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EX-32.1 - CERTIFICATION - Black Ridge Oil & Gas, Inc.blackridge_10q-ex3201.htm

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 

FORM 10-Q

(Mark One)

 

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

 

For Quarterly Period Ended September 30, 2013

or

 

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

 

For the Transition period from _______________ to ______________

 

Commission File Number 000-53952

 

 

 

(Name of registrant in its charter)

 

Nevada

(State or other jurisdiction of incorporation or organization)

27-2345075

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

 

10275 Wayzata Blvd. Suite 310, Minnetonka, Minnesota 55305

(Address of principal executive offices) (Zip Code)

 

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

 

 

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

Yes S No £

 

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

Yes S No £

 

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

 

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

 

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

Yes £ No S

  

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

 

The number of shares of registrant’s common stock outstanding as of November 12, 2013 was 47,979,990.

 

 

 
 

TABLE OF CONTENTS

 

PART I – FINANCIAL INFORMATION  
ITEM 1. FINANCIAL STATEMENTS (Unaudited) 3
  Condensed Balance Sheets at September 30, 2013 (Unaudited) and December 31, 2012  3
  Unaudited Condensed Statements of Operations for the Three and Nine Months Ended September 30, 2013 and  2012  4
  Unaudited Condensed Statements of Cash Flows for the Nine Months Ended September 30, 2013 and 2012  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

 

   September 30,   December 31, 
   2013   2012 
  (Unaudited)     
ASSETS          
           
Current assets:          
Cash and cash equivalents  $5,086,978   $1,417,340 
Accounts receivable   2,144,259    856,233 
Settlement receivable   2,500,000    2,500,000 
Advances to operators   1,220,576    1,350,295 
Prepaid expenses   30,791    47,155 
Total current assets   10,982,604    6,171,023 
           
Property and equipment:          
Oil and natural gas properties, full cost method of accounting          
Proved properties   47,556,747    35,248,983 
Unproved properties   5,539,955    9,055,513 
Other property and equipment   87,218    85,917 
Total property and equipment   53,183,920    44,390,413 
Less, accumulated depreciation, amortization, depletion and allowance for impairment   (8,443,947)   (5,793,184)
Total property and equipment, net   44,739,973    38,597,229 
           
Derivative instruments   6,885     
Debt issuance costs, net   691,661    657,702 
           
Total assets  $56,421,123   $45,425,954 
           
LIABILITIES AND STOCKHOLDERS' EQUITY          
           
Current liabilities:          
Accounts payable  $5,014,464   $2,953,526 
Settlement payable   160,000    160,000 
Settlement accounts payable, related party   116,234    116,234 
Accrued expenses   96,916    61,666 
Derivative instruments   53,110     
Total current liabilities   5,440,724    3,291,426 
           
Asset retirement obligations   82,319    67,145 
Revolving credit facilities and long term debt, net of discounts of $2,717,949 and $-0-, respectively   12,318,718    5,748,844 
Deferred tax liability   4,117,287    4,732,696 
           
Total liabilities   21,959,048    13,840,111 
           
Commitments and contingencies (See note 15)        
           
Stockholders' equity:          
Preferred stock, $0.001 par value, 20,000,000 shares authorized, no shares issued and outstanding        
Common stock, $0.001 par value, 500,000,000 shares authorized, 47,979,990 shares issued and outstanding   47,980    47,980 
Additional paid-in capital   32,930,595    29,847,212 
Retained earnings   1,483,500    1,690,651 
Total stockholders' equity   34,462,075    31,585,843 
           
Total liabilities and stockholders' equity  $56,421,123   $45,425,954 

 

See accompanying notes to financial statements.

 

3
 

 

BLACK RIDGE OIL & GAS, INC.

CONDENSED STATEMENTS OF OPERATIONS

(Unaudited)

 

   For the Three Months   For the Nine Months 
   Ended September 30,   Ended September 30, 
   2013   2012   2013   2012 
                 
Oil and gas sales  $2,612,640   $2,285,731   $6,674,940   $4,332,461 
Loss on settled derivatives   (21,184)       (21,184)    
Unrealized loss on derivative instruments   (46,225)       (46,225)    
Total revenues  $2,545,231   $2,285,731   $6,607,531   $4,332,461 
                     
Operating expenses:                    
Production expenses   274,756    161,793    813,023    427,676 
Production taxes   271,116    292,925    722,986    526,735 
General and administrative   524,849    1,003,743    1,715,287    2,955,517 
Depletion of oil and gas properties   1,064,921    919,138    2,633,309    1,733,753 
Accretion of discount on asset retirement obligations   1,811    1,339    4,774    3,344 
Depreciation and amortization   5,832    5,811    17,454    18,395 
Total operating expenses   2,143,285    2,384,749    5,906,833    5,665,420 
                     
Net operating income (loss)   401,946    (99,018)   700,698    (1,332,959)
                     
Other income (expense):                    
Interest income   148    209    341    451 
Interest (expense)   (714,466)   (278,129)   (1,523,599)   (804,297)
Settlement income       8,020,759        8,020,759 
Settlement expense       (2,276,116)       (2,276,116)
Total other income (expense)   (714,318)   5,466,723    (1,523,258)   4,940,797 
                     
Loss before provision for income taxes   (312,372)   5,367,705    (822,560)   3,607,838 
                     
Provision for income taxes   88,708    (2,012,195)   615,409    (1,630,630)
                     
Net income (loss)  $(223,664)  $3,355,510   $(207,151)  $1,977,208 
                     
                     
Weighted average common shares outstanding - basic   47,979,990    47,979,990    47,979,990    47,725,172 
Weighted average common shares outstanding - fully diluted   47,979,990    48,583,451    47,979,990    48,049,669 
                     
Net income (loss) per common share - basic  $(0.00)  $0.07   $(0.00)  $0.04 
Net income (loss) per common share - fully diluted  $(0.00)  $0.07   $(0.00)  $0.04 

 

See accompanying notes to financial statements.

 

4
 

 

BLACK RIDGE OIL & GAS, INC.

CONDENSED STATEMENTS OF CASH FLOWS

(Unaudited)

 

   For the Nine Months 
   Ended September 30, 
   2013   2012 
CASH FLOWS FROM OPERATING ACTIVITIES          
Net income (loss)  $(207,151)  $1,977,208 
Adjustments to reconcile net income (loss) to net cash provided by operating activities:          
Depletion of oil and gas properties   2,633,309    1,733,753 
Depreciation and amortization   17,454    18,395 
Amortization of debt issuance costs   691,928    148,299 
Accretion of discount on asset retirement obligations   4,774    3,344 
Unrealized loss on derivative instruments   46,225     
Accrued payment in kind interest applied to long term debt   36,667     
Amortization of original issue discount on debt   6,457     
Amortization of debt discounts, warrants   49,170     
Common stock issued for terminated oil and gas acquisition       438,539 
Common stock warrants   108,190    261,845 
Common stock warrants, related parties       45,719 
Common stock options, related parties   501,617    698,974 
Deferred income taxes   (615,409)   1,630,630 
Decrease (increase) in current assets:          
Accounts receivable   (1,288,026)   (69,113)
Settlement receivable       (15,000,000)
Prepaid expenses   16,364    15,100 
Contingent consideration receivable       6,008,602 
Increase (decrease) in current liabilities:          
Accounts payable   (216,975)   96,034 
Accounts payable, related parties       (4,876)
Settlement payable       2,000,000 
Settlement payable, related parties       550,079 
Accrued expenses   35,250    82,352 
Royalties payable, related party       (300,431)
Net cash provided by operating activities   1,819,844    334,453 
           
CASH FLOWS FROM INVESTING ACTIVITIES          
Proceeds from sale of oil and gas properties   500,031    993,449 
Purchases of oil and gas properties and development capital expenditures   (5,991,601)   (12,025,284)
Advances to operators   (882,604)    
Purchases of other property and equipment   (1,301)   (7,428)
Net cash used in investing activities   (6,375,475)   (11,039,263)
           
CASH FLOWS FROM FINANCING ACTIVITIES          
Advances from revolving credit facilities and long term debt   22,000,000    13,850,000 
Repayments on revolving credit facilities   (13,048,844)   (2,000,000)
Debt issuance costs paid   (725,887)   (771,233)
Net cash provided by financing activities   8,225,269    11,078,767 
           
NET CHANGE IN CASH   3,669,638    373,957 
CASH AT BEGINNING OF PERIOD   1,417,340    1,401,141 
CASH AT END OF PERIOD  $5,086,978   $1,775,098 
           
           
SUPPLEMENTAL INFORMATION:          
Interest paid  $551,399   $266,082 
Income taxes paid  $   $ 
           
NON-CASH INVESTING AND FINANCING ACTIVITIES:          
Net change in accounts payable for purchase of oil and gas properties  $2,277,913   $5,458,084 
Advances to operators received in swap for oil and gas properties  $(1,200,000)  $ 
Advances to operators applied to purchase of oil and gas properties  $2,212,323   $ 
Capitalized asset retirement costs, net of revision in estimate  $10,400   $50,294 
Liabilities relieved to additional paid-in capital  $   $180,000 
Fair value of detachable warrants granted in consideration of debt financing  $2,473,576   $ 

 

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

 

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

 

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

 

 

Note 2 – Basis of Presentation and Significant Accounting Policies

 

The interim condensed financial statements included herein, presented in accordance with United States generally accepted accounting principles and stated in US dollars, have been prepared by the Company, without audit, pursuant to the rules and regulations of the Securities and Exchange Commission. Certain information and footnote disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles have been condensed or omitted pursuant to such rules and regulations, although the Company believes that the disclosures are adequate to not make the information presented misleading.

 

These statements reflect all adjustments, which in the opinion of management, are necessary for fair presentation of the information contained therein. Except as otherwise disclosed, all such adjustments are of a normal recurring nature. It is suggested that these interim condensed financial statements be read in conjunction with the audited financial statements for the year ended December 31, 2012, which were included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2012. The Company follows the same accounting policies in the preparation of interim reports.

