EX-99.1 2 blackridge_8k-ex9901.htm PRESS RELEASE

Exhibit 99.1

Black Ridge Oil & Gas Announces First Quarter 2015 Results

MINNETONKA, Minn., May 14, 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 months ended March 31, 2015.

First Quarter 2015 Company Highlights

Quarterly production increased 89% over the first quarter of 2014 to 89.3 thousand barrels of oil equivalent (“MBoe”), an average of approximately 992 barrels of oil equivalent per day (“Boe/d”)

Oil and gas sales totaled $2.9 million, a decrease of 28% from the first quarter of 2014

Participated in the completion of 39 gross (0.91 net) wells, increasing our total producing well count to 286 gross (8.79 net), an increase of 60% over the first quarter of 2014

Recorded $2.1 million of adjusted EBITDA, representing a decrease of 12% from the first quarter of 2014

Reduced general and administrative expenses to $9.07 per Boe, a decrease of 44% from the first quarter of 2014

Increased full year 2015 production guidance from an average of 1,100 BOEPD to 1,200 BOEPD

Acreage and Drilling

As of March 31, 2015, the Company controlled approximately 9,400 net acres in the Williston Basin. Approximately 67% of the acreage is held by production with 286 gross (8.79 net) wells producing. Additionally, the Company had 2.2 net wells in development as of March 31, 2015.

Management Comment

Ken DeCubellis, Black Ridge’s CEO, commented, “While the commodity price environment was challenging during the first quarter of 2015, we are generally pleased with the underlying performance of our asset base. The Company was able to achieve our second highest average production on record in the first quarter despite lower than expected volume in Stockyard Creek as wells were shut in for offset completion activities. As we look forward to the balance of 2015, we are cautiously optimistic as we have seen oil prices improve by over 20%, as compared to the average in the first quarter, and we have received indications from our operating partners that drilling and completion costs will be lower than the assumptions used in our 2015 capital plan. However, we are not changing our original 2015 development plan, with the cornerstone being our 1.76 net well Teton project, which is currently scheduled to commence production during the second half of 2015. Any incremental cash flow above our original 2015 plan will be used to reduce debt and build additional liquidity.”

Teton Project Update and Production Guidance

The 23 gross well, 1.76 net well, Teton project continues development per plan. All of the wells in this project have finished the drilling phase and completions will begin in the coming weeks. Based on the Company’s current expectation for total drilling and completion costs, estimated ultimate recoveries, and the current commodity price deck, the Teton project is expected to meet or exceed our 30% IRR investment hurdle. The Company is increasing our full year production guidance from an average of 1,100 BOEPD to 1,200 BOEPD. We anticipate our production levels to be below the full year average until the Teton project is online, at which point our daily production volumes will exceed the full year average.

DeCubellis added, “The Company has taken some risk to participate in the Teton project during this phase of the commodity price cycle. We are excited about the current pace of the project’s development, our current view of the overall economics of the project, and most importantly, the significant improvement that the project will bring to the Company’s balance sheet once in full production. As such, we have recently taken the opportunity to hedge additional volume from October 2015 through June 2016.”

Liquidity Position and Borrowing Base

Black Ridge ended the quarter with $25.95 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 first quarter of 2015, the Company realized a $1,133,421 gain on settled derivatives and a $367,329 unrealized gain on mark-to-market adjustments to its outstanding derivatives contracts. As of March 31, 2015, the Company’s net derivative asset was $7,947,074. On May 11, 2015, the Company entered into new swap contracts for 36,000 barrels in Q4 2015 at $61.87 and 45,000 barrels in 1H 2016 at $62.88. The following table summarizes the Company’s open crude oil swap contracts as of May 12, 2015:

	Oil	Weighted Average
Term	(barrels)	Price ($ per Bbl)
2015:
Q2	21,750	89.84
Q3	21,750	89.84
Q4	57,750	72.40
2016:
Q1	43,500	75.84
Q2	43,500	75.84
Q3	21,000	89.73
Q4	21,000	89.73
2017:
Q1	19,500	87.18
Q2	19,500	87.18
Q3	19,500	87.18
Q4	19,500	87.18

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 May 12, 2015:

	Oil	Floor/Ceiling
Term	(Barrels)	Price (WTI)	Basis
*Costless Collars – Crude Oil*
04/01/2015 – 12/31/2015	27,000	$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
	March 31,
	2015		2014			% Change
Net Production:
Oil (Bbl)		72,922		43,155			69
Natural gas (Mcf)		98,314		24,337			304
Barrel of oil equivalent (Boe)		89,308		47,211			89
Average daily production (Boe/d)		992		525			89

Average Sales Prices:
Oil (per Bbl)	$	37.60	$	87.99			(57	)
Effect of oil hedges on average price (per Bbl)	$	15.55	$	(2.69	)
Oil net of hedging (per Bbl)	$	53.15	$	85.30			(38	)
Natural gas (per Mcf)	$	1.47	$	9.58			(85	)
Effect of natural gas hedges on average price (per Mcf)	$	–	$	–
Natural gas net of hedging (per Mcf)	$	1.47	$	9.58			(85	)

Per Boe including settled derivatives	$	45.01	$	82.91			(46	)

Operating Expenses (per Boe):
Production expenses	$	11.08	$	10.75			3
Production taxes	$	3.20	$	8.59			(63	)
G&A expense	$	9.07	$	16.33			(44	)
Depletion, depreciation, amortization and accretion	$	29.59	$	33.88			(13	)

First Quarter 2015 Financial Results

In the first quarter of 2015, oil and gas sales, excluding the impact of settled derivatives, were $2.89 million, a decrease of 28% as compared to the first quarter of 2014. The Company realized an average price of $37.60 per barrel of oil and $1.47 per mcf of gas, representing decreases of 57% and 85%, respectively, as compared to the first quarter of 2014. The impact of weaker commodity prices was partially offset by an 89% increase in production over the first quarter of 2014.

The Company’s production in the first quarter of 2015 was comprised of 82% oil and 18% natural gas and natural gas liquids, on a Boe basis. The Company’s increased gas sales percentage reflects the continued improvement in gas infrastructure in North Dakota and higher gas production in the Company’s current areas of focus.

Lease operating expenses for the first quarter of 2015 were $1.0 million, or $11.08 per Boe, compared to $0.5 million, or $10.75 per Boe, for the first quarter of 2014. The increase in lease operating expense in the first quarter was primarily attributable to cleanout costs on producing wells subsequent to completion activities on offset locations in the Company’s Stockyard Creek project.

General and administrative expenses (“G&A”) for the first quarter of 2015 were $0.8 million, or $9.07 per Boe, compared to $0.8 million, or $16.33 per Boe for the first quarter of 2014. Cash G&A (non-GAAP, excludes stock-based compensation expense) was $0.6 million, or $7.27 per Boe, for the first quarter of 2015 compared to $0.6 million, or $13.27 per Boe for the first quarter of 2014.

The Company recorded $2.1 million of adjusted EBITDA in the first quarter of 2015, representing a decrease of 12% from $2.4 million of adjusted EBITDA in the first 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.

Producing Wells

The following table sets forth wells in which Black Ridge holds a participating interest that were completed or acquired during the quarter ending March 31, 2015:

*Well*	*Operator*	*Location*	*WI⁽¹⁾*
Bootleg 6-14-15TFH	Slawson	Williams, ND	11.4%
Bootleg 7-14-15TFH	Slawson	Williams, ND	11.3%
Bootleg 8-14-15TF2H	Slawson	Williams, ND	11.3%
Billabong 2-13-14HBK	Slawson	Williams, ND	7.5%
Ironbank 4-14-13TFH	Slawson	Williams, ND	5.5%
Ironbank 7-14-13TFH	Slawson	Williams, ND	5.4%
Ironbank 6-14-13TFH	Slawson	Williams, ND	5.4%
EN-VP AND R- ###-##-####H-1	Hess	Mountrail, ND	3.1%
EN-VP AND R- ###-##-####H-2	Hess	Mountrail, ND	3.1%
EN-VP AND R- ###-##-####H-3	Hess	Mountrail, ND	3.1%
EN-VP AND R- ###-##-####H-4	Hess	Mountrail, ND	3.1%
Duletski Federal 14-12PH	Whiting	Billings, ND	0.8%
CCU Main Streeter 24-24TFH	Burlington Resources	Dunn, ND	0.8%
CCU North Coast 41-25MBH	Burlington Resources	Dunn, ND	0.8%
CCU North Coast 4-8-23TFH	Burlington Resources	Dunn, ND	0.8%
CCU North Coast 4-8-23MBH	Burlington Resources	Dunn, ND	0.8%
CCU North Coast 31-25MBH	Burlington Resources	Dunn, ND	0.8%
CCU North Coast 41-25TFH	Burlington Resources	Dunn, ND	0.8%
CCU Pullman 1-8-7TFH	Burlington Resources	Dunn, ND	0.8%
CCU Pullman 2-8-7MBH	Burlington Resources	Dunn, ND	0.8%
CCU Pullman 3-8-7TFH	Burlington Resources	Dunn, ND	0.8%
CCU Pullman 3-8-7MBH	Burlington Resources	Dunn, ND	0.8%
CCU Pullman 5-8-7TFH	Burlington Resources	Dunn, ND	0.8%
CCU Pullman 5-8-7MBH	Burlington Resources	Dunn, ND	0.8%
CCU Pullman 6-8-7TFH	Burlington Resources	Dunn, ND	0.8%
CCU Pullman 6-8-7MBH	Burlington Resources	Dunn, ND	0.8%
CCU Pullman 8-8-7TFH	Burlington Resources	Dunn, ND	0.8%
CCU Pullman 7-8-7MBH	Burlington Resources	Dunn, ND	0.8%
CCU Pullman 7-8-7TFH	Burlington Resources	Dunn, ND	0.8%
CCU Golden Creek 44-23TFH	Burlington Resources	Dunn, ND	0.8%
CCU Golden Creek 44-23MBH	Burlington Resources	Dunn, ND	0.8%
CCU Main Streeter 14-24MBH	Burlington Resources	Dunn, ND	0.8%
Oakdale 2-13H1	Continental	Dunn, ND	0.6%
Ryden 3-24H	Continental	Dunn, ND	0.6%
Ryden 2-24AH1	Continental	Dunn, ND	0.6%
Oakdale 5-13H	Continental	Dunn, ND	0.6%
Oakdale 3-13H	Continental	Dunn, ND	0.6%
Oakdale 4-13H1	Continental	Dunn, ND	0.6%
Ryden 4-24H1	Continental	Dunn, ND	0.6%

⁽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 March 31, 2015:

*Well*	*Operator*	*Location*	*WI⁽¹⁾*
Rainbow 10-19-18HBK	Samson Oil and Gas	Williams, ND	10.0%
Kings Canyon 5-8-34UTF	Burlington Resources	McKenzie, ND	8.4%
Teton 5-8-10MBH	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%
Kings Canyon 4-1-27MTFH	Burlington Resources	McKenzie, ND	8.4%
Teton 5-1-3TFSH	Burlington Resources	McKenzie, ND	8.4%
Teton 3-8-10MBH	Burlington Resources	McKenzie, ND	8.4%
Teton 2-8-10MBH	Burlington Resources	McKenzie, ND	8.4%
Teton 6-8-10TFSH	Burlington Resources	McKenzie, ND	8.4%
Teton 6-8-10MBH	Burlington Resources	McKenzie, ND	8.4%
Kings Canyon 6-1-27MBH	Burlington Resources	McKenzie, ND	8.4%
Teton 8-8-10TFSH	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%
Kings Canyon 6-8-34UTFH	Burlington Resources	McKenzie, ND	8.4%
Teton 7-8-10MBH	Burlington Resources	McKenzie, ND	8.4%
Kings Canyon 6-1-27MTFH	Burlington Resources	McKenzie, ND	8.4%
Kings Canyon 3-1-27MTFH	Burlington Resources	McKenzie, ND	8.4%
Tetonorman 1-1-3UTFH ULW	Burlington Resources	McKenzie, ND	6.3%
Remingteton 8-8-10MBH	Burlington Resources	McKenzie, ND	6.2%
Thorp Federal 11X-28A	XTO	Dunn, ND	3.4%
DeKing 1-8-34MBH-ULW	Burlington Resources	McKenzie, ND	2.1%
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 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%
P Berger 156-100-14-7-6-4H	Kodiak	Williams, ND	1.0%
P Berger 156-100-14-7-6-3H	Kodiak	Williams, ND	1.0%
Gobbler 6-35-26TFH	Slawson	Mountrail, ND	0.8%
Aaberg 8-5N-1H	Mountain Divide	Divide, ND	0.8%
CCU Dakotan 3-8-17MBH	Burlington Resources	Dunn, ND	0.8%
CCU Powell 41-29TFH	Burlington Resources	Dunn, ND	0.8%
CCU North Coast 31-25TFH	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 Red River 7-2-15TFH	Burlington Resources	Dunn, ND	0.8%
CCU Red River 8-2-15MBH	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%
Jersey 1-6H	Continental	Mountrail, ND	0.8%
Jersey 5-6H	Continental	Mountrail, ND	0.8%
Jersey 3-6H1	Continental	Mountrail, ND	0.8%
Jersey 2-6H2	Continental	Mountrail, ND	0.8%
P Johnson 153-98-1-6-7-16H	Kodiak	Williams, ND	0.6%
P Johnson 153-98-1-6-7-16HA	Kodiak	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 net income (loss) on the mark-to-market of derivatives, net of tax. We define Adjusted EBITDA as earnings (loss) before (i) interest expense, (ii) income taxes, (iii) depreciation, depletion and amortization, (iv) accretion of abandonment liability, (v) income (losses) on the mark-to-market of derivatives, and (vi) non-cash expenses relating to share based payments recognized under ASC Topic 718. We believe the use of non-GAAP financial measures provides useful information to investors regarding our current financial performance; however, Adjusted Net 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
	March 31,
	2015			2014
Net loss	$	(1,272,936	)	$	(381,560	)
Add back:
Losses (gains) on the mark-to-market of derivatives, net of tax ^(a)		(246,239	)		134,835
Adjusted net loss	$	(1,519,175	)	$	(246,725	)

