EX-99.1 2 brog_8k-ex9901.htm PRESS RELEASE

Exhibit 99.1

Black Ridge Oil & Gas Announces Third Quarter 2014 Results

and Issues Fourth Quarter 2014 Average Production Guidance

of 950 to 1,100 Boe per day

MINNETONKA, MN – November 12, 2014 – Black Ridge Oil & Gas, Inc. (“the Company”) (OTCQB: ANFC), a growth-oriented exploration and production (E&P) company focused on non-operated Bakken and Three Forks properties, today announced financial and operating results for the quarter ended September 30, 2014.

Third Quarter 2014 Highlights

Record quarterly production averaged 761 barrels of oil equivalent per day (“Boe/d”), representing 147% year over year and 6% sequential quarter over quarter growth

Participated in the development and start-up of five gross (0.62 net) Mandaree wells in EOG’s Antelope Extension prospect

Drilling activity commenced on the Company’s 22 gross well (1.37 net) Teton project, production expected in mid-2015

Increased borrowing base on senior-secured credit facility from $20 million to $35 million. The facility carries interest rates of LIBOR + 3% to LIBOR + 3.50%. Availability as of September 30, 2014 was $17.25 million

As of September 30, 2014, the Company was participating in an additional 65 gross (1.61 net) wells that were preparing to drill, drilling, awaiting completion or completing

Fourth Quarter 2014 Guidance

The Company anticipates fourth quarter 2014 average production between 950 to 1,100 Boe/d

Black Ridge has 45,000 barrels of oil hedged for the fourth quarter at an average price of $94.49

As of October 31, 2014, the Company was participating in an additional 86 gross (2.48 net) wells that were preparing to drill, drilling, awaiting completion or completing

Management Comment

“The third quarter of 2014 was another excellent quarter for the Company. Despite planned shut-ins for additional well completions in the Stockyard Creek prospect, we were still able to achieve a production record.” commented Black Ridge’s Chief Executive Officer Ken DeCubellis. “As we look to the remainder of 2014 and into 2015, the five gross (0.62 net) well Mandaree prospect in EOG’s prolific Antelope area of McKenzie County began producing at the tail end of the third quarter of 2014 and will be the main driver for growth in the fourth quarter. We expect fourth quarter production to average between 950 and 1,100 Boe/d net to the Company. In this environment of lower oil prices the Company is maintaining a disciplined, return driven approach to investments. Our Mandaree and Teton projects are expected to exceed our hurdle rate of 30% IRR at current oil prices.”

Mandaree Update

The following table summarizes initial results in the Mandaree Project operated by EOG Resources, Inc. The Company has a 12.5% working interest in each well:

Well Name	Bench/Target Formation	Initial Production Rate
Mandaree 17-05H	Three Forks – 1^st Bench	2,212 Boe/d
Mandaree 135-05H	Three Forks – 2^nd Bench	2,037 Boe/d
Mandaree 134-05H	Three Forks – 3^rd Bench	1,777 Boe/d
Mandaree 28-05H	Middle Bakken	Confidential
Mandaree 110-05H	Middle Bakken	Confidential

Third Quarter 2014 Operating and Financial Results

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

	Three Months Ended
	September 30,
	2014			2013			% Change
Net Production:
Oil (Bbl)		62,603			26,427			137
Natural Gas (Mcf)		44,639			11,535			287
Barrel of Oil Equivalent (Boe)		70,043			28,349			147
Average Daily Production (Boe/d)		761			308			147

Average Sales Prices:
Oil (per Bbl)	$	84.17		$	96.07			(12	)
Effect of oil hedges on average price (per Bbl)	$	(1.12	)	$	(0.80	)
Oil net of hedging (per Bbl)	$	83.05		$	95.27			(13	)
Natural Gas (per Mcf)	$	4.99		$	6.41			(22	)
Effect of natural gas hedges on average price (per Mcf)	$	–		$	–
Natural gas net of hedging (per Mcf)	$	4.99		$	6.41			(22	)

Per Boe including settled derivatives	$	77.41		$	91.41			(15	)

Operating Expenses (per Boe):
Production Expenses	$	9.57		$	9.69			(1	)
Production Taxes	$	8.41		$	9.56			(12	)
G&A Expense	$	9.85		$	18.51			(47	)
Depletion, Depreciation, Amortization and Accretion	$	32.69		$	37.83			(14	)

Third Quarter 2014 Operational Results

Production for the third quarter of 2014 totaled 70 thousand barrels of oil equivalent (“MBoe”), averaging a record 761 Boe/d, representing 147% growth over the third quarter of 2013 and 6% growth over the second quarter of 2014 on a Boe/d basis. Production growth in the quarter was limited by shut-ins for offset completions in the Stockyard Creek prospect.

