EX-99.1 2 blackridge_8k-ex9901.htm PRESS RELEASE

Exhibit 99.1

Black Ridge Oil & Gas Announces Third Quarter 2015 Results

MINNETONKA, Minn., November 12, 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 nine months ended September 30, 2015.

Third Quarter 2015 Company Highlights

Ended quarter with $26.65 million drawn from our senior secured facility, a net reduction of $3.1 million from the end of the second quarter of 2015

Monetized $6.3 million of hedges and used proceeds to pay down debt

Quarterly production increased 41% over the third quarter of 2014 to 98.9 thousand barrels of oil equivalent (“MBoe”), an average of approximately 1,075 barrels of oil equivalent per day (“Boe/d”)

Oil and gas sales totaled $3.6 million, a decrease of 33% over the second quarter of 2015 and a decrease of 39% from the third quarter of 2014

Added 50 gross (1.92 net) wells, increasing our total producing well count to 341 gross (10.88 net), an increase of 48% over the third quarter of 2014

Recorded $9.0 million of adjusted EBITDA, including $6.3 million from the liquidation of derivative contracts prior to their contractual maturity

Recorded GAAP net loss for the quarter of $0.60 per diluted share, impacted by a non-cash impairment of $31.0 million ($0.65 per diluted share, net of tax effect). The impairment is primarily the result of low oil prices

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

Liquidity Position and Borrowing Base

Black Ridge ended the quarter with $26.65 million drawn on its $34 million senior secured revolving credit facility. The borrowing base was adjusted by our lender as part of a regularly scheduled redetermination to $33 million effective October 1, 2015 and will adjust down to $32 million on November 16, 2015. The reduction in borrowing base is the net effect of lower commodity prices and monetization of hedges, substantially offset by Teton project development. The next redetermination date is scheduled for April 1, 2016. We currently have no obligations to enter into new hedging agreements, but may choose to opportunistically do so in accord with our lending partners. Until we see sustained improvement in oil prices, the Company’s future acquisition and development activity is likely to be focused within the Merced joint venture. With limited development within the base business, the Company expects the current borrowing base and cash flows to meet our liquidity needs.

Teton Project Update and Production Guidance

In October 2015, 19 of the 23 wells in our Teton project were turned over to full production, with the remaining four wells scheduled to be turned over to production in mid-December once facilities are connected. All of the 19 wells are producing at rates near or above our expectations based on very positive flow-back rates achieved early in the second quarter. With the startup delay, the Teton project contributed only 199 boe/d during the third quarter. We expect production contribution to increase significantly during the fourth quarter.

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. “As we look forward to the remainder of 2015 and into 2016, the Company’s focus will be maintaining liquidity by allocating our free cash flow to debt reduction and finding acquisition opportunities for our joint venture with Merced.”

Hedging Update

In the third quarter of 2015, the Company realized a $7,456,284 gain on settled derivatives, of which $1,201,284 was from settlements on their scheduled maturity dates and $6,255,000 was from the liquidation of our 2018, 2017, and the majority of our 2016 derivative contracts prior to their scheduled maturity dates. As of September 30, 2015, the Company’s net derivative asset was $2,693,561. The following table summarizes the Company’s open crude oil swap contracts as of September 30, 2015:

	Oil	Weighted Average
Term	(barrels)	Price ($ per Bbl)
2015:
Q4	57,750	72.40
2016:
Q2	29,000	75.84

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 September 30, 2015:

Oil

Floor/Ceiling

Term

(Barrels)

Price (WTI)

Basis

Costless Collars – Crude Oil

10/01/2015 – 12/31/2015

9,000

$75.00/$95.60

NYMEX

01/01/2016 – 06/30/2016

3,334

$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						Nine Months Ended
	September 30,						September 30,
	2015			2014			2015			2014
Net Production:
Oil (Bbl)		86,533			62,603			249,593			164,570
Natural gas (Mcf)		74,279			44,639			244,974			106,458
Barrel of oil equivalent (Boe)		98,933			70,043			290,422			182,313

