl)   $ 9.99     $ 10.27     $ 11.74     $ 10.31  
Natural gas (per Mcf)   $ 0.30     $ 0.61     $ 0.41     $ 0.72  
Barrel of oil equivalent (per Boe)   $ 8.97     $ 9.57     $ 10.44     $ 9.73  
Production Taxes (per Boe)   $ 3.34     $ 8.41     $ 4.03     $ 8.70  
General and Administrative Expense (per Boe)   $ 7.63     $ 9.85     $ 7.90     $ 11.49  
Depletion, Depreciation and Accretion (per Boe)   $ 18.10     $ 32.69     $ 25.42     $ 33.10  
                                 

(a) Excludes the effect of derivatives settlement prior to their contractual settlement date.

 

Depletion of Oil and Natural Gas Properties

 

Our depletion expense is driven by many factors including certain exploration costs involved in the development of producing reserves, production levels and estimates of proved reserve quantities and future developmental costs. The following table presents our depletion expenses for the nine months ended September 30, 2015 and 2014, respectively.

 

    Nine months Ended  
    September 30,  
    2015     2014  
Depletion of oil and natural gas properties   $ 7,346,356     $ 5,994,180  

 

Productive Oil Wells

 

The following table summarizes gross and net productive oil wells by state at September 30, 2015 and 2014, 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.

 

    September 30, 2015     September 30, 2014  
    Gross     Net     Gross     Net  
North Dakota     336       10.51       230       7.28  
Montana     5       0.37       1       0.08  
Total     341       10.88       231       7.36  

 

  25  
 

 

Exploratory Oil Wells

 

The following table summarizes gross and net exploratory wells as of September 30, 2015 and 2014. The wells are at various stages of completion and the costs incurred are included in unevaluated oil and gas properties on our balance sheet.

 

    September 30, 2015     September 30, 2014  
    Gross     Net     Gross     Net  
North Dakota                 9       0.17  
Total                 9       0.17  

 

Results of Operations for the Three Months Ended September 30, 2015 and 2014.

 

The following table summarizes selected items from the statement of operations for the three months ended September 30, 2015 and 2014, respectively.

 

    Three Months Ended        
    September 30,     Increase /  
    2015     2014     (Decrease)  
Oil and gas sales   $ 3,359,684     $ 5,492,326     $ (2,132,642 )
Gain (loss) on settled derivatives     7,456,284       (70,253 )     7,526,537  
Gain (loss) on mark-to-market of derivatives     (3,297,358 )     2,147,798       (5,445,156 )
Total revenues:     7,518,610       7,569,871       (51,261 )
                         
Operating expenses:                        
Production expenses     887,187       670,404       216,783  
Production taxes     330,186       588,923       (258,737 )
General and administrative     754,788       690,189       64,599  
Depletion of oil and gas properties     1,778,580       2,275,703       (497,123 )
Impairment of oil and natural gas properties     30,995,000             30,995,000  
Accretion of discount on ARO     8,039       5,833       2,206  
Depreciation and amortization     4,010       8,214       (4,204 )
Total operating expenses:     34,757,790       4,239,266       30,518,524  
                         
Net operating income (loss)     (27,239,180 )     3,330,605       (30,569,785 )
                         
Total other income (expense)     (1,681,307 )     (1,439,302 )     (242,005 )
                         
Loss before provision for income taxes     (28,920,487 )     1,891,303       (30,811,790 )
                         
Provision for income taxes           (700,587 )     700,587  
                         
Net loss   $ (28,920,487 )   $ 1,190,716     $ (30,111,203 )

 

Oil and Natural Gas Sales

 

We recognized $3,359,684 in revenues from sales of crude oil and natural gas, excluding gains on derivatives, for the three months ended September 30, 2015, compared to revenues of $5,492,326 for the three months ended September 30, 2014, a decrease of $2,132,642, or 39%. The decrease in revenues was driven by a 57% decrease in prices on a BOE basis before the effects of derivatives, partially offset by a 41% increase in production on a BOE basis. We had 10.88 net producing wells as of September 30, 2015, compared to 7.36 net producing wells as of September 30, 2014.

 

Derivatives

 

For the three months ended September 30, 2015, we had a gain on settled derivatives of $7,456,284, compared to a loss on settled derivatives of $70,253 for the same period in 2014. The 2015 gain on settled derivatives includes a September 24, 2015 gain upon redemption of derivatives prior to their original maturity (the “unwind”) of $6,255,000.

 

We had a mark-to-market derivative loss of $3,297,358 in the three months ended September 30, 2015, resulting in a net derivative asset of $2,693,561 largely due to the realization of the gain of $6,255,000 upon the redemption of derivatives in the September 24, 2015 unwind offset by a drop in market prices for oil. In the third quarter of 2014, we had a mark-to-market gain of $2,147,798 as oil futures dropped in price between June 30, 2014 and September 30, 2014.

 

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Production Expenses

 

Production expenses were $887,187 and $670,404 for the three months ended September 30, 2015 and 2014, respectively, an increase of $216,783, or 32%. Our production expenses are greater than the comparative period due to our continued expansion in production. On a per unit basis, production expenses decreased from $9.57 per Boe in the three months ended September 30, 2014 to $8.97 per Boe in the three months ended September 30, 2015. The decrease in production expenses on a BOE basis was primarily a result of lower water disposal costs as much of the new production from wells recently put into production had lower water cuts (percentage of barrels of water produced to barrels of oil produced).

 

Production Taxes

 

Our production taxes were $330,186 and $588,923 for the three months ended September 30, 2015 and 2014, respectively, a decrease of $258,737, or 44%. Production taxes are paid based on realized oil and natural gas sales. Production taxes represented 9.8% and 10.7% of oil and gas sales in the three months ended September 30, 2015 and 2014, respectively.

 

General and Administrative Expenses

 

General and administrative expenses for the three months ended September 30, 2015 were $754,788, compared to $690,189 for the three months ended September 30, 2014, an increase of $64,599, or 9%. The increase in general and administrative expenses was primarily due to increased staffing and external contract work to facilitate growth in production. General and administrative expenses per Boe produced decreased from $9.85 to $7.63 as we have grown administrative staffing and expenses at a slower rate than our production.

 

Depletion of Oil and Natural Gas Properties

 

Our depletion expense is driven by many factors, including certain exploration costs involved in the development of producing reserves, production levels and estimates of proved reserve quantities and future developmental costs. We recognized depletion expense of $1,778,580 and $2,275,703 for the three months ended September 30, 2015 and 2014, respectively, a decrease of $497,123, or 22%. The decrease was due primarily to a decrease in our full cost pool resulting from our impairment taken in second quarter of 2015. Depletion expense per Boe produced decreased from $32.49 in 2014 to $17.98 in 2015.

 

Impairment of Oil and Natural Gas Properties

 

As a result of currently prevailing low commodity prices and their effect on the proved reserve values of properties in 2015, we recorded a non-cash ceiling test impairment of $30,995,000 or $313.29 per Boe for the three months ended September 30, 2015. The Company did not have any impairment of its proved oil and gas properties for the three months ended September 30, 2014. The impairment charge affected our reported net income but did not reduce our cash flow.

 

If commodity prices remain at decreased levels, the trailing 12-month average price used in the ceiling calculation will decline and will likely cause write downs of our oil and natural gas properties. Continued write downs of oil and natural gas properties are expected to occur until such time as commodity prices have recovered, and remained at recovered levels, so as to meaningfully increase the trailing 12-month average price used in the ceiling calculation. In addition to commodity prices, our production rates, levels of proved reserves, future development costs, transfers of unevaluated properties and other factors will determine our actual ceiling test calculation and impairment analyses in future periods.

 

Depreciation and Accretion

 

Depreciation expense for the three months ended September 30, 2015 was $4,010, compared to $8,214 for the three months ended September 30, 2014. Accretion of the discount on asset retirement obligations was $8,039 and $5,833 for the three month periods ended September 30, 2015 and 2014, respectively.

 

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Other Income and (Expense)

 

Other income and (expense) for the three months ended September 30, 2015 was ($1,681,307), compared to ($1,439,302) for the three months ended September 30, 2014. The net other income and (expense) for the three months ended September 30, 2015 consisted entirely of interest expense. Interest expense included $162,249 of amortized warrant costs, $42,520 of amortization related to original issue discounts, $327,632 of PIK interest applied to our debt balances and $96,477 of amortized debt financing costs for the three months ended September 30, 2015. Additionally, we capitalized $57,241 of interest expense into our full cost pool related to interest costs incurred while our wells were being drilled and completed. Our net other income and (expenses) for the three months ended September 30, 2014 consisted of $972 of interest income and $1,440,274 of interest expense, including $158,628 of amortized warrant costs, $42,278 of amortization related to original issue discounts, $314,632 of PIK interest applied to our debt balances and $84,629 of amortized debt financing costs for the three months ended September 30, 2015. Additionally, during the third quarter of 2014, we capitalized $111,340 of interest expense into our full cost pool related to interest costs incurred while our wells were being drilled and completed.

 

Provision for Income Taxes

 

We had income tax expense of $-0- and $700,587 for the three months ended September 30, 2015 and 2014, respectively, a decrease of $700,587. In the three months ended September 30, 2015, our lower effective tax rate relates to a valuation allowance on the net deferred tax asset. The tax expense in the three months ended September 30, 2014 was primarily driven by the Company’s income before provision for income taxes of $1,891,303.

 

Results of Operations for the Nine months Ended September 30, 2015 and 2014.

 

The following table summarizes selected items from the statement of operations for the nine months ended September 30, 2015 and 2014, respectively.

 

    Nine Months Ended        
    September 30,     Increase /  
    2015     2014     (Decrease)  
Oil and gas sales   $ 11,296,220     $ 15,076,743     $ (3,780,523 )
Gain (loss) on settled derivatives     9,436,903       (449,135 )     9,886,038  
Loss on mark-to-market of derivatives     (4,886,184 )     1,052,639       (5,938,823 )
Total revenues:     15,846,939       15,680,247       166,692  
                         
Operating expenses:                        
Production expenses     3,030,707       1,773,458       1,257,249  
Production taxes     1,171,530       1,585,755       (414,225 )
General and administrative     2,295,241       2,095,071       200,170  
Depletion of oil and gas properties     7,346,356       5,994,180       1,352,176  
Impairment of oil and natural gas properties     52,634,000             52,634,000  
Accretion of discount on asset retirement obligations     23,900       15,486       8,414  
Depreciation and amortization     12,286       24,327       (12,041 )
Total operating expenses:     66,514,020       11,488,277       55,025,743  
                         
Net operating income (loss)     (50,667,081 )     4,191,970       (54,859,051 )
                         
Total other income (expense)     (4,789,020 )     (3,815,325 )     (973,695 )
                         
Income (loss) before provision for income taxes     (55,456,101 )     376,645     (55,832,746 )
                         
Provision for income taxes     6,593,040       (110,849 )     6,703,889  
                         
Net loss   $ (48,863,061 )   $ 265,796     $ (49,128,857 )

 

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Oil and Natural Gas Sales

 

We recognized $11,296,220 in revenues from sales of crude oil and natural gas for the nine months ended September 30, 2015 compared to revenues of $15,076,743 for the nine months ended September 30, 2014, a decrease of $3,780,523, or 25%. The decrease was driven by a 53% decrease in realized prices before the effects of settled derivatives and partially offset by a 59% increase in production. We had 10.88 net producing wells as of September 30, 2015 compared to 7.36 net producing as of September 30, 2014.

 

Included in the revenues for the nine month period ended September 30, 2015 were revenues of $1,241,214 related to production from prior fiscal years for the Dahl Federal. Recognition of the Dahl Federal revenues was delayed until title issues related to riparian rights in the Missouri River were resolved.

 

Derivatives

 

For the nine months ended September 30, 2015 we had a gain on settled derivatives of $9,436,903, compared to a loss on settled derivatives of $449,135 for the same period in 2014. The 2015 gain on settled derivatives includes a September 24, 2015 gain upon redemption of derivatives prior to their original maturity (the “unwind”) of $6,255,000.

 

We had a mark-to-market derivative loss of $4,886,184 in the nine months ended September 30, 2015, resulting in a net derivative asset of $2,693,561. In the nine months ended September 30, 2014, we had mark-to-market gains on our derivatives of $1,052,639.

 

Production Expenses

 

Production expenses were $3,030,707 and $1,773,458 for the nine months ended September 30, 2015 and 2014, respectively, an increase of $1,257,249, or 71%. Our production expenses are greater than the comparative period due to our rapid expansion in production. On a per unit basis, production expenses increased from $9.73 per Boe in the nine months ended September 30, 2014 to $10.44 per Boe in the nine months ended September 30, 2015. The increase in production expenses on a BOE basis was primarily a result of workover expenses incurred in wells shut-in while neighboring wells were completed during the first half of the year.

 

Production expenses for the nine month period ended September 30, 2015 included production expenses of $75,359 related to production from prior periods for the Dahl Federal. Recognition of the Dahl Federal revenues and expenses was delayed until title issues related to riparian rights in the Missouri River were resolved.

 

Production Taxes

 

Our production taxes of $1,171,530 and $1,585,755 for the nine months ended September 30, 2015 and 2014, respectively, a decrease of $414,255, or 26%. Production taxes are paid based on realized oil and natural gas sales. Production taxes represented 10.4% and 10.5% of oil and gas sales in the nine months ended September 30, 2015 and 2014, respectively.

 

Production taxes for the nine month period ended September 30, 2015 included production taxes of $137,860 related to production from prior periods for the Dahl Federal. Recognition of the Dahl Federal revenues and expenses was delayed until title issues related to riparian rights in the Missouri River were resolved.

 

General and Administrative Expenses

 

General and administrative expenses for the nine months ended September 30, 2015 were $2,295,241 compared to $2,095,071 for the nine months ended September 30, 2014, an increase of $200,170, or 10%. The increase in general and administrative expenses was primarily due to increased staffing and external contract work to facilitate our production growth and lease and consulting costs related to a new software package. General and administrative expenses per Boe produced decreased from $11.49 to $7.90 as we grew administrative staffing and expenses at a slower rate than our production.

 

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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 $7,346,356 and $5,994,180 for the nine months ended September 30, 2015 and 2014, respectively, an increase of $1,352,176, or 23%. The increase was due primarily to our increased production, partially offset by a decrease in our full cost pool resulting from our impairment taken in second quarter of 2015. Depletion expense per Boe produced decreased from $32.88 in 2014 to $25.30 in 2015.

 

Impairment of Oil and Natural Gas Properties

 

As a result of currently prevailing low commodity prices and their effect on the proved reserve values of properties in 2015, we recorded non-cash ceiling test impairments of $52,634,000 or $181.23 per Boe for the nine months ended September 30, 2015. The Company did not have any impairment of its proved oil and gas properties for the nine months ended September 30, 2014. The impairment charge affected our reported net income but did not reduce our cash flow.

 

If commodity prices remain at decreased levels, the trailing 12-month average price used in the ceiling calculation will decline and will likely cause potential write downs of our oil and natural gas properties. Continued write downs of oil and natural gas properties are expected to occur until such time as commodity prices have recovered, and remained at recovered levels, so as to meaningfully increase the trailing 12-month average price used in the ceiling calculation. In addition to commodity prices, our production rates, levels of proved reserves, future development costs, transfers of unevaluated properties and other factors will determine our actual ceiling test calculation and impairment analyses in future periods.

 

Depreciation and Accretion

 

Depreciation expense for the nine months ended September 30, 2015 was $12,286 compared to $24,327 for the nine months ended September 30, 2014. Accretion of the discount on asset retirement obligations was $23,900 and $15,486 for the nine month periods ended September 30, 2015 and 2014, respectively.

 

Other Income and (Expense)

 

Other income and (expense) for the nine months ended September 30, 2015 was ($4,789,020) compared to ($3,815,325) for the nine months ended September 30, 2014. The net other income and (expense) for the nine months ended September 30, 2015 consisted of $4,795,727 of interest expense and $6,707 of other income. The $4,795,727 of interest expense included $484,012 of amortized warrant costs, $127,378 of amortization related to original issue discounts, $962,551 of PIK interest applied to our debt balances and $287,227 of amortized debt financing costs for the nine months ended September 30, 2015. Additionally, we capitalized $352,572 of interest expense into our full cost pool related to interest costs incurred while our wells were being drilled and completed. The net other income and (expense) for the nine months ended September 30, 2014 consisted of $972 of interest income and $3,816,297 of interest expense including $468,670 of amortized warrant costs, $102,566 of amortization related to original issue discounts, $787,344 of PIK interest applied to our debt balances and $229,936 of amortized debt financing costs for the nine months ended September 30, 2014. Additionally, we capitalized $216,895 of interest expense into our full cost pool related to interest costs incurred while our wells were being drilled and completed.

