Sow Good Inc. - FORM 10-Q - August 12, 2014

Attached files

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EX-31.1 - CERTIFICATION - Sow Good Inc.	brog_10q-ex3101.htm
EX-31.2 - CERTIFICATION - Sow Good Inc.	brog_10q-ex3102.htm
EX-32.2 - CERTIFICATION - Sow Good Inc.	brog_10q-ex3202.htm
EX-32.1 - CERTIFICATION - Sow Good Inc.	brog_10q-ex3201.htm
EXCEL - IDEA: XBRL DOCUMENT - Sow Good Inc.	Financial_Report.xls

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)

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

For Quarterly Period Ended June 30, 2014

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

For the Transition period from _______________ to ______________

Commission File Number 000-53952

(Name of registrant in its charter)

Nevada

(State or other jurisdiction of incorporation or organization)

27-2345075

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

10275 Wayzata Blvd. Suite 100, Minnetonka, Minnesota 55305

(Address of principal executive offices) (Zip Code)

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

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

Yes

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	o		Accelerated filer	o
Non-accelerated filer (Do not check if a smaller reporting company)	o		Smaller reporting company	x

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

Yes

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

The number of shares of registrant’s common stock outstanding as of August 8, 2014 was 47,979,990.

TABLE OF CONTENTS

PART I - FINANCIAL INFORMATION
ITEM 1.	FINANCIAL STATEMENTS (Unaudited)	3
	Condensed Balance Sheets as of June 30, 2014 (Unaudited) and December 31, 2013	3
	Unaudited Condensed Statements of Operations for the Three and Six Months Ended June 30, 2014 and 2013	4
	Unaudited Condensed Statements of Cash Flows for the Six Months Ended June 30, 2014 and 2013	5
	Notes to the Condensed Financial Statements (Unaudited)	6
ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	24
ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	40
ITEM 4.	CONTROLS AND PROCEDURES	40
PART II - OTHER INFORMATION
ITEM 1.	Legal Proceedings	41
ITEM 1A.	RISK FACTORS	41
ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	41
ITEM 3.	DEFAULTS UPON SENIOR SECURITIES	41
ITEM 4.	MINE SAFETY DISCLOSURES	41
ITEM 5.	OTHER INFORMATION	41
ITEM 6.	EXHIBITS	41
	SIGNATURES	42

PART I - FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS.

BLACK RIDGE OIL & GAS, INC.

CONDENSED BALANCE SHEETS

	June 30,			December 31,
	2014			2013
	(Unaudited)
ASSETS

Current assets:
Cash and cash equivalents	$	84,415		$	1,150,347
Accounts receivable		4,740,795			1,905,467
Advances to operators		2,560,046			1,214,662
Prepaid expenses		41,954			26,142
Total current assets		7,427,210			4,296,618

Property and equipment:
Oil and natural gas properties, full cost method of accounting:
Proved properties		91,749,159			79,361,432
Unproved properties		2,855,106			2,798,795
Other property and equipment		126,613			115,482
Total property and equipment		94,730,878			82,275,709
Less, accumulated depreciation, amortization, depletion and allowance for impairment		(13,248,024	)		(9,513,434	)
Total property and equipment, net		81,482,854			72,762,275

Debt issuance costs, net		682,358			772,883

Total assets	$	89,592,422		$	77,831,776


LIABILITIES AND STOCKHOLDERS' EQUITY

Current liabilities:
Accounts payable	$	8,543,446		$	8,453,709
Accrued expenses		62,853			4,813
Current portion of derivative instruments		940,926			139,065
Total current liabilities		9,547,225			8,597,587

Derivative instruments		367,909			74,611
Asset retirement obligations		211,030			160,665
Revolving credit facilities and long term debt, net of discounts of $2,475,252 and $2,645,582, respectively		42,249,343			30,556,301
Deferred tax liability		3,444,107			4,033,845

Total liabilities		55,819,614			43,423,009

Commitments and contingencies (See note 15)		–			–

Stockholders' equity:
Preferred stock, $0.001 par value, 20,000,000 shares authorized, no shares issued and outstanding		–			–
Common stock, $0.001 par value, 500,000,000 shares authorized, 47,979,990 shares issued and outstanding		47,980			47,980
Additional paid-in capital		33,361,756			33,072,795
Retained earnings		363,072			1,287,992
Total stockholders' equity		33,772,808			34,408,767

Total liabilities and stockholders' equity	$	89,592,422		$	77,831,776

See accompanying notes to financial statements.

BLACK RIDGE OIL & GAS, INC.

CONDENSED STATEMENTS OF OPERATIONS

(Unaudited)

	For the Three Months						For the Six Months
	Ended June 30,						Ended June 30,
	2014			2013			2014			2013

Oil and gas sales	$	5,553,997		$	2,151,001		$	9,584,417		$	4,062,300
Loss on settled derivatives		(262,719	)		–			(378,882	)		–
Loss on the mark-to-market of derivatives		(881,124	)		–			(1,095,159	)		–
Total revenues		4,410,154			2,151,001			8,110,376			4,062,300

Operating expenses:
Production expenses		595,591			269,461			1,103,054			538,267
Production taxes		591,525			232,528			996,832			451,870
General and administrative		634,109			586,860			1,404,882			1,190,438
Depletion of oil and gas properties		2,131,545			868,663			3,718,477			1,568,388
Accretion of discount on asset retirement obligations		5,148			1,811			9,653			2,963
Depreciation and amortization		8,188			5,811			16,113			11,622
Total operating expenses		3,966,106			1,965,134			7,249,011			3,763,548

Net operating income (loss)		444,048			185,867			861,365			298,752

Other income (expense):
Interest income		–			73			–			193
Interest (expense)		(1,293,123	)		(576,153	)		(2,376,023	)		(809,133	)
Total other income (expense)		(1,293,123	)		(576,080	)		(2,376,023	)		(808,940	)

Loss before provision for income taxes		(849,075	)		(390,213	)		(1,514,658	)		(510,188	)

Provision for income taxes		305,715			92,913			589,738			526,701

Net income (loss)	$	(543,360	)	$	(297,300	)	$	(924,920	)	$	16,513


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			47,979,990			47,979,990			48,540,032

Net income (loss) per common share - basic	$	(0.01	)	$	(0.01	)	$	(0.02	)	$	0.00
Net income (loss) per common share - fully diluted	$	(0.01	)	$	(0.01	)	$	(0.02	)	$	0.00

See accompanying notes to financial statements.

BLACK RIDGE OIL & GAS, INC.

CONDENSED STATEMENTS OF CASH FLOWS

(Unaudited)

	For the Six Months
	Ended June 30,
	2014			2013
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	(924,920	)	$	16,513
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion of oil and gas properties		3,718,477			1,568,388
Depreciation and amortization		16,113			11,622
Amortization of debt issuance costs		145,307			399,654
Accretion of discount on asset retirement obligations		9,653			2,963
Loss on the mark-to-market of derivatives		1,095,159			–
Accrued payment in kind interest applied to long term debt		472,712			–
Amortization of original issue discount on debt		60,288			–
Amortization of debt discounts, warrants		310,042			–
Common stock warrants granted as financing costs		–			65,884
Common stock options issued to employees and directors		288,961			329,714
Deferred income taxes		(589,738	)		(526,701	)
Decrease (increase) in current assets:
Accounts receivable		(2,835,328	)		(911,092	)
Prepaid expenses		(15,812	)		17,798
Increase (decrease) in current liabilities:
Accounts payable		203,177			(14,833	)
Accrued expenses		58,040			52,517
Net cash provided by operating activities		2,012,131			1,012,427

CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from sale or swap of oil and gas properties		1,360,920			343,486
Purchases of oil and gas properties and development capital expenditures		(11,731,981	)		(2,675,398	)
Advances to operators		(3,491,089	)		(615,370	)
Purchases of other property and equipment		(11,131	)		–
Net cash used in investing activities		(13,873,281	)		(2,947,282	)

CASH FLOWS FROM FINANCING ACTIVITIES
Advances from revolving credit facilities and long term debt		18,700,000			4,300,000
Repayments on revolving credit facilities		(7,850,000	)		(2,185,006	)
Debt issuance costs		(54,782	)		(25,000	)
Net cash provided by financing activities		10,795,218			2,089,994

NET CHANGE IN CASH		(1,065,932	)		155,139
CASH AT BEGINNING OF PERIOD		1,150,347			1,417,340
CASH AT END OF PERIOD	$	84,415		$	1,572,479


SUPPLEMENTAL INFORMATION:
Interest paid	$	1,457,540		$	275,920
Income taxes paid	$	–		$	–

NON-CASH INVESTING AND FINANCING ACTIVITIES:
Net change in accounts payable for purchase of oil and gas properties	$	(98,778	)	$	2,198,196
Advances to operators received in swap for oil and gas properties	$	–		$	(1,200,000	)
Advances to operators applied to development of oil and gas properties	$	2,131,043		$	1,592,306
Capitalized asset retirement costs, net of revision in estimate	$	40,712		$	2,494

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

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

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

Note 2 – Basis of Presentation and Significant Accounting Policies

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

These statements reflect all adjustments, which in the opinion of management, are necessary for fair presentation of the information contained therein. Except as otherwise disclosed, all such adjustments are of a normal recurring nature. It is suggested that these interim condensed financial statements be read in conjunction with the audited financial statements for the year ended December 31, 2013, which were included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2013. 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.

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Financial Statements

(Unaudited)

Cash and Cash Equivalents

Cash equivalents include money market accounts which have maturities of three months or less. For the purpose of the statements of cash flows, all highly liquid investments with an original maturity of three months or less are considered to be cash equivalents. Cash equivalents are stated at cost plus accrued interest, which approximates market value. Cash and cash equivalents consist of the following:

	June 30,		December 31,
	2014		2013
Cash	$	84,415	$	1,112,356
Money market funds		–		37,991
Total	$	84,415	$	1,150,347

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 $862,356 in excess of FDIC and SIPC insured limits at June 30, 2014 and December 31, 2013, 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 June 30, 2014, and December 31, 2013, was $682,358 and $772,883, respectively. Amortization of debt issuance costs charged to interest expense were $145,307 and $399,654 for the six months ended June 30, 2014 and 2013, 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 June 30, 2014. 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 $9,443 and $9,443 for the six months ended June 30, 2014 and 2013, respectively.

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Financial Statements

(Unaudited)

Income Taxes

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

Net Income (Loss) Per Common Share

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

The reconciliation of the denominators used to calculate basic EPS and diluted EPS for the three and six months ended June 30, 2014 and 2013 are as follows:

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2014		2013		2014		2013
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		–		–		–		560,042
Weighted average common shares outstanding – diluted		47,979,990		47,979,990		47,979,990		48,540,032

Stock options and warrants excluded from the calculation of diluted EPS because their effect was anti-dilutive were 16,135,709 and 9,374,876 for the three months ended June 30, 2014 and 2013, respectively, and 16,135,709 and 8,176,209 for the six months ended June 30, 2014 and 2013, respectively.

Segment Reporting

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

Fair Value of Financial Instruments

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

Non-Oil & Gas Property and Equipment

Property and equipment that are not oil and gas properties are recorded at cost and depreciated using the straight-line method over their estimated useful lives of three to seven years. Expenditures for replacements, renewals, and betterments are capitalized. Maintenance and repairs are charged to operations as incurred. Long-lived assets, other than oil and gas properties, are evaluated for impairment to determine if current circumstances and market conditions indicate the carrying amount may not be recoverable. The Company has not recognized any impairment losses on non-oil and gas long-lived assets. Depreciation expense was $16,113 and $11,622 for the six months ended June 30, 2014 and 2013, respectively.

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Financial Statements

(Unaudited)

Revenue Recognition

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

Asset Retirement Obligations

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

Full Cost Method

The Company follows the full cost method of accounting for oil and gas operations whereby all costs related to the exploration and development of oil and gas properties are initially capitalized into a single cost center ("full cost pool"). Such costs include land acquisition costs, geological and geophysical expenses, carrying charges on non-producing properties, costs of drilling directly related to acquisition, and exploration activities. Internal costs that are capitalized are directly attributable to acquisition, exploration and development activities and do not include costs related to the production, general corporate overhead or similar activities. Costs associated with production and general corporate activities are expensed in the period incurred. Capitalized costs are summarized as follows for the six months ended June 30, 2014 and 2013, respectively:

	Six Months Ended
	June 30,
	2014		2013
Capitalized Certain Payroll and Other Internal Costs	$	23,944	$	10,540
Capitalized Interest Costs		105,555		–
Total	$	129,499	$	10,540

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.

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 $288,961 and $329,714 for the six months ended June 30, 2014 and 2013, 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, $310,042 and $65,884 of warrant related costs were amortized during the six months ended June 30, 2014 and 2013, respectively, pursuant to warrants granted in consideration for credit facilities, of which $310,042 and $-0- was amortized pursuant to debt discounts during the six months ended June 30, 2014 and 2013, respectively. The fair value of warrants is determined similar to the method used in determining the fair value of employee stock options and the fair value is amortized over the life of the related credit facility and accelerated 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, 2013.

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Financial Statements

(Unaudited)

Note 3 – Acquisition

On December 13, 2013, the Company acquired oil and natural gas properties from CP Exploration, LP (“CPX”) for approximately $20.6 million, net of purchase price adjustments (“the CPX Acquisition”). The properties acquired in the CPX Acquisition are comprised of leasehold interests in approximately 2,040 net leasehold acres in the Williston Basin of North Dakota and interests in 43 gross (0.92 net) producing wells on the acquired leases.

The Company completed its valuation of the properties acquired in the CPX Acquisition which is summarized as follows:

Purchase price of Acquired Properties	$	20,680,032

Allocation of Purchase Price:
Proved Oil and Gas Properties	$	20,517,903
Unproved Oil and gas Properties		195,780
Total fair value of oil and gas properties		20,713,683
Asset retirement obligations⁽¹⁾		(33,651	)
Fair value of net assets acquired	$	20,680,032

⁽¹⁾ The estimated fair value of the acquired asset retirement obligation was determined using the Company’s credit adjusted risk-free rate.

The following unaudited pro forma combined results of operations for the six months ended June 30, 2014 and 2013 are presented as though the CPX Acquisition had been completed as of January 1, 2013. The pro forma combined results of operations for the six months ended June 30, 2014 and 2013 have been prepared by adjusting the historical results of the Company to include the historical results of the properties acquired in the CPX Acquisition. The supplemental pro forma results of operations are provided for illustrative purposes only and do not purport to be indicative of the actual results that would have been achieved by the combined company for the periods presented. The pro forma results of operations do not include any cost savings or other synergies that resulted from the CPX Acquisition or any estimated costs incurred to integrate the CPX Acquisition assets.

