EX-99.1 2 blackridge_8k-ex9901.htm PRESS RELEASE

Exhibit 99.1

Black Ridge Oil & Gas Announces Second Quarter 2015 Results

MINNETONKA, Minn., August 13, 2015 - Black Ridge Oil & Gas, Inc. ("the Company") (OTCQB: ANFC), a growth-oriented exploration and production company focused on non-operated Bakken and Three Forks properties, today announced financial and operating results for the three and six months ended June 30, 2015.

Second Quarter 2015 Company Highlights

Quarterly production increased 57% over the second quarter of 2014 to 102.2 thousand barrels of oil equivalent (“MBoe”), an average of approximately 1,123 barrels of oil equivalent per day (“Boe/d”)

Oil and gas sales totaled $5.1 million, an increase of 75% over the first quarter of 2015 and a decrease of 9% from the second quarter of 2014

Added 5 gross (0.17 net) wells, increasing our total producing well count to 291 gross (8.96 net), an increase of 43% over the second quarter of 2014

Recorded $3.6 million of adjusted EBITDA, equal to the EBITDA generated in the second quarter of 2014

Reduced general and administrative expenses to $7.15 per Boe, a decrease of 27% from the second quarter of 2014

Recorded GAAP net loss for the quarter of $0.39 per diluted share, impacted by a non-cash impairment of $21.6 million ($0.34 per diluted share, net of tax effect)

Announced the formation of a strategic partnership with Merced Capital, focused on acquiring non-operated assets in the Williston Basin

Continued the development of the Teton project (1.76 net wells) with strong initial production rates

During and subsequent to the second quarter, entered into swap contracts to sell an additional 237,000 barrels of oil at a weighted average price of $60.40.

Teton Project Update and Production Guidance

The drilling, completion and flowback of the Teton project is running ahead of the Company’s original plan, and the daily production volumes achieved during the flowback phase were higher than our initial estimates. The transition from flowback to full production will occur after all of the Teton wells are connected to permanent production facilities, and at this stage, the natural gas tie-in is running behind schedule. While we are very encouraged by the production rates achieved during flowback, we are not updating our full year production guidance of 1,200 Boe/d until we receive clarity on the timing of the facility completion.

The following table summarizes the flowback status of the Teton project as of August 10, 2015. The operator’s flowback procedure limited production to less than 15,000 barrels of oil per well. Flowback commenced in late June and is expected to end on approximately August 15.

WELL	W.I.	Current Status	Flowback Information
WELL	W.I.	Current Status	Bbls Oil Produced	MCF Gas Produced	# of Days
Teton 2-8-10MBH	8.4%	Flowback Complete, Waiting on Facilities	14,839	24,020	6
Teton 6-8-10MBH	8.4%	Flowback Complete, Waiting on Facilities	14,656	27,510	6
Teton 7-8-10MBH	8.4%	Flowback Complete, Waiting on Facilities	14,785	22,171	7
Teton 8-8-10TFSH	8.4%	Flowback Complete, Waiting on Facilities	14,789	21,645	7
Teton 5-1-3TFSH	8.4%	Flowback Complete, Waiting on Facilities	14,732	16,173	8
Teton 6-8-10TFSH	8.4%	Flowback Complete, Waiting on Facilities	14,883	23,203	8
Teton 5-8-10MBH	8.4%	Flowback Complete, Waiting on Facilities	14,280	21,591	8
Teton 7-1-3TFSH	8.4%	Flowback Complete, Waiting on Facilities	14,835	25,283	8
Kings Canyon 6-1-27MBH	8.4%	Flowback Complete, Waiting on Facilities	14,699	10,225	9
Kings Canyon 7-8-34MBH	8.4%	Flowback Complete, Waiting on Facilities	14,805	28,901	9
Teton 3-8-10MBH	8.4%	Flowback Complete, Waiting on Facilities	14,861	23,839	9
Kings Canyon 2-8-34UTFH	8.4%	Flowback Complete, Waiting on Facilities	14,224	14,066	11
Kings Canyon 4-8-34UTFH	8.4%	Flowback Complete, Waiting on Facilities	14,696	19,730	11
Kings Canyon 6-8-34UTFH	8.4%	Flowback Complete, Waiting on Facilities	14,087	25,180	11
Kings Canyon 4-1-27MTFH	8.4%	Flowback Complete, Waiting on Facilities	14,691	11,371	11
Kings Canyon 4-8-34MBH	8.4%	Flowback Complete, Waiting on Facilities	12,806	16,552	12
Kings Canyon 5-8-34UTFH	8.4%	Flowback Complete, Waiting on Facilities	14,764	17,500	12
Kings Canyon 6-1-27MTFH	8.4%	Flowback in Process	11,391	13,050	8
Kings Canyon 3-1-27MTFH	8.4%	Flowback in Process	9,701	14,606	11
RemingTeton 8-8-10 MBH	6.3%	Flowback Complete, Waiting on Facilities	14,805	20,641	7
TetoNorman 1-1-3UTFH	6.3%	Flowback Complete, Waiting on Facilities	14,736	16,696	9
LaCanyon 8-8-34MBH	2.1%	Flowback Complete, Waiting on Facilities	14,794	25,880	7
DeKing 1-8-34MBH-ULW	2.1%	Flowback Complete, Waiting on Facilities	14,713	22,758	9

