UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 

FORM 10-Q

(Mark One)

 

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

 

For Quarterly Period Ended June 30, 2016

or

 

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

 

For the Transition period from _______________ to ______________

 

Commission File Number 000-53952

 

(Exact name of registrant as specified in its charter)

 

Nevada (State or other jurisdiction of incorporation or organization)

27-2345075 (I.R.S. Employer Identification No.)

 

110 North 5^th Street, Suite 410, Minneapolis, Minnesota 55403

(Address of principal executive offices) (Zip Code)

 

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

 

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

Yes

[X]

No

[_]

 

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

Yes

[X]

No

[_]

 

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

Large accelerated filer	[_]		Accelerated filer	[_]
Non-accelerated filer (Do not check if a smaller reporting company)	[_]		Smaller reporting company	[X]

 

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

Yes

[_]

No

[X]

 

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

 

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

 

TABLE OF CONTENTS

 

PART I – FINANCIAL INFORMATION
ITEM 1.		FINANCIAL STATEMENTS (Unaudited)
		Condensed Balance Sheets as of June 30, 2016 (Unaudited) and December 31, 2015	3
		Unaudited Condensed Statements of Operations for the Three and Six Months Ended June 30, 2016 and 2015	4
		Unaudited Condensed Statements of Cash Flows for the Six Months Ended June 30, 2016 and 2015	5
		Notes to the Condensed Financial Statements (Unaudited)	6
ITEM 2.		MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	25
ITEM 3.		QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	43
ITEM 4.		CONTROLS AND PROCEDURES	43
PART II – OTHER INFORMATION
ITEM 1.		Legal Proceedings	44
ITEM 1A.		RISK FACTORS	44
ITEM 2.		UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	44
ITEM 3.		DEFAULTS UPON SENIOR SECURITIES	44
ITEM 4.		MINE SAFETY DISCLOSURES	44
ITEM 5.		OTHER INFORMATION	44
ITEM 6.		EXHIBITS	44
		SIGNATURES	45

 

 

PART I – FINANCIAL INFORMATION

 

ITEM 1. FINANCIAL STATEMENTS.

 

BLACK RIDGE OIL & GAS, INC.

CONDENSED BALANCE SHEETS

 

		June 30,				December 31,
		2016				2015
		(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents		$	1,038,567			$	228,194
Prepaid expenses			67,621				–
Current assets from discontinued operations			–				6,229,646
Total current assets			1,106,188				6,457,840
Property and equipment:
Property and equipment			139,004				139,004
Less accumulated depreciation			(105,221	)			(97,857	)
Total property and equipment, net			33,783				41,147
Investment in Black Ridge Holding Company, LLC			52,853				–
Non-current assets from discontinued operations			–				31,808,230
Total assets		$	1,192,824			$	38,307,217
LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT)
Current liabilities:
Current liabilities from discontinued operations		$	–			$	68,312,897
Accounts payable			114,106				–
Due to Black Ridge Holding Company, LLC			967,141				–
Accrued expenses			3,404				–
Total current liabilities			1,084,651				68,312,897
Non-current liabilities from discontinued operations			–				368,089
Total liabilities			1,084,651				68,680,986
Commitments and contingencies (See note 17)			–				–
Stockholders' equity (deficit):
Preferred stock, $0.001 par value, 20,000,000 shares authorized, no shares issued and outstanding			–				–
Common stock, $0.001 par value, 500,000,000 shares authorized, 47,979,990 shares issued and outstanding			47,980				47,980
Additional paid-in capital			34,591,062				34,275,414
Accumulated deficit			(34,530,869	)			(64,697,163	)
Total stockholders' equity (deficit)			108,173				(30,373,769	)
Total liabilities and stockholders' equity (deficit)		$	1,192,824			$	38,307,217

 

See accompanying notes to financial statements.

 

 

BLACK RIDGE OIL & GAS, INC.

CONDENSED STATEMENTS OF OPERATIONS

(Unaudited)

 

		For the Three Months								For the Six Months
		Ended June 30,								Ended June 30,
		2016				2015				2016				2015
Management fee income		$	49,451			$	–			$	49,451			$	–
Total revenues			49,451				–				49,451				–
Operating expenses:
General and administrative			614,661				645,837				1,299,569				1,332,724
Depreciation and amortization			3,479				4,009				7,364				8,276
Total operating expenses			618,140				649,846				1,306,933				1,341,000
Net operating income (loss)			(568,689	)			(649,846	)			(1,257,482	)			(1,341,000	)
Other income (expense):
Other income			–				6,707				–				6,707
Gain on debt restructuring			41,621,150				–				41,621,150				–
Total other income (expense)			41,621,150				6,707				41,621,150				6,707
Income (loss) before provision for income taxes			41,052,461				(643,139	)			40,363,668				(1,334,293	)
Provision for income taxes			–				–				–				–
Income (loss) from continuing operations, net of income taxes			41,052,461				(643,139	)			40,363,668				(1,334,293	)
Loss from discontinued operations, net of income taxes			(2,970,654	)			(18,026,499	)			(10,197,374	)			(18,608,281	)
Net income (loss)		$	38,081,807			$	(18,669,638	)		$	30,166,294			$	(19,942,574	)
Weighted average common shares outstanding - basic			47,979,990				47,979,990				47,979,990				47,979,990
Weighted average common shares outstanding - fully diluted			48,058,679				47,979,990				48,056,573				47,979,990
Net income (loss) per common share - basic		$	0.79			$	(0.39	)		$	0.63			$	(0.42	)
Net income (loss) per common share - fully diluted		$	0.79			$	(0.39	)		$	0.63			$	(0.42	)

 

See accompanying notes to financial statements.

 

 

BLACK RIDGE OIL & GAS, INC.

CONDENSED STATEMENTS OF CASH FLOWS

(Unaudited)

 

		For the Six Months
		Ended June 30,
		2016				2015
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)		$	30,166,294			$	(19,942,574	)
Loss from discontinued operations, net of income taxes			(10,197,374	)			(18,608,281	)
Income (loss) from continuing operations, net of income taxes			40,363,668				(1,334,293	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization			7,364				8,276
Gain on debt restructuring			(41,621,150	)			–
Common stock options issued to employees and directors			315,648				313,751
Decrease (increase) in current assets:
Prepaid expenses			(30,521	)			(5,470	)
Increase (decrease) in current liabilities:
Accounts payable			87,892				18,553
Due to Black Ridge Holding Company, LLC			967,141				–
Accrued expenses			4,114				30,441
Net cash provided by (used in) operating activities from continuing operations			94,156				(968,742	)
Net cash provided by operating activities from discontinued operations			3,829,723				6,512,822
Net cash provided by operating activities			3,923,879				5,544,080
CASH FLOWS FROM INVESTING ACTIVITIES
Net cash used in investing activities from continuing operations			–				–
Net cash used in investing activities from discontinued operations			(4,763,506	)			(12,574,179	)
Net cash used in investing activities			(4,763,506	)			(12,574,179	)
CASH FLOWS FROM FINANCING ACTIVITIES
Net cash provided by financing activities from continuing operations			–				–
Net cash provided by financing activities from discontinued operations			1,650,000				7,150,000
Net cash provided by financing activities			1,650,000				7,150,000
NET CHANGE IN CASH			810,373				119,901
CASH AT BEGINNING OF PERIOD			228,194				94,682
CASH AT END OF PERIOD		$	1,038,567			$	214,583
SUPPLEMENTAL INFORMATION:
Interest paid		$	1,429,564			$	2,174,153
Income taxes paid		$	–			$	–
NON-CASH INVESTING AND FINANCING ACTIVITIES:
Investment in Black Ridge Holding Company, LLC		$	(41,568,297	)		$	–
Net change in accounts payable for purchase of oil and gas properties		$	(3,744,487	)		$	(161,409	)
Capitalized asset retirement costs, net of revision in estimate		$	4,737			$	41,695

 

See accompanying notes to financial statements.

 

 

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Financial Statements

(Unaudited)

 

Note 1 – Organization and Nature of Business

 

Effective April 2, 2012, Ante5, Inc. changed its corporate name to Black Ridge Oil & Gas, Inc., and continues to be quoted on the OTCQB under the trading symbol “ANFC”. Black Ridge Oil & Gas, Inc. (formerly Ante5, Inc.) (the “Company”) became an independent company in April 2010. We became a publicly traded company when our shares began trading on July 1, 2010. Since October 2010, we had 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.

 

On June 21, 2016 we closed on a debt restructuring transaction with our secured lenders as described in Note 4 – Debt Restructuring. Following the transaction, our focus is on managing the oil and gas assets in which we will continue to have an indirect minority interest. In addition, we will continue to pursue distressed asset acquisitions in the Bakken and/or Three Forks and other formations that may be acquired with capital from our secured lenders as part of the restructuring terms, existing joint venture partners or other capital providers.

 

Note 2 – Basis of Presentation and Significant Accounting Policies

 

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

 

These statements reflect all adjustments, which in the opinion of management, are necessary for fair presentation of the information contained therein. Except as otherwise disclosed, all such adjustments are of a normal recurring nature. It is suggested that these interim condensed financial statements be read in conjunction with the audited financial statements for the year ended December 31, 2015, which were included in our Annual Report on Form 10-K. The Company follows the same accounting policies in the preparation of interim reports.

 

Reclassifications

In the current year, the Company classified assets and liabilities subject to our restructuring transaction outlined in Note 4 – Restructuring as assets and liabilities from discontinued operations in the balance sheet and income, expense and cash flows from the restructured operations are shown as net income and cash flows from discontinued operations. For comparative purposes, amounts in the prior periods have been reclassified to conform to current year presentation.

 

Use of Estimates

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

 

Environmental Liabilities

The oil and gas industry is subject, by its nature, to environmental hazards and clean-up costs. At this time, management knows of no substantial losses from environmental accidents or events which would have a material effect on the Company.

 

Cash and Cash Equivalents

Cash equivalents include money market accounts which have maturities of three months or less. For the purpose of the statements of cash flows, all highly liquid investments with an original maturity of three months or less are considered to be cash equivalents. Cash equivalents are stated at cost plus accrued interest, which approximates market value. No cash equivalents were on hand at June 30, 2016 and December 31, 2015.

