8-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC  20549

FORM 8-K

Current Report

Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

Date of Report (Date of earliest event reported):  March 30, 2015

BLACK RIDGE OIL & GAS, INC.

(Exact name of registrant as specified in its charter)

Nevada	000-53952	27-2345075
(State or other jurisdiction of incorporation)	(Commission File Number)	(I.R.S. Employer Identification No.)

10275 Wayzata Boulevard, Suite 100

Minnetonka, MN 55305

(Address of principal executive offices)

(Zip Code)

Registrant’s telephone number, including area code:   (952) 426-1241

Not Applicable

(Former name or former address, if changed since last report)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

o Written communications pursuant to Rule 425 under the Securities Act  (17 CFR 230.425)

o Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

o Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

o Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Item 2.02.          Results of Operations and Financial Condition.

On March 30, 2015, Black Ridge Oil & Gas, Inc. (“Black Ridge”) issued a press release regarding its financial results for the fourth quarter and full year of 2014 and certain other information. A copy of the press release is furnished as Exhibit 99.1 hereto.

The press release includes information regarding operating income which include adjustments to amounts calculated under generally accepted accounting principles. These measures are not in accordance with, or an alternative for, GAAP, and may be different from similar measures used by other companies. The operating income and information presented in the press release are provided as a complement to results provided in accordance with GAAP and are provided to give investors a more complete understanding of the underlying operational results and trends in Black Ridge’s performance. 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. A reconciliation of this information to the most directly comparable financial measure presented in accordance with GAAP is provided in the press release.

In addition, the press release includes information regarding our reserves on a Pre-tax PV10% which may be considered a non-GAAP financial measure as defined by the SEC and is derived from the standardized measure of discounted future net cash flows, which is the most directly comparable standardized financial measure. Pre-tax PV10% is computed on the same basis as the standardized measure of discounted future net cash flows but without deducting future income taxes. We believe Pre-tax PV10% is a useful measure for investors for evaluating the relative monetary significance of our crude oil and natural gas properties. We further believe investors may utilize our Pre-tax PV10% as a basis for comparison of the relative size and value of our reserves to other companies because many factors that are unique to each individual company impact the amount of future income taxes to be paid. Our management uses this measure when assessing the potential return on investment related to our crude oil and natural gas properties and acquisitions. However, Pre-tax PV10% is not a substitute for the standardized measure of discounted future net cash flows. Our Pre-tax PV10% and the standardized measure of discounted future net cash flows do not purport to present the fair value of our crude oil and natural gas reserves.

The information in this Item 2.02 and Exhibit 99.1 shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, nor shall it be deemed incorporated by reference into any filing under the Securities Act of 1933, as amended.

Item 7.01 Regulation FD Disclosure.

Black Ridge has also updated the investor presentation that is posted on its website regarding its operations and business. The PowerPoint slide presentation regarding its operations and business is furnished as Exhibit 99.2.

The information in Exhibit 99.2 attached hereto shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, nor shall it be deemed incorporated by reference in any filing under the Securities Act of 1933, as amended.

Item 9.01.          Financial Statements and Exhibits.

(d) Exhibits

99.1	Press Release (furnished)
99.2	PowerPoint Slides (furnished)

2

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

	BLACK RIDGE OIL & GAS, INC.
	By:	/s/ James Moe
		James Moe
		Chief Financial Officer
Date: March 30, 2015

3

EX-99.1

Exhibit 99.1

Black Ridge Oil & Gas Announces 2014 Fourth Quarter and Full Year Results

MINNETONKA, Minn., March 30, 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 and year ended December 31, 2014.