 

Provision for Income Taxes

 

We had an income tax benefit of $6,593,040 for the nine months ended September 30, 2015 and income tax expense of $110,849 for the nine months ended September 30, 2014, a difference of $6,703,889. The tax benefits for the nine months ended September 30, 2015 and 2014 were primarily driven by the Company’s income or loss before provision for income taxes of $55,461,101, but the lower effective tax rate is derived from the valuation allowance on the net deferred tax asset. Our income tax expense of $110,849 for the nine months ended September 30, 2014 was primarily driven by our income before provision for income taxes of $376,645.

 

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Non-GAAP Financial Measures

 

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

 

Black Ridge Oil & Gas, Inc.

Reconciliation of Adjusted Net Income (Loss)

(Unaudited)

 

    Three Months Ended     Nine Months Ended  
    September 30,     September 30,  
    2015     2014     2015     2014  
Net income (loss)   $ (28,920,487 )   $ 1,190,716     $ (48,863,061 )   $ 265,796  
Add back:                                
Loss (income) on mark-to-market of derivatives, net of tax (a)     3,297,358       (1,352,798 )     4,300,184       (663,639 )
Impairment of oil and gas properties, net of tax (b)     30,995,000             46,318,000        
Adjusted net income (loss)   $ 5,371,871     $ (162,082 )   $ 1,755,123     $ (397,843 )
                                 
Weighted average common shares outstanding - basic     47,979,990       47,979,990       47,979,990       47,979,990  
                                 
Weighted average common shares outstanding - fully diluted     47,979,990       49,588,039       47,979,990       49,824,437  
                                 
Net income (loss) per common share – basic   $ (0.60 )   $ 0.02     $ (1.02 )   $ 0.01  
Add:                                
Change due to loss (income) on mark-to-market of derivatives, net of tax     0.07       (0.03 )     0.09       (0.01 )
Change due to impairment of oil and gas properties, net of tax     0.65             0.97        
Adjusted net income (loss) per common share – basic   $ 0.11     $ (0.00 )   $ 0.04     $ (0.01 )
                                 
Net income (loss) per common share – fully diluted   $ (0.60 )   $ 0.02     $ (1.02 )   $ 0.01  
Add:                                
Change due to loss (income) on mark-to- market of derivatives, net of tax     0.07       (0.03 )     0.09       (0.01 )
Change due to impairment of oil and gas properties, net of tax     0.65             0.97        
Adjusted net income (loss) per common share – fully diluted   $ 0.11     $ (0.00 )   $ 0.04     $ (0.01 )

 

(a) Adjusted to reflect tax expense (benefit), computed based on our effective tax rate of approximately 0% and 12% for the three and nine months ended September 30, 2015, and 37% in both the three and nine months ended September 30, 2014, consisting of $-0- and $795,000 for the three month ended September 30, 2015 and 2014, respectively, and ($586,000) and $389,000 for the nine months ended September 30, 2015 and 2014, respectively.

 

(b) Adjusted to reflect tax expense, computed based on our effective tax rate of approximately 0% and 12% for the three and nine months ended September 30, 2015, and 37% in both the three and nine months ended September 30, 2014, consisting of $8,369,000 and $-0- for the three month ended September 30, 2015 and 2014, respectively, and $14,211,000 and $-0- for the nine months ended September 30, 2015 and 2014, respectively.

 

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Black Ridge Oil & Gas, Inc.

Reconciliation of Adjusted EBITDA (Unaudited)

 

    Three Months Ended     Nine Months Ended  
    September 30,     September 30,  
    2015     2014     2015     2014  
Net income (loss)   $ (28,920,487 )   $ 1,190,716     $ (48,863,061 )   $ 265,796  
Add back:                                
Interest expense, net, excluding amortization of warrant based financing costs     1,519,058       1,280,674       4,311,715       3,346,655  
Income tax provision           700,587       (6,593,040 )     110,849  
Depreciation, depletion, and amortization     1,782,590       2,283,917       7,358,642       6,018,507  
Impairment of oil and gas properties     30,995,000             52,634,000        
Accretion of abandonment liability     8,039       5,833       23,900       15,486  
Share based compensation     314,374       302,961       949,888       901,964  
Loss (gain) on mark-to market of derivatives     3,297,358       (2,147,798 )     4,886,184       (1,052,639 )
                                 
Adjusted EBITDA   $ 8,995,932     $ 3,616,890     $ 14,708,228     $ 9,606,618  

 

Our adjusted EBITDA for the nine month periods ended September 30, 2015 includes income from the Dahl Federal well that was recognized in the current period based on activity in prior periods of $1,027,995.

 

Liquidity and Capital Resources

 

The following table summarizes our total current assets, liabilities and working capital at September 30, 2015 and December 31, 2014, respectively.

 

    September 30,     December 31,  
    2015     2014  
Current Assets   $ 6,663,190     $ 9,448,043  
                 
Current Liabilities   $ 8,503,979     $ 10,348,697  
                 
Working Capital   $ (1,840,789 )   $ (900,654 )

 

As of September 30, 2015 we had negative working capital of $1,840,789.

 

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The following table summarizes our cash flows during the nine month periods ended September 30, 2015 and 2014, respectively.

 

    Nine Months Ended  
    September 30,  
    2015     2014  
Net cash provided by operating activities   $ 13,804,992     $ 6,385,513  
Net cash used in investing activities     (17,841,075 )     (21,803,227 )
Net cash provided by financing activities     4,000,000       14,295,606  
Net change in cash   $ (36,083 )   $ (1,122,108 )

 

Our net cash flows from operations are primarily affected by production volumes and commodity prices. Net cash provided by operating activities was $13,804,992 and $6,385,513 for the nine months ended September 30, 2015 and 2014, respectively, an increase of $7,419,479. The increase was due primarily to settled derivative gains of $9,436,903 in 2015 as compared to settled derivative losses of $449,135 in 2014. Changes in working capital from operating activities resulted in an increase in cash of $2,031,324 in the nine months ended September 30, 2015 as compared to a decrease in cash of ($994,296) for the same period in the previous year, primarily driven by a decrease in accounts receivable in 2015 and an increase in accounts receivable in 2014.

 

Net cash used in investing activities was $17,841,075 and $21,803,227 for the nine months ended September 30, 2015 and 2014, respectively, a decrease of $3,962,152. We paid $17,865,495 for well development and $-0- in advances to operators for future well development during the 2015 period while in the 2014 period we spent $15,009,426 for well development and $5,742,272 in advances to operators for future well development. Additionally, the decrease in cash used in investing activities was attributable to a decrease in cash spent for property acquisition as we purchased 9 net leasehold acres of oil and gas properties for $102,928 in the nine months ended September 30, 2015 as compared to purchasing 319 net leasehold acres of oil and gas properties for $2,401,318 in the nine months ended September 30, 2014. In the nine months ended September 30, 2015 we sold 14 net leasehold acres and three wellbores for proceeds of $127,348, while in the comparable 2014 period we sold 490 net leasehold acres for proceeds of $1,360,920, including proceeds of $20,000 from a swap transaction.

 

Net cash provided from financing was $4,000,000 and $14,295,606 for the nine months ended September 30, 2015 and 2014, respectively. We drew $4,050,000, net of repayments, on our credit facilities during the nine months ended September 30, 2015. We drew $14,550,000, net of repayments, on our credit facilities during the nine months ended September 30, 2014.

 

Senior Credit Facility and Subordinated Credit Facilities

 

The Company, as borrower, entered into a Credit Agreement dated August 8, 2013 and amendments thereto dated December 13, 2013, March 24, 2014, April 21, 2014, September 11, 2014, March 30, 2015 and August 10, 2015 (as amended, the “Senior Credit Agreement ) with Cadence Bank, N.A. (“Cadence”), as lender (the “Senior Credit Facility”). Under the terms of the Senior Credit Agreement, a senior secured revolving line of credit in the maximum aggregate principal amount of $50 million is available from time to time (i) for direct investment in oil and gas properties, (ii) for general working capital purposes, including the issuance of letters of credit, and (iii) to refinance the then existing debt under the Company’s former credit facility with Dougherty Funding LLC.

 

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Availability under the Senior Credit Facility is at all times subject to the then-applicable borrowing base, determined by Cadence in a manner consistent with the normal and customary oil and gas lending practices of Cadence. Availability was initially set at $7 million and is subject to periodic redeterminations. The availability was $35 million as of December 31, 2014, and subsequently amended to $34 million on March 30, 2015. Our borrowing base on Senior Secured Facility was adjusted by our lender as part of a regularly scheduled redetermination from $34 million to $33 million effective October 1, 2015. The borrowing base will adjust down to $32 million on November 16, 2015 if certain commodity hedging is not put in place. The next scheduled borrowing base amount determination date is April 1, 2016. Subject to availability under the borrowing base, the Company may borrow, repay and re-borrow funds in amounts of $250,000 or more. At the Company’s election, the unpaid principal balance of any borrowings under the Senior Credit Facility may bear interest at either (i) the Base Rate, as defined in the Senior Credit Facility, plus the applicable margin, which varies from 1.00% to 1.50% or (ii) the LIBOR rate, as defined in the Senior Credit Facility, plus the applicable margin, which varies from 3.00% to 3.50%. Interest is payable for Base Rate loans on the last business day of the month and for LIBOR loans on the last LIBOR business day of each LIBOR interest period. The Company is also required to pay a quarterly fee of 0.50% on any unused portion of the borrowing base, as well as a facility fee of 0.90% of the initial and any subsequent additions to the borrowing base.

 

The Senior Credit Facility’s maturity date of August 8, 2016, was subsequently amended to January 15, 2017 pursuant to the amendment on March 30, 2015. The Company may prepay the entire amount of Base Rate loans at any time, and may prepay the entire amount of LIBOR loans upon at least three business days’ notice to Cadence. The Senior Credit Facility is secured by first priority interests in mortgages on substantially all of the Company’s assets, including but not limited to the Company’s mineral interests in North Dakota and Montana.

 

The Company had borrowings of $26.65 million and $22.6 million outstanding under the Senior Credit Agreement as of September 30, 2015 and December 31, 2014, respectively.

 

Subordinated Credit Facility

 

The Company, as borrower, entered into a Second Lien Credit Agreement dated August 8, 2013 and amendments thereto dated December 13, 2013, March 24, 2014, April 21, 2014, September 11, 2014, March 30, 2015, and August 10, 2015 (as amended, the “Subordinated Credit Agreement”) by and among the Company, as borrower, Chambers Energy Management, LP, as administrative agent (“Chambers”), and the several other lenders named therein (the “Subordinated Credit Facility”). Under the Subordinated Credit Facility, term loans in the aggregate principal amount of up to $75 million are available from time to time (i) to repay the Previous Credit Facility, (ii) for fees and closing costs in connection with both the Senior Credit Facility and the Subordinated Credit Facility (together, the “Credit Facilities”), and (iii) general corporate purposes.

 

The Subordinated Credit Agreement provided initial commitment availability of $25 million, which was subsequently amended to the current availability of $30 million, with the remaining commitments subject to the approval of Chambers and other customary conditions. The Company may borrow the available commitments in amounts of $5 million or more and shall not request borrowings of such loans more than once a month, provided that the initial draw was at least $15 million. Loans under the Subordinated Credit Facility shall be funded net of a 2% OID. The unpaid principal balance of borrowings under the Subordinated Credit Facility bears interest at the Cash Interest Rate plus the PIK Interest Rate. The Cash Interest Rate is 9.00% per annum plus a rate per annum equal to the greater of (i) 1.00% and (ii) the offered rate for three-month deposits in U.S. dollars that appears on Reuters Screen LIBOR 01 as of 11:00 a.m. (London time) on the second full LIBOR business day preceding the first day of each calendar quarter. The PIK Interest Rate is equal to 4.00% per annum. Interest is payable on the last day of each month. The Company is also required to pay an annual nonrefundable administration fee of $50,000 and a monthly availability fee computed at a rate of 0.50% per annum on the average daily amount of any unused portion of the available amount under the commitment.

 

The Subordinated Credit Facility matures on June 30, 2017. Upon at least three business days’ written notice, the Company may prepay the entire amount under the loans, together with accrued interest. Each prepayment made prior to the second anniversary of the funding date, as defined in the Subordinated Credit Facility, shall be accompanied by a make-whole amount, as defined in the Subordinated Credit Agreement. Prepayments made on or after the second anniversary of the funding date shall be accompanied by an applicable premium, as set forth in the Subordinated Credit Agreement. The Subordinated Credit Facility is secured by second priority interests on substantially all of the Company’s assets, including but not limited to second priority mortgages on the Company’s mineral interests in North Dakota and Montana.

 

The first funding from the Subordinated Credit Facility occurred on September 9, 2013 at which time we drew $14.7 million, net of a $300,000 original issue discount, from the Subordinated Credit Agreement and used $10,226,057 of those proceeds to repay and terminate a previously outstanding revolving credit facility. We have drawn an additional $14.7 million, net of $300,000 original issue discounts, through September 30, 2015. The Company had borrowings of $30 million and $30 million outstanding under the Subordinated Credit Facility as of September 30, 2015 and December 31, 2014, respectively.

 

  34  
 

 

Intercreditor Agreements and Covenants

 

Cadence and Chambers have entered into an Intercreditor Agreement dated August 8, 2013 (the “Intercreditor Agreement”). The Intercreditor Agreement provides that any liens on the assets of the Company securing indebtedness under the Subordinated Credit Facility are subordinate to liens on the assets securing indebtedness under the Senior Credit Facility and sets forth the respective rights, obligations and remedies of the lenders under the Senior Credit Facility with respect to their first priority liens and the lenders under the Subordinated Credit Facility with respect to their second priority liens.

 

The Credit Facilities, as amended, require customary affirmative and negative covenants for credit facilities of the respective types and sizes for companies operating in the oil and gas industry, as well as customary events of default. Furthermore, the Credit Facilities contain financial covenants that require the Company to satisfy certain specified financial ratios. The Senior Credit Agreement requires the Company to maintain, as of the last day of each fiscal quarter of the Company, (i) a collateral coverage ratio (reserve value plus consolidated working capital to adjusted indebtedness) of at least 0.65 to 1.00 through the quarter ending June 30, 2014, 0.70 to 1.00 for the quarters ending September 30, 2014 and December 31, 2014, was waived for the quarters ending March 31, 2015 and June 30, 2015, and 0.70 to 1.00 for the quarter ending September 30, 2015, and 0.80 to 1.00 for the quarter ending December 31, 2015 and thereafter, (ii) a ratio of current assets, including debt facility available to be drawn, to current liabilities of a minimum of 1.0 to 1.0, except for the quarter ending June 30, 2014, which was waived, (iii) a net debt to EBITDAX, as defined in the Senior Credit Agreement, ratio of 3.75 to 1.00 for the quarter ended March 31, 2014, 4.25 to 1.00 for the quarters ended June 30, 2014 and September 30, 2014, 4.00 to 1.00 for the quarter ended December 31, 2014, was waived for the quarters ended March 31, 2015 and June 30, 2015, and 3.50 to 1.00 for the quarter ending September 30, 2015, and 3.65 to 1.00 for the quarter ending December 31, 2015, and 3.50 to 1.00 for the quarter ending March 31, 2016 and thereafter, in each case calculated on a modified trailing four quarter basis, (iv) a maximum senior leverage ratio of not more than 2.5 to 1.0 calculated on a modified trailing four quarter basis, and (v) a minimum interest coverage ratio of not less than 3.0 to 1.0. The Subordinated Credit Agreement requires the Company to maintain, as of the last day of each fiscal quarter of the Company, (i) a collateral coverage ratio (reserve value plus consolidated working capital to adjusted indebtedness) of at least 0.65 to 1.00 through the quarter ending June 30, 2014, 0.70 to 1.00 for the quarters ending September 30, 2014 and December 31, 2014, was waived for the quarters ending March 31, 2015 and June 30, 2015, and 0.70 to 1.00 for the quarter ending September 30, 2015, and 0.80 to 1.00 for the quarter ending December 31, 2015 and thereafter, (ii) a consolidated net leverage ratio (adjusted total indebtedness less the amount of unrestricted cash equivalents to consolidated EBITDA) of no more than 3.75 to 1.00 for the quarter ending March 31, 2014, 4.25 to 1.00 for the quarters ending June 30, 2014 and September 30, 2014, 4.00 to 1.00 for the quarter ending December 31, 2014, was waived for the quarters ending March 31, 2015 and June 30, 2015, and 3.50 to 1.00 for the quarter ending September 30, 2015, and 3.65 to 1.00 for the quarter ending December 31, 2015, and 3.50 to 1.00 for the quarter ending March 31, 2016 and thereafter, calculated on a modified trailing four quarter basis, (iii) a consolidated cash interest coverage ratio (consolidated EBITDA to consolidated cash interest expense) of no less than 2.5 to 1.0, calculated on a modified trailing four quarter basis and (iv) a ratio of consolidated current assets to consolidated current liabilities of at least 1.0 to 1.0, except for the quarter ending June 30, 2015 when the covenant was waived. In addition, each of the Credit Facilities requires that the Company enter into hedging agreements based on anticipated oil production from currently producing wells as agreed to by the lenders. The Company is in compliance with all covenants, as amended, for the period ending September 30, 2015.