Average Sales Prices:
Oil (per Bbl)	$	37.83		$	84.17		$	43.86		$	87.71
Effect of oil hedges on average price (per Bbl)	$	13.88	(a)	$	(1.12	)	$	12.75	(a)	$	(2.73	)
Oil net of hedging (per Bbl)	$	51.71	(a)	$	83.05		$	56.61	(a)	$	84.98
Natural gas (per Mcf)	$	1.14		$	4.99		$	1.43		$	6.03
Realized price on a Boe basis, net of settled derivatives	$	46.10	(a)	$	77.41		$	49.85	(a)	$	80.23

Average Production Costs:
Oil (per Bbl)	$	9.99		$	10.27		$	11.74		$	10.31
Natural gas (per Mcf)	$	0.30		$	0.61		$	0.41		$	0.72
Barrel of oil equivalent (per Boe)	$	8.97		$	9.57		$	10.44		$	9.73
Production Taxes (per Boe)	$	3.34		$	8.41		$	4.03		$	8.70
General and Administrative Expense (per Boe)	$	7.63		$	9.85		$	7.90		$	11.49
Depletion, Depreciation and Accretion (per Boe)	$	18.10		$	32.69		$	25.42		$	33.10

^(a)Excludes the effect of derivatives settlement prior to their contractual settlement date.

Derivative Liquidation

During the third quarter of 2015, we settled all of our 2017 and 2018 derivative contracts and the majority of our 2016 derivative contracts prior to the expiration of their contractual maturities, resulting in cash proceeds totaling $6,255,000. The resulting gain is included in our gain on settled derivatives for the three and nine months ended September 30, 2015.

Third Quarter 2015 Financial Results

In the third quarter of 2015, oil and gas sales, excluding the impact of settled derivatives, were $3.4 million, a decrease of 39% as compared to the third quarter of 2014. The Company realized an average price of $37.83 per barrel of oil, before the effects of hedging, and $1.14 per mcf of gas, representing decreases of 55% and 77%, respectively, as compared to the third quarter of 2014. The impact of weaker commodity prices was partially offset by a 41% increase in production over the third quarter of 2014. The Company’s production in the third quarter of 2015 was comprised of 87% oil and 13% natural gas and natural gas liquids, on a Boe basis.

For the third quarter of 2015, the Company realized a gain on settled derivatives of $7.5 million, compared to a loss of $0.1 million in the third quarter of 2014. The third quarter 2015 settlements include the $6.3 million gain from the derivative liquidation and $1.2 million realized gain from the settlement of derivatives upon their contracted expiration date. The Company had a mark-to-market derivative loss of $3.3 million in the third quarter of 2015 compared to a mark-to-market gain of $2.1 million in the third quarter of 2014. The mark-to-market derivative loss in the third quarter of 2015 was primarily driven by the conversion of unrealized gains to realized gains, partially offset by an increase in the value of remaining hedges in the portfolio.

Production expenses for the third quarter of 2015 were $0.9 million, or $8.97 per Boe, compared to $0.7 million, or $9.57 per Boe, for the third quarter of 2014. The decrease in production expense in the third quarter was primarily attributable to lower water disposal costs as much of the new production brought on in the third quarter is from wells with lower water cuts.

Production taxes for the third quarter of 2015 were $0.3 million, compared to $0.6 million, for the third quarter of 2014. Production taxes as a percent of oil and gas sales were 9.8% for the third quarter of 2015, compared to 10.7% for the third quarter of 2014.

Depletion, depreciation, amortization and accretion (“DD&A”) was $1.8 million, or $18.10 per Boe, in the third quarter of 2015, compared to $2.3 million, or $32.69 per Boe, in the third quarter of 2014. The primary driver for the decrease in DD&A was the reduction in the full cost pool caused by the impairment recorded in the second quarter of 2015.