	Six Months Ended
	June 30,
	2014			2013
	(Unaudited)
Boe Produced		112,270			72,057

Revenues	$	8,110,376		$	6,144,500
Net operating income	$	861,365		$	1,171,004
Net income (loss)	$	(924,920	)	$	108,358
Income (loss) per common share
Basic	$	(0.02	)	$	0.00
Diluted	$	(0.02	)	$	0.00

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Financial Statements

(Unaudited)

Note 4 – Property and Equipment

Property and equipment at June 30, 2014 and December 31, 2013, consisted of the following:

	June 30,			December 31,
	2014			2013
Oil and gas properties, full cost method:
Evaluated costs	$	91,749,159		$	79,361,432
Unevaluated costs, not subject to amortization or ceiling test		2,855,106			2,798,795
		94,604,265			82,160,227
Other property and equipment		126,613			115,482
		94,730,878			82,275,709
Less: Accumulated depreciation, amortization, depletion and impairments		(13,248,024	)		(9,513,434	)
Total property and equipment, net	$	81,482,854		$	72,762,275

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

	Six Months Ended
	June 30,
	2014		2013
Depletion of costs for evaluated oil and gas properties	$	3,718,477	$	1,568,388
Depreciation and amortization of other property and equipment		16,113		11,622
Total depreciation, amortization and depletion	$	3,734,590	$	1,580,010

Note 5 – Oil and Gas Properties

The following table summarizes gross and net productive oil wells by state at June 30, 2014 and 2013. A net well represents our percentage ownership of a gross well. The following table does not include wells in which our interest is limited to royalty and overriding royalty interests. The following table also does not include wells which were awaiting completion, in the process of completion or awaiting flow back subsequent to fracture stimulation.

	June 30, 2014				June 30, 2013
	Gross		Net		Gross		Net
North Dakota		206		6.20		80		2.74
Montana		1		0.08		1		0.08
Total		207		6.28		81		2.82

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 June 30, 2014 and 2013, our principal oil and gas assets included approximately 9,800 and 11,891 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 six months ended June 30, 2014 and 2013, respectively:

	Six Months Ended
	June 30,
	2014			2013
Purchases of oil and gas properties and development costs for cash	$	11,731,981		$	2,675,398
Purchase of oil and gas properties accrued at period-end		7,855,023			4,816,341
Purchase of oil and gas properties accrued at beginning of period		(7,953,801	)		(2,618,145	)
Advances to operators applied to purchase of oil and gas properties		2,131,043			1,592,306
Capitalized asset retirement costs, net of revision in estimate		40,712			2,494
Total purchase and development costs, oil and gas properties	$	13,804,958		$	6,468,394

2014 Acquisitions

During the six months ended June 30, 2014, we purchased approximately 200 net leasehold acres of oil and gas properties in North Dakota. In consideration for the assignment of these mineral leases, we paid the sellers a total of approximately $1,652,551.

2014 Divestitures

During the six months ended June 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 six months ended June 30, 2014, we traded a total of approximately 52 net mineral 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.

2013 Acquisitions

During the six months ended June 30, 2013, we purchased approximately 800 net leasehold acres of oil and gas properties in North Dakota. In consideration for the assignment of these mineral leases, we paid the sellers a total of approximately $416,283.

2013 Divestitures

During the six months ended June 30, 2013, we sold a total of approximately 105 net leasehold acres of oil and gas properties for total proceeds of $343,486. No gain or loss was recorded pursuant to the sales.

2013 Swap Transactions

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

Undeveloped Acreage Expirations

During the six months ended June 30, 2014, we had leases encompassing 4,196 net acres expire with carrying costs of $6,187,557 that had been reserved and transferred to the full cost pool subject to depletion in 2013. We estimate that approximately 6 additional net acres with carrying costs of approximately $10,002 will expire prior to the commencement of production activities on the related leased property during 2014. The carrying costs of leases we estimate will expire in 2015 have also been reserved and transferred to the full cost pool and are subject to depletion.

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Financial Statements

(Unaudited)

Note 6 – Asset Retirement Obligation

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

The following table summarizes the Company’s asset retirement obligation transactions recorded in accordance with the provisions of FASB ASC 410-20-25 during the six months ended June 30, 2014 and 2013:

	Six Months Ended
	June 30,
	2014		2013
Beginning asset retirement obligation	$	160,665	$	67,145
Revision in estimate of asset retirement obligation		–		(20,123	)
Liabilities incurred for new wells placed in production		40,712		22,617
Accretion of discount on asset retirement obligation		9,653		2,963
Ending asset retirement obligation	$	211,030	$	72,602

Note 7 – Related Party

We have subleased and currently lease office space on a month to month basis where the lessor is an entity owned by our former CEO and current Chairman of the Board of Directors, Bradley Berman. The sublease agreement was cancelled and we entered into a direct lease on April 30, 2012 to expand and occupy approximately 1,142 square feet of office space. The 2012 lease was amended effective November 15, 2013 to 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 $35,501 and $15,765 to this entity during the six months ended June 30, 2014 and 2013, respectively.

Note 8 – Derivative Instruments

The Company is required to recognize all derivative instruments on the balance sheet as either assets or liabilities measured at fair value. The Company has not designated its derivative instruments as 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 June 30, 2014, the Company had outstanding derivative contracts with respect to future production as follows:

Crude Oil Swaps
Settlement Period	Oil (Barrels)		Fixed Price
July 1, 2014 – December 31, 2014		22,002	$	94.45
July 1, 2014 – December 31, 2014		19,998	$	93.40
July 1, 2014 – December 31, 2014		18,000	$	94.90
July 1, 2014 – December 31, 2014		12,000	$	100.12
January 1, 2015 – December 31, 2015		24,000	$	88.28
January 1, 2015 – December 31, 2015		21,000	$	89.70
January 1, 2015 – December 31, 2015		12,000	$	92.37
January 1, 2016 – December 31, 2016		60,000	$	90.36

Crude Oil Costless Collars

Floor/Ceiling

Settlement Period

Oil (Barrels)

Price

Basis

January 1, 2015 – December 31, 2015

36,000

$75.00/$95.60

NYMEX

January 1, 2016 – June 30, 2016

10,002

$80.00/$89.50

NYMEX

As of June 30, 2014 the Company had total volume on open commodity swaps of 189,000 barrels at a weighted average price of approximately $92 per barrel.

Derivative Gains and Losses

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

	Six Months Ended
	June 30,
	2014			2013
Realized loss on derivatives:
Crude oil fixed price swaps	$	(378,882	)	$	–
Crude oil collars		–			–
Realized loss on derivatives, net	$	(378,882	)	$	–

Unrealized gain (loss) on derivatives:
Crude oil fixed price swaps	$	(912,071	)	$	–
Crude oil collars		(183,088	)		–
Unrealized loss on derivatives, net	$	(1,095,159	)	$	–

Balance Sheet Offsetting of Derivative Assets and Liabilities

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

All of the Company’s derivative contracts are carried at their fair value in the condensed balance sheets under the captions “Derivative instruments” and “Noncurrent derivative instruments”. Derivative instruments from the same counterparty that are subject to contractual terms which provide for net settlement are reported on a net basis in the condensed balance sheets. The following tables present the gross amounts of recognized derivative assets and liabilities, the amounts offset under the netting arrangements with counterparties, and the resulting net amounts presented in the condensed balance sheets for the periods presented, all at fair value.

