Sow Good Inc. - FORM 10-Q - August 13, 2013

Attached files

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EX-32.1 - CERTIFICATION - Sow Good Inc.	brog_10q-ex3201.htm
EX-31.1 - CERTIFICATION - Sow Good Inc.	brog_10q-ex3101.htm
EX-32.2 - CERTIFICATION - Sow Good Inc.	brog_10q-ex3202.htm
EX-31.2 - CERTIFICATION - Sow Good Inc.	brog_10q-ex3102.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)

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

For Quarterly Period Ended June 30, 2013

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

For the Transition period from _______________ to ______________

Commission File Number 000-53952

(Name of registrant in its charter)

Nevada

(State or other jurisdiction of incorporation or organization)

27-2345075

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

10275 Wayzata Blvd. Suite 310, Minnetonka, Minnesota 55305

(Address of principal executive offices) (Zip Code)

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

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

Yes

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

Yes

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

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

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 12, 2013 was 47,979,990.

TABLE OF CONTENTS

PART I - FINANCIAL INFORMATION
ITEM 1.	FINANCIAL STATEMENTS (Unaudited)	2
	Condensed Balance Sheets at June 30, 2013 (Unaudited) and December 31, 2012	2
	Unaudited Condensed Statements of Operations for the Three and Six Months Ended June 30, 2013 and 2012	3
	Unaudited Condensed Statements of Cash Flows for the Six Months Ended June 30, 2013 and 2012	4
	Notes to the Condensed Financial Statements (Unaudited)	5
ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	21
ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	37
ITEM 4.	CONTROLS AND PROCEDURES	37
PART II - OTHER INFORMATION
ITEM 1.	Legal Proceedings	38
ITEM 1A.	RISK FACTORS	38
ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	38
ITEM 3.	DEFAULTS UPON SENIOR SECURITIES	38
ITEM 4.	MINE SAFETY DISCLOSURES	38
ITEM 5.	OTHER INFORMATION	38
ITEM 6.	EXHIBITS	38
	SIGNATURES	39

ITEM 1. FINANCIAL STATEMENTS.

BLACK RIDGE OIL & GAS, INC.

CONDENSED BALANCE SHEETS

	June 30,			December 31,
	2013			2012
ASSETS	(Unaudited)

Current assets:
Cash and cash equivalents	$	1,572,479		$	1,417,340
Accounts receivable		1,767,325			856,233
Settlement receivable		2,500,000			2,500,000
Advances to operators		1,573,359			1,350,295
Prepaid expenses		29,357			47,155
Total current assets		7,442,520			6,171,023

Property and equipment:
Oil and natural gas properties, full cost method of accounting
Proved properties		42,565,477			35,248,983
Unproved properties		6,663,926			9,055,513
Other property and equipment		85,917			85,917
Total property and equipment		49,315,320			44,390,413
Less, accumulated depreciation, amortization, depletion and allowance for impairment		(7,373,193	)		(5,793,184	)
Total property and equipment, net		41,942,127			38,597,229

Debt issuance costs, net		283,048			657,702

Total assets	$	49,667,695		$	45,425,954


LIABILITIES AND STOCKHOLDERS' EQUITY

Current liabilities:
Accounts payable	$	5,136,889		$	2,953,526
Settlement payable		160,000			160,000
Settlement accounts payable, related party		116,234			116,234
Accrued expenses		114,183			61,666
Total current liabilities		5,527,306			3,291,426

Asset retirement obligations		72,602			67,145
Revolving credit facility		7,863,838			5,748,844
Deferred tax liability		4,205,995			4,732,696

Total liabilities		17,669,741			13,840,111

Commitments and contingencies (See note 14)		–			–

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		30,242,810			29,847,212
Retained earnings		1,707,164			1,690,651
Total stockholders' equity		31,997,954			31,585,843

Total liabilities and stockholders' equity	$	49,667,695		$	45,425,954

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,
	2013			2012			2013			2012

Oil and gas sales	$	2,151,001		$	1,380,524		$	4,062,300		$	2,046,730

Operating expenses:
Production expenses		269,461			121,732			538,267			265,883
Production taxes		232,528			158,378			451,870			233,810
General and administrative		586,860			1,237,883			1,190,438			1,951,774
Depletion of oil and gas properties		868,663			527,712			1,568,388			814,615
Accretion of discount on asset retirement obligations		1,811			1,208			2,963			2,005
Depreciation and amortization		5,811			5,734			11,622			12,584
Total operating expenses		1,965,134			2,052,647			3,763,548			3,280,671

Net operating income (loss)		185,867			(672,123	)		298,752			(1,233,941	)

Other income (expense):
Interest income		73			200			193			242
Interest (expense)		(576,153	)		(172,903	)		(809,133	)		(526,168	)
Total other income (expense)		(576,080	)		(172,703	)		(808,940	)		(525,926	)

Loss before provision for income taxes		(390,213	)		(844,826	)		(510,188	)		(1,759,867	)

Provision for income taxes		92,913			227,381			526,701			381,565

Net income (loss)	$	(297,300	)	$	(617,445	)	$	16,513		$	(1,378,302	)


Weighted average common shares outstanding - basic		47,979,990			47,789,762			47,979,990			47,596,363
Weighted average common shares outstanding - fully diluted		47,979,990			47,789,762			48,540,032			47,596,363

Net income (loss) per common share - basic	$	(0.01	)	$	(0.01	)	$	0.00		$	(0.03	)
Net income (loss) per common share - fully diluted	$	(0.01	)	$	(0.01	)	$	0.00		$	(0.03	)

See accompanying notes to financial statements.

BLACK RIDGE OIL & GAS, INC.

CONDENSED STATEMENTS OF CASH FLOWS

(Unaudited)

	For the Six Months
	Ended June 30,
	2013			2012
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	16,513		$	(1,378,302	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion of oil and gas properties		1,568,388			814,615
Depreciation and amortization		11,622			12,584
Amortization of debt issuance costs		399,654			80,463
Accretion of discount on asset retirement obligations		2,963			2,005
Common stock issued for terminated oil and gas acquisition		–			438,539
Common stock warrants		65,884			259,069
Common stock warrants, related parties		–			45,719
Common stock options, related parties		329,714			474,162
Deferred income taxes		(526,701	)		(381,565	)
Decrease (increase) in current assets:
Accounts receivable		(911,092	)		(563,619	)
Prepaid expenses		17,798			(52,452	)
Contingent consideration receivable		–			335,999
Increase (decrease) in current liabilities:
Accounts payable		(14,833	)		44,749
Accounts payable, related parties		–			(9,206	)
Accrued expenses		52,517			–
Royalties payable, related party		–			(16,800	)
Net cash provided by operating activities		1,012,427			105,960

CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from sale of oil and gas properties		343,486			736,625
Purchases of oil and gas properties and development capital expenditures		(2,675,398	)		(6,893,144	)
Advances to operators		(615,370	)		–
Purchases of other property and equipment		–			(7,428	)
Net cash used in investing activities		(2,947,282	)		(6,163,947	)

CASH FLOWS FROM FINANCING ACTIVITIES
Advances from revolving credit facilities		4,300,000			7,825,000
Repayments on revolving credit facilities		(2,185,006	)		(2,000,000	)
Debt issuance costs paid		(25,000	)		(295,822	)
Net cash provided by financing activities		2,089,994			5,529,178

NET CHANGE IN CASH		155,139			(528,809	)
CASH AT BEGINNING OF PERIOD		1,417,340			1,401,141
CASH AT END OF PERIOD	$	1,572,479		$	872,332


SUPPLEMENTAL INFORMATION:
Interest paid	$	275,920		$	140,917
Income taxes paid	$	–		$	–

NON-CASH INVESTING AND FINANCING ACTIVITIES:
Net change in accounts payable for development of oil and gas properties	$	2,198,196		$	7,865,941
Advances from operators received in swap for oil and gas properties	$	(1,200,000	)	$	–
Advances to operators applied to development of oil and gas properties	$	1,592,306		$	–
Capitalized asset retirement costs, net of revision in estimate	$	2,494		$	48,688

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

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

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

Note 2 – Basis of Presentation and Significant Accounting Policies

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

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

Reclassifications

In the current year, the Company separately classified advances to operators from prepaid expenses in the Balance Sheet. For comparative purposes, amounts in the prior periods have been reclassified to conform to current year presentation.