 

Reclassifications

In the current year, the Company separately classified advances to operators from prepaid expenses 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 for which the Company may be currently liable.

 

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. Cash and cash equivalents consist of the following:

 

   September 30,   December 31, 
   2013   2012 
Cash  $3,264,534   $513,788 
Money market funds   1,822,444    903,552 
Total  $5,086,978   $1,417,340 

 

Cash in Excess of FDIC Insured Limits

The Company maintains its cash in bank deposit accounts which, at times, may exceed federally insured limits. Accounts are guaranteed by the Federal Deposit Insurance Corporation (FDIC) and the Securities Investor Protection Corporation (SIPC) up to $250,000 and $500,000, respectively, under current regulations. The Company had approximately $4,586,978 and $917,340 in excess of FDIC and SIPC insured limits at September 30, 2013 and December 31, 2012, respectively. The Company has not experienced any losses in such accounts.

 

Advances to Operators

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

 

Debt Issuance Costs

Costs relating to obtaining our revolving credit facilities are capitalized and amortized over the term of the related debt using the straight-line method. The unamortized balance of debt issuance costs at September 30, 2013, and December 31, 2012, was $691,661 and $657,702, respectively. Amortization of debt issuance costs charged to interest expense were $691,928 and $148,299 for the nine months ended September 30, 2013 and 2012, respectively. When a loan is paid in full, any unamortized financing costs are removed from the related accounts and charged to interest expense.

 

Website Development Costs

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

 

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

 

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

 

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

 

We have capitalized a total of $56,660 of website development costs from inception through September 30, 2013. 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 $14,165 and $13,908 for the nine months ended September 30, 2013 and 2012, respectively.

 

7
 

 

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Financial Statements

(Unaudited)

 

Income Taxes

The Company recognizes deferred tax assets and liabilities based on differences between the financial reporting and tax basis of assets and liabilities using the enacted tax rates and laws that are expected to be in effect when the differences are expected to be recovered. The Company provides a valuation allowance for deferred tax assets for which it does not consider realization of such assets to be more likely than not.

 

Net Income (Loss) Per Common Share

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

 

The reconciliation of the denominators used to calculate basic EPS and diluted EPS for the three and nine months ended September 30, 2013 and 2012 are as follows:

 

   Three Months Ended   Nine Months Ended 
   September 30,   September 30, 
   2013   2012   2013   2012 
Weighted average common shares outstanding – basic   47,979,990    47,979,990    47,979,990    47,725,172 
Plus: Potentially dilutive common shares:                    
Stock options and warrants       603,461        324,497 
Weighted average common shares outstanding – diluted   47,979,990    48,583,451    47,979,990    48,049,669 

 

 

Stock options and warrants excluded from the calculation of diluted EPS because their effect was anti-dilutive were 14,539,876 and 6,438,042 for the three months ended September 30, 2013 and 2012, respectively, and 14,539,876 and 5,667,042 for the nine months ended September 30, 2013 and 2012, respectively.

 

Segment Reporting

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

 

Fair Value of Financial Instruments

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

 

Non-Oil & Gas Property and Equipment

Property and equipment that are not oil and gas properties are recorded at cost and depreciated using the straight-line method over their estimated useful lives of three to seven years. Expenditures for replacements, renewals, and betterments are capitalized. Maintenance and repairs are charged to operations as incurred. Long-lived assets, other than oil and gas properties, are evaluated for impairment to determine if current circumstances and market conditions indicate the carrying amount may not be recoverable. The Company has not recognized any impairment losses on non-oil and gas long-lived assets. Depreciation expense was $17,454 and $18,395 for the nine months ended September 30, 2013 and 2012, respectively.

 

Revenue Recognition

The Company recognizes oil and gas revenues from its interests in producing wells when production is delivered to, and title has transferred to, the purchaser and to the extent the selling price is reasonably determinable. The Company uses the sales method of accounting for gas balancing of gas production and would recognize a liability if the existing proven reserves were not adequate to cover an imbalance situation.

 

8
 

 

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Financial Statements

(Unaudited)

 

Asset Retirement Obligations

The Company records the fair value of a liability for an asset retirement obligation in the period in which the well is spud or the asset is acquired and a corresponding increase in the carrying amount of the related long-lived asset. The liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized.

 

Full Cost Method

The Company follows the full cost method of accounting for oil and gas operations whereby all costs related to the exploration and development of oil and gas properties are initially capitalized into a single cost center ("full cost pool"). Such costs include land acquisition costs, geological and geophysical expenses, carrying charges on non-producing properties, costs of drilling directly related to acquisition, and exploration activities. Internal costs that are capitalized are directly attributable to acquisition, exploration and development activities and do not include costs related to the production, general corporate overhead or similar activities. Costs associated with production and general corporate activities are expensed in the period incurred. Capitalized costs are summarized as follows for the nine months ended September 30, 2013 and 2012, respectively:

 

   Nine Months Ended 
   September 30, 
   2013   2012 
Capitalized Certain Payroll and Other Internal Costs  $17,291   $66,098 
Capitalized Interest Costs        
Total  $17,291   $66,098 

 

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

 

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

 

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

 

9
 

 

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Financial Statements

(Unaudited)

 

Impairment

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

 

FASB ASC 310-40 requires that impaired loans receivable be measured based on the present value of expected future cash flows discounted at the loan’s effective interest rate or, as a practical expedient, at the loan’s observable market price or the fair value of the collateral if the loan is collateral dependent. The Company considers the contingent consideration receivable received pursuant to a sale of substantially all of the assets of the Company, as received in the spin-off on April 16, 2010, to be accounted for in accordance with ASC 310-40. As such, prior to the settlement of the contingent consideration receivable in September of 2012, we tested for impairment annually using the present value of expected future net cash flows.

 

Stock-Based Compensation

The Company adopted FASB guidance on stock based compensation upon inception at April 9, 2010. Under FASB ASC 718-10-30-2, all share-based payments to employees, including grants of employee stock options, are to be recognized in the income statement based on their fair values. Pro forma disclosure is no longer an alternative. Expense related to common stock and stock options issued for services and compensation totaled $501,617 and $1,137,513 for the nine months ended September 30, 2013 and 2012, respectively, including $-0- and $438,539, respectively, of common stock valued at the fair market value based on the Company’s closing trading price on the date of grant, and $501,617 and $698,974, 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, $157,360 and $307,564 of warrant related costs were amortized during the nine months ended September 30, 2013 and 2012, respectively, pursuant to warrants granted in consideration for credit facilities, of which $49,170 and $-0- was amortized pursuant to the debt discounts during the nine months ended September 30, 2013 and 2012, respectively. The fair value of warrants is determined similar to the method used in determining the fair value of employee stock options and the fair value is amortized over the life of the related credit facility and accelerated upon termination of a credit facility.

 

Uncertain Tax Positions

Effective upon inception at April 9, 2010, the Company adopted new standards for accounting for uncertainty in income taxes. These standards prescribe a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. These standards also provide guidance on de-recognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition.

 

Various taxing authorities periodically audit the Company’s income tax returns. These audits include questions regarding the Company’s tax filing positions, including the timing and amount of deductions and the allocation of income to various tax jurisdictions. In evaluating the exposures connected with these various tax filing positions, including state and local taxes, the Company records allowances for probable exposures. A number of years may elapse before a particular matter, for which an allowance has been established, is audited and fully resolved. Black Ridge Oil & Gas, Inc. (formerly Ante5, Inc.) has not yet undergone an examination by any taxing authorities.

 

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

 

Derivative Instruments and Price Risk Management

The Company uses derivative instruments to manage market risks resulting from fluctuations in the prices of crude oil. 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 unrealized gain (loss) on derivatives on the statements of operations.

 

10
 

 

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Financial Statements

(Unaudited)

 

Recent Accounting Pronouncements

New accounting pronouncements are issued by 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, 2012.

 

Recently Adopted

 

Balance Sheet Offsetting — In December 2011, the FASB issued Balance Sheet (Topic 210) — Disclosures about Offsetting Assets and Liabilities (ASU No. 2011-11), which requires disclosures regarding netting arrangements in agreements underlying derivatives, certain financial instruments and related collateral amounts, and the extent to which an entity’s financial statement presentation policies related to netting arrangements impact amounts recorded to the financial statements. In January 2013, the FASB issued Balance Sheet (Topic 210) — Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities (ASU No. 2013-01) to clarify the specific instruments that should be considered in these disclosures. These disclosure requirements do not affect the presentation of amounts in the balance sheets, and were effective for annual reporting periods beginning on or after January 1, 2013, and interim periods within those annual reporting periods.

 

 

Note 3 – Property and Equipment

 

Property and equipment at September 30, 2013 and December 31, 2012, consisted of the following:

 

   September 30,   December 31, 
   2013   2012 
Oil and gas properties, full cost method:          
Evaluated costs  $47,556,747   $35,248,983 
Unevaluated costs, not subject to amortization or ceiling test   5,539,955    9,055,513 
    53,096,702    44,304,496 
Other property and equipment   87,218    85,917 
    53,183,920    44,390,413 
Less: Accumulated depreciation, amortization, depletion and impairments   (8,443,947)   (5,793,184)
Total property and equipment, net  $44,739,973   $38,597,229 

 

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

 

   Nine Months Ended 
   September 30, 
   2013   2012 
Depletion of costs for evaluated oil and gas properties  $2,633,309   $1,733,753 
Depreciation and amortization of other property and equipment   17,454    18,395 
Total depreciation, amortization and depletion  $2,650,763   $1,752,148 

 

 

Note 4 – Oil and Gas Properties

 

The following table summarizes gross and net productive oil wells by state at September 30, 2013 and 2012. A net well represents our percentage ownership of a gross well. The following table does not include wells in which our interest is limited to royalty and overriding royalty interests. The following table also does not include wells which were awaiting completion, in the process of completion or awaiting flow back subsequent to fracture stimulation.

