Notes to Condensed Consolidated Financial Statements

(Unaudited)

Note 1 – Organization and Nature of Business

Effective April 2, 2012, Ante5, Inc. changed its corporate name to Black Ridge Oil & Gas, Inc., and continues to 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 3 – Debt Restructuring. Following the transaction, our focus has been managing the oil and gas assets in which we continue to have an indirect minority interest. Our management services agreement related to those same oil and gas assets was terminated on April 3, 2017, effective June 30, 2017. 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 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, 2016, which were included in our Annual Report on Form 10-K. The Company follows the same accounting policies in the preparation of interim reports.

⁽¹⁾ Wholly-owned subsidiary

The consolidated financial statements herein contain the operations of the wholly-owned subsidiary listed above. All significant inter-company transactions have been eliminated in the preparation of theses financial statements. The parent company, Black Ridge Oil & Gas, Inc. and subsidiary, Black Ridge Acquisition Corp. will be collectively referred to herein as the “Company” or “Black Ridge”. The Company’s headquarters is in Minneapolis, Minnesota and substantially all of its operations are in the United States.

Reclassifications

As discussed in Note 3 – Debt Restructuring, income, expense and cash flows from the restructured operations for the three and six months ended June 30, 2016 have been reclassified as net loss and cash flows from discontinued operations.

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.

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Consolidated Financial Statements

(Unaudited)

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, 2017 and December 31, 2016.

Cash in Excess of FDIC Insured Limits

The Company maintains its cash in bank deposit accounts which, at times, may exceed federally insured limits. Accounts are guaranteed by the Federal Deposit Insurance Corporation (FDIC) and the Securities Investor Protection Corporation (SIPC) up to $250,000 and $500,000, respectively, under current regulations. The Company had approximately $-0- and $-0- in excess of FDIC and SIPC insured limits at June 30, 2017 and December 31, 2016, respectively. The Company has not experienced any losses in such accounts.

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:

We have capitalized a total of $56,660 of website development costs from inception through June 30, 2017. 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 $-0- for the six months ended June 30, 2017 and 2016, respectively, as all website development costs have been fully depreciated.

Income Taxes

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

Basic and Diluted Loss Per Share

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

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Consolidated Financial Statements

(Unaudited)

The reconciliation of the denominators used to calculate basic EPS and diluted EPS for the three and six months ended June 30, 2017 and 2016 are as follows:

Stock options and warrants excluded from the calculation of diluted EPS because their effect was anti-dilutive were 10,957,000 and 9,954,875 for the three months ended June 30, 2017 and 2016, respectively, and 10,957,000 and 9,954,875 for the six months ended June 30, 2017 and 2016, 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 $5,734 and $7,364 for the six months ended June 30, 2017 and 2016, respectively.

Revenue Recognition

The Company recognizes management fee income as services are provided.

The Company recognized oil and gas revenues from its former interests in producing wells when production was delivered to, and title was transferred to, the purchaser and to the extent the selling price is reasonably determinable. Oil and gas revenues are reflected as a component of discontinued operations on the statements 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 expense related to accretion of the discount on the asset retirement liability is reflected as a component of discontinued operations on the statement of operations for the six months ended June 30, 2016.

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Consolidated Financial Statements

(Unaudited)

Full Cost Method

The Company followed the full cost method of accounting for oil and gas operations in 2016 whereby all costs related to the exploration and development of oil and gas properties were initially capitalized into a single cost center ("full cost pool"). The Company had no oil and gas operations in 2017 as they were disposed as part of the debt restructuring transaction on June 21, 2016 described in Note 3 – Debt Restructuring. Capitalized costs included 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 were capitalized were directly attributable to acquisition, exploration and development activities and did not include costs related to the production, general corporate overhead or similar activities. Costs associated with production and general corporate activities were expensed in the period incurred. Capitalized costs for the six month period ended June 30, 2016 are summarized as follows:

Proceeds from sales of proved properties were credited to the full cost pool, with no gain or loss recognized, unless such a sale would significantly altered 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 assessed all items classified as unevaluated property on a quarterly basis for possible impairment or reduction in value. The assessment included 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 were transferred to the full cost pool and were 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 were 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 were 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) could 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). When capitalized costs exceeded this ceiling, impairment was recognized. The present value of estimated future net cash flows was 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. When this comparison indicated an excess carrying value, the excess was charged to earnings as an impairment expense. The Company recognized an impairment loss of $5,219,000 during the six months ended June 30, 2016. The impairment loss is reflected as a component of discontinued operations on the statement of operations for the period.