Use of Estimates

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

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Financial Statements

(Unaudited)

The oil and gas industry is subject, by its nature, to environmental hazards and clean-up costs. At this time, management knows of no substantial losses from environmental accidents or events for which the Company may be currently liable.

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,
	2013		2012
Cash	$	513,817	$	513,788
Money market funds		1,058,662		903,552
Total	$	1,572,479	$	1,417,340

Cash in Excess of FDIC Insured Limits

The Company maintains its cash in bank deposit accounts which, at times, may exceed federally insured limits. Accounts are guaranteed by the Federal Deposit Insurance Corporation (FDIC) and the Securities Investor Protection Corporation (SIPC) up to $250,000 and $500,000, respectively, under current regulations. The Company had approximately $1,072,479 and $917,340 in excess of FDIC and SIPC insured limits at June 30, 2013 and December 31, 2012, respectively. The Company has not experienced any losses in such accounts.

Advances to Operators

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

Debt Issuance Costs

Costs relating to obtaining our revolving credit facilities are capitalized and amortized over the term of the related debt using the straight-line method. The unamortized balance of debt issuance costs at June 30, 2013, and December 31, 2012, was $283,048 and $657,702, respectively. Amortization of debt issuance costs charged to interest expense were $399,654 and $80,463 for the six months ended June 30, 2013 and 2012, respectively. When a loan is paid in full, any unamortized financing costs are removed from the related accounts and charged to interest expense.

Website Development Costs

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

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, 2013. We depreciate our website development costs on a straight line basis over the estimated useful life of the assets, which is currently three years. We have recognized depreciation expense on these website costs of $9,443 and $9,187 for the six months ended June 30, 2013 and 2012, 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, 2013 and 2012 are as follows:

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2013		2012		2013		2012
Weighted average common shares outstanding – basic		47,979,990		47,789,762		47,979,990		47,596,363
Plus: Potentially dilutive common shares:
Stock options and warrants		–		–		560,042		–
Weighted average common shares outstanding – diluted		47,979,990		47,789,762		48,540,032		47,596,363

Stock options and warrants excluded from the calculation of diluted EPS because their effect was anti-dilutive were 9,374,876 and 8,040,375 for the three months ended June 30, 2013 and 2012, respectively, and 8,176,209 and 8,040,375 for the six months ended June 30, 2013 and 2012, respectively.

Segment Reporting

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

Fair Value of Financial Instruments

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

Non-Oil & Gas Property and Equipment

Property and equipment that are not oil and gas properties are recorded at cost and depreciated using the straight-line method over their estimated useful lives of three to seven years. Expenditures for replacements, renewals, and betterments are capitalized. Maintenance and repairs are charged to operations as incurred. Long-lived assets, other than oil and gas properties, are evaluated for impairment to determine if current circumstances and market conditions indicate the carrying amount may not be recoverable. The Company has not recognized any impairment losses on non-oil and gas long-lived assets. Depreciation expense was $11,622 and $12,584 for the six months ended June 30, 2013 and 2012, respectively.

Revenue Recognition

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

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Financial Statements

(Unaudited)

Asset Retirement Obligations

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

Full Cost Method

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

	Six Months Ended
	June 30,
	2013		2012
Capitalized Certain Payroll and Other Internal Costs	$	10,540	$	66,098
Capitalized Interest Costs		–		–
Total	$	10,540	$	66,098

Proceeds from property sales 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)

Impairment

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

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

Stock-Based Compensation

The Company adopted FASB guidance on stock based compensation upon inception at April 9, 2010. Under FASB ASC 718-10-30-2, all share-based payments to employees, including grants of employee stock options, are to be recognized in the income statement based on their fair values. Pro forma disclosure is no longer an alternative. Expense related to common stock and stock options issued for services and compensation totaled $329,714 and $912,701 for the six months ended June 30, 2013 and 2012, respectively, including $-0- and $438,539, respectively, of common stock valued at the fair market value based on the Company’s closing trading price on the date of grant, and $329,714 and $474,162, 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, $65,884 and $304,788 of warrant related costs were amortized during the six months ended June 30, 2013 and 2012, respectively, pursuant to warrants granted in consideration for credit facilities. The fair value of warrants is determined similar to the method used in determining the fair value of employee stock options and the fair value is amortized over the life of the related credit facility and accelerated upon termination of a credit facility.

Uncertain Tax Positions

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

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

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

Recent Accounting Pronouncements

New accounting pronouncements are issued by FASB that are adopted by the Company as of the specified effective date. There have been no developments to recently issued accounting standards, including expected dates of adoption and estimated effects on our financial statements, from those disclosed in our Annual Report on Form 10-K for the year ended December 31, 2012.

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Financial Statements

(Unaudited)

Note 3 – Property and Equipment

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

	June 30,			December 31,
	2013			2012
Oil and gas properties, full cost method:
Evaluated costs	$	42,565,477		$	35,248,983
Unevaluated costs, not subject to amortization or ceiling test		6,663,926			9,055,513
		49,229,403			44,304,496
Other property and equipment		85,917			85,917
		49,315,320			44,390,413
Less: Accumulated depreciation, amortization, depletion and impairments		(7,373,193	)		(5,793,184	)
Total property and equipment, net	$	41,942,127		$	38,597,229

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

	Six Months Ended
	June 30,
	2013		2012
Depletion of costs for evaluated oil and gas properties	$	1,568,388	$	814,615
Depreciation and amortization of other property and equipment		11,622		12,584
Total depreciation, amortization and depletion	$	1,580,010	$	827,199

Note 4 – Oil and Gas Properties

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

	June 30, 2013				June 30, 2012
	Gross		Net		Gross		Net
North Dakota		80		2.74		48		1.83
Montana		1		0.08		–		–
Total		81		2.82		48		1.83

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, 2013 and 2012, our principal oil and gas assets included approximately 11,891 and 11,213 net acres, respectively, located in North Dakota and Montana.

The following table summarizes our capitalized costs for the purchase and development of our oil and gas properties for the six months ended June 30, 2013 and 2012, respectively:

	Six Months Ended
	June 30,
	2013			2012
Purchases of oil and gas properties and development costs for cash	$	2,675,398		$	6,893,144
Purchase of oil and gas properties accrued at period-end		4,816,341			10,288,091
Purchase of oil and gas properties accrued at beginning of period		(2,618,145	)		(2,422,150	)
Advances to operators applied to purchase of oil and gas properties		1,592,306			–
Capitalized asset retirement costs, net of revision in estimate		2,494			48,688
Total purchase and development costs, oil and gas properties	$	6,468,394		$	14,807,773

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Financial Statements

(Unaudited)

2013 Acquisitions

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

2013 Divestitures

During the six months ended June 30, 2013, we sold a total of approximately 105 net mineral 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.