 

Cash in Excess of FDIC Insured Limits

The Company maintains its cash in bank deposit accounts which, at times, may exceed federally insured limits. Accounts are guaranteed by the Federal Deposit Insurance Corporation (FDIC) and the Securities Investor Protection Corporation (SIPC) up to $250,000 and $500,000, respectively, under current regulations. The Company had approximately $538,567 and $-0- in excess of FDIC and SIPC insured limits at June 30, 2016 and December 31, 2015, respectively. The Company has not experienced any losses in such accounts.

 

 

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Financial Statements

(Unaudited)

 

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 June 30, 2016, and December 31, 2015, was $-0-. Amortization of debt issuance costs charged to interest expense were $-0- and $190,780 for the six months ended June 30, 2016 and 2015, respectively. Interest expense related to debt issuance costs is reflected as part of loss from discontinued operations on the statement of operations. When a loan is paid in full or becomes due on demand due to a default on the loan any unamortized financing costs are removed from the related accounts and charged to interest expense.

 

Website Development Costs

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

 

1)

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

 

2)

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

 

3)

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

 

We have capitalized a total of $56,660 of website development costs from inception through June 30, 2016. We depreciate our website development costs on a straight line basis over the estimated useful life of the assets, which is currently three years. We have recognized depreciation expense on these website costs of $-0- and $257 for the six months ended June 30, 2016 and 2015, respectively. As of June 30, 2016, all website development costs have been fully depreciated.

 

Income Taxes

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

 

 

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Financial Statements

(Unaudited)

 

Basic and Diluted Loss Per Share

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

 

The reconciliation of the denominators used to calculate basic EPS and diluted EPS for the three and six months ended June 30, 2016 and 2015 are as follows:

 

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2016				2015				2016				2015
Weighted average common shares outstanding – basic			47,979,990				47,979,990				47,979,990				47,979,990
Plus: Potentially dilutive common shares:
Stock options and warrants			78,689				–				76,583				–
Weighted average common shares outstanding – diluted			48,058,679				47,979,990				48,056,573				47,979,990

 

Stock options and warrants excluded from the calculation of diluted EPS because their effect was anti-dilutive were 9,954,875 and 16,275,542 for the three months ended June 30, 2016 and 2015, respectively, and 9,954,875 and 16,275,542 for the six months ended June 30, 2016 and 2015, respectively.

 

Fair Value of Financial Instruments

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

 

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 $7,364 and $8,276 for the six months ended June 30, 2016 and 2015, respectively.

 

Revenue Recognition

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

 

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. The capitalized cost and asset retirement obligation as of December 31, 2015 and the expense related to accretion of the discount on the asset retirement liability are reflected as part of discontinued operations on the balance sheet and statement of operations.

 

 

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Financial Statements

(Unaudited)

 

Full Cost Method

The Company follows the full cost method of accounting for oil and gas operations whereby all costs related to the exploration and development of oil and gas properties are initially capitalized into a single cost center ("full cost pool"). Such costs include land acquisition costs, geological and geophysical expenses, carrying charges on non-producing properties, costs of drilling directly related to acquisition, and exploration activities. Internal costs that are capitalized are directly attributable to acquisition, exploration and development activities and do not include costs related to the production, general corporate overhead or similar activities. Costs associated with production and general corporate activities are expensed in the period incurred. Capitalized costs are summarized as follows for the six months ended June 30, 2016 and 2015, respectively:

 

		Six Months Ended
		June 30,
		2016				2015
Capitalized Certain Payroll and Other Internal Costs		$	–			$	–
Capitalized Interest Costs			7,219				295,331
Total		$	7,219			$	295,331

 

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

 

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

 

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

 

As a result of currently prevailing low commodity prices and their effect on the proved reserve values of properties throughout 2015 and 2016, we recorded non-cash ceiling test impairments of $5,219,000 and $21,639,000 for the six months ended June 30, 2016 and 2015, respectively. The impairment charges affected our reported net income but did not reduce our cash flow. The impairment charges are reflected as part of discontinued operations on the statement of operations.

 

 

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Financial Statements

(Unaudited)

 

Stock-Based Compensation

The Company adopted FASB guidance on stock based compensation upon inception at April 9, 2010. Under FASB ASC 718-10-30-2, all share-based payments to employees, including grants of employee stock options, are recognized in the income statement based on their fair values. Expense related to common stock and stock options issued for services and compensation totaled $315,648 and $313,751 for the six months ended June 30, 2016 and 2015, respectively, using the Black-Scholes options pricing model and an effective term of 6 to 6.5 years based on the weighted average of the vesting periods and the stated term of the option grants and the discount rate on 5 to 7 year U.S. Treasury securities at the grant date. In addition, $-0- and $321,763 of warrant related debt discounts were amortized during the six months ended June 30, 2016 and 2015, respectively, and treated as interest expense and reflected as part of discontinued operations on the statement of operation. The fair value of warrants is determined similar to the method used in determining the fair value of employee stock options and the fair value is amortized over the life of the related credit facility and accelerated in the event of termination of the related credit facility or if the related credit facility becomes payable on demand due to a default on the related credit facility. The amortization of the debt discount attributable to the warrants was accelerated in 2015 to fully amortize the discount as of December 31, 2015 when the related debt became payable on demand due to a default on the related debt. As part of the debt restructuring all related warrants were retired and cancelled.

 

Uncertain Tax Positions

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

 

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

 

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

 

Derivative Instruments and Price Risk Management

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

 

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

 

Recent Accounting Pronouncements

New accounting pronouncements are issued by the Financial Accounting Standards Board (“FASB”) that are adopted by the Company as of the specified effective date. If not discussed below, management believes there have been no developments to recently issued accounting standards, including expected dates of adoption and estimated effects on our financial statements, from those disclosed in our Annual Report on Form 10-K for the year ended December 31, 2015.

 

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

 

 

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Financial Statements

(Unaudited)

 

In April 2015, the FASB issued ASU No. 2015-03, Interest–Imputation of Interest (Subtopic 835-30) (“ASU 2015-03”), which changes the presentation of debt issuance costs in financial statements. ASU 2015-03 requires an entity to present such costs in the balance sheet as a direct deduction from the related debt liability rather than as an asset. Amortization of the costs will continue to be reported as interest expense. It is effective for annual reporting periods beginning after December 15, 2016. The new guidance will be applied retrospectively to each prior period presented. As of January 1, 2016, the Company has adopted of ASU 2015-03.

 

Note 3 – Going Concern

 

In August 2014, the FASB issued ASU No. 2014-15, "Presentation of Financial Statements - Going Concern (Subtopic 205-40)". The Company chose to adopt this pronouncement in 2015 due to the applicability to our current condition. The new guidance addresses management's responsibility to evaluate whether there is substantial doubt about an entity's ability to continue as a going concern and in certain circumstances to provide related footnote disclosures.

 

As shown in the accompanying financial statements, the Company has incurred losses from operations resulting in an accumulated deficit of ($34,530,869) as of June 30, 2016, which was reduced in the current quarter by a gain on debt restructuring of $41,621,150. While the debt restructuring outlined in Note 4 – Debt Restructuring leaves the Company debt free, it also eliminated the asset base from which the Company derived the majority of its cash flow. The management fees from the management agreement entered into as part of the debt restructuring should be sufficient to cover the Company’s overhead costs for the balance of 2016. However, the management agreement can be cancelled by either party without penalty after January 1, 2017. While the Company is actively working to secure additional joint ventures with assets to manage, to date the Company has not found other sources of revenue. These factors raise substantial doubt about the Company’s ability to continue as a going concern.

 

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

 

Note 4 – Debt Restructuring

 

On March 29, 2016, the Company entered into an Asset Contribution Agreement with Black Ridge Holding Company, LLC, a Delaware limited liability company (“BRHC”) which was recently formed by the Company to contribute and assign to BRHC, all of the Company's (i) oil and gas assets (including working capital and tangible and intangible assets) (the “Assets”), (ii) outstanding balances under that certain Credit Agreement between the Company, as borrower, and Cadence Bank, N.A. (“Cadence”), as lender (the “Cadence Credit Facility”) and the outstanding balances under that certain Credit Agreement between the Company, as borrower, and the several banks and other financial institutions or entities from time to time parties thereto (the “Chambers”), and Chambers, as administrative agent (the “Chambers Credit Facility”) and (iii) all current liabilities related to the Assets, in exchange for 5% of the issued and outstanding Class A Units (the “Class A Units”) in BRHC (the “Asset Contribution”). On March 29, 2016, affiliates of Chambers Energy Management, LP (“Chambers”) (specifically, Chambers Energy Capital II, LP and CEC II TE, LLC (collectively, the “Chambers Affiliates”)) entered into a Debt Contribution Agreement between BRHC and the Chambers Affiliates, pursuant to which BRHC will issue a number of Class A Units representing 95% of the Class A Units of BRHC to the Chambers Affiliates in exchange for the release of BRHC's obligations under the Chambers Credit Facility (the “Satisfaction of Debt” and, together with the Asset Contribution, the “BRHC Transaction”). Concurrent with the Satisfaction of Debt, each warrant originally issued with the Chambers Credit Facility was automatically retired and cancelled. The closing of the BRHC Transaction was subject to the Company obtaining the approval of stockholders holding a majority of its outstanding capital stock and to the Company having assigned the Cadence Credit Agreement to BRHC with Cadence’s consent, and BRHC and Cadence entering into any applicable amendment agreements related to such assignment and waiver of financial covenant ratio compliance for the quarter ended December 31, 2015 and quarter ending March 31, 2016. On June 21, 2016, the Company satisfied all of these conditions and, for accounting purposes, the BRHC Transaction was closed. The parties have agreed that the BRHC Transaction, the Asset Contribution and the Satisfaction of Debt are effective, for valuation purposes, as of April 1, 2016.

 

 

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Financial Statements

(Unaudited)

 

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

 

·

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

·

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

·

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

 

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

 

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

 

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

 

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

 

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

 

As a result of the transaction, the Company recorded a gain on debt restructuring of $41,621,150 calculated as the difference between our final ownership interest in BRHC, after conversion of debt to equity and the equity contribution of the Initial Chambers Investment within BRHC and our retention of a 3.88% ownership interest in BRHC, and the net book value of the assets and liabilities we transferred to BRHC.