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 $31.0 million in the third quarter of 2015. The Company did not have any impairment of its proved oil and gas properties in the third 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 third quarter of 2015 were $0.8 million, or $7.63 per Boe, compared to $0.7 million, or $9.85 per Boe, for the third quarter of 2014. Cash G&A (non-GAAP, excludes stock-based compensation expense) was $0.6 million, or $6.09 per Boe, for the third quarter of 2015 compared to $0.5 million, or $7.79 per Boe, for the third quarter of 2014.

Interest expense, net of capitalized interest, was $1.7 million in the third quarter of 2015, compared to $1.4 million in the third 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 third quarter of 2015 was $-0- million, or 0.0% of the loss before income taxes, as compared to a net income tax expense of $0.7 million, or 37.0% of the loss before income taxes, in the third quarter of 2014. The lower effective tax rate in 2015 relates to a valuation allowance placed on the net deferred tax asset in the third quarter of 2015.

The Company recorded $9.0 million of adjusted EBITDA in the third quarter of 2015, which includes the liquidated derivative gain of $6.3 million. Adjusted EBITDA was $3.6 million for the third 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 September 30, 2015, the Company controlled approximately 8,509 net acres in the Williston Basin. Approximately 72% of the acreage is held by production with 341 gross (10.88 net) wells producing. Additionally, the Company had 0.26 net wells in development as of September 30, 2015.

Producing Wells

The following table sets forth wells in which Black Ridge holds a participating interest that were completed during the quarter ending September 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 2-8-34UTFH	Burlington Resources	McKenzie, ND	8.4%
Kings Canyon 3-1-27MTFH	Burlington Resources	McKenzie, ND	8.4%
Kings Canyon 4-1-27MTFH	Burlington Resources	McKenzie, ND	8.4%
Kings Canyon 4-8-34MBH	Burlington Resources	McKenzie, ND	8.4%
Kings Canyon 4-8-34UTFH	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 6-8-34UTFH	Burlington Resources	McKenzie, ND	8.4%
Kings Canyon 7-8-34MBH	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 5-1-3TFSH	Burlington Resources	McKenzie, ND	8.4%
Teton 6-8-10MBH	Burlington Resources	McKenzie, ND	8.4%
Teton 6-8-10TFSH	Burlington Resources	McKenzie, ND	8.4%
Teton 7-1-3TFSH	Burlington Resources	McKenzie, ND	8.4%
Teton 7-8-10MBH	Burlington Resources	McKenzie, ND	8.4%
Teton 8-8-10TFSH	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%
CCU Boxcar 44-22PH	Burlington Resources	Dunn, ND	0.8%
CCU Dakotan 1-7-17MBH	Burlington Resources	Dunn, ND	0.8%

CCU Dakotan 1-7-17TFH	Burlington Resources	Dunn, ND	0.8%
CCU Dakotan 2-7-17MBH	Burlington Resources	Dunn, ND	0.8%
CCU Dakotan 2-7-17TFH	Burlington Resources	Dunn, ND	0.8%
CCU Dakotan 3-8-17MBH	Burlington Resources	Dunn, ND	0.8%
CCU Dakotan 4-8-17TFH	Burlington Resources	Dunn, ND	0.8%
CCU Dakotan 5-8-17MBH	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 7-8-17MBH	Burlington Resources	Dunn, ND	0.8%
CCU Dakotan 7-8-17TFH	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 Olympian 31-2MBH	Burlington Resources	Dunn, ND	0.8%
CCU Powell 41-29TFH	Burlington Resources	Dunn, ND	0.8%
CCU Red River 8-2-15MBH	Burlington Resources	Dunn, 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 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%
Burr Federal 9-26H1	Continental	Mountrail, ND	0.5%

⁽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 September 30, 2015:

