Sow Good Inc. - FORM 10-Q - November 12, 2015

Attached files

file	filename
EX-10.2 - MANAGEMENT SERVICES AGREEMENT - Sow Good Inc.	brog_10q-ex1002.htm
EX-32.1 - CERTIFICATION - Sow Good Inc.	brog_10q-ex3201.htm
EX-32.2 - CERTIFICATION - Sow Good Inc.	brog_10q-ex3202.htm
EX-31.2 - CERTIFICATION - Sow Good Inc.	brog_10q-ex3102.htm
EX-10.1 - LIMITED LIABILITY COMPANY AGREEMENT - Sow Good Inc.	brog_10q-ex1001.htm
EX-31.1 - CERTIFICATION - Sow Good Inc.	brog_10q-ex3101.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)

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

For Quarterly Period Ended September 30, 2015

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

For the Transition period from _______________ to ______________

Commission File Number 000-53952

(Exact name of registrant as specified in its charter)

Nevada

(State or other jurisdiction of incorporation or organization)

27-2345075

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

10275 Wayzata Blvd. Suite 100, Minnetonka, Minnesota 55305

(Address of principal executive offices) (Zip Code)

(952) 426-1241

(Registrant’s telephone number, including area code)

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

Yes

☒

☐

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

☒

☐

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

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

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

Yes

☐

☒

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

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

TABLE OF CONTENTS

PART I - FINANCIAL INFORMATION

ITEM 1.	FINANCIAL STATEMENTS (Unaudited)	3
	Condensed Balance Sheets as of September 30, 2015 (Unaudited) and December 31, 2014	3
	Unaudited Condensed Statements of Operations for the Three and Nine Months Ended September 30, 2015 and 2014	4
	Unaudited Condensed Statements of Cash Flows for the Nine Months Ended September 30, 2015 and 2014	5
	Notes to the Condensed Financial Statements (Unaudited)	6
ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	22
ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	37
ITEM 4.	CONTROLS AND PROCEDURES	37

PART II - OTHER INFORMATION

ITEM 1.	Legal Proceedings	38
ITEM 1A.	RISK FACTORS	38
ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	38
ITEM 3.	DEFAULTS UPON SENIOR SECURITIES	38
ITEM 4.	MINE SAFETY DISCLOSURES	38
ITEM 5.	OTHER INFORMATION	38
ITEM 6.	EXHIBITS	38
	SIGNATURES	39

PART I – FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS.

BLACK RIDGE OIL & GAS, INC.

CONDENSED BALANCE SHEETS

	September 30,			December 31,
	2015			2014
ASSETS		(Unaudited)

Current assets:
Cash and cash equivalents	$	58,599		$	94,682
Derivative instruments, current		2,693,561			3,571,803
Accounts receivable		3,861,923			5,740,171
Prepaid expenses		49,107			41,387
Total current assets		6,663,190			9,448,043

Property and equipment:
Oil and natural gas properties, full cost method of accounting:
Proved properties		128,083,460			112,418,105
Unproved properties		803,718			591,121
Other property and equipment		139,004			139,004
Total property and equipment		129,026,182			113,148,230
Less, accumulated depreciation, amortization, depletion and allowance for impairment		(78,895,166	)		(18,902,524	)
Total property and equipment, net		50,131,016			94,245,706

Derivative instruments, long-term		–			4,007,942
Debt issuance costs, net		463,792			701,019

Total assets	$	57,257,998		$	108,402,710


LIABILITIES AND STOCKHOLDERS' EQUITY

Current liabilities:
Accounts payable	$	8,438,772		$	10,291,262
Accrued expenses		65,207			57,435
Total current liabilities		8,503,979			10,348,697

Asset retirement obligations		353,095			286,804
Revolving credit facilities and long term debt, net of discounts of $1,461,093 and $2,072,483, respectively		57,458,543			51,834,603
Deferred tax liability		–			6,593,040

Total liabilities		66,315,617			69,063,144

Commitments and contingencies (See note 16)		–			–

Stockholders' equity:
Preferred stock, $0.001 par value, 20,000,000 shares authorized, no shares issued and outstanding		–			–
Common stock, $0.001 par value, 500,000,000 shares authorized, 47,979,990 shares issued and outstanding		47,980			47,980
Additional paid-in capital		34,117,590			33,651,714
Retained earnings (accumulated deficit)		(43,223,189	)		5,639,872
Total stockholders' equity		(9,057,619	)		39,339,566

Total liabilities and stockholders' equity	$	57,257,998		$	108,402,710

See accompanying notes to financial statements.

BLACK RIDGE OIL & GAS, INC.