 

Debt Discount, Detachable Warrants

 

In connection with the Subordinated Credit Facility, the Company agreed to issue to the lenders detachable warrants to purchase up to 5,000,000 shares of the Company’s common stock at an exercise price of $0.65 per share. The warrants expire on August 8, 2018. Proceeds from the loan were allocated between the debt and equity based on the relative fair values at the time of issuance, resulting in a debt discount of $2,473,576 at issuance that is presented as a debt discount on the balance sheet and is being amortized using the effective interest method over the life of the credit facility, which matures on June 30, 2017. A total of $484,012 and $468,670 was amortized during the nine months ended September 30, 2015 and 2014, respectively. The remaining unamortized balance of the debt discount attributable to the warrants is $1,161,737 as of September 30, 2015.

 

Although our revenues are expected to grow as our wells are placed into production, our revenues are not expected to exceed our investment in developing oil and gas wells and our operating costs throughout 2015. However, we believe our credit facilities will provide sufficient funding for our development plans through those same periods. 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.

 

  35  
 

 

Satisfaction of our cash obligations for the next 12 months

 

As of September 30, 2015, our balance of cash and cash equivalents was $58,599. 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 facilities, sale of properties that do not meet our investment criteria, and potential sale or use of shares of our stock.

 

We ended the quarter with $26.65 million drawn on our $34 million senior secured revolving credit facility. The borrowing base was adjusted by our lender as part of our regularly scheduled redetermination to $33 million effective October 1, 2015 and will adjust down to $32 million on November 16, 2015. The reduction in borrowing base is the net effect of lower commodity prices and monetization of hedges, substantially offset by our Teton project development. The next redetermination date is scheduled for April 1, 2016. Until we see sustained improvement in oil prices, the Company’s future acquisition and development activity is likely to be focused within the Merced joint venture. With limited development within our base business, we expect the current borrowing base and cash flows to meet our liquidity needs.

 

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. 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.

 

  36  
 

 

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.

 

As required under our Credit Facilities, we will maintain derivative contracts to achieve a more predictable cash flow by reducing our exposure to oil price volatility. We anticipate using derivatives to economically hedge a significant, but varying portion of our anticipated future production over a rolling 42 month horizon. Any payments due to counterparties under our derivative contracts are funded by proceeds received from the sale of our production. Production receipts, however, lag payments to the counterparties. Any interim cash needs will be funded by cash from operations or borrowings under our credit facilities.

 

Interest Rate Risk

 

Under our Credit Facilities our long-term debt is comprised of borrowings on floating interest rates. As a result, changes in interest rates can impact results of operations and cash flows.

 

 

ITEM 4. CONTROLS AND PROCEDURES.

 

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

 

Our management, under the direction of our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the design and operation of our disclosure controls and procedures (as such terms are defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of September 30, 2015. As part of such evaluation, management considered the matters discussed below relating to internal control over financial reporting. Based on this evaluation our management, including the Company’s Chief Executive Officer and Chief Financial Officer, has concluded that the Company’s disclosure controls and procedures were effective as of September 30, 2015 to ensure that the information required to be disclosed in our Exchange Act reports was recorded, processed, summarized and reported on a timely basis.

 

There have been no changes in the Company’s internal control over financial reporting during the three month period ended September 30, 2015 that materially affected or are reasonably likely to materially affect the Company’s internal control over financial reporting.

 

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PART II - OTHER INFORMATION

 

Item 1. Legal Proceedings.

 

Other than routine legal proceedings incident to our business, there are no material legal proceedings to which we are a party or to which any of our property is subject.

 

 

ITEM 1A. RISK FACTORS.

 

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

 

 

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

 

None.

 

 

ITEM 3. DEFAULTS UPON SENIOR SECURITIES.

 

None.

 

 

ITEM 4. MINE SAFETY DISCLOSURES.

 

Not applicable.

 

 

ITEM 5. OTHER INFORMATION.

 

None.

 

 

ITEM 6. EXHIBITS .

 

Exhibit   Description
3.1   Certificate of Incorporation (incorporated by reference to Exhibit 3.1 of the Form 8-K filed with the Securities and Exchange Commission by Black Ridge Oil & Gas, Inc. on December 12, 2012)
3.2   Bylaws (incorporated by reference to Exhibit 3.2 of the Form 8-K filed with the Securities and Exchange Commission by Black Ridge Oil & Gas, Inc. on December 12, 2012)
10.1* Ω    Limited Liability Company Agreement of Merced Black Ridge, LLC dated July 21, 2015
10.2* Ω   Management Services Agreement dated July 21, 2015 by and between Black Ridge Oil & Gas, Inc. and Merced Black Ridge, LLC
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

* Filed herewith.

Ω Filed subject to confidential treatment request.

 

  38  
 

 

SIGNATURES

 

Pursuant to the requirements of the Securities Exchange Act of 1934, 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: November 13, 2015 By: /s/ Kenneth DeCubellis
      Kenneth DeCubellis, Chief Executive Officer (Principal Executive Officer)
       
Dated: November 13, 2015 By: /s/ James A. Moe
      James A. Moe, Chief Financial Officer (Principal Financial Officer)

 

 

  39  

EXHIBIT 10.1

 

[CONFIDENTIAL TREATMENT REQUESTED. CONFIDENTIAL PORTIONS OF THIS DOCUMENT HAVE BEEN REDACTED AND HAVE BEEN SEPARATELY FILED WITH THE COMMISSION]

 

LIMITED LIABILITY COMPANY AGREEMENT

 

OF

 

MERCED BLACK RIDGE, LLC

 

This LIMITED LIABILITY COMPANY AGREEMENT OF MERCED BLACK RIDGE, LLC , a Delaware limited liability company (the “ Company ”) (this “ Agreement ”) is made effective as of July 21, 2015, by and among Merced Oil & Gas, LLC, a Delaware limited liability company (“ Merced ”) and Black Ridge Oil & Gas Inc., a Nevada corporation (“ Black Ridge ”) (Merced and Black Ridge are collectively referred to herein as the “ Parties ” and individually as a “ Party ”). All capitalized terms used without definition will have the meanings given to them in Article I.

 

RECITALS

 

Company was formed as a limited liability company under the laws of the State of Delaware on June 17, 2015. The Parties now wish to enter into this written agreement, in accordance with the provisions of the Delaware Limited Liability Company Act and any successor statute, as amended from time to time (the “ Act ”), governing the affairs of the Company and the conduct of its business.

 

NOW, THEREFORE, the parties hereto, intending to be legally bound, hereby agree as follows:

 

ARTICLE I

DEFINITIONS

 

1.1           General Interpretive Principles. Except as otherwise expressly provided in this Agreement or unless the context otherwise requires, (i) the terms defined in this Article will have the meanings assigned to them in this Article and will include the plural as well as the singular, (ii) the use of any gender in this Agreement will be deemed to include the other gender and (iii) the word “including” means “including, but not limited to.”

 

1.2           Defined Terms. As used in this Agreement, the following terms will have the following respective meanings:

 

Act ” means the Delaware Limited Liability Company Act, as codified in Title 6 of the Delaware Code, §§ 18-101 et seq., as the same may be amended from time to time.

 

AFE ” means an Authorization for Expenditure.

 

Affiliate ” means any Person directly or indirectly Controlling, Controlled by, or under Common Control of such other Person.

 

1
 

 

Agreement ” means this Limited Liability Company Agreement, as originally executed or as the same may be amended from time to time.

 

Black Ridge ” is defined in the introductory paragraph of this Agreement.

 

Book Value ” means, with respect to any asset of the Company, the adjusted basis of such asset for federal income tax purposes; provided, however, that (i) if any asset is contributed to the Company, the initial Book Value of such asset will equal its fair market value on the date of contribution (as determined by the Managing Member and set forth on Exhibit A hereto), and (ii) if the Capital Accounts of the Members are adjusted pursuant to Treasury Regulation Section 1.704-1(b)(2)(iv)(g) to reflect the fair market value of any asset of the Company, the Book Value of such asset will be adjusted to equal its respective fair market value as of the time of such adjustment (as determined by the Managing Member), in accordance with such Treasury Regulation.

 

Business Day ” means any day other than a Saturday, Sunday or day on which commercial banks in New York City are authorized or required by law to close.

 

Capital Account ” is defined in Section 10.1 as adjusted under Treasury Regulation Section 1.704-1(b).

 

Capital Contribution ” means the aggregate contributions made by a Member to the Company in cash or property whenever made. The Capital Contributions of the Members are reflected in the books and records of the Company and the Company will maintain such books and records as are necessary and appropriate to reflect the Capital Contributions of its Members.

 

Certificate ” means the Certificate of Formation for the Company, filed with the Secretary of State of the State of Delaware on June 17, 2015, as the same may be amended from time to time.

 

Code ” means the Internal Revenue Code of 1986, as the same may be amended from time to time.

 

Company ” is defined in the introductory paragraph of this Agreement.

 

Control ” including the correlative terms “Controlling”, “Controlled by” and “Under Common Control with” means possession, directly or indirectly, of the power to direct or cause the direction of management or policies (whether through ownership of securities or any partnership or other ownership interest, by contract or otherwise) of a Person. Without limiting the effect of the preceding sentence, control will be deemed to exist (but will not be limited to) when a Person possesses, directly or indirectly, through one or more intermediaries (i) in the case of a corporation, 50 percent or more of the outstanding voting securities thereof; (ii) in the case of a limited liability company, partnership, limited partnership or venture, the right to 50 percent or more of the distributions therefrom (including liquidating distributions); or (iii) in the case of any other Person, 50 percent or more of the economic or beneficial interest therein.

 

Covered Person ” is defined in Section 5.7 .

 

2
 

 

Depreciation ” means, for each Fiscal Year or other period, an amount equal to the depreciation, amortization, or other cost recovery deduction allowable with respect to Company property for such Fiscal Year or other period for federal income tax purposes as determined by the Managing Member; provided, however, that if the Book Value of Company property differs from its adjusted basis for federal income tax purposes at the beginning of such Fiscal Year or other period, Depreciation shall be determined by the Managing Member in accordance with Treasury Regulation Section 1.704-1(b)(2)(iv)(g).

 

Effective Date ” means July 20, 2015.

 

Fiscal Year ” means the Company’s fiscal year, which will be the calendar year.

 

Loss ” is defined under the definition of “Profit” in this Article.

 

Management Participation Interest ” means the interest in partnership profits issued to Black Ridge contemporaneously with the initial Capital Contributions of Merced in connection with the performance of services for the Company pursuant to Rev. Proc. 93-27, 1993-2 CB 343 and Rev. Proc. 2001-43, 2001-2 CB 191, representing the right to receive a percentage of the profits of the Company pursuant to Section 7.1(c) of this Agreement.

 

Management Services Agreement” means that certain Management Services Agreement dated the date hereof between Black Ridge and the Company.

 

Managing Member” means Merced with such responsibilities as described in Article V and elsewhere in this Agreement.

 

Members ” means, collectively, Merced and Black Ridge and any other Person admitted as a member in accordance with the terms of this Agreement.

 

Membership Interest” means each Member’s entire interest in the capital and profits of the Company and, if applicable, the right to vote on or participate in, and the right to receive information concerning, the business and affairs of the Company, including such Member’s Percentage Interest, Management Participation Interest and Voting Interest, if any, as reflected on Exhibit A hereto and as provided in this Agreement. Initially, the Membership Interests will not be represented by certificates. If the Managing Member determines that it is in the interest of the Company to issue certificates representing Membership Interests, certificates will be issued. A Transfer by a Member of less than 100% of its Membership Interest pursuant to this Agreement will constitute a division of such Member’s Membership Interest and a Transfer of a portion of the Member’s Membership Interest in proportion to the Membership Interest transferred.

 

Merced ” is defined in the introductory paragraph of this Agreement.

 

Net Cash Flow ” means Operating Cash Flow (i) less (x) capital investments, interest on financings, principal on financings, management fees, and any other similar uses of cash in the operation of the Company, and (y) such reserves as are determined by the Managing Member to be reasonably necessary for the conduct of the Company’s business (including broker commissions, expenses related to the ownership and protection of properties owned by the Company and servicing fees paid to Black Ridge pursuant to the Management Services Agreement); and (ii) plus proceeds of sales of capital assets, interest earned on cash, proceeds of financings, and any other similar sources of cash.

 

3
 

 

Non-Voting Member ” means any Person admitted as a Member of the Company and not allocated any Voting Interest, as reflected on Exhibit A hereto.

 

Officer ” is defined in Section 5.4 .

 

Operating Cash Flow ” means, for any period, the sum of all operating revenues of the Company (including fees earned by the Company and its subsidiaries and revenue from hedging activities), reduced by all operating and hedging expenses of the Company and its subsidiaries, in each case determined on an accrual basis. The calculation of Operating Cash Flow will not include depreciation or amortization, interest paid or accrued, debt principal payments or fundings, capital investments or management fees.

 

Percentage Interest ” means, with respect to a Member, the “Percentage Interest” of such Member as reflected on Exhibit A attached hereto. The Percentage Interests will be recalculated by the Managing Member and promptly communicated to all Members upon (i) the admission of additional Members, (ii) the reallocation of Percentage Interests among existing Members, (iii) the forfeiture of Percentage Interests allocated to Black Ridge pursuant to Section 6.2 or (iv) the Transfer, repurchase or cancellation of any outstanding Percentage Interests. The Percentage Interests will be recalculated as of the effective date of such admission, issuance, reallocation, Transfer, repurchase or cancellation and the Company will reflect any such change on its books and records.

 

Person ” means a natural person, partnership (whether general or limited), limited liability company, trust, estate, association, corporation, custodian, nominee or any other individual or entity in its own or any representative capacity.

 

Pool ” means a set of one or more investments in Projects, identified by the Managing Member in its reasonable discretion, where such assets have an aggregate value of acquisition costs and approved AFEs for drilling of approximately $50 million.

 

Preferred Return ” means an amount equal to *** 1

 

Profit ” or “ Loss ” means, for any Fiscal Year or other period, an amount equal to the Company’s taxable income, gain or loss for such Fiscal Year or other period, determined in accordance with Section 703(a) of the Code (for this purpose, all items of income, gain, loss or deduction required to be separately stated pursuant to Section 703(a)(1) of the Code shall be included in taxable income or loss), with the following adjustments:

 

 

_____________

1 *** Confidential Information has been omitted and filed separately with the Securities and Exchange Commission. Confidential treatment has been requested with respect to this omitted information.

 

4
 

 

(a) Any income of the Company that is exempt from federal income tax or otherwise described in Section 705(a)(1)(B) of the Code and not otherwise taken into account shall be added to such taxable income or loss;

 

(b) Any expenditure of the Company described in Section 705(a)(2)(B) of the Code and nondeductible syndication costs described in Section 709 of the Code and not otherwise taken into account shall be subtracted from such taxable income or loss;

 

(c) If the Book Value of any asset differs from its adjusted basis for federal income tax purposes at the beginning of such Fiscal Year or other period, in lieu of depreciation, amortization and other cost recovery deduction, there shall be taken into account Depreciation for such Fiscal Year or other period, and in lieu of a gain or loss resulting from disposition of Company property and taken into account in computing taxable income or loss, there shall be taken into account gain or loss computed by reference to the Book Value of such Company property rather than its adjusted basis for federal income tax purposes; and

 

(d) Items of income, gain, loss or deduction that are specifically allocated pursuant to Section 8.3 shall not be taken into account in calculating Profits and Losses.

 

Project ” means a minority, non-operator interest in a parcel of land intended for oil or gas well drilling or containing oil or gas well drilling operations in the Williston Basin.

 

Regulatory Allocations ” is defined in Section 8.3(f) .

 

Securities Act ” is defined in Section 12.2 .

 

Transfer ” means transfer, sale, assignment, pledge, hypothecation, exchange, gifting, or bequeathment.

 

Treasury Regulations ” means regulations issued by the Department of the Treasury under the Code. Any reference to a specific section or sections of the Treasury Regulations will be deemed to include a reference to any corresponding provision of future regulations under the Code.

 

Unreturned Capital Contributions ” means as to a Member, at any time, the aggregate Capital Contributions made with respect to such Member, reduced (but not below zero) by the aggregate amounts distributed pursuant to Section 7.1(b) with respect to such Member (whenever made and regardless of the source or character thereof). In the event any Member transfers its Membership Interest in accordance with the terms of this Agreement, such Member’s transferee will succeed to the Unreturned Capital Contribution Balance that relates to such Membership Interest.

 

Unsatisfied Preferred Return ” means, with respect to a Member, at any time, the amount (if any) that the Preferred Return on such Member’s Capital Contribution exceeds the aggregate amount of all distributions made to such Member (whenever made and regardless of the source or character thereof) pursuant to Section 7.1(a) .

 

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Voting Interest ” means, with respect to a Member, the “Voting Interest” of such Member as reflected on Exhibit A attached hereto. The Voting Interests will be recalculated by the Managing Member and promptly communicated to all Members upon (i) the admission of additional Voting Members, (ii) the reallocation of Voting Interests among existing Voting Members, or (iii) the Transfer, repurchase or cancellation of any outstanding Voting Interests. The Voting Interests will be recalculated as of the effective date of such admission, issuance, reallocation, Transfer, repurchase or cancellation and the Company will reflect any such change on its books and records.