*Well*	*Operator*	*Location*	*WI⁽¹⁾*
EN-VP AND R- ###-##-####H-5	Hess	Mountrail, ND	3.1%
EN-VP AND R- ###-##-####H-6	Hess	Mountrail, ND	3.1%
P Berger 156-100-14-7-6-3H	Whiting	Williams, ND	1.0%
P Berger 156-100-14-7-6-4H	Whiting	Williams, ND	1.0%
Aaberg 8-5N-1H	Mountain Divide	Divide, ND	0.8%
CCU Atlantic Express 13-19TFH	Burlington Resources	Dunn, ND	0.8%
CCU Atlantic Express 23-19MBH	Burlington Resources	Dunn, ND	0.8%
CCU Atlantic Express 41-30MBH	Burlington Resources	Dunn, ND	0.8%
CCU Audubon 3-7-22TFH	Burlington Resources	Dunn, ND	0.8%
CCU Bison Point 24-34MBH	Burlington Resources	Dunn, ND	0.8%
CCU Bison Point 24-34TFH	Burlington Resources	Dunn, ND	0.8%

CCU Bison Point 34-34MBH	Burlington Resources	Dunn, ND	0.8%
CCU Bison Point 34-34TFH	Burlington Resources	Dunn, ND	0.8%
CCU Boxcar 4-7-22TFH	Burlington Resources	Dunn, ND	0.8%
CCU Burner 31-26TFH	Burlington Resources	Dunn, ND	0.8%
CCU Golden Creek 34-23TFH	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 Pacific Express 12-19TFH	Burlington Resources	Dunn, ND	0.8%
CCU Plymouth 11-29MBH	Burlington Resources	Dunn, ND	0.8%
CCU Plymouth 11-29TFH	Burlington Resources	Dunn, ND	0.8%
CCU Plymouth 21-29TFH	Burlington Resources	Dunn, ND	0.8%
CCU Red River 7-2-15TFH	Burlington Resources	Dunn, ND	0.8%
Jersey 1-6H	Continental	Mountrail, ND	0.8%
Jersey 2-6H2	Continental	Mountrail, ND	0.8%
Jersey 3-6H1	Continental	Mountrail, ND	0.8%
Jersey 5-6H	Continental	Mountrail, ND	0.8%

Adjusted Net Loss and Adjusted EBITDA

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 (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 income (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 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 (loss), GAAP, is included below:

Reconciliation of Net Loss to Adjusted Net Income (Loss)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2015			2014			2015			2014
Net income (loss)	$	(28,920,487	)	$	1,190,716		$	(48,863,061	)	$	265,796
Add back:
Loss (income) on mark-to-market of derivatives, net of tax ^(a)		3,297,358			(1,352,798	)		4,300,184			(663,639	)
Impairment of oil and gas properties, net of tax ^(b)		30,995,000			–			46,318,000			–
Adjusted net income (loss)	$	5,371,871		$	(162,082	)	$	1,755,123		$	(397,843	)

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

Net income (loss) per common share – basic	$	(0.60	)	$	0.02		$	(1.02	)	$	0.01
Add:
Change due to loss (income) on mark-to-market of derivatives, net of tax		0.07			(0.03	)		0.09			(0.01	)
Change due to impairment of oil and gas properties, net of tax		0.65			–			0.97			–
Adjusted net income (loss) per common share – basic	$	0.11		$	(0.00	)	$	0.04		$	(0.01	)

Net income (loss) per common share – fully diluted	$	(0.60	)	$	0.02		$	(1.02	)	$	0.01
Add:
Change due to loss (income) on mark-to- market of derivatives, net of tax		0.07			(0.03	)		0.09			(0.01	)
Change due to impairment of oil and gas properties, net of tax		0.65			–			0.97			–
Adjusted net income (loss) per common share – fully diluted	$	0.11		$	(0.00	)	$	0.04		$	(0.01	)

^(a)Adjusted to reflect tax expense (benefit), computed based on our effective tax rate of approximately 0% and 12% for the three and nine months ended September 30, 2015, and 37% in both the three and nine months ended September 30, 2014, consisting of $-0- and $795,000 for the three month ended September 30, 2015 and 2014, respectively, and ($586,000) and $389,000 for the nine months ended September 30, 2015 and 2014, respectively.