Throughout the third quarter of 2014, the Company participated in the completion of 24 gross (1.08 net) wells compared to 11 gross (0.40 net) wells in the third quarter of 2013. Well additions were driven primarily by the completion of the five gross (0.62 net) Mandaree wells in the final days of the quarter.

As of September 30, 2014, the Company had participated in a total of 231 gross (7.36 net) producing wells compared to 92 gross (3.22 net) producing wells in the third quarter of 2013, representing an increase of 129% on a net well basis.

In addition to the 7.36 net producing wells, the Company owned working interests in 65 gross (1.61 net) wells that were preparing to drill, drilling, awaiting completion, or completing as of September 30, 2014.

The Company controlled approximately 10,000 net mineral acres prospective for the Bakken and Three Forks formations in North Dakota and eastern Montana as of September 30, 2014.

Third Quarter 2014 Financial Results

Oil and gas sales, which exclude the effect of derivatives, totaled $5.5 million for the third quarter of 2014, representing 110% growth over the third quarter of 2013 and a 1% decline from the second quarter of 2014. The decline from the second quarter of 2014 was driven primarily by lower average realized oil prices.

For the third quarter of 2014, the Company realized a loss on settled derivatives of $0.1 million. The Company realized a non-cash mark-to-market gain on unsettled derivatives of $2.1 million.

For the third quarter of 2014, the Company’s realized oil price was $84.17 per barrel of oil before the effect of settled derivatives. The Company’s realized price was 14% per barrel below the NYMEX WTI benchmark in the third quarter of 2014. For the third quarter of 2014, the Company’s realized price for natural gas, including natural gas liquids, was $4.99 per MCF, representing a 22% decrease compared to $6.41 per MCF in the third quarter of 2013. The realized price on a per BOE basis, including settled derivatives, was $77.41, a decrease of 15% compared to the third quarter of 2013 and a decrease of 5% compared to the second quarter of 2014.

Production expenses increased to $670 thousand in the third quarter of 2014 compared to $275 thousand in the third quarter of 2013, driven primarily by the Company’s production growth. On a per unit basis, this equated to a 1% decrease in production expenses to $9.57/Boe in the third quarter of 2014 from $9.69/Boe in the third quarter of 2013.

Production taxes increased to $589 thousand in the third quarter of 2014 from $271 thousand in the third quarter of 2013, driven primarily by increased production. For the third quarter of 2014, production taxes averaged 10.7% of oil and gas sales compared to 10.4% for the third quarter of 2013.

General and administrative (“G&A”) expenses increased to $690 thousand for the third quarter of 2014 from $525 thousand for the third quarter of 2013. On a per Boe basis, G&A expenses averaged $9.85/Boe for the third quarter of 2014, representing a 47% decrease from $18.51/Boe in the third quarter of 2013 and an increase of 1% from $9.75/Boe in the second quarter of 2014.

Depletion, depreciation, amortization, and accretion (“DD&A”) totaled $2.3 million in the third quarter of 2014, an increase of 113% as compared to $1.1 million in the third quarter of 2013. Depletion expense, the largest component of DD&A, was $32.49/Boe in the third quarter of 2014, representing a decrease of 14% as compared to $37.56/Boe in the third quarter of 2013.

Interest expense in the third quarter of 2014 totaled $1.4 million as compared to $0.7 million in the third quarter of 2013. The increase was primarily driven by increased borrowings as the Company financed acquisitions and well development.

Income tax expense in the third quarter of 2014 was $0.7 million as compared to an income tax benefit of $0.1 million in the same period in 2013.

The Company reported net income attributable to common stockholders of $1.2 million, or $0.02 per basic and diluted common share for the third quarter of 2014 as compared to a net loss of $0.2 million, or ($0.00) per basic and diluted common share for the third quarter of 2013.

The Company recorded adjusted EBITDA of $3.6 million in the third quarter of 2014, an increase of 114% compared to adjusted EBITDA of $1.7 million in the third quarter of 2013 and equaling our record $3.6 million in 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.