 

11
 

 

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Financial Statements

(Unaudited)

 

   September 30, 2013   September 30, 2012 
   Gross   Net   Gross   Net 
North Dakota   91    3.14    57    2.20 
Montana   1    0.08         
Total   92    3.22    57    2.20 

 

The Company’s oil and gas properties consist of all acreage acquisition costs (including cash expenditures and the value of stock consideration), drilling costs and other associated capitalized costs. As of September 30, 2013 and 2012, our principal oil and gas assets included approximately 11,923 and 11,159 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 nine months ended September 30, 2013 and 2012, respectively:

 

   Nine Months Ended 
   September 30, 
   2013   2012 
Purchases of oil and gas properties and development costs for cash  $5,991,601   $12,025,284 
Purchase of oil and gas properties accrued at period-end   4,896,058    7,880,234 
Purchase of oil and gas properties accrued at beginning of period   (2,618,145)   (2,422,150)
Advances to operators applied to purchase of oil and gas properties   2,212,323     
Capitalized asset retirement costs, net of revision in estimate   10,400    50,294 
Total purchase and development costs, oil and gas properties  $10,492,237   $17,533,662 

 

2013 Acquisitions

During the nine months ended September 30, 2013, we purchased approximately 1,043 net mineral acres of oil and gas properties in North Dakota. In consideration for the assignment of these mineral leases, we paid the sellers a total of approximately $970,309.

 

2013 Divestitures

During the nine months ended September 30, 2013, we sold a total of approximately 157 net mineral acres of oil and gas properties for total proceeds of $500,031. No gain or loss was recorded pursuant to the sales.

 

2013 Swap Transactions

During the nine months ended September 30, 2013, we traded a total of approximately 950 net mineral acres of oil and gas properties for 160 net mineral acres and approximately $1.2 million in prepaid well development costs. No gain or loss was recorded pursuant to the transaction.

 

2012 Acquisitions

During the nine months ended September 30, 2012, we purchased approximately 986 net mineral acres of oil and gas properties in North Dakota. In consideration for the assignment of these mineral leases, we paid the sellers a total of approximately $1,301,113.

 

Of the 2012 acquisitions, 110 of the net mineral acres were acquired on February 14, 2012 from the State of North Dakota. The acreage we purchased lies within the riverbed of the Missouri river and there is third-party litigation ongoing in the State of North Dakota pertaining to state’s ownership of similar riparian acreage. In the event the state is not successful in defending its ownership claim, the state is required to refund the Company the original purchase price for the lease. We have signed an Authorization for Expenditure (“AFE”) to participate in our 8.7% working interest in a well developed on the spacing unit where the acreage resides and the operator has agreed to retroactively honor the AFE if the state is successful in defending its ownership claim. As a result, we have not capitalized our share of the development costs or recognized any of the revenue from this well.

 

2012 Divestitures

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

 

12
 

 

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Financial Statements

(Unaudited)

 

Note 5 – Asset Retirement Obligation

 

The Company has asset retirement obligations associated with the future plugging and abandonment of proved properties and related facilities. Under the provisions of FASB ASC 410-20-25, the fair value of a liability for an asset retirement obligation is recorded in the period in which it is incurred and a corresponding increase in the carrying amount of the related long lived asset. The liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized. The Company has no assets that are legally restricted for purposes of settling asset retirement obligations.

 

The following table summarizes the Company’s asset retirement obligation transactions recorded in accordance with the provisions of FASB ASC 410-20-25 during the nine months ended September 30, 2013 and 2012:

 

   Nine Months Ended 
   September 30, 
   2013   2012 
Beginning asset retirement obligation  $67,145   $3,900 
Revision in estimate of asset retirement obligation   (20,123)    
Liabilities incurred for new wells placed in production   30,523    50,294 
Accretion of discount on asset retirement obligation   4,774    3,344 
Ending asset retirement obligation  $82,319   $57,538 

 

 

Note 6 – Related Party

 

Effective August 1, 2013, the Company appointed Mr. Michael Eisele, 30, to the position of Chief Operating Officer. Mr. Eisele has served since August 2012 as the Company’s Vice President of Land, overseeing the Company’s acreage portfolio and managing acquisitions and divestitures. The Company and Mr. Eisele also entered into the Company’s standard Director and Officer Indemnification Agreement, pursuant to which the Company will indemnify Mr. Eisele against certain liabilities which may arise by reason of his status as an officer, as well as a Change of Control Agreement, which provides, among other things, for twelve months of severance pay in the event of termination as a result of a change in control of the Company.

 

A former officer of the Company, Steve Lipscomb, received a commission of 5% of a royalty stream from Peerless Media Ltd., recorded on the balance sheet as of December 31, 2011 as a contingent consideration receivable, as a result of an incentive arrangement with Mr. Lipscomb that was approved by Ante4’s Board of Directors in February 2009. Mr. Lipscomb received a total of $-0- and $35,674 during the nine months ended September 30, 2013 and 2012, respectively, of which $16,116 was received by Mr. Lipscomb while an officer of the Company in 2012. As a result of the settlement of litigation related to the same agreement, Mr. Lipscomb was due 5% of the settlement payments from the litigation settlement amounting to approximately $548,827 of which $432,593 was paid in 2012 and the remaining $116,234 is due upon receipt by the Company of the final settlement payment from Peerless Media, Ltd.

 

We have subleased and currently lease office space on a month to month basis where the lessor is an entity owned by our former CEO and current Chairman of the Board of Directors, Bradley Berman. The sublease agreement was cancelled and we entered into a direct lease on April 30, 2012 to expand and occupy approximately 1,142 square feet of office space. In accordance with this lease, our lease term remains on a month-to-month basis, provided that either party may provide ninety (90) day notice to terminate the lease, with base rents of $1,142 per month, plus common area operations and maintenance charges, and monthly parking fees of $240 per month, for the first year commencing on May 1, 2012, and subject to increases of $24 per month for each of the subsequent four year periods. We have paid a total of $23,668 and $18,460 to this entity during the nine months ended September 30, 2013 and 2012, respectively.

 

13
 

 

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Financial Statements

(Unaudited)

 

Note 7 – Litigation Settlements and Contingent Consideration Receivable

 

Peerless Settlement

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

 

  Contingent       Net Contingent 
  Consideration   Royalties   Consideration 
  Receivable   Payable   Receivable 
Balance spun-off, April 16, 2010:  $7,532,985   $(415,000)  $7,117,985 
                
Net royalties received and commissions paid   (182,335)   11,343    (170,992)
Fair value adjustment   (878,650)   80,057    (798,593)
Balance, December 31, 2010   6,472,000    (323,600)   6,148,400 
                
Net royalties received and commissions paid   (463,398)   23,169    (440,229)
Balance, December 31, 2011   6,008,602    (300,431)   5,708,171 
                
Net royalties received and commissions paid   (529,361)   26,468    (502,893)
Elimination of the contingent receivable due to settlement agreement   (5,479,241)   273,963    (5,205,278)
Balance, December 31, 2012  $   $   $ 

 

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

 

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

 

As of September 30, 2013, the Company has a settlement receivable of $2.5 million for the remaining litigation settlement and payables of $160,000 and $116,234 related to remaining contingent attorneys’ fees payable and amounts due Mr. Lipscomb, respectively. The contingent consideration receivable was relieved in 2012 as a part of the settlement. The Company has expensed non-contingent expenses and fees associated with pursuing the settlement as those expenses and fees were incurred amounting to $-0- and $333,176 for the nine months ended September 30, 2013 and 2012, respectively.

 

14
 

 

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Financial Statements

(Unaudited)

 

Note 8 – 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 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 on Settled Derivatives” and “Unrealized Gain (Loss) on Derivative Instruments.”

 

The Company has utilized swap and collar derivative contracts to hedge against the variability in cash flows associated with the forecasted sale of crude oil production. 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.

 

As of September 30, 2013, the Company had outstanding derivative contracts with respect to future production as follows:

 

Crude Oil Swaps

Settlement Period   Oil (Barrels)   Fixed Price 
 October 1, 2013 – December 31, 2013    15,750   $102.20 
 January 1, 2014 – December 31, 2014    44,004   $94.45 
 January 1, 2015 – December 31, 2015    24,000   $88.28 

 

Crude Oil Costless Collars

            Floor/Ceiling 
Settlement Period   Oil (Barrels)   Price   Basis 
 January 1, 2016 – June 30, 2016    10,002    $80.00/$89.50    NYMEX 

 

As of September 30, 2013 the Company had total volume on open commodity swaps of 83,754 barrels at a weighted average price of approximately $94.14.

 

15
 

 

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Financial Statements

(Unaudited)

 

Derivative gains and losses

 

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

 

   Three Months Ended   Nine Months Ended 
   September 30,   September 30, 
   2013   2012   2013   2012 
Realized gain (loss) on derivatives:                    
Crude oil fixed price swaps  $(21,184)  $   $(21,184)  $ 
Crude oil collars                
Realized loss on derivatives, net  $(21,184)  $   $(21,184)  $ 
                     
Unrealized loss on derivatives:                    
Crude oil fixed price swaps  $(35,936)  $   $(35,936)  $ 
Crude oil collars   (10,289)       (10,289)    
Unrealized loss on derivatives  $(46,225)  $   $(46,225)  $ 

 

Balance sheet offsetting of derivative assets and liabilities

 

In December 2011, the FASB issued ASU No2011-11, Balance Sheet (Topic210)-Disclosures about Offsetting Assets and Liabilities, which requires an entity to disclose information about offsetting arrangements to enable financial statement users to understand the effects of netting arrangements on an entity’s financial position. The Company adopted the provision of the standard upon entering into our first derivative contract and has provided the applicable disclosures below with respect to its derivative instruments.