 

 

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Financial Statements

(Unaudited)

 

The income and expense for the associated with the operating activities (through June 21, 2016, the date of the BRHC transaction) contributed in the BRHC Transaction are reflected as “Loss from discontinued items, net of income taxes” on our condensed statement of operations for all periods presented herein. The items included in “Loss from discontinued operations, net of income taxes” are as follows:

 

		For the Three Months								For the Six Months
		Ended June 30,								Ended June 30,
		2016				2015				2016				2015
Oil and gas sales		$	2,877,058			$	5,050,080			$	5,539,613			$	7,936,536
Gain on settled derivatives			1,043,026				847,198				1,043,026				1,980,619
Loss on the mark-to-market of derivatives			(4,272,849	)			(1,956,155	)			(4,288,736	)			(1,588,826	)
Total revenues			(352,765	)			3,941,123				2,293,903				8,328,329
Operating expenses:
Production expenses			652,882				1,153,663				1,400,639				2,143,520
Production taxes			292,080				555,152				568,028				841,344
General and administrative			311,061				84,608				476,461				207,729
Depletion of oil and gas properties			1,091,843				2,937,744				3,114,347				5,567,776
Impairment of oil and gas properties			–				21,639,000				5,219,000				21,639,000
Accretion of discount on asset retirement obligations			8,125				7,932				16,258				15,861
Total operating expenses			2,355,991				26,378,099				10,794,733				30,415,230
Net operating loss			(2,708,756	)			(22,436,976	)			(8,500,830	)			(22,086,901	)
Other income (expense):
Interest expense			(261,898	)			(1,547,172	)			(1,696,544	)			(3,114,420	)
Total other income (expense)			(261,898	)			(1,547,172	)			(1,696,544	)			(3,114,420	)
Loss before provision for income taxes			(2,970,654	)			(23,984,148	)			(10,197,374	)			(25,201,321	)
Provision for income taxes			–				5,957,649				–				6,593,040
Net income (loss)		$	(2,970,654	)		$	(18,026,499	)		$	(10,197,374	)		$	(18,608,281	)

 

 

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Financial Statements

(Unaudited)

 

The assets and liabilities subject to the BRHC Transaction have been retroactively reclassified as assets and liabilities from discontinued operations on the Company’s balance sheet as of December 31, 2015.

 

Assets and liabilities reclassified as assets and liabilities from discontinued operations as of December 31, 2015 consisted of the following:

 

		December 31,
		2015
ASSETS
Assets from discontinued operations, current
Derivative instruments		$	1,154,400
Accounts receivable			5,038,146
Prepaid expenses			37,100
Total assets from discontinued operations, current			6,229,646
Assets from discontinued operations, long term
Oil and natural gas properties, full cost method of accounting
Proved properties			131,168,906
Unproved properties			10,394
Total oil and natural gas properties, full cost method of accounting			131,179,300
Less, accumulated depletion and allowance for impairment			(99,371,070	)
Total assets from discontinued operations, long term			31,808,230
Total assets from discontinued operations		$	38,037,876
LIABILITIES
Liabilities from discontinued operations, current
Accounts payable		$	7,906,438
Accrued expenses			55,830
Current portion of revolving credit facility and long term debt			60,350,629
Total liabilities from discontinued operations, current			68,312,897
Liabilities from discontinued operations, long term
Asset retirement obligations			368,089
Total liabilities from discontinued operations, long term			368,089
Total liabilities from discontinued operations		$	68,680,986

 

 

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Financial Statements

(Unaudited)

 

Note 5 – Joint Venture

 

On July 20, 2015, the Company signed a definitive agreement with an affiliate of Merced Capital (“Merced”) to form a joint venture that will acquire and develop Williston Basin non-operated assets. The joint venture will be funded by Merced with an initial investment target of $50 Million. Investments will be subject to Merced approval, and will be managed by the Company.

 

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

 

We have not yet commenced operations pursuant to this joint venture, but continue to actively evaluate investment opportunities with Merced.

 

Note 6 – Property and Equipment

 

Property and equipment at June 30, 2016 and December 31, 2015, consisted of the following:

 

		June 30,				December 31,
		2016				2015
Property and equipment		$	139,004			$	139,004
Less: Accumulated depreciation and amortization			(105,221	)			(97,857	)
Total property and equipment, net		$	33,783			$	41,147

 

All of the oil and gas assets have been classified as non-current assets from discontinued operations on the balance sheet as of December 31, 2015 as the Company effectively disposed of those assets as part of the restructuring discussed in Note 4 – Debt Restructuring.

 

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

 

		Six Months Ended
		June 30,
		2016				2015
Depletion of costs for evaluated oil and gas properties (1)		$	3,114,347			$	5,567,776
Depreciation and amortization of other property and equipment			7,364				8,276
Total depreciation, amortization and depletion		$	3,121,711			$	5,576,052

⁽¹⁾  Presented as an element of loss from discontinued operations, net of income taxes.

 

Impairment of Oil and Gas Properties

As a result of currently prevailing low commodity prices and their effect on the proved reserve values of properties in 2016, we recorded non-cash ceiling test impairments of $5,219,000 and $21,639,000 for the six months ended June 30, 2016 and 2015, respectively. The expense associated with the impairments is presented as part of loss from discontinued operations, net of income taxes. The impairment charges affected our reported net income but did not reduce our cash flow.

 

 

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Financial Statements

(Unaudited)

 

Note 7 – Oil and Gas Properties

 

The following table summarizes gross and net productive oil wells by state at June 21, 2016 (prior to their disposition through our debt restructuring) and June 30, 2015. A net well represents our percentage ownership of a gross well. The following table does not include wells in which our interest is limited to royalty and overriding royalty interests. The following table also does not include wells which were awaiting completion, in the process of completion or awaiting flow back subsequent to fracture stimulation.

 

	June 21, 2016				June 30, 2015
	Gross		Net		Gross			Net
North Dakota	352		10.64			286			8.59
Montana	5		0.37			5			0.37
Total	357		11.01			291			8.96

 

The Company’s oil and gas properties consisted of all acreage acquisition costs (including cash expenditures and the value of stock consideration), drilling costs and other associated capitalized costs. As of June 21, 2016 (prior to their disposition through our debt restructuring) and June 30, 2015, our principal oil and gas assets included approximately 7,016 and 8,566 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 six months ended June 30, 2016 and 2015, respectively:

 

		Six Months Ended
		June 30,
		2016				2015
Purchases of oil and gas properties and development costs for cash		$	4,858,134			$	12,677,179
Purchase of oil and gas properties accrued at period-end			3,155,016				9,203,387
Purchase of oil and gas properties accrued at beginning of period (prior to disposition)			(6,899,503	)			(9,364,796	)
Capitalized asset retirement costs			4,737				41,695
Total purchase and development costs, oil and gas properties		$	1,118,384			$	12,557,465

 

2016 Acquisitions

During the six months ended June 30, 2016, we did not purchase any oil and gas properties.

 

2016 Divestitures

During the six months ended June 30, 2016, we sold approximately 14 net leasehold acres oil and gas properties for total proceeds of $94,628. No gain or loss was recorded pursuant to the sales.

 

2016 Disposition in Debt Restructuring

On June 21, 2016 we disposed of all of our oil gas properties, with net carrying costs of $24,498,638, as part of our debt restructuring as outlined in Note 4 – Debt Restructuring.

 

2015 Acquisitions

During the six months ended June 30, 2015, we purchased a total of approximately 9 net leasehold acres of oil and gas properties. In consideration for the assignment, we paid the sellers a total of approximately $102,928.

 

2015 Divestitures

During the six months ended June 30, 2015, we sold approximately 9 net leasehold acres of oil and gas properties for total proceeds of $103,000. No gain or loss was recorded pursuant to the sales.

 

Undeveloped Acreage Expirations

During the six months ended June 30, 2016, we had leases encompassing 1,079 net acres expire with carrying costs of $650,816 that had been reserved and transferred to the full cost pool subject to depletion in 2015.

 

 

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Financial Statements

(Unaudited)

 

Note 8 – Asset Retirement Obligation

 

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

 

The following table summarizes the Company’s asset retirement obligation transactions recorded in accordance with the provisions of FASB ASC 410-20-25 during the six months ended June 30, 2016 and 2015:

 

		Six Months Ended
		June 30,
		2016				2015
Beginning ARO		$	368,089			$	286,804
Liabilities incurred for new wells placed in production			4,737				41,695
Accretion of discount on ARO			16,258				15,861
Liability relieved in debt restructuring			(389,084	)			–
Ending ARO		$	–			$	344,360

 

The ARO as of December 31, 2015 has been reclassified to non-current liabilities from discontinued operations on the balance sheet.

 

Note 9 – Related Party

 

We leased office space on a month to month basis where the lessor is an entity owned by our former CEO and current Chairman of the Board of Directors, Bradley Berman. Pursuant to the lease, we occupied approximately 2,813 square feet of office space. We terminated the lease concurrent with our move to another location on June 30, 2016. The lease had base rents of $2,110 per month, plus common area operations and maintenance charges, and monthly parking fees of $240 per month, for the period from November 15, 2013 to October 31, 2014, and was subject to increases of $117 per month beginning November 1, 2014 and for each of the subsequent annual periods. We paid a total of $36,183 and $35,128 to this entity during the six months ended June 30, 2016 and 2015, respectively.

 

Note 10 – Derivative Instruments

 

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

 

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

 

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

 

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

 

As of June 30, 2016, the Company had no outstanding derivative contracts. All of our then outstanding derivative contracts, with a mark-to-market liability valuation of $3,134,336, were transferred to BRHC as part of the debt restructuring.