Management Comment

”The Company is excited by the initial results from our Teton project and we look forward to full production and cash flow from this asset,” said Ken DeCubellis, Chief Executive Officer. “We added additional hedges in May and July to protect our balance sheet, maintain ample cash flow and preserve our asset value during this down cycle in oil prices. As we look forward to the remainder of 2015 and 2016, the Company’s focus will be on allocating our free cash flow to debt reduction and finding acquisition opportunities for our joint venture with Merced.”

Liquidity Position and Borrowing Base

Black Ridge ended the quarter with $29.75 million drawn on its $34 million senior secured revolving credit facility. The next redetermination date is scheduled for October 1, 2015. The Company expects to fund 2015 development from availability under the borrowing base and cash flow from operations.

Hedging Update

In the second quarter of 2015, the Company realized an $847,198 gain on settled derivatives, and a $1,956,155 unrealized loss on mark-to-market adjustments to its outstanding derivatives contracts. As of June 30, 2015, the Company’s net derivative asset was $5,990,919. On July 22, 2015, the Company entered into new crude oil swap contracts for 18,000 barrels in 2H 2016 at $55.55, 42,000 barrels in 2017 at $57.95 and 96,000 barrels at $60.67 in 2018. The following table summarizes the Company’s open crude oil swap contracts as of August 12, 2015:

	Oil	Weighted Average
Term	(barrels)	Price ($ per Bbl)
2015:
Q3	21,750	89.84
Q4	57,750	72.40
2016:
Q1	43,500	75.84
Q2	43,500	75.84
Q3	30,000	79.47
Q4	30,000	79.47
2017:
Q1	30,000	76.95
Q2	30,000	76.95
Q3	30,000	76.95
Q4	30,000	76.95
2018:
Q1	24,000	60.67
Q2	24,000	60.67
Q3	24,000	60.67
Q4	24,000	60.67

In addition to the open crude oil swap contracts, the Company has entered into costless collar contracts. The costless collars are used to establish floor and ceiling prices on anticipated crude oil production. There were no premiums paid or received by us related to the costless collar contracts. The following table reflects open costless collar crude oil contracts as of August 12, 2015:

	Oil	Floor/Ceiling
Term	(Barrels)	Price (WTI)	Basis
*Costless Collars – Crude Oil*
07/01/2015 – 12/31/2015	18,000	$75.00/$95.60	NYMEX
01/01/2016 – 06/30/2016	10,002	$80.00/$89.50	NYMEX

2015 Operating and Financial Results

The following table presents selected operating and financial data for the periods indicated.