 

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.

 

  September 30, 2013   December 31, 2012
      Gross   Net       Gross   Net
  Gross   amounts   amounts of   Gross   amounts   amounts of
  amounts of   offset   assets   amounts of   offset   assets
  recognized   on balance   on balance   recognized   on balance   on balance
  assets   sheet   sheet   assets   sheet   sheet
Commodity derivative assets $ 95,861   $ (88,976 ) $ 6,885   $   $   $

 

  September 30, 2013   December 31, 2012
      Gross   Net       Gross   Net
  Gross   amounts   amounts of   Gross   amounts   amounts of
  amounts of   offset   liabilities   amounts of   offset   liabilities
  recognized   on balance   on balance   recognized   on balance   on balance
  liabilities   sheet   sheet   liabilities   sheet   sheet
Commodity derivative liabilities $ (68,188 ) $ 15,078   $ (53,110 ) $   $   $

 

16
 

 

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Financial Statements

(Unaudited)

 

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

 

   September 30,   December 31 
   2013   2012 
Derivative assets  $   $ 
Noncurrent derivative assets   6,885     
Net amount of assets on the balance sheet   6,885     
           
Derivative liabilities   (53,110)    
Noncurrent derivative liabilities        
Net amounts of liabilities on the balance sheet   (53,110)    
Total derivative liabilities, net  $(46,225)  $ 

 

 

Note 9 – Fair Value of Financial Instruments

 

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

 

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

 

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

 

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

 

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

 

The following schedule summarizes the valuation of financial instruments at fair value on a recurring basis in the balance sheets as of September 30, 2013 and December 31, 2012:

 

  Fair Value Measurements at September 30, 2013  
  Level 1     Level 2     Level 3  
Assets                      
Cash and cash equivalents $ 5,086,978     $     $  
Derivative Instruments (crude oil swaps and collars)         6,885        
Total assets   5,086,978       6,885        
Liabilities                      
Derivative Instruments (crude oil swaps and collars)         53,110        
Long term debts, net of discounts         12,318,718        
Total Liabilities         12,371,828        
  $ 5,086,978     $ (12,364,943 )   $  

 

17
 

 

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Financial Statements

(Unaudited)

 

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

 

There were no transfers of financial assets or liabilities between Level 1 and Level 2 inputs for the nine months ended September 30, 2013 and 2012.

 

Level 2 liabilities include Revolving credit facilities. No fair value adjustment was necessary during the nine months ended September 30, 2013 and 2012.

 

 

Note 10 – Revolving Credit Facilities and Long Term Debt

 

Senior Credit Facility, Cadence Bank, N.A.

The Company entered into a Credit Agreement dated August 8, 2013 (the “Senior Credit Agreement) by and between the Company, as borrower, and Cadence Bank, N.A., as lender (“Cadence”) (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 existing debt under the Company’s credit facility with Dougherty Funding LLC.

 

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 is initially set at $7 million and is subject to periodic redeterminations. 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 will mature on August 8, 2016. 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.

 

Subordinated Credit Facility, Chambers Energy Management, LP

On August 8, 2013, the Company entered into a Second Lien Credit Agreement dated August 8, 2013 (the “Subordinated Credit Agreement”) by and among the Company, as borrower, Chambers Energy Management, LP, as administrative agent (“Chambers”), and the several other lenders (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.

 

18
 

 

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Financial Statements

(Unaudited)

 

The Subordinated Credit Agreement provides for initial commitment availability of $25 million, subject to customary conditions, 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 must be at least $15 million. Loans under the Subordinated Credit Facility shall be funded net of a 2% Original Issue Discount (“OID”). The unpaid principal balance of borrowings under the Subordinated Credit Facility bears interest at the Cash Interest Rate plus the Payment In Kind (”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 until December 31, 2014, 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. In conjunction with entering into the Subordinated Credit Facility, the Company issued detachable warrants to purchase 5,000,000 shares of the Company’s common stock at an exercise price of $0.65 per share over a five year term. The estimated fair value using the Black-Scholes Pricing Model was $2,473,576 at issuance, based on a volatility rate of 114%, risk-free interest rate of 1.38% and a call option value of $0.4947 per share. Proceeds from the sale 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 $49,170 was amortized during the nine months ended September 30, 2013. The remaining unamortized balance of the debt discount attributable to the warrants is $2,424,406 as of September 30, 2013.

 

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 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 (i) as of the last day of any fiscal quarter of the Company, a collateral coverage ratio (reserve value plus consolidated working capital to adjusted indebtedness) net of at least 1.25 to 1.0, (ii) a ratio of current assets to current liabilities of a minimum of 1.0 to 1.0, (iii) a total funded debt to EBITDAX, as defined in the Senior Credit Agreement, ratio of 3.5 to 1.0, 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 (i) as of the last day of any fiscal quarter of the Company, a collateral coverage ratio (reserve value plus consolidated working capital to adjusted indebtedness) of at least 1.25 to 1.0, (ii) as of the last day of any fiscal quarter of the Company, a consolidated net leverage ratio (adjusted total indebtedness less the amount of unrestricted cash equivalents to consolidated EBITDA) of no more than 3.5 to 1.0, calculated on a modified trailing four quarter basis, (iii) as of the last day of any fiscal quarter of the Company, 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) as of the last day of any period of four consecutive fiscal quarters of the Company, a ratio of consolidated current assets to consolidated current liabilities of at least 1.0 to 1.0. In addition, each of the Credit Facilities requires that the Company enter into hedging agreements prior to funding with regard to no less than 50% and no greater than 75% of its future oil production on currently producing wells. The Company is in compliance with all covenants for the period ending September 30, 2013.

 

On September 9, 2013, the Company repaid principal and interest outstanding under the Dougherty Credit Facility from the proceeds received pursuant to the Subordinated Credit Facility.

 

19
 

 

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Financial Statements

(Unaudited)

 

Revolving Credit Facility, Dougherty Funding, LLC (former credit facility)

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

 

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

 

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

 

The Credit Facility had a maturity date of August 1, 2015. The Credit Facility could be prepaid with thirty (30) days written notice at any time. On September 5, 2012, in connection with the amended financing, the Company issued Dougherty Funding, LLC warrants to purchase 585,000 shares of the Company’s common stock at an exercise price of $0.38 per share. The warrants expire on August 31, 2015.

 

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

 

On September 9, 2013, we repaid and terminated the Dougherty Credit Facility with proceeds from the Subordinated Credit Facility.

 

20
 

 

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Financial Statements

(Unaudited)

 

Revolving Credit Facility, PrenAnte5, LLC

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

 

Amounts outstanding under revolving credit facilities and long term debts consisted of the following as of September 30, 2013 and December 31, 2012, respectively:

 

   September 30,   December 31, 
   2013   2012 
Senior Revolving Credit Facility, Cadence Bank, N.A.  $   $ 
Subordinated Credit Agreement, Chambers   15,000,000     
PIK Interest on Subordinated Credit Agreement, Chambers   36,667     
Revolving Credit Facility, Dougherty Funding, LLC       5,748,844 
           
Total credit facilities and long term debts   15,036,667    5,748,844 
Less: Unamortized OID   (293,543)    
Less: Unamortized debt discount attributable to warrants   (2,424,406)    
Total credit facilities and long term debts, net of discounts   12,318,718     
Less: current maturities        
           
Long term portion of credit facilities and long term debts  $12,318,718   $5,748,844 

 

Net proceeds of $14,700,000 were received from our $15,000,000 advance due to the $300,000 OID pursuant to the Subordinated Credit Agreement at issuance that is presented as a debt discount on the balance sheet and is being amortized using the effective interest method over the life of the credit facility, which matures on June 30, 2017. A total of $6,457 was amortized during the nine months ended September 30, 2013. The remaining unamortized balance of the debt discount attributable to the OID is $293,543 as of September 30, 2013.

 

The following presents components of interest expense for the nine months ended September 30, 2013 and 2012, respectively:

 

  Nine Months Ended 
  September 30, 
   2013   2012 
Credit Facilities, accrued PIK interest  $36,667   $ 
Credit Facilities, amortization of OID   6,457     
Credit Facilities, interest and commitment fees   631,188    348,434 
Credit Facilities, amortization of debt issuance costs   691,927    148,299 
Credit Facilities, amortization of warrant costs   157,360    307,564 
   $1,523,599   $804,297 

 

21
 

 

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Financial Statements

(Unaudited)

 

Note 11 – Changes in Stockholders’ Equity

 

Preferred Stock

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

 

Common Stock

The Company has 500,000,000 authorized shares of $0.001 par value common stock.

 

Potential Reverse Stock Split

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

 

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

 

 

Note 12 – Options

 

Options Granted

On August 1, 2013, the Company granted options to purchase 165,000 shares of its common stock to Michael Eisele in connection with Mr. Eisele’s promotion to Chief Operating Officer. These options vest annually over five years beginning on the first anniversary of the grants and are exercisable until the tenth anniversary of the date of grant at an exercise price of $0.64 per share. The estimated fair value using the Black-Scholes Pricing Model, based on a volatility rate of 114% and a call option value of $0.5520 was $91,087 and is being amortized over the vesting period.

 

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

 

The Company recognized a total of $501,617, and $698,974 of compensation expense during the nine months ended September 30, 2013 and 2012, respectively, on common stock options issued to Employees and Directors that are being amortized over the implied service term, or vesting period, of the options. The remaining unamortized balance of these options is $1,544,292 as of September 30, 2013.

 

Options Exercised

No options were exercised during the nine months ended September 30, 2013 and 2012.

 

Options Forfeited

No options were forfeited during the nine months ended September 30, 2013 and 466,333 were forfeited during the nine months ended September 30, 2012.