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

Net loss per common share - basic	$	(0.03	)	$	(0.01	)
Add:
Change due to losses (gains) on the mark-to-market of derivatives, net of tax		–			–
Adjusted net loss per common share - basic	$	(0.03	)	$	(0.01	)

Net income (loss) per common share - fully diluted		(0.03	)	$	(0.01	)
Add:
Change due to losses (gains) on the mark-to-market of derivatives, net of tax		–			–
Adjusted net loss per common share - fully diluted	$	(0.03	)	$	(0.01	)

^(a)Adjusted to reflect tax benefit (expense), computed based on our effective tax rate of approximately 33% in 2015 and 37% in 2014, of ($121,000) and $79,200 for the three months ended March 31, 2015 and 2014, respectively.

Reconciliation of Net Loss to Adjusted EBITDA

	Three Months Ended
	March 31,
	2015			2014
Net loss	$	(1,272,936	)	$	(381,560	)
Add back:
Interest expense, net, excluding amortization of warrant based financing costs		1,406,820			929,378
Income tax provision		(635,391	)		(284,023	)
Depreciation, depletion, and amortization		2,634,299			1,594,857
Accretion of abandonment liability		7,929			4,505
Share based compensation		321,352			297,762
Unrealized gain (loss) on the mark-to-market of derivatives		(367,328	)		214,035

Adjusted EBITDA	$	2,094,745		$	2,374,954

BLACK RIDGE OIL & GAS, INC.

CONDENSED BALANCE SHEETS

	March 31,			December 31,
	2015			2014
	(Unaudited)
ASSETS

Current assets:
Cash and cash equivalents	$	97,781		$	94,682
Derivative instruments		3,863,912			3,571,803
Accounts receivable		3,420,230			5,740,171
Prepaid expenses		38,243			41,387
Total current assets		7,420,166			9,448,043

Property and equipment:
Oil and natural gas properties, full cost method of accounting
Proved properties		118,421,670			112,418,105
Unproved properties		2,168,117			591,121
Other property and equipment		139,004			139,004
Total property and equipment		120,728,791			113,148,230
Less, accumulated depreciation, amortization, depletion and allowance for impairment		(21,536,823	)		(18,902,524	)
Total property and equipment, net		99,191,968			94,245,706

Derivative instruments		4,083,162			4,007,942
Debt issuance costs, net		604,697			701,019

Total assets	$	111,299,993		$	108,402,710


LIABILITIES AND STOCKHOLDERS' EQUITY

Current liabilities:
Accounts payable	$	11,014,273		$	10,291,262
Accrued expenses		68,416			57,435
Total current liabilities		11,082,689			10,348,697

Asset retirement obligations		330,557			286,804
Revolving credit facility and long term debt, net of discounts of $1,869,656 and $2,072,483, respectively		55,701,544			51,834,603
Deferred tax liability		5,957,649			6,593,040

Total liabilities		73,072,439			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		33,812,638			33,651,714
Retained earnings		4,366,936			5,639,872
Total stockholders' equity		38,227,554			39,339,566

Total liabilities and stockholders' equity	$	111,299,993		$	108,402,710

BLACK RIDGE OIL & GAS, INC.

