UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 

FORM 10-Q

(Mark One)

 

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

 

For Quarterly Period Ended March 31, 2016

or

 

[_] TRANSITION REPORT UNDER SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934

 

For the Transition period from _______________ to ______________

 

Commission File Number 000-53952

 

(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)

 

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

 

 

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

 

Yes   [X] 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   [X] 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 [X]

 

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

 

Yes   [_] No   [X]

 

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

 

The number of shares of registrant’s common stock outstanding as of May 12, 2016 was 47,979,990.

 

 

   
 

 

TABLE OF CONTENTS

 

PART I - FINANCIAL INFORMATION  
   
ITEM 1.   FINANCIAL STATEMENTS (Unaudited)  
       
    Condensed Balance Sheets as of March 31, 2016 (Unaudited) and December 31, 2015 3
       
    Unaudited Condensed Statements of Operations for the Three Months Ended March 31, 2016 and 2015 4
       
    Unaudited Condensed Statements of Cash Flows for the Three Months Ended March 31, 2016 and 2015 5
       
    Notes to the Condensed Financial Statements (Unaudited) 6
       
ITEM 2.   MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 25
       
ITEM 3.   QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK 39
       
ITEM 4.   CONTROLS AND PROCEDURES 39
       
PART II - OTHER INFORMATION  
   
ITEM 1.   Legal Proceedings 40
       
ITEM 1A.   RISK FACTORS 40
       
ITEM 2.   UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS 40
       
ITEM 3.   DEFAULTS UPON SENIOR SECURITIES 40
       
ITEM 4.   MINE SAFETY DISCLOSURES 40
       
ITEM 5.   OTHER INFORMATION 40
       
ITEM 6.   EXHIBITS 40
       
    SIGNATURES 41

 

 

 2 
 

 

PART I – FINANCIAL INFORMATION

 

ITEM 1. FINANCIAL STATEMENTS.

 

BLACK RIDGE OIL & GAS, INC.

CONDENSED BALANCE SHEETS

 

   March 31,   December 31, 
   2016   2015 
ASSETS   (Unaudited)       
           
Current assets:          
Assets held for sale  $6,682,084   $6,457,840 
Total current assets   6,682,084    6,457,840 
           
Property and equipment:          
Property and equipment   139,004    139,004 
Less, accumulated depreciation, amortization, depletion and allowance for impairment   (101,742)   (97,857)
Total property and equipment, net   37,262    41,147 
           
Assets held for sale, long term   25,479,212    31,808,230 
           
Total assets  $32,198,558   $38,307,217 
           
           
LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT)          
           
Current liabilities:          
Liabilities held for sale  $69,913,486   $68,312,897 
Total current liabilities   69,913,486    68,312,897 
           
Liabilities held for sale, long term   416,530    368,089 
           
Total liabilities   70,330,016    68,680,986 
           
Commitments and contingencies (See note 17)        
           
Stockholders' equity (deficit):          
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   34,433,238    34,275,414 
Accumulated deficit   (72,612,676)   (64,697,163)
Total stockholders' equity (deficit)   (38,131,458)   (30,373,769)
           
Total liabilities and stockholders' equity (deficit)  $32,198,558   $38,307,217 

 

See accompanying notes to financial statements.

 

 

 3 
 

 

BLACK RIDGE OIL & GAS, INC.

CONDENSED STATEMENTS OF OPERATIONS

(Unaudited)

 

   For the Three Months 
   Ended March 31, 
   2016   2015 
Oil and gas sales  $2,662,555   $2,886,456 
Gain (loss) on settled derivatives       1,133,421 
Gain (loss) on the mark-to-market of derivatives   (15,887)   367,329 
Total revenues   2,646,668    4,387,206 
           
Operating expenses:          
Production expenses   747,757    989,857 
Production taxes   275,948    286,192 
General and administrative   850,308    810,008 
Depletion of oil and gas properties   2,022,504    2,630,032 
Impairment of oil and natural gas properties   5,219,000     
Accretion of discount on asset retirement obligations   8,133    7,929 
Depreciation and amortization   3,885    4,267 
Total operating expenses   9,127,535    4,728,285 
           
Net operating loss   (6,480,867)   (341,079)
           
Other income (expense):          
Interest (expense)   (1,434,646)   (1,567,248)
Total other income (expense)   (1,434,646)   (1,567,248)
           
Loss before provision for income taxes   (7,915,513)   (1,908,327)
           
Provision for income taxes       635,391 
           
Net loss  $(7,915,513)  $(1,272,936)
           
Weighted average common shares outstanding - basic   47,979,990    47,979,990 
Weighted average common shares outstanding - fully diluted   47,979,990    47,979,990 
           
Net loss per common share - basic  $(0.16)  $(0.03)
Net loss per common share - fully diluted  $(0.16)  $(0.03)

 

See accompanying notes to financial statements.

 

 4 
 

 

BLACK RIDGE OIL & GAS, INC.

CONDENSED STATEMENTS OF CASH FLOWS

(Unaudited)

 

   For the Three Months 
   Ended March 31, 
   2016   2015 
CASH FLOWS FROM OPERATING ACTIVITIES          
Net loss  $(7,915,513)  $(1,272,936)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:          
Depletion of oil and gas properties   2,022,504    2,630,032 
Depreciation and amortization   3,885    4,267 
Amortization of debt issuance costs       96,322 
Accretion of discount on asset retirement obligations   8,133    7,929 
(Gain) loss on the mark-to-market of derivatives   15,887    (367,329)
Accrued payment in kind interest applied to long term debt   330,740    314,114 
Amortization of original issue discount on debt       42,399 
Amortization of debt discounts, warrants       160,428 
Common stock options issued to employees and directors   157,824    160,924 
Deferred income taxes       (635,391)
Impairment of oil and natural gas properties   5,219,000     
Decrease (increase) in current assets:          
Accounts receivable   (189,982)   2,319,941 
Prepaid expenses   (18,013)   3,144 
Increase (decrease) in current liabilities:          
Accounts payable   89,466    110,460 
Accrued expenses   17,686    10,981 
Net cash provided by (used in) operating activities   (258,383)   3,585,285 
           
CASH FLOWS FROM INVESTING ACTIVITIES          
Proceeds from sale of oil and gas properties       99,000 
Purchases of oil and gas properties and development capital expenditures   (1,149,789)   (7,031,186)
Net cash used in investing activities   (1,149,789)   (6,932,186)
           
CASH FLOWS FROM FINANCING ACTIVITIES          
Advances from revolving credit facilities and long term debt   2,050,000    5,700,000 
Repayments on revolving credit facilities   (650,000)   (2,350,000)
Net cash provided by financing activities   1,400,000    3,350,000 
           
NET CHANGE IN CASH   (8,172)   3,099 
CASH AT BEGINNING OF PERIOD   228,194    94,682 
CASH AT END OF PERIOD  $220,022   $97,781 
           
SUPPLEMENTAL INFORMATION:          
Interest paid  $1,114,527   $1,110,083 
Income taxes paid  $   $ 
           
NON-CASH INVESTING AND FINANCING ACTIVITIES:          
Net change in accounts payable for purchase of oil and gas properties  $(237,303)  $612,551 
Capitalized asset retirement costs  $   $35,824 

 

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. 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, 2015, which were included in our Annual Report on Form 10-K. The Company follows the same accounting policies in the preparation of interim reports.

 

Reclassifications

In the current year, the Company classified assets and liabilities subject to the transaction proposed in Note 3 – Going Concern as held for sale in the balance sheet. For comparative purposes, amounts in the prior periods have been reclassified to conform to current year presentation.

 

Use of Estimates

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

 

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.

 

 

 6 
 

 

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Financial Statements

(Unaudited)

 

 

Cash and Cash Equivalents

Cash equivalents include money market accounts which have maturities of three months or less. For the purpose of the statements of cash flows, all highly liquid investments with an original maturity of three months or less are considered to be cash equivalents. Cash equivalents are stated at cost plus accrued interest, which approximates market value. No cash equivalents were on hand at March 31, 2016 and December 31, 2015.

 

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 March 31, 2016 and December 31, 2015, 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 March 31, 2016, and December 31, 2015, was $-0-. Amortization of debt issuance costs charged to interest expense were $-0- and $96,322 for the three months ended March 31, 2016 and 2015, respectively. When a loan is paid in full or becomes due on demand due to a default on the loan any unamortized financing costs are removed from the related accounts and charged to interest expense.

 

Website Development Costs

The Company accounts for website development costs in accordance with ASC 350-50, “Accounting for Website Development Costs” (“ASC 350-50”), wherein website development costs are segregated into three activities:

 

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

 

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

 

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

 

We have capitalized a total of $56,660 of website development costs from inception through March 31, 2016. 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 $-0- and $257 for the three months ended March 31, 2016 and 2015, respectively. As of March 31, 2016, 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.