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Financial Statements

(Unaudited)

June 30, 2014

December 31, 2013

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 assets

–

June 30, 2014

December 31, 2013

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

(1,360,074)

51,239

(1,308,835)

(396,573)

182,897

(213,676)

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

	June 30,			December 31,
	2014			2013
Derivative assets	$	–		$	–
Noncurrent derivative assets		–			–
Net amount of assets on the balance sheet		–			–

Current portion of derivative instruments		(940,926	)		(139,065	)
Derivative instruments		(367,909	)		(74,611	)
Net amounts of liabilities on the balance sheet		(1,308,835	)		(213,676	)
Total derivative liabilities, net	$	(1,308,835	)	$	(213,676	)

Note 9 – Fair Value of Financial Instruments

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

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Financial Statements

(Unaudited)

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

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

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

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

The following schedule summarizes the valuation of financial instruments at fair value on a recurring basis in the balance sheets as of June 30, 2014 and December 31, 2013:

Fair Value Measurements at June 30, 2014

Level 1

Level 2

Level 3

Assets

Cash and cash equivalents

84,415

–

Total assets

84,415

–

Liabilities

Derivative instruments (crude oil swaps and collars)

–

1,308,835

–

Revolving credit facilities and long term debt, net of discounts

–

42,249,343

–

Total Liabilities

–

43,558,178

–

84,415

(43,558,178

)

–

Fair Value Measurements at December 31, 2013

Level 1

Level 2

Level 3

Assets

Cash and cash equivalents

1,150,347

–

Total assets

1,150,347

–

Liabilities

Derivative instruments (crude oil swaps and collars)

–

213,676

–

Revolving credit facilities and long term debt, net of discounts

–

30,556,301

–

Total Liabilities

–

30,769,977

–

1,150,347

(30,769,977

)

–

There were no transfers of financial assets or liabilities between Level 1 and Level 2 inputs for the six months ended June 30, 2014 and 2013.

Level 2 liabilities include Revolving credit facilities. No fair value adjustment was necessary during the six months ended June 30, 2014 and 2013.

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Financial Statements

(Unaudited)

Note 10 – Revolving Credit Facilities and Long Term Debt

Senior Credit Facility and Subordinated Credit Facilities

The Company, as borrower, entered into a Credit Agreement dated August 8, 2013 and amendments thereto dated December 13, 2013 and March 24, 2014 (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 existing debt under the Company’s former credit facility with Dougherty Funding LLC.

Availability under the Senior Credit Facility is at all times subject to the then-applicable borrowing base, determined by Cadence in a manner consistent with the normal and customary oil and gas lending practices of Cadence. Availability was initially set at $7 million and is subject to periodic redeterminations. The availability has been increased to $20 million as a result of redeterminations. Subject to availability under the borrowing base, the Company may borrow, repay and re-borrow funds in amounts of $250,000 or more. At the Company’s election, the unpaid principal balance of any borrowings under the Senior Credit Facility may bear interest at either (i) the Base Rate, as defined in the Senior Credit Facility, plus the applicable margin, which varies from 1.00% to 1.50% or (ii) the LIBOR rate, as defined in the Senior Credit Facility, plus the applicable margin, which varies from 3.00% to 3.50%. Interest is payable for Base Rate loans on the last business day of the month and for LIBOR loans on the last LIBOR business day of each LIBOR interest period. The Company is also required to pay a quarterly fee of 0.50% on any unused portion of the borrowing base, as well as a facility fee of 0.90% of the initial and any subsequent additions to the borrowing base.

The Senior Credit Facility will mature on August 8, 2016. The Company may prepay the entire amount of Base Rate loans at any time, and may prepay the entire amount of LIBOR loans upon at least three business days’ notice to Cadence. The Senior Credit Facility is secured by first priority interests in mortgages on substantially all of the Company’s assets, including but not limited to the Company’s mineral interests in North Dakota and Montana.

As of June 30, 2014, the Company had borrowings of $14.05 million outstanding under the Senior Credit Agreement.

The Company, as borrower, entered into a Second Lien Credit Agreement dated August 8, 2013 and amendments thereto dated December 13, 2013 and March 24, 2014 (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 former credit facility, (ii) for fees and closing costs in connection with both the Senior Credit Facility and the Subordinated Credit Facility (together, the “Credit Facilities”), and (iii) general corporate purposes.

The Subordinated Credit Agreement provides for initial commitment availability of $25 million, subject to customary conditions, with the remaining commitments subject to the approval of Chambers and other customary conditions. The Company may borrow the available commitments in amounts of $5 million or more and shall not request borrowings of such loans more than once a month, provided that the initial draw 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.

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Financial Statements

(Unaudited)

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 $14,700,000, net of a $300,000 original issue discount, from the Subordinated Credit Agreement and used $10,226,057 of those proceeds to repay and terminate the Dougherty revolving credit facility. We have drawn an additional $14,700,000, net of $300,000 original issue discount through June 30, 2014. Availability under the facility is $35 million as of June 30, 2014.

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

The Credit Facilities, as amended, require customary affirmative and negative covenants for credit facilities of the respective types and sizes for companies operating in the oil and gas industry, as well as customary events of default. Furthermore, the Credit Facilities contain financial covenants that require the Company to satisfy certain specified financial ratios. The Senior Credit Agreement requires the Company to maintain (i) as of the last day of each fiscal quarter of the Company, 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, and 0.80 to 1.00 for the quarter ending March 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, (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, and 3.50 to 1.00 for the quarter ended March 31, 2015 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 (i) as of the last day of each fiscal quarter of the Company, 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, and 0.80 to 1.00 for the quarter ending March 31, 2015 and thereafter, (ii) as of the last day of each fiscal quarter of the Company, a consolidated net leverage ratio (adjusted total indebtedness less the amount of unrestricted cash equivalents to consolidated EBITDA) of no more than 3.75 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, and 3.50 to 1.00 for the quarter ending March 31, 2015 and thereafter, calculated on a modified trailing four quarter basis, (iii) as of the last day of any fiscal quarter of the Company, a consolidated cash interest coverage ratio (consolidated EBITDA to consolidated cash interest expense) of no less than 2.5 to 1.0, calculated on a modified trailing four quarter basis and (iv) as of the last day of any period of four consecutive fiscal quarters of the Company, a ratio of consolidated current assets to consolidated current liabilities of at least 1.0 to 1.0. In addition, each of the Credit Facilities requires that the Company enter into hedging agreements prior to funding with regard to no less than 50% and no greater than 75% of its future oil production on currently producing wells. The Company is in compliance with all covenants, as amended, for the period ending June 30, 2014.

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Financial Statements

(Unaudited)

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 $310,042 was amortized during the six months ended June 30, 2014. The remaining unamortized balance of the debt discount attributable to the warrants is $1,963,902 as of June 30, 2014.

Dougherty Revolving Credit Facility (former credit facility)

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

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

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

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

Amounts outstanding under revolving credit facilities and long term debts consisted of the following as of June 30, 2014 and December 31, 2013, respectively:

	June 30,			December 31,
	2014			2013
Senior Revolving Credit Facility, Cadence Bank, N.A.	$	14,050,000		$	13,000,000
Subordinated Credit Agreement, Chambers		30,000,000			20,000,000
PIK Interest on Subordinated Credit Agreement, Chambers		674,595			201,883

Total credit facilities and long term debts		44,724,595			33,201,883
Less: Unamortized OID		(511,350	)		(371,638	)
Less: Unamortized debt discount attributable to warrants		(1,963,902	)		(2,273,944	)
Total credit facilities and long term debts, net of discounts		42,249,343			30,556,301
Less: current maturities		–			–

Long term portion of credit facilities and long term debts	$	42,249,343		$	30,556,301

Net proceeds of $29,400,000 were received from our $30,000,000 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 $60,288 was amortized during the six months ended June 30, 2014. The remaining unamortized balance of the debt discount attributable to the OID is $511,350 as of June 30, 2014.

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Financial Statements

(Unaudited)

The following presents components of interest expense for the six months ended June 30, 2014 and 2013, respectively:

	Six Months Ended
	June 30,
	2014			2013
Accrued PIK interest	$	472,712		$	–
Amortization of OID		60,288			–
Interest and commitment fees		1,493,229			343,595
Amortization of debt issuance costs		145,307			399,654
Amortization of warrant costs		310,042			65,884
Less interest capitalized to the full cost pool of our proved oil & gas properties		(105,555	)		–
	$	2,376,023		$	809,133

Note 11 – Changes in Stockholders’ Equity

Preferred Stock

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

Common Stock

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

Note 12 – Options

Options Granted

On February 10, 2014, the Company granted 27,500 options to purchase its common stock to an employee. 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 exercise prices of $0.782 per share. The total estimated fair value using the Black-Scholes Pricing Model, based on a volatility rate of 116% and a call option value of $0.6778 was $18,639 and is being amortized over the vesting period.