 

Voting Member ” means any Member that holds a Voting Interest.

 

ARTICLE II

ORGANIZATIONAL MATTERS

 

2.1           Formation . The Company was organized as a Delaware limited liability company pursuant to the Act. Thomas G. Rock, as an authorized person within the meaning of the Act, executed, delivered and filed the Certificate with the Secretary of State of the State of Delaware. Upon the execution of this Agreement, Mr. Rock’s powers as an authorized person ceased.

 

2.2           Rights and Obligations of the Members . The rights and obligations of the Members will be determined pursuant to the Act and this Agreement. To the extent that the rights or obligations of the Members are different by reason of any provision of this Agreement than they would be in the absence of such provision, this Agreement will, to the extent permitted by the Act, control. Each Member will be entitled to rely on the provisions of this Agreement, and no Member will be liable to the Company or to any other Member for any action or refusal to act taken in good faith reliance on this Agreement.

 

2.3           Name . The name of the Company will be “ MERCED BLACK RIDGE, LLC ” and such name will be used at all times in connection with the conduct of the Company’s business. Each Member acknowledges and agrees that the Company will have the exclusive right to use the name set forth in this Section or any other names under which the Company operates, subject to customary use and reference by Members in connection with providing services to the Company and reporting on their interest in the Company. In the event the Management Services Agreement is terminated, the Company shall amend its name to remove the reference to “Black Ridge” within ninety (90) days of such termination.

 

2.4           Term . Unless otherwise agreed to in writing amending this Agreement, the Company’s existence will be perpetual.

 

2.5           Registered Agent and Office . The Company’s registered agent for service of process and registered office in the State of Delaware will be The Corporation Trust Company, Corporation Trust Center, 1209 Orange Street, Wilmington, New Castle County, Delaware 19801. The Company will continuously maintain a registered office and a registered agent in the State of Delaware, as required by the Act. The Delaware registered office and registered agent may be changed from time to time by the Managing Member, in accordance with the Act.

 

2.6           Principal Place of Business . The Company’s principal place of business will be located at 601 Carlson Parkway, Suite 200, Minnetonka, MN 55305. The Managing Member may change the location of the Company’s principal place of business. The Managing Member will cause to be made any filing and cause to be taken any other action required by applicable law in connection with any such change and will give notice to all Members of the new location of the Company’s principal place of business promptly after any such change becomes effective. The Company also may have such other offices as the Managing Member from time to time may determine.

 

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2.7           Maintenance . The Managing Member will cause to be filed promptly all certificates, amendments, or other instruments as required by law to maintain the Company in good standing as a limited liability company in the State of Delaware and any other jurisdiction in which the Company conducts business, including as required to comply with any fictitious name statutes.

 

2.8           Business and Purpose . The purpose of the Company will be to engage in any lawful activity for which a limited liability company may be organized under the Act, including the acquisition, ownership and disposition of one or more Projects.

 

2.9           Powers . The Company will have all powers of a limited liability company under the Act and the power to do all things necessary or convenient to operate its business and accomplish its purpose as described in Section 2.8 .

 

2.10           Existence, Properties, Etc . The Managing Member will maintain, preserve, and keep in full force and effect (i) all rights, franchises, licenses and permits necessary to the proper conduct of the Company’s business and (ii) ownership, leasing or operation of the Company’s properties which, if not so maintained, could reasonably be expected to have a material adverse effect on the Company. The Managing Member also will take all action that may be reasonably required to obtain, preserve, renew and extend all material licenses, permits, authorizations, trade names, trademarks, service names, service marks, copyrights and patents which are necessary for the continuance of the operation of any such properties and the business by the Company.

 

2.11           Effective Date . This Agreement became effective on the Effective Date.

 

2.12           Title to Company Property . All property owned by the Company will be owned by the Company as an entity and, insofar as permitted by applicable law, no Member will have any ownership interest in any Company property in its individual name or right, and each Member’s interest in the Company will be personal property for all purposes.

 

2.13           No Partnership . The Company will not be a partnership or joint venture under any state or federal law, and no Member will be a partner or joint venturer of any other Member for any purpose, other than the Code and other applicable tax laws, and this Agreement will not be construed otherwise.

 

2.14           Financial Statements. All of the Company’s financial records will be maintained pursuant to generally accepted accounting principles ( except for the absence of footnotes and subject to changes resulting from normal year-end audit adjustments for recurring accruals of the types included in the financial statements of the Company in prior fiscal years ), and its other records will be maintained to the extent necessary to record the activities and business operations of the Company. The Company will provide complete financial reports, including a balance sheet, income statement and statement of cash flows to all Members within 120 days after the end of each fiscal year. The expense of preparing such financial reports will be borne by the Company.

 

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ARTICLE III

MEMBERS

 

3.1           Members . The Members of the Company will be as set forth on Exhibit A hereto, as amended from time to time in accordance with this Agreement. Except as required under the Act or as expressly set forth in this Agreement, no Member, in its capacity as a Member, (i) will take part in the control, management, direction or operation of the affairs of the Company or have power or authority to bind the Company or (ii) will be personally liable for any debt, obligation or liability of the Company, whether such debt, obligation or liability arises in contract, tort or otherwise.

 

3.2           Additional Members . Additional Members will not be admitted to the Company without the approval of the Managing Member. The Membership Interests allocated to any additional Member will be determined by the Managing Member. The Managing Member will amend the books and records of the Company to reflect any revised Membership Interests. An additional Member that intends to become a party to this Agreement pursuant to this Section will not have any rights under this Agreement or with respect to the Company, and will not be admitted as a Member of the Company, unless and until such additional Member executes a counterpart of this Agreement and satisfactorily completes, executes and delivers such additional documentation and certifications as the Managing Member may require.

 

3.3           Managing Member . Except as expressly otherwise provided in this Agreement, actions of the Company may be taken only at the direction and consent of the Managing Member in accordance with Section 5.2 , without the requirement of any vote or consent of any other Member.

 

3.4           Meetings . Meetings of the Members for any purpose consistent with this Agreement may be called by the Managing Member. Non-Voting Members have the right to receive notice of and attend any meetings of Members, but may not otherwise participate in such meetings, except as the Managing Member may otherwise direct from time to time or as otherwise expressly provided in this Agreement. Written notice of each meeting of the Members will be delivered, pursuant to Section 13.1 or as otherwise required by the Act, by or at the direction of the Person calling such meeting, to each such Member. Each notice delivered pursuant to this Section will state the place, day and hour of the meeting and the purpose for which such meeting is being called. A quorum necessary for the transaction of any business is present if the Managing Member is present and more than fifty percent (50%) of the Voting Interest of all Voting Members is present. Any action that can be taken at a meeting can be taken by a written action, provided that such written action is signed by the Managing Member and such other Members as are necessary to represent more than fifty percent (50%) of the Voting Interest of all Voting Members. A copy of such written action will promptly be transmitted to the Members not signing such written action. Meetings of the Members may be made by video or audio conferencing or similar communications equipment provided that a quorum exists and if all Members participating in the meeting can hear each other.

 

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ARTICLE IV

TRANSFERS; OPTION TO BID

 

4.1           Transfer Restrictions .

 

(a)          Except for Merced, which may Transfer all or any portion of its Membership Interest to any party without restriction (subject to the provisions of Section 4.1(b) ), no Member may Transfer all or any part of its Membership Interest without receiving express, prior written consent from the Managing Member, which consent may be withheld in the Managing Member’s sole and absolute discretion, provided that Black Ridge may Transfer all or a part of its Membership Interest to an Affiliate. Any consent granted by the Managing Member will only apply to such Transfer as specifically described in such written consent (including the name(s) of the buyer, assignee or transferee, and the terms and conditions of such Transfer), and will terminate automatically in the event such Transfer is not consummated by the deadline specified in such written consent. All Persons to whom Membership Interests are transferred pursuant to this Section will also be subject to the transfer restrictions contained in this Section.

 

(b)          In the event Merced Transfers its entire Membership Interest (other than to an Affiliate of Merced) or Merced Transfers part of its Membership Interest (other than to an Affiliate of Merced) and will no longer serve as the Managing Member as a result of such Transfer, Black Ridge shall have the right to include in the sale its entire Membership Interest in the Company. The amount to be received by Black Ridge in connection with a sale under this Section 4.1(b) shall be equal to the amount Black Ridge would have received with respect to the transferred Membership Interest if the sale proceeds had been paid to the Company, and the Company had then liquidated on the date of the sale and distributed the proceeds of such liquidation to the holders of the transferred Membership Interests in accordance with the provisions of Article 11 relating to distributions to be made in connection with the winding up of the Company.

 

4.2           Direct and Indirect Transfers . For purposes of this Agreement, restrictions upon the Transfer of a Membership Interest will extend to any direct or indirect Transfer and any involuntary transfer of such Membership Interest (such as a transfer pursuant to a foreclosure sale or a transfer resulting by operation of law).

 

4.3           Substitution of a Member .

 

(a)           Other than an assignee, legatee, or transferee of Merced (as provided in Section 4.1 above), no assignee, legatee, or transferee (by conveyance, operation of law or otherwise) of the whole or any portion of a Membership Interest will have the right to become a substituted Member without the written approval of the Managing Member, which approval may be withheld in the Managing Member’s sole discretion. The granting or denial of a request for approval will be within the absolute discretion of the Managing Member; provided , however, that the Managing Member will not unreasonably withhold or delay consent regarding any Transfer of a Membership Interest by a Member to an Affiliate of such Member. Any purported Transfer in violation of this Article IV will be null and void and the purported transferee will become neither a Member nor a holder of any interest in the Company whatsoever. A substituted Member that is admitted as a Member in accordance with Section 4.6 will succeed to all the Membership Interest of its assignor.

 

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(b)          If a Member will be dissolved, merged or consolidated, its successor-in- interest will have the same rights and obligations that such Member would have had if it had not been dissolved, merged or consolidated, except that the successor will not become a substituted Member without the prior approval of the Managing Member pursuant to (a) above.

 

(c)          As conditions to its substitution as a Member pursuant to this Section, a Person will (i) execute and deliver such instruments, in form and substance satisfactory to the Managing Member, as the Managing Member deem necessary in its sole discretion and (ii) pay all reasonable expenses of the Company in connection with its admission as a substituted Member.

 

4.4           Conditions to Transfer . No Transfer of any Membership Interest in the Company otherwise permitted under this Agreement will be effective for any purpose whatsoever until the transferee will have assumed the transferor’s obligations to the extent of the Membership Interest transferred and will have agreed to be bound by all the terms and conditions hereof, by written instrument, duly acknowledged, in form and substance reasonably satisfactory to the Managing Member in its sole discretion.

 

4.5           Adjustment of Membership Interests . Upon a Transfer, redemption or other change in any Membership Interest, including a Member substitution, pursuant to this Article, the Managing Member will amend Exhibit A hereto to reflect such Transfer, redemption or other change.

 

4.6           New Member as a Party to this Agreement . A Person that (a) has been approved as an additional or substitute Member pursuant to Section 3.2 or Section 4.3 , as applicable, and (b) intends to become a party to this Agreement pursuant to this Article, will not have any rights under this Agreement or with respect to the Company, and will not be admitted as a Member of the Company, unless and until such Person executes a counterpart of this Agreement. An assignee, legatee or transferee that is not admitted as a Member will be entitled only to the allocations and distributions to which its assignor would otherwise be entitled.

 

4.7           Black Ridge Option to Bid . In the event that the Managing Member determines to sell one or more Projects or its Membership Interest related thereto by means of an auction or similar sales process (the “ Auction ”), the Managing Member will send written notice (the “ Auction Notice ”) of such intent to Black Ridge. Black Ridge will have the option to deliver to the Managing Member, in accordance with the applicable Auction terms, a bid to purchase the Project(s) or Membership Interest being offered for sale and setting forth the gross purchase price and other significant terms on which Black Ridge is willing to purchase the Company’s assets. The Managing Member will determine whether to accept the Offer or reject it in the course of the Auction and will have the sole discretion whether to accept the Offer or any other bid, or to decide not to consummate such sale. The option set forth in this section will not apply to, and the Managing Member will not be obligated to deliver an Auction Notice with respect to, any endeavor by the Managing Member to sell all or a portion of the Projects or its Membership Interest through a private sale process; e.g. , pursuant to bilateral discussions with a third party.

 

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ARTICLE V

MANAGEMENT

 

5.1           Management .

 

(a)          The management and control of the business and affairs of the Company will be exclusively vested in the Managing Member, without the requirement of any vote or consent of any other Member.

 

(b)          The Company will indemnify the Managing Member and its Affiliates, officers, directors, equity holders, partners, employees and agents to the fullest extent permitted by Delaware law, against any liability or cost arising out of its service to the Company. The Company will advance funds to cover expenses, including attorneys’ fees, incurred by the Managing Member in connection with the defense of any civil, criminal, administrative or investigative action, suit or proceeding arising out of such member’s service to the fullest extent permitted by Delaware law.

 

(c)          The Company will indemnify the Members and their Affiliates, officers, directors, equity holders, partners, employees and agents to the fullest extent permitted by Delaware law, against any liability or cost arising out of their Membership Interests in the Company. The Company will advance funds to cover expenses, including attorneys’ fees, incurred by a Member in connection with the defense of any civil, criminal, administrative or investigative action, suit or proceeding arising out of such Member’s Membership Interest to the fullest extent permitted by Delaware law. For the avoidance of doubt, the indemnification and advance of funds provided under this Section 5.1(c) will not cover or apply to Black Ridge with respect to its performance of, or any liability under, the Management Services Agreement, including any manner of tax liability arising thereunder.

 

5.2           Action by Managing Member . Any action, decision or determination by the Managing Member will constitute an action, decision or determination of the Company. Except as expressly otherwise provided in this Agreement, actions of the Company may be taken only at the direction and consent of the Managing Member in accordance with this Section 5.2 , without the requirement of any vote or consent of any other Member.

 

5.3           Independent Activities; Transactions with Affiliates .

 

(a)          The Managing Member will devote such time to the affairs of the Company as it, in its sole discretion, deem necessary to manage and operate the Company.

 

(b)          To the extent permitted by applicable law, and except as specifically provided in this Section 5.3 , neither this Agreement nor any activity undertaken pursuant to this Agreement will prevent a Member or any of its respective Affiliates from engaging in whatever activities they choose, whether the same are competitive with the Company or otherwise and any such activities may be undertaken without having or incurring any obligation to offer any interest in such activities to the Company or any other Member, or requiring the Company or any other Member (or such Member’s Affiliates) to participate in any such activities.

 

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(c)          To the extent permitted by applicable law and subject to the provisions of this Agreement, the Managing Member is authorized to cause the Company to purchase property from, sell property to, or otherwise deal with any other Member, acting on its own behalf, or any Affiliate of any Member; provided that any such purchase, sale or other transaction is either (i) made on terms and conditions which are no less favorable to the Company than if the sale, purchase or other transaction had been made with an independent third party or (ii) consented to by a majority of the disinterested Members.

 

(d)          The Managing Member is authorized to have the Company enter into the Management Services Agreement with Black Ridge.

 

5.4           Officers . The Company is not required to have officers, but may have such officers or other authorized persons as deemed necessary or appropriate by the Managing Member in its sole discretion (each, an “ Officer ”). All Officers shall be selected by the Managing Member and shall serve at the pleasure of the Managing Member. Any individual may hold any number of offices. Each Officer shall have the powers and duties of management usually vested in such Officer’s office by a corporation existing under Delaware law, and shall have such other powers and duties as may be prescribed by the Managing Member.

 

5.5           Reliance by Third Parties . No third party dealing with the Company will be required to ascertain whether the Managing Member or any Officer is or are acting in accordance with the provisions of this Agreement. All third parties may rely on a document executed by the Managing Member (or an Officer duly authorized by the Managing Member to execute such document) as binding the Company. If any Member acts without authority, such Person will be liable to the Members for any damages arising out of such unauthorized actions.

 

5.6           Insurance . The Managing Member will cause the Company to maintain, at the cost of the Company and for the protection of the Company and all of its Members, officers’ insurance and such other insurance as the Managing Member deems necessary for the operations being conducted.

 

5.7           Fiduciary Duties . This Agreement is not intended to, and does not, create or impose any duty (including any fiduciary duty) on the Managing Member, any other Member, or agent of the Company, or an Officer, director, equity holder, partner, employee, agent or Affiliate of such Person (each, a “ Covered Person ”). Further, notwithstanding any other provision of this Agreement or any duty otherwise existing at law or in equity, the parties hereto agree that no Member or Managing Member shall, to the fullest extent permitted by law, have duties (including fiduciary duties) to any other Member or to the Company, and in doing so, recognize, acknowledge and agree that their duties and obligations to one another and to the Company are only as expressly set forth in this Agreement; provided, however, that each Member shall have the duty to act in accordance with the implied contractual covenant of good faith and fair dealing. To the extent that, at law or in equity, any Covered Person has duties (including fiduciary duties) and liabilities relating thereto to the Company or to any other Covered Person, a Covered Person acting under this Agreement will not be liable to the Company, to any Member or to any other Covered Person for its good faith reliance on the provisions of this Agreement. The provisions of this Agreement, to the extent that they restrict the duties and liabilities of a Covered Person otherwise existing at law or in equity, are agreed by the Members to replace such other duties and liabilities of such Covered Person.