 

 

 7 
 

 

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Financial Statements

(Unaudited)

 

 

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. For the periods presented, potential dilutive securities had an anti-dilutive effect and were not included in the calculation of diluted net loss per common share.

 

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 $3,885 and $4,267 for the three months ended March 31, 2016 and 2015, 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.

 

Full Cost Method

The Company follows the full cost method of accounting for oil and gas operations whereby all costs related to the exploration and development of oil and gas properties are initially capitalized into a single cost center ("full cost pool"). Such costs include land acquisition costs, geological and geophysical expenses, carrying charges on non-producing properties, costs of drilling directly related to acquisition, and exploration activities. Internal costs that are capitalized are directly attributable to acquisition, exploration and development activities and do not include costs related to the production, general corporate overhead or similar activities. Costs associated with production and general corporate activities are expensed in the period incurred. Capitalized costs are summarized as follows for the three months ended March 31, 2016 and 2015, respectively:

 

   Three Months Ended 
   March 31, 
   2016   2015 
Capitalized Certain Payroll and Other Internal Costs  $   $ 
Capitalized Interest Costs   7,219    155,991 
Total  $7,219   $155,991 

 

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.

 

 8 
 

 

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Financial Statements

(Unaudited)

 

 

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. The Company recognized an impairment loss of $5,219,000 during the three months ended March 31, 2016. The Company did not recognize an impairment loss during three months ended March 31, 2015.

 

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 $157,824 and $160,924 for the three months ended March 31, 2016 and 2015, 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, $-0- and $160,428 of warrant related debt discounts were amortized during the three months ended March 31, 2016 and 2015, 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 or if the related credit facility becomes payable on demand due to a default on the related credit facility. The amortization of the debt discount attributable to the warrants was accelerated in 2015 to fully amortize the discount as of December 31, 2015 when the related debt became payable on demand due to a default on the related debt.

 

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.

 

 

 9 
 

 

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Financial Statements

(Unaudited)

 

 

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, 2015.

 

In November 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2015-17, Balance Sheet Classification of Deferred Taxes, which eliminates the current requirement to present deferred tax liabilities and assets as current and noncurrent amounts in a classified statement of financial position. Instead, entities will be required to classify all deferred tax assets and liabilities as noncurrent in a statement of financial position. This standard is effective financial statements issued for annual periods beginning after December 15, 2016, and interim periods within those annual periods. Early application is permitted. The Company elected early application of this ASU as of December 31, 2015, and has applied its provisions prospectively.

 

In April 2015, the FASB issued 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. The new guidance will be applied retrospectively to each prior period presented. As of January 1, 2016, the Company has adopted of ASU 2015-03.

 

Note 3 – Going Concern

 

As shown in the accompanying financial statements, the Company has incurred losses from operations resulting in an accumulated deficit of ($72,612,676), as of March 31, 2016, the Company’s current liabilities exceeded its current assets by $63,231,402, which includes the current classification of all of the Company’s debt, and its total liabilities exceeded its total assets by $38,131,458. As of March 31, 2016, the Company is out of compliance with the collateral coverage ratio covenant contained in both its Senior Secured Facility and Subordinated Credit Facility and the current ratio covenant as defined in the Subordinated Credit Facility which constitutes an event of default. These factors raise substantial doubt about the Company’s ability to continue as a going concern.

 

In August 2014, the FASB issued ASU No. 2014-15, "Presentation of Financial Statements - Going Concern (Subtopic 205-40)". The Company chose to adopt this pronouncement in 2015 due to the applicability to our current condition. The new guidance 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.

 

 10 
 

 

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Financial Statements

(Unaudited)

 

 

On March 29, 2016, the Company entered into an Asset Contribution Agreement with Black Ridge Holding Company, LLC, a Delaware limited liability company (“BRHC”) which was recently formed by the Company to contribute and assign to BRHC, all of the Company's (i) oil and gas assets (including working capital and tangible and intangible assets) (the “Assets”), (ii) outstanding balances under that certain Credit Agreement between the Company, as borrower, and Cadence Bank, N.A. (“Cadence”), as lender (the “Cadence Credit Facility”) and the outstanding balances under that certain Credit Agreement between the Company, as borrower, and the several banks and other financial institutions or entities from time to time parties thereto (the “Chambers”), and Chambers, as administrative agent (the “Chambers Credit Facility”) and (iii) all current liabilities related to the Assets, in exchange for 5% of the issued and outstanding Class A Units (the “Class A Units”) in BRHC (the “Asset Contribution”). On March 29, 2016, affiliates of Chambers Energy Management, LP (“Chambers”) (specifically, Chambers Energy Capital II, LP and CEC II TE, LLC (collectively, the “Chambers Affiliates”)) entered into a Debt Contribution Agreement between BRHC and the Chambers Affiliates, pursuant to which BRHC will issue a number of Class A Units representing 95% of the Class A Units of BRHC to the Chambers Affiliates in exchange for the release of BRHC's obligations under the Chambers Credit Facility (the “Satisfaction of Debt” and, together with the Asset Contribution, the “BRHC Transaction”). Concurrent with the Satisfaction of Debt, each warrant originally issued with the Chambers Credit Facility shall be automatically retired and cancelled. The closing of the BRHC Transaction is subject to the Company obtaining the approval of stockholders holding a majority of its outstanding capital stock and to the Company having assigned the Cadence Credit Agreement to BRHC with Cadence’s consent, and BRHC and Cadence entering into any applicable amendment agreements related to such assignment and waiver of financial covenant ratio compliance for the quarter ended December 31, 2015 and quarter ending March 31, 2016. The Company is currently in the process of preparing to satisfy both conditions.

 

The terms of the Class A Units of BRHC will be set forth in the limited liability company agreement of BRHC (the “LLC Agreement”), which will be effective upon the closing of the BRHC Transaction. All distributions by BRHC of cash or other property, and whether upon liquidation or otherwise, will be made as follows:

 

  First, 100% to the Class A Members, pro rata, until each Class A Member has received distributions in aggregate totaling the then Class A Preference, which is an amount equal to a 10.0% internal rate of return on the invested capital amount.
  Second, 90% to the Class A Members, pro rata, and 10% to the Class B Members, pro rata, until such time as the aggregate distributions to Chambers equals 250% of the capital contribution of its Class A Units.
 

Third, 80% to the Class A Members, pro rata, and 20% to the Class B Members, pro rata. BRHC will be managed by the BRHC Board, which will be responsible for the conduct of the day-to-day business of BRHC and the management, oversight and disposition of the assets of BRHC. The initial BRHC Board will be comprised of three managers, consisting of two managers appointed by Chambers and one member from the Company.

 

In addition, under the LLC Agreement, Chambers will commit to contribute up to $30 million cash (the “Chambers Investment Commitment”) to BRHC in exchange for Class A Units. At Closing, Chambers shall fund $10 million (the “Initial Chambers Investment”) of the Chambers Investment Commitment, the proceeds of which shall be used to reduce outstanding amounts owed by BRHC to Cadence under the Cadence Credit Facility and for general corporate purposes. The remaining $20 million (the “Subsequent Chambers Investment”), subject to certain conditions, may be called from time to time during the Investment Period by the board of managers of BRHC (the “BRHC Board”). The Initial Chambers Investment and any Subsequent Chambers Investment shall serve to proportionately reduce the Company's Class A Units percentage ownership in BRHC. The investment period shall be the lesser of three years or such time as the entire Chambers Investment Commitment has been called by the BRHC Board (the “Investment Period”). Any portion of Chambers Investment Commitment not called by the BRHC Board prior to the expiration of the Investment Period will be cancelled. In no event will Chambers be required to make a capital contribution in an amount in excess of its undrawn commitment.

 

The Company will be granted 1,000,000 Class B Units in BRHC at the Closing of the BRHC Transaction. At the discretion of the BRHC’s Board of Managers, the Company may be granted additional Class B Units in BRHC, and in turn, the Company may transfer such Class B Units to certain members of the Company's management. Subject to certain conditions, the Class B Units will entitle the holders to participate in any future distributions of BRHC after distributions equal to the capital contributions and preferred return have been made to the holders of Class A Units of BRHC.