 

 

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:

 

		Six Months Ended
		June 30,
		2016				2015
Realized gain on derivatives:
Crude oil fixed price swaps		$	922,872			$	1,589,818
Crude oil collars			120,154				390,801
Realized gain on derivatives, net		$	1,043,026			$	1,980,619
Loss on the mark-to-market of derivatives:
Crude oil fixed price swaps		$	(4,157,491	)		$	(1,161,398	)
Crude oil collars			(131,245	)			(427,428	)
Loss on the mark-to-market of derivatives, net		$	(4,288,736	)		$	(1,588,826	)

 

Balance Sheet Offsetting of Derivative Assets and Liabilities

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

 

		December 31, 2015
					Gross			Net
		Gross			amounts			amounts of
		amounts of			offset			assets
		recognized			on balance			on balance
		assets			sheet			sheet
Commodity derivative assets		$	1,154,417		$	(17	)	$	1,154,400
		December 31, 2015
					Gross			Net
		Gross			amounts			amounts of
		amounts of			offset			liabilities
		recognized			on balance			on balance
		liabilities			sheet			sheet
Commodity derivative liabilities		$	–		$	–		$	–

 

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

 

		December 31,
		2015
Current assets from discontinued operations		$	1,154,400
Non-current assets from discontinued operations			–
Net amount of assets on the balance sheet			1,154,400
Current liabilities from discontinued operations			–
Non-current liabilities from discontinued operations			–
Net amounts of liabilities on the balance sheet			–
Total derivative assets, net		$	1,154,400

 

 

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Financial Statements

(Unaudited)

 

Note 11 – Fair Value of Financial Instruments

 

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

 

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

 

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

 

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

 

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

 

The following schedule summarizes the valuation of financial instruments at fair value on a recurring basis in the balance sheets as of June 30, 2016 and December 31, 2015:

 

		Fair Value Measurements at June 30, 2016
		Level 1			Level 2			Level 3
Assets
Cash and cash equivalents		$	1,038,567		$	–		$	–
Derivative Instruments (crude oil swaps and collars)			–			–			–
Total assets			1,038,567			–			–
Liabilities
Derivative Instruments (crude oil swaps and collars)			–			–			–
Revolving credit facilities and long term debt			–			–			–
Total Liabilities			–			–			–
		$	1,038,567		$	–		$	–

 

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

 

There were no transfers of financial assets or liabilities between Level 1 and Level 2 inputs for the six months ended June 30, 2016 and 2015.

 

Level 2 liabilities include Revolving credit facilities. No fair value adjustment was necessary during the six months ended June 30, 2016 and 2015.

 

The derivative instruments and revolving credit facilities are reflected on the balance sheets as part of assets or liabilities from discontinued operations as detailed in Note 4 – Debt Restructuring.

 

 

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Financial Statements

(Unaudited)

 

Note 12 – Revolving Credit Facilities and Long Term Debt

 

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

 

Availability under the Senior Credit Facility was at all times subject to the then-applicable borrowing base, determined by Cadence in a manner consistent with the normal and customary oil and gas lending practices of Cadence. Availability was initially set at $7 million and was subject to periodic redeterminations. Subject to availability under the borrowing base, the Company could 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 was 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 was also required to pay a quarterly fee of 0.50% on any unused portion of the borrowing base, as well as a facility fee of 0.90% of the initial and any subsequent additions to the borrowing base.

 

The Senior Credit Facility’s maturity date of August 8, 2016, was subsequently amended to January 15, 2017 pursuant to the amendment on March 30, 2015. The Company could prepay the entire amount of Base Rate loans at any time, and could prepay the entire amount of LIBOR loans upon at least three business days’ notice to Cadence. The Senior Credit Facility was 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.

 

As part of the debt restructuring outline in Note 4 – Debt Restructuring, the Company transferred the obligation with a balance outstanding of $29,400,000 under the Senior Credit Facility to BRHC. The Company had borrowings of $27.75 million outstanding under the Senior Credit Agreement as of December 31, 2015.

 

Subordinated Credit Facility

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

 

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

 

The Subordinated Credit Facility matured on June 30, 2017. Upon at least three business days’ written notice, the Company could 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, would 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 were accompanied by an applicable premium, as set forth in the Subordinated Credit Agreement. The Subordinated Credit Facility was 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.

 

 

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Financial Statements

(Unaudited)

 

The first funding from the Subordinated Credit Facility 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 a previously outstanding revolving credit facility. We had drawn an additional $14,700,000, net of $300,000 original issue discounts, through December 31, 2015. The Company had borrowings of $30.0 million outstanding under the Subordinated Credit Facility as of December 31, 2015. The obligations under the Subordinated Credit Facility, $30.0 million of principal and $2,931,369 of PIK interest payable, were transferred to BRHC and converted to equity in BRHC as part of the debt restructuring outlined in Note 4- Debt Restructuring.

 

Intercreditor Agreements and Covenants

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

 

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

 

 

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Financial Statements

(Unaudited)

 

Covenant Violations

The Company was out of compliance with the collateral coverage ratio covenant as of March 31, 2016 and December 31, 2015 and the current ratio covenant as defined by the Subordinated Credit Facility as of March 31, 2016. Additionally, the audit report the Company received with respect to its financial statements as of December 31, 2015 contains an explanatory paragraph expressing uncertainty as to the Company’s ability to continue as a going concern, the delivery of which constitutes a default under both its Senior Credit Facility and Subordinated Credit Facility. See Note 3, “Going Concern”, for additional information. The Company received a waiver for all debt covenants as of December 31, 2015 and March 31, 2016 as part of the debt restructuring outlined in Note 4 – Debt Restructuring.

 

Debt Discount, Detachable Warrants

In connection with the Subordinated Credit Facility, the Company agreed to issue to the lenders detachable warrants to purchase up to 5,000,000 shares of the Company’s common stock at an exercise price of $0.65 per share. The warrants expire on August 8, 2018. Proceeds from the loan were allocated between the debt and equity based on the relative fair values at the time of issuance, resulting in a debt discount of $2,473,576 at issuance that is presented as a debt discount on the balance sheet and is being amortized using the effective interest method over the life of the credit facility, which matures on June 30, 2017. A total of $-0- and $321,763 was amortized during the six months ended June 30, 2016 and 2015. The remaining unamortized balance of the debt discount attributable to the warrants is $-0- as of June 30, 2016. The amortization of the debt discount attributable to the warrants was accelerated in 2015 to fully amortize the discount as of December 31, 2015 when the related debt became payable on demand due to a default on the related debt. As part of the debt restructuring all related warrants were retired and cancelled.

 

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

 

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

 

⁽¹⁾ Due to existing and anticipated covenant violations, the Company’s Senior Credit Facility and Subordinated Credit Facility were classified as current December 31, 2015 and are presented as part of current liabilities from discontinued operations on the balance sheet.

 

Net proceeds of $29.4 million was received from our $30 million in advances due to $600,000 of OID pursuant to the Subordinated Credit Agreement at issuance that is presented as a debt discount on the balance sheet and was being amortized using the effective interest method over the life of the credit facility, which matures on June 30, 2017. A total of $-0- and $84,858 was amortized during the six months ended June 30, 2016 and 2015, respectively. The remaining unamortized balance of the debt discount attributable to the OID is $-0- as of June 30, 2016 and December 31, 2015 as the amortization was accelerated in 2015 to fully amortize the discount as of December 31, 2015 when the related debt became payable on demand due to a default on the related debt.

 

 

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Financial Statements

(Unaudited)

 

The following presents components of interest expense, presented as a component of loss from discontinued operations, for the six months ended June 30, 2016 and 2015, respectively:

 

		Six Months Ended
		June 30,
		2016				2015
Accrued PIK interest		$	330,740			$	634,919
Amortization of OID			–				84,858
Interest and commitment fees			1,373,023				2,177,431
Amortization of debt issuance costs			–				190,780
Amortization of warrant costs			–				321,763
Less interest capitalized to the full cost pool of our proved oil & gas properties			(7,219	)			(295,331	)
		$	1,696,544			$	3,114,420

 

Note 13 – Changes in Stockholders’ Equity

 

Preferred Stock

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

 

Common Stock

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

 

Note 14 – Options

 

Options Granted

No options were granted during the six months ended June 30, 2016.

 

The Company recognized a total of $315,648, and $313,751 of compensation expense during the six months ended June 30, 2016 and 2015, respectively, on common stock options issued to Employees and Directors that are being amortized over the implied service term, or vesting period, of the options. The remaining unamortized balance of these options is $1,176,572 as of June 30, 2016.

 

Options Exercised

No options were exercised during the six months ended June 30, 2016 and 2015.

 

Options Forfeited

No options were forfeited during the six months ended June 30, 2016 and 2015.

 

Note 15 – Warrants

 

Warrants Granted

No warrants were granted during the six months ended June 30, 2016 and 2015.

 

We recognized a total of $-0- and $321,763 of finance expense during the six months ended June 30, 2016 and 2015, respectively, on common stock warrants issued to lenders. All warrants granted pursuant to debt financings are amortized over the remaining life of the respective loan.

 

Warrants Exercised

No warrants were exercised during the six months ended June 30, 2016 and 2015.

 

Warrants Expired and Cancelled

A total of 500,000 warrants, all at an exercise price of $0.95, expired during the six months ended June 30, 2016. Additionally 5,000,000 warrants, at an exercise price of $0.65, were cancelled and retired as part of the debt restructuring outlined in Note 4 – Debt restructuring. No options were forfeited during the six months ended June 30, 2015.

 

 

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Financial Statements

(Unaudited)

 

Note 16 – Income Taxes

 

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

 

We currently estimate that our effective tax rate for the year ending December 31, 2016 will be 0%. Losses incurred during the period from April 9, 2011 (inception) to June 30, 2016 could be used to offset future tax liabilities. Accounting standards require the consideration of a valuation allowance for deferred tax assets if it is “more likely than not” that some component or all of the benefits of deferred tax assets will not be realized. As of June 30, 2016, net deferred tax assets were $11,537,106, after an offsetting reduction in deferred tax liabilities of $4,962, primarily related to net operating loss carryforwards. A valuation allowance of approximately $11,537,106 was applied to the remaining net deferred tax assets. We have not provided any valuation allowance against our deferred tax liabilities, which were netted against our deferred tax assets.

 

The tax benefit for the six months ended June 30, 2016 was $-0- as the Company utilized a portion of the Company’s deferred tax asset, which was offset by a corresponding reduction in the valuation allowance on the utilized deferred tax asset.

 

In accordance with FASB ASC 740, the Company has evaluated its tax positions and determined there are no significant uncertain tax positions as of any date on, or before June 30, 2016.

 

Note 17 – Commitments and Contingencies

 

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

 

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

 

Note 18 – Subsequent Events

 

There were no subsequent events to report through the date of this filing.