 

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ARTICLE VI

CAPITAL CONTRIBUTIONS; INTERESTS; ADDITIONAL PROJECTS

 

6.1           Initial Capital Contributions; Interests . Merced has made an initial Capital Contribution to the Company in the amount set forth on Exhibit A , which is an amount deemed sufficient by the Managing Member for the initial capital needs of the Company (including costs and expenses association with forming the Company). Each Member is deemed to have the Percentage Interest and Voting Interest, if any, set forth on Exhibit A hereto.

 

6.2            Forfeiture of Management Participation Interest . If the Management Services Agreement is terminated by the Company for * * * or by Black Ridge pursuant to Section 7.1 of such agreement (Termination for Convenience), then the Management Participation Interest will be immediately forfeited and declared null and void and of no further effect, and neither the Company nor the Managing Member will have any further liability with respect to the Management Participation Interest. For the avoidance of doubt, if the Management Services Agreement is terminated by the Company pursuant to * * *, by the Company pursuant to * * *, or by Black Ridge pursuant to Section 7.2 of such agreement (Termination for Cause), Black Ridge will retain its Management Participation Interest and maintain its status as a Member hereunder until such time as this Agreement is terminated and the Company is dissolved pursuant to the terms and conditions of this Agreement. Nothing set forth in this Section 6.2 will affect Black Ridge’s rights to compensation under the Management Services Agreement.

 

6.3           Additional Capital Contributions .

 

(a)          Merced will from time to time and in its sole discretion make additional Capital Contributions to the Company for Project acquisitions, to fund approved AFEs for Projects and as needed for the operations of the Company, in each case based on Merced’s evaluation of each Project, AFE and potential Project, and of additional criteria (including satisfactory progress of existing Project(s) and a continuing favorable market outlook). Unless otherwise agreed by all Members or as set forth in Section 6.3(b) below, all additional Capital Contributions will be made 100% by Merced. For purposes of clarity, nothing in this Agreement shall obligate Merced to acquire any number of Projects or to make a minimum investment in Project acquisitions.

 

(b)          Subject to Section 6.3(d) , if, from time to time in the reasonable judgment of the Managing Member, the Company requires additional capital for any purpose and Merced does not wish to make such additional Capital Contribution, the Managing Member is authorized to cause the Company to issue additional Membership Interests of any class, on terms and conditions and with repayment priorities as determined by the Managing Member in its sole discretion.

 

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(c)          Subject to Section 6.3(d) , if, from time to time, the Managing Member determines that it is in the best interest of the Company to issue additional Membership Interests to one or more Persons performing services for the Company, the Managing Member will have the right to cause the Company to issue such Membership Interests of any class. The Percentage Interest, Voting Interest and the cost of each will be determined by the Managing Member in its sole discretion. The Managing Member may elect, in connection with the issuance of a Membership Interest in connection with the performance of services, to revalue the Company’s property pursuant to Treasury Regulation Section 1.704-1(b)(2)(iv)(f)(5) and adjust the Capital Accounts of Members pursuant to such regulation. The Company and each Member acknowledge that the Internal Revenue Service (“ Service ”) has issued Rev. Proc. 93-27, 1993-2 CB 343 and Rev. Proc. 2001-43, 2001-2 CB 191, which set forth criteria which the Service is bound to apply to the issuance by a partnership of vested or unvested profits interests in connection with the performance of services. The Service subsequently issued proposed regulations in 2005 which when made final would, among other things, revoke these revenue procedures and subject the issuance of any partnership interest, whether a capital or a profits interest, to the provisions of Section 83 of the Code; there is no assurance that these regulations will be finalized, and, if finalized, whether they will contain provisions identical to those in the proposed regulations. The proposed regulations if finalized in their present form would affect the tax consequences to both the service partner and the Company of an issuance of a profits or capital interest in connection with the performance of services including adjustments which may be required to be made to the Capital Accounts of the Members. Accordingly, in addition to any other power and authority vested in the Managing Member, and notwithstanding any other provision of this Agreement, the Managing Member may:

 

(i)          cause such adjustments to the Capital Accounts of Members as the Managing Member determines to be necessary or appropriate to reflect the economic rights and obligations that the Managing Member agrees to embody in Membership Interests that are issued in connection with the performance of services;

 

(ii)         make any special allocation of taxable income or items thereof that is consistent with the provisions of current or future law relating to issuance of partnership interests in connection with the performance of services;

 

(iii)        cause the Company to elect, maintain and comply with the safe harbor provisions described in proposed Treasury Regulation Section 1.83-3(1), when finalized, and to take any action on behalf of each Member as may be necessary or appropriate to legally bind the Company and all Members, including transferees, to elect, maintain and comply with the requirements of such safe harbor, and each Member will execute such documentation as may be reasonably requested by the Company to assurance such election, compliance and maintenance; and

 

(iv)        amend this Agreement without Member approval to the extent the Managing Member considers necessary or appropriate to implement the foregoing provisions of this Section 6.3(c) .

 

(d)          So long as no default has occurred and is continuing under the Management Services Agreement, and notwithstanding anything to the contrary in this Agreement, Black Ridge’s prior written consent will be required in order to issue additional Membership Interests or reallocate the Membership Interests of the Members pursuant to an issuance of Membership Interests to one or more Persons performing services for the Company, if such issuance or reallocation has the effect of diluting the economic interests of Black Ridge. Additional Capital Contributions by a Member, and the right to distributions of Unreturned Capital Contributions, and Unsatisfied Preferred Returns pertaining thereto, will not be treated as diluting the economic interests of the other Members.

 

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(e)          Upon the acceptance of additional Capital Contributions and issuance of additional Membership Interests or reallocation of Membership Interests pursuant to this Section, the Managing Member will update the books and records of the Company to reflect such additional Capital Contributions and issuance, which books and records will be definitive evidence of the amount of each Member’s Capital Contributions and ownership of Membership Interests of the Company, absent manifest error.

 

6.4           Return of Capital Contributions . Capital Contributions will be expended in furtherance of the business of the Company. All costs and expenses of the Company will be paid from its funds. No interest will be paid on Capital Contributions. The Company will not have any personal liability for the repayment of any Capital Contribution to a Member.

 

6.5           Acquisition of Additional Projects; Black Ridge Option to Co-Invest . Prior to the Company’s acquisition of a new Project, Black Ridge will have the option to participate as a co-investor with the Company in such Project (each, a “ Co-Invest Project ”), up to a maximum co-investment of twenty-five percent (25%) of the total Co-Invest Project capital. If Black Ridge elects to participate in a Co-Invest Project, Black Ridge will deliver to the Managing Member no more than five (5) business days after notice to the Company of a new Project or at the time of the Company’s approval of the Project acquisition, if such approval is made earlier, a written notice of Black Ridge’s intent to co-invest and its co-investment commitment amount (the “ Co-Invest Percentage ”). Each Co-Invest Project will be owned severally (and not jointly) by Black Ridge and the Company, with Black Ridge holding a portion equal to the Co-Invest Percentage and the Company owning the remaining portion.

 

ARTICLE VII

DISTRIBUTIONS

 

7.1           Distributions . On a quarterly basis, and more often as the Managing Member may determine in its sole discretion, the Company: (i) will distribute to the Members Net Cash Flow of the Company; and (ii) may distribute other assets of the Company as determined by the Managing Member in its sole discretion, such distribution not to be unreasonably withheld (the amount of any such distribution of Net Cash Flow or other assets of the Company, the “ Distributable Amount ”). The Company will not distribute Net Cash Flow unless the Managing Member determines in its reasonable discretion that (x) such Net Cash Flow or portion thereof proposed to be distributed is held by the Company in the form of cash and (y) such cash is not needed by the Company for the payment of expenses. Unless otherwise unanimously agreed by the Members, Net Cash Flow and Operating Cash Flow of the Company will be calculated and distributed separately for each Pool, and will be distributed to the Members in the following order of priorities:

 

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(a)          First, 100 percent of such Distributable Amount will be distributed to the Members, in proportion to and to the extent of their respective then outstanding Unsatisfied Preferred Returns;

 

(b)          Next, 100 percent of any remaining Distributable Amount will be distributed to the Members in proportion to and to the extent of their respective then outstanding Unreturned Capital Contributions; and

 

(c)          Thereafter, the balance of any remaining Distributable Amount will be distributed * * * % to the Members in proportion to their Percentage Interests and * * * % to Black Ridge in respect of its Management Participation Interest.

 

The Members intend that nonliquidating distributions to the Members under Section 7.1 be separately calculated with respect to each Pool. For the avoidance of doubt, the Members intend that distributions under Section 7.1(a) and 7.1(b) be calculated by allocating to each Pool its proper share of the Unsatisfied Preferred Returns and Unreturned Capital Contributions of a Member, and that distributions may accordingly be made to the Members pursuant to Section 7.1(c) with respect to a given Pool even though there remain Unsatisfied Preferred Returns and Unreturned Capital Contributions with respect to other Pools.

 

The Management Participation Interest has been structured to satisfy the requirements of Rev. Proc. 93-27 to be treated as a profits interest thereunder, and for avoidance of doubt, the Members intend the provisions of Section 7.1(a) , (b) and (c) to satisfy the requirement of such revenue procedure that, if the Company were liquidated immediately following the issuance of the Management Participation Agreement, its debts repaid and the net remaining proceeds distributed to Merced pursuant to Section 7.1(a) and (b) , there would be no remaining proceeds available for distribution to Black Ridge under Section 7.1(c) .

 

7.2           Amounts Withheld . Any amounts withheld from a distribution by the Company to a Member pursuant to any federal, state, local or foreign tax law shall be treated as if the same had been distributed to that Member pursuant to Section 7.1 . Any other amount required to be paid by the Company to a taxing authority with respect to a Member pursuant to any federal, state, local or foreign tax law in connection with any payment to or tax liability (estimated or otherwise) of the Member shall be treated as a loan from the Company to that Member. If such loan is not repaid within thirty (30) days from the date the Managing Member notifies that Member of the withholding, the loan shall bear interest at an annual rate equal to the lesser of (a) ten percent (10%) per annum or (b) the highest nonusurious rate permitted by applicable law under such circumstances from the date of the applicable notice to the date of repayment. In addition to all other remedies the Company may have, the Company may withhold distributions that would otherwise be payable to that Member and apply those distributions instead to the repayment of the loan and accrued interest.

 

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ARTICLE VIII

ALLOCATIONS OF PROFIT AND LOSS

 

8.1           Determination of Profit and Loss . Profit or Loss will be determined by the Managing Member in accordance with this Agreement on an annual basis and for such other periods as may be required by this Agreement or otherwise.

 

8.2           Allocations of Profit and Loss . Except as otherwise provided in this Agreement, and after giving effect to Section 8.3 , Profit or Loss for any Fiscal Year will be allocated among the Members such that the Capital Account of each Member, immediately after giving effect to such allocations, will equal (proportionately), as nearly as possible, (A) the amount of the distributions that would be made to such Member during such Fiscal Year if (i) the Company were dissolved and terminated, (ii) its affairs were wound up and each asset were sold for its Book Value (except that any asset which was the subject of a disposition in such Fiscal Year will be treated as if it were sold for cash equal to the sum of the amount received by the Company in any such disposition and the fair market value of any other property received by the Company in such disposition), (iii) all liabilities of the Company were satisfied; and (iv) the net assets of the Company were distributed to the Members in accordance with Section 7.1 , minus (B) such Member’s share of partnership minimum gain and partner nonrecourse debt minimum gain determined pursuant to Treasury Regulation Sections 1.704-2(g)(1) and 1.704-2(i)(5), computed immediately prior to the hypothetical sale of assets. The Managing Member will make such other assumptions as it deems necessary or appropriate in its good faith and reasonable judgment in order to effectuate the intended beneficial entitlements of the Members.

 

8.3           Regulatory Allocations and Curative Provision .

 

(a)          The “partnership minimum gain” and “partner nonrecourse debt minimum gain” provisions of Treasury Regulation Section 1.704-2 are incorporated herein by reference and will apply notwithstanding the allocation of Profit and Loss provided for under Section 8.2 to the extent provided in that regulation.

 

(b)          The “qualified income offset” provisions of Treasury Regulation Section 1.704-1(b)(2)(ii)(d) are incorporated herein by reference and will apply notwithstanding the allocation of Profit and Loss otherwise provided for under Section 8.2 to the extent provided in that regulation.

 

(c)          Company deductions that are characterized as “nonrecourse deductions” under Treasury Regulation Sections 1.704-2(b)(1) and 1.704-2(c) for any taxable year, or portion thereof, will be allocated to the Members in proportion to their respective Percentage Interests.

 

(d)          Company deductions that are characterized as “partner nonrecourse deductions” under Treasury Regulation Sections 1.704-2(i)(1) and 1.704-2(i)(2) for any taxable year, or portion thereof, will be allocated to the Members as provided in Treasury Regulation Section 1.704-2(i)(1).

 

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(e)          Notwithstanding the provisions of Section 8.2 , if during any Fiscal Year the allocation of any loss or deduction, net of any income or gain, to a Member would cause or increase a negative balance in a Member’s Capital Account as of the end of that Fiscal Year, only the amount of such loss or deduction that reduces the balance to zero will be allocated to the Member and the remaining amount will be allocated to the other Members. For the purpose of the preceding sentence, a Capital Account will be reduced by the adjustments, allocations and distributions described in Treasury Regulations Sections 1.704-1(b)(2)(ii)(d)(4), (5) and (6), and increased by the amount, if any, that the Member is obligated to restore to the Member’s Capital Account within the meaning of Treasury Regulation Section 1.704-1 (b )(2)(ii)(c) as of that time or is deemed obligated to restore under Treasury Regulation Section 1.704-2(g)(1) or Section 1.704-2(i)(5).

 

(f)          All allocations pursuant to the foregoing provisions of this Section (the “ Regulatory Allocations ”) will be taken into account in computing allocations of other items under Section 8.2 , including, if necessary, allocations in subsequent Fiscal Years, so that the net amounts reflected in the Members’ Capital Accounts and the character for income tax purposes of the taxable income recognized (e.g., as capital or ordinary) will, to the extent possible, be the same as if no Regulatory Allocations had been given effect. In exercising its discretion under this Section 8.3(f) , the Company shall take into account future Regulatory Allocations under Section 8.3(a) that, although not yet made, are likely to offset other Regulatory Allocations previously made under Sections 8.3(c) and (d) .

 

ARTICLE IX

ALLOCATION OF TAXABLE INCOME AND LOSS

 

9.1           General . Except as provided in Section 9.2 , each item of income, gain, loss and deduction of the Company for federal income tax purposes will be allocated among the Members in the same manner as such item is allocated under Article VIII.

 

9.2           Allocation of Section 704(c) Items . The Members recognize that with respect to property contributed to the Company by a Member and with respect to property revalued in accordance with Treasury Regulation Section 1.704-1(b)(2)(iv)(f), there may be a difference between the fair market value of such property at the time of contribution or revaluation and the adjusted tax basis of such property at that time, which will result under Treasury Regulation Section 1.704(b) in a difference between the Book Value of such property and its adjusted tax basis. All items of tax depreciation, cost recovery, amortization, amount realized and gain or loss with respect to such assets will be allocated among the Members to take into account such book-tax disparities in accordance with the provisions of Section 704(c) of the Code and the Treasury Regulations thereunder using a reasonable method selected by the Managing Member.

 

9.3           Recapture Items . In the event that the Company has taxable income that is characterized as ordinary income under the recapture provisions of the Code, then Sections 1.1245-1(e) and 1.1250-1(f) of the Treasury Regulations shall apply, and in the event that the Company has taxable income that is characterized as “unrecaptured Section 1250 gain” under Section 1(h)(6) of the Code, then the principles of such Treasury Regulations shall apply.

 

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ARTICLE X

ACCOUNTING, REPORTING AND TAX MATTERS

 

10.1           Capital Accounts . The Managing Member will establish and maintain a separate capital account (“ Capital Account ”) for each Member in accordance with the Treasury Regulations under Section 704(b) of the Code and such other accounts as may be necessary or desirable to comply with the requirements of applicable laws and regulations. No Member will be required to make up a negative balance in its Capital Account or to pay to any Member the amount of any such negative balance.