CONDENSED STATEMENTS OF OPERATIONS

(Unaudited)

	For the Three Months						For the Nine Months
	Ended September 30,						Ended September 30,
	2015			2014			2015			2014

Oil and gas sales	$	3,359,684		$	5,492,326		$	11,296,220		$	15,076,743
Gain (loss) on settled derivatives		7,456,284			(70,253	)		9,436,903			(449,135	)
Gain (loss) on the mark-to-market of derivatives		(3,297,358	)		2,147,798			(4,886,184	)		1,052,639
Total revenues		7,518,610			7,569,871			15,846,939			15,680,247

Operating expenses:
Production expenses		887,187			670,404			3,030,707			1,773,458
Production taxes		330,186			588,923			1,171,530			1,585,755
General and administrative		754,788			690,189			2,295,241			2,095,071
Depletion of oil and gas properties		1,778,580			2,275,703			7,346,356			5,994,180
Impairment of oil and gas properties		30,995,000			–			52,634,000			–
Accretion of discount on asset retirement obligations		8,039			5,833			23,900			15,486
Depreciation and amortization		4,010			8,214			12,286			24,327
Total operating expenses		34,757,790			4,239,266			66,514,020			11,488,277

Net operating income (loss)		(27,239,180	)		3,330,605			(50,667,081	)		4,191,970

Other income (expense):
Other income		–			–			6,707			–
Interest income		–			972			–			972
Interest (expense)		(1,681,307	)		(1,440,274	)		(4,795,727	)		(3,816,297	)
Total other income (expense)		(1,681,307	)		(1,439,302	)		(4,789,020	)		(3,815,325	)

Income (loss) before provision for income taxes		(28,920,487	)		1,891,303			(55,456,101	)		376,645

Provision for income taxes		–			(700,587	)		6,593,040			(110,849	)

Net income (loss)	$	(28,920,487	)	$	1,190,716		$	(48,863,061	)	$	265,796


Weighted average common shares outstanding - basic		47,979,990			47,979,990			47,979,990			47,979,990
Weighted average common shares outstanding - fully diluted		47,979,990			49,588,039			47,979,990			49,824,437

Net loss per common share - basic	$	(0.60	)	$	0.02		$	(1.02	)	$	0.01
Net loss per common share - fully diluted	$	(0.60	)	$	0.02		$	(1.02	)	$	0.01

See accompanying notes to financial statements.

BLACK RIDGE OIL & GAS, INC.

CONDENSED STATEMENTS OF CASH FLOWS

(Unaudited)

	For the Nine Months
	Ended September 30,
	2015			2014
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	(48,863,061	)	$	265,796
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion of oil and gas properties		7,346,356			5,994,180
Depreciation and amortization		12,286			24,327
Amortization of debt issuance costs		287,227			229,936
Accretion of discount on asset retirement obligations		23,900			15,486
Loss (gain) on the mark-to-market of derivatives		4,886,184			(1,052,639	)
Accrued payment in kind interest applied to long term debt		962,550			787,344
Amortization of original issue discount on debt		127,378			102,566
Amortization of debt discounts, warrants		484,012			468,670
Common stock options issued to employees and directors		465,876			433,294
Deferred income taxes		(6,593,040	)		110,849
Impairment of oil and natural gas properties		52,634,000			–
Decrease (increase) in current assets:
Accounts receivable		1,878,248			(1,233,582	)
Prepaid expenses		(7,720	)		(45,916	)
Increase (decrease) in current liabilities:
Accounts payable		153,024			223,779
Accrued expenses		7,772			61,423
Net cash provided by operating activities		13,804,992			6,385,513

CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from sale or swap of oil and gas properties		127,348			1,360,920
Purchases of oil and gas properties and development capital expenditures		(17,968,423	)		(17,410,744	)
Advances to operators		–			(5,742,272	)
Purchases of other property and equipment		–			(11,131	)
Net cash used in investing activities		(17,841,075	)		(21,803,227	)

CASH FLOWS FROM FINANCING ACTIVITIES
Advances from revolving credit facilities and long term debt		14,000,000			24,150,000
Repayments on revolving credit facilities		(9,950,000	)		(9,600,000	)
Debt issuance costs		(50,000	)		(254,394	)
Net cash provided by financing activities		4,000,000			14,295,606

NET CHANGE IN CASH		(36,083	)		(1,122,108	)
CASH AT BEGINNING OF PERIOD		94,682			1,150,347
CASH AT END OF PERIOD	$	58,599		$	28,239


SUPPLEMENTAL INFORMATION:
Interest paid	$	3,292,793		$	2,411,463
Income taxes paid	$	–		$	–

NON-CASH INVESTING AND FINANCING ACTIVITIES:
Net change in accounts payable for purchase of oil and gas properties	$	(2,005,514	)	$	3,821,375
Advances to operators applied to development of oil and gas properties	$	–		$	4,285,575
Capitalized asset retirement costs, net of revision in estimate	$	42,391		$	61,815

See accompanying notes to financial statements.