Liquidity Position

The Company ended the third quarter of 2014 with $47.8 million drawn on its Senior and Subordinate Credit Facilities. As of September 30, 2014, total availability under the two facilities was $65 million following the redetermination of the Senior Credit Facility borrowing base from $20 million to $35 million in August. The Company expects the next redetermination of the Senior Credit Facility borrowing base in April 2015. The Company expects to fund future development through operating cash flow and additional borrowings from the existing credit facilities.

Hedging Update

The following table summarizes our derivative contracts as of September 30, 2014, by fiscal quarter:

	Swaps				Costless Collars
Contract period	Volume (Bbls)		Weighted Average Price (per Bbl)		Volume (Bbls)		Weighted Average Floor/Ceiling Price (per Bbl)
2014:
Q4		45,000	$	94.49		–	-
2015:
Q1		21,750	$	89.84		9,000	$75.00 – $95.60
Q2		21,750	$	89.84		9,000	$75.00 – $95.60
Q3		21,750	$	89.84		9,000	$75.00 – $95.60
Q4		21,750	$	89.84		9,000	$75.00 – $95.60
2016:
Q1		21,000	$	89.73		5,001	$80.00 – $89.50
Q2		21,000	$	89.73		5,001	$80.00 – $89.50
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		–	-

Well Update:

Producing Wells: The following table sets forth Bakken and Three Forks wells in which Black Ridge holds a participating interest that were completed or acquired during the quarter ending September 30, 2014.

*Well*	*Operator*	*Location*	*WI⁽¹⁾*
Mandaree 110-05H	EOG	McKenzie, ND	12.5%
Mandaree 134-05H	EOG	McKenzie, ND	12.5%
Mandaree 135-05H	EOG	McKenzie, ND	12.5%
Mandaree 17-05H	EOG	McKenzie, ND	12.5%
Mandaree 28-05H	EOG	McKenzie, ND	12.5%
Bootleg 4-14-15TFH	Slawson	Williams, ND	11.4%
Bootleg 5-14-15TFH	Slawson	Williams, ND	11.4%
Wallace 1-6H	Continental	Williams, ND	8.5%
Gladys 1-20H	Continental	Williams, ND	2.0%
Miller 157-101-12D-1-3H	Halcon	Williams, ND	1.1%
Miller 157-101-12D-1-4H	Halcon	Williams, ND	1.1%
CCU Corral Creek 11-28MBH	Burlington Resources	Dunn, ND	0.8%
CCU Corral Creek 21-28TFH	Burlington Resources	Dunn, ND	0.8%
CCU Corral Creek 31-28MBH	Burlington Resources	Dunn, ND	0.8%
CCU Corral Creek 31-28TFH	Burlington Resources	Dunn, ND	0.8%
CCU Four Aces 24-21MBH	Burlington Resources	Dunn, ND	0.8%
CCU Four Aces 24-21TFH	Burlington Resources	Dunn, ND	0.8%
CCU Four Aces 34-21MBH	Burlington Resources	Dunn, ND	0.8%
CCU Four Aces 34-21TFH	Burlington Resources	Dunn, ND	0.8%
CCU Olympian 11-2MBH	Burlington Resources	Dunn, ND	0.8%
CCU Olympian 21-2TFH	Burlington Resources	Dunn, ND	0.8%
CCU Olympian 44-35MBH	Burlington Resources	Dunn, ND	0.8%
CCU Olympian 44-35TFH	Burlington Resources	Dunn, ND	0.8%
Bock Federal 44-7PH	Whiting	Stark, 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 Bakken and Three Forks wells in which Black Ridge holds a participating interest that are either preparing to drill, drilling, awaiting completion or completing as of September 30, 2014.