	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2015		2014			2015		2014
Net Production:
Oil (Bbl)		90,118		58,812			163,041		101,967
Natural gas (Mcf)		72,381		37,482			170,695		61,819
Barrel of oil equivalent (Boe)		102,182		65,059			191,490		112,270

Average Sales Prices:
Oil (per Bbl)	$	54.71	$	91.27		$	47.06	$	89.88
Effect of oil hedges on average price (per Bbl)	$	9.40	$	(4.47	)	$	12.15	$	(3.71	)
Oil net of hedging (per Bbl)	$	64.11	$	86.80		$	59.21	$	86.17
Natural gas (per Mcf)	$	1.66	$	4.97		$	1.55	$	6.78
Realized price, net of settled derivatives (Boe)	$	57.71	$	81.33		$	51.79	$	81.99

Average Production Costs:
Oil (per Bbl)	$	12.50	$	9.79		$	12.68	$	9.85
Natural gas (per Mcf)	$	0.38	$	0.53		$	0.45	$	0.75
Barrel of oil equivalent (Boe)	$	11.29	$	9.15		$	11.19	$	9.36

Dahl Federal Recognition

During the second quarter of 2015, the Company recognized all well costs, revenues, and expenses related to the Dahl Federal 2-15H well back to the inception of the well in January of 2012. Due to uncertainties regarding the Company’s ownership of this interest related to the State of North Dakota’s claim to mineral rights under the Missouri River, the Company had not previously recognized any well costs, revenues, or expenses for this well. As these uncertainties are now resolved, in the second quarter of 2015, the Company recognized $1.3 million of oil and gas revenues, $83,000 of production expenses, $140,000 of production taxes, and production of 15,682 net Boe from prior periods. The Company also capitalized $0.9 million of well costs related to the drilling and completion of the well. Please see the Company’s 10-Q filing for additional information.

Second Quarter 2015 Financial Results

In the second quarter of 2015, oil and gas sales, excluding the impact of settled derivatives, were $5.05 million, a decrease of 9% as compared to the second quarter of 2014. The Company realized an average price of $54.71 per barrel of oil and $1.66 per mcf of gas, representing decreases of 40% and 67%, respectively, as compared to the second quarter of 2014. The impact of weaker commodity prices was partially offset by a 57% increase in production over the second quarter of 2014. The Company’s production in the second quarter of 2015 was comprised of 88% oil and 12% natural gas and natural gas liquids, on a Boe basis.

For the second quarter of 2015, the Company realized a gain on settled derivatives of $0.8 million, compared to a loss of $0.3 million in the second quarter of 2014. The Company had a mark-to-market derivative loss of $2.0 million in the second quarter of 2015 compared to a mark-to-market loss of $0.9 million in the second quarter of 2014.

Production expenses for the second quarter of 2015 were $1.2 million, or $11.29 per Boe, compared to $0.6 million, or $9.15 per Boe, for the second quarter of 2014. The increase in production expense in the second quarter was primarily attributable to cleanout costs on producing wells subsequent to completion activities on offset locations in the Company’s Stockyard Creek project.

Production taxes for the second quarter of 2015 were $0.6 million, compared to $0.6 million, for the second quarter of 2014. Production taxes as a percent of revenue were 11.0% for the second quarter of 2015, compared to 10.7% for the second quarter of 2014.

Depletion, depreciation, amortization and accretion (“DD&A”) was $2.9 million, or $28.87 per Boe, in the second quarter of 2015, compared to $2.1 million, or $32.97 per Boe, in the second quarter of 2014.

As a result of the currently prevailing low commodity prices and their effect on the proved reserve values of properties in 2015, we recorded a non-cash ceiling test impairment of $21.6 million in the second quarter of 2015. The Company did not have any impairment of its proved oil and gas properties in the second quarter of 2014. The impairment charge affected our reported net income but did not reduce our cash flow.