CONDENSED STATEMENTS OF OPERATIONS

(Unaudited)

	For the Three Months
	Ended March 31,
	2015			2014
Oil and gas sales	$	2,886,456		$	4,030,420
Gain (loss) on settled derivatives		1,133,421			(116,163	)
Gain (loss) on the mark-to-market of derivatives		367,329			(214,035	)
Total revenues	$	4,387,206		$	3,700,222

Operating expenses:
Production expenses		989,857			507,463
Production taxes		286,192			405,307
General and administrative		810,008			770,773
Depletion of oil and gas properties		2,630,032			1,586,932
Accretion of discount on asset retirement obligations		7,929			4,505
Depreciation and amortization		4,267			7,925
Total operating expenses		4,728,285			3,282,905

Net operating income (loss)		(341,079	)		417,317

Other income (expense):
Interest (expense)		(1,567,248	)		(1,082,900	)
Total other income (expense)		(1,567,248	)		(1,082,900	)

Loss before provision for income taxes		(1,908,327	)		(665,583	)

Provision for income taxes		635,391			284,023

Net loss	$	(1,272,936	)	$	(381,560	)


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

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

BLACK RIDGE OIL & GAS, INC.

CONDENSED STATEMENTS OF CASH FLOWS

(Unaudited)

	For the Three Months
	Ended March 31,
	2015			2014
CASH FLOWS FROM OPERATING ACTIVITIES
Net loss	$	(1,272,936	)	$	(381,560	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depletion of oil and gas properties		2,630,032			1,586,932
Depreciation and amortization		4,267			7,925
Amortization of debt issuance costs		96,322			70,653
Accretion of discount on asset retirement obligations		7,929			4,505
(Gain) loss on the mark-to-market of derivatives		(367,329	)		214,035
Accrued payment in kind interest applied to long term debt		314,114			208,803
Amortization of original issue discount on debt		42,399			26,316
Amortization of debt discounts, warrants		160,428			153,522
Common stock options issued to employees and directors		160,924			144,240
Deferred income taxes		(635,391	)		(284,023	)
Decrease (increase) in current assets:
Accounts receivable		2,319,941			(1,160,467	)
Prepaid expenses		3,144			(8,444	)
Increase (decrease) in current liabilities:
Accounts payable		110,460			252,259
Accrued expenses		10,981			42,271
Net cash provided by operating activities		3,585,285			876,967

CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from sale of oil and gas properties		99,000			1,234,740
Purchases of oil and gas properties and development capital expenditures		(7,031,186	)		(7,582,458	)
Advances to operators		–			(1,410,896	)
Purchases of other property and equipment		–			(8,094	)
Net cash used in investing activities		(6,932,186	)		(7,766,708	)

CASH FLOWS FROM FINANCING ACTIVITIES
Advances from revolving credit facilities and long term debt		5,700,000			9,350,000
Repayments on revolving credit facilities		(2,350,000	)		(3,550,000	)
Net cash provided by financing activities		3,350,000			5,800,000

NET CHANGE IN CASH		3,099			(1,089,741	)
CASH AT BEGINNING OF PERIOD		94,682			1,150,347
CASH AT END OF PERIOD	$	97,781		$	60,606


SUPPLEMENTAL INFORMATION:
Interest paid	$	1,110,083		$	640,978
Income taxes paid	$	–		$	–

NON-CASH INVESTING AND FINANCING ACTIVITIES:
Net change in accounts payable for purchase of oil and gas properties	$	612,551		$	(846,354	)
Advances to operators applied to purchase of oil and gas properties	$	–		$	321,904
Capitalized asset retirement costs, net of revision in estimate	$	35,824		$	23,259

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.

Make sure you are first to receive timely information on Black Ridge Oil & Gas when it hits the newswire. Sign up for Black Ridge's email news alert system today at http://ir.stockpr.com/blackridgeoil/email-alerts

Contact

Black Ridge Oil & Gas, Inc.

Ken DeCubellis, Chief Executive Officer
952-426-1241