On January 30, 2014, the Company granted 5,000 options to purchase its common stock to an employee. 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 exercise prices of $0.63 per share. The total estimated fair value using the Black-Scholes Pricing Model, based on a volatility rate of 115% and a call option value of $0.5471 was $2,735 and is being amortized over the vesting period.

The Company recognized a total of $288,961, and $329,714 of compensation expense during the six months ended June 30, 2014 and 2013, 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 $2,115,749 as of June 30, 2014.

Options Exercised

No options were exercised during the six months ended June 30, 2014 and 2013.

Options Forfeited

No options were forfeited during the six months ended June 30, 2014 and 2013.

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Financial Statements

(Unaudited)

Note 13 – Warrants

Warrants Granted

No warrants were granted during the six months ended June 30, 2014 and 2013.

We recognized a total of $310,042 and $65,884 of finance expense during the six months ended June 30, 2014 and 2013, 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 six months ended June 30, 2014 and 2013.

Note 14 – Income Taxes

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

We currently estimate that our effective tax rate for the year ending December 31, 2014 will be approximately 37%. Losses incurred during the period from April 9, 2011 (inception) to June 30, 2014 could be used to offset future tax liabilities. Accounting standards require the consideration of a valuation allowance for deferred tax assets if it is “more likely than not” that some component or all of the benefits of deferred tax assets will not be realized. As of June 30, 2014, net deferred tax assets were $13,453,500 after a valuation allowance applied to net deferred tax assets of approximately $567,688. This valuation allowance reflects an allowance on only a portion of the Company’s deferred tax assets which the Company believes it is more likely than not that the benefit of these assets will not be realized. We have not provided any valuation allowance against our deferred tax liabilities. As of June 30, 2014, the Company recognized deferred tax liabilities totaling $16,897,607 primarily related to differences in the book and tax basis amounts of the Company’s oil and gas properties resulting from the expensing of intangible drilling costs and the accelerated depreciation utilized for tax purposes.

The tax benefit for the six months ended June 30, 2014 of $589,738 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 June 30, 2014.

Note 15 – Commitments and Contingencies

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

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

The Company commits to its participation in upcoming well development by signing an Authorization for Expenditure (“AFE”). As of June 30, 2014, the Company had committed to AFE’s of approximately $10.7 million beyond amounts previously paid or accrued. Additionally, the Company acquired a lease for mineral rights from the State of North Dakota on February 14, 2012 for 110 acres or an 8.7% working interest in the Dahl Federal 2-15H well that spud on January 6, 2012. The acreage we purchased lies within the riverbed of the Missouri River and there is currently third-party litigation ongoing in the State of North Dakota pertaining to the state’s ownership claim to similar riparian acreage. We have signed an AFE for the well and the operator has agreed to retroactively honor the AFE if the state is successful in defending its ownership claim. As a result we have not capitalized any of the AFE costs or recognized any sales from this well. Our proportion of the well costs, based on the AFE and our working interest, is approximately $800,000. The well started production on May 21, 2012. Had we recognized the revenue and expenses from this well, we would have recorded approximately an additional $1,057,000 in oil and gas sales and $271,000 of production taxes and operating expenses to date of which $138,000 of oil and gas revenue and $37,000 of production expenses and taxes would relate to the six months ended June 30, 2014. In the event the state is not successful in defending its ownership claim, the state is required to refund the Company the cost to purchase the lease.

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Financial Statements

(Unaudited)

Note 16 – Subsequent Events

Debt Facilities

During the period from June 30, 2014 to August 12, 2014, the Company drew an additional $1.25 million on the senior secured facility.

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;

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 June 30, 2014, we owned an interest in 207 gross (6.28 net) producing oil and gas wells and controlled the rights to mineral leases covering approximately 9,800 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 June 30, 2014				As of December 31, 2013
	Productive Wells		Average Daily	Proved
Net Acres ⁽¹⁾	Gross	Net	Production ⁽²⁾	Reserves	PV-10 ⁽³⁾
			(Boe per day)	(000's Boe)	($000)
9,800	207	6.28	715	4,538	74,377

_______________

⁽¹⁾Includes leases encompassing approximately 6 net acres that we estimate will expire over the remainder of 2014.

⁽²⁾Represents average daily production over the three months ended June 30, 2014.

⁽³⁾PV-10 is a non-GAAP financial measure. 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, 2013.

Looking forward, we are pursuing the following objectives:

acquire high-potential mineral leases;

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

develop and maintain strategic industry relationships;

attract and retain talented associates;

operate a low overhead non-operator business model; and

become a low cost producer of hydrocarbons.

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

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

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

the sales price per barrel of oil;

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

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

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

Operational Highlights

During the second quarter of 2014, we achieved the following financial and operating results:

production reached 715 Boe per day, representing 153% growth compared to the second quarter of 2013 and 36% growth compared to the first quarter of 2014;

participated in the completion of 19 gross (0.77 net) wells increasing our total producing wells to 207 gross (6.28 net) wells;

attained adjusted EBITDA from operations of $3.6 million;

reduced general and administrative expenses to $9.75 per Boe, compared to $22.80/per Boe in the second quarter of 2013, representing a 57% decrease on a per Boe basis;

realized $1.1 million of cash flow from operating activities; and

continued expansion of our activities in the Bakken and Three Forks plays by growing production and improving our acreage portfolio.

Operationally, our second quarter of 2014 performance reflects continued success in executing our strategy of developing our acreage position and building production. Our production increased 38% to 65,059 Boe in the second quarter of 2014 as compared to first quarter of 2014 production of 47,211 Boe. The increase in production was driven by a 14% increase in net producing wells from 5.51 net wells at March 31, 2014 to 6.28 net wells at June 30, 2014.

Total revenues increased 105% in the second quarter of 2014 compared to the second quarter of 2013 primarily driven by increased production. Average realized prices on a Boe basis decreased 3% after the effect of settled derivatives, in the second quarter of 2014 compared to the second quarter of 2013. Additionally, our loss on the mark-to-market of derivatives was $881,000. Significant changes in crude oil and natural gas prices can have a material impact on our results of operations and our balance sheet.

Recent Developments

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 month and six month periods ended June 30, 2014 and 2013, respectively. As of June 30, 2014, we controlled approximately 9,800 net acres in the Williston Basin. In addition, the Company owned working interests in 207 gross wells representing 6.28 net wells that are producing and an additional 47 gross wells representing 1.64 net wells that are preparing to drill, drilling, awaiting completion or completing.

	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2014			2013		2014			2013
Net Production:
Oil (Bbl)		58,812			23,663		101,967			44,159
Natural Gas (Mcf)		37,482			12,465		61,819			20,302
Barrel of Oil Equivalent (Boe)		65,059			25,741		112,270			47,543

Average Sales Prices:
Oil (per Bbl)	$	91.27		$	88.02	$	89.88		$	89.26
Effect of oil hedges on average price (per Bbl)	$	(4.47	)	$	–	$	(3.71	)	$	–
Oil net of hedging (per Bbl)	$	86.80		$	88.02	$	86.17		$	89.26
Natural Gas (per Mcf)	$	4.97		$	5.48	$	6.78		$	5.94
Effect of natural gas hedges on average price (per Mcf)	$	–		$	–	$	–		$	–
Natural gas net of hedging (per Mcf)	$	4.97		$	5.48	$	6.78		$	5.94

Average Production Costs:
Oil (per Bbl)	$	9.79		$	11.03	$	9.85		$	11.83
Natural Gas (per Mcf)	$	0.53		$	0.69	$	0.75		$	0.78
Barrel of Oil Equivalent (Boe)	$	9.15		$	10.47	$	9.36		$	11.32

Depletion of Oil and Natural Gas Properties

Our depletion expense is driven by many factors including certain exploration costs involved in the development of producing reserves, production levels and estimates of proved reserve quantities and future developmental costs. The following table presents our depletion expenses for the six months ended June 30, 2014 and 2013, respectively.