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Financial Statements

(Unaudited)

Note 1 – Organization and Nature of Business

Effective April 2, 2012, Ante5, Inc. changed its corporate name to Black Ridge Oil & Gas, Inc., and continues to be quoted on the OTCQB under the trading symbol “ANFC”. Black Ridge Oil & Gas, Inc. (formerly Ante5, Inc.) (the “Company”) became an independent company in April 2010. We became a publicly traded company when our shares began trading on July 1, 2010. Since October 2010, we have been engaged in the business of acquiring oil and gas leases and participating in the drilling of wells in the Bakken and Three Forks trends in North Dakota and Montana. Our strategy is to participate in the exploration, development and production of oil and gas reserves as a non-operating working interest owner with a growing, diversified portfolio of oil and gas wells. We aggressively seek to accumulate mineral rights and participate in the drilling of new wells on a continuous basis. Occasionally, we also purchase working interests in producing wells.

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

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

Note 2 – Basis of Presentation and Significant Accounting Policies

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

These statements reflect all adjustments, which in the opinion of management, are necessary for fair presentation of the information contained therein. Except as otherwise disclosed, all such adjustments are of a normal recurring nature. It is suggested that these interim condensed financial statements be read in conjunction with the audited financial statements for the year ended December 31, 2014, which were included in our Annual Report on Form 10-K filed with the SEC. The Company follows the same accounting policies in the preparation of interim reports.

Use of Estimates

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

Environmental Liabilities

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

Cash and Cash Equivalents

Cash equivalents include money market accounts which have maturities of three months or less. For the purpose of the statements of cash flows, all highly liquid investments with an original maturity of three months or less are considered to be cash equivalents. Cash equivalents are stated at cost plus accrued interest, which approximates market value. No cash equivalents were on hand at September 30, 2015 and December 31, 2014.

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Financial Statements

(Unaudited)

Cash in Excess of FDIC Insured Limits

The Company maintains its cash in bank deposit accounts which, at times, may exceed federally insured limits. Accounts are guaranteed by the Federal Deposit Insurance Corporation (FDIC) and the Securities Investor Protection Corporation (SIPC) up to $250,000 and $500,000, respectively, under current regulations. The Company had approximately $-0- and $-0- in excess of FDIC and SIPC insured limits at September 30, 2015 and December 31, 2014, respectively. The Company has not experienced any losses in such accounts.

Advances to Operators

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

Debt Issuance Costs

Costs relating to obtaining our revolving credit facilities are capitalized and amortized over the term of the related debt using the straight-line method. The unamortized balance of debt issuance costs at September 30, 2015, and December 31, 2014, was $463,792 and $701,019, respectively. Amortization of debt issuance costs charged to interest expense were $287,227 and $229,936 for the nine months ended September 30, 2015 and 2014, respectively. When a loan is paid in full, any unamortized financing costs are removed from the related accounts and charged to interest expense.

Website Development Costs

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

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

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.

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

We have capitalized a total of $56,660 of website development costs from inception through September 30, 2015. We depreciate our website development costs on a straight line basis over the estimated useful life of the assets, which is currently three years. We have recognized depreciation expense on these website costs of $257 and $14,165 for the nine months ended September 30, 2015 and 2014, respectively. As of September 30, 2015, all website development costs have been fully depreciated.

Income Taxes

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

Basic and Diluted Loss Per Share

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

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Financial Statements

(Unaudited)

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

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

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

Fair Value of Financial Instruments

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

Non-Oil & Gas Property and Equipment

Property and equipment that are not oil and gas properties are recorded at cost and depreciated using the straight-line method over their estimated useful lives of three to seven years. Expenditures for replacements, renewals, and betterments are capitalized. Maintenance and repairs are charged to operations as incurred. Long-lived assets, other than oil and gas properties, are evaluated for impairment to determine if current circumstances and market conditions indicate the carrying amount may not be recoverable. The Company has not recognized any impairment losses on non-oil and gas long-lived assets. Depreciation expense was $12,286 and $24,327 for the nine months ended September 30, 2015 and 2014, respectively.

Revenue Recognition

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

Asset Retirement Obligations

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

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Financial Statements

(Unaudited)

Full Cost Method

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

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

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

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

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

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

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Financial Statements

(Unaudited)

Stock-Based Compensation

The Company adopted FASB guidance on stock based compensation upon inception at April 9, 2010. Under FASB ASC 718-10-30-2, all share-based payments to employees, including grants of employee stock options, are recognized in the income statement based on their fair values. Expense related to common stock and stock options issued for services and compensation totaled $465,876 and $433,294 for the nine months ended September 30, 2015 and 2014, respectively, using the Black-Scholes options pricing model and an effective term of 6 to 6.5 years based on the weighted average of the vesting periods and the stated term of the option grants and the discount rate on 5 to 7 year U.S. Treasury securities at the grant date. In addition, $484,012 and $468,670 of warrant related debt discounts were amortized during the nine months ended September 30, 2015 and 2014, respectively, and treated as interest expense. The fair value of warrants is determined similar to the method used in determining the fair value of employee stock options and the fair value is amortized over the life of the related credit facility and accelerated in the event of termination of the related credit facility.