^(b)Adjusted to reflect tax expense, computed based on our effective tax rate of approximately 0% and 12% for the three and nine months ended September 30, 2015, and 37% in both the three and nine months ended September 30, 2014, consisting of $8,369,000 and $-0- for the three month ended September 30, 2015 and 2014, respectively, and $14,211,000 and $-0- for the nine months ended September 30, 2015 and 2014, respectively.

Reconciliation of Net Loss to Adjusted EBITDA

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2015			2014			2015			2014
Net income (loss)	$	(28,920,487	)	$	1,190,716		$	(48,863,061	)	$	265,796
Add back:
Interest expense, net, excluding amortization of warrant based financing costs		1,519,058			1,280,674			4,311,715			3,346,655
Income tax provision		–			700,587			(6,593,040	)		110,849
Depreciation, depletion, and amortization		1,782,590			2,283,917			7,358,642			6,018,507
Impairment of oil and gas properties		30,995,000			–			52,634,000			–
Accretion of abandonment liability		8,039			5,833			23,900			15,486
Share based compensation		314,374			302,961			949,888			901,964
Loss (gain) on mark-to market of derivatives		3,297,358			(2,147,798	)		4,886,184			(1,052,639	)

Adjusted EBITDA	$	8,995,932		$	3,616,890		$	14,708,228		$	9,606,618

Our adjusted EBITDA for the nine month periods ended September 30, 2015 includes income from the Dahl Federal well that was recognized in the current period based on activity in prior periods of $1,027,995.

BLACK RIDGE OIL & GAS, INC.

CONDENSED BALANCE SHEETS

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

Current assets:
Cash and cash equivalents	$	58,599		$	94,682
Derivative instruments, current		2,693,561			3,571,803
Accounts receivable		3,861,923			5,740,171
Prepaid expenses		49,107			41,387
Total current assets		6,663,190			9,448,043

Property and equipment:
Oil and natural gas properties, full cost method of accounting:
Proved properties		128,083,460			112,418,105
Unproved properties		803,718			591,121
Other property and equipment		139,004			139,004
Total property and equipment		129,026,182			113,148,230
Less, accumulated depreciation, amortization, depletion and allowance for impairment		(78,895,166	)		(18,902,524	)
Total property and equipment, net		50,131,016			94,245,706

Derivative instruments, long-term		–			4,007,942
Debt issuance costs, net		463,792			701,019

Total assets	$	57,257,998		$	108,402,710

LIABILITIES AND STOCKHOLDERS' EQUITY

Current liabilities:
Accounts payable	$	8,438,772		$	10,291,262
Accrued expenses		65,207			57,435
Total current liabilities		8,503,979			10,348,697

Asset retirement obligations		353,095			286,804
Revolving credit facilities and long term debt, net of discounts of $1,461,093 and $2,072,483, respectively		57,458,543			51,834,603
Deferred tax liability		–			6,593,040

Total liabilities		66,315,617			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		34,117,590			33,651,714
Retained earnings (accumulated deficit)		(43,223,189	)		5,639,872
Total stockholders' equity		(9,057,619	)		39,339,566

Total liabilities and stockholders' equity	$	57,257,998		$	108,402,710

BLACK RIDGE OIL & GAS, INC.

CONDENSED STATEMENTS OF OPERATIONS

(Unaudited)

	For the Three Months						For the Nine Months
	Ended September 30,						Ended September 30,
	2015			2014			2015			2014
Oil and gas sales	$	3,359,684		$	5,492,326		$	11,296,220		$	15,076,743
Gain (loss) on settled derivatives		7,456,284			(70,253	)		9,436,903			(449,135	)
Gain (loss) on the mark-to-market of derivatives		(3,297,358	)		2,147,798			(4,886,184	)		1,052,639
Total revenues		7,518,610			7,569,871			15,846,939			15,680,247