	Six Months Ended
	June 30,
	2014		2013
Depletion of oil and natural gas properties	$	3,718,477	$	1,568,388

Productive Oil Wells

The following table summarizes gross and net productive oil wells by state at June 30, 2014 and 2013, respectively. A net well represents our percentage ownership of a gross well. The following table does not include wells in which our interest is limited to royalty and overriding royalty interests. The following table also does not include wells which were awaiting completion, in the process of completion or awaiting flow back subsequent to fracture stimulation.

	June 30, 2014				June 30, 2013
	Gross		Net		Gross		Net
North Dakota		206		6.20		80		2.74
Montana		1		0.08		1		0.08
Total		207		6.28		81		2.82

Exploratory Oil Wells

The following table summarizes gross and net exploratory wells as of June 30, 2014 and 2013. The wells are at various stages of completion and the costs incurred are included in unevaluated oil and gas properties on our balance sheet.

	June 30, 2014				June 30, 20143
	Gross		Net		Gross		Net
North Dakota		7		0.29		2		0.15
Total		7		0.29		2		0.15

Results of Operations for the Three Months Ended June 30, 2014 and 2013.

The following table summarizes selected items from the statement of operations for the three months ended June 30, 2014 and 2013, respectively.

	Three Months Ended
	June 30,						Increase /
	2014			2013			(Decrease)
Oil and gas sales	$	5,553,997		$	2,151,001		$	3,402,996
Loss on settled derivatives		(262,719	)		–			(262,719	)
Loss on mark-to-market of derivatives		(881,124	)		–			(881,124	)
Total revenues:		4,410,154			2,151,001			2,259,153

Operating expenses:
Production expenses		595,591			269,461			326,130
Production taxes		591,525			232,528			358,997
General and administrative		634,109			586,860			47,249
Depletion of oil and gas properties		2,131,545			868,663			1,262,882
Accretion of discount on asset retirement obligations		5,148			1,811			3,337
Depreciation and amortization		8,188			5,811			2,377
Total operating expenses:		3,966,106			1,965,134			2,000,972

Net operating income (loss)		444,048			185,867			258,151

Total other income (expense)		(1,293,123	)		(576,080	)		(717,043	)

Loss before provision for income taxes		(849,075	)		(390,213	)		(458,862	)

Provision for income taxes		305,715			92,913			212,802

Net income (loss)	$	(543,360	)	$	(297,300	)	$	(246,060	)

Oil and Natural Gas Sales

We recognized $5,553,997 in revenues from sales of crude oil and natural gas, excluding losses on derivatives, for the three months ended June 30, 2014 compared to revenues of $2,151,001 for the three months ended June 30, 2013, an increase of $3,402,996, or 158%. The increase in revenues was driven by a 153% increase in production and a 2% increase in realized prices before the effects of settled derivatives. We had 6.28 net producing wells as of June 30, 2014 compared to 2.82 net producing as of June 30, 2013.

Derivatives

For the second quarter of 2014 we incurred a loss on settled derivatives of $262,719. We had no derivative instruments in 2013.

We had a mark-to market derivative loss of $881,124 in the second quarter of 2014, resulting in a net derivative liability of $1,308,835. The third quarter of 2013 was the first quarter we entered into derivative contracts.

Production Expenses

Production expenses were $595,591 and $269,461 for the three months ended June 30, 2014 and 2013, respectively, an increase of $326,130, or 121%. Our production expenses are greater than the comparative period due to our rapid increase in production. On a per unit basis, production expenses decreased from $10.47 per Boe in the second quarter of 2013 to $9.15 per Boe in the second quarter of 2014.

Production Taxes

Our production taxes of $591,525 and $232,528 for the three months ended June 30, 2014 and 2013, respectively, an increase of $358,997, or 154%. Production taxes are paid based on realized oil and natural gas sales. Production taxes represented 10.7% and 10.8% of oil and gas sales in the second quarter of 2014 and 2013.

General and Administrative Expenses

General and administrative expenses for the three months ended June 30, 2014 were $634,109 compared to $586,860 for the three months ended June 30, 2013, an increase of $47,249, or 8%. The increase in general and administrative expenses was primarily due to increased staffing to facilitate our growing production. General and administrative expenses per Boe produced decreased from $22.80 to $9.75 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 $2,131,545 and $868,663 for the three months ended June 30, 2014 and 2013, respectively, an increase of $1,262,882, or 145%. The increase was due primarily to our increased production. Depletion expense per Boe produced decreased from $33.75 in 2013 to $32.76 in 2014.

Depreciation

Depreciation expense for the three months ended June 30, 2014 was $8,188 compared to $5,811 for the three months ended June 30, 2013.

Other Income and (Expense)

Other income and (expense) for the three months ended June 30, 2014 was ($1,293,123) compared to ($576,080) for the three months ended June 30, 2013. The net other income and (expense) for the three months ended June 30, 2014 consisted of ($1,293,123) of interest expense including ($156,520) of amortized warrant costs, ($33,972) of amortization related to original issue discounts, ($263,909) of PIK interest applied to our debt balances and ($74,654) of amortized debt financing costs for the three months ended June 30, 2014. Additionally, we capitalized $51,781 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 June 30, 2013 consisted of $73 of interest income and ($576,153) of interest expense including ($55,796) of amortized warrant costs and ($336,582) of amortized debt issuance costs. Amortization of warrant costs and deferred financing costs were accelerated during 2013 due to the termination of the Dougherty credit facility in the third quarter of 2013 as part of a refinancing.

Provision for Income Taxes

We had income tax benefits of $305,715 and $92,913 for the three months ended June 30, 2014 and 2013, respectively, an increase of $212,802, or 229%. The tax benefit for the three months ended June 30, 2014 and 2013 was primarily driven by the Company’s loss before provision for income taxes.

Results of Operations for the Six months Ended June 30, 2014 and 2013.

The following table summarizes selected items from the statement of operations for the six months ended June 30, 2014 and 2013, respectively.

	Six months Ended
	June 30,						Increase /
	2014			2013			(Decrease)
Oil and gas sales	$	9,584,417		$	4,062,300		$	5,522,117
Loss on settled derivatives		(378,882	)		–			(378,882	)
Loss on mark-to-market of derivatives		(1,095,159	)		–			(1,095,159	)
Total revenues:		8,110,376			4,062,300			4,048,076

Operating expenses:
Production expenses		1,103,054			538,267			564,787
Production taxes		996,832			451,870			544,962
General and administrative		1,404,882			1,190,438			214,444
Depletion of oil and gas properties		3,718,477			1,568,388			2,150,089
Accretion of discount on asset retirement obligations		9,653			2,963			6,690
Depreciation and amortization		16,113			11,622			4,491
Total operating expenses:		7,249,011			3,763,548			3,485,463

Net operating income (loss)		861,365			298,752			562,613

Total other income (expense)		(2,376,023	)		(808,940	)		(1,567,083	)

Loss before provision for income taxes		(1,514,658	)		(510,188	)		(1,004,470	)

Provision for income taxes		589,738			526,701			63,037

Net income (loss)	$	(924,920	)	$	16,513		$	(941,433	)

Oil and Natural Gas Sales

We recognized $9,584,417 in revenues from sales of crude oil and natural gas, excluding losses on derivatives, for the six months ended June 30, 2014 compared to revenues of $4,062,300 for the six months ended June 30, 2013, an increase of $5,522,117, or 136%. The increase in revenues was driven by a 136% increase in production while realized prices before the effects of settled derivatives were relatively consistent between periods. We had 6.28 net producing wells as of June 30, 2014 compared to 2.82 net producing as of June 30, 2013.