2012 Acquisitions

During the six months ended June 30, 2012, we purchased approximately 978 net mineral acres of oil and gas properties in North Dakota. In consideration for the assignment of these mineral leases, we paid the sellers a total of approximately $1,291,113.

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

2012 Divestitures

On various dates during the six months ended June 30, 2012, we sold approximately 221 net acres for total proceeds of $736,625. No gain or loss was recorded pursuant to the sales.

Note 5 – Asset Retirement Obligation

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

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

	Six Months Ended
	June 30,
	2013			2012
Beginning asset retirement obligation	$	67,145		$	3,900
Revision in estimate of asset retirement obligation		(20,123	)		–
Liabilities incurred for new wells placed in production		22,617			48,688
Accretion of discount on asset retirement obligation		2,963			2,005
Ending asset retirement obligation	$	72,602		$	54,593

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Financial Statements

(Unaudited)

Note 6 – Related Party

A former officer of the Company, Steve Lipscomb, received a commission of 5% of a royalty stream from Peerless Media Ltd., recorded on the balance sheet as of December 31, 2011 as a contingent consideration receivable, as a result of an incentive arrangement with Mr. Lipscomb that was approved by Ante4’s Board of Directors in February 2009. Mr. Lipscomb received a total of $-0- and $26,006 during the six months ended June 30, 2013 and 2012, respectively, of which $6,448 was received by Mr. Lipscomb while an officer of the Company in 2012. As a result of the settlement of litigation related to the same agreement, Mr. Lipscomb was due 5% of the settlement payments from the litigation settlement amounting to approximately $548,827 of which $432,593 was paid in 2012 and the remaining $116,234 is due upon receipt by the Company of the final settlement payment from Peerless Media, Ltd.

We have subleased and currently lease office space on a month to month basis where the lessor is an entity owned by our former CEO and current Chairman of the Board of Directors, Bradley Berman. The sublease agreement was cancelled and we entered into a direct lease on April 30, 2012 to expand and occupy approximately 1,142 square feet of office space. In accordance with this lease, our lease term remains on a month-to-month basis, provided that either party may provide 90 day notice to terminate the lease, with base rents of $1,142 per month, plus common area operations and maintenance charges, and monthly parking fees of $240 per month, for the first year commencing on May 1, 2012, and subject to increases of $24 per month for each of the subsequent four year periods. We have paid a total of $15,765 and $10,844 to this entity during the six months ended June 30, 2013 and 2012, respectively.

Note 7 – Litigation Settlements and Contingent Consideration Receivable

Peerless Settlement

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

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Financial Statements

(Unaudited)

	Contingent						Net Contingent
	Consideration			Royalties			Consideration
	Receivable			Payable			Receivable
Balance spun-off, April 16, 2010:	$	7,532,985		$	(415,000	)	$	7,117,985

Net royalties received and commissions paid		(182,335	)		11,343			(170,992	)
Fair value adjustment		(878,650	)		80,057			(798,593	)
Balance, December 31, 2010		6,472,000			(323,600	)		6,148,400

Net royalties received and commissions paid		(463,398	)		23,169			(440,229	)
Balance, December 31, 2011		6,008,602			(300,431	)		5,708,171

Net royalties received and commissions paid		(529,361	)		26,468			(502,893	)
Elimination of the contingent receivable due to settlement agreement		(5,479,241	)		273,963			(5,205,278	)
Balance, December 31, 2012	$	–		$	–		$	–

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

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

As of June 30, 2013, the Company has a settlement receivable of $2.5 million for the remaining litigation settlement and payables of $160,000 and $116,234 related to remaining contingent attorneys’ fees payable and amounts due Mr. Lipscomb, respectively. The contingent consideration receivable was relieved in 2012 as a part of the settlement. The Company has expensed non-contingent expenses and fees associated with pursuing the settlement as those expenses and fees were incurred amounting to $-0- and $31,408 for the six months ended June 30, 2013 and 2012, respectively.

Note 8 – 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, 2013 and December 31, 2012:

Fair Value Measurements at June 30, 2013

Level 1

Level 2

Level 3

Assets

Cash and cash Equivalents

1,572,479

–

Total assets

1,572,479

–

Liabilities

Revolving credit facilities

–

7,863,838

–

Total Liabilities

–

7,863,838

–

1,572,479

(7,863,838

)

–

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

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

Level 2 liabilities consist of Revolving credit facilities. No fair value adjustment was necessary during the six months ended June 30, 2013 and 2012.

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Financial Statements

(Unaudited)

Note 9 – Revolving Credit Facilities

PrenAnte5, LLC Revolving credit facility

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

Dougherty Funding, LLC Revolving credit facility

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

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

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

The Credit Facility will mature on August 1, 2015. The Credit Facility may be prepaid with thirty (30) days written notice at any time. On September 5, 2012, in connection with the amended financing, the Company agreed to issue Dougherty Funding, LLC warrants to purchase up to 900,000 shares of the Company’s common stock, of which 585,000 shares have currently been issued, at an exercise price of $0.38 per share. The remaining warrants to purchase 315,000 shares are available to be granted when the remaining $3.5 million of the credit facility becomes available. The warrants expire on August 31, 2015.

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

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Financial Statements

(Unaudited)

Revolving credit facility consisted of the following as of June 30, 2013 and December 31, 2012, respectively:

	June 30,		December 31,
	2013		2012
Dougherty Funding, LLC Revolving Credit Facility	$	7,863,838	$	5,748,844

The following presents components of interest expense by instrument type for the six months ended June 30, 2013 and 2012, respectively:

	Six Months Ended
	June 30,
	2013		2012
Revolving Credit Facilities, interest	$	343,595	$	140,917
Revolving Credit Facilities, finance charges		399,654		80,463
Revolving Credit Facilities, warrant costs		65,884		304,788
	$	809,133	$	526,168

Note 10 – Changes in Stockholders’ Equity

Preferred Stock

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

Common Stock

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

Potential Reverse Stock Split

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

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

Note 11 –Options

Options

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

The Company recognized a total of $329,714, and $474,162 of compensation expense during the six months ended June 30, 2013 and 2012, respectively, on common stock options issued to Employees and Directors that are being amortized over the implied service term, or vesting period, of the options. The remaining unamortized balance of these options is $1,625,108 as of June 30, 2013.

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Financial Statements

(Unaudited)

Options Exercised

No options were exercised during the six month periods ended June 30, 2013 and 2012.

Options Forfeited

No options were forfeited during the six month periods ended June 30, 2013 and 2012.

Note 12 – Warrants

Warrants

We recognized a total of $65,884 and $304,788 of finance expense during the six months ended June 30, 2013 and 2012, respectively, on common stock warrants issued to lenders, including related party amounts of $-0- and $45,719 during the six months ended June 30, 2013 and 2012, respectively. Warrants are amortized over the remaining life of the respective loan. The fair value of the warrants related to the PrenAnte5 Revolving Credit Facility were being amortized over the life of the loan and the amortization was accelerated to fully amortize the fair value as of the early termination date of April 12, 2012. The remaining unamortized balance of warrants is $42,306 as of June 30, 2013 and the amortization has been accelerated to fully amortize the fair value of the warrants by the anticipated payoff date of the Dougherty facility, which is September 7, 2013.