 

22
 

 

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Financial Statements

(Unaudited)

 

Note 13 – Warrants

 

Warrants Granted

On August 8, 2013, in connection with entering into the Subordinated Credit Facility, the Company agreed to issue to the lenders cashless 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. The estimated fair value using the Black-Scholes Pricing Model, based on a volatility rate of 114%, risk-free interest rate of 1.38% and a call option value of $0.4947 was $2,473,576 and is being amortized using the effective interest method over the life of the credit facility, which matures on June 30, 2017. Proceeds from the sale were allocated between the debt and equity based on the relative fair values at the time of issuance. The fair value of $2,473,576 is presented as a debt discount on the balance sheet and a total of $49,170 and $-0- was amortized during the nine months ended September 30, 2013 and 2012, respectively. The remaining unamortized balance of those warrants is $2,424,406 as of September 30, 2013.

 

We recognized a total of $157,360 and $307,564 of finance expense during the nine months ended September 30, 2013 and 2012, respectively, on common stock warrants issued to lenders, including related party amounts of $-0- and $45,719 during the nine months ended September 30, 2013 and 2012, respectively. All warrants granted pursuant to debt financings are amortized over the remaining life of the respective loan. The fair value of the warrants related to the Dougherty Funding, LLC Revolving Credit Facility was being amortized over the life of the loan and the amortization was accelerated to fully amortize the fair value as of the early termination date of September 9, 2013. The fair value of the warrants related to the PrenAnte5 Revolving Credit Facility was amortized over the life of the loan and the amortization was accelerated to fully amortize the fair value as of the early termination date of April 12, 2012.

 

Warrants Exercised

No warrants were exercised during the nine months ended September 30, 2013 and 2012.

 

 

Note 14 – 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, 2013 will be approximately 37.35%. Losses incurred during the period from April 9, 2011 (inception) to September 30, 2013 could be used to offset future tax liabilities. Accounting standards require the consideration of a valuation allowance for deferred tax assets if it is “more likely than not” that some component or all of the benefits of deferred tax assets will not be realized. As of September 30, 2013, net deferred tax assets were $5,608,018 after a valuation allowance applied to net deferred tax assets of approximately $544,495. This valuation allowance reflects an allowance on only a portion of the Company’s deferred tax assets which the Company believes it is more likely than not that the benefit of these assets will not be realized. We have not provided any valuation allowance against our deferred tax liabilities. As of September 30, 2013, the Company recognized deferred tax liabilities totaling $9,725,305 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.

 

The tax benefit for the nine months ended September 30, 2013 of $615,409 was primarily driven by the Company’s loss before provision for income taxes and by a change in the Company’s effective tax rate from 41.0% to 37.35% due to a change in state apportionment factors.

 

In accordance with FASB ASC 740, the Company has evaluated its tax positions and determined there are no significant uncertain tax positions as of any date on, or before September 30, 2013.

 

23
 

 

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Financial Statements

(Unaudited)

 

Note 15 – Commitments and Contingencies

 

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

 

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

 

The Company commits to its participation in upcoming well development by signing an Authorization for Expenditure (“AFE”). As of September 30, 2013 the Company had committed to AFE’s of approximately $4.3 million beyond amounts previously paid or accrued. Additionally, the Company acquired a lease for mineral rights from the State of North Dakota on February 14, 2012 for 110 acres or an 8.7% working interest in the Dahl Federal 2-15H well that spud on January 6, 2012. The acreage we purchased lies within the riverbed of the Missouri River and there is currently third-party litigation ongoing in the State of North Dakota pertaining to the state’s ownership claim to similar riparian acreage. We have signed an AFE for the well and the operator has agreed to retroactively honor the AFE if the state is successful in defending its ownership claim. As a result we have not capitalized any of the AFE costs or recognized any sales from this well. Our proportion of the well costs, based on the AFE and our working interest, is approximately $800,000. The well started production on May 21, 2012. Had we recognized the revenue and expenses from this well we would have recorded approximately an additional $835,000 in oil and gas sales and $204,000 of production taxes and operating expenses to date of which $367,000 of oil and gas revenue and $92,000 of production expenses and taxes would relate to the nine months ended September 30, 2013. In the event the state is not successful in defending its ownership claim, the state is required to refund the Company the cost to purchase the lease.

 

 

Note 16 – Subsequent Events

 

Oil and Gas Property Purchases

The Company purchased 250 net acres of oil and gas properties in North Dakota for approximately $1,239,927 from October 1, 2013 through November 12, 2013.

 

Oil and Gas Property Sales

The Company sold 32 net acres of oil and gas properties in North Dakota for proceeds of $103,144 from October 1, 2013 through November 12, 2013.

 

 

 

 

 

 

 

 

 

 

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 earn revenues or to monetize claims that we have for payments owed to us;
·material defaults on monetary obligations owed us, resulting in unexpected losses;
·inadequate capital to acquire working interests in oil and gas prospects and to participate in the drilling and production of oil and other hydrocarbons;
·unavailability of oil and gas prospects to acquire;
·failure to discover or produce commercial quantities of oil, natural gas or other hydrocarbons;
·cost overruns incurred on our oil and gas prospects, causing unexpected operating deficits;
·drilling of dry holes;
·acquisition of oil and gas leases that are subsequently lost due to the absence of drilling or production;
·dissipation of existing assets and failure to acquire or grow a new business;
·litigation, disputes and legal claims involving outside parties; and
·risks related to our ability to be listed on a national securities exchange and meeting listing requirements

 

We have based these forward-looking statements on our current expectations and assumptions about future events. While our management considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks and uncertainties, most of which are difficult to predict and many of which are beyond our control. Accordingly, results actually achieved may differ materially from expected results in these statements. Forward-looking statements speak only as of the date they are made.

 

Readers are urged not to place undue reliance on these forward-looking statements. We assume no obligation to update any forward-looking statements in order to reflect any event or circumstance that may arise after the date of this report, other than as may be required by applicable law or regulation. Readers are urged to carefully review and consider the various disclosures made by us in our reports filed with the United States Securities and Exchange Commission (the “SEC”) which attempt to advise interested parties of the risks and factors that may affect our business, financial condition, results of operation and cash flows. If one or more of these risks or uncertainties materialize, or if the underlying assumptions prove incorrect, our actual results may vary materially from those expected or projected.

 

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 September 30, 2013, we controlled the rights to mineral leases covering approximately 11,923 net acres for prospective drilling to the Bakken and/or Three Forks formations. Looking forward, we are pursuing the following objectives:

 

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

 

We believe the following are the key drivers to our business performance:

 

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

 

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

 

Operational Highlights

 

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

 

·production reached 28,349 Boe, or 308 Boe per day, representing 2% production growth compared to the third quarter of 2012 and 10% production growth compared to the second quarter of 2013;
·participated in the completion of 11 gross (0.40 net) wells, with a 100% success rate in the Bakken and Three Forks plays increasing our total producing wells to 92 gross (3.22 net) wells;
·decreased our general and administrative expenses 24% on a per Boe basis compared to the third quarter of 2012, excluding the effect of 2012 settlement related legal expenses;
·attained a record adjusted EBITDA from operations, excluding settlement income of $1.7 million;
·realized $0.8 million of cash flow from operating activities; and
·continued expansion of our activities in the Bakken and Three Forks plays by growing production and improving our acreage portfolio.

 

Operationally, our third quarter of 2013 performance reflects continued success in executing our strategy of developing our acreage position and building production. Our production increased 10% to 28,349 Boe in the third quarter of 2013 as compared to second quarter of 2013 production of 25,741 Boe. The increase in production was driven by a 14% increase in net producing wells from 2.82 net wells at June 30, 2013 to 3.22 net wells at September 30, 2013.

 

Total revenues increased 18% in the third quarter of 2013 compared to the second quarter of 2013, driven by higher production and an increase in average realized prices on a Boe basis of 9% in the third quarter of 2013 compared to the second quarter of 2013. Significant changes in crude oil and natural gas prices can have a material impact on our results of operations and our balance sheet.

 

26
 

 

Recent Developments

 

Refinance

 

On August 8, 2013, the Company entered into a $50 million first lien revolving credit facility (the “Senior Credit Facility”) with Cadence Bank, N.A. (“Cadence”) and a $75 million second lien term loan facility (the “Subordinated Credit Facility”) with Chambers Energy Management, LP (“Chambers”).

 

The Senior Credit Facility has an initial availability of $7 million which was established based on the Company’s year-end 2012 proved reserves. This borrowing base is subject to periodic redeterminations based on changes to the Company’s reserve base. The Senior Credit Facility will mature August 8, 2016.

 

The Subordinated Credit Facility has a maximum aggregate principal amount of $75 million and has an initial availability of $25 million. The Company expects the availability to increase as the Company continues to acquire new, high value leaseholds in the heart of the Bakken and Three Forks development fairway. The Subordinated Credit Facility will mature on June 30, 2017.

 

We intend to use these two new facilities to accelerate the growth of the Company’s footprint in the Bakken/Three Forks trends through potential working interest and/or leasehold purchases, development of wells on the Company’s existing leases, and retiring the existing credit facility with Dougherty Funding LLC.

 

Potential Reverse Stock Split

 

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

 

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

 

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

 

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

 

27
 

 

Production History

 

The following table presents information about our produced oil and gas volumes during the three and nine month periods ended September 30, 2013 and 2012, respectively. As of September 30, 2013, we controlled approximately 11,923 net acres in the Williston Basin. In addition, the Company owned working interests in 108 gross wells representing 3.93 net wells that are preparing to drill, drilling, awaiting completion, complete or producing.