General and administrative expenses (“G&A”) for the second quarter of 2015 were $0.7 million, or $7.15 per Boe, compared to $0.6 million, or $9.75 per Boe, for the second quarter of 2014. Cash G&A (non-GAAP, excludes stock-based compensation expense) was $0.6 million, or $5.65 per Boe, for the second quarter of 2015 compared to $0.5 million, or $7.52 per Boe, for the second quarter of 2014.

Interest expense, net of capitalized interest, was $1.6 million in the second quarter of 2015, compared to $1.3 million in the second quarter of 2014. The increase in interest expense was primarily due to additional borrowing to fund the Company’s capital development program.

The income tax benefit recognized during the second quarter of 2015 was $6.0 million, or 24.2% of the loss before income taxes, as compared to a net income tax benefit of $0.3 million, or 36.0% of the loss before income taxes, in the second quarter of 2014. The lower effective tax rate in 2015 relates to a valuation allowance placed on the net deferred tax asset in the second quarter of 2015.

The Company recorded $3.6 million of adjusted EBITDA in the second quarter of 2015, flat compared to the second quarter of 2014. Adjusted EBITDA is a non-GAAP financial measure. Please refer to the reconciliation in this release for additional information about this measure.

Acreage and Drilling

As of June 30, 2015, the Company controlled approximately 8,600 net acres in the Williston Basin. Approximately 72% of the acreage is held by production with 291 gross (8.96 net) wells producing. Additionally, the Company had 2.04 net wells in development as of June 30, 2015.

Producing Wells

The following table sets forth wells in which Black Ridge holds a participating interest that were completed, acquired, or first recognized during the quarter ending June 30, 2015:

*Well*	*Operator*	*Location*	*WI⁽¹⁾*
Dahl Federal 2-15H	SM Energy	McKenzie, ND	8.7%
Tetonorman 1-1-3UTFH ULW	Burlington Resources	McKenzie, ND	6.3%
DeKing 1-8-34MBH-ULW	Burlington Resources	McKenzie, ND	2.1%
P Jackman 156-100-2-18-6-1H	Whiting	Williams, ND	1.0%
P Jackman 156-100-2-18-6-2H	Whiting	Williams, ND	1.0%
CCU North Coast 31-25TFH	Burlington Resources	Dunn, ND	0.8%

⁽¹⁾The working interests are based on Black Ridge's internal records and may be subject to change by operators' third-party legal counsel in preparing final division order title opinions for each well.

"Drilling" Wells

The following table sets forth wells in which Black Ridge holds a participating interest that were either preparing to drill, drilling, awaiting completion or completing as of June 30, 2015:

*Well*	*Operator*	*Location*	*WI⁽¹⁾*
Kings Canyon 5-8-34UTF	Burlington Resources	McKenzie, ND	8.4%
Teton 5-8-10MBH	Burlington Resources	McKenzie, ND	8.4%
Kings Canyon 6-1-27MBH	Burlington Resources	McKenzie, ND	8.4%
Kings Canyon 6-1-27MTFH	Burlington Resources	McKenzie, ND	8.4%
Kings Canyon 4-1-27MTFH	Burlington Resources	McKenzie, ND	8.4%
Kings Canyon 3-1-27MTFH	Burlington Resources	McKenzie, ND	8.4%
Kings Canyon 6-8-34UTFH	Burlington Resources	McKenzie, ND	8.4%
Kings Canyon 2-8-34UTFH	Burlington Resources	McKenzie, ND	8.4%
Kings Canyon 4-8-34UTFH	Burlington Resources	McKenzie, ND	8.4%
Kings Canyon 4-8-34MBH	Burlington Resources	McKenzie, ND	8.4%
Teton 5-1-3TFSH	Burlington Resources	McKenzie, ND	8.4%
Teton 2-8-10MBH	Burlington Resources	McKenzie, ND	8.4%
Teton 3-8-10MBH	Burlington Resources	McKenzie, ND	8.4%
Teton 6-8-10TFSH	Burlington Resources	McKenzie, ND	8.4%
Teton 8-8-10TFSH	Burlington Resources	McKenzie, ND	8.4%
Teton 7-8-10MBH	Burlington Resources	McKenzie, ND	8.4%
Teton 6-8-10MBH	Burlington Resources	McKenzie, ND	8.4%
Teton 7-1-3TFSH	Burlington Resources	McKenzie, ND	8.4%
Kings Canyon 7-8-34MBH	Burlington Resources	McKenzie, ND	8.4%
Remingteton 8-8-10MBH	Burlington Resources	McKenzie, ND	6.2%
Thorp Federal 11X-28A	XTO	Dunn, ND	3.4%
LaCanyon 8-8-34MBH ULW	Burlington Resources	McKenzie, ND	2.1%
EN-Weyrauch B-LW-154-93-3031H-1	Hess	Mountrail, ND	1.6%
P Berger 156-100-14-7-6-4H	Whiting	Williams, ND	1.0%
P Berger 156-100-14-7-6-3H	Whiting	Williams, ND	1.0%