Uncertain Tax Positions

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

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

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

Derivative Instruments and Price Risk Management

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

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

Recent Accounting Pronouncements

New accounting pronouncements are issued by the Financial Accounting Standards Board (“FASB”) that are adopted by the Company as of the specified effective date. If not discussed below, management believes there have been no developments to recently issued accounting standards, including expected dates of adoption and estimated effects on our financial statements, from those disclosed in our Annual Report on Form 10-K for the year ended December 31, 2014.

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

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

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Financial Statements

(Unaudited)

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

Note 3 – Joint Venture

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

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

We have not yet commenced operations pursuant this joint venture.

Note 4 – Dahl Federal Recognition

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

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Financial Statements

(Unaudited)

Note 5 – Property and Equipment

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

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

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

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

Impairment of Oil and Gas Properties

Note 6 – Oil and Gas Properties

The following table summarizes gross and net productive oil wells by state at September 30, 2015 and 2014. A net well represents our percentage ownership of a gross well. The following table does not include wells in which our interest is limited to royalty and overriding royalty interests. The following table also does not include wells which were awaiting completion, in the process of completion or awaiting flow back subsequent to fracture stimulation.

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

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

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Financial Statements

(Unaudited)

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

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

2015 Acquisitions

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

2015 Divestitures

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

2014 Acquisitions

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

2014 Divestitures

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

2014 Swap Transactions

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

Undeveloped Acreage Expirations

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

Note 7 – Asset Retirement Obligation

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

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Financial Statements

(Unaudited)

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

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

Note 8 – Related Party

We currently lease office space on a month to month basis where the lessor is an entity owned by our former CEO and current Chairman of the Board of Directors, Bradley Berman. Pursuant to the lease, we occupy approximately 2,813 square feet of office space. In accordance with this lease, our lease term remains on a month-to-month basis, provided that either party may provide ninety (90) day notice to terminate the lease, with base rents of $2,110 per month, plus common area operations and maintenance charges, and monthly parking fees of $240 per month, for the period from November 15, 2013 to October 31, 2014, and subject to increases of $117 per month beginning November 1, 2014 and for each of the subsequent three year periods. We have paid a total of $52,298 and $52,284 to this entity during the nine months ended September 30, 2015 and 2014, respectively.

Note 9 – Derivative Instruments

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

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

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

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

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Financial Statements

(Unaudited)

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

Crude Oil Swaps

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

Crude Oil Costless Collars

Floor/Ceiling

Settlement Period

Oil (Barrels)

Price

Basis

October 1, 2015 – December 31, 2015

9,000

$75.00/$95.60

NYMEX

April 1, 2016 – May 31, 2016

3,334

$80.00/$89.50

NYMEX

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

Derivative Liquidations

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

Derivative Gains and Losses

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

	Nine Months Ended
	September 30,
	2015			2014
Gain (loss) on settled derivatives:
Crude oil fixed price swaps	$	8,579,756		$	(449,135	)
Crude oil collars		857,147			–
Gain (loss) on settled derivatives, net	$	9,436,903		$	(449,135	)

Gain (loss) on the mark-to-market of derivatives:
Crude oil fixed price swaps	$	(4,366,810	)	$	1,012,502
Crude oil collars		(519,374	)		40,137
Gain (loss) on the mark-to-market of derivatives, net	$	(4,886,184	)	$	1,052,639

Balance Sheet Offsetting of Derivative Assets and Liabilities

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

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Financial Statements

(Unaudited)

September 30, 2015

December 31, 2014

Gross

Net

Gross

Net

Gross

amounts

amounts of

Gross

amounts

amounts of

offset

assets

amounts of

offset

assets

recognized

on balance

recognized

on balance

assets

sheet

assets

sheet

Commodity derivative assets

2,694,001

(440

)

2,693,561

7,620,896

(41,151

)

7,579,745

September 30, 2015

December 31, 2014

Gross

Net

Gross

Net

Gross

amounts

amounts of

Gross

amounts

amounts of

offset

liabilities

amounts of

offset

liabilities

recognized

on balance

recognized

on balance

liabilities

sheet

liabilities

sheet

Commodity derivative liabilities

–

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

	September 30,		December 31,
	2015		2014
Derivative assets	$	2,693,561	$	3,571,803
Noncurrent derivative assets		–		4,007,942
Net amount of assets on the balance sheet		2,693,561		7,579,745

Current portion of derivative liabilities		–		–
Derivative liabilities		–		–
Net amount of liabilities on the balance sheet		–		–
Total derivative assets (liabilities), net	$	2,693,561	$	7,579,745