 

   Three Months Ended   Nine Months Ended 
   September 30,   September 30, 
   2013   2012   2013   2012 
Net Production:                    
Oil (Bbl)   26,427    27,099    70,586    51,885 
Natural gas (Mcf)   11,535    4,966    31,837    9,616 
Barrel of oil equivalents (Boe)   28,349    27,927    75,892    53,488 
                     
Average Sales Prices:                    
Oil (per Bbl)  $96.07   $82.79   $91.81   $82.56 
Effect of loss on settled derivatives on average price (per Bbl)  $(0.80)  $   $(0.30)  $ 
Oil net of settled derivatives (per Bbl)  $95.27   $82.79   $91.51   $82.56 
Natural gas and NGL’s (per Mcf)  $6.41   $4.37   $6.11   $5.07 
Realized price on a Boe basis including all realized settled derivatives  $91.41   $81.85   $87.67   $81.00 
                     
Average Production Costs:                    
Oil (per Bbl)  $10.10   $5.92   $11.18   $8.16 
Natural Gas (per Mcf)  $0.67   $0.30   $0.74   $0.43 
Barrel of Oil Equivalent (Boe)  $9.69   $5.79   $10.71   $8.00 

 

Depletion of Oil and Natural Gas Properties

 

Our depletion expense is driven by many factors including certain exploration costs involved in the development of producing reserves, production levels and estimates of proved reserve quantities and future developmental costs. The following table presents our depletion expenses for the nine months ended September 30, 2013 and 2012, respectively.

 

   Nine Months Ended 
   September 30, 
   2013   2012 
Depletion of oil and natural gas properties  $2,633,309   $1,733,753 

 

Productive Oil Wells

 

The following table summarizes gross and net productive oil wells by state at September 30, 2013 and 2012, respectively. A net well represents our percentage ownership of a gross well. The following table does not include wells in which our interest is limited to royalty and overriding royalty interests. The following table also does not include wells which were awaiting completion, in the process of completion or awaiting flow back subsequent to fracture stimulation.

 

   September 30, 2013   September 30, 2012 
   Gross   Net   Gross   Net 
North Dakota   91    3.14    57    2.20 
Montana   1    0.08         
Total   92    3.22    57    2.20 

 

Exploratory Oil Wells

 

The following table summarizes gross and net exploratory wells as of September 30, 2013 and 2012. The wells are at various stages of completion and the costs incurred are included in unevaluated oil and gas properties on our balance sheet.

 

 

   September 30, 2013   September 30, 2012 
   Gross   Net   Gross   Net 
North Dakota   4    0.24        0.00 
Total   4    0.24        0.00 

 

28
 

 

Results of Operations for the Three Months Ended September 30, 2013 and 2012.

 

The following table summarizes selected items from the statement of operations for the three months ended September 30, 2013 and 2012, respectively.

 

   Three Months Ended     
   September 30,   Increase / 
   2013   2012   (Decrease) 
Oil and gas sales  $2,612,640   $2,285,731   $326,909 
Loss on settled derivatives   (21,184)       (21,184)
Unrealized loss on derivatives   (46,225)       (46,225)
Total revenues:   2,545,231    2,285,731    259,500 
                
Operating expenses:               
Production expenses   274,756    161,793    112,963 
Production taxes   271,116    292,925    (21,809)
General and administrative   524,849    1,003,743    (478,894)
Depletion of oil and gas properties   1,064,921    919,138    145,783 
Accretion of discount on asset retirement obligations   1,811    1,339    472 
Depreciation and amortization   5,832    5,811    21 
Total operating expenses:   2,143,285    2,384,749    (241,464)
                
Net operating income (loss)   401,946    (99,018)   500,964 
                
Total other income (expense)   (714,318)   5,466,723    (6,181,041)
                
Loss before provision for income taxes   (312,372)   5,367,705    (5,680,077)
                
Provision for income taxes   88,708    (2,012,195)   2,100,903 
                
Net income (loss)  $(223,664)  $3,355,510   $(3,579,174)

 

Oil and Natural Gas Sales

 

We recognized $2,612,640 in revenues from sales of crude oil and natural gas, excluding losses on derivatives, for the three months ended September 30, 2013 compared to revenues of $2,285,731 for the three months ended September 30, 2012, an increase of $326,909, or 14%. The increase in revenues was driven by a 2% increase in production and a 13% increase in realized prices before the effects of settled derivatives. We had 92 gross producing wells as of September 30, 2013 and an additional 16 wells that were either in the drilling preparation, drilling, awaiting completion or completing stages compared to 57 gross producing wells and an additional six wells that were either in the drilling preparation, drilling, awaiting completion or completing stages as of September 30, 2012.

 

Derivatives

 

For the third quarter of 2013 we incurred a loss on settled derivatives of $21,184. We had no derivative instruments in 2012.

 

We had mark-to market derivative losses of $46,225 in the third quarter of 2013 resulting in a net derivative liability of $46,225. The third quarter of 2013 was the first quarter we entered into a derivative contracts.

 

Production Expenses

 

Production expenses were $274,756 and $161,793 for the three months ended September 30, 2013 and 2012, respectively, an increase of $112,963, or 70%. Our production expenses are greater than the comparative period due to our rapid expansion and increased acreage holdings. Production expenses increased as a percentage of revenues from 7.1% in 2012 to 10.8% in 2013 as increased workover and related expenses and higher water hauling and disposal costs in 2013 drove production costs higher. On a per unit basis, production expenses increased from $5.79 per Boe in the third quarter of 2012 to $9.69 per Boe in the third quarter of 2013.

 

29
 

 

Production Taxes

 

Our production taxes of $271,116 and $292,925 for the three months ended September 30, 2013 and 2012, respectively, a decrease of $21,809, or 7%. Production taxes are paid based on realized oil and natural gas sales. Production taxes represented 10.7% and 12.8% of oil and gas revenues in the third quarter of 2013 and 2012, respectively, the decrease driven by increased oil production in Montana, which has a lower production tax rate, and increased gas and related product sales which have lower average tax rates than oil sales compared to revenue.

 

General and Administrative Expenses

 

General and administrative expenses for the three months ended September 30, 2013 were $524,849 compared to $1,003,743 for the three months ended September 30, 2012, a decrease of $478,894, or 48%. The decrease in general and administrative expenses was primarily due to non-contingent legal and other costs associated with litigation settlement activity in 2012 that were expensed as incurred. Legal and other costs associated with litigation settlement activity were $-0- and $327,363 in the three months ended September 30, 2013 and 2012, respectively. Additionally, share based compensation expense in general and administrative costs decreased $52,909 during the third quarter of 2013 compared to the third quarter of 2012.

 

Depletion of Oil and Natural Gas Properties

 

Our depletion expense is driven by many factors, including certain exploration costs involved in the development of producing reserves, production levels and estimates of proved reserve quantities and future developmental costs. We recognized depletion expense of $1,064,921 and $919,138 for the three months ended September 30, 2013 and 2012, respectively, an increase of $145,783, or 16%. The increase was due primarily to our expansion of production and acquisitions of oil & gas properties.

 

Depreciation

 

Depreciation expense for the three months ended September 30, 2013 was $5,832 compared to $5,811 for the three months ended September 30, 2012.

 

Other Income and (Expenses)

 

Other income and (expenses) for the three months ended September 30, 2013 was ($714,318) compared to $5,466,723 for the three months ended September 30, 2012. The net other income and (expenses) for the three months ended September 30, 2013 consisted of $148 of interest income and ($714,466) of interest expense including ($91,746) of amortized warrant costs and ($292,273) of amortized debt financing costs for the three months ended September 30, 2013. Our net other income and (expenses) for the three months ended September 30, 2012 consisted of a gain of $5,744,643 due to the settlement, net of expenses, of the Peerless/ElectraWorks arbitration, $209 of interest income and ($278,129) of interest expense including ($2,776) of amortized warrant costs and ($67,836) of amortized debt issuance. Amortization of the warrants and deferred financing costs were accelerated during 2013 due to the termination of the Dougherty credit facility on September 9, 2013 as part of our refinancing.

 

Provision for Income Taxes

 

We had an income tax benefit of $88,708 and income tax expense of ($2,012,195) for the three months ended September 30, 2013 and 2012, respectively, a difference of $2,100,903. The income tax benefit in the 2012 period was driven primarily by the settlement, net of expenses, of the Peerless/ElectraWorks arbitration, which resulted in tax expense of approximately $2,360,000 based on our effective tax rate of approximately 41%.

 

30
 

 

Results of Operations for the Nine Months Ended September 30, 2013 and 2012.

 

The following table summarizes selected items from the statement of operations for the nine months ended September 30, 2013 and 2012, respectively.

 

   Nine Months Ended     
   September 30,   Increase / 
   2013   2012   (Decrease) 
Oil and gas sales  $6,674,940   $4,332,461   $2,342,479 
Loss on settled derivatives   (21,184)       (21,184)
Unrealized loss on derivatives   (46,225)       (46,225)
Total revenues:   6,607,531    4,332,461    2,275,070 
                
Operating expenses:               
Production expenses   813,023    427,676    385,347 
Production taxes   722,986    526,735    196,251 
General and administrative   1,715,287    2,955,517    (1,240,230)
Depletion of oil and gas properties   2,633,309    1,733,753    899,556 
Accretion of discount on asset retirement obligations   4,774    3,344    1,430 
Depreciation and amortization   17,454    18,395    (941)
Total operating expenses:   5,906,833    5,665,420    241,413 
                
Net operating income (loss)   700,698    (1,332,959)   2,033,657 
                
Total other income (expense)   (1,523,258)   4,940,797    (6,464,055)
                
Loss before provision for income taxes   (822,560)   3,607,838    (4,430,398)
                
Provision for income taxes   615,409    (1,630,630)   2,246,039 
                
Net income (loss)  $(207,151)  $1,977,208   $(2,184,359)

 

Oil and Natural Gas Sales

 

We recognized $6,674,940 in revenues from sales of crude oil and natural gas for the nine months ended September 30, 2013 compared to revenues of $4,332,461 for the nine months ended September 30, 2012, an increase of $2,342,479, or 54%. The increase in revenues was driven by a 42% increase in production and a 9% increase in realized prices before the effects of settled derivatives. We had 92 gross producing wells as of September 30, 2013 and an additional 16 wells that were either in the drilling preparation, drilling, awaiting completion or completing stages compared to 57 gross producing wells and an additional six wells that were either in the drilling preparation, drilling, awaiting completion or completing stages as of September 30, 2012.