*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%
Matilda Bay 1-15H	Slawson	Williams, ND	10.0%
Rainbow 10-19-18HBK	Samson Oil and Gas	Williams, ND	10.0%
Billabong 2-13-14HBK	Slawson	Williams, ND	7.5%
McCracken 2758 21-10 5B	Oasis	Roosevelt, MT	7.1%
McCracken 2758 44-9 4B	Oasis	Roosevelt, MT	7.1%
McCracken 2758 34-9 3B	Oasis	Roosevelt, MT	7.1%
McCracken 2758 41-10 6B	Oasis	Roosevelt, MT	7.1%
Teton 5-1-3TFSH	Burlington Resources	McKenzie, ND	6.2%
Kings Canyon 6-8-34UTFH	Burlington Resources	McKenzie, ND	6.2%
Ironbank 4-14-13TFH	Slawson	Williams, ND	5.4%
Ironbank 5-14-13TFH	Slawson	Williams, ND	5.4%
Ironbank 6-14-13TFH	Slawson	Williams, ND	5.4%
Ironbank 7-14-13TFH	Slawson	Williams, ND	5.4%
Revolver 7-35H	Slawson	Mountrail, ND	1.6%
Little Muddy 10TFH	Triangle	Williams, ND	0.9%
CCU Powell 41-29TFH	Burlington Resources	Dunn, ND	0.8%
CCU Olympian 11-2TFH	Burlington Resources	Dunn, ND	0.8%
CCU Pullman 2-8-7MBH	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%
Jersey 23-6H1	Continental	Mountrail, ND	0.8%
Jersey 25-6H	Continental	Mountrail, ND	0.8%
Jersey 26-6H2	Continental	Mountrail, ND	0.8%
Jersey 27-6H1	Continental	Mountrail, ND	0.8%
Jersey 28-6H3	Continental	Mountrail, ND	0.8%
Jersey 29-6XH	Continental	Mountrail, ND	0.8%
CCU Powell 41-29MBH	Burlington Resources	Dunn, ND	0.8%
CCU Pullman 6-8-7MBH	Burlington Resources	Dunn, ND	0.8%
CCU Pullman 1-8-7TFH	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 7-8-7TFH	Burlington Resources	Dunn, ND	0.8%
CCU Golden Creek 44-23MBH	Burlington Resources	Dunn, ND	0.8%

“Drilling” Wells (Continued):

*Well*	*Operator*	*Location*	*WI(1)*
Jersey 1-6H	Continental	Mountrail, ND	0.8%
Jersey 3-6H1	Continental	Mountrail, ND	0.8%
Jersey 7-6H1	Continental	Mountrail, ND	0.8%
Jersey 6-6H2	Continental	Mountrail, ND	0.8%
Jersey 24-6H3	Continental	Mountrail, ND	0.8%
Aaberg 8-5N-1H	Mountain Divide	Divide, ND	0.8%
CCU North Coast 21-25TFH	Burlington Resources	Dunn, ND	0.8%
CCU North Coast 31-25MBH	Burlington Resources	Dunn, ND	0.8%
CCU North Coast 4-8-23MBH	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 Golden Creek 44-23TFH	Burlington Resources	Dunn, ND	0.8%
CCU North Coast 41-25TFH	Burlington Resources	Dunn, ND	0.8%
CCU Main Streeter 24-24TFH	Burlington Resources	Dunn, ND	0.8%
CCU Main Streeter 14-24MBH	Burlington Resources	Dunn, ND	0.8%
Jersey 2-6H2	Continental	Mountrail, ND	0.8%
Jersey 8-6H3	Continental	Mountrail, ND	0.8%
Jersey 5-6H	Continental	Mountrail, ND	0.8%
Jersey 4-6H3	Continental	Mountrail, 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)

Non-GAAP Financial Measures

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

Black Ridge Oil & Gas, Inc.

Reconciliation of Adjusted Net Income (Loss)

(Unaudited)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2014			2013			2014			2013
Net Income (Loss)	$	1,190,716		$	(223,664	)	$	265,796		$	(207,151	)
Add back:
Loss (gain) on mark-to-market of derivatives, net of tax ^(a)		(1,352,798	)		29,225			(663,639	)		29,225
Adjusted Net Income (Loss)	$	(162,082	)	$	(194,439	)	$	(397,843	)	$	(177,926	)

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		49,588,039			47,979,990			49,824,437			47,979,990

Net income (loss) per common share – basic	$	0.02		$	(0.00	)	$	0.01		$	(0.00	)
Subtract:
Change due to loss (gain) on mark-to- market of derivatives, net of tax		(0.03	)		0.00			(0.01	)		0.00
Adjusted Net Income (loss) per common share - basic	$	(0.00	)	$	(0.00	)	$	(0.01	)	$	(0.00	)

Net income (loss) per common share - fully diluted		0.02			(0.00	)		0.01		$	0.00
Subtract:
Change due to loss (gain) on mark-to- market of derivatives, net of tax		(0.03	)		0.00			(0.01	)		0.00
Adjusted Net Income (Loss) per common share - fully diluted	$	(0.00	)	$	(0.00	)	$	(0.01	)	$	(0.00	)

_____________________________

^(a)Adjusted to reflect tax expense (benefit), computed based on our effective tax rate of approximately 37%, of $795,000 and $(17,000) for the three months ended September 30, 2014 and 2013, respectively, and $389,000 and ($17,000) for the nine months ended September 30, 2014 and 2013, respectively.