Note 10 – Fair Value of Financial Instruments

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

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

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

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

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

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Financial Statements

(Unaudited)

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

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

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

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

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

Note 11 – Revolving Credit Facilities and Long Term Debt

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

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

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Financial Statements

(Unaudited)

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

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

Subordinated Credit Facility

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

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

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

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

Intercreditor Agreements and Covenants

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

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Financial Statements

(Unaudited)

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

Debt Discount, Detachable Warrants

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

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

	September 30,			December 31,
	2015			2014
Senior Revolving Credit Facility, Cadence Bank, N.A.	$	26,650,000		$	22,600,000
Subordinated Credit Agreement, Chambers		30,000,000			30,000,000
PIK Interest on Subordinated Credit Agreement, Chambers		2,269,636			1,307,086

Total credit facilities and long term debts		58,919,636			53,907,086
Less: Unamortized OID		(299,356	)		(426,734	)
Less: Unamortized debt discount attributable to warrants		(1,161,737	)		(1,645,749	)
Total credit facilities and long term debts, net of discounts		57,458,543			51,834,603
Less: current maturities		–			–

Long term portion of credit facilities and long term debts	$	57,458,543		$	51,834,603

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

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Financial Statements

(Unaudited)

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

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

Note 12 – Changes in Stockholders’ Equity

Preferred Stock

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

Common Stock

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

Note 13 – Options

Options Granted

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

The Company recognized a total of $465,876, and $433,294 of compensation expense during the nine months ended September 30, 2015 and 2014, respectively, on common stock options issued to Employees and Directors that are being amortized over the implied service term, or vesting period, of the options. The remaining unamortized balance of these options is $1,650,044 as of September 30, 2015.

Options Exercised

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

Options Expired/Forfeited

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

Note 14 – Warrants

Warrants Granted

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

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

Warrants Exercised

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

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Financial Statements

(Unaudited)

Note 15 – Income Taxes

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

We currently estimate that our effective tax rate for the year ending December 31, 2015 will be approximately 12%. Losses incurred during the period from April 9, 2011 (inception) to September 30, 2015 could be used to offset future tax liabilities. Accounting standards require the consideration of a valuation allowance for deferred tax assets if it is “more likely than not” that some component or all of the benefits of deferred tax assets will not be realized. As of September 30, 2015, net deferred tax assets were $15,417,147, after an offsetting reduction in deferred tax liabilities of $1,066,200, primarily related to differences in the book and tax basis amounts of the Company’s oil and gas properties resulting from the expensing of intangible drilling costs and the accelerated depreciation utilized for tax purposes, was applied. A valuation allowance of approximately $15,417,147 was applied to the remaining net deferred tax assets. This valuation allowance reflects an allowance on only a portion of the Company’s deferred tax assets which the Company believes it is more likely than not that the benefit of these assets will not be realized. We have not provided any valuation allowance against our deferred tax liabilities, which were netted against our deferred tax assets.

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

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

Note 16 – Commitments and Contingencies

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

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

The Company commits to its participation in upcoming well development by signing an Authorization for Expenditure (“AFE”). As of September 30, 2015, the Company had committed to AFE’s of approximately $1.6 million beyond amounts previously paid or accrued.

Note 17 – Subsequent Events

Debt Facilities

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

Borrowing Base Redetermination

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

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

Cautionary Statements

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

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

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

volatility or decline of our stock price;

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

potential fluctuation in quarterly results;

our failure to collect payments owed to us;

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

inability to effectively manage our hedging activities;

inadequate capital to acquire working interests in oil and gas prospects and to participate in the drilling and production of oil and other hydrocarbons;

	·	inability to meet financial covenants and restrictions associated with our debt agreements;
	·	inability to maintain adequate liquidity to meet our financial obligations;

unavailability of oil and gas prospects to acquire;

decline in oil prices;

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

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

drilling of dry holes;

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

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

litigation, disputes and legal claims involving outside parties; and

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

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

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

Overview and Outlook

We are an oil and natural gas exploration and production company. Our properties are located in North Dakota and Montana. Our corporate strategy is the acquisition, exploration, development and production of crude oil and natural gas properties, primarily in the Bakken and Three Forks trends in North Dakota and Montana. As of September 30, 2015, we owned an interest in 341 gross (10.88 net) producing oil and gas wells and controlled the rights to mineral leases covering approximately 8,509 net acres for prospective drilling to the Bakken and/or Three Forks formations. The following table provides a summary of important information regarding our assets:

As of September 30, 2015

As of December 31, 2014

Productive Wells

Average Daily

Proved

Net Acres ⁽¹⁾

Gross

Net

Production ⁽²⁾

Reserves

PV-10 ⁽³⁾

(Boe per day)

(000'sBoe)

($000)

8,509

341

10.88

1,075

5,356

100,335

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

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

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

Looking forward, we are pursuing the following objectives:

acquire high-potential mineral leases;

access appropriate capital markets to fund continued acreage acquisition and drilling activities;

develop and maintain strategic industry relationships;

attract and retain talented associates;

operate a low overhead non-operator business model; and

become a low cost producer of hydrocarbons.