 

Derivatives

 

For the nine months ended September 30, 2013 we incurred a loss on settled derivatives of $21,184. We had no derivative instruments in 2012.

 

We had mark-to market derivative losses of $46,225 in the nine months ended September 30, 2013 resulting in a net derivative liability of $46,225. The third quarter of 2013 was the first quarter we entered into a derivative contracts.

 

Production Expenses

 

Production expenses were $813,023 and $427,676 for the nine months ended September 30, 2013 and 2012, respectively, an increase of $385,347, or 90%. Production expenses increased as a percentage of revenues from 9.9% in 2012 to 12.3% in 2013. On a per unit basis, production expenses increased from $8.00 per Boe in 2012 to $10.71 per Boe in 2013. Our 2013 production expenses are greater than the comparative period due to our rapid expansion and increased acreage holdings in addition to increased well workover and related expenses in nine months ended September 30, 2013 and increased weather related expenses incurred in the first quarter of 2013, offset by higher water disposal costs in the first quarter of 2012.

 

31
 

 

Production Taxes

 

Our production taxes were $722,986 and $526,735 for the nine months ended September 30, 2013 and 2012, respectively, an increase of $196,251, or 37%. Production taxes are paid based on realized oil and natural gas sales. Production taxes represented 10.9% and 12.2% of oil and gas revenues in nine months ended September 30, 2013 and 2012, respectively. The decrease in production taxes as a percent of sales is driven by increased oil production in Montana, which has a lower production tax rate, and increased gas and related product sales which have lower average tax rates than oil sales compared to revenue.

 

General and Administrative Expenses

 

General and administrative expenses for the nine months ended September 30, 2013 were $1,715,287 compared to $2,955,517 for the nine months ended September 30, 2012, a decrease of $1,240,230, or 42%. Our decrease in general and administrative expenses was primarily due to a one-time expense of $438,539 incurred in 2012 related to the fair value of common stock granted as a non-refundable deposit on acreage acquisitions we decided not to complete and $371,323 of non-contingent legal costs associated with litigation settlement activity incurred in 2012. Additionally, share based compensation expense in general and administrative costs decreased $197,357 during the three months ended September 30, 2013 compared to the three months ended September 30, 2012.

 

Depletion of Oil and Natural Gas Properties

 

Our depletion expense is driven by many factors, including certain exploration costs involved in the development of producing reserves, production levels and estimates of proved reserve quantities and future developmental costs. We recognized depletion expense of $2,633,309 for the nine months ended September 30, 2013, compared to $1,733,753 for the nine months ended September 30, 2012, an increase of $899,556, or 52%. The increase was due primarily to our expansion of production and acquisitions of oil & gas properties during 2012 and the first nine months of 2013.

 

Depreciation

 

Depreciation expense for the nine months ended September 30, 2013 was $17,454 compared to $18,395 for the nine months ended September 30, 2012.

 

Other Income and (Expenses)

 

Other income and (expenses) for the nine months ended September 30, 2013 was ($1,523,258) compared to $4,940,797 for the nine months ended September 30, 2012. The net other income and (expenses) for the nine months ended September 30, 2013 consisted of $341 of interest income and ($1,523,599) of interest expense including ($157,360) of amortized warrant costs and ($691,927) of amortized debt financing costs for the nine months ended September 30, 2013. Amortization of the fair value of warrants and deferred financing costs were accelerated in 2013 due to the termination of the Dougherty credit facility in the third quarter of 2013 as part of our refinancing. The net other income and (expenses) for the nine months ended September 30, 2012 consisted of a net gain of $5,744,643 due to the settlement, net of expenses, of the Peerless/ElectraWorks arbitration, $451 of interest income earned on money market accounts, and ($804,297) of interest expense, including ($307,564) of amortized warrant costs and ($148,299) of amortized debt issuance costs. Amortization of the warrants and debt issuance costs related to the PrenAnte5 Credit Agreement were accelerated due to the Company’s repayment and voluntary termination of the revolving credit facility on April 12, 2012.

 

Provision for Income Taxes

 

We had an income tax benefit of $615,409 for the nine months ended September 30, 2013 and income tax expense of $1,630,630 for the nine months and September 30, 2013, a difference of $2,246,039. The tax benefit in the nine months ended September 30, 2013 the difference is driven primarily by the settlement, net of expenses, of the Peerless/ElectraWorks arbitration, which resulted in tax expense of approximately $2,360,000 based on our effective tax rate of approximately 41%.

 

32
 

 

Non-GAAP Financial Measures

 

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

 

Black Ridge Oil & Gas, Inc.

Reconciliation of Adjusted Net Income (Loss)

(Unaudited)

  

   Three Months Ended   Nine Months Ended 
   September 30,   September 30, 
   2013   2012   2013   2012 
Net Income (Loss)  $(223,664)  $3,355,510   $(207,151)  $1,977,208 
Subtract:                    
Settlement Income, Net of Tax (a)       (3,384,643)       (3,384,643)
Adjusted Net Income (Loss)  $(223,664)  $(29,133)  $(207,151)  $(1,407,435)
                     
Weighted average common shares outstanding - basic   47,979,990    47,979,990    47,979,990    47,725,172 
Weighted average common shares outstanding - fully diluted   47,979,990    48,583,451    47,979,990    48,049,669 
                     
Net income (loss) per common share - basic  $(0.00)  $0.07   $(0.00)  $0.04 
Subtract:                    
Change due to Settlement Income, Net of Tax   0.00    (0.07)   0.00    (0.07)
Adjusted Net Income (loss) per common share - basic  $(0.00)  $(0.00)  $(0.00)  $(0.03)
                     
Net income (loss) per common share - fully diluted   (0.00)  $0.07   $(0.00)  $0.04 
Subtract:                    
Change due to Settlement Income, Net of Tax   0.00    (0.07)   0.00    (0.07)
Adjusted Net Income (Loss) per common share - fully diluted  $(0.00)  $(0.00)  $(0.00)  $(0.03)

 

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

 

33
 

 

Black Ridge Oil & Gas, Inc.

Reconciliation of Adjusted EBITDA

(Unaudited)

 

   Three Months Ended   Nine Months Ended 
   September 30,   September 30, 
   2013   2012   2013   2012 
Net income (loss)  $(223,664)  $3,355,510   $(207,151)  $1,977,208 
Add back:                    
Interest expense, net, excluding amortization of warrant based financing costs   622,842    275,144    1,365,898    496,282 
Income tax provision   (88,708)   2,012,195    (615,409)   1,630,630 
Depreciation, depletion, and amortization   1,070,753    924,949    2,650,763    1,752,148 
Accretion of abandonment liability   1,811    1,339    4,774    3,344 
Common stock issued for terminated oil and gas acquisition               438,539 
Share based compensation   263,379    227,588    658,977    1,006,538 
Unrealized loss on derivatives   46,225        46,225     
                     
Adjusted EBITDA  $1,692,638   $6,796,725   $3,904,077   $7,304,689 

 

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

34
 
 

Liquidity and capital resources

 

The following table summarizes our total current assets, liabilities and working capital at September 30, 2013 and December 31, 2012, respectively.

 

   September 30,   December 31, 
   2013   2012 
Current Assets  $10,982,604   $6,171,023 
           
Current Liabilities  $5,440,724   $3,291,426 
           
Working Capital  $5,541,880   $2,879,597 

 

As of September 30, 2013 we had positive working capital of $5,541,880.

 

The following table summarizes our cash flows during the nine month periods ended September 30, 2013 and 2012, respectively.

 

   Nine Months Ended 
   September 30, 
   2013   2012 
Net cash provided by operating activities  $1,819,844   $334,453 
Net cash used in investing activities   (6,375,475)   (11,039,263)
Net cash provided by financing activities   8,225,269    11,078,767 
           
Net change in cash and cash equivalents  $3,669,638   $373,957 

 

Our net cash flows from operations are primarily affected by production volumes and commodity prices. Net cash provided by operating activities was $1,819,844 and $334,453 for the nine months ended September 30, 2013 and 2012, respectively, an increase of $1,485,391. The increase was due to increased gross profit from higher production activity offset by changes in working capital from operating activities. Changes in working capital from operating activities resulted in a decrease in cash of ($1,453,387) in the nine months ended September 30, 2013 as compared to a decrease in cash of ($6,622,253) for the same period in the previous year, primarily driven by an increase in accounts receivable in 2013 and activity related to the Peerless settlement in 2012.

 

Net cash used in investing activities was $6,375,475 and $11,039,263 for the nine months ended September 30, 2013 and 2012, respectively, a decrease of $4,663,788. The decrease was primarily driven by decreased expenditures for well development as we paid $10,724,171 for well development during the 2012 period while in the 2013 period we spent $5,021,292 for well development and $882,604 in advances to operators for future well development. Additionally, the decrease in cash used in investing activities was also attributable to a decrease in cash spent for property acquisition as we purchased 1,043 acres of oil and gas properties for $970,309 in the nine months ended September 30, 2013 as compared to purchasing 986 acres of oil and gas properties for $1,301,113 in the nine months ended September 30, 2012.

 

Net cash provided from financing was $8,225,269 and $11,078,767 for the nine months ended September 30, 2013 and 2012, respectively, a decrease of $2,853,498. We drew $8,951,156, net of repayments, on our revolving credit facility and long term debts during the nine months ended September 30, 2013 while funding a portion of the operational and investing activity through operating income and working capital and paid $725,887 in debt issuance costs. In the nine months ended September 30, 2012 we drew $2 million on our PrenAnte5 revolving credit facility and drew $11,850,000 on our Dougherty revolving credit facility, of which $2 million of the proceeds were used to repay the PrenAnte5 revolving credit facility, and paid debt issuance costs of $771,233.