 

 

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

 

Cautionary Statements

 

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

 

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

 

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

 

·

volatility or decline of our stock price;

·

low trading volume and illiquidity of our common stock, and possible application of the SEC’s penny stock rules;

·

potential fluctuation in quarterly results;

·

our failure to collect payments owed to us;

·

material defaults on monetary obligations owed us, resulting in unexpected losses;

·

inability to obtain capital from investment partners to acquire oil and gas properties to manage;

·

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;

·

decline in oil prices;

·

failure to discover or produce commercial quantities of oil, natural gas or other hydrocarbons;

·

cost overruns incurred on our oil and gas prospects, causing unexpected operating deficits;

·

drilling of dry holes;

·

acquisition of oil and gas leases that are subsequently lost due to the absence of drilling or production;

·

dissipation of existing assets and failure to acquire or grow a new business;

·

litigation, disputes and legal claims involving outside parties; and

·

risks related to our ability to be listed on a national securities exchange and meeting listing requirements

 

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

 

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

 

 

Overview and Outlook

 

On June 21, 2016 we closed on a debt restructuring transaction with our secured lenders that is described below in “Recent Developments.” Following the transaction, our focus is on managing the oil and gas assets in which we will continue to have an indirect minority interest. In addition, we will continue to pursue distressed asset acquisitions in the Bakken and/or Three Forks and other formations that may be acquired with capital from our secured lenders as part of the restructuring terms, existing joint venture partners or other capital providers.

 

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

 

Recent Developments

 

On March 29, 2016, the Company entered into an Asset Contribution Agreement with Black Ridge Holding Company, LLC, a Delaware limited liability company (“BRHC”) which was recently formed by the Company to contribute and assign to BRHC, all of the Company's (i) oil and gas assets (including working capital and tangible and intangible assets) (the “Assets”), (ii) outstanding balances under that certain Credit Agreement between the Company, as borrower, and Cadence Bank, N.A. (“Cadence”), as lender (the “Cadence Credit Facility”) and the outstanding balances under that certain Credit Agreement between the Company, as borrower, and the several banks and other financial institutions or entities from time to time parties thereto (the “Chambers”), and Chambers, as administrative agent (the “Chambers Credit Facility”) and (iii) all current liabilities related to the Assets, in exchange for 5% of the issued and outstanding Class A Units (the “Class A Units”) in BRHC (the “Asset Contribution”). On March 29, 2016, affiliates of Chambers Energy Management, LP (“Chambers”) (specifically, Chambers Energy Capital II, LP and CEC II TE, LLC (collectively, the “Chambers Affiliates”)) entered into a Debt Contribution Agreement between BRHC and the Chambers Affiliates, pursuant to which BRHC will issue a number of Class A Units representing 95% of the Class A Units of BRHC to the Chambers Affiliates in exchange for the release of BRHC's obligations under the Chambers Credit Facility (the “Satisfaction of Debt” and, together with the Asset Contribution, the “BRHC Transaction”). Concurrent with the Satisfaction of Debt, each warrant originally issued with the Chambers Credit Facility shall be automatically retired and cancelled. The closing of the BRHC Transaction was subject to the Company obtaining the approval of stockholders holding a majority of its outstanding capital stock and to the Company having assigned the Cadence Credit Agreement to BRHC with Cadence’s consent, and BRHC and Cadence entering into any applicable amendment agreements related to such assignment and waiver of financial covenant ratio compliance for the quarter ended December 31, 2015 and quarter ending June 30, 2016. On June 21, 2016, the Company satisfied all of these conditions and, for accounting purposes, the BRHC Transaction has been consummated. The parties have agreed that the BRHC Transaction, the Asset Contribution and the Satisfaction of Debt are effective, for valuation purposes, as of April 1, 2016.

 

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

 

·

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

·

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

·

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

 

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

 

 

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

 

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

 

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

 

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

 

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

 

 

Operational Highlights

 

Continuing Operations

 

Under our structure following our debt restructuring, our revenues from continuing operations consist of management fees, which we began earning on June 21, 2016, the date of the restructuring, amounted to $49,451. Our management services agreement with BRHC includes management services fees amounting to $500,000 per quarter and was effective beginning April 1, 2016. Management services fees due, amounting to $450,549, for the period from the effective date of April 1, 2016 to the date the restructuring transaction was finalized, were treated as a reduction in the amounts due to BRHC in the restructuring transaction.

 

General and administrative expenses from continuing operation, excluding those general and administrative expenses directly related to the oil and gas assets and debt transferred to BRHC in the restructuring were $614,661 in the three months ended June 30, 2016 as compared to $645,837 in the three months ended June 30, 2015.

 

Discontinued Operations

 

While we no longer have a direct ownership interest in oil and gas operations after the restructuring transaction, our discontinued oil and gas operations were a significant portion of our activity from April 1, 2016 to through June 21, 2016 and had the following results:

 

·

Production was 1,319 Boe per day (82 days of production) compared to the second quarter of 2015 production of 1,123 BOE per day and 1,543 BOE per day compared to the first quarter of 2016;

·

Production expenses were $6.04 per BOE, compared to $11.29 per BOE in the second quarter of 2015, largely due to lower water disposal costs and other costs on the CCU and Teton project wells which represented 58% of the oil production; and

·

Realized $3.8 million of cash flow from operating activities of discontinued operations

 

Our production during the 82 day period up to the date of the restructuring was 108,159 Boe in the second quarter of 2015, as compared to second quarter of 2015 production of 102,182 Boe.

 

Oil and gas sales amounted to $2.9 million during the second quarter of 2016 as compared to $5.1 for the same period in 2015. Realized prices on a Boe basis decreased 46% before the effect of settled derivatives and 37% after the effect of settled derivatives in the second quarter of 2016 as compared to the second quarter of 2015. The realized gains on settled derivatives amounted to $1.0 million in the second quarter of 2016 and we recorded an unrealized loss of $4.3 million on the mark-to-market of derivatives through the period up to the date of debt restructuring. Significant changes in crude oil and natural gas prices have had a material impact on our results of operations and our balance sheet.

 

 

Production History

 

The following table presents information about our produced oil and gas volumes during the three and six month periods ended June 30, 2016 and 2015, respectively. All of this activity represents discontinued operations following the transfer of oil and gas assets as part of the BRHC transaction

 

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2016				2015				2016				2015
Net Production:
Oil (Bbl)			77,211				90,118				184,731				163,041
Natural gas (Mcf)			185,691				72,381				383,114				170,695
Barrel of oil equivalent (Boe)			108,159				102,182				248,583				191,490
Average Sales Prices:
Oil (per Bbl)		$	36.71			$	54.71			$	29.70			$	47.06
Effect of oil hedges on average price (per Bbl)		$	13.51			$	9.40			$	5.65			$	12.15
Oil net of hedging (per Bbl)		$	50.22			$	64.11			$	35.35			$	59.21
Natural gas (per Mcf)		$	0.23			$	1.66			$	.14			$	1.55
Realized price on a Boe basis, net of settled derivatives		$	36.24			$	57.71			$	26.48			$	51.79
Average Production Costs:
Oil (per Bbl)		$	8.33			$	12.50			$	7.51			$	12.68
Natural gas (per Mcf)		$	0.05			$	0.38			$	0.03			$	0.45
Barrel of oil equivalent (Boe)		$	6.04			$	11.29			$	5.63			$	11.19

 

Depletion of Oil and Natural Gas Properties

 

Our depletion expense is driven by many factors including certain exploration costs involved in the development of producing reserves, production levels and estimates of proved reserve quantities and future developmental costs. The following table presents our depletion expenses for the six months ended June 30, 2016 and 2015, respectively.

 

		Six Months Ended
		June 30,
		2016				2015
Depletion of oil and natural gas properties		$	3,114,347			$	5,567,776

 

Productive Oil Wells

 

The following table summarizes gross and net productive oil wells by state at June 20, 2016 (the day preceding our debt restructuring) and June 30, 2015, respectively. A net well represents our percentage ownership of a gross well. The following table does not include wells in which our interest is limited to royalty and overriding royalty interests. The following table also does not include wells which were awaiting completion, in the process of completion or awaiting flow back subsequent to fracture stimulation.

 

	June 20, 2016				June 30, 2015
	Gross		Net		Gross			Net
North Dakota	352		10.64			286			8.59
Montana	5		0.37			5			0.37
Total	357		11.01			291			8.96

 

 

Results of Operations for the Three Months Ended June 30, 2016 and 2015.

 

While our oil and gas operations have been transferred to BRHC as result our debt restructuring, the majority of the periods presented we operated as an oil and gas company, with only nine days of the 2016 period strictly as an asset management company. As such, we are presenting the following including the results of the discontinued operations for a more constructive comparison. The following table summarizes selected items from the statement of operations combined with the results from our discontinued operations for the three months ended June 30, 2016 and 2015, respectively.

 

		Three Months Ended
		June 30,								Increase /
		2016				2015				(Decrease)
Oil and gas sales		$	2,877,058			$	5,050,080			$	(2,173,022	)
Management fee revenue			49,451				–				49,451
Gain on settled derivatives			1,043,026				847,198				195,828
Loss on mark-to-market of derivatives			(4,272,849	)			(1,956,155	)			(2,316,694	)
Total revenues:			(303,314	)			3,941,123				(4,244,437	)
Operating expenses:
Production expenses			652,882				1,153,663				(500,781	)
Production taxes			292,080				555,152				(263,072	)
General and administrative			925,722				730,445				195,277
Depletion of oil and gas properties			1,091,843				2,937,744				(1,845,901	)
Impairment of oil and natural gas properties			–				21,639,000				(21,639,000	)
Accretion of discount on ARO			8,125				7,932				193
Depreciation and amortization			3,479				4,009				(530	)
Total operating expenses:			2,974,131				27,027,945				(24,053,814	)
Net operating income (loss)			(3,277,445	)			(23,086,822	)			19,809,377
Total other income (expense)			41,359,252				(1,540,465	)			42,899,717
Net income (loss) before provision for income taxes			38,081,807				(24,627,287	)			62,709,094
Provision for income taxes			–				5,957,649				(5,957,649	)
Net income (loss)		$	38,081,807			$	(18,669,638	)		$	56,751,445

 

Oil and Natural Gas Sales

 

We recognized $2,877,058 in revenues from sales of crude oil and natural gas, excluding gains on derivatives, for the three months ended June 30, 2016, compared to revenues of $5,050,080 for the three months ended June 30, 2015, a decrease of $2,173,022, or 43%. The decrease in revenues was driven by a 46% decrease in prices on a BOE basis before the effects of derivatives, partially offset by a 6% increase in production on a BOE basis. We had 11.01 net producing wells as of June 20, 2016 (prior to our restructuring), compared to 8.96 net producing wells as of June 30, 2015.