Warrants Granted

No warrants were granted during the six month periods ended June 30, 2013 and 2012.

Warrants Exercised

No warrants were exercised during the six month periods ended June 30, 2013 and 2012.

Note 13 – Income Taxes

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

We currently estimate that our effective tax rate for the year ending December 31, 2013 will be approximately 37.5%. Losses incurred during the period from April 9, 2011 (inception) to June 30, 2013 could be used to offset future tax liabilities. Accounting standards require the consideration of a valuation allowance for deferred tax assets if it is “more likely than not” that some component or all of the benefits of deferred tax assets will not be realized. As of June 30, 2013, net deferred tax assets were $4,337,441 after a valuation allowance applied to net deferred tax assets of approximately $506,803. 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, 2013, the Company recognized deferred tax liabilities totaling $8,543,436 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, 2013 of $526,701 was primarily driven by a change in the Company’s effective tax rate from 41.0% to 37.5% due to a change in state apportionment factors.

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

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Financial Statements

(Unaudited)

Note 14 – 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, 2013 the Company had committed to AFE’s of approximately $3.6 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 $720,000 in oil and gas sales and $179,000 of production taxes and operating expenses to date of which $252,000 of oil and gas revenue and $55,000 of production expenses and taxes would relate to the six months ended June 30, 2013. In the event the state is not successful in defending its ownership claim, the state is required to refund the Company the cost to purchase the lease.

Note 15 – Subsequent Events

Changes in Management

Effective August 1, 2013, the Company appointed Mr. Michael Eisele, 30, to the position of Chief Operating Officer. Mr. Eisele has served since August 2012 as the Company’s Vice President of Land, overseeing the Company’s acreage portfolio and managing acquisitions and divestitures.

In connection with Mr. Eisele’s promotion to Chief Operating Officer, his annual salary increased from $105,000 to $130,000 and, pursuant to the Company’s 2012 Amended and Restated Stock Incentive Plan and a Stock Option Agreement, Mr. Eisele was granted options to purchase 165,000 shares. These options vest in five equal installments, commencing one year from the date of grant on August 1, 2013, and continuing for the next four anniversaries thereof until fully vested. The Company and Mr. Eisele also entered into the Company’s standard Director and Officer Indemnification Agreement, pursuant to which the Company will indemnify Mr. Eisele against certain liabilities which may arise by reason of his status as an officer, as well as a Change of Control Agreement, which provides, among other things, for twelve months of severance pay in the event of termination as a result of a change in control of the Company.

Debt Refinance

On August 8, 2013, the Company entered into a $50 million first lien revolving credit facility and a $75 million second lien term credit facility, which are described in further detail below.

Senior and Subordinated Credit Facilities

The Company has entered into a Credit Agreement dated August 8, 2013 (the “Senior Credit Agreement”) by and between the Company, as borrower, and Cadence Bank, N.A., as lender (“Cadence”) (the “Senior Credit Facility”). Under the terms of the Senior Credit Agreement, a senior secured revolving line of credit in the maximum aggregate principal amount of $50 million is available from time to time (i) for direct investment in oil and gas properties, (ii) for general working capital purposes, including the issuance of letters of credit, and (iii) to refinance existing debt under the Company’s credit facility with Dougherty Funding LLC.

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Financial Statements

(Unaudited)

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

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

On August 8, 2013, the Company entered into a Second Lien Credit Agreement dated August 8, 2013 (the “Subordinated Credit Agreement”) by and among the Company, as borrower, Chambers Energy Management, LP, as administrative agent (“Chambers”), and the several other lenders (the “Subordinated Credit Facility”). Under the Subordinated Credit Facility, term loans in the aggregate principal amount of up to $75 million are available from time to time (i) to repay the Previous Credit Facility, (ii) for fees and closing costs in connection with both the Senior Credit Facility and the Subordinated Credit Facility (together, the “Credit Facilities”), and (iii) general corporate purposes.

The Subordinated Credit Agreement provides for initial commitment availability of $25 million subject to customary conditions, with the remaining commitments subject to the approval of Chambers and other customary conditions. The Company may borrow the available commitments in amounts of $5 million or more and shall not request borrowings of such loans more than once a month, provided that the initial draw must be at least $15 million. Loans under the Subordinated Credit Facility shall be funded net of a 2% original issue discount. The unpaid principal balance of borrowings under the Subordinated Credit Facility bears interest at the Cash Interest Rate plus the PIK (Payment In Kind) Interest Rate. The Cash Interest Rate is 9.00% per annum plus a rate per annum equal to the greater of (i) 1.00% and (ii) the offered rate for three-month deposits in U.S. dollars that appears on Reuters Screen LIBOR 01 as of 11:00 a.m. (London time) on the second full LIBOR business day preceding the first day of each calendar quarter. The PIK Interest Rate is equal to 4.00% per annum. Interest is payable on the last day of each month. The Company is also required to pay an annual nonrefundable administration fee of $50,000 and until December 31, 2014, a monthly availability fee computed at a rate of 0.50% per annum on the average daily amount of any unused portion of the available amount under the commitment.

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

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

BLACK RIDGE OIL & GAS, INC.

Notes to Condensed Financial Statements

(Unaudited)

The Credit Facilities require customary affirmative and negative covenants for credit facilities of the respective types and sizes for companies operating in the oil and gas industry, as well as customary events of default. Furthermore, the Credit Facilities contain financial covenants that require the Company to satisfy certain specified financial ratios. The Senior Credit Agreement requires the Company to maintain (i) as of the last day of any fiscal quarter of the Company, a collateral coverage ratio (reserve value plus consolidated working capital to adjusted indebtedness) net of at least 1.25 to 1.0, (ii) a ratio of current assets to current liabilities of a minimum of 1.0 to 1.0, (iii) a total funded debt to EBITDAX, as defined in the Senior Credit Agreement, ratio of 3.5 to 1.0, calculated on a modified trailing four quarter basis, (iv) a maximum senior leverage ratio of not more than 2.5 to 1.0 calculated on a modified trailing four quarter basis, and (v) a minimum interest coverage ratio of not less than 3.0 to 1.0. The Subordinated Credit Agreement requires the Company to maintain (i) as of the last day of any fiscal quarter of the Company, a collateral coverage ratio (reserve value plus consolidated working capital to adjusted indebtedness) of at least 1.25 to 1.0, (ii) as of the last day of any fiscal quarter of the Company, a consolidated net leverage ratio (adjusted total indebtedness less the amount of unrestricted cash equivalents to consolidated EBITDA) of no more than 3.5 to 1.0, calculated on a modified trailing four quarter basis, (iii) as of the last day of any fiscal quarter of the Company, a consolidated cash interest coverage ratio (consolidated EBITDA to consolidated cash interest expense) of no less than 2.5 to 1.0, calculated on a modified trailing four quarter basis and (iv) as of the last day of any period of four consecutive fiscal quarters of the Company, a ratio of consolidated current assets to consolidated current liabilities of at least 1.0 to 1.0. In addition, each of the Credit Facilities requires that the Company enter into hedging agreements prior to funding with regard to no less than 50% and no greater than 75% of its future oil production on currently producing wells.

In connection with the funding of the Credit Facilities, the Company will pay-off amounts outstanding, including accrued interest, and terminate the Dougherty Credit Facility.