 

 

 11 
 

 

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Financial Statements

(Unaudited)

 

 

At the closing of the BRHC Transaction, the Company will enter into a Management Services Agreement with BRHC. Under the Management Services Agreement, the Company will provide services to BRHC with respect to the business operations of BRHC, including but not limited to locating, investigating and analyzing potential non-operator oil and gas projects and day-to-day operations related to such projects. The Company will be paid a fee under the Management Services Agreement intended to cover the costs of providing such services and will be reimbursed for certain third party expenses. The term of the Management Services Agreement commences on the closing of the BRHC Transaction and continues indefinitely, unless terminated. The Management Services Agreement will provide termination provisions upon reasonable notice for both the BRHC and the Company as well as upon a change of control, provided that if the Management Services Agreement is terminated before December 31, 2016 that BRHC shall pay the Company a termination fee equal to the amount that would have been paid if the Management Services Agreement was in place until December 31, 2016.

 

The Company believes that the BRHC Transaction and related actions will allow the Company to continue as a manager of the oil and gas assets in which we will continue to have an indirect minority interest. In addition, it will give us the flexibility to pursue distressed asset acquisitions in the Bakken and/or Three Forks formation that may be acquired with capital from our secured lenders as part of the restructuring terms, existing joint venture partners or other capital providers.

 

However, the BRHC Transaction has not closed as of the date of this report and certain conditions remain to be met prior to closing. ASU 2014-15 does not allow the Company to consider a plan when evaluating going concern uncertainties until that plan has been fully implemented. As the Company’s plans are not fully implemented, there remains substantial doubt about the Company’s ability to continue as a going concern.

 

The financial statements do not include any adjustments that might result from the outcome of any uncertainty as to the Company’s ability to continue as a going concern. These financial statements also do not include any adjustments relating to the recoverability and classification of recorded asset amounts, or amounts and classifications of liabilities that might be necessary should the Company be unable to continue as a going concern.

 

Note 4 – Assets and Liabilities Held for Sale

 

As part of the restructuring discussed in Note 3 – Going Concern, assets and liabilities subject to the proposed BRHC Transaction have been classified as assets held for sale on the Company’s balance sheet as of March 31, 2016 with retroactive classification on the Company’s balance sheet as of December 31, 2015.

 

 

 

 

 

 12 
 

 

Assets and liabilities held for sale as of March 31, 2016 and December 31, 2015 consisted of the following:

 

   March 31,   December 31, 
   2016   2015 
ASSETS          
           
Assets held for sale, current          
Cash and cash equivalents  $220,022   $228,194 
Derivative instruments   1,178,821    1,154,400 
Accounts receivable   5,228,128    5,038,146 
Prepaid expenses   55,113    37,100 
Total assets held for sale, current   6,682,084    6,457,840 
           
Assets held for sale, long term          
Oil and natural gas properties, full cost method of accounting          
Proved properties   132,081,392    131,168,906 
Unproved properties   10,394    10,394 
Total oil and natural gas properties, full cost method of accounting   132,091,786    131,179,300 
Less, accumulated depletion and allowance for impairment   (106,612,574)   (99,371,070)
Total assets held for sale, long term   25,479,212    31,808,230 
           
Total assets held for sale  $32,161,296   $38,266,070 
           
           
LIABILITIES          
           
Liabilities held for sale, current          
Accounts payable  $7,758,601   $7,906,438 
Accrued expenses   73,516    55,830 
Current portion of revolving credit facility and long term debt   62,081,369    60,350,629 
Total liabilities held for sale, current   69,913,486    68,312,897 
           
Liabilities held for sale, long term          
Asset retirement obligations   376,222    368,089 
Derivative instruments   40,308     
Total liabilities held for sale, long term   416,530    368,089 
           
Total liabilities held for sale  $70,330,016   $68,680,986 

 

 

 

 

 13 
 

 

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Financial Statements

(Unaudited)

 

 

Note 5 – Joint Venture

 

On July 20, 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 to this joint venture.

 

Note 6 – Property and Equipment

 

Property and equipment at March 31, 2016 and December 31, 2015, consisted of the following:

 

   March 31,   December 31, 
   2016   2015 
Property and equipment  $139,004   $139,004 
Less: Accumulated depreciation and amortization   (101,742)   (97,857)
Total property and equipment, net  $37,262   $41,147 

 

All of the oil and gas assets have been classified as assets held for sale on the balance sheet as the Company has determined it will be effectively disposing of those assets as part of the restructuring discussed in Note 3 – Going Concern.

 

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

 

   Three Months Ended 
   March 31, 
   2016   2015 
Depletion of costs for evaluated oil and gas properties  $2,022,504   $2,630,032 
Depreciation and amortization of other property and equipment   3,885    4,267 
Total depreciation, amortization and depletion  $2,026,389   $2,634,299 

 

 14 
 

 

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Financial Statements

(Unaudited)

 

 

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 2016, we recorded non-cash ceiling test impairments of $5,219,000 for the three months ended March 31, 2016. The Company did not have any impairment of its proved oil and gas properties for the three months ended March 31, 2015. 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 7 – Oil and Gas Properties

 

The following table summarizes gross and net productive oil wells by state at March 31, 2016 and 2015. A net well represents our percentage ownership of a gross well. The following table does not include wells in which our interest is limited to royalty and overriding royalty interests. The following table also does not include wells which were awaiting completion, in the process of completion or awaiting flow back subsequent to fracture stimulation.

 

   March 31, 2016   March 31, 2015 
   Gross   Net   Gross   Net 
North Dakota   352    10.64    281    8.42 
Montana   5    0.37    5    0.37 
Total   357    11.01    286    8.79 

 

The Company’s oil and gas properties consist of all acreage acquisition costs (including cash expenditures and the value of stock consideration), drilling costs and other associated capitalized costs. As of March 31, 2016 and 2015, our principal oil and gas assets included approximately 7,030 and 9,401 net acres, respectively, located in North Dakota and Montana.

 

The following table summarizes our capitalized costs for the purchase and development of our oil and gas properties for the three months ended March 31, 2016 and 2015, respectively:

 

   Three Months Ended 
   March 31, 
   2016   2015 
Purchases of oil and gas properties and development costs for cash  $1,149,789   $7,031,186 
Purchase of oil and gas properties accrued at period-end   6,662,200    9,977,347 
Purchase of oil and gas properties accrued at beginning of period   (6,899,503)   (9,364,796)
Capitalized asset retirement costs       35,824 
Total purchase and development costs, oil and gas properties  $912,486   $7,679,561 

 

2016 Acquisitions

During the three months ended March 31, 2016, we did not purchase any oil and gas properties.

 

2016 Divestitures

During the three months ended March 31, 2016, we did not sell any oil and gas properties.

 

2015 Acquisitions

During the three months ended March 31, 2015, we purchased a total of approximately 9 net leasehold acres of oil and gas properties. In consideration for the assignment, we paid the sellers a total of approximately $102,928.

 

2015 Divestitures

During the three months ended March 31, 2015, we sold a total of approximately 9 net leasehold acres of oil and gas properties for total proceeds of $99,000. No gain or loss was recorded pursuant to the sales.

 

Undeveloped Acreage Expirations

During the three months ended March 31, 2016, we had leases encompassing 1,079 net acres expire with carrying costs of $650,816 that had been reserved and transferred to the full cost pool subject to depletion in 2015. We estimate that approximately 35 additional net acres with carrying costs of approximately $37,768 will expire prior to the commencement of production activities on the related leased property during 2016. The carrying costs of leases we estimate will expire during the remainder of 2016 had been reserved and transferred to the full cost pool subject to depletion in 2015.

 

 

 15 
 

 

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Financial Statements

(Unaudited)

 

 

Note 8 – 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.

 

The following table summarizes the Company’s asset retirement obligation transactions recorded in accordance with the provisions of FASB ASC 410-20-25 during the three months ended March 31, 2016 and 2015:

 

   Three Months Ended 
   March 31, 
   2016   2015 
Beginning ARO  $368,089   $286,804 
Liabilities incurred for new wells placed in production       35,824 
Accretion of discount on ARO   8,133    7,929 
Ending ARO  $376,222   $330,557 

 

The ARO has been reclassified to liabilities held for sale, long term, on the balance sheet.

 

Note 9 – 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 $17,276 and $17,958 to this entity during the three months ended March 31, 2016 and 2015, respectively.

 

Note 10 – 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.

 

 16 
 

 

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Financial Statements

(Unaudited)

 

 

As of March 31, 2016, the Company had outstanding derivative contracts with respect to future production as follows:

 

Crude Oil Swaps        
Settlement Period  Oil (Barrels)   Fixed Price 
April 1, 2016 – May 31, 2016   10,000   $90.36 
April 1, 2016 – May 31, 2016   4,000   $88.15 
April 1, 2016 – May 31, 2016   15,000   $62.88 
June 1, 2016 – June 30, 2016   10,000   $40.75 
July 1, 2016 – December 31, 2016   48,000   $42.10 
January 1, 2017 – December 31, 2017   72,000   $44.50 

 

Crude Oil Costless Collars

 

        Floor/Ceiling     
Settlement Period   Oil (Barrels)   Price   Basis 
 April 1, 2016 – May 31, 2016    3,334    $80.00/$89.50    NYMEX 

 

As of March 31, 2016, the Company had total volume on open commodity swaps of 159,000 barrels at a weighted average price of approximately $49.26 per barrel.