Black Ridge Oil & Gas, Inc.

Reconciliation of Adjusted EBITDA

(Unaudited)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2014			2013			2014			2013
Net Income (loss)	$	1,190,716		$	(223,664	)	$	265,796		$	(207,151	)
Add Back:
Interest Expense, net, excluding amortization
of warrant based financing costs		1,280,674			622,842			3,346,655			1,365,898
Income Tax Provision		700,587			(88,708	)		110,849			(615,409	)
Depreciation, Depletion, and Amortization		2,283,917			1,070,753			6,018,507			2,650,763
Accretion of Abandonment Liability		5,833			1,811			15,486			4,774
Share Based Compensation		302,961			263,379			901,964			658,977
Loss (gain) on mark-to market of derivatives		(2,147,798	)		46,225			(1,052,639	)		46,225

Adjusted EBITDA	$	3,616,890		$	1,692,638		$	9,606,618		$	3,904,077

Financial and Statistical Data Tables

Following are the financial highlights for the comparative three and nine month periods ended September 30, 2014 and 2013. The following information is based on GAAP reported earnings, with additional required disclosures included in the Company's Form 10-Q:

BLACK RIDGE OIL & GAS, INC.

CONDENSED BALANCE SHEETS

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

Current assets:
Cash and cash equivalents	$	28,239		$	1,150,347
Derivative instruments		287,421			–
Accounts receivable		3,139,049			1,905,467
Advances to operators		2,656,697			1,214,662
Prepaid expenses		72,058			26,142
Total current assets		6,183,464			4,296,618

Property and equipment:
Oil and natural gas properties, full cost method of accounting:
Proved properties		104,227,772			79,361,432
Unproved properties		2,151,044			2,798,795
Other property and equipment		126,613			115,482
Total property and equipment		106,505,429			82,275,709
Less, accumulated depreciation, amortization, depletion and allowance for impairment		(15,531,941	)		(9,513,434	)
Total property and equipment, net		90,973,488			72,762,275

Derivative instruments		551,542			–
Debt issuance costs, net		797,341			772,883

Total assets	$	98,505,835		$	77,831,776

LIABILITIES AND STOCKHOLDERS' EQUITY

Current liabilities:
Accounts payable	$	12,484,201		$	8,453,709
Accrued expenses		66,236			4,813
Current portion of derivative instruments		–			139,065
Total current liabilities		12,550,437			8,597,587

Derivative instruments		–			74,611
Asset retirement obligations		237,966			160,665
Revolving credit facilities and long term debt, net of discounts of $2,274,346 and $2,645,582, respectively		46,464,881			30,556,301
Deferred tax liability		4,144,694			4,033,845

Total liabilities		63,397,978			43,423,009

Commitments and contingencies (See note 15)		–			–

Stockholders' equity:
Preferred stock, $0.001 par value, 20,000,000 shares authorized, no shares issued and outstanding		–			–
Common stock, $0.001 par value, 500,000,000 shares authorized, 47,979,990 shares issued and outstanding		47,980			47,980
Additional paid-in capital		33,506,089			33,072,795
Retained earnings		1,553,788			1,287,992
Total stockholders' equity		35,107,857			34,408,767

Total liabilities and stockholders' equity	$	98,505,835		$	77,831,776

BLACK RIDGE OIL & GAS, INC.

CONDENSED STATEMENTS OF OPERATIONS

(Unaudited)

	For the Three Months						For the Nine Months
	Ended September 30,						Ended September 30,
	2014			2013			2014			2013

Oil and gas sales	$	5,492,326		$	2,612,640		$	15,076,743		$	6,674,940
Loss on settled derivatives		(70,253	)		(21,184	)		(449,135	)		(21,184	)
Gain (loss) on the mark-to-market of derivatives		2,147,798			(46,225	)		1,052,639			(46,225	)
Total revenues		7,569,871			2,545,231			15,680,247			6,607,531

Operating expenses:
Production expenses		670,404			274,756			1,773,458			813,023
Production taxes		588,923			271,116			1,585,755			722,986
General and administrative		690,189			524,849			2,095,071			1,715,287
Depletion of oil and gas properties		2,275,703			1,064,921			5,994,180			2,633,309
Accretion of discount on asset retirement obligations		5,833			1,811			15,486			4,774
Depreciation and amortization		8,214			5,832			24,327			17,454
Total operating expenses		4,239,266			2,143,285			11,488,277			5,906,833