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

the ability of the Company to acquire acreage at a price that is significantly below the acreage value when fully developed;

the ability of operators to successfully drill wells on the acreage position we hold and incur customary costs;

the sales price per barrel of oil;

the number of producing wells we own and the performance of those wells;

our ability to raise capital to fund drilling costs and acreage acquisitions; and

maintain a strong balance sheet and adequate liquidity to achieve our objectives.

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

Recent Developments

Derivative Liquidation

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

Operational Highlights

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

production reached 1,075 Boe per day, representing 41% growth compared to the third quarter of 2014 and a 4% decrease compared to the second quarter of 2015;

participated in the completion of 50 gross (1.92 net) wells increasing our total producing wells to 341 gross (10.88 net) wells;

attained adjusted EBITDA from operations of $9.0 million, which includes a $6.3 million gain from the liquidation of derivatives prior to their maturity;

reduced general and administrative expenses to $7.63 per Boe, compared to $9.85 per Boe in the third quarter of 2014, representing a 23% decrease on a per Boe basis;

realized $8.3 million of cash flow from operating activities;

	·	continued development of our core acreage including our Corral Creek and Teton projects; and
	·	ended the quarter with $26.65 million drawn on our senior secured revolving credit facility, a net reduction of $3.1 million from the end of the second quarter of 2015.

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

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

Potential Reverse Stock Split

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

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

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

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

Production History

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

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2015			2014			2015			2014
Net Production:
Oil (Bbl)		86,533			62,603			249,593			164,570
Natural gas (Mcf)		74,279			44,639			244,974			106,458
Barrel of oil equivalent (Boe)		98,933			70,043			290,422			182,313

Average Sales Prices:
Oil (per Bbl)	$	37.83		$	84.17		$	43.86		$	87.71
Effect of oil hedges on average price (per Bbl)	$	13.88	(a)	$	(1.12	)	$	12.75	(a)	$	(2.73	)
Oil net of hedging (per Bbl)	$	51.71	(a)	$	83.05		$	56.61	(a)	$	84.98
Natural gas (per Mcf)	$	1.14		$	4.99		$	1.43		$	6.03
Realized price on a Boe basis, net of settled derivatives	$	46.10	(a)	$	77.41		$	49.85	(a)	$	80.23

Average Production Costs:
Oil (per Bbl)	$	9.99		$	10.27		$	11.74		$	10.31
Natural gas (per Mcf)	$	0.30		$	0.61		$	0.41		$	0.72
Barrel of oil equivalent (per Boe)	$	8.97		$	9.57		$	10.44		$	9.73
Production Taxes (per Boe)	$	3.34		$	8.41		$	4.03		$	8.70
General and Administrative Expense (per Boe)	$	7.63		$	9.85		$	7.90		$	11.49
Depletion, Depreciation and Accretion (per Boe)	$	18.10		$	32.69		$	25.42		$	33.10

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

Depletion of Oil and Natural Gas Properties

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

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

Productive Oil Wells

The following table summarizes gross and net productive oil wells by state at September 30, 2015 and 2014, respectively. A net well represents our percentage ownership of a gross well. The following table does not include wells in which our interest is limited to royalty and overriding royalty interests. The following table also does not include wells which were awaiting completion, in the process of completion or awaiting flow back subsequent to fracture stimulation.

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

Exploratory Oil Wells

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

September 30, 2015

September 30, 2014

Gross

Net

Gross

Net

North Dakota

–

0.17

Total

–

0.17

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

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

	Three Months Ended
	September 30,						Increase /
	2015			2014			(Decrease)
Oil and gas sales	$	3,359,684		$	5,492,326		$	(2,132,642	)
Gain (loss) on settled derivatives		7,456,284			(70,253	)		7,526,537
Gain (loss) on mark-to-market of derivatives		(3,297,358	)		2,147,798			(5,445,156	)
Total revenues:		7,518,610			7,569,871			(51,261	)

Operating expenses:
Production expenses		887,187			670,404			216,783
Production taxes		330,186			588,923			(258,737	)
General and administrative		754,788			690,189			64,599
Depletion of oil and gas properties		1,778,580			2,275,703			(497,123	)
Impairment of oil and natural gas properties		30,995,000			–			30,995,000
Accretion of discount on ARO		8,039			5,833			2,206
Depreciation and amortization		4,010			8,214			(4,204	)
Total operating expenses:		34,757,790			4,239,266			30,518,524

Net operating income (loss)		(27,239,180	)		3,330,605			(30,569,785	)