Aaberg 8-5N-1H	Mountain Divide	Divide, ND	0.8%
CCU Powell 41-29TFH	Burlington Resources	Dunn, ND	0.8%
CCU Dakotan 2-7-17MBH	Burlington Resources	Dunn, ND	0.8%
CCU Dakotan 1-7-17TFH	Burlington Resources	Dunn, ND	0.8%
CCU Dakotan 1-7-17MBH	Burlington Resources	Dunn, ND	0.8%
CCU Dakotan 2-7-17TFH	Burlington Resources	Dunn, ND	0.8%
CCU Dakotan 5-8-17TFH	Burlington Resources	Dunn, ND	0.8%
CCU Dakotan 6-8-17MBH	Burlington Resources	Dunn, ND	0.8%
CCU Dakotan 7-8-17TFH	Burlington Resources	Dunn, ND	0.8%
CCU Dakotan 7-8-17MBH	Burlington Resources	Dunn, ND	0.8%
CCU Dakotan 5-8-17MBH	Burlington Resources	Dunn, ND	0.8%
CCU Dakotan 4-8-17TFH	Burlington Resources	Dunn, ND	0.8%
CCU Dakotan 3-8-17MBH	Burlington Resources	Dunn, ND	0.8%
CCU Gopher 1-2-15TFH	Burlington Resources	Dunn, ND	0.8%
CCU Gopher 2-2-15MBH	Burlington Resources	Dunn, ND	0.8%
CCU Red River 7-2-15TFH	Burlington Resources	Dunn, ND	0.8%
CCU Red River 8-2-15MBH	Burlington Resources	Dunn, ND	0.8%
CCU Bison Point 24-34TFH	Burlington Resources	Dunn, ND	0.8%
CCU Bison Point 24-34MBH	Burlington Resources	Dunn, ND	0.8%
CCU Bison Point 34-34TFH	Burlington Resources	Dunn, ND	0.8%
CCU Bison Point 34-34MBH	Burlington Resources	Dunn, ND	0.8%
CCU Olympian 21-2MBH	Burlington Resources	Dunn, ND	0.8%
CCU Olympian 31-2TFH	Burlington Resources	Dunn, ND	0.8%
CCU Olympian 31-2MBH	Burlington Resources	Dunn, ND	0.8%
CCU Golden Creek 34-23TFH	Burlington Resources	Dunn, ND	0.8%
CCU Burner 31-26TFH	Burlington Resources	Dunn, ND	0.8%
Jersey 1-6H	Continental	Mountrail, ND	0.8%
Jersey 3-6H1	Continental	Mountrail, ND	0.8%
Jersey 2-6H2	Continental	Mountrail, ND	0.8%
Jersey 5-6H	Continental	Mountrail, ND	0.8%
P Johnson 153-98-1-6-7-16H	Whiting	Williams, ND	0.6%
P Johnson 153-98-1-6-7-16HA	Whiting	Williams, ND	0.6%
P Pankowski 153-98-4-6-7-13H	Whiting	Williams, ND	0.6%
P Pankowski 153-98-4-6-7-13HA	Whiting	Williams, ND	0.6%
Burr Federal 10-26H	Continental	Mountrail, ND	0.5%
Burr Federal 9-26H1	Continental	Mountrail, ND	0.5%
Burr Federal 11-26H	Continental	Mountrail, ND	0.5%
Burr Federal 12-26H1	Continental	Mountrail, ND	0.5%
Burr Federal 13-26H	Continental	Mountrail, ND	0.5%
Burr Federal 14-26H	Continental	Mountrail, ND	0.5%