Derivatives

For the six months ended June 30, 2014 we incurred a loss on settled derivatives of $378,882. We had no derivative instruments in 2013.

We had a mark-to market derivative loss of $1,095,129 in the six months ended June 30, 2014, resulting in a net derivative liability of $1,308,835. The third quarter of 2013 was the first quarter we entered into derivative contracts.

Production Expenses

Production expenses were $1,103,054 and $538,267 for the six months ended June 30, 2014 and 2013, respectively, an increase of $564,787, or 105%. Our production expenses are greater than the comparative period due to our rapid expansion in production. On a per unit basis, production expenses decreased from $11.32 per Boe in the six months ended June 30, 2013 to $9.83 per Boe in the six months ended June 30, 2014.

Production Taxes

Our production taxes of $996,832 and $451,870 for the six months ended June 30, 2014 and 2013, respectively, an increase of $544,962, or 121%. Production taxes are paid based on realized oil and natural gas sales. Production taxes represented 10.4% and 11.1% of oil and gas sales in the six months ended June 30, 2014 and 2013, respectively, the decrease driven by increased oil production in Montana and certain tax jurisdictions in North Dakota, which have a lower production tax rates, and increased gas and related product sales which have lower average tax rates than oil sales compared to revenue.

General and Administrative Expenses

General and administrative expenses for the six months ended June 30, 2014 were $1,404,882 compared to $1,190,438 for the six months ended June 30, 2013, an increase of $214,444, or 18%. The increase in general and administrative expenses was primarily due to increased staffing and external contract work to facilitate our growing production. General and administrative expenses per Boe produced decreased from $25.04 to $12.51 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 $3,718,477 and $1,568,388 for the six months ended June 30, 2014 and 2013, respectively, an increase of $2,150,089, or 137%. The increase was due primarily to our increased production. Depletion expense per Boe produced increased from $32.99 in 2013 to $33.12 in 2014.

Depreciation

Depreciation expense for the six months ended June 30, 2014 was $16,113 compared to $11,622 for the six months ended June 30, 2013.

Other Income and (Expense)

Other income and (expense) for the six months ended June 30, 2014 was ($2,376,023) compared to ($808,940) for the six months ended June 30, 2013. The net other income and (expense) for the six months ended June 30, 2014 consisted of ($2,376,023) of interest expense including ($310,042) of amortized warrant costs, ($60,288) of amortization related to original issue discounts, ($472,712) of PIK interest applied to our debt balances and ($145,307) of amortized debt financing costs for the six months ended June 30, 2014. Additionally, we capitalized $105,555 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 six months ended June 30, 2013 consisted of $193 of interest income and ($809,133) of interest expense including ($65,884) of amortized warrant costs and ($399,654) of amortized debt issuance costs. Amortization of warrant costs and deferred financing costs were accelerated during 2013 due to the termination of the Dougherty credit facility in the third quarter of 2013 as part of a refinancing.

Provision for Income Taxes

We had income tax benefits of $589,738 and $526,701 for the six months ended June 30, 2014 and 2013, respectively, an increase of $63,037, or 12%. The tax benefit for the six months ended June 30, 2014 of $589,738 was primarily driven by the Company’s loss before provision for income taxes. The tax benefit for the six months ended June 30, 2013 was driven by the Company’s loss before income taxes and a change in our effective rate from 41.0% to 37.5% due to a change in state apportionment factors.

Non-GAAP Financial Measures

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

Black Ridge Oil & Gas, Inc.

Reconciliation of Adjusted Net Income (Loss)

(Unaudited)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2014			2013			2014			2013
Net Income (Loss)	$	(543,360	)	$	(297,300	)	$	(924,920	)	$	16,513
Add back:
Loss on mark-to-market of derivatives, net of tax ^(a)		555,124			–			690,159			–
Adjusted Net Income (Loss)	$	11,764		$	(297,300	)	$	(234,761	)	$	16,513

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			47,979,990			47,979,990			48,540,032

Net income (loss) per common share - basic	$	(0.01	)	$	(0.01	)	$	(0.02	)	$	0.00
Subtract:
Change due to loss on mark-to- market of derivatives, net of tax		0.01			0.00			0.01			0.00
Adjusted Net Income (loss) per common share - basic	$	0.00		$	(0.01	)	$	(0.01	)	$	0.00

Net income (loss) per common share - fully diluted		(0.01	)		(0.01	)		(0.02	)	$	0.00
Subtract:
Change due to loss on mark-to- market of derivatives, net of tax		0.01			0.00			0.01			0.00
Adjusted Net Income (Loss) per common share - fully diluted	$	0.00		$	(0.01	)	$	(0.01	)	$	0.00

^(a) Adjusted to reflect tax expense, computed based on our effective tax rate of approximately 37%, of $326,000 and $405,000 for the three and six months ended June 30, 2014, respectively.

Black Ridge Oil & Gas, Inc.

Reconciliation of Adjusted EBITDA (Unaudited)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2014			2013			2014			2013
Net Income (loss)	$	(543,360	)	$	(297,300	)	$	(924,920	)	$	16,513
Add Back:
Interest Expense, net, excluding amortization of warrant based financing costs		1,136,603			520,284			2,065,981			743,056
Income Tax Provision		(305,715	)		(92,913	)		(589,738	)		(526,701	)
Depreciation, Depletion, and Amortization		2,139,733			874,474			3,734,590			1,580,010
Accretion of Abandonment Liability		5,148			1,811			9,653			2,963
Share Based Compensation		301,241			223,145			599,003			395,598
Loss on mark-to market of derivatives		881,124			–			1,095,159			–

Adjusted EBITDA	$	3,614,774		$	1,229,501		$	5,989,728		$	2,211,439

Liquidity and capital resources

The following table summarizes our total current assets, liabilities and working capital at June 30, 2014 and December 31, 2013, respectively.

	June 30,			December 31,
	2014			2013
Current Assets	$	7,427,210		$	4,296,618

Current Liabilities	$	9,547,225		$	8,597,587

Working Capital	$	(2,120,015	)	$	(4,300,969	)

As of June 30, 2014 we had negative working capital of $2,120,125.

The following table summarizes our cash flows during the three month periods ended June 30, 2014 and 2013, respectively.

	Six months Ended
	June 30,
	2014			2013
Net cash provided by operating activities	$	2,012,131		$	1,012,427
Net cash used in investing activities		(13,873,281	)		(2,947,282	)
Net cash provided by financing activities		10,795,218			2,089,994

Net change in cash and cash equivalents	$	(1,065,932	)	$	155,139

Our net cash flows from operations are primarily affected by production volumes and commodity prices. Net cash provided by operating activities was $2,012,131 and $1,012,427 for the six months ended June 30, 2014 and 2013, respectively, an increase of $999,704. The increase was due to increased gross profit from higher production activity offset by changes in working capital from operating activities. Changes in working capital from operating activities resulted in a decrease in cash of ($2,589,923) in the six months ended June 30, 2014 as compared to a decrease in cash of ($855,610) for the same period in the previous year, primarily driven by increase in accounts receivable in both periods.