 

35
 

 

Senior Credit Facility and Subordinated Credit Facilities

 

On August 8, 2013 the Company entered into a Credit Agreement (the “Senior Credit Agreement) by and between the Company, as borrower, and Cadence Bank, N.A., as lender (“Cadence”) (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 existing debt under the Company’s credit facility with Dougherty Funding LLC.

 

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 is initially set at $7 million and is subject to periodic redeterminations. 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 will mature on August 8, 2016. 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.

 

On August 8, 2013, the Company entered into a Second Lien Credit Agreement dated August 8, 2013 (the “Subordinated Credit Agreement”) by and among the Company, as borrower, Chambers Energy Management, LP, as administrative agent (“Chambers”), and the several other lenders (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 provides for initial commitment availability of $25 million, subject to customary conditions, 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 must be 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 until December 31, 2014, 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.

 

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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 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 (i) as of the last day of any fiscal quarter of the Company, a collateral coverage ratio (reserve value plus consolidated working capital to adjusted indebtedness) of at least 1.25 to 1.0, (ii) a ratio of current assets to current liabilities of a minimum of 1.0 to 1.0, (iii) a net debt to EBITDAX, as defined in the Senior Credit Agreement, ratio of 3.5 to 1.0, 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 (i) as of the last day of any fiscal quarter of the Company, a collateral coverage ratio (reserve value plus consolidated working capital to adjusted indebtedness) of at least 1.25 to 1.0, (ii) as of the last day of any fiscal quarter of the Company, a consolidated net leverage ratio (adjusted total indebtedness less the amount of unrestricted cash equivalents to consolidated EBITDA) of no more than 3.5 to 1.0, calculated on a modified trailing four quarter basis, (iii) as of the last day of any fiscal quarter of the Company, 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) as of the last day of any period of four consecutive fiscal quarters of the Company, a ratio of consolidated current assets to consolidated current liabilities of at least 1.0 to 1.0. In addition, each of the Credit Facilities requires that the Company enter into hedging agreements prior to funding with regard to no less than 50% and no greater than 75% of its future oil production on currently producing wells. The Company is in compliance with all covenants for the period ending September 30, 2013.

 

The first funding from the Credit Facilities occurred on September 9, 2013 at which time we drew $14,700,000, 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 the Dougherty revolving credit facility.

 

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 sale 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 $49,170 was amortized during the nine months ended September 30, 2013.  The remaining unamortized balance of the debt discount attributable to the warrants is $2,424,406 as of September 30, 2013.

 

Dougherty Revolving Credit Facility (former credit facility)

 

On April 4, 2012, the Company entered into a Secured Revolving Credit Agreement with Dougherty Funding, LLC (“Dougherty”) as Lender which was subsequently amended on September 5, 2012 and December 14, 2012 with an Amended and Restated Secured Revolving Credit Agreement (collectively the “Dougherty Credit Facility”).

 

The Dougherty Credit Facility provided for a maximum available amount of $20 million, of which $16.5 million was available prior to termination of the facility, with interest payable on the outstanding balance at a rate of 9.25% per year and a maturity date of August 1, 2015. In connection with the amended financing, the Company issued Dougherty Funding, LLC warrants to purchase 585,000 shares of the Company’s common stock at an exercise price of $0.38 per share. The warrants expire on August 31, 2015.

 

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

 

On September 9, 2013, we repaid the Dougherty Credit Facility with proceeds from the Subordinated Credit Facility.

 

Although our revenues are expected to grow as our wells are placed into production, our revenues are not expected to exceed our investment developing oil and gas wells and our operating costs throughout the remainder of 2013 and 2014. However, our availability under our credit facilities provides ample funding for our property acquisition and development plans through those same periods. Our prospects still must be considered in light of the risks, expenses and difficulties frequently encountered by companies in their early stage of development. Such risks for us include, but are not limited to, potential failure to earn revenues or to sufficiently monetize certain claims that we have for payments that are owed to us; an inability to identify investment and expansion targets; and dissipation of existing assets. To address these risks, we must, among other things, seek growth opportunities through investment and acquisitions in the oil and gas industry, effectively monitor and manage our claims for payments that are owed to us, implement and successfully execute our business strategy, respond to competitive developments, and attract, retain and motivate qualified personnel. We cannot assure that we will be successful in addressing such risks, and the failure to do so could have a material adverse effect on our business prospects, financial condition and results of operations.

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Satisfaction of our cash obligations for the next 12 months

 

As of September 30, 2013, our balance of cash and cash equivalents was $5,086,978. Our plan for satisfying our cash requirements for the next twelve months, in addition to our revenues from oil and gas sales is through draws on our credit facilities and potential sale or use of shares of our stock.

 

Off-Balance Sheet Arrangements

 

We have no off-balance sheet arrangements.

 

Critical Accounting Policies and Estimates

 

Our management’s discussion and analysis of financial conditions and results of operations is based on our financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States, or GAAP. The preparation of these financial statements required us to make estimates and judgments that affect the reported amounts of assets, liabilities and expenses. On an ongoing basis, we evaluate these estimates and judgments, including those described below. We base our estimates on our historical experience and on various other assumptions that we believe to be reasonable under the circumstances. These estimates and assumptions form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results and experiences may differ materially from these estimates.

 

While our significant accounting policies are more fully described in notes to our financial statements appearing elsewhere in this Form 10-Q, we believe that the following accounting policies are the most critical to aid you in fully understanding and evaluating our reported financial results and affect the more significant judgments and estimates that we used in the preparation of our financial statements.

 

Stock-Based Compensation

 

We have accounted for stock-based compensation under the provisions of FASB Accounting Standards Codification (ASC) 718-10-55 (Prior authoritative literature: FASB Statement 123(R), Share-Based Payment). This statement requires us to record any expense associated with the fair value of stock-based compensation. We used the Black-Scholes option valuation model to calculate stock based compensation at the date of grant. Option pricing models require the input of highly subjective assumptions, including the expected price volatility. Changes in these assumptions can materially affect the fair value estimate.

 

Full Cost Method

 

We follow the full cost method of accounting for oil and gas operations whereby all costs related to the exploration and development of oil and gas properties are initially capitalized into a single cost center (“full cost pool”). Such costs include land acquisition costs, geological and geophysical expenses, carrying charges on non-producing properties, costs of drilling directly related to acquisitions, and exploration activities.

 

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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 new 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. We entered into our first derivative contracts in August of 2013 as required by our financing agreements.

 

Interest Rate Risk

 

Our credit facility with Dougherty had a fixed interest rate. Under our new Credit Facilities our long-term debt is comprised of borrowings on floating interest rates. As a result, in future quarters, changes in interest rates can impact results of operations and cash flows.

 

 

ITEM 4. CONTROLS AND PROCEDURES.

 

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

 

Our management, under the direction of our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the design and operation of our disclosure controls and procedures (as such terms are defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of September 30, 2013. As part of such evaluation, management considered the matters discussed below relating to internal control over financial reporting. Based on this evaluation our management, including the Company’s Chief Executive Officer and Chief Financial Officer, has concluded that the Company’s disclosure controls and procedures were effective as of September 30, 2013 to ensure that the information required to be disclosed in our Exchange Act reports was recorded, processed, summarized and reported on a timely basis.

 

There have been no changes in the Company’s internal control over financial reporting during the three month period ended September 30, 2013 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.

 

None.

 

 

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

 

None.

 

 

ITEM 3. DEFAULTS UPON SENIOR SECURITIES.

 

None.

 

 

ITEM 4. MINE SAFETY DISCLOSURES.

 

Not applicable.

 

 

ITEM 5. OTHER INFORMATION.

 

None.

 

 

ITEM 6. EXHIBITS.

 

Exhibit   Description
10.1   Credit Agreement dated August 8, 2013 by and between Black Ridge Oil & Gas, Inc., as Borrower, and Cadence Bank, N.A., as Lender (incorporated by reference to Exhibit 10.1 of the Form 8-K filed with the Securities and Exchange Commission by Black Ridge Oil & Gas, Inc. August 9, 2013)
10.2   Second Lien Credit Agreement dated August 8, 2013 by and among Black Ridge Oil & Gas, Inc., as Borrower, the several banks and other financial institutions or entities from time to time parties thereto, as Lenders, and Chambers Energy Management LP, as Agent (incorporated by reference to Exhibit 10.2 of the Form 8-K filed with the Securities and Exchange Commission by Black Ridge Oil & Gas, Inc. August 9, 2013)
10.3   Warrant dated August 8, 2013 from Black Ridge Oil & Gas, Inc. to Chambers Energy Capital II, LP (incorporated by reference to Exhibit 10.2 of the Form 8-K filed with the Securities and Exchange Commission by Black Ridge Oil & Gas, Inc. August 9, 2013)
10.4   Warrant dated August 8, 2013 from Black Ridge Oil & Gas, Inc. to Chambers Energy Capital II TE, LP (incorporated by reference to Exhibit 10.2 of the Form 8-K filed with the Securities and Exchange Commission by Black Ridge Oil & Gas, Inc. August 9, 2013)
10.5   Stock Option Agreement dated August 1, 2013 from Black Ridge Oil & Gas, Inc. to Michael Eisele (incorporated by reference to Exhibit 10.1 of the Form 8-K filed with the Securities and Exchange Commission by Black Ridge Oil & Gas, Inc. August 1, 2013)
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

 

 

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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: November 13, 2013 By: /s/ Kenneth DeCubellis
    Kenneth DeCubellis, Chief Executive Officer
    (Principal Executive Officer)
     
Dated: November 13, 2013 By: /s/ James A. Moe
    James A. Moe, Chief Financial Officer
    (Principal Financial Officer)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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