Net operating income		3,330,605			401,946			4,191,970			700,698

Other income (expense):
Interest income		972			148			972			341
Interest (expense)		(1,440,274	)		(714,466	)		(3,816,297	)		(1,523,599	)
Total other income (expense)		(1,439,302	)		(714,318	)		(3,815,325	)		(1,523,258	)

Income (loss) before provision for income taxes		1,891,303			(312,372	)		376,645			(822,560	)

Provision for income taxes		(700,587	)		88,708			(110,849	)		615,409

Net income (loss)	$	1,190,716		$	(223,664	)	$	265,796		$	(207,151	)


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		49,588,039			47,979,990			49,824,437			47,979,990

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

BLACK RIDGE OIL & GAS, INC.

CONDENSED STATEMENTS OF CASH FLOWS

(Unaudited)

	For the Nine Months
	Ended September 30,
	2014			2013
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	265,796		$	(207,151	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion of oil and gas properties		5,994,180			2,633,309
Depreciation and amortization		24,327			17,454
Amortization of debt issuance costs		229,936			691,928
Accretion of discount on asset retirement obligations		15,486			4,774
Loss (gain) on the mark-to-market of derivatives		(1,052,639	)		46,225
Accrued payment in kind interest applied to long term debt		787,344			36,667
Amortization of original issue discount on debt		102,566			6,457
Amortization of debt discounts, warrants		468,670			49,170
Common stock warrants granted as financing costs		–			108,190
Common stock options issued to employees and directors		433,294			501,617
Deferred income taxes		110,849			(615,409	)
Decrease (increase) in current assets:
Accounts receivable		(1,233,582	)		(1,288,026	)
Prepaid expenses		(45,916	)		16,364
Increase (decrease) in current liabilities:
Accounts payable		223,779			(216,975	)
Accrued expenses		61,423			35,250
Net cash provided by operating activities		6,385,513			1,819,844

CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from sale or swap of oil and gas properties		1,360,920			500,031
Purchases of oil and gas properties and development capital expenditures		(17,410,744	)		(5,991,601	)
Advances to operators		(5,742,272	)		(882,604	)
Purchases of other property and equipment		(11,131	)		(1,301	)
Net cash used in investing activities		(21,803,227	)		(6,375,475	)

CASH FLOWS FROM FINANCING ACTIVITIES
Advances from revolving credit facilities and long term debt		24,150,000			22,000,000
Repayments on revolving credit facilities		(9,600,000	)		(13,048,844	)
Debt issuance costs		(254,394	)		(725,887	)
Net cash provided by financing activities		14,295,606			8,225,269

NET CHANGE IN CASH		(1,122,108	)		3,669,638
CASH AT BEGINNING OF PERIOD		1,150,347			1,417,340
CASH AT END OF PERIOD	$	28,239		$	5,086,978

SUPPLEMENTAL INFORMATION:
Interest paid	$	2,411,463		$	551,399
Income taxes paid	$	–		$	–

NON-CASH INVESTING AND FINANCING ACTIVITIES:
Net change in accounts payable for purchase of oil and gas properties	$	3,821,375		$	2,277,913
Advances to operators paid in swap for oil and gas properties	$	–		$	(1,200,000	)
Advances to operators applied to development of oil and gas properties	$	4,285,575		$	2,212,323
Capitalized asset retirement costs, net of revision in estimate	$	61,815		$	10,400
Fair value of detachable warrants granted in consideration of debt financing	$	–		$	2,473,576

Upcoming Conference Presentation Schedule

Black Ridge Oil & Gas plans to present at the following energy conferences and investor events:

SeeThruEquity Microcap Investor Conference

November 12, 2014

Convene Midtown East, New York, NY

Midwest Investment Conference

November 18, 2014

Cleveland Convention Center, Cleveland, OH

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 Black Ridge Oil & Gas 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 Black Ridge Oil & Gas

Black Ridge Oil & Gas is a growth-oriented 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. Black Ridge Oil & Gas controls approximately 10,000 net acres prospective for Bakken and/or Three Forks development. For additional information, visit the Company's website at www.blackridgeoil.com.

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:

Ken DeCubellis

Chief Executive Officer

952-426-1241

ken.decubellis@blackridgeoil.com

Source: Black Ridge Oil & Gas, Inc.