 

Included in the revenues for the three month period ended June 30, 2015 were revenues of $1,264,226 related to production from prior periods for the Dahl Federal. Recognition of the Dahl Federal revenues continues to be delayed until title issues related to riparian rights in the Missouri River were resolved.

 

Management Fee Revenue

 

Management fees represent fees of $49,451 earned for the nine day period following the completion of the BRHC transaction.

 

Derivatives

 

For the three months ended June 30, 2016, we had a gain on settled derivatives of $1,043,026, compared to a gain on settled derivatives of $847,198 for the same period in 2015.

 

We had a mark-to-market derivative loss of $4,272,849 in the three months ended June 30, 2016, resulting in a net derivative liability of $3,134,336 as of the date of the transfer to BRHC, largely due to a rebound in market prices for oil during the quarter. In the second quarter of 2015, we had mark-to-market losses of $1,956,155.

 

 

Production Expenses

 

Production expenses were $652,882 and $1,153,663 for the three months ended June 30, 2016 and 2015, respectively, a decrease of $500,781, or 43%. Our production expenses are lower than the comparative period due decreased water disposal and other costs, primarily in our Teton Project and CCU Project areas where water cuts are lower and capital has been deployed to help drive down water disposal costs. On a per unit basis, production expenses decreased from $11.29 per Boe in the three months ended June 30, 2015 to $6.04 per Boe in the three months ended June 30, 2016. The decrease in production expenses on a BOE basis was again the result of lower water disposal costs.

 

Production expenses for the three month period ended June 30, 2015 included production expenses of $83,477 related to production from prior periods for the Dahl Federal. Recognition of the Dahl Federal revenue and expenses were delayed until title issues related to riparian rights in the Missouri River were resolved.

 

Production Taxes

 

Our production taxes were $292,080 and $555,152 for the three months ended June 30, 2016 and 2015, respectively, a decrease of $263,072, or 47%. Production taxes are paid based on realized oil and natural gas sales. Production taxes represented 10.2% and 11.0% of oil and gas sales in the three months ended June 30, 2016 and 2015, respectively. The decrease corresponds to a reduction in the North Dakota oil tax rate from 10.5% of revenue to 10.0% of revenue.

 

Production taxes for the three month period ended June 30, 2015 included production taxes of $140,382 related to production from prior periods for the Dahl Federal. Recognition of the Dahl Federal revenues and expenses was delayed until title issues related to riparian rights in the Missouri River were resolved.

 

General and Administrative Expenses

 

General and administrative expenses for the three months ended June 30, 2016 were $925,722, compared to $730,445 for the three months ended June 30, 2015, an increase of $195,277, or 27%. The increase in general and administrative expenses was primarily due to legal and other costs associated with the BRHC transaction. General and administrative expenses per Boe produced increased from $7.15 to $8.56.

 

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 $1,091,843 and $2,937,744 for the three months ended June 30, 2016 and 2015, respectively, a decrease of $1,845,901, or 63%. The decrease was due to impairment write-downs reducing the basis in our full cost pool over 2015 and the first half of 2016 with the continuing slump in oil prices.

 

Impairment of Oil and Natural Gas Properties

 

As a result of current prevailing low commodity prices and their effect on the proved reserve values of properties in 2015 and 2016 we recorded a non-cash ceiling test impairment of $21,639,000 or $211.77 per Boe for the three months ended June 30, 2015. No such impairment was taken in 2016 prior to the transfer of our oil and gas assets to BRHC. The impairment charge affected our reported net income but did not reduce our cash flow.

 

Depreciation and Accretion

 

Depreciation expense for the three months ended June 30, 2016 was $3,479, compared to $4,009 for the three months ended June 30, 2015. Accretion of the discount on asset retirement obligations was $8,125 and $7,932 for the three month periods ended June 30, 2016 and 2015, respectively.

 

 

Other Income and (Expense)

 

Other income and (expense) for the three months ended June 30, 2016 was $41,359,252, compared to ($1,540,465) for the three months ended June 30, 2015. The net other income and (expense) for the three months ended June 30, 2016 consisted of a gain on debt restructuring of $41,621,150, as the conversion of debt to equity within BRHC and our retention of 3.88% ownership interest in BRHC exceeded the net book value of the assets and labilities we transferred to BRHC, and ($261,898) of interest expense. Interest expense in the 2016 period included $330,740 of PIK interest applied to our debt balances. The net other income and (expense) for the three months ended June 30, 2015 consisted of $6,707 of other income and ($1,547,172) of interest expense. Interest expense included $161,355 of amortized warrant costs, $42,459 of amortization related to original issue discounts, $320,805 of PIK interest applied to our debt balances and $94,458 of amortized debt financing costs for the three months ended June 30, 2015. Additionally, we capitalized $139,340 of interest expense into our full cost pool related to interest costs incurred while our wells were being drilled and completed.

 

Provision for Income Taxes

 

We had no income tax expense or benefit for the three months ended June 30, 2016 as the Company reserved against the deferred tax asset due the uncertainty of realization of the benefit. We had income tax benefits of $5,957,649 for the three months ended June 30, 2015 driven by the Company’s loss before provision for income taxes of $24,627,287.

 

 

Results of Operations for the Six Months Ended June 30, 2016 and 2015.

 

While our oil and gas operations have been transferred to BRHC as result our debt restructuring, the majority of the periods presented we operated as an oil and gas company, with only nine days of the 2016 period strictly as an asset management company. As such, we are presenting the following including the results of the discontinued operations for a more constructive comparison. The following table summarizes selected items from the statement of operations combined with the results from our discontinued operations for the six months ended June 30, 2016 and 2015, respectively.

 

		Six Months Ended
		June 30,								Increase /
		2016				2015				(Decrease)
Oil and gas sales		$	5,539,613			$	7,936,536			$	(2,396,923	)
Gain on settled derivatives			1,043,026				1,980,619				(937,593	)
Loss on mark-to-market of derivatives			(4,288,736	)			(1,588,826	)			(2,699,910	)
Management fee revenues			49,451				–				49,451
Total revenues:			2,343,354				8,328,329				(5,984,975	)
Operating expenses:
Production expenses			1,400,639				2,143,520				(742,881	)
Production taxes			568,028				841,344				(273,316	)
General and administrative			1,776,030				1,540,453				235,577
Depletion of oil and gas properties			3,114,347				5,567,776				(2,453,429	)
Impairment of oil and gas properties			5,219,000				21,639,000				(16,420,000	)
Accretion of discount on ARO			16,258				15,861				397
Depreciation and amortization			7,364				8,276				(912	)
Total operating expenses:			12,101,666				31,756,230				(19,654,564	)
Net loss			(9,758,312	)			(23,427,901	)			13,669,589
Total other income (expense)			39,924,606				(3,107,713	)			43,032,319
Income (loss) before provision for income taxes			30,166,294				(26,535,614	)			56,701,908
Provision for income taxes			–				6,593,040				(6,593,040	)
Net income (loss)		$	30,166,294			$	(19,942,574	)		$	50,108,868

 

Oil and Natural Gas Sales

 

We recognized $5,539,613 in revenues from sales of crude oil and natural gas, excluding gains on derivatives, for the six months ending June 30, 2016, compared to revenues of $7,936,536 for the six months ending June 30, 2015, a decrease of $2,396,923, or 30%. The decrease in revenues was driven by a 46% decrease in prices on a BOE basis before the effects of derivatives, offset by a 30% increase in production on a BOE basis. We had 11.01 net producing wells as of June 30, 2016, compared to 8.96 net producing wells as of June 30, 2015.

 

Management Fee Revenue

 

Management fees represent fees of $49,451 earned for the nine day period following the completion of the BRHC transaction.

 

Derivatives

 

For the six months ending June 30, 2016, we had a gain on settled derivatives of $1,043,026, compared to a gain on settled derivatives of $1,980,619 for the same period in 2015.

 

We had a mark-to-market derivative loss of $4,288,736 in the six months ending June 30, 2016, resulting in a net derivative liability of $3,134,336 as of the date of the transfer to BRHC, largely due to a rebound in market prices for oil during the latter half of the period. In the six month period ended June 30, 2015 we had mark-to-market losses of $1,588,826.

 

 

Production Expenses

 

Production expenses were $1,400,639 and $2,143,520 for the six months ending June 30, 2016 and 2015, respectively, a decrease of $742,881, or 35%. On a per unit basis, production expenses decreased from $11.19 per Boe in the six months ending June 30, 2015 to $5.63 per Boe in the six months ending June 30, 2016. The decrease in production expenses was primarily a result of decreased water disposal costs as the wells put into production during the latter half of 2015 had lower water cuts and water disposal costs than the balance of our producing wells and workover expenses were lower in the 2016 period as compared to the 2015 period when we experienced high levels of workover expenses on wells shut-in while neighboring wells were completed.

 

Production Taxes

 

Our production taxes were $568,028 and $841,344 for the six months ending June 30, 2016 and 2015, respectively, a decrease of $273,316, or 32%. Production taxes are paid based on realized oil and natural gas sales. Production taxes represented 10.3% and 10.6% of oil and gas sales in the six months ending June 30, 2016 and 2015, respectively. The decrease corresponds to a reduction in the North Dakota oil tax rate from 10.5% of revenue to 10.0% of revenue.

 

General and Administrative Expenses

 

General and administrative expenses for the six months ending June 30, 2016 were $1,776,030, compared to $1,540,453 for the six months ending June 30, 2015, an increase of $235,577, or 15%. The increase in general and administrative expenses was primarily due to legal and other costs associated with the BRHC transaction. General and administrative expenses per Boe produced decreased from $8.04 to $7.14 due to increased production, particularly in the first quarter of 2016.