 

10.2           Transfers During Year . In order to avoid an interim closing of the Company’s books, the share of Profits or Losses under Article VIII of a Member who transfers part or all of its interest in the Company during the Company’s accounting year may be determined by taking such Member’s pro rata share of the amount of such Profits or Losses for the year. The proration will be based on the portion of the Company’s accounting year that has elapsed prior to the transfer or may be determined under any other reasonable method; provided, however, that any gain or loss from the sale of Company assets will be allocated to the owner of the Membership Interest at the time of such sale. The balance of the Profits or Losses attributable to the Membership Interest transferred will be allocated to the transferee of such Membership Interest.

 

10.3            Tax Filings . The Managing Member will cause the income tax returns for the Company to be prepared and filed in a timely manner with the appropriate authorities. Prior to March 15 of each year, the Members will be provided with a copy of the Company federal income tax return (Form 1065), as filed or to be filed for the preceding year.

 

10.4           Election to be Taxed as Partnership . The Company will be treated as a partnership for federal income tax purposes. Neither the Managing Member nor any Member will take any action that would cause the Company to be treated as a corporation for federal income tax purposes.

 

10.5           Section 754 Election . Upon the request of any Member, the Managing Member may, at its discretion, cause the Company to make the election provided for under Section 754 of the Code.

 

10.6           Tax Matters Partner . Merced will represent the Company as “tax matters partner” (as defined in Section 6231 of the Code) in connection with all examinations of the Company’s affairs by tax authorities, including resulting judicial and administrative proceedings, and will expend the Company’s funds for professional services and costs associated therewith.

 

A RTICLE XI

DISSOLUTION AND WINDING UP

 

11.1           Dissolution . The Company will be dissolved, its assets disposed of, and its affairs wound up upon the occurrence of any of the following events:

 

(a)          a written election by the Managing Member to dissolve the Company;

 

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(b)          the merger of the Company (where the Company is not the surviving entity) or sale of all or substantially all of the assets of the Company; or

 

(c)          entry of a decree of judicial dissolution pursuant to Section 18-802 of the Act.

 

11.2           Winding Up . If the Company is dissolved pursuant to Section 11.1 , the Company will continue solely for the purpose of winding up its affairs in an orderly manner, liquidating its assets, and satisfying the claims of its creditors. The Managing Member, or, if the Managing Member is unable to act, another Person selected by the Managing Member, will be responsible for overseeing the winding up and liquidation of the Company, will take full account of the liabilities and assets of the Company and will cause the Company’s assets to be sold (as promptly as is consistent with obtaining the fair market value thereof) prior to distributing any such assets, and will cause the proceeds therefrom, to the extent sufficient therefor, to be applied and distributed as provided in Section 11.3 . The Managing Member (or such other Person selected in accordance with this Section) will give written notice of the commencement of winding up to each Member and to all known creditors and claimants whose addresses appear on the records of the Company.

 

11.3           Payment of Liabilities and Distribution of Assets upon Dissolution .

 

(a)          After determining that all reasonably foreseeable debts and liabilities of the Company, including debts and liabilities to any of the Members as creditors of the Company, have been paid or adequately provided for, the remaining assets will be distributed to the Members in accordance with Section 7.1 . Such distribution will be made by the later of (i) the end of the Company’s taxable year in which the Company is liquidated or (ii) 90 days after the date of such liquidation.

 

(b)          The payment of a debt or liability, whether the whereabouts of the creditor is known or unknown, may be adequately provided for by either of the following means (provided, however, that the following means will not prescribe the exclusive means of making adequate provision for the payment of debts and liabilities):

 

Payment thereof has been assumed or guaranteed in good faith by one or more financially responsible Persons or by the United States government or any agency thereof, and the provision, including the financial responsibility of the Person, was determined in good faith and with reasonable care by the Managing Member (or other Person selected by the Managing Member) to be adequate at the time of any distribution of the assets pursuant to this Section; or

 

The amount of the debt or liability has been provided for in accordance with Section 18-804(b) of the Act.

 

11.4           Distributions In Kind . Any non-cash asset distributed to one or more Members will first be valued at its fair market value as of a date reasonably close to the date of liquidation. Any unrealized appreciation or depreciation with respect to such asset will be allocated among the Members (in accordance with the provisions of Article VIII assuming that the asset was sold for appraised value and the proceeds where distributed in accordance to Section 7.1 ) and taken into consideration in determining the balance in the Members’ Capital Accounts as of the date of liquidation. Distribution of any such asset in kind to a Member will be considered a distribution of an amount equal to the asset's fair market value for purposes of Section 7.1 . The Managing Member (or such other Person selected in accordance with Section 11.2 ), in its sole discretion, may distribute any percentage of any asset in kind to a Member even if such percentage exceeds the percentage in which the Member shares in distributions as long as the sum of the cash and fair market value of all the assets distributed to each Member equals the amount of the distribution to which such Member is entitled pursuant to this Agreement. The fair market value of any non-cash asset will be determined by the Members and, if the Members are unable to agree within 30 days of the date or event requiring such determination, by an independent appraisal. The cost of such appraisal shall be borne by the Company.

 

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11.5           Certificate of Cancellation . As soon as possible following the dissolution and the completion of winding up of the Company pursuant to this Article, or as otherwise required under the Act, the Managing Member (or such other Person selected in accordance with Section 11.2 ) will execute a certificate of cancellation and will cause such certificate of cancellation to be filed with the Secretary of State of the State of Delaware and will take such other actions as may be necessary to terminate the Company.

 

ARTICLE XII

INVESTMENT REPRESENTATIONS

 

12.1           Investment Purpose . In acquiring a Membership Interest in the Company, each Member represents and warrants to the Company that it is acquiring such Membership Interest for its own account for investment and not with a view to its sale or distribution. Each Member recognizes that investments such as those contemplated by the Company are speculative and involve substantial risk and are suitable only for investors of substantial means who have no immediate need for liquidity of the amount invested, and that such investments involve a risk of loss of all or a substantial part of such investments. Each Member further represents and warrants that none of the Company, Merced, Black Ridge, or any Affiliate, officer, director, equity holders, partner, employee or agent of the Company or any such Member, has made any guaranty or representation upon which said Member has relied concerning the possibility or probability of profit or loss as a result of its acquisition of an Membership Interest in the Company.

 

12.2           Restrictions on Transfer . Each Member recognizes that: (i) its Membership Interest has not been registered under the Securities Act of 1933, as amended (the “ Securities Act ”), in reliance upon an exemption from such registration, (ii) a Member may not Transfer or offer to Transfer all or any part of Membership Interest in the Company in the absence of an effective registration statement covering such interest under the Securities Act, unless such Transfer or offer of Transfer is exempt from registration under the Securities Act (and is otherwise in compliance with any additional restrictions on transfer set forth elsewhere in this Agreement), (iii) the Company will not have any obligation to register any Member’s interest for sale or to assist in establishing an exemption from registration for any proposed Transfer and (iv) these restrictions on Transfer, together with the additional restrictions on Transfer set forth in this Agreement, may severely affect the liquidity of a Member’s investment.

 

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12.3           Accredited Investors . In acquiring a Membership Interest in the Company, each Member represents and warrants to the Company that:

 

(a)          it is an “accredited investor” within the meaning of Rule 501 of Regulation D promulgated under the Securities Act;

 

(b)          such Member has such knowledge and experience in financial, tax and business matters so as to enable it to evaluate the merits and risks of an investment in the Company and to make an informed investment with respect thereto;

 

(c)          such Member is not relying on the Company with respect to the tax or other economic considerations of an investment in the Company and has obtained, or had the opportunity to obtain, the advice of its own legal, tax and other advisors;

 

(d)          such Member, if executing this Agreement in a representative or fiduciary capacity, has full power and authority to execute and deliver this Agreement in such capacity and on behalf of the Person for whom such Member is executing this Agreement, and such Person has full right and power to perform pursuant to this Agreement and make an investment in the Company;

 

(e)          such Member, if a natural person, has reached the age of majority in the state in which such Member resides; and

 

(f)          such Member or its adviser has had a reasonable opportunity to ask questions of and receive answers from one or more Persons on behalf of the Company concerning the offering of the Membership Interests and all such questions have been answered to the full satisfaction of such Member.

 

12.4           Indemnification . Each Member agrees to indemnify and hold harmless the Company, the Managing Member, other Members, Officers, employees, agents and Affiliates against any and all loss, liability, claim, damage and expense whatsoever (including any and all expenses reasonably incurred in investigating, preparing or defending against any litigation commenced or threatened or any claim whatsoever) arising out of or based upon any false representation or warranty or breach or failure by such Member to comply with any covenant or agreement made by such Member pursuant to this Article.

 

ARTICLE XIII

MISCELLANEOUS PROVISIONS

 

13.1           Notices . All notices, demands and other communications to be given or delivered under or by reason of the provisions of this Agreement will be delivered to the appropriate parties at the respective addresses for such parties set forth on Exhibit B hereto, unless another address is specified in writing by any such party and notice thereof is delivered to the Company and each of the other parties in accordance with this Section. Such notices, demands and other communications will be in writing and will be deemed to have been given (i) when personally delivered, (ii) when mailed by certified mail, return receipt requested, (iii) when sent by telecopy or electronic mail with confirmation of receipt received, or (iv) when delivered by overnight courier with executed receipt.

 

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13.2           Captions . The captions used in this Agreement are for convenience of reference only and do not constitute a part of this Agreement and will not be deemed to limit, characterize or in any way affect any provision of this Agreement, and all provisions of this Agreement will be enforced and construed as if no captions had been used in this Agreement.

 

13.3           Complete Agreement: Exhibits . Each exhibit delivered pursuant to this Agreement will be in writing and will constitute a part of this Agreement. This Agreement, together with such exhibits, and the Certificate constitute the complete statement of agreement with respect to the subject matter herein and therein and will supersede any prior understandings, agreements or representations, written or oral, which may have related to the subject matter hereof in any way.

 

13.4           Governing Law and Jurisdiction . The laws of the State of Delaware, without regard to conflict of law doctrines, will govern all questions concerning the construction, validity and interpretation of this Agreement and the performance of the obligations imposed by this Agreement. In any action brought to enforce a right provided hereunder, the Parties agree to submit to the exclusive jurisdiction of a federal or state court located in Hennepin County, Minnesota.

 

13.5           Waiver of Jury Trial . Each Member hereby unconditionally waives any right to a jury trial with respect to and in any action, proceeding, claim, counterclaim, demand or other matter whatsoever arising out of this Agreement.

 

13.6           Third Party Beneficiaries . Nothing in this Agreement is intended or will be construed to entitle any Person, other than the Company, the Members and their respective successors and assigns, to any claim, cause of action, remedy or right of any kind.

 

13.7           Severability . If any provision of this Agreement is declared illegal, invalid or unenforceable it will be severed if the remaining provisions of this Agreement can reasonably and fairly be given effect without affecting the legal and economic substance of the transactions contemplated by this Agreement in a manner adverse to the Company or any Member. To the full extent, however, that the provisions of such applicable law may be waived, they are hereby waived to the end that this Agreement will be deemed to be a valid and binding agreement enforceable in accordance with its terms.

 

13.8           Binding Effect . This Agreement will be binding upon and inure to the benefit of the Company, the Members and their respective successors and assigns.

 

13.9           Amendments: Waiver . This Agreement may not be amended and no provision hereof may be waived except by a written instrument signed by all of the Members. Notwithstanding the foregoing, Exhibit A and Exhibit B hereto may be amended by the Managing Member without such signatures, if such amendment is made pursuant to this Agreement.

 

13.10           Costs and Attorneys Fees . A prevailing party will be awarded attorneys’ fees and costs in any proceeding brought after the Effective Date of this Agreement to enforce or to interpret this Agreement. For purposes of this Agreement, the term “prevailing party” will be the party who is determined by a trial court judge or, if the matter is appealed, an appellate court judge, to be adjudicated to recover costs of suit, whether or not the proceeding is brought to final judgment or award. A party not entitled to recover costs will not recover attorneys’ fees. No sum of attorneys’ fees will be included in any computation of the amount of judgment or award for purposes of determining whether a party is entitled to recover costs or attorneys’ fees.

 

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13.11           Counterparts . This Agreement may be executed in two or more counterparts, each of which will be deemed an original, but all of which together will constitute one and the same instrument.

 

13.12           Confidential Information .

 

(a)          Each Member covenants and agrees that it will not at any time while it is a Member, or for a period of two (2) years thereafter, directly or indirectly use, sell or otherwise disclose Confidential Information (as defined herein) except in furtherance of the Company’s business. “ Confidential Information ” means the terms and conditions of this Agreement and the Management Agreement, financial models, market analysis, the relative or absolute rights or interests of any of the Members or other proprietary information of or regarding the Company that has not been publicly disclosed by the Managing Member. The Confidential Information will be maintained in confidence by Members using the same degree of care with which such Member employs with respect to its own confidential information, but in no event maintained with less than a reasonable standard of care. This provision does not apply to information that is presently a matter of public knowledge, which is or becomes available on a non-confidential basis from a source which is not known to be prohibited from disclosing such information or which was legally in the possession of the parties bound by this provision without obligation of confidentiality prior to disclosure by the Company or its direct and indirect subsidiaries. In the event that a Member bound by this provision is requested or required by legal or regulatory authority to disclose any Confidential Information, the affected party will promptly notify the Company of such request or requirement prior to disclosure so that the Company or other Members may seek an appropriate protective order and/or waive compliance with the terms of this Agreement. If, in the absence of a protective order or other remedy or the receipt of a waiver by such other party, the party requested or required to make the disclosure or any of its Affiliates is nonetheless, under the advice of counsel, legally required to disclose Confidential Information, the disclosing party may, without liability hereunder, disclose only that portion of the Confidential Information that such party’s counsel advises is legally required to be disclosed.

 

(b)          Each Member agrees that upon Transfer or redemption of all of its Membership Interests, such Member will immediately return to the Company all Company property, including records reflecting Confidential Information, and such Member will not take or retain (1) any records reflecting Confidential Information, or copies thereof, whether or not originated by the Company, or (2) any other Company property, including tapes or other materials. Notwithstanding the foregoing, a Member may retain copies of the Confidential Information in accordance with policies and procedures of such Member solely in order to comply with law, regulation or archival purposes; provided, however, that any Confidential Information so retained will continue to be Confidential Information pursuant to the terms of this Agreement and the retaining Member will continue to be bound by the terms of this Agreement with respect to such Confidential Information.

 

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(c)          Each Member agrees that, so long as it remains a Member and thereafter, it will not make any disparaging, uncomplimentary or negative communication, whether oral or written, about the Company to any Person, including any communication with respect to the Company’s (or its subsidiaries’ or affiliates’) products, services, business affairs or employees.

 

(d)          Each Member agrees that it would be difficult or impossible to measure the damage to the Company from any breach by it of the covenants set forth in this Section 13.12 , and that damages to the Company for any such injury would therefore be an inadequate remedy for any such breach. Accordingly, each Member agrees that if it breaches any term of this Section 13.12 , the Company will be entitled, in addition to and without limitation upon all other remedies the Company may have, to obtain injunctive or other appropriate equitable relief to restrain any such breach without showing or proving any actual damage to the Company.

 

(e)          No Member shall issue or publish any press release or other public communication about the formation, existence or operations of the Company without the approval of Merced and Black Ridge, which consent shall not be unreasonably withheld and shall be provided promptly following submission of the proposed press release or other public communication. Notwithstanding the foregoing, Black Ridge may make all required regulatory filings regarding this Agreement and the Management Services Agreement, without the consent of Merced; provided, that Black Ridge will use commercially reasonable efforts to provide Merced with an opportunity to review any Company-related disclosures contained in such filings prior to filing. The foregoing provisions shall not be deemed to prohibit any Member from disclosing summary information related to the amount of capital invested by the Company, the performance of its investment in the Company or general information about the performance of the Company or its Projects to any of its investors, prospective investors or lenders. In no event may Black Ridge disclose the dollar or percentage values of the Preferred Return, the Management Participation Interest or the compensation payable under the Management Services Agreement in any press release or other public communication and, if under the advice of counsel Black Ridge is legally required to disclose such values in a regulatory filing, Black Ridge shall use commercially reasonable efforts to seek confidential treatment thereof and shall disclose only such values that Black Ridge’s counsel advises is legally required to be disclosed.

 

[Remainder of page intentionally left blank.]

 

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IN WITNESS WHEREOF, the undersigned have signed this Agreement as of the day and year first above written.

 

MERCED OIL & GAS, LLC ,

a Delaware limited liability company

 

 

By: / s/ Thomas G. Rock

       Name: Thomas G. Rock

       Its: Authorized Signatory

 

 

BLACK RIDGE OIL & GAS INC. ,

a Nevada corporation

 

By: /s/ Ken DeCubellis

       Name: Ken DeCubellis

       Its: Chief Executive Officer

 

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Exhibit A

 

MEMBERS, CAPITAL CONTRIBUTIONS AND INTERESTS

 

As of the Effective Date

 

 

Member Capital Contribution Percentage Interest and Voting Interest Management Participation Interest
 
Merced Oil & Gas, LLC * * * 100%  
Black Ridge Oil & Gas Inc. $-0- 0%  * * *

 

 

 

 

 

 

 

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Exhibit B

 

NOTICES

 

Company and Merced :

 

c/o Merced Capital, L.P.