In connection with the Subordinated Credit Facility, the Company agreed to issue to the lenders cashless warrants to purchase up to 5,000,000 shares of the Company’s common stock at an exercise price of $0.65 per share. The warrants expire on August 8, 2018.

ITEM 2.

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

Cautionary Statements

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

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

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

volatility or decline of our stock price;

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

potential fluctuation in quarterly results;

our failure to earn revenues or to monetize claims that we have for payments owed to us;

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

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

unavailability of oil and gas prospects to acquire;

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

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

drilling of dry holes;

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

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

litigation, disputes and legal claims involving outside parties; and

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

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

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

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, 2013, we controlled the rights to mineral leases covering approximately 11,891 net acres for prospective drilling to the Bakken and/or Three Forks formations. Looking forward, we are pursuing the following objectives:

acquire high-potential mineral leases;

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

develop and maintain strategic industry relationships;

attract and retain talented associates;

operate a low overhead non-operator business model; and

become a low cost producer of hydrocarbons.

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

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

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

the sales price per barrel of oil;

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

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

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

Operational Highlights

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

production reached 25,741 Boe, or 283 Boe per day, representing 47% production growth compared to the second quarter of 2012 and 17% production growth compared to the first quarter of 2013;

participated in the completion of 8 gross (0.23 net) wells, with a 100% success rate in the Bakken and Three Forks plays increasing our total producing wells to 81 gross (2.82 net) wells;

decreased our general and administrative expenses 68% on a per Boe basis compared to the second quarter of 2012;

attained a record adjust EBITDA from operations of $1.2 million;

realized $.04 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 2013 performance reflects continued success in executing our strategy of developing our acreage position and building production. Our production increased 47% to 25,741 Boe in the second quarter of 2013 as compared to second quarter of 2012 production of 17,515 Boe. The increase in production was driven by a 54% increase in producing net wells from 1.83 net wells at June 30, 2012 to 2.82 net wells at June 30, 2013.

Total revenues increased 56% in the second quarter of 2013 compared to the second quarter of 2012 driven by higher production and an increase in average realized prices on a Boe basis of 6.0% in the second quarter of 2013 compared to the same period in 2012. 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

Refinance

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

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

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

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

Acreage Swap

On May 8, 2013, the Company closed on an acreage swap agreement. In exchange for 950 net acres in the Company’s Rainbow Field drilling units in Williams County North Dakota, the Company received:

7.5% working interest (WI) in the drilling unit consisting of Sections 13 & 14 of Township 154 North, Range 99 West, in the Stockyard Creek Field;

8.5% WI in the drilling unit consisting of Sections 14 & 15 of Township 154 North, Range 99 West, in the Stockyard Creek Field;

a drilling carry on the retained 151 net non-operated acres in the Rainbow Field whereby the operator will pay all drilling and completion costs of the Company’s retained 10% working interest on the first well in the one drilling unit and the Company’s retained 2% working interest on the first well in a second drilling unit. The operator has assessed that the Rainbow Field acreage will support sixteen wells, eight in the middle Bakken and eight in the first bench of the Three Forks.

The parties have a mutual option to execute a swap of additional acreage in the second Rainbow Field drilling unit in exchange for additional carried interest in the drilling unit.

The operator is currently drilling the first four wells of a fourteen well development plan in the Stockyard Creek Field. This transaction is exclusive of the wells currently producing on the acreage.

Potential Reverse Stock Split

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. There can be no assurance however that we will be able to obtain a listing on a national securities exchange even if we implement the reverse stock split.

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

Production History

The following table presents information about our produced oil and gas volumes during the three and six month periods ended June 30, 2013 and 2012, respectively. As of June 30, 2013, we controlled approximately 11,891 net acres in the Williston Basin. In addition, the Company owned working interests in 97 gross wells representing 3.50 net wells that are preparing to drill, drilling, awaiting completion, complete or producing.

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2013		2012		2013		2012
Net Production:
Oil (Bbl)		23,663		17,165		44,159		24,786
Natural Gas (Mcf)		12,465		2,102		20,302		4,650
Barrel of Oil Equivalent (Boe)		25,741		17,515		47,543		25,561

Average Sales Prices:
Oil (per Bbl)	$	88.02	$	79.77	$	89.26	$	81.51
Effect of oil hedges on average price (per Bbl)	$	–	$	–	$	–	$	–
Oil net of hedging (per Bbl)	$	88.02	$	79.77	$	89.26	$	81.51
Natural Gas (per Mcf)	$	5.48	$	5.31	$	5.94	$	5.66
Effect of natural gas hedges on average price (per Mcf)	$	–	$	–	$	–	$	–
Natural gas net of hedging (per Mcf)	$	5.48	$	5.31	$	5.94	$	5.66

Average Production Costs:
Oil (per Bbl)	$	11.03	$	7.07	$	11.83	$	10.62
Natural Gas (per Mcf)	$	0.69	$	0.16	$	0.78	$	0.58
Barrel of Oil Equivalent (Boe)	$	10.47	$	6.95	$	11.32	$	10.40

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, 2013 and 2012, respectively.

	Six Months Ended
	June 30,
	2013		2012
Depletion of oil and natural gas properties	$	1,568,388	$	814,615

Productive Oil Wells

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

	June 30, 2013				June 30, 2012
	Gross		Net		Gross		Net
North Dakota		80		2.74		48		1.83
Montana		1		0.08		–		–
Total		81		2.82		48		1.83

Exploratory Oil Wells

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

	June 30, 2013				June 30, 2012
	Gross		Net		Gross		Net
North Dakota		2		0.15		2		0.07
Total		2		0.15		2		0.07

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

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

	Three Months Ended
	June 30,						Increase /
	2013			2012			(Decrease)
Oil and gas sales	$	2,151,001		$	1,380,524		$	770,447

Operating expenses:
Production expenses		269,461			121,732			147,729
Production taxes		232,528			158,378			74,150
General and administrative		586,860			1,237,883			(651,023	)
Depletion of oil and gas properties		868,663			527,712			340,951
Accretion of discount on asset retirement obligations		1,811			1,208			603
Depreciation and amortization		5,811			5,734			77
Total operating expenses:		1,965,134			2,052,647			(87,513	)

Net operating income (loss)		185,867			(672,123	)		857,990

Total other income (expense)		(576,080	)		(172,703	)		(403,377	)

Loss before provision for income taxes		(390,213	)		(844,826	)		454,613

Provision for income taxes		92,913			227,381			(134,468	)

Net income (loss)	$	(297,300	)	$	(617,445	)	$	320,145

Revenues:

We recognized $2,151,001 in revenues from sales of crude oil and natural gas for the three months ended June 30, 2013 compared to revenues of $1,380,524 for the three months ended June 30, 2012, an increase of $770,477, or 56%. These revenues are due to the drilling and development of producing wells. We had 81 gross producing wells as of June 30, 2013, and an additional 16 wells that were either in the drilling preparation, drilling, awaiting completion, or completing stages, compared to 48 gross producing wells, and an additional 11 wells that were either in the drilling preparation, drilling, awaiting completion, or completing stages as of June 30, 2012.

Expenses:

Production expenses

Production expenses were $269,461 and $121,732 for the three months ended June 30, 2013 and 2012, respectively, an increase of $147,729, or 121%. Our production expenses are greater than the comparative period due to our rapid expansion and increased acreage holdings. Production expenses increased as a percentage of revenues from 8.8% in 2012 to 12.5% in 2013 as increased workover and related expenses and higher water hauling and disposal costs in 2013 drove production costs higher. On a per unit basis, production expenses increased from $6.95 per Boe in the second quarter of 2012 to $10.47 per Boe in the second quarter of 2013.