Operating expenses:
Production expenses		887,187			670,404			3,030,707			1,773,458
Production taxes		330,186			588,923			1,171,530			1,585,755
General and administrative		754,788			690,189			2,295,241			2,095,071
Depletion of oil and gas properties		1,778,580			2,275,703			7,346,356			5,994,180
Impairment of oil and gas properties		30,995,000			–			52,634,000			–
Accretion of discount on asset retirement obligations		8,039			5,833			23,900			15,486
Depreciation and amortization		4,010			8,214			12,286			24,327
Total operating expenses		34,757,790			4,239,266			66,514,020			11,488,277

Net operating income (loss)		(27,239,180	)		3,330,605			(50,667,081	)		4,191,970

Other income (expense):
Other income		–			–			6,707			–
Interest income		–			972			–			972
Interest (expense)		(1,681,307	)		(1,440,274	)		(4,795,727	)		(3,816,297	)
Total other income (expense)		(1,681,307	)		(1,439,302	)		(4,789,020	)		(3,815,325	)

Income (loss) before provision for income taxes		(28,920,487	)		1,891,303			(55,456,101	)		376,645

Provision for income taxes		–			(700,587	)		6,593,040			(110,849	)

Net income (loss)	$	(28,920,487	)	$	1,190,716		$	(48,863,061	)	$	265,796


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

Net loss per common share - basic	$	(0.60	)	$	0.02		$	(1.02	)	$	0.01
Net loss per common share - fully diluted	$	(0.60	)	$	0.02		$	(1.02	)	$	0.01

BLACK RIDGE OIL & GAS, INC.

CONDENSED STATEMENTS OF CASH FLOWS

(Unaudited)

	For the Nine Months
	Ended September 30,
	2015			2014
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	(48,863,061	)	$	265,796
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion of oil and gas properties		7,346,356			5,994,180
Depreciation and amortization		12,286			24,327
Amortization of debt issuance costs		287,227			229,936
Accretion of discount on asset retirement obligations		23,900			15,486
Loss (gain) on the mark-to-market of derivatives		4,886,184			(1,052,639	)
Accrued payment in kind interest applied to long term debt		962,550			787,344
Amortization of original issue discount on debt		127,378			102,566
Amortization of debt discounts, warrants		484,012			468,670
Common stock options issued to employees and directors		465,876			433,294
Deferred income taxes		(6,593,040	)		110,849
Impairment of oil and natural gas properties		52,634,000			–
Decrease (increase) in current assets:
Accounts receivable		1,878,248			(1,233,582	)
Prepaid expenses		(7,720	)		(45,916	)
Increase (decrease) in current liabilities:
Accounts payable		153,024			223,779
Accrued expenses		7,772			61,423
Net cash provided by operating activities		13,804,992			6,385,513

CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from sale or swap of oil and gas properties		127,348			1,360,920
Purchases of oil and gas properties and development capital expenditures		(17,968,423	)		(17,410,744	)
Advances to operators		–			(5,742,272	)
Purchases of other property and equipment		–			(11,131	)
Net cash used in investing activities		(17,841,075	)		(21,803,227	)

CASH FLOWS FROM FINANCING ACTIVITIES
Advances from revolving credit facilities and long term debt		14,000,000			24,150,000
Repayments on revolving credit facilities		(9,950,000	)		(9,600,000	)
Debt issuance costs		(50,000	)		(254,394	)
Net cash provided by financing activities		4,000,000			14,295,606

NET CHANGE IN CASH		(36,083	)		(1,122,108	)
CASH AT BEGINNING OF PERIOD		94,682			1,150,347
CASH AT END OF PERIOD	$	58,599		$	28,239


SUPPLEMENTAL INFORMATION:
Interest paid	$	3,292,793		$	2,411,463
Income taxes paid	$	–		$	–

NON-CASH INVESTING AND FINANCING ACTIVITIES:
Net change in accounts payable for purchase of oil and gas properties	$	(2,005,514	)	$	3,821,375
Advances to operators applied to development of oil and gas properties	$	–		$	4,285,575
Capitalized asset retirement costs, net of revision in estimate	$	42,391		$	61,815

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