601 Carlson Parkway, Suite 200

Minnetonka, Minnesota 55305

Attn: General Counsel

Phone: (952) 476-7200

Fax: (952) 476-7201

Email: tom.rock@mercedcapital.com

 

 

Black Ridge :

 

c/o Black Ridge Oil & Gas Inc.

10275 Wayzata Boulevard, Suite 100

Minnetonka, MN 55305

Attn: Ken DeCubellis

Phone: (952) 426-1821

Fax: ___________________

Email: ken.decubellis@blackridgeoil.com

 

 

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EXHIBIT 10.2

 

[CONFIDENTIAL TREATMENT REQUESTED. CONFIDENTIAL PORTIONS OF THIS DOCUMENT HAVE BEEN REDACTED AND HAVE BEEN SEPARATELY FILED WITH THE COMMISSION]

 

MANAGEMENT SERVICES AGREEMENT

 

THIS MANAGEMENT SERVICES AGREEMENT (“ Agreement ”), dated to be effective as of July 21, 2015, is entered into between Black Ridge Oil & Gas Inc., a Nevada corporation (“ Black Ridge ”), and Merced Black Ridge, LLC, a Delaware limited liability company (the “ Owner ”).

 

RECITALS

 

A.          The Owner engages in the acquisition, ownership and disposition of minority, non-operator interests in parcels of land intended for oil or gas well drilling or containing oil or gas well drilling operations in the Williston Basin (the “ Projects ”); and

 

B.          The Owner desires to engage Black Ridge to act as the manager to provide sourcing, evaluation, and day-to-day management services of the Projects on the Owner’s behalf.

 

In consideration of the premises and the mutual agreements hereinafter set forth, the Owner and Black Ridge agree as provided herein:

 

ARTICLE I
DEFINITIONS

 

1.1           General Interpretive Principles . Except as otherwise expressly provided in this Agreement or unless the context otherwise requires, (i) the terms defined in this Article will have the meanings assigned to them in this Article and will include the plural as well as the singular, (ii) the use of any gender in this Agreement will be deemed to include the other gender and (iii) the word “including” means “including, but not limited to.”

 

1.2           Defined Terms . As used in this Agreement, the following terms have the following meanings:

 

Affiliate ” means any Person directly or indirectly Controlling, Controlled by, or under Common Control of such other Person.

 

Bad Act ” is defined in Section 7.2.1 .

 

Black Ridge ” is defined in the Preamble.

 

Confidential Information ” is defined in Section 9.1.1 .

 

Control ” (including the correlative terms “Controlling”, “Controlled by” and “under Common Control with”) means possession, directly or indirectly, of the power to direct or cause the direction of management or policies (whether through ownership of securities or any partnership or other ownership interest, by contract or otherwise) of a Person. Without limiting the effect of the preceding sentence, control will be deemed to exist (but will not be limited to) when a Person possesses, directly or indirectly, through one or more intermediaries (i) in the case of a corporation, 50 percent or more of the outstanding voting securities thereof; (ii) in the case of a limited liability company, partnership, limited partnership or venture, the right to 50 percent or more of the distributions therefrom (including liquidating distributions); or (iii) in the case of any other Person, 50 percent or more of the economic or beneficial interest therein.

 

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Direct Expenses ” means all third-party costs incurred by Black Ridge that are directly attributable to providing the Management Services pursuant to this Agreement.

 

Disclosing Party ” is defined in Section 9.1.1 .

 

LOE ” means lease operating expenses charged by operators of Projects to Owner.

 

Management Services ” is defined in Section 2.1 .

 

Operating Account ” means a separate bank account established with a financial institution in the name of, and owned by, the Owner, for which the Owner will provide the requisite funds pursuant to a budget agreed upon by the Owner and Black Ridge.

 

Owner ” is defined in the Preamble.

 

Owner Operating Agreement ” is defined in Section 7.3.1 .

 

Project ” is defined in the Recitals.

 

Receiving Party ” is defined in Section 9.1.1 .

 

Revenue Account ” is defined in Section 2.1.4 .

 

ARTICLE II
MANAGEMENT SERVICES

 

2.1 Services to be Provided . The Owner hereby retains Black Ridge to perform the following services (the “ Management Services ”):
2.1.1. Locate, investigate and analyze potential Project acquisition opportunities for the Owner, and, on approval of the Owner, negotiate the acquisition of Projects from well operators or other third parties.
2.1.2. Coordinate the closing and funding of Project acquisitions and, following the making of such acquisitions, oversee the management and operation of the Projects, and keep the Owner informed of the progress thereof.
2.1.3. Upon receipt of any notice regarding an Authorization for Expenditure (“ AFE ”) for a Project, review the AFE and all supporting documentation, provide Owner with a timely recommendation as to whether Owner should participate in such AFE and coordinate Owner’s response to such AFE. Coordinate payments from Owner’s Operating Account for AFE, Direct Expenses and LOE.
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2.1.4. Upon receipt of any payments with respect to the Projects, promptly deposit such payments into a bank account (the “ Revenue Account ”) established with a financial institution in the name of, and owned by, the Owner.
2.1.5. Maintain books of account with respect to all Projects, and provide such reports and financial information with respect to such Projects as are reasonably requested by the Owner.
2.1.6. Perform such other functions related to the matters set forth above as may be authorized by the Owner from time to time, consistent with the provisions of the Owner Operating Agreement.
2.1.7. Coordinate procurement of well control coverage insurance and such other insurance as from time to time approved by the Owner for the Projects.
2.2 Standard of Care . In performing its duties and obligations under this Agreement, Black Ridge will act in a commercially reasonable manner and comply in all material respects with all applicable federal, state, and local laws and regulations, and will exercise that degree of skill and care consistent with the degree of skill and care customarily exercised in the industry with respect to assets similar to the Projects, and that is consistent with prudent industry standards.
2.3 Licensing . In performing its duties and obligations hereunder, Black Ridge will maintain all state and federal licenses, permits and regulatory approvals necessary and appropriate for it to perform its responsibilities hereunder, and will not impair the rights of the Owner in the Projects.
2.4 Reporting .
2.4.1. On or before the fifteenth (15 th ) day of each month, Black Ridge will provide the Owner the following detailed monthly reports for the preceding month:

    (i) Cash reconciliation, including reconciliation of the Operating Account and Revenue Account and substantiation of Servicing Fees payable pursuant to Section 3.1 ;
       
    (ii) Direct Expenses, AFE and LOE report setting forth, on a line-item basis for each Project, the Direct Expenses, AFE and LOE incurred during the prior month.

 

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2.4.2. Black Ridge shall allocate Direct Expenses incurred related to multiple Projects on a reasonable allocation basis and report such method of allocation to the Owner.
2.4.3. Black Ridge will maintain on Dropbox (or a similar virtual data site), and make available to the Owner at all times through the life of each Project, all documentation and information received or created by Black Ridge with respect to each Project including AFE history and communications. Upon termination of this Agreement, Black Ridge will transfer to Owner all information maintained on Dropbox (or a similar virtual data site) related to the Projects.
2.4.4. Black Ridge will provide (i) within forty-five (45) days after the end of each interim quarterly accounting period of Black Ridge, unaudited financial statements of Black Ridge for such period; and (ii) within ninety (90) days after the end of each fiscal year of Black Ridge, audited financial statements of Black Ridge for such fiscal year. To the extent Black Ridge makes such financial statements publicly available on EDGAR, the timely filing of such statements will be deemed to satisfy the requirements of this paragraph.
2.4.5. Black Ridge will provide additional reporting and information as reasonably requested by the Owner.
2.4.6. Black Ridge will promptly respond to all inquiries from the Owner.
2.5 Regulatory and Tax Matters.
2.5.1. Black Ridge will cause the Owner to execute and file punctually all forms and reports regarding the ownership and operation of the Projects that are required by law or regulation.
2.5.2. Black Ridge will provide year-end tax statements as may be required by state and federal laws, including Forms 1098 and 1099. Any third party expenses related to such tax statements will be paid by the Owner.
2.5.3. Black Ridge will coordinate filings and cause the Owner to pay real or personal property taxes to the extent necessary to protect the Projects.
2.6 * * *

 

_______________

* * * Confidential Information has been omitted and filed separately with the Securities and Exchange Commission. Confidential treatment has been requested with respect to this omitted information.

 

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ARTICLE III
MANAGEMENT FEES AND EXPENSES

 

3.1 Management Fees . Subject to Section 7.4 , as compensation for the full performance of its obligations hereunder, Black Ridge will be paid the fees in the amounts and at the times set forth on Schedule 3.1 hereto (the “ Servicing Fees ”), as such schedule may be amended from time to time by written agreement of the parties.
3.2 Expenses .
3.2.1. Black Ridge may request that the Owner pay all Direct Expenses from the Operating Account to the extent reflected in a budget agreed upon by the Owner and Black Ridge for each Project or as otherwise set forth in this Agreement. Black Ridge may request that the Owner pay all AFE and LOE for each Project from the Operating Account once the Owner has agreed to participate in an AFE for a Project. Black Ridge will (i) collect invoices from operators and third parties, (ii) review such invoices for accuracy and completeness, (iii) request that the Owner process and pay such invoices according to generally accepted accounting principles and such other controls agreed upon by Black Ridge and the Owner, and (iv) report such Direct Expenses, AFE and LOE to the Owner through monthly reports.
3.2.2. Any authorized fees and Direct Expenses advanced by Black Ridge and not paid from the applicable Operating Account will be billed monthly by Black Ridge to the Owner. Black Ridge will provide the Owner with invoices and other information reasonably satisfactory to the Owner to substantiate the amount of Direct Expenses that Black Ridge has incurred.
3.2.3. All Direct Expenses, AFE and LOE will be paid without mark-up.
3.2.4. All costs and obligations that Black Ridge incurs that are related to its overhead or the compensation of its employees will be the sole responsibility of Black Ridge.

ARTICLE IV
REPRESENTATIONS AND WARRANTIES

 

4.1 Representations and Warranties of the Owner and Black Ridge . The Owner and Black Ridge each make the following representations and warranties to each other as of the date of this Agreement and each is entitled to rely on such representations and warranties. The representations and warranties set forth in this Article IV are continuous and will survive the termination or expiration of this Agreement, unless otherwise agreed to in writing by the parties.
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4.1.1. It is now and will continue at all times to be duly organized, validly existing, and in good standing under the laws of the jurisdiction of its organization and has the power to own its assets and to transact the business in which it is currently engaged. It is duly qualified to do business as a foreign entity and is in good standing in each jurisdiction in which it is required by law and the character of the business transacted by it or properties owned or leased by it requires such qualification and in which the failure to be so qualified would have a material adverse effect on its business, properties, assets or condition (financial or otherwise).
4.1.2. It has the power and authority to make, execute, deliver, and perform its responsibilities and obligations under this Agreement and all of the transactions contemplated under this Agreement.
4.1.3. It is not required to obtain the prior consent of any agency in connection with the execution, delivery, or performance of this Agreement.
4.1.4. The execution, delivery and performance of this Agreement will not violate any provision of any existing law or regulation or any order or decree of any court that would have a material adverse effect on its business, properties, assets or condition (financial or otherwise) or the certificate of incorporation or bylaws (or similar documents such as partnership or operating agreement, if applicable) of the entity, or constitute a material breach of any deed to secure debt, mortgage, indenture, contract or other agreement to which it is a party or by which it may be bound.
4.1.5. The execution and delivery of this Agreement by it, and the performance by it of its obligations hereunder, have been duly authorized by all necessary company actions. This Agreement has been duly executed and delivered by it and constitutes its legal, valid and binding obligation, enforceable against it in accordance with its terms, subject to applicable bankruptcy, insolvency and similar laws affecting creditors’ rights generally and to general principles of equity (whether considered in a proceeding in equity or at law).
4.1.6. There is no litigation or administrative proceeding of or before any court, tribunal, or governmental body that is currently pending, or, to its knowledge, threatened against it or any of its properties or with respect to this Agreement, which, if adversely determined, would reasonably be expected to adversely affect the transactions contemplated by this Agreement.
4.2 Representations and Warranties of Black Ridge . Black Ridge makes the following representations and warranties to the Owner as of the date of this Agreement and the Owner is entitled to rely on such representations and warranties. The representations and warranties set forth in this Article IV are continuous and will survive the termination or expiration of this Agreement, unless otherwise agreed to in writing by the parties.
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4.2.1. It is duly registered and licensed and will continue to be registered and licensed as required by the law of each state in which the Projects are located, or in which its actions or status may otherwise require. In addition, it is in possession of all licenses, approvals, or authorizations from, or registration or declaration with, any governmental authority, bureau or agency necessary to perform its responsibilities and obligations under this Agreement. This representation and warranty is subject to the terms contained in Section 2.2 of this Agreement.
4.2.2. It is not subject to any obligation to any third party that will prevent it from submitting any opportunity to the Owner to acquire one or more Projects pursuant to the terms of Section 2.6 .

ARTICLE V
INSPECTION AND AUDIT

 

The Owner reserves the right, at any time during normal business hours and upon not less than three days’ prior notice where practicable, at the Owner’s expense, to inspect and audit any and all books, ledgers, files and records maintained by Black Ridge in connection with the performance of its obligations under this Agreement. Black Ridge will make available for review and inspection by the Owner copies of all books, ledgers, files and records that pertain to a particular Project or that will enable the Owner to determine the status of each Project promptly upon request by the Owner. Such documents will be maintained by Black Ridge in accordance with generally accepted accounting principles, consistently applied. To the extent practicable, Black Ridge will make the books of account and other records available to the Owner electronically.

 

ARTICLE VI
INSURANCE

 

Upon request of the Owner, Black Ridge will submit to Owner quotes for the premiums of (i) an errors and omissions policy of insurance and/or (ii) employee fidelity insurance coverage, from such insurers and in such amounts as approved by the Owner in its sole discretion. At the election of Owner in its sole discretion, Black Ridge shall obtain (i) an errors and omissions policy of insurance and/or (ii) employee fidelity insurance coverage consistent with such premium quotes and the costs for such insurance shall be considered a Direct Expense. If such insurance is obtained upon the request of the Owner, Black Ridge will cause to be delivered to the Owner a certificate of insurance for such bond and insurance policies naming the Owner as an additional insured party to the extent of the Projects managed by Black Ridge and a statement from the surety and the insurer that such bond and insurance policies shall in no event be terminated or materially modified without thirty (30) days’ prior written notice to the Owner.

 

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ARTICLE VII
TERMINATION; REMOVAL

 

7.1 Termination for Convenience . Either party to this Agreement may terminate this Agreement by providing the other party with 90 days’ advance written notice.
7.2 Termination for Cause .
7.2.1. Either party may terminate this Agreement immediately due to any of the following actions by or events regarding the other party: (i) filing a voluntary petition in bankruptcy; (ii) being adjudicated bankrupt or insolvent; (iii) filing a petition or answer seeking any reorganization, arrangement, composition, readjustment, liquidation, dissolution or similar relief under any present or future statute or law relating to bankruptcy, insolvency or other relief for debtors, whether federal or state (hereinafter, a “reorganization”); (iv) entry by a court of competent jurisdiction of an order, judgment or decree approving a petition seeking a reorganization, to which the other party consents or acquiesces (as hereinafter defined) or such order, judgment or decree remains unvacated or unstayed for an aggregate period of 60 days from the date of entry thereof; (v) seeking, consenting to or acquiescing in the appointment of a trustee, receiver, conservator or liquidator of or for all or any substantial part of its assets; or (vi) entry by a court of competent jurisdiction of an order, judgment or decree finding that the other party or its Affiliates (or an admission that such party or Affiliate) engaged in gross negligence, willful misconduct, fraud, bad faith or any criminal activity in connection with the subject matter of this Agreement (each of the matters listed in this clause (vi), a “ Bad Act ”). As used herein, “ acquiesces ” or “ acquiescing ” includes the failure to file a petition or motion to vacate or discharge any order, judgment or decree providing for the appointment of a trustee, receiver, conservator or liquidator within the time specified by law.
7.2.2. In addition, the Owner may terminate this Agreement (i) immediately upon written notice to Black Ridge if Black Ridge liquidates, dissolves, terminates or suspends its business operations or otherwise fails to operate its business within the ordinary course, or sells all or substantially all of its assets; (ii) immediately upon written notice to Black Ridge if any representation, warranty or statement of Black Ridge made in this Agreement, or in any written certificate or report delivered by Black Ridge to the Owner in the course of providing the Management Services, (A) proves to be incorrect in any material respect as of the date made and (B) with respect to a representation, warranty or statement in a written certificate or report delivered by Black Ridge, the Owner reasonably relies to its material detriment upon such representation, warranty or statement; or (iii) within 30 days of written notice to Black Ridge of Black Ridge’s failure to perform any of its Management Services or fulfill any covenant hereunder in the manner or within the time required under this Agreement, which failure remains uncured after such 30-day period.
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7.3 Effect of Termination .
7.3.1. Payment of Servicing Fees. Black Ridge will be entitled to * * *. With respect to the “Management Participation Interest” (as such term is defined in the Limited Liability Company Agreement of the Owner (the “ Owner Operating Agreement ”)) of Black Ridge, the effect of any termination of this Agreement on such Management Participation Interest will be as set forth in the Owner Operating Agreement.
7.3.2. Termination for any reason will not release either party from any liability or obligation that has already accrued as of the effective date of such termination, or that expressly survives termination of this Agreement, and will not constitute a waiver or release of, or otherwise be deemed to prejudice or adversely affect, any rights, remedies or claims that a party may have under this Agreement or that may arise out of or in connection with such termination.
7.4 Appointment of Replacement Manager . Upon the occurrence of any event described in Section 7.2.2 , the Owner may elect, in its sole discretion and without prejudice to Owner’s right to terminate this Agreement as a result of such event or otherwise, to continue this Agreement and appoint one or more replacement managers to manage the Projects and provide the Management Services hereunder. Selection of any such replacement manager, and the terms and conditions or such replacement manager’s appointment, will be in Owner’s sole discretion and, provided that the replacement manager is a third party and not an Affiliate of the Owner, the Owner will be entitled to offset any fees paid to the replacement manager against any Servicing Fees payable to Black Ridge hereunder.
7.5 Transition. Upon termination of this Agreement or appointment of a replacement manager, the Owner and Black Ridge will cooperate fully in connection with the transfer of servicing responsibilities.
7.6 Survival . The provisions of Article I (Definitions), Article IV (Representations and Warranties), Article V (Inspection and Audit), Article VII (Termination and Removal), Article VIII (Indemnification) and Sections 2.4.2 (Virtual Access to Records), 9.1 (Confidentiality), 9.2 (Dispute Resolution; Venue), 9.3 (Governing Law), 9.5 (Entire Agreement; Severability), 9.10 (No Waiver) and 9.11 (Notices) will survive any termination of this Agreement.