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 $318,984 and $315,648 for the six months ended June 30, 2017 and 2016, 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.

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Consolidated Financial Statements

(Unaudited)

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

During the 2016 period, while the Company had oil and gas operations, the Company entered into derivative contracts, including price swaps, caps and floors, which required 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 were based on a portion of the expected production from existing wells.

Any realized gains and losses were recorded to gain (loss) on settled derivatives and unrealized gains or losses as a result of mark-to market valuations were recorded to gain (loss) on the mark-to-market of derivatives and are included as a component of loss from discontinued operations 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, 2016.

Note 3 – 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 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 issued 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 agreed that the BRHC Transaction, the Asset Contribution and the Satisfaction of Debt were effective, for valuation purposes, as of April 1, 2016.

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Consolidated 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, are to be made as follows:

BRHC is managed by the BRHC Board, which is 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 is 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, could 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 is 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 provides 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 is paid a fee under the Management Services Agreement intended to cover the costs of providing such services and is reimbursed for certain third party expenses. The term of the Management Services Agreement commenced on the closing of the BRHC Transaction and continued indefinitely, until terminated, which required a three month notice by the terminating party. The management services agreement was terminated by BRHC on April 3, 2017, effective June 30, 2017.

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 the Company’s retention of a 3.88% ownership interest in BRHC at the date of the restructuring, and the net book value of the assets and liabilities the Company transferred to BRHC.

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Consolidated Financial Statements

(Unaudited)

The income and expense associated with the operating activities contributed in the BRHC Transaction are reflected as “Loss from discontinued items, net of income taxes” on our condensed statement of operations for the three and six months ended June 30, 2016. The items included in “Loss from discontinued operations, net of income taxes” are as follows:

Note 4 – Rights Offering and Formation of Black Ridge Acquisition Corp.

As further discussed in Note 19 – Subsequent Events, the Company has filed a rights offering to raise capital with the proceeds primarily used to sponsor a special purpose acquisition company (“SPAC”). The Company formed a subsidiary, Black Ridge Acquisition Corp. (“BRAC”), on May 9, 2017 with the purpose of becoming the SPAC which would conduct an initial public offering later in 2017.

The Company has incurred costs through June 30, 2017, which have been classified on the balance sheet as deferred offering costs. Deferred offering costs consist of costs associated with equity offerings of BROG and its subsidiary BRAC. These costs will be reclassified to additional paid-in capital upon a successful offering or be charged to general and administrative expense if the offerings are unsuccessful. Prepaid offering costs consist of the following:

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Consolidated Financial Statements

(Unaudited)

Note 6 – Investment in Black Ridge Holding Company, LLC

The investment in Black Ridge Holding Company, LLC represents our equity interest in Black Ridge Holding Company, LLC following the debt restructuring and related activity as described in Note 3 – Debt Restructuring. We account for the investment using the cost method.

During the six months ended June 30, 2017 we sold certain assets with a net book value of $6,874 for proceeds of $2,160, resulting in a loss on disposal of $4,714.

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

⁽¹⁾ Presented as a component 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 a non-cash ceiling test impairment of $5,219,000 for the six months ended June 30, 2016. The expense associated with the impairment is presented as a component of loss from discontinued operations, net of income taxes as described in Note 3 – Debt Restructuring. The impairment charge affected our reported net income but did not reduce our cash flow.

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Consolidated Financial Statements

(Unaudited)

Note 8 – Oil and Gas Properties

The following table summarizes gross and net productive oil wells by state at June 21, 2016 (prior to their disposition in our debt restructuring). 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.

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 the their disposition through our debt restructuring) our principal oil and gas assets included approximately 7,016 net acres located in North Dakota and Montana and were disposed by the Company on June 21, 2016 as part of the debt restructuring transaction summarized in Note 3 – Debt Restructuring.

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:

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 of 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 and gas properties, with net carrying costs $24,498,638, as part of our debt restructuring as outlined in Note 3 – Debt Restructuring.

Note 9 – Asset Retirement Obligation

The Company had asset retirement obligations (ARO) associated with the future plugging and abandonment of proved properties and related facilities prior to the disposition of the Company’s oil and gas operations as part of its debt restructuring summarized in Note 3 – Debt Restructuring. 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.