Net cash used in investing activities was $13,873,281 and $2,947,282 for the six months ended June 30, 2014 and 2013, respectively, an increase of $10,925,999. The increase was primarily driven by increased expenditures for well development as we paid $10,079,431 for well development and $3,491,089 in advances to operators for future well development during the 2014 period while in the 2013 period we spent $2,259,115 for well development and $615,370 in advances to operators for future well development. Additionally, the increase in cash used in investing activities was attributable to an increase in cash spent for property acquisition as we purchased 200 net leasehold acres of oil and gas properties for $1,652,551 in the six months ended June 30, 2014 as compared to purchasing 800 net leasehold acres of oil and gas properties for $416,283 in the six months ended June 30, 2013. In the six months ended June 30, 2014 we sold 490 net leasehold acres for proceeds of $1,360,920, including proceeds of $20,000 from a swap transaction, while in the comparable 2013 period we sold 105 net leasehold acres for proceeds of $343,486.

Net cash provided from financing was $10,795,218 and $2,089,994 for the six months ended June 30, 2014 and 2013, respectively. We drew $10,850,000, net of repayments, on our credit facilities during the six months ended June 30, 2014 while funding a portion of the operational and investing activity through operating income and working capital. We drew $2,114,994 on our Dougherty revolving credit facility in 2013 while funding additional investing activity through operating cash flows and working capital.

Senior Credit Facility and Subordinated Credit Facilities

The Company, as borrower, entered into a Credit Agreement dated August 8, 2013 and amendments thereto (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 existing debt under the Company’s credit facility with Dougherty Funding LLC.

As of June 30, 2014 the Company had borrowings of $14.05 million outstanding under the Senior Credit Agreement.

The Company, as borrower, entered into a Second Lien Credit Agreement dated August 8, 2013 and amendments thereto (as amended, the “Subordinated Credit Agreement”) with 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 provides for initial commitment availability of $25 million, subject to customary conditions, with the remaining commitments subject to the approval of Chambers and other customary conditions. The Company may borrow the available commitments in amounts of $5 million or more and shall not request borrowings of such loans more than once a month, except that the initial draw was required to be at least $15 million. Loans under the Subordinated Credit Facility shall be funded net of a 2% OID. The unpaid principal balance of borrowings under the Subordinated Credit Facility bears interest at the Cash Interest Rate plus the PIK Interest Rate. The Cash Interest Rate is 9.00% per annum plus a rate per annum equal to the greater of (i) 1.00% and (ii) the offered rate for three-month deposits in U.S. dollars that appears on Reuters Screen LIBOR 01 as of 11:00 a.m. (London time) on the second full LIBOR business day preceding the first day of each calendar quarter. The PIK Interest Rate is equal to 4.00% per annum. Interest is payable on the last day of each month. The Company is also required to pay an annual nonrefundable administration fee of $50,000 and 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 first funding from the Subordinated Credit Facility occurred on September 9, 2013 at which time we drew $14,700,000, net of a $300,000 original issue discount, from the Subordinated Credit Agreement and used $10,226,057 of those proceeds to repay and terminate the Dougherty revolving credit facility. We have made subsequent draws of an additional $14,700,000, net of $300,000 in original issue discount. Availability under the facility is $35 million as of June 30, 2014.

The Credit Facilities require customary affirmative and negative covenants for credit facilities of the respective types and sizes for companies operating in the oil and gas industry, as well as customary events of default. Furthermore, the Credit Facilities contain financial covenants that require the Company to satisfy certain specified financial ratios. The Senior Credit Agreement requires the Company to maintain (i) as of the last day of each fiscal quarter of the Company, 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, and 0.80 to 1.00 for the quarter ending March 31, 2015 and thereafter, (ii) a ratio of current assets to current liabilities of a minimum of 1.0 to 1.0, (iii) a net debt to EBITDAX, as defined in the Senior Credit Agreement, ratio of 3.75 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, and 3.50 to 1.00 for the quarter ended March 31, 2015 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 (i) as of the last day of each fiscal quarter of the Company, 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, and 0.80 to 1.00 for the quarter ending March 31, 2015 and thereafter, (ii) as of the last day of each fiscal quarter of the Company, a consolidated net leverage ratio (adjusted total indebtedness less the amount of unrestricted cash equivalents to consolidated EBITDA) of no more than 3.75 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, and 3.50 to 1.00 for the quarter ending March 31, 2015 and thereafter, calculated on a modified trailing four quarter basis, (iii) as of the last day of any fiscal quarter of the Company, a consolidated cash interest coverage ratio (consolidated EBITDA to consolidated cash interest expense) of no less than 2.5 to 1.0, calculated on a modified trailing four quarter basis and (iv) as of the last day of any period of four consecutive fiscal quarters of the Company, a ratio of consolidated current assets to consolidated current liabilities of at least 1.0 to 1.0. In addition, each of the Credit Facilities requires that the Company enter into hedging agreements prior to funding with regard to no less than 50% and no greater than 75% of its future oil production on currently producing wells. The Company is in compliance with all covenants, as amended, for the period ending June 30, 2014.

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. The remaining unamortized balance of the debt discount attributable to the warrants is $1,963,902 as of June 30, 2014.

Dougherty Revolving Credit Facility (former credit facility)

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

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

Although our revenues are expected to grow as our wells are placed into production, our revenues are not expected to exceed our investment developing oil and gas wells and our operating costs throughout the remainder of 2014 and into 2015. However, we believe our availability under our credit facilities provides ample funding for our property acquisition and development plans through those same periods. Our prospects still must be considered in light of the risks, expenses and difficulties frequently encountered by companies in their early stage of development. Such risks for us include, but are not limited to, potential failure to earn revenues and collect 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 June 30, 2014, our balance of cash and cash equivalents was $84,415. Our plan for satisfying our cash requirements for the next twelve months, in addition to our revenues from oil and gas sales is through draws on our credit facilities and potential sale or use of shares of our stock.

Off-Balance Sheet Arrangements

We have no off-balance sheet arrangements.

Critical Accounting Policies and Estimates

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

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

Stock-Based Compensation

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

Full Cost Method

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

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

Commodity Price Risk

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

As required under our new Credit Facilities, we will maintain derivative contracts to achieve a more predictable cash flow by reducing our exposure to oil price volatility. We anticipate using derivatives to economically hedge a significant, but varying portion of our anticipated future production over a rolling 42 month horizon. Any payments due to counterparties under our derivative contracts are funded by proceeds received from the sale of our production. Production receipts, however, lag payments to the counterparties. Any interim cash needs will be funded by cash from operations or borrowings under our credit facilities. We entered into our first derivative contracts in August of 2013 as required by our financing agreements.

Interest Rate Risk

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

ITEM 4. CONTROLS AND PROCEDURES.

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

Our management, under the direction of our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the design and operation of our disclosure controls and procedures (as such terms are defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of June 30, 2014. As part of such evaluation, management considered the matters discussed below relating to internal control over financial reporting. Based on this evaluation our management, including the Company’s Chief Executive Officer and Chief Financial Officer, has concluded that the Company’s disclosure controls and procedures were effective as of June 30, 2014 to ensure that the information required to be disclosed in our Exchange Act reports was recorded, processed, summarized and reported on a timely basis.

There have been no changes in the Company’s internal control over financial reporting during the three month period ended June 30, 2014 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 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
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

SIGNATURES

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

	BLACK RIDGE OIL & GAS, INC.

Dated: August 12, 2014	By:	/s/ Kenneth DeCubellis
		Kenneth DeCubellis, Chief Executive Officer (Principal Executive Officer)


Dated: August 12, 2014	By:	/s/ James A. Moe
		James A. Moe, Chief Financial Officer (Principal Financial Officer)

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