 

Derivative Gains and Losses

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

 

   Three Months Ended 
   March 31, 
   2016   2015 
Realized gain (loss) on derivatives:          
Crude oil fixed price swaps  $   $896,133 
Crude oil collars       237,288 
Realized loss on derivatives, net  $   $1,133,421 
           
Gain (loss) on the mark-to-market of derivatives:          
Crude oil fixed price swaps  $(19,898)  $405,779 
Crude oil collars   4,011    (38,450)
Gain (loss) on the mark-to-market of derivatives, net  $(15,887)  $367,329 

 

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.

 

 

 

 17 
 

 

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Financial Statements

(Unaudited)

 

 

   March 31, 2016   December 31, 2015 
   Gross amounts of recognized assets   Gross amounts offset on balance sheet   Net amounts of assets on balance sheet   Gross amounts of recognized assets   Gross amounts offset on balance sheet   Net amounts of assets on balance sheet 
Commodity derivative assets  $1,207,359   $(28,538)  $1,178,821   $1,154,417   $(17)  $1,154,400 

 

 

   March 31, 2016   December 31, 2015 
   Gross amounts of recognized liabilities   Gross amounts offset on balance sheet   Net amounts of liabilities on balance sheet   Gross amounts of recognized liabilities   Gross amounts offset on balance sheet   Net amounts of liabilities on balance sheet 
Commodity derivative liabilities  $(40,854)  $546   $(40,308)  $   $   $ 

 

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

 

   March 31,   December 31, 
   2016   2015 
Assets held for sale, short term  $1,178,821   $1,154,400 
Assets held for sale, long term        
Net amount of assets on the balance sheet   1,178,821    1,154,400 
           
Liabilities held for sale, short term        
Liabilities held for sale, long term   (40,308)    
Net amounts of liabilities on the balance sheet        
Total derivative assets, net  $1,138,513   $1,154,400 

 

Note 11 – 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.

 

 18 
 

 

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 March 31, 2016 and December 31, 2015:

 

    
   Level 1   Level 2   Level 3 
Assets               
Cash and cash equivalents  $220,022   $   $ 
Derivative Instruments (crude oil swaps and collars)       1,178,821     
Total assets   220,022    1,178,821     
Liabilities               
Derivative Instruments (crude oil swaps and collars)       40,308     
Revolving credit facilities and long term debt       62,081,369     
Total Liabilities       62,121,677     
   $220,022   $(60,942,856)  $ 

 

   Fair Value Measurements at December 31, 2015 
   Level 1   Level 2   Level 3 
Assets               
Cash and cash equivalents  $228,194   $   $ 
Derivative Instruments (crude oil swaps and collars)       1,154,400     
Total assets   228,194    1,154,400     
Liabilities               
Revolving credit facilities and long term debt       60,350,629     
Total Liabilities       60,350,629     
   $228,194   $(59,196,229)  $ 

 

There were no transfers of financial assets or liabilities between Level 1 and Level 2 inputs for the three months ended March 31, 2016 and 2015.

 

Level 2 liabilities include Revolving credit facilities. No fair value adjustment was necessary during the three months ended March 31, 2016 and 2015.

 

Note 12 – 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 $32 million as of March 31, 2016, of which $29.15 million was borrowed and outstanding as of March 31, 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.

 

 19 
 

 

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 $29.15 million and $27.75 million outstanding under the Senior Credit Agreement as of March 31, 2016 and December 31, 2015, 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 December 31, 2015. The Company had borrowings of $30 million and $30 million outstanding under the Subordinated Credit Facility as of March 31, 2016 and December 31, 2015, 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.

 

 20 
 

 

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 March 31, 2016, except as noted below under “Covenant Violations”.

 

Covenant Violations

The Company was out of compliance with the collateral coverage ratio covenant as of March 31, 2016 and December 31, 2015 and the current ratio covenant as defined by the Subordinated Credit Facility as of March 31, 2016. Additionally, the audit report the Company received with respect to its financial statements as of December 31, 2015 contains an explanatory paragraph expressing uncertainty as to the Company’s ability to continue as a going concern, the delivery of which constitutes a default under both its Senior Credit Facility and Subordinated Credit Facility. See Note 3, “Going Concern”, for additional information. As such, both the Senior Credit Facility and the Subordinated Credit Facility are in default and are classified on the balance sheet as current liabilities.

 

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 $-0- and $160,248 was amortized during the three months ended March 31, 2016 and 2015. The remaining unamortized balance of the debt discount attributable to the warrants is $-0- as of March 31, 2016. The amortization of the debt discount attributable to the warrants was accelerated in 2015 to fully amortize the discount as of December 31, 2015 when the related debt became payable on demand due to a default on the related debt.

 

 21 
 

 

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Financial Statements

(Unaudited)

 

 

Amounts outstanding under revolving credit facilities and long term debts consisted of the following as of March 31, 2016 and December 31, 2015, respectively:

 

   March 31,   December 31, 
   2016   2015 
Senior Revolving Credit Facility, Cadence Bank, N.A.  $29,150,000   $27,750,000 
Subordinated Credit Agreement, Chambers   30,000,000    30,000,000 
PIK Interest on Subordinated Credit Agreement, Chambers   2,931,369    2,600,629 
           
Total credit facilities and long term debts   62,081,369    60,350,629 
Less: Unamortized OID        
Less: Unamortized debt discount attributable to warrants        
Total credit facilities and long term debts, net of discounts   62,081,369    60,350,629 
Less: current maturities (1)   (62,081,369)   (60,350,629)
           
Long term portion of credit facilities and long term debts  $   $ 

 

(1) Due to existing and anticipated covenant violations, the Company’s Senior Credit Facility and Subordinated Credit Facility were classified as current at March 31, 2016 and December 31, 2015 and are included in liabilities held for sale on the balance sheet.

 

Net proceeds of $29.4 million was 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 was being amortized using the effective interest method over the life of the credit facility, which matures on June 30, 2017. A total of $-0- and $42,399 was amortized during the three months ended March 31, 2016 and 2015, respectively. The remaining unamortized balance of the debt discount attributable to the OID is $-0- as of March 31, 2016 and December 31, 2015 as the amortization was accelerated in 2015 to fully amortize the discount as of December 31, 2015 when the related debt became payable on demand due to a default on the related debt.

 

The following presents components of interest expense for the three months ended March 31, 2016 and 2015, respectively:

 

   Three Months Ended 
   March 31, 
   2016   2015 
Accrued PIK interest  $330,740   $314,114 
Amortization of OID       42,399 
Interest and commitment fees   1,111,125    1,109,976 
Amortization of debt issuance costs       96,322 
Amortization of warrant costs       160,428 
Less interest capitalized to the full cost pool of our proved oil & gas properties   (7,219)   (155,991)
   $1,434,646   $1,567,248 

 

Note 13 – 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.

 

 22 
 

 

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Financial Statements

(Unaudited)

 

 

Note 14 –Options

 

Options Granted

No options were granted during the three months ended March 31, 2016.

 

The Company recognized a total of $157,824, and $160,924 of compensation expense during the three months ended March 31, 2016 and 2015, 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 $1,334,396 as of March 31, 2016.

 

Options Exercised

No options were exercised during the three months ended March 31, 2016 and 2015.

 

Options Forfeited

No options were forfeited during the three months ended March 31, 2016 and 2015.

 

Note 15 – Warrants

 

Warrants Granted

No warrants were granted during the three months ended March 31, 2016 and 2015.

 

We recognized a total of $-0- and $160,428 of finance expense during the three months ended March 31, 2016 and 2015, respectively, on common stock warrants issued to lenders. 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 three months ended March 31, 2016 and 2015.

 

Note 16 – 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, 2016 will be 0%. Losses incurred during the period from April 9, 2011 (inception) to March 31, 2016 could be used to offset future tax liabilities. Accounting standards require the consideration of a valuation allowance for deferred tax assets if it is “more likely than not” that some component or all of the benefits of deferred tax assets will not be realized. As of March 31, 2016, net deferred tax assets were $25,321,986, after an offsetting reduction in deferred tax liabilities of $425,768, 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 $25,321,986 was applied to the remaining net deferred tax assets. 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 three months ended March 31, 2016 of $-0- was primarily driven by the Company’s loss before provision for income taxes and offset by the valuation allowance on the resulting deferred tax asset.