Total other income (expense)		(1,681,307	)		(1,439,302	)		(242,005	)

Loss before provision for income taxes		(28,920,487	)		1,891,303			(30,811,790	)

Provision for income taxes		–			(700,587	)		700,587

Net loss	$	(28,920,487	)	$	1,190,716		$	(30,111,203	)

Oil and Natural Gas Sales

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

Derivatives

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

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

Production Expenses

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

Production Taxes

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

General and Administrative Expenses

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

Depletion of Oil and Natural Gas Properties

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

Impairment of Oil and Natural Gas Properties

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

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

Depreciation and Accretion

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

Other Income and (Expense)

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

Provision for Income Taxes

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

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

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

	Nine Months Ended
	September 30,						Increase /
	2015			2014			(Decrease)
Oil and gas sales	$	11,296,220		$	15,076,743		$	(3,780,523	)
Gain (loss) on settled derivatives		9,436,903			(449,135	)		9,886,038
Loss on mark-to-market of derivatives		(4,886,184	)		1,052,639			(5,938,823	)
Total revenues:		15,846,939			15,680,247			166,692

Operating expenses:
Production expenses		3,030,707			1,773,458			1,257,249
Production taxes		1,171,530			1,585,755			(414,225	)
General and administrative		2,295,241			2,095,071			200,170
Depletion of oil and gas properties		7,346,356			5,994,180			1,352,176
Impairment of oil and natural gas properties		52,634,000			–			52,634,000
Accretion of discount on asset retirement obligations		23,900			15,486			8,414
Depreciation and amortization		12,286			24,327			(12,041	)
Total operating expenses:		66,514,020			11,488,277			55,025,743

Net operating income (loss)		(50,667,081	)		4,191,970			(54,859,051	)

Total other income (expense)		(4,789,020	)		(3,815,325	)		(973,695	)

Income (loss) before provision for income taxes		(55,456,101	)		376,645			(55,832,746	)

Provision for income taxes		6,593,040			(110,849	)		6,703,889

Net loss	$	(48,863,061	)	$	265,796		$	(49,128,857	)

Oil and Natural Gas Sales

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

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

Derivatives

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

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

Production Expenses

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

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

Production Taxes

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

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

General and Administrative Expenses

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

Depletion of Oil and Natural Gas Properties

Our depletion expense is driven by many factors, including certain exploration costs involved in the development of producing reserves, production levels and estimates of proved reserve quantities and future developmental costs. We recognized depletion expense of $7,346,356 and $5,994,180 for the nine months ended September 30, 2015 and 2014, respectively, an increase of $1,352,176, or 23%. The increase was due primarily to our increased production, partially offset by a decrease in our full cost pool resulting from our impairment taken in second quarter of 2015. Depletion expense per Boe produced decreased from $32.88 in 2014 to $25.30 in 2015.

Impairment of Oil and Natural Gas Properties

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

Depreciation and Accretion

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

Other Income and (Expense)

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

Provision for Income Taxes

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

Non-GAAP Financial Measures

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

Black Ridge Oil & Gas, Inc.

Reconciliation of Adjusted Net Income (Loss)

(Unaudited)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2015			2014			2015			2014
Net income (loss)	$	(28,920,487	)	$	1,190,716		$	(48,863,061	)	$	265,796
Add back:
Loss (income) on mark-to-market of derivatives, net of tax ^(a)		3,297,358			(1,352,798	)		4,300,184			(663,639	)
Impairment of oil and gas properties, net of tax ^(b)		30,995,000			–			46,318,000			–
Adjusted net income (loss)	$	5,371,871		$	(162,082	)	$	1,755,123		$	(397,843	)

Weighted average common shares outstanding - basic		47,979,990			47,979,990			47,979,990			47,979,990

Weighted average common shares outstanding - fully diluted		47,979,990			49,588,039			47,979,990			49,824,437

Net income (loss) per common share – basic	$	(0.60	)	$	0.02		$	(1.02	)	$	0.01
Add:
Change due to loss (income) on mark-to-market of derivatives, net of tax		0.07			(0.03	)		0.09			(0.01	)
Change due to impairment of oil and gas properties, net of tax		0.65			–			0.97			–
Adjusted net income (loss) per common share – basic	$	0.11		$	(0.00	)	$	0.04		$	(0.01	)

Net income (loss) per common share – fully diluted	$	(0.60	)	$	0.02		$	(1.02	)	$	0.01
Add:
Change due to loss (income) on mark-to- market of derivatives, net of tax		0.07			(0.03	)		0.09			(0.01	)
Change due to impairment of oil and gas properties, net of tax		0.65			–			0.97			–
Adjusted net income (loss) per common share – fully diluted	$	0.11		$	(0.00	)	$	0.04		$	(0.01	)

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

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

Black Ridge Oil & Gas, Inc.