 

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 $3,114,347 and $5,567,776 for the six months ending June 30, 2016 and 2015, respectively, a decrease of $2,453,429, or 44%. The decrease was due primarily to decreases in the full cost pool due to the impairment losses of $71,272,000 taken in 2015 and $5,219,000 in the first quarter of 2016, offset by increased production. Depletion expense per Boe produced decreased from $29.08 in 2015 to $12.53 in 2016.

 

Impairment of Oil and Natural Gas Properties

 

As a result of currently prevailing low commodity prices and their effect on the proved reserve values of properties in throughout 2015 and the first half of 2016, we recorded a non-cash ceiling test impairment of $5,219,000 and $21,639,000 for the six months ended June 30, 2016 and 2015, respectively, or $20.99 and $113.00 per Boe, respectively for the same periods. The impairment charge affected our reported net income but did not reduce our cash flow.

 

Depreciation and Accretion

 

Depreciation expense for the six months ending June 30, 2016 was $7,364, compared to $8,276 for the six months ending June 30, 2015. Accretion of the discount on asset retirement obligations was $16,258 and $15,861 for the three month periods ended June 30, 2016 and 2015, respectively.

 

Other Income and (Expense)

 

Other income and (expense) for the six months ended June 30, 2016 was $39,924,606 compared to ($3,107,713) for the six months ended June 30, 2015. The net other income and (expense) for the six months ended June 30, 2016 consisted of a gain on debt restructuring of $41,621,150, as the conversion of debt to equity within BRHC and our retention of 3.88% ownership interest in BRHC exceeded the net book value of the assets and labilities we transferred to BRHC, and ($1,696,544) of interest expense. Interest expense in the 2016 period included $330,740 of PIK interest applied to our debt balances. The net other income and (expense) for the six months ended June 30, 2015 consisted of $3,114,420 of interest expense and $6,707 of other income. The $3,114,420 of interest expense included $321,763 of amortized warrant costs, $84,858 of amortization related to original issue discounts, $634,919 of PIK interest applied to our debt balances and $190,780 of amortized debt financing costs for the six months ended June 30, 2015. Additionally, we capitalized $295,331 of interest expense into our full cost pool related to interest costs incurred while our wells were being drilled and completed.

 

 

Provision for Income Taxes

 

We had no income tax benefit or expense in the six months ending June 30, 2016 and an income tax benefit of $6,593,040 for the six months ending June 30, 2015. In 2016, we could not recognize a tax benefit as we reserved against the deferred tax asset due to the uncertainty of the realization of the benefit. The tax benefit for the six months ending June 30, 2015 was primarily driven by the Company’s loss before provision for income taxes of $26,535,614.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Non-GAAP Financial Measures

 

In addition to reporting net income (loss) as defined under GAAP, we also present Adjusted Net Income (Loss) and Adjusted EBITDA. We define Adjusted Net Income (Loss) as net income (loss) excluding (i) gain on debt restructuring, net of tax, (ii) net of losses on the mark-to-market of derivatives, net of tax, and (iii) impairment of oil and gas assets, net of tax. We define Adjusted EBITDA as net income before (i) gain on debt restructuring, (ii) interest expense, (iii) income taxes, (iv) depreciation, depletion and amortization, (v) impairment of oil and natural gas properties, (vi) accretion of abandonment liability, (vii) loss on the mark-to-market of derivatives, and (viii) 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								Six Months Ended
		June 30,								June 30,
		2016				2015				2016				2015
Net income (loss)		$	38,081,807			$	(18,669,638	)		$	30,166,294			$	(19,942,574	)
Add back:
Gain on debt restructuring, net of tax (a)			(41,621,150	)			–				(41,621,150	)			–
Loss on mark-to-market of derivatives, net of tax (b)			4,272,849				1,467,155				4,288,736				1,191,826
Impairment of oil and gas properties, net of tax (c)			–				16,229,000				5,219,000				16,229,000
Adjusted net income (loss)		$	733,506			$	(973,483	)		$	(1,947,120	)		$	(2,521,748	)
Weighted average common shares outstanding - basic			47,979,990				47,979,990				47,979,990				47,979,990
Weighted average common shares outstanding - fully diluted			48,058,679				47,979,990				48,056,573				47,979,990
Net income (loss) per common share – basic		$	0.79			$	(0.39	)		$	0.63			$	(0.42	)
Add:
Change due to gain on debt restructuring, net of tax			(0.87	)			–				(0.87	)			–
Change due to loss on mark-to- market of derivatives, net of tax			0.09				0.03				0.09				0.03
Change due to impairment of oil and gas properties, net of tax			–				0.34				0.11				0.34
Adjusted net income (loss) per common share – basic		$	0.01			$	(0.02	)		$	(0.04	)		$	(0.05	)
Net income (loss) per common share –fully diluted		$	0.79			$	(0.39	)		$	0.63			$	(0.42	)
Add:
Change due to gain on debt restructuring, net of tax			(0.87	)			–				(0.87	)			–
Change due to loss on mark-to- market of derivatives, net of tax			0.09				0.03				0.09				0.03
Change due to impairment of oil and gas properties, net of tax			–				0.34				0.11				0.34
Adjusted net income (loss) per common share – fully diluted		$	0.01			$	(0.02	)		$	(0.04	)		$	(0.05	)

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

^(b)Adjusted to reflect tax expense, computed based on our effective tax rate of approximately 0% in 2016 and 25% in 2015, of $-0- and $489,000 for the three month ended June 30, 2016 and 2015, respectively, and $-0- and $397,000 for the six months ended June 30, 2016 and 2015, respectively.

^(c)Adjusted to reflect tax expense, computed based on our effective tax rate of approximately 0% in 2016 and 25% in 2015, of $-0- and $5,410,000 for the three month ended June 30, 2016 and 2015, respectively, and $-0- and $5,410,000 for the six months ended June 30, 2016 and 2015, respectively.

 

 

Black Ridge Oil & Gas, Inc.

Reconciliation of Adjusted EBITDA

(Unaudited)

 

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2016				2015				2016				2015
Net income (loss)		$	38,081,807			$	(18,669,638	)		$	30,166,294			$	(19,942,574	)
Add back:
Gain on debt restructuring			(41,621,150	)			–				(41,621,150	)			–
Interest expense, net, excluding amortization of warrant based financing costs			261,898				1,385,837				1,696,544				2,792,657
Income tax provision			–				(5,957,649	)			–				(6,593,040	)
Depreciation, depletion, and amortization			1,095,322				2,941,753				3,121,711				5,576,052
Impairment of oil and gas properties			–				21,639,000				5,219,000				21,639,000
Accretion of abandonment liability			8,125				7,932				16,258				15,861
Share based compensation			157,824				314,162				315,648				635,514
Loss on mark-to market of derivatives			4,272,849				1,956,155				4,288,736				1,588,826
Adjusted EBITDA		$	2,256,675			$	3,617,552			$	3,203,041			$	5,712,296

 

Our adjusted EBITDA for the three and six month periods ended June 30, 2015 includes income from the Dahl Federal well that was recognized in those periods based on activity in prior periods of $1,040,397 and $1,027,995, respectively.

 

Liquidity and Capital Resources

 

The following table summarizes our total current assets, liabilities and working capital at June 30, 2016 and December 31, 2015, respectively.

 

		June 30,				December 31,
		2016				2015
Current Assets		$	1,106,188			$	6,457,840
Current Liabilities		$	1,084,651			$	68,312,897
Working Capital		$	21,537			$	(61,855,057	)

 

As of June 30, 2016 we had positive working capital of $21,537.

 

The following table summarizes our cash flows during the three month periods ended June 30, 2016 and 2015, respectively.

 

		Six Months Ended
		June 30,
		2016				2015
Net cash provided by operating activities		$	3,923,879			$	5,544,080
Net cash used in investing activities			(4,763,506	)			(12,574,179	)
Net cash provided by financing activities			1,650,000				7,150,000
Net change in cash and cash equivalents		$	810,373			$	119,901

 

 

Our net cash flows from operations are primarily affected by production volumes and commodity prices. Net cash provided by operating activities was $3,923,879 and $5,544,080 for the six months ended June 30, 2016 and 2015, respectively, a decrease of $1,620,201. The increase was due primarily to cash provided from operating activities of discontinued operations. Cash provided from operating activities of discontinued operations was $3,829,723 and $6,512,822, for the six month periods ended June 30, 2016 and 2015, respectively, the decrease driven primarily due to lower commodity prices.

 

Net cash used in investing activities was $4,763,506 and $12,574,179 for the six months ended June 30, 2016 and 2015, respectively, a decrease of $7,810,673. All of our investing activity in both periods was derived from discontinued operations. We paid $4,858,134 for well development during the 2016 period while in the 2015 period we spent $12,574,251 for well development. Additionally, the decrease in cash used in investing activities was attributable to a decrease in cash spent for property acquisition as we purchased no property during the six months ended June 30, 2016 as compared to purchasing 9 net leasehold acres of oil and gas properties for $102,928 in the six months ended June 30, 2015. In the six months ended June 30, 2016 we sold 14 net leasehold acres for proceeds of $94,628, while in the comparable 2015 period we sold 9 net leasehold acres and two wellbores for proceeds of $103,000.

 

Net cash provided from financing was $1,650,000 and $7,150,000 for the six months ended June 30, 2016 and 2015, respectively, all due to net borrowings for discontinued operations.