 

In accordance with FASB ASC 740, the Company has evaluated its tax positions and determined there are no significant uncertain tax positions as of any date on, or before March 31, 2016.

 

 23 
 

 

 

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Financial Statements

(Unaudited)

 

 

Note 17 – Commitments and Contingencies

 

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

 

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

 

The Company commits to its participation in upcoming well development by signing an Authorization for Expenditure (“AFE”). As of March 31, 2016, the Company had committed to AFE’s of approximately $0.6 million beyond amounts previously paid or accrued.

 

Note 18 – Subsequent Events

 

Debt Facilities

During the period from April 1, 2016 to May 12, 2016, the Company sold approximately 14 net acres of oil and gas properties for $94,628.

 

Debt Facilities

During the period from April 1, 2016 to May 12, 2016, the Company drew an additional $0.25 million, net of repayments, on the senior secured facility.

 

On April 22, the Company received a notice of deficiency related to its Senior Credit Facility. The borrowing base for the Senior Credit Facility was re-determined to be $19 million, effective May 1, 2016. The Company must make a lump sum payment of the amount of the current balance, currently $29.4 million, in excess of the re-determined borrowing base, or $10.4 million, within 90 days of the notice, or make six or fewer consecutive installments on a monthly basis in an amount equal to one-sixth of the amount in excess of the borrowing base beginning 30 days from the notice.

 

Crude Oil Swaps

Between April 1, 2016 and May 12, 2016, the Company entered into the following crude oil swap contracts with crude oil settlements based on NYMEX WTI pricing as follows:

 

Settlement Period  Oil (Barrels)   Fixed Price 
July 1, 2016 – December 31, 2016   60,000   $42.00 
January 1, 2017 – December 31, 2017   96,000   $43.85 
May 1, 2016 – December 31, 2016   56,000   $46.56 
January 1, 2017 – December 31, 2017   48,000   $48.39 
January 1, 2018 – December 31, 2018   48,000   $49.59 

 

 

 

 

 

 

 24 
 

 

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;
·our inability to meet financial covenants and restrictions associated with our debt agreements;
·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.

 

 25 
 

 

Overview and Outlook

 

We are an oil and natural gas exploration and production company. Our properties are located in North Dakota and Montana. Our corporate strategy is the acquisition, exploration, development and production of crude oil and natural gas properties, primarily in the Bakken and Three Forks trends in North Dakota and Montana. As of March 31, 2016, we owned an interest in 357 gross (11.01 net) producing oil and gas wells and controlled the rights to mineral leases covering approximately 7,030 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 March 31, 2016  As of December 31, 2015 
   Productive Wells   Average Daily   Proved     
Net Acres (1)  Gross   Net   Production (2)   Reserves   PV-10 (3) 
           (Boe per day)   (000'sBoe)   ($000) 
7,030   357    11.01    1,543    2,335    31,798 

 

(1)Includes leases encompassing approximately 35 net acres that we estimate will expire over the remainder of 2016.

(2)Represents average daily production over the three months ended March 31, 2016.

(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, 2015 assumed a WTI oil price of $50.28, a Henry Hub gas price of $2.59. Market prices as of March 31, 2016 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, 2015.

 

During 2015, commodity prices for crude oil, natural gas and natural gas liquids (“NGLs”) experienced sharp declines, and this downward trend accelerated further into the first quarter of 2016, with crude oil prices reaching a twelve year low in February of 2016.

 

Looking forward, we are in the midst of satisfying the conditions to close on a restructuring transaction with our secured lenders that is described below in “Recent Developments.” We expect to complete such transaction in May of 2016. Following such transaction, our focus will be on managing the oil and gas assets in which we will continue to have an indirect minority interest. In addition, we will continue to pursue distressed asset acquisitions in the Bakken and/or Three Forks formation that may be acquired with capital from our secured lenders as part of the restructuring terms, existing joint venture partners or other capital providers.

 

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

 

On March 29, 2016, the Company entered into an Asset Contribution Agreement with Black Ridge Holding Company, LLC, a Delaware limited liability company (“BRHC”) which was recently formed by the Company to contribute and assign to BRHC, all of the Company's (i) oil and gas assets (including working capital and tangible and intangible assets) (the “Assets”), (ii) outstanding balances under that certain Credit Agreement between the Company, as borrower, and Cadence Bank, N.A. (“Cadence”), as lender (the “Cadence Credit Facility”) and the outstanding balances under that certain Credit Agreement between the Company, as borrower, and the several banks and other financial institutions or entities from time to time parties thereto (the “Chambers”), and Chambers, as administrative agent (the “Chambers Credit Facility”) and (iii) all current liabilities related to the Assets, in exchange for 5% of the issued and outstanding Class A Units (the “Class A Units”) in BRHC (the “Asset Contribution”). On March 29, 2016, affiliates of Chambers Energy Management, LP (“Chambers”) (specifically, Chambers Energy Capital II, LP and CEC II TE, LLC (collectively, the “Chambers Affiliates”)) entered into a Debt Contribution Agreement between BRHC and the Chambers Affiliates, pursuant to which BRHC will issue a number of Class A Units representing 95% of the Class A Units of BRHC to the Chambers Affiliates in exchange for the release of BRHC's obligations under the Chambers Credit Facility (the “Satisfaction of Debt” and, together with the Asset Contribution, the “BRHC Transaction”). Concurrent with the Satisfaction of Debt, each warrant originally issued with the Chambers Credit Facility shall be automatically retired and cancelled. The closing of the BRHC Transaction is subject to the Company obtaining the approval of stockholders holding a majority of its outstanding capital stock and to the Company having assigned the Cadence Credit Agreement to BRHC with Cadence’s consent, and BRHC and Cadence entering into any applicable amendment agreements related to such assignment and waiver of financial covenant ratio compliance for the quarter ended December 31, 2015 and quarter ending March 31, 2016. The Company is currently in the process of preparing to satisfy both conditions.

 

 

 26 
 

 

The terms of the Class A Units of BRHC will be set forth in the limited liability company agreement of BRHC (the “LLC Agreement”), which will be effective upon the closing of the BRHC Transaction. All distributions by BRHC of cash or other property, and whether upon liquidation or otherwise, will be made as follows:

 

• First, 100% to the Class A Members, pro rata, until each Class A Member has received distributions in aggregate totaling the then Class A Preference, which is an amount equal to a 10.0% internal rate of return on the invested capital amount.

• Second, 90% to the Class A Members, pro rata, and 10% to the Class B Members, pro rata, until such time as the aggregate distributions to Chambers equals 250% of the capital contribution of its Class A Units.

• Third, 80% to the Class A Members, pro rata, and 20% to the Class B Members, pro rata.

BRHC will be managed by the BRHC Board, which will be responsible for the conduct of the day-to-day business of BRHC and the management, oversight and disposition of the assets of BRHC. The initial BRHC Board will be comprised of three managers, consisting of two managers appointed by Chambers and one member from the Company.

 

In addition, under the LLC Agreement, Chambers will commit to contribute up to $30 million cash (the “Chambers Investment Commitment”) to BRHC in exchange for Class A Units. At Closing, Chambers shall fund $10 million (the “Initial Chambers Investment”) of the Chambers Investment Commitment, the proceeds of which shall be used to reduce outstanding amounts owed by BRHC to Cadence under the Cadence Credit Facility and for general corporate purposes. The remaining $20 million (the “Subsequent Chambers Investment”), subject to certain conditions, may be called from time to time during the Investment Period by the board of managers of BRHC (the “BRHC Board”). The Initial Chambers Investment and any Subsequent Chambers Investment shall serve to proportionately reduce the Company's Class A Units percentage ownership in BRHC. The investment period shall be the lesser of three years or such time as the entire Chambers Investment Commitment has been called by the BRHC Board (the “Investment Period”). Any portion of Chambers Investment Commitment not called by the BRHC Board prior to the expiration of the Investment Period will be cancelled. In no event will Chambers be required to make a capital contribution in an amount in excess of its undrawn commitment.

 

The Company will be granted 1,000,000 Class B Units in BRHC at the Closing of the BRHC Transaction. At the discretion of the BRHC’s Board of Managers, the Company may be granted additional Class B Units in BRHC, and in turn, the Company may transfer such Class B Units to certain members of the Company's management. Subject to certain conditions, the Class B Units will entitle the holders to participate in any future distributions of BRHC after distributions equal to the capital contributions and preferred return have been made to the holders of Class A Units of BRHC.