Reconciliation of Adjusted EBITDA (Unaudited)

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

Adjusted EBITDA	$	8,995,932		$	3,616,890		$	14,708,228		$	9,606,618

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

Liquidity and Capital Resources

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

	September 30,			December 31,
	2015			2014
Current Assets	$	6,663,190		$	9,448,043

Current Liabilities	$	8,503,979		$	10,348,697

Working Capital	$	(1,840,789	)	$	(900,654	)

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

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

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

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

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

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

Senior Credit Facility and Subordinated Credit Facilities

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

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

Subordinated Credit Facility

Intercreditor Agreements and Covenants

Debt Discount, Detachable Warrants

Although our revenues are expected to grow as our wells are placed into production, our revenues are not expected to exceed our investment in developing oil and gas wells and our operating costs throughout 2015. However, we believe our credit facilities will provide sufficient funding for our development plans through those same periods. Our prospects still must be considered in light of the risks, expenses and difficulties frequently encountered by companies in their early stage of development. Such risks for us include, but are not limited to, potential failure to earn revenues or to sufficiently monetize certain claims that we have for payments that are owed to us; an inability to identify investment and expansion targets; and dissipation of existing assets. To address these risks, we must, among other things, seek growth opportunities through investment and acquisitions in the oil and gas industry, effectively monitor and manage our claims for payments that are owed to us, implement and successfully execute our business strategy, respond to competitive developments, and attract, retain and motivate qualified personnel. We cannot assure that we will be successful in addressing such risks, and the failure to do so could have a material adverse effect on our business prospects, financial condition and results of operations.

Satisfaction of our cash obligations for the next 12 months

As of September 30, 2015, our balance of cash and cash equivalents was $58,599. Our plan for satisfying our cash requirements for the next twelve months, in addition to our revenues from oil and gas sales is through draws on our credit facilities, sale of properties that do not meet our investment criteria, and potential sale or use of shares of our stock.

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

Off-Balance Sheet Arrangements

We have no off-balance sheet arrangements.

Critical Accounting Policies and Estimates

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

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

Stock-Based Compensation

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

Full Cost Method

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

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

Commodity Price Risk

The price we receive for our crude oil and natural gas production will heavily influence our revenue, profitability, access to capital and future rate of growth. Crude oil and natural gas are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for crude oil and natural gas have been volatile, and these markets will likely continue to be volatile in the future. The prices we receive for our production depend on numerous factors beyond our control. Our revenue will generally increase or decrease along with any increases or decreases in crude oil or natural gas prices, but the exact impact on our income is indeterminable given the variety of expenses associated with producing and selling crude oil that also increase and decrease along with crude oil prices.

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

Interest Rate Risk

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

ITEM 4. CONTROLS AND PROCEDURES.

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

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

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

PART II - OTHER INFORMATION

Item 1. Legal Proceedings.

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

ITEM 1A. RISK FACTORS.

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

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

None.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES.

None.

ITEM 4. MINE SAFETY DISCLOSURES.

Not applicable.

ITEM 5. OTHER INFORMATION.

None.

ITEM 6. EXHIBITS.

Exhibit		Description
3.1		Certificate of Incorporation (incorporated by reference to Exhibit 3.1 of the Form 8-K filed with the Securities and Exchange Commission by Black Ridge Oil & Gas, Inc. on December 12, 2012)
3.2		Bylaws (incorporated by reference to Exhibit 3.2 of the Form 8-K filed with the Securities and Exchange Commission by Black Ridge Oil & Gas, Inc. on December 12, 2012)
10.1* Ω		Limited Liability Company Agreement of Merced Black Ridge, LLC dated July 21, 2015
10.2* Ω		Management Services Agreement dated July 21, 2015 by and between Black Ridge Oil & Gas, Inc. and Merced Black Ridge, LLC
31.1*		Section 302 Certification of Chief Executive Officer
31.2*		Section 302 Certification of Chief Financial Officer
32.1*		Section 906 Certification of Chief Executive Officer
32.2*		Section 906 Certification of Chief Financial Officer
101.INS*		XBRL Instance Document
101.SCH*		XBRL Schema Document
101.CAL*		XBRL Calculation Linkbase Document
101.DEF*		XBRL Definition Linkbase Document
101.LAB*		XBRL Labels Linkbase Document
101.PRE*		XBRL Presentation Linkbase Document

* Filed herewith.

Ω Filed subject to confidential treatment request.

SIGNATURES

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

	BLACK RIDGE OIL & GAS, INC.

Dated: November 13, 2015	By:	/s/ Kenneth DeCubellis
			Kenneth DeCubellis, Chief Executive Officer (Principal Executive Officer)

Dated: November 13, 2015	By:	/s/ James A. Moe
			James A. Moe, Chief Financial Officer (Principal Financial Officer)

Attached files

Sow Good Inc. Reports

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