 

ARTICLE VIII
INDEMNIFICATION

 

8.1 Indemnification by Black Ridge . Black Ridge will indemnify and defend the Owner, its directors, officers, employees, managers, equity holders, and agents and hold them harmless from and against any liability, damage, penalty, fee, cost, expense or obligation (including reasonable attorneys’ fees and disbursements) arising from any breach of this Agreement by Black Ridge or from any other action or omission by Black Ridge in the performance of its duties hereunder, if such action or omission constitutes gross negligence, recklessness or misconduct on the part of Black Ridge.
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8.2 Indemnification by the Owner . The Owner will indemnify and defend Black Ridge, its directors, officers, employees and agents and hold them harmless from and against any liability, damage, penalty, fee, cost, expense or obligation (including reasonable attorneys’ fees and disbursements) arising from any breach of this Agreement by the Owner or from any other action or omission by the Owner in the performance of its duties hereunder, if such action or omission constitutes gross negligence, recklessness or misconduct on the part of the Owner.
8.3 Limitation of Liability . Notwithstanding anything in this Agreement to the contrary, neither party will have any liability to the other party for any special, consequential or punitive damages.
8.4 Third Party Claims . Black Ridge will immediately notify the Owner if a claim is made by a third party with respect to (i) this Agreement, (ii) any matter arising from the Management Services, or (iii) any Project that is the subject of this Agreement. Black Ridge will propose counsel to defend any such claim and the Owner will have the right to approve such counsel or direct Black Ridge to retain counsel of the Owner’s choosing. The Owner will pay all expenses in connection with the defense of such claim, including counsel fees, and promptly pay, discharge and satisfy any judgment or decree which may be entered in respect of such claim, except when the claim results from Black Ridge’s negligence, misconduct or recklessness.

ARTICLE IX
MISCELLANEOUS

9.1 Confidentiality .
9.1.1. Black Ridge covenants and agrees that it will not at any time during the term of this Agreement, or for a period of two (2) years thereafter, directly or indirectly use, sell or otherwise disclose Confidential Information (as defined below) of the other party except in connection with the Management Services and the Projects. For purposes of this Agreement, “ Confidential Information ” means all nonpublic or proprietary information disclosed by the Company to Black Ridge or its Affiliates, other than information that Black Ridge can demonstrate (i) is presently a matter of public knowledge, (ii) is or becomes available on a non-confidential basis from a source that is not known to be prohibited from disclosing such information or (iii) was legally in the possession of the parties bound by this provision without obligation of confidentiality prior to disclosure by the Owner or its Managing Member. The Confidential Information will be maintained in confidence by Black Ridge using the same degree of care with which Black Ridge employs with respect to its own confidential information, but in no event maintained with less than a reasonable standard of care. In the event that Black Ridge is requested or required by legal or regulatory authority to disclose any Confidential Information, Black Ridge will promptly notify the Owner of such request or requirement prior to disclosure so that the Owner may seek an appropriate protective order or waive compliance with the terms of this Agreement. If, in the absence of a protective order or other remedy or the receipt of a waiver by the Owner, Black Ridge or any of its Affiliates is nonetheless, under the advice of counsel, legally required to disclose Confidential Information, Black Ridge may, without liability hereunder, disclose only that portion of the Confidential Information that Black Ridge’s counsel advises is legally required to be disclosed.
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9.1.2. Black Ridge agrees that upon termination of this Agreement, it will immediately return to the Owner all documents and materials constituting or containing Confidential Information of the Owner, and Black Ridge will not take or retain any records reflecting Confidential Information of the Owner, or copies thereof, whether or not originated by Black Ridge. Notwithstanding the foregoing, Black Ridge may retain copies of the Owner’s Confidential Information in accordance with policies and procedures of Black Ridge solely in order to comply with law, regulation or archival purposes; provided, however, that any Confidential Information so retained will continue to be Confidential Information pursuant to the terms of this Agreement and Black Ridge will continue to be bound by the terms of this Agreement with respect to such Confidential Information.
9.1.3. Black Ridge agrees that it would be difficult or impossible to measure the damage to the Owner from any breach by it of the covenants set forth in this Section 9.1 , and that damages to the Owner for any such injury would therefore be an inadequate remedy for any such breach. Accordingly, Black Ridge agrees that if it breaches any term of this Section 9.1 , the Owner will be entitled, in addition to and without limitation upon all other remedies it may have, to obtain injunctive or other appropriate equitable relief to restrain any such breach without showing or proving any actual damage to the Owner.
9.1.4. Black Ridge, on behalf of itself and its respective Affiliates, hereby waives the right to seek any equitable relief in connection with a breach by the Owner of its obligations hereunder or otherwise in connection with the Management Services, including, without limitation, any rights of rescission and the right to seek injunctive relief, it being acknowledged by Black Ridge that the right to seek actual damages shall constitute its sole and exclusive remedy for such breach, and is fully adequate to compensate Black Ridge for same.
9.1.5. Under this Agreement, the Owner may become privy to information that is considered material inside information about Black Ridge within the meaning and intent of applicable securities laws and the rules and regulations promulgated thereunder. The Owner shall not use any of such information, and shall direct each of its Affiliates to whom such information is disclosed not to use any of such information, directly or indirectly, as a basis for any decision to buy, sell or otherwise deal in any securities in a manner prohibited by U.S. law.
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9.1.6. Neither the Owner nor Black Ridge shall issue or publish any press release or other public communication about the formation, existence or operations of the Owner without the approval of the Owner and Black Ridge, which consent shall not be unreasonably withheld and shall be provided promptly following submission of the proposed press release or other public communication. Notwithstanding the foregoing, Black Ridge may make all required regulatory filings regarding this Agreement and the Owner Operating Agreement, without the consent of Owner; provided, that Black Ridge will use commercially reasonable efforts to provide the Owner with an opportunity to review any Owner-related disclosures contained in such filings prior to filing. The foregoing provisions shall not be deemed to prohibit Black Ridge or the Owner from disclosing summary information related to the amount of capital invested in the Owner, the performance of the Owner or general information about the performance of the Owner or its Projects to any of its investors, prospective investors or lenders. In no event may Black Ridge disclose the dollar or percentage values of the “Preferred Return” or the “Management Participation Interest” (as such terms are defined in the Owner Operating Agreement) or the compensation payable under this Agreement in any press release or other public communication and, if under the advice of counsel Black Ridge is legally required to disclose such values in a regulatory filing, Black Ridge shall use commercially reasonable efforts to seek confidential treatment thereof and shall disclose only such values that Black Ridge’s counsel advises is legally required to be disclosed.
9.2 Dispute Resolution . Any claim or dispute arising out of or in connection with this Agreement will be resolved solely though the following procedures:
9.2.1. The parties will attempt in good faith to resolve any dispute arising out of or relating to this Agreement promptly through negotiation. Either party may give the other party written notice of any dispute not resolved in the normal course of business. Within five (5) business days after receipt of such notice, the parties are required to meet personally at a mutually acceptable time and place to attempt to resolve the dispute. Each party’s right pursuant to Section 9.1.3 to obtain equitable relief shall not be subject to this Section 9.2.1 .
9.2.2. Absent resolution pursuant to Section 9.2.1 , the parties hereby submit all controversies, claims and matters of difference arising under this Agreement to any court of competent jurisdiction in Minneapolis, Minnesota.
9.2.3. To the fullest extent permitted by law, each party unconditionally waives any objection to the laying of venue of any such action brought in any such court, and any claim that any such action has been brought in an inconvenient forum.
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9.2.4. Each party irrevocably agrees to waive trial by jury in any action, proceeding, claim or counterclaim brought by or on behalf of either party related to or arising out of this Agreement or the performance of Management Services hereunder.
9.3 Governing Law . The validity, construction and enforceability of this Agreement will be governed and constructed in accordance with the laws of the State of Minnesota, without regard to its principles of conflicts of law.
9.4 Force Majeure . Notwithstanding anything in this Agreement to the contrary, Black Ridge will not be liable to the Owner, and the Owner will not be liable to Black Ridge, for any delay or failure to perform any of its obligations hereunder due to an act of God, war (whether declared or undeclared), riot, civil commotion, fire, casualty, strike, boycott, labor dispute, act of any federal, state or local authority, or for any other similar reason beyond its reasonable control.
9.5 Entire Agreement; Severability . The terms and conditions contained in this Agreement constitute the entire agreement between the parties hereto with regard to the subject matter hereof and supersede all previous agreements and understandings, whether oral or written, between the parties with respect thereto. No amendment to this Agreement is binding upon any party unless set forth in a written document which expressly refers to this Agreement and which is signed and delivered by both parties hereto. If any provision of this Agreement is held invalid, illegal or unenforceable, it will be severed if the remaining provisions of this Agreement can reasonably and fairly be given effect without affecting the legal and economic substance of the transactions contemplated by this Agreement in a manner adverse to either party. To the full extent, however, that the provisions of such applicable law may be waived, they are hereby waived to the end that this Agreement will be deemed to be a valid and binding agreement enforceable in accordance with its terms.
9.6 Independent Contractor . The parties are independent contractors. Nothing contained in this Agreement or done pursuant to this Agreement will cause either party to be deemed the agent, partner, or joint venturer of the other party for any purpose.
9.7 Counterparts; Electronic Delivery . This Agreement may be executed in any number of counterparts, each counterpart constituting an original instrument, and all such separate counterparts will constitute only one and the same instrument. Delivery of an executed counterpart of a signature page to this Agreement by facsimile, electronic mail or other electronic transmission is effective as delivery of an original executed counterpart of this Agreement.
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9.8 Assignment . This Agreement will inure to the benefit of and be binding upon the successors and assigns of the parties hereto. Black Ridge may not assign, transfer or delegate its rights or obligations hereunder (including in each case by operation of law), in whole or in part, without the Owner’s prior written consent. The Owner may not assign, transfer or delegate its rights and obligations hereunder (including in each case by operation of law), in whole or in part, without Black Ridge’s prior written consent, provided that the Owner may assign its rights and obligations hereunder to any of its Affiliates with prior written notice to Black Ridge. Any purported assignment, transfer or delegation in violation of the foregoing will be null and void. Further, any assignment will not relieve the assigning party of its obligations of confidentiality hereunder.
9.9 Amendments . This Agreement may be amended from time to time by the further agreement of the parties hereto in a writing signed by both parties.
9.10 No Waiver . The failure by a party to exercise or any delay in exercising any right under this Agreement or by law does not constitute a waiver of the right or remedy or a waiver of other rights or remedies. Further, a party’s waiver of any right under this Agreement shall not constitute an ongoing waiver of such right.
9.11 Notices . All notices, demands or other communications required or permitted to be given under or by reason of the provisions of this Agreement will be delivered to the appropriate parties at the respective addresses for such parties set forth below, unless another address is specified in writing by any such party and notice thereof is delivered to the other party in accordance with this Section. Such notices, demands and other communications will be in writing and will be deemed to have been given (i) when personally delivered, (ii) when mailed by certified mail, return receipt requested, (iii) when sent by electronic mail with confirmation of receipt received, or (iv) when delivered by overnight courier with executed receipt, addressed as follows:
  Owner

Merced Black Ridge, LLC

c/o Merced Capital, L.P.

Attn: General Counsel

601 Carlson Parkway, Suite 200

Minnetonka, MN 55331

Telephone: (952) 476-7200

Email: tom.rock@mercedcapital.com

 

  Black Ridge

Black Ridge Oil & Gas Inc.

Attn: Chief Executive Officer

10275 Wayzata Boulevard, Suite 100

Minnetonka, MN 55305

Telephone: (952) 426-1821

Email: ken.decubellis@blackridgeoil.com

 

[Remainder of page intentionally left blank.]

 

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IN WITNESS WHEREOF, the parties hereto have executed this Agreement as of the day and year first above written.

 

BLACK RIDGE:

 

BLACK RIDGE OIL & GAS INC.

 

 

By: /s/ Ken DeCubellis

Name: Ken DeCubellis

Title: Chief Executive Officer

 

 

OWNER:

 

MERCED BLACK RIDGE, LLC

 

By: /s/ Thomas G. Rock

Name: Thomas G. Rock

Title: Authorized Signatory

 

 

 

 

 

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SCHEDULE 3.1

SERVICING FEES

 

Black Ridge will be paid the following fees pursuant to the terms of the Agreement:

 

1. * * *.
2. * * *.
3. * * *.

For purposes of clarity, nothing in this Agreement shall obligate the Owner to acquire any number of Projects or to make a minimum investment in Project acquisitions.

 

 

___________________

* * * Confidential Information has been omitted and filed separately with the Securities and Exchange Commission. Confidential treatment has been requested with respect to this omitted information.

 

 

 

16

EXHIBIT 31.1

CERTIFICATION

 

I, Kenneth DeCubellis, certify that:

 

1. I have reviewed this quarterly report on Form 10-Q for the fiscal quarter ended September 30, 2015 of Black Ridge Oil & Gas, Inc.;

 

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

 

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

 

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

 

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

 

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

 

c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

 

d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting.

 

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

 

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

 

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the small business issuer’s internal control over financial reporting.

 

Dated: November 13, 2015

 

 

/s/ Kenneth DeCubellis                         

Kenneth DeCubellis, Chief Executive Officer

(Principal Executive Officer)

 

 

EXHIBIT 31.2

CERTIFICATION

 

I, James A. Moe, certify that:

 

1. I have reviewed this quarterly report on Form 10-Q for the fiscal quarter ended September 30, 2015 of Black Ridge Oil & Gas, Inc.;

 

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

 

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

 

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

 

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

 

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

 

c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

 

d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting.

 

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

 

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

 

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the small business issuer’s internal control over financial reporting.

 

Date: November 13, 2015

 

 

/s/ James A. Moe                      

James A. Moe, Chief Financial Officer

(Principal Financial Officer)

Exhibit 32.1

 

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

 

In connection with the Quarterly Report of Black Ridge Oil & Gas, Inc. (the “Company”) on Form 10-Q for the period ending September 30, 2015 (the “Report”) I, Kenneth DeCubellis, Chief Executive Officer of the Company, certify, pursuant to 18 USC Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge and belief:

 

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

 

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

 

Dated: November 13, 2015

 

 

/s/ Kenneth DeCubellis                    

Kenneth DeCubellis, Chief Executive Officer

 

This certification accompanies the Report pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 and shall not, except to the extent required by the Sarbanes-Oxley Act of 2002, be deemed filed by the Company for purposes of Section 18 of the Securities Exchange Act of 1934, as amended.

 

Exhibit 32.2

 

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

 

In connection with the Quarterly Report of Black Ridge Oil & Gas, Inc. (the “Company”) on Form 10-Q for the period ending September 30, 2015 (the “Report”) I, James A. Moe, Chief Financial Officer of the Company, certify, pursuant to 18 USC Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge and belief:

 

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

 

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

 

Dated: November 13, 2015

 

/s/ James A. Moe                 

James A. Moe, Chief Financial Officer

 

This certification accompanies the Report pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 and shall not, except to the extent required by the Sarbanes-Oxley Act of 2002, be deemed filed by the Company for purposes of Section 18 of the Securities Exchange Act of 1934, as amended.