 

At the closing of the BRHC transaction, the Company will enter into a Management Services Agreement with BRHC. Under the Management Services Agreement, the Company will provide services to BRHC with respect to the business operations of BRHC, including but not limited to locating, investigating and analyzing potential non-operator oil and gas projects and day-to-day operations related to such projects. The Company will be paid a fee under the Management Services Agreement intended to cover the costs of providing such services and will be reimbursed for certain third party expenses. The term of the Management Services Agreement commences on the closing of the BRHC Transaction and continues indefinitely, unless terminated. The Management Services Agreement will provide termination provisions upon reasonable notice for both the BRHC and the Company as well as upon a change of control, provided that if the Management Services Agreement is terminated before January 1, 2017 that BRHC shall pay the Company a termination fee equal to the amount that would have been paid if the Management Services Agreement was in place until January 1, 2017.

 

The summaries of the LLC Agreement, Management Services Agreement, Asset Contribution Agreement, and Debt Contribution Agreement above do not purport to be complete and are qualified by reference to the LLC Agreement, Management Services Agreement, Asset Contribution Agreement, and Debt Contribution Agreement which are filed as exhibits to the Company's Information Statement filed on Form Schedule 14C.

 

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.

 

 27 
 

 

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.

 

Operational Highlights

 

During the first quarter of 2016, we achieved the following financial and operating results:

 

·production reached 1,543 Boe per day, representing 56% growth compared to the first quarter of 2015 and 5% growth compared to the fourth quarter of 2015;
·increased our total producing wells to 357 gross (11.01 net) wells;
·attained adjusted EBITDA from operations of $0.9 million;
·reduced general and administrative expenses to $6.06 per Boe, compared to $9.07 per Boe in the first quarter of 2015, representing a 33% decrease on a per Boe basis; and
·reduced our capital expenditures to $1.1 million in the first quarter of 2016 as compared to $7.0 million in the first quarter of 2015.

 

Our production increased 57% to 140,424 Boe in the first quarter of 2016 as compared to the first quarter of 2015 production of 89,308 Boe. The increase in production was driven by a 25% increase in net producing wells from 8.79 net wells at March 31, 2015, to 11.01 net wells at March 31, 2016.

 

Total revenues decreased 40% in the first quarter of 2016, compared to the first quarter of 2015 primarily driven by decreased derivative activity in 2016. We had no realized derivative activity in the first quarter of 2016 and realized gains on settled derivatives of $1.1 million in the first quarter of 2015. Realized prices on a Boe basis decreased 41% before the effect of settled derivatives and 58% after the effect of settled derivatives. Additionally, we had a loss on the mark-to-market of derivatives of $16 thousand in the first quarter of 2016 compared to a gain on the mark-to-market of derivatives of $0.4 million in the first quarter of 2015. Significant changes in crude oil and natural gas prices can have a material impact on our results of operations and our balance sheet.

 

 

 

 28 
 

 

Production History

 

The following table presents information about our produced oil and gas volumes during the three month periods ended March 31, 2016 and 2015, respectively. As of March 31, 2016, we controlled approximately 7,030 net acres in the Williston Basin. In addition, the Company owned working interests in 357 gross wells representing 10.01 net wells that are producing and an additional 16 gross wells representing 0.18 net wells that are preparing to drill, drilling, awaiting completion or completing.

 

   Three Months Ended 
   March 31, 
   2016   2015 
Net Production:          
Oil (Bbl)   107,520    72,922 
Natural gas (Mcf)   197,423    98,314 
Barrel of oil equivalents (Boe)   140,424    89,308 
           
Average Sales Prices:          
Oil (per Bbl)  $24.66   $37.60 
Effect of gain/loss on settled derivatives on average price (per Bbl)  $   $15.55 
Oil net of settled derivatives (per Bbl)  $24.66   $53.15 
Natural gas and NGL’s (per Mcf)  $0.05   $1.47 
Realized price on a Boe basis, net of settled derivatives  $18.96   $45.01 
           
Average Production Costs:          
Oil (per Bbl)  $6.93   $12.90 
Natural Gas (per Mcf)  $0.02   $0.50 
Barrel of Oil Equivalent (Boe)  $5.32   $11.08 

 

Depletion of Oil and Natural Gas Properties

 

Our depletion expense is driven by many factors including certain exploration costs involved in the development of producing reserves, production levels and estimates of proved reserve quantities and future developmental costs. The following table presents our depletion expenses for the three months ended March 31, 2016 and 2015, respectively.

 

   Three Months Ended 
   March 31, 
   2016   2015 
Depletion of oil and natural gas properties  $2,022,504   $2,630,032 

 

Productive Oil Wells

 

The following table summarizes gross and net productive oil wells by state at March 31, 2016 and 2015, respectively. A net well represents our percentage ownership of a gross well. The following table does not include wells in which our interest is limited to royalty and overriding royalty interests. The following table also does not include wells which were awaiting completion, in the process of completion or awaiting flow back subsequent to fracture stimulation.

 

   March 31, 2016   March 31, 2015 
   Gross   Net   Gross   Net 
North Dakota   352    10.64    281    8.42 
Montana   5    0.37    5    0.37 
Total   357    11.01    286    8.79 

 

Exploratory Oil Wells

 

The following table summarizes gross and net exploratory wells as of March 31, 2016 and 2015. The wells are at various stages of completion and the costs incurred are included in unevaluated oil and gas properties on our balance sheet.

 

   March 31, 2016   March 31, 2015 
   Gross   Net   Gross   Net 
North Dakota   -0-    0.00    3    0.25 
Total   -0-    0.00    3    0.25 

 

 

 29 
 

 

Results of Operations for the Three Months Ended March 31, 2016 and 2015.

 

The following table summarizes selected items from the statement of operations for the three months ended March 31, 2016 and 2015, respectively.

 

   Three Months Ended     
   March 31,   Increase / 
   2016   2015   (Decrease) 
Oil and gas sales  $2,662,555   $2,886,456   $(223,901)
Gain (loss) on settled derivatives       1,133,421    (1,133,421)
Gain (loss) on mark-to-market of derivatives   (15,887)   367,329    (383,216)
Total revenues:   2,646,668    4,387,206    (1,740,538)
                
Operating expenses:               
Production expenses   747,757    989,857    (242,100)
Production taxes   275,948    286,192    (10,244)
General and administrative   850,308    810,008    40,300 
Depletion of oil and gas properties   2,022,504    2,630,032    (607,528)
Impairment of oil and gas properties   5,219,000        5,219,000 
Accretion of discount on ARO   8,133    7,929    204 
Depreciation and amortization   3,885    4,267    (382)
Total operating expenses:   9,127,535    4,728,285    4,399,250 
                
Net operating income (loss)   (6,480,867)   (341,079)   (6,139,788)
                
Total other income (expense)   (1,434,646)   (1,567,248)   132,602 
                
Loss before provision for income taxes   (7,915,513)   (1,908,327)   (6,007,186)
                
Provision for income taxes       635,391    (635,391)
                
Net loss  $(7,915,513)  $(1,272,936)  $(6,642,577)

 

Oil and Natural Gas Sales

 

We recognized $2,662,555 in revenues from sales of crude oil and natural gas, excluding gains on derivatives, for the three months ended March 31, 2016, compared to revenues of $2,886,456 for the three months ended March 31, 2015, a decrease of $223,901, or 8%. The decrease in revenues was driven by a 41% decrease in prices on a BOE basis before the effects of derivatives, offset by a 57% increase in production on a BOE basis. We had 11.01 net producing wells as of March 31, 2016, compared to 8.79 net producing wells as of March 31, 2015.

 

Derivatives

 

For the three months ended March 31, 2016, we had a no gain or loss on settled derivatives, compared to a gain on settled derivatives of $1,133,421 for the same period in 2015.

 

We had a mark-to-market derivative loss of $15,887 in the three months ended March 31, 2016, resulting in a net derivative asset of $1,138,513. In the first quarter of 2015, we had mark-to-market gains of $367,329.

 

Production Expenses

 

Production expenses were $747,757 and $989,857 for the three months ended March 31, 2016 and 2015, respectively, a decrease of $242,100, or 24%. On a per unit basis, production expenses decreased from $11.08 per Boe in the three months ended March 31, 2015 to $5.32 per Boe in the three months ended March 31, 2016. The decrease in production expenses was primarily a result of decreased water disposal costs as the wells put into production during the latter half of 2015 had lower water cuts and water disposal costs than the balance of our producing wells and workover expenses lower in the first quarter of 2016 as compared to the first quarter of 2015 when we experienced high levels of workover expenses on wells shut-in while neighboring wells were completed.