Adjusted Net Loss and Adjusted EBITDA

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

Reconciliation of Net Loss to Adjusted Net Loss

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2015			2014			2015			2014
Net loss	$	(18,669,638	)	$	(543,360	)	$	(19,942,574	)	$	(924,920	)
Add back:
Loss on mark-to-market of derivatives, net of tax ^(a)		1,467,155			555,124			1,191,826			690,159
Impairment of oil and gas properties, net of tax ^(b)		16,229,000			–			16,229,000			–
Adjusted net income (loss)	$	(973,483	)	$	11,764		$	(2,521,748	)	$	(234,761	)

Weighted average common shares outstanding - basic and fully diluted		47,979,990			47,979,990			47,979,990			47,979,990

Net income (loss) per common share – basic and fully diluted	$	(0.39	)	$	(0.01	)	$	(0.42	)	$	(0.02	)
Add:
Change due to loss on mark-to- market of derivatives, net of tax		0.03			0.01			0.03			0.01
Change due to impairment of oil and gas properties, net of tax		0.34			–			0.34			–
Adjusted net income (loss) per common share – basic and fully diluted	$	(0.02	)	$	0.00		$	(0.05	)	$	(0.01	)

^(a)Adjusted to reflect tax expense, computed based on our effective tax rate of approximately 25% in 2015 and 37% in 2014, of $489,000 and $326,000 for the three month ended June 30, 2015 and 2014, respectively, and $397,000 and $405,000 for the six months ended June 30, 2015 and 2014, respectively.

^(b)Adjusted to reflect tax expense, computed based on our effective tax rate of approximately 25% in 2015 and 37% in 2014, of $5,410,000 and $-0- for the three month ended June 30, 2015 and 2014, respectively, and $5,410,000 and $-0- for the six months ended June 30, 2015 and 2014, respectively.

Reconciliation of Net Loss to Adjusted EBITDA

Black Ridge Oil & Gas, Inc.

Reconciliation of Adjusted EBITDA

(Unaudited)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2015			2014			2015			2014
Net income (loss)	$	(18,669,638	)	$	(543,360	)	$	(19,942,574	)	$	(924,920	)
Add back:
Interest expense, net, excluding amortization of warrant based financing costs		1,385,837			1,136,603			2,792,657			2,065,981
Income tax provision		(5,957,649	)		(305,715	)		(6,593,040	)		(589,738	)
Depreciation, depletion, and amortization		2,941,753			2,139,733			5,576,052			3,734,590
Impairment of oil and gas properties		21,639,000			–			21,639,000			–
Accretion of abandonment liability		7,932			5,148			15,861			9,653
Share based compensation		314,162			301,241			635,514			599,003
Loss on mark-to market of derivatives		1,956,154			881,124			1,588,826			1,095,159

Adjusted EBITDA	$	3,617,551		$	3,614,774		$	5,712,296		$	5,989,728

Our Adjusted EBITDA for the three and six month periods ending June 30, 2015 includes income from the Dahl Federal 2-15H well recognized in the current period from activity in prior periods of $1,040,397 and $1,027,995, respectively.

BLACK RIDGE OIL & GAS, INC.