 

BRHC Transaction

 

As described above in “Recent Developments,” on March 29, 2016, the Company entered into an Asset Contribution Agreement with Black Ridge Holding Company, LLC, a Delaware limited liability company (“BRHC”) which was recently formed by the Company to contribute and assign to BRHC, all of the Company's (i) oil and gas assets (including working capital and tangible and intangible assets) (the “Assets”), (ii) outstanding balances under that certain Credit Agreement between the Company, as borrower, and Cadence Bank, N.A. (“Cadence”), as lender (the “Cadence Credit Facility”) and the outstanding balances under that certain Credit Agreement between the Company, as borrower, and the several banks and other financial institutions or entities from time to time parties thereto (the “Chambers”), and Chambers, as administrative agent (the “Chambers Credit Facility”) and (iii) all current liabilities related to the Assets, in exchange for 5% of the issued and outstanding Class A Units (the “Class A Units”) in BRHC (the “Asset Contribution”). On March 29, 2016, affiliates of Chambers Energy Management, LP (“Chambers”) (specifically, Chambers Energy Capital II, LP and CEC II TE, LLC (collectively, the “Chambers Affiliates”)) entered into a Debt Contribution Agreement between BRHC and the Chambers Affiliates, pursuant to which BRHC will issue a number of Class A Units representing 95% of the Class A Units of BRHC to the Chambers Affiliates in exchange for the release of BRHC's obligations under the Chambers Credit Facility (the “Satisfaction of Debt” and, together with the Asset Contribution, the “BRHC Transaction”). Concurrent with the Satisfaction of Debt, each warrant originally issued with the Chambers Credit Facility shall be automatically retired and cancelled. The closing of the BRHC Transaction was subject to the Company obtaining the approval of stockholders holding a majority of its outstanding capital stock and to the Company having assigned the Cadence Credit Agreement to BRHC with Cadence’s consent, and BRHC and Cadence entering into any applicable amendment agreements related to such assignment and waiver of financial covenant ratio compliance for the quarter ended December 31, 2015 and quarter ending March 31, 2016. On June 21, 2016, the Company satisfied all of these conditions and the BRHC Transaction has been consummated. The parties have agreed that the BRHC Transaction, the Asset Contribution and the Satisfaction of Debt are effective as of April 1, 2016.

 

 

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

 

·

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

·

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

·

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

 

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

 

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

 

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

 

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

 

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

 

 

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

 

Senior Credit Facility and Subordinated Credit Facilities

 

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

 

Availability under the Senior Credit Facility was at all times subject to the then-applicable borrowing base, determined by Cadence in a manner consistent with the normal and customary oil and gas lending practices of Cadence. Availability was initially set at $7 million and was subject to periodic redeterminations. Subject to availability under the borrowing base, the Company could 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 was 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 was also required to pay a quarterly fee of 0.50% on any unused portion of the borrowing base, as well as a facility fee of 0.90% of the initial and any subsequent additions to the borrowing base.

 

The Senior Credit Facility’s maturity date of August 8, 2016, was subsequently amended to January 15, 2017 pursuant to the amendment on March 30, 2015. The Company could prepay the entire amount of Base Rate loans at any time, and could prepay the entire amount of LIBOR loans upon at least three business days’ notice to Cadence. The Senior Credit Facility was 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.

 

As part of the debt restructuring outline in Note 4 – Debt Restructuring, the Company transferred the obligation with a balance outstanding of $29,400,000 under the Senior Credit Facility to BRHC. The Company had borrowings of $27.75 million outstanding under the Senior Credit Agreement as of December 31, 2015.

 

Subordinated Credit Facility

 

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

 

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

 

 

The Subordinated Credit Facility matured on June 30, 2017. Upon at least three business days’ written notice, the Company could 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, would 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 were accompanied by an applicable premium, as set forth in the Subordinated Credit Agreement. The Subordinated Credit Facility was secured by second priority interests on substantially all of the Company’s assets, including but not limited to second priority mortgages on the Company’s mineral interests in North Dakota and Montana.

 

The first funding from the Subordinated Credit Facility occurred on September 9, 2013 at which time we drew $14,700,000, 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 a previously outstanding revolving credit facility. We had drawn an additional $14,700,000, net of $300,000 original issue discounts, through December 31, 2015. The Company had borrowings of $30.0 million outstanding under the Subordinated Credit Facility as of December 31, 2015. The obligations under the Subordinated Credit Facility, $30.0 million of principal and $2,931,369 of PIK interest payable, were transferred to BRHC and converted to equity in BRHC as part of the debt restructuring outlined in Note 4- Debt Restructuring.

 

Intercreditor Agreements and Covenants

 

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

 

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

 

 

Covenant Violations

 

The Company was out of compliance with the collateral coverage ratio covenant as of March 31, 2016 and December 31, 2015 and the current ratio covenant as defined by the Subordinated Credit Facility as of March 31, 2016. Additionally, the audit report the Company received with respect to its financial statements as of December 31, 2015 contains an explanatory paragraph expressing uncertainty as to the Company’s ability to continue as a going concern, the delivery of which constitutes a default under both its Senior Credit Facility and Subordinated Credit Facility. See Note 3, “Going Concern”, for additional information. The Company received a waiver for all debt covenants as of December 31, 2015 and March 31, 2016 as part of the debt restructuring outlined in Note 4 – Debt Restructuring.

 

Debt Discount, Detachable Warrants

 

In connection with the Subordinated Credit Facility, the Company agreed to issue to the lenders detachable warrants to purchase up to 5,000,000 shares of the Company’s common stock at an exercise price of $0.65 per share. The warrants expire on August 8, 2018. Proceeds from the loan were allocated between the debt and equity based on the relative fair values at the time of issuance, resulting in a debt discount of $2,473,576 at issuance that is presented as a debt discount on the balance sheet and is being amortized using the effective interest method over the life of the credit facility, which matures on June 30, 2017. A total of $-0- and $321,763 was amortized during the six months ended June 30, 2016 and 2015. The remaining unamortized balance of the debt discount attributable to the warrants is $-0- as of June 30, 2016. The amortization of the debt discount attributable to the warrants was accelerated in 2015 to fully amortize the discount as of December 31, 2015 when the related debt became payable on demand due to a default on the related debt. As part of the debt restructuring all related warrants were retired and cancelled.

 

Satisfaction of our cash obligations for the next 12 months

 

As of June 30, 2016, our balance of cash and cash equivalents was $1,038,567 and we had $21,537 of working capital. Following the close of the BRHC Transaction, our plan for satisfying our cash requirements for the next twelve months is through the terms of our management agreement.

 

Off-Balance Sheet Arrangements

 

We have no off-balance sheet arrangements.

 

Critical Accounting Policies and Estimates

 

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

 

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

 

 

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

 

Commodity Price Risk

 

Prior to the BRHC Transaction, the prices we received for our crude oil and natural gas production heavily influenced 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 received for our production depended on numerous factors beyond our control. Our revenue generally increased or decreased along with any increases or decreases in crude oil or natural gas prices, but the impact on our income was indeterminable given the variety of expenses associated with producing and selling crude oil that also increase and decrease along with crude oil prices.

 

Those same commodity price risks heavily influence the profitability and access to capital in the companies we currently or will manage through management service agreements, thus affecting their ability to pay for the services we currently or are working to provide in the future. Thus commodity price risk continues to be a factor affecting our future profitability.

 

 

ITEM 4. CONTROLS AND PROCEDURES.

 

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

 

Our management, under the direction of our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the design and operation of our disclosure controls and procedures (as such terms are defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of June 30, 2016. As part of such evaluation, management considered the matters discussed below relating to internal control over financial reporting. Based on this evaluation our management, including the Company’s Chief Executive Officer and Chief Financial Officer, has concluded that the Company’s disclosure controls and procedures were effective as of June 30, 2016 to ensure that the information required to be disclosed in our Exchange Act reports was recorded, processed, summarized and reported on a timely basis.

 

There have been no changes in the Company’s internal control over financial reporting during the three month period ended June 30, 2016 that materially affected or are reasonably likely to materially affect the Company’s internal control over financial reporting.

 

 

PART II - OTHER INFORMATION

 

Item 1. Legal Proceedings.

 

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

 

 

ITEM 1A. RISK FACTORS.

 

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

 

 

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

 

None.

 

 

ITEM 3. DEFAULTS UPON SENIOR SECURITIES.

 

None.

 

 

ITEM 4. MINE SAFETY DISCLOSURES.

 

Not applicable.

 

 

ITEM 5. OTHER INFORMATION.

 

None.

 

 

ITEM 6. EXHIBITS.

 

Exhibit		Description
3.1		Certificate of Incorporation (incorporated by reference to Exhibit 3.1 of the Form 8-K filed with the Securities and Exchange Commission by Black Ridge Oil & Gas, Inc. on December 12, 2012)
3.2		Bylaws (incorporated by reference to Exhibit 3.2 of the Form 8-K filed with the Securities and Exchange Commission by Black Ridge Oil & Gas, Inc. on December 12, 2012)
10.1		Asset Contribution Agreement dated March 29, 2016 by and between Black Ridge Oil & Gas, Inc., as Transferor, and Black Ridge Holding Company, LLC, as Transferee (incorporated by reference to Preliminary Information Statement on Schedule 14C filed with the Securities and Exchange Commission by Black Ridge Oil & Gas, Inc. on March 31, 2016)
10.2		Debt Contribution Agreement dated March 29, 2016 by and between Black Ridge Oil & Gas, Inc., Black Ridge Holding Company, LLC, Chambers Energy Capital II, LP and CEC II TE, LLC (incorporated by reference to Preliminary Information Statement on Schedule 14C filed with the Securities and Exchange Commission by Black Ridge Oil & Gas, Inc. on March 31, 2016)
10.3*		Limited Liability Company Agreement of Black Ridge Holding Company, LLC dated June 21, 2016 by and between Black Ridge Oil & Gas, Inc., Chambers Energy Capital II, LP and CEC II TE, LLC, as Members
10.4*		Management Services Agreement dated June 21, 2016 by and between Black Ridge Holding Company, LLC and Black Ridge Oil & Gas, Inc.
31.1*		Section 302 Certification of Chief Executive Officer
31.2*		Section 302 Certification of Chief Financial Officer
32.1*		Section 906 Certification of Chief Executive Officer
32.2*		Section 906 Certification of Chief Financial Officer
101.INS*		XBRL Instance Document
101.SCH*		XBRL Schema Document
101.CAL*		XBRL Calculation Linkbase Document
101.DEF*		XBRL Definition Linkbase Document
101.LAB*		XBRL Labels Linkbase Document
101.PRE*		XBRL Presentation Linkbase Document

*Filed herewith

 

 

SIGNATURES

 

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

 

 

	BLACK RIDGE OIL & GAS, INC.
Dated: August 15, 2016	By:	/s/Kenneth DeCubellis
			Kenneth DeCubellis, Chief Executive Officer (Principal Executive Officer)
Dated: August 15, 2016	By:	/s/James A. Moe
			James A. Moe, Chief Financial Officer (Principal Financial Officer)