Production taxes

Our production taxes of $232,528 and $158,378 for the three months ended June 30, 2013 and 2012, respectively, an increase of $74,150, or 47%. Production taxes are paid based on realized oil and natural gas sales. Production taxes represented 10.8% and 11.5% of oil and gas revenues in the second quarter of 2013 and 2012, respectively, the decrease driven by increased production from Montana which has a lower production tax rate.

General and administrative expenses

General and administrative expenses for the three months ended June 30, 2013 were $586,860 compared to $1,237,883 for the three months ended June 30, 2012, a decrease of $651,023, or 53%. Our decrease in general and administrative expenses was primarily due to a one-time expense $438,539 incurred in 2012 related to the fair value of common stock granted as a non-refundable deposit on acreage acquisitions that we decided not to complete as well as decreased option related compensation expense and decreased professional fees for legal and consulting services offset by increased compensation as a result of hiring additional employees to support our expanding operations.

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 $868,663 for the three months ended June 30, 2013, compared to $527,712 for the three months ended June 30, 2012, an increase of $340,951, or 65%. The increase was due primarily due to our expansion of production and acquisitions of oil & gas properties during 2012 and the first half of 2013.

Depreciation

Depreciation expense for the three months ended June 30, 2013 was $5,811, compared to $5,734 for the three months ended June 30, 2012, an increase of $77, or 1%.

Net operating income (loss)

The net operating income for the three months ended June 30, 2013 was $185,867, compared to a net operating loss of ($672,123) for the three months ended June 30, 2012, a difference of $857,990. Our net operating income (loss) consisted primarily of our oil and gas revenue netted against oil & gas production costs, professional fees, officer salaries and depletion expense incurred as we expanded our oil and gas business. The majority of the difference is due to a one-time expense of $438,539 incurred in 2012 related to the fair value of common stock granted as a non-refundable deposit on acreage acquisitions that we decided not to complete and our expenses, primarily general and administrative expenses, not growing as rapidly as our oil and gas revenue.

Other income and (expenses)

Other income and (expenses) for the three months ended June 30, 2013 was ($576,080) compared to ($172,703) for the three months ended June 30, 2012. The 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 financing costs for the three months ended June 30, 2013. Our net other income and (expenses) for the three months ended June 30, 2012 consisted of $200 of interest income and ($172,903) of interest expense including ($35,507) of amortized warrant costs and ($34,479) of amortized debt issuance costs for the three months ended June 30, 2013. Amortization of the warrants and deferred financing costs were accelerated during 2013 due to our anticipated termination of the Dougherty credit facility in the third quarter of 2013 as part of our refinancing.

Provision for income taxes

We had income tax benefits of $526,701 and $381,565 for the six months and June 30, 2013 and 2012, respectively, a difference of $145,136. The tax benefit in the six months ended June 30, 2013 and 2012 was driven by our pre-tax losses of $510,188 and $1,759,867, respectively, and increased by the effect on deferred taxes of a change in our effective tax rate from 41.0% to 37.5% during the six months ended June 30, 2013 due to a change in state apportionment factors.

Net income (loss)

The net loss for the three months ended June 30, 2013 was ($297,300), compared to a net loss of ($617,445) for the three months ended June 30, 2012, a difference of $320,145. Our net income or loss consisted primarily of our oil and gas revenues and income tax benefits netted against our oil & gas production costs, professional fees, officer salaries and interest expense. The difference is primarily due to a one-time expense of $438,539 incurred in 2012 related to the fair value of common stock granted as a non-refundable deposit on acreage acquisitions that we decided not to complete and an increase in revenues greater than the increase in operating expenses, primarily general and administrative expenses, offset by increased interest expense due to the acceleration of amortization on warrant and debt financing costs in the 2013 period due to the anticipated termination of the Dougherty credit facility in the third quarter of 2013 as part of our refinancing.

Results of Operations for the Six Months Ended June 30, 2013 and 2012.

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

	Six Months Ended
	June 30,						Increase /
	2013			2012			(Decrease)
Oil and gas sales	$	4,062,300		$	2,046,730		$	2,015,570

Operating expenses:
Production expenses		538,267			265,883			272,384
Production taxes		451,870			233,810			218,060
General and administrative		1,190,438			1,951,774			(761,336	)
Depletion of oil and gas properties		1,568,388			814,615			753,773
Accretion of discount on asset retirement obligations		2,963			2,005			958
Depreciation and amortization		11,622			12,584			(962	)
Total operating expenses:		3,763,548			3,280,671			482,877

Net operating income (loss)		298,752			(1,233,941	)		1,532,693

Total other income (expense)		(808,940	)		(525,926	)		(283,014	)

Loss before provision for income taxes		(510,188	)		(1,759,867	)		1,249,679

Provision for income taxes		526,701			381,565			145,136

Net income (loss)	$	16,513		$	(1,378,302	)	$	1,394,815

Revenues:

We recognized $4,062,300 in revenues from sales of crude oil and natural gas for the six months ended June 30, 2013 compared to revenues of $2,046,730 for the six months ended June 30, 2012, an increase of $2,015,570, or 98%. These revenues are due to the drilling and development of producing wells. We had 81 gross producing wells as of June 30, 2013, and an additional 16 wells that were either in the drilling preparation, drilling, awaiting completion, or completing stages, compared to 48 gross producing wells, and an additional 11 wells that were either in the drilling preparation, drilling, awaiting completion, or completing stages as of June 30, 2012.

Expenses:

Production expenses

Production expenses were $538,267 and $265,883 for the six months ended June 30, 2013 and 2012, respectively, an increase of $272,384, or 102%. Production expenses increased as a percentage of revenues from 13.0% in 2012 to 13.3% in 2013. On a per unit basis, production expenses increased from $10.40 per Boe in in the first half of 2012 to $11.32 per Boe in the first half of 2013. Our 2013 production expenses are greater than the comparative period due to our rapid expansion and increased acreage holdings in addition to increased well workover and related expenses in the first and second quarters and increased weather related expenses incurred in the first quarter of 2013, offset by higher water disposal costs in the first quarter of 2012.

Production taxes

Our production taxes of $451,870 and $233,810 for the six months ended June 30, 2013 and 2012, respectively, an increase of $218,060, or 93%. Production taxes are paid based on realized oil and natural gas sales. Production taxes represented 11.1% and 11.4% of oil and gas revenues in the first half of 2013 and 2012, respectively. The decrease in production taxes as a percent of sales is driven by our expansion into Montana, which has a lower production tax rate.

General and administrative expenses

General and administrative expenses for the six months ended June 30, 2013 were $1,190,438 compared to $1,951,774 for the six months ended June 30, 2012, a decrease of $761,336, or 39%. Our decrease in general and administrative expenses was primarily due to a one-time expense of $438,539 incurred in 2012 related to the fair value of common stock granted as a non-refundable deposit on acreage acquisitions we decided not to complete as well as decreased option related compensation expense and decreased professional fees for legal and consulting services offset by increased compensation as a result of hiring additional employees to support our expanding operations.