CONDENSED BALANCE SHEETS

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

Current assets:
Cash and cash equivalents	$	214,583		$	94,682
Derivative instruments, current		3,007,135			3,571,803
Accounts receivable		4,091,371			5,740,171
Prepaid expenses		46,351			41,387
Total current assets		7,359,440			9,448,043

Property and equipment:
Oil and natural gas properties, full cost method of accounting:
Proved properties		124,205,553			112,418,105
Unproved properties		1,258,138			591,121
Other property and equipment		139,004			139,004
Total property and equipment		125,602,695			113,148,230
Less, accumulated depreciation, amortization, depletion and allowance for impairment		(46,117,576	)		(18,902,524	)
Total property and equipment, net		79,485,119			94,245,706

Derivative instruments, long-term		2,983,784			4,007,942
Debt issuance costs, net		510,239			701,019

Total assets	$	90,338,582		$	108,402,710


LIABILITIES AND STOCKHOLDERS' EQUITY

Current liabilities:
Accounts payable	$	10,166,181		$	10,291,262
Accrued expenses		91,155			57,435
Total current liabilities		10,257,336			10,348,697

Asset retirement obligations		344,360			286,804
Revolving credit facilities and long term debt, net of discounts of $1,665,862 and $2,072,483, respectively		60,026,143			51,834,603
Deferred tax liability		–			6,593,040

Total liabilities		70,627,839			69,063,144

Commitments and contingencies		–			–

Stockholders' equity:
Preferred stock, $0.001 par value, 20,000,000 shares authorized, no shares issued and outstanding		–			–
Common stock, $0.001 par value, 500,000,000 shares authorized, 47,979,990 shares issued and outstanding		47,980			47,980
Additional paid-in capital		33,965,465			33,651,714
Retained earnings (accumulated deficit)		(14,302,702	)		5,639,872
Total stockholders' equity		19,710,743			39,339,566

Total liabilities and stockholders' equity	$	90,338,582		$	108,402,710

BLACK RIDGE OIL & GAS, INC.

CONDENSED STATEMENTS OF OPERATIONS

(Unaudited)

	For the Three Months						For the Six Months
	Ended June 30,						Ended June 30,
	2015			2014			2015			2014

Oil and gas sales	$	5,050,080		$	5,553,997		$	7,936,536		$	9,584,417
Gain (loss) on settled derivatives		847,198			(262,719	)		1,980,619			(378,882	)
Loss on the mark-to-market of derivatives		(1,956,155	)		(881,124	)		(1,588,826	)		(1,095,159	)
Total revenues		3,941,123			4,410,154			8,328,329			8,110,376

Operating expenses:
Production expenses		1,153,663			595,591			2,143,520			1,103,054
Production taxes		555,152			591,525			841,344			996,832
General and administrative		730,445			634,109			1,540,453			1,404,882
Depletion of oil and gas properties		2,937,744			2,131,545			5,567,776			3,718,477
Impairment of oil and gas properties		21,639,000			–			21,639,000			–
Accretion of discount on asset retirement obligations		7,932			5,148			15,861			9,653
Depreciation and amortization		4,009			8,188			8,276			16,113
Total operating expenses		27,027,945			3,966,106			31,756,230			7,249,011

Net operating income (loss)		(23,086,822	)		444,048			(23,427,901	)		861,365

Other income (expense):
Other income		6,707			–			6,707			–
Interest (expense)		(1,547,172	)		(1,293,123	)		(3,114,420	)		(2,376,023	)
Total other income (expense)		(1,540,465	)		(1,293,123	)		(3,107,713	)		(2,376,023	)

Loss before provision for income taxes		(24,627,287	)		(849,075	)		(26,535,614	)		(1,514,658	)

Provision for income taxes		5,957,649			305,715			6,593,040			589,738

Net loss	$	(18,669,638	)	$	(543,360	)	$	(19,942,574	)	$	(924,920	)


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

Net loss per common share - basic	$	(0.39	)	$	(0.01	)	$	(0.42	)	$	(0.02	)
Net loss per common share - fully diluted	$	(0.39	)	$	(0.01	)	$	(0.42	)	$	(0.02	)

BLACK RIDGE OIL & GAS, INC.