 

 

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Production Taxes

 

Our production taxes were $275,948 and $286,192 for the three months ended March 31, 2016 and 2015, respectively, a decrease of $10,244, or 4%. Production taxes are paid based on realized oil and natural gas sales. Production taxes represented 10.4% and 9.9% of oil and gas sales in the three months ended March 31, 2016 and 2015, respectively.

 

General and Administrative Expenses

 

General and administrative expenses for the three months ended March 31, 2016 were $850,308, compared to $810,008 for the three months ended March 31, 2015, an increase of $40,300, or 5%. The increase in general and administrative expenses was primarily due to salary increases and increased external contract, particularly legal work related to the BRHC transaction. General and administrative expenses per Boe produced decreased from $9.07 to $6.06 as we maintained staffing levels despite increased production activity.

 

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 $2,022,504 and $2,630,032 for the three months ended March 31, 2016 and 2015, respectively, a decrease of $607,528, or 23%. The decrease was due primarily to decreases in the full cost pool due to the impairment losses of $71,272,000 taken in 2015, offset by increased production. Depletion expense per Boe produced decreased from $29.45 in 2015 to $14.40 in 2016.

 

Depreciation and Accretion

 

Depreciation expense for the three months ended March 31, 2016 was $3,885, compared to $4,267 for the three months ended March 31, 2015. Accretion of the discount on asset retirement obligations was $8,133 and $7,929 for the three month periods ended March 31, 2016 and 2015, respectively.

 

Other Income and (Expense)

 

Other income and (expense) for the three months ended March 31, 2016 was ($1,434,646), compared to ($1,567,248) for the three months ended March 31, 2015. The net other income and (expense) for the three months ended March 31, 2016 consisted entirely of interest expense, including $330,740 of PIK interest applied to our debt balances for the three months ended March 31, 2016. Additionally, we capitalized $7,219 of interest expense into our full cost pool related to interest costs incurred while our wells were being drilled and completed. We had no amortization of warrant costs, original issue discounts or debt financing costs in 2016 as all of the related amortization was accelerated in 2015 to fully amortize those costs as the related debt became payable on demand due to a default of a loan covenant. Our net other income and (expenses) for the three months ended March 31, 2015 consisted entirely of interest expense, including $160,428 of amortized warrant costs, $42,399 of amortization related to original issue discounts, $314,114 of PIK interest applied to our debt balances and $96,322 of amortized debt financing costs for the three months ended March 31, 2016. Additionally, we capitalized $155,991 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 no income tax benefit or expense in the three months ended March 31, 2016 and an income tax benefit of $635,391 for the three months ended March 31, 2015, respectively. In 2016, we could not recognize a tax benefit as we reserved against the deferred tax asset due to the uncertainty of the realization of the benefit. The tax benefit for the three months ended March 31, 2015 was primarily driven by the Company’s loss before provision for income taxes of $1,908,327.

 

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Non-GAAP Financial Measures

 

In addition to reporting net loss as defined under GAAP, we also present Adjusted Net Loss and Adjusted EBITDA. We define Adjusted Net Loss as net loss, excluding (i) net loss (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 (loss) 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 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 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 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 Loss and Adjusted EBITDA to net loss, GAAP, is included below:

 

Black Ridge Oil & Gas, Inc.

Reconciliation of Adjusted Net Loss

(Unaudited)

 

   Three Months Ended 
   March 31, 
   2016   2015 
Net loss  $(7,915,513)  $(1,272,936)
Add back (subtract):          
Losses (gains) on the mark-to-market of derivatives, net of tax (a)   15,887    (246,239)
Impairment of oil and gas properties, net of tax (b)   5,219,000     
Adjusted net loss  $(2,680,626)  $(1,519,175)
           
Weighted average common shares outstanding – basic and fully diluted   47,979,990    47,979,990 
           
Net loss per common share – basic and diluted  $(0.16)  $(0.03)
Add (subtract):          
Change due to loss (gain) on the mark-to-market of derivatives, net of tax        
Change due to impairment of oil and gas properties, net of tax   0.10     
Adjusted net loss per common share – basic and diluted  $(0.06)  $(0.03)

 

(a)Adjusted to reflect tax benefit (expense), computed based on our effective tax rate of approximately 0% in 2016 and 33% in 2015, of $-0- and $(121,000) for the three months ended March 31, 2016 and 2015, respectively.

(b)Adjusted to reflect tax benefit (expense), computed based on our effective tax rate of approximately 0% in 2016.

 

 

 

 

 32 
 

 

Black Ridge Oil & Gas, Inc.

Reconciliation of Adjusted EBITDA

(Unaudited)

 

 

   Three Months Ended 
   March 31, 
   2016   2015 
Net loss  $(7,915,513)  $(1,272,936)
Add back:          
Interest expense, net, excluding amortization of warrant based financing costs   1,434,646    1,406,820 
Income tax provision       (635,391)
Depreciation, depletion, and amortization   2,026,389    2,634,299 
Impairment of oil and gas properties   5,219,000     
Accretion of abandonment liability   8,133    7,929 
Share based compensation   157,824    321,352 
Loss (gain) on the mark-to-market of derivatives   15,887    (367,328)
Adjusted EBITDA  $946,366   $2,094,745 

 

 

 

 

 33 
 

 

Liquidity and Capital Resources

 

The following table summarizes our total current assets, liabilities and working capital at March 31, 2016 and December 31, 2015, respectively.

 

   March 31,   December 31, 
   2016   2015 
Current Assets  $6,682,084   $6,457,840 
           
Current Liabilities  $69,913,486   $68,312,897 
           
Working Capital  $(63,321,402)  $(61,855,057)

 

As of March 31, 2016 we had negative working capital of $63,231,402, including $62,081,369 of debt that has been classified as current and included liabilities held for sale as a current liability due to the loan default and proposed restructuring.

 

The following table summarizes our cash flows during the three month periods ended March 31, 2016 and 2015, respectively.

 

    Three Months Ended  
    March 31, 
    2016    2015 
Net cash provided by (used in) operating activities  $(258,383)  $3,585,285 
Net cash used in investing activities   (1,149,789)   (6,932,186)
Net cash provided by financing activities   1,400,000    3,350,000 
Net change in cash and cash equivalents  $(8,172)  $3,099 

 

Our net cash flows from operations are primarily affected by production volumes and commodity prices. Net cash provided by (used in) operating activities was ($258,383) and $3,585,285 for the three months ended March 31, 2016 and 2015, respectively, a decrease of $3,843,668. The decrease was primarily due to decreased collection of gains on settled derivatives. Changes in working capital from operating activities resulted in a decrease in cash of $100,843 in the three months ended March 31, 2016 as compared to an increase in cash of $2,444,526 for the same period in the previous year, primarily driven by a decrease in accounts receivable in 2015.

 

Net cash used in investing activities was $1,149,789 and $6,932,186 for the three months ended March 31, 2016 and 2015, respectively, a decrease of $5,782,397. We paid $1,149,789 for well development during the 2016 period, while in the 2015 period we paid $6,928,258 for well development. We purchased no oil and gas properties in the three months ended March 31, 2016 as compared to purchasing 9 net leasehold acres of oil and gas properties for $102,928 in the three months ended March 31, 2015. In the three months ended March 31, 2016 we sold no oil and gas properties while in the comparable 2015 period we sold 9 net leasehold acres for proceeds of $99,000.

 

Net cash provided from financing was $1.40 million and $3.35 million for the three months ended March 31, 2016 and 2015, respectively. We drew $1.40 million, net of repayments, on our credit facilities during the three months ended March 31, 2016. During the same period in 2015 we drew $3.35 million, net of repayments, on out credit facilities funding a portion of our investing activity through operating cash flow, primarily derivative gains and collection of receivables.

 

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.

 

 

 34 
 

 

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 $32 million as of March 31, 2016 and December 31, 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.

 

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 $29.15 million and $27.75 million outstanding under the Senior Credit Agreement as of March 31, 2016 and December 31, 2015, respectively.

 

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 March 31, 2016. The Company had borrowings of $30 million and $30 million outstanding under the Subordinated Credit Facility as of March 31, 2016 and December 31, 2015, respectively.

 

 

 35 
 

 

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 was out of compliance with its collateral coverage ratio as of December 31, 2015 and March 31, 2016 and the current ratio as defined in the Subordinated Credit Facility as of March 31, 2016. The Company is in compliance with all other covenants, as amended, for the period ending March 31, 2016.