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Consolidated Financial Statements

(Unaudited)

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

Note 10 – Related Party

Prior to July 1, 2016 the Company leased office space on a month to month basis where the lessor was 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 to this entity during the six months ended June 30, 2016.

Note 11 – Derivative Instruments

The Company was required to recognize all derivative instruments on the balance sheet as either assets or liabilities measured at fair value. The Company did not designated its derivative instruments as cash flow hedges for accounting purposes and, as such, marked its derivative instruments to fair value and recognized 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” as a component of loss from discontinued operations.

The Company had utilized swap and collar derivative contracts. While the use of these derivative instruments limited the downside risk of adverse price movements, their use also limited 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 were settled based on reported settlement prices on commodity exchanges, with crude oil derivative settlements based on NYMEX West Texas Intermediate (“WTI”) pricing.

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Consolidated Financial Statements

(Unaudited)

Note 12 – 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 had 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, 2017 and December 31, 2016:

There were no transfers of financial assets or liabilities between Level 1 and Level 2 inputs for the six months ended June 30, 2017.

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Consolidated Financial Statements

(Unaudited)

Note 13 – 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 was 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 3 – Debt Restructuring, the Company transferred the obligation with a balance outstanding of $29,400,000 under the Senior Credit Facility to BRHC on June 21, 2016.

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 were 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 $30 million, with the remaining commitments subject to the approval of Chambers and other customary conditions. The Company could borrow the available commitments in amounts of $5 million or more and could 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 were funded net of a 2% OID. The unpaid principal balance of borrowings under the Subordinated Credit Facility bore interest at the Cash Interest Rate plus the PIK Interest Rate. The Cash Interest Rate was 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 was equal to 4.00% per annum. Interest was payable on the last day of each month. The Company was 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 was to mature 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 Consolidated 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 June 21, 2016. The Company had borrowings of $30.0 million outstanding under the Subordinated Credit Facility as of June 21, 2016. 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 3 - Debt Restructuring on June 21, 2016.

Intercreditor Agreements and Covenants

Cadence and Chambers had entered into an Intercreditor Agreement dated August 8, 2013 (the “Intercreditor Agreement”). The Intercreditor Agreement provided that any liens on the assets of the Company securing indebtedness under the Subordinated Credit Facility were subordinate to liens on the assets securing indebtedness under the Senior Credit Facility and set 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 required the Company to satisfy certain specified financial ratios. The Senior Credit Agreement required 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 required 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 constituted a default under both its Senior Credit Facility and Subordinated Credit Facility. 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 3 – Debt Restructuring.

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Consolidated Financial Statements

(Unaudited)

The following presents components of interest expense which is presented as a component of component of loss from discontinued operations, net of tax, on the Company’s statement of operations for the six months ended June 30, 2016:

Note 14 – 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 15 –Options

Options Granted

No options were granted during the six months ended June 30, 2017 and 2016.

The Company recognized a total of $318,984 and $315,648 of compensation expense during the six months ended June, 2017 and 2016, respectively, related to 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 $703,405 as of June 30, 2017.

Options Exercised

No options were exercised during the six months ended June 30, 2017 and 2016.

Options Forfeited

No options were forfeited during the six months ended June 30, 2017 and 2016.

Note 16 – Warrants

Warrants Granted

No warrants were granted during the six months ended June 30, 2017 and 2016.

Warrants Exercised

No warrants were exercised during the six months ended June 30, 2017 and 2016.

During 2016, all remaining warrants either expired or were forfeited pursuant to our debt restructuring as described in Note 3- Debt Restructuring. The Company has no outstanding warrants as of June 30, 2017.

Note 17 – 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.

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Consolidated Financial Statements

(Unaudited)

We currently estimate that our effective tax rate for the year ending December 31, 2017 will be 0%. Losses incurred during the period from April 9, 2011 (inception) to June 30, 2017 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, 2017, net deferred tax assets were $12,853,533, after an offsetting reduction in deferred tax liabilities of $708, primarily related to net operating loss carryforwards. A valuation allowance of approximately $12,853,533 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, 2017 of $-0- was primarily driven by the Company’s loss before provision for income taxes and offset by the valuation allowance on the resulting deferred tax asset.

In accordance with FASB ASC 740, the Company has evaluated its tax positions and determined there are no significant uncertain tax positions as of any date on, or before June 30, 2017.

Note 18 – 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.