CONDENSED STATEMENTS OF CASH FLOWS

(Unaudited)

	For the Six Months
	Ended June 30,
	2015			2014
CASH FLOWS FROM OPERATING ACTIVITIES
Net loss	$	(19,942,574	)	$	(924,920	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion of oil and gas properties		5,567,776			3,718,477
Depreciation and amortization		8,276			16,113
Amortization of debt issuance costs		190,780			145,307
Accretion of discount on asset retirement obligations		15,861			9,653
Loss on the mark-to-market of derivatives		1,588,826			1,095,159
Accrued payment in kind interest applied to long term debt		634,919			472,712
Amortization of original issue discount on debt		84,858			60,288
Amortization of debt discounts, warrants		321,763			310,042
Common stock options issued to employees and directors		313,751			288,961
Deferred income taxes		(6,593,040	)		(589,738	)
Impairment of oil and natural gas properties		21,639,000			–
Decrease (increase) in current assets:
Accounts receivable		1,648,800			(2,835,328	)
Prepaid expenses		(4,964	)		(15,812	)
Increase (decrease) in current liabilities:
Accounts payable		36,328			203,177
Accrued expenses		33,720			58,040
Net cash provided by operating activities		5,544,080			2,012,131

CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from sale or swap of oil and gas properties		103,000			1,360,920
Purchases of oil and gas properties and development capital expenditures		(12,677,179	)		(11,731,981	)
Advances to operators		–			(3,491,089	)
Purchases of other property and equipment		–			(11,131	)
Net cash used in investing activities		(12,574,179	)		(13,873,281	)

CASH FLOWS FROM FINANCING ACTIVITIES
Advances from revolving credit facilities and long term debt		10,600,000			18,700,000
Repayments on revolving credit facilities		(3,450,000	)		(7,850,000	)
Debt issuance costs		–			(54,782	)
Net cash provided by financing activities		7,150,000			10,795,218

NET CHANGE IN CASH		119,901			(1,065,932	)
CASH AT BEGINNING OF PERIOD		94,682			1,150,347
CASH AT END OF PERIOD	$	214,583		$	84,415


SUPPLEMENTAL INFORMATION:
Interest paid	$	2,174,153		$	1,457,540
Income taxes paid	$	–		$	–

NON-CASH INVESTING AND FINANCING ACTIVITIES:
Net change in accounts payable for purchase of oil and gas properties	$	(161,409	)	$	(98,778	)
Advances to operators applied to development of oil and gas properties	$	–		$	2,131,043
Capitalized asset retirement costs, net of revision in estimate	$	41,695		$	40,712

Cautionary Statement as to Forward-Looking Statements

Certain statements contained herein, which are not historical, are forward-looking statements that are subject to risks and uncertainties not known or disclosed herein that could cause actual results to differ materially from those expressed herein. These statements may include projections and other "forward-looking statements" within the meaning of the federal securities laws. Any such projections or statements reflect management’s current views about future events and financial performance. No assurances can be given that such events or performance will occur as projected and actual results may differ materially from those projected. Important factors that could cause the actual results to differ materially from those projected include, without limitation, general economic or industry conditions nationally and/or in the communities in which our Company conducts business, volatility in commodity prices for crude oil and natural gas, environmental risks, legislation or regulatory requirements, conditions of the securities markets, our ability to raise capital or have access to debt financing, changes in accounting principles, policies or guidelines, financial or political instability, acts of war or terrorism, increases in operator costs, other economic, competitive, governmental, regulatory and technical factors affecting our Company's operations, products, services and prices and other risks inherent in the Company's businesses that are detailed in the Company's Securities and Exchange Commission ("SEC") filings. Readers are encouraged to review these risks in the Company's SEC filings.

About the Company

Black Ridge Oil & Gas is an oil and gas exploration and production company based in Minnetonka, Minnesota. Black Ridge's focus is exclusive to the Williston Basin Bakken and Three Forks trend in North Dakota and Montana. For additional information, visit the Company's website at www.blackridgeoil.com.

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Contact

Black Ridge Oil & Gas, Inc.

Ken DeCubellis, Chief Executive Officer
952-426-1241