Depletion of oil and natural gas properties

Our depletion expense is driven by many factors, including certain exploration costs involved in the development of producing reserves, production levels and estimates of proved reserve quantities and future developmental costs. We recognized depletion expense of $1,568,388 for the six months ended June 30, 2013, compared to $814,615 for the six months ended June 30, 2012, an increase of $753,773, or 93%. The increase was due primarily due to our expansion of production and acquisitions of oil & gas properties during 2012 and the first half of 2013.

Depreciation

Depreciation expense for the six months ended June 30, 2013 was $11,622 compared to $12,584 for the six months ended June 30, 2012, a decrease of $962, or 8%. The decreased depreciation expense was due to leasehold improvements becoming fully depreciated in 2012.

Net operating income (loss)

The net operating income for the six months ended June 30, 2013 was $298,752, compared to a net loss of ($1,233,941) for the six months ended June 30, 2012, a difference of $1,532,693. Our net operating income (loss) consisted primarily of our oil and gas revenue netted against oil and gas production costs, professional fees, officer salaries and depletion expense incurred as we expanded our oil and gas business. A part of the difference is a result of a one-time expense $438,539 incurred in 2012 related to the fair value of common stock granted as a non-refundable deposit on acreage acquisitions that we decided not to complete and our expenses, primarily general and administrative expenses, not growing as rapidly as our oil and gas revenue.

Other income and (expenses)

Other income and (expenses) for the six months ended June 30, 2013 was ($808,940) compared to ($525,926) for the six months ended June 30, 2012. The 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 financing costs for the six months ended June 30, 2013. Amortization of the fair value of warrants and deferred financing costs were accelerated in 2013 due to the anticipated termination of the Dougherty credit facility in the third quarter of 2013 as part of our refinancing. Our net other income and (expenses) for the six months ended June 30, 2012 consisted of $242 of interest income and ($526,168) of interest expense including ($304,788) of amortized warrant costs and ($80,463) of amortized debt issuance costs for the six months ended June 30, 2012. Amortization of the warrants and deferred financing costs were accelerated during the six months ended June 30, 2012 due to the termination of the PrenAnte5 credit facility on April 12, 2012.

Provision for income taxes

Net income (loss)

The net income for the six months ended June 30, 2013 was $16,513, compared to a net loss of ($1,378,302) for the six months ended June 30, 2012, a difference of $1,394,815. Our net income (loss) consisted primarily of our oil and gas revenues and income tax benefits netted against our oil and gas production costs, professional fees, officer salaries and interest expense. The difference is primarily due to a one-time expense $438,539 incurred in 2012 related to the fair value of common stock granted as a non-refundable deposit on acreage acquisitions that we decided not to complete as well as an increase in revenues greater than the increase in operating expenses, primarily general and administrative expenses offset by increased interest expense due to higher levels of borrowing and the acceleration of amortization on warrant and debt financing costs in the 2013 period due to the anticipated termination of the Dougherty credit facility as compared the acceleration of amortization on warrant and debt financing costs in the 2012 period due to the termination of the PrenAnte5 credit facility on April 12, 2012.

Non-GAAP Financial Measures

In addition to reporting net income (loss) as defined under GAAP, we also present Adjusted EBITDA. We define Adjusted EBITDA as net income before (i) interest expense, (ii) income taxes, (iii) depreciation, depletion and amortization, (iv) accretion of abandonment liability, and (v) 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 EBITDA does not represent, and should not be considered an alternative to GAAP measurements. We believe this measure is useful in evaluating our fundamental core operating performance. Specifically, we believe the non-GAAP Adjusted EBITDA results provide useful information to both management and investors by excluding certain expenses that our management believes are not indicative of our core operating results. Although we use 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 EBITDA to Net Income, GAAP, are included below:

Black Ridge Oil & Gas, Inc.

Reconciliation of Adjusted EBITDA

(Unaudited)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2013			2012			2013			2012
Net Income (loss)	$	(297,300	)	$	(617,445	)	$	16,513		$	(1,378,302	)
Add Back:
Interest Expense, net, excluding amortization of warrant based financing costs		520,284			137,196			743,056			221,138
Income Tax Provision		(92,913	)		(227,381	)		(526,701	)		(381,565	)
Depreciation, Depletion, and Amortization		874,474			533,446			1,580,010			827,199
Accretion of Abandonment Liability		1,811			1,208			2,963			2,005
Common stock issued for terminated oil and gas acquisition		–			438,539			–			438,539
Share Based Compensation		223,145			272,208			395,598			778,950

Adjusted EBITDA	$	1,229,501		$	537,771		$	2,211,439		$	507,964

Liquidity and capital resources

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

	June 30,		December 31,
	2013		2012
Current Assets	$	7,442,520	$	6,171,023

Current Liabilities	$	5,527,306	$	3,291,426

Working Capital	$	1,915,214	$	2,879,597

As of June 30, 2013 we had positive working capital of $1,915,214.

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

	Six Months Ended
	June 30,
	2013			2012
Net cash provided by operating activities	$	1,012,427		$	105,960
Net cash used in investing activities		(2,947,282	)		(6,163,947	)
Net cash provided by financing activities		2,089,994			5,529,178

Net change in cash and cash equivalents	$	155,139		$	(528,809	)

Our net cash flows from operations are primarily affected by production volumes and commodity prices. Net cash provided by operating activities was $1,012,427 and $105,960 for the six months ended June 30, 2013 and 2012, respectively, an increase of $906,467. 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 ($855,610) in the six months ended June 30, 2013 as compared to a decrease in cash of ($261,329) for the same period in the previous year, primarily driven in both periods by increases in accounts receivable balances.

Net cash used in investing activities was $2,947,282 and $6,163,947 for the six months ended June 30, 2013 and 2012, respectively, a decrease of $3,216,665. The decrease was primarily driven by decreased expenditures for well development as we paid $5,602,031 for well development during the 2012 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 decrease in cash used in investing activities was also attributable to a decrease in cash spent for property acquisition as we purchased 800 acres of oil and gas properties for $416,283 in the six months ended June 30, 2013 as compared to purchasing 978 acres of oil and gas properties for $1,291,113 in the six months ended June 30, 2012.

Net cash provided from financing was $2,089,994 and $5,529,178 for the six month period ended June 30, 2013 and 2012, respectively. We drew $2,114,994, net of repayments, on our revolving credit facility in the in the six months ended June 30, 2013 while funding a portion of the operational and investing activity through operating income and working capital and paid $25,000 in debt issuance costs. In the six months ended June 30, 2012 we drew $2 million on our PrenAnte5 revolving credit facility and drew $5,825,000 on our Dougherty revolving credit facility, of which $2 million of the proceeds were used to repay the PrenAnte5 revolving credit facility, and paid debt issuance costs of $295,822.

Senior Credit Facility and Subordinated Credit Facilities

On August 8, 2013, the Company entered into a $50 million first lien revolving credit facility and a $75 million second lien term credit facility (collectively “the Credit Facilities”). The first funding from the Credit Facilities is scheduled to coincide with the repayment of the Dougherty Credit Facility at the end of a 30 day notice period.