 

On April 22, 2016 the Company received a notice of deficiency related to its Senior Credit Facility. The borrowing base for the Senior Credit Facility was re-determined to be $19 million, effective May 1, 2016. The Company must make a lump sum payment of the amount of the current balance, currently $29.4 million, in excess of the re-determined borrowing base, or $10.4 million, within 90 days of the notice, or make six or fewer consecutive installments on a monthly basis in an amount equal to one-sixth of the balance in excess of the borrowing base beginning 30 days from the notice.

 

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 $-0- and $153,522 was amortized during the three months ended March 31, 2016 and 2015. Amortization was accelerated in 2015 to fully amortize the remaining balance. The remaining unamortized balance of the debt discount attributable to the warrants is $-0- as of March 31, 2016. As part of the BRHC Transaction described below, these warrants will be cancelled.

 

 

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BRHC Transaction

 

As described above in “Recent Developments,” on March 29, 2016, the Company entered into an Asset Contribution Agreement with Black Ridge Holding Company, LLC, a Delaware limited liability company (“BRHC”) which was recently formed by the Company to contribute and assign to BRHC, all of the Company's (i) oil and gas assets (including working capital and tangible and intangible assets) (the “Assets”), (ii) outstanding balances under that certain Credit Agreement between the Company, as borrower, and Cadence Bank, N.A. (“Cadence”), as lender (the “Cadence Credit Facility”) and the outstanding balances under that certain Credit Agreement between the Company, as borrower, and the several banks and other financial institutions or entities from time to time parties thereto (the “Chambers”), and Chambers, as administrative agent (the “Chambers Credit Facility”) and (iii) all current liabilities related to the Assets, in exchange for 5% of the issued and outstanding Class A Units (the “Class A Units”) in BRHC (the “Asset Contribution”). On March 29, 2016, affiliates of Chambers Energy Management, LP (“Chambers”) (specifically, Chambers Energy Capital II, LP and CEC II TE, LLC (collectively, the “Chambers Affiliates”)) entered into a Debt Contribution Agreement between BRHC and the Chambers Affiliates, pursuant to which BRHC will issue a number of Class A Units representing 95% of the Class A Units of BRHC to the Chambers Affiliates in exchange for the release of BRHC's obligations under the Chambers Credit Facility (the “Satisfaction of Debt” and, together with the Asset Contribution, the “BRHC Transaction”). Concurrent with the Satisfaction of Debt, each warrant originally issued with the Chambers Credit Facility shall be automatically retired and cancelled. The closing of the BRHC Transaction is subject to the Company obtaining the approval of stockholders holding a majority of its outstanding capital stock and to the Company having assigned the Cadence Credit Agreement to BRHC with Cadence’s consent, and BRHC and Cadence entering into any applicable amendment agreements related to such assignment and waiver of financial covenant ratio compliance for the quarter ended December 31, 2015 and quarter ending March 31, 2016. The Company is currently in the process of preparing to satisfy both conditions.

 

The terms of the Class A Units of BRHC will be set forth in the limited liability company agreement of BRHC (the “LLC Agreement”), which will be effective upon the closing of the BRHC Transaction. All distributions by BRHC of cash or other property, and whether upon liquidation or otherwise, will be made as follows:

 

  First, 100% to the Class A Members, pro rata, until each Class A Member has received distributions in aggregate totaling the then Class A Preference, which is an amount equal to a 10.0% internal rate of return on the invested capital amount.
  Second, 90% to the Class A Members, pro rata, and 10% to the Class B Members, pro rata, until such time as the aggregate distributions to Chambers equals 250% of the capital contribution of its Class A Units.
 

Third, 80% to the Class A Members, pro rata, and 20% to the Class B Members, pro rata.

BRHC will be managed by the BRHC Board, which will be responsible for the conduct of the day-to-day business of BRHC and the management, oversight and disposition of the assets of BRHC. The initial BRHC Board will be comprised of three managers, consisting of two managers appointed by Chambers and one member from the Company.

 

In addition, under the LLC Agreement, Chambers will commit to contribute up to $30 million cash (the “Chambers Investment Commitment”) to BRHC in exchange for Class A Units. At Closing, Chambers shall fund $10 million (the “Initial Chambers Investment”) of the Chambers Investment Commitment, the proceeds of which shall be used to reduce outstanding amounts owed by BRHC to Cadence under the Cadence Credit Facility and for general corporate purposes. The remaining $20 million (the “Subsequent Chambers Investment”), subject to certain conditions, may be called from time to time during the Investment Period by the board of managers of BRHC (the “BRHC Board”). The Initial Chambers Investment and any Subsequent Chambers Investment shall serve to proportionately reduce the Company's Class A Units percentage ownership in BRHC. The investment period shall be the lesser of three years or such time as the entire Chambers Investment Commitment has been called by the BRHC Board (the “Investment Period”). Any portion of Chambers Investment Commitment not called by the BRHC Board prior to the expiration of the Investment Period will be cancelled. In no event will Chambers be required to make a capital contribution in an amount in excess of its undrawn commitment.

 

The Company will be granted 1,000,000 Class B Units in BRHC at the Closing of the BRHC Transaction. At the discretion of the BRHC’s Board of Managers, the Company may be granted additional Class B Units in BRHC, and in turn, the Company may transfer such Class B Units to certain members of the Company's management. Subject to certain conditions, the Class B Units will entitle the holders to participate in any future distributions of BRHC after distributions equal to the capital contributions and preferred return have been made to the holders of Class A Units of BRHC.

 

 

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At the closing of the BRHC transaction, the Company will enter into a Management Services Agreement with BRHC. Under the Management Services Agreement, the Company will provide services to BRHC with respect to the business operations of BRHC, including but not limited to locating, investigating and analyzing potential non-operator oil and gas projects and day-to-day operations related to such projects. The Company will be paid a fee under the Management Services Agreement intended to cover the costs of providing such services and will be reimbursed for certain third party expenses. The term of the Management Services Agreement commences on the closing of the BRHC Transaction and continues indefinitely, unless terminated. The Management Services Agreement will provide termination provisions upon reasonable notice for both the BRHC and the Company as well as upon a change of control, provided that if the Management Services Agreement is terminated before January 1, 2017 that BRHC shall pay the Company a termination fee equal to the amount that would have been paid if the Management Services Agreement was in place until January 1, 2017.

 

Satisfaction of our cash obligations for the next 12 months

 

As of March 31, 2016, our balance of cash and cash equivalents was $220,022. If closing of the BRHC Transaction is delayed past May 2016 due to failure to satisfy the closing conditions, we will require further discussions with Chambers and Cadence to extend our current financing terms. We cannot assure you that such extension will be granted and Chambers and Cadence may initiate legal action under the credit facilities to enforce their rights in our Collateral. We are diligently pursuing satisfaction of the closing conditions. Presuming the BRHC Transaction closes, our plan for satisfying our cash requirements for the next twelve months is through the terms of our management agreement.

 

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.

 

Our critical accounting policies are more fully described in Note 1 of the footnotes to our financial statements appearing elsewhere in this Form 10-Q, and Note 2 of the footnotes to the financial statements provided in our Annual Report on Form 10-K for the fiscal year ended December 31, 2015.

 

 

 

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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 March 31, 2016. As part of such evaluation, management considered the matters discussed below relating to internal control over financial reporting. Based on this evaluation our management, including the Company’s Chief Executive Officer and Chief Financial Officer, has concluded that the Company’s disclosure controls and procedures were effective as of March 31, 2016 to ensure that the information required to be disclosed in our Exchange Act reports was recorded, processed, summarized and reported on a timely basis.

 

There have been no changes in the Company’s internal control over financial reporting during the three month period ended March 31, 2016 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   Asset Contribution Agreement dated March 29, 2016 by and between Black Ridge Oil & Gas, Inc. as Transferor, and Black Ridge Holding Company, LLC as Transferee (incorporated by reference to Preliminary Information Statement on Schedule 14C filed with the Securities and Exchange Commission by Black Ridge Oil & Gas, Inc. on March 31, 2016)
10.2   Debt Contribution Agreement dated March 29, 2016 by and between Black Ridge Oil & Gas, Inc., Black Ridge Holding Company, LLC, Chambers Energy Capital II, LP and CEC II, TE (incorporated by reference to Preliminary Information Statement on Schedule 14C filed with the Securities and Exchange Commission by Black Ridge Oil & Gas, Inc. on March 31, 2016)
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.

 

 

 

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SIGNATURES

 

Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

 

 

 

 

  BLACK RIDGE OIL & GAS, INC.
   
   
   
Dated: May 12, 2016 By: /s/Kenneth DeCubellis
      Kenneth DeCubellis, Chief Executive Officer (Principal Executive Officer)
       
       
Dated: May 12, 2016 By: /s/James A. Moe
      James A. Moe, Chief Financial Officer (Principal Financial Officer)

 

 

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