The Subordinated Credit Agreement provides for initial commitment availability of $25 million, subject to customary conditions, with the remaining commitments subject to the approval of Chambers and other customary conditions. The Company may borrow the available commitments in amounts of $5 million or more and shall not request borrowings of such loans more than once a month, provided that the initial draw must be at least $15 million. Loans under the Subordinated Credit Facility shall be funded net of a 2% original issue discount. The unpaid principal balance of borrowings under the Subordinated Credit Facility bears interest at the Cash Interest Rate plus the PIK (Payment In Kind) Interest Rate. The Cash Interest Rate is 9.00% per annum plus a rate per annum equal to the greater of (i) 1.00% and (ii) the offered rate for three-month deposits in U.S. dollars that appears on Reuters Screen LIBOR 01 as of 11:00 a.m. (London time) on the second full LIBOR business day preceding the first day of each calendar quarter. The PIK Interest Rate is equal to 4.00% per annum. Interest is payable on the last day of each month. The Company is also required to pay an annual nonrefundable administration fee of $50,000 and until December 31, 2014, a monthly availability fee computed at a rate of 0.50% per annum on the average daily amount of any unused portion of the available amount under the commitment.

The Credit Facilities require customary affirmative and negative covenants for credit facilities of the respective types and sizes for companies operating in the oil and gas industry, as well as customary events of default. Furthermore, the Credit Facilities contain financial covenants that require the Company to satisfy certain specified financial ratios. The Senior Credit Agreement requires the Company to maintain (i) as of the last day of any fiscal quarter of the Company, a collateral coverage ratio (reserve value plus consolidated working capital to adjusted indebtedness) of at least 1.25 to 1.0, (ii) a ratio of current assets to current liabilities of a minimum of 1.0 to 1.0, (iii) a net debt to EBITDAX, as defined in the Senior Credit Agreement, ratio of 3.5 to 1.0, calculated on a modified trailing four quarter basis, (iv) a maximum senior leverage ratio of not more than 2.5 to 1.0 calculated on a modified trailing four quarter basis, and (v) a minimum interest coverage ratio of not less than 3.0 to 1.0. The Subordinated Credit Agreement requires the Company to maintain (i) as of the last day of any fiscal quarter of the Company, a collateral coverage ratio (reserve value plus consolidated working capital to adjusted indebtedness) of at least 1.25 to 1.0, (ii) as of the last day of any fiscal quarter of the Company, a consolidated net leverage ratio (adjusted total indebtedness less the amount of unrestricted cash equivalents to consolidated EBITDA) of no more than 3.5 to 1.0, calculated on a modified trailing four quarter basis, (iii) as of the last day of any fiscal quarter of the Company, a consolidated cash interest coverage ratio (consolidated EBITDA to consolidated cash interest expense) of no less than 2.5 to 1.0, calculated on a modified trailing four quarter basis and (iv) as of the last day of any period of four consecutive fiscal quarters of the Company, a ratio of consolidated current assets to consolidated current liabilities of at least 1.0 to 1.0. In addition, each of the Credit Facilities requires that the Company enter into hedging agreements prior to funding with regard to no less than 50% and no greater than 75% of its future oil production on currently producing wells.

In connection with the funding of the Credit Facilities, the Company will pay-off amounts outstanding, including accrued interest, and terminate the Dougherty Credit Facility.

In connection with the Subordinated Credit Facility, the Company agreed to issue to the lenders 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.

Dougherty Revolving 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”). Under the terms of the amended Credit Facility, up to $20 million maximum is available from time to time (i) to fund, or to reimburse the Company for, the Company’s pro-rata share of development and production costs for oil wells that relate to the Company’s oil and gas leasehold interests for which there is a valid and enforceable Authorization for Expenditure and that are incurred from and after the date of the Credit Facility, and (ii) to reimburse the Company for amounts that the Company paid from its own funds or from funds that it borrowed under its previous credit facility from Prenante5, LLC as agent pursuant to the Revolving Credit and Security Agreement dated May 2, 2011. Of the $20 million Dougherty Credit Facility, $16.5 million is currently available. If the Company has not successfully completed an equity offering of at least $10 million by August 31, 2014, then advances will no longer be available under the Dougherty Credit Facility.

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

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

The Dougherty Credit Facility will mature on August 1, 2015. The Credit Facility may be prepaid with thirty (30) days written notice at any time. In connection with the amended financing, the Company agreed to issue Dougherty Funding, LLC warrants to purchase up to 900,000 shares of the Company’s common stock, of which 585,000 shares have currently been issued, 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, and we have taken subsequent draws, net of repayments, of $5,413,838 through June 30, 2013 and have used the proceeds to pay for development of oil and gas wells.

On August 8, 2013, we gave Dougherty notice of our intent to prepay the Dougherty Credit Facility in 30 days with proceed 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 2013. However, our availability under our credit facilities provides ample funding for our property acquisition and development plans throughout 2013. Our prospects still must be considered in light of the risks, expenses and difficulties frequently encountered by companies in their early stage of development. Such risks for us include, but are not limited to, potential failure to earn revenues or to sufficiently monetize certain claims that we have for payments that are owed to us; an inability to identify investment and expansion targets; and dissipation of existing assets. To address these risks, we must, among other things, seek growth opportunities through investment and acquisitions in the oil and gas industry, effectively monitor and manage our claims for payments that are owed to us, implement and successfully execute our business strategy, respond to competitive developments, and attract, retain and motivate qualified personnel. We cannot assure that we will be successful in addressing such risks, and the failure to do so could have a material adverse effect on our business prospects, financial condition and results of operations.

Satisfaction of our cash obligations for the next 12 months

As of June 30, 2013, our balance of cash and cash equivalents was $1,572,479. 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 enter into 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. As of June 30, 2013, we had not entered into any derivative 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, 2013. As part of such evaluation, management considered the matters discussed below relating to internal control over financial reporting. Based on this evaluation our management, including the Company’s Chief Executive Officer and Chief Financial Officer, has concluded that the Company’s disclosure controls and procedures were effective as of June 30, 2013 to ensure that the information required to be disclosed in our Exchange Act reports was recorded, processed, summarized and reported on a timely basis.

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

None.

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

None.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES.

None.

ITEM 4. MINE SAFETY DISCLOSURES.

Not applicable.

ITEM 5. OTHER INFORMATION.

None.

ITEM 6. EXHIBITS.

Exhibit		Description

10.1		Change of Control Agreement, dated April 5, 2013, between Black Ridge Oil & Gas, Inc. and Ken DeCubellis (incorporated by reference to Exhibit 10.1 of the Form 8-K filed with the Securities and Exchange Commission by Black Ridge Oil & Gas, Inc. April 5, 2013)
10.2		Change of Control Agreement, dated April 5, 2013, between Black Ridge Oil & Gas, Inc. and James Moe (incorporated by reference to Exhibit 10.2 of the Form 8-K filed with the Securities and Exchange Commission by Black Ridge Oil & Gas, Inc. April 5, 2013)
31.1		Section 302 Certification of Chief Executive Officer
31.2		Section 302 Certification of Chief Financial Officer
32.1		Section 906 Certification of Chief Executive Officer
32.2		Section 906 Certification of Chief Financial Officer
101.INS		XBRL Instance Document
101.SCH		XBRL Schema Document
101.CAL		XBRL Calculation Linkbase Document
101.DEF		XBRL Definition Linkbase Document
101.LAB		XBRL Labels Linkbase Document
101.PRE		XBRL Presentation Linkbase Document

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 13, 2013	By:	/s/Kenneth DeCubellis
		Kenneth DeCubellis, Chief Executive Officer (Principal Executive Officer)

Dated: August 13, 2013

By:

/s/James A. Moe

James A. Moe, Chief Financial Officer

(Principal Financial Officer)

Sow Good Inc. - FORM 10-Q - August 13, 2013

Attached files

Sow Good Inc. Reports