2014 Company Highlights

· Annual production increased 168% to 291.8 thousand barrels of oil equivalent (“MBoe”), an average of approximately 799 barrels of oil equivalent per day (“Boe/d”)

· Oil and gas sales increased 127% to $21.1 million

· Total proved reserves increased 18% to 5.4 MMBoe

· Pre-tax PV-10% of the total proved reserves as of December 31, 2014 increased 35% to $100.3 million

· Ended 2014 with production from 247 gross (7.88 net) wells, up from 153 gross (4.87 net) at the end of 2013, an increase of 62% on a net well basis

· Recorded $14.4 million of adjusted EBITDA, representing an increase of 145% from 2013

· Fourth quarter production increased to 1,190 Boe/d, a 233% increase over the fourth quarter of 2013 and a 56% sequential increase over the third quarter of 2014

Acreage and Drilling

As of December 31, 2014, the Company controlled approximately 10,000 net acres in the Williston Basin. Approximately 63% of the acreage is held by production. In 2014, the Company added 3.01 net wells to production, ending the year with a total producing well count of 7.88 net wells. Additionally, the Company had 2.8 additional net wells in development at year end.

Management Comment

Ken DeCubellis, Black Ridge’s CEO, commented, “We are proud of our execution and growth in 2014. Our disciplined process for making investment decisions has the Company on a solid foundation as we closed out 2014. Now, all of our attention has shifted to executing a plan to manage through the commodity price downturn. Measured production growth, within the context of available liquidity and prudent balance sheet risk, and our continued focus on making investment decisions that exceed our internal rate of return threshold are the pillars of our plan that will help guide the Company through the down cycle.”

2015 Capital Program and Production Guidance

The Company expects 2015 capital expenditures to total approximately $16 million. The Company expects additional cash expenditures of approximately $9 million related to wells in process and accrued as of December 31, 2014. Black Ridge expects to bring 2.8 net wells online during the year, with the majority of the additions coming in the third and fourth quarters. The Company’s Teton and Corral Creek Unit projects are expected to comprise approximately 75% of the net well additions. These two projects, located in core of the Williston Basin in eastern McKenzie and northern Dunn counties, respectively, are expected to meet or exceed the Company’s return thresholds based on current oil prices. As the price environment dictates, the Company may look to strategically divest mature producing assets. Total Company production is expected to average approximately 1,100 boe/d in 2015.

Liquidity Position and Borrowing Base

Black Ridge ended the year with $22.6 million drawn on its $35 million senior secured revolving credit facility. Subsequent to year-end, the senior secured borrowing base was re-determined to $34 million. The next redetermination date is scheduled for October 1, 2015.

1

Hedging Update

In 2014, the Company realized a $511,451 gain on settled derivatives and a $7,793,421 unrealized gain on mark-to-market adjustments to its outstanding derivatives contracts. The following table summarizes the Company’s open derivatives contracts as of December 31, 2014.

Weighted Average Price of
Open Commodity Swap Contracts
		Weighted
	Volumes	Average
Year	(Bbl)	Price (WTI)
2015	87,000	$	89.84
2016	84,000	$	89.73
2017	78,000	$	87.18

In addition to the open commodity 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 contracts as of December 31, 2014.

	Oil	Floor/Ceiling
Term	(Barrels)	Price (WTI)	Basis
Costless Collars – Crude Oil
01/01/2015 – 12/31/2015	36,000	$75.00/$95.60	NYMEX
01/01/2016 – 06/30/2016	10,002	$80.00/$89.50	NYMEX

2014 Operating and Financial Results

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

	Year Ended
	December 31,
	2014		2013		% Change
Net Production:
Oil (Bbl)		256,256		99,979		156
Natural Gas (Mcf)		213,141		52,973		302
Barrel of Oil Equivalent (Boe)		291,780		108,808		168
Average Daily Production (Boe/d)		799		298		168
Average Sales Prices:
Oil (per Bbl)	$	78.64	$	89.58		(12	)
Effect of oil hedges on average price (per Bbl)	$	1.99	$	0.54
Oil net of hedging (per Bbl)	$	80.63	$	90.12		(11	)
Natural Gas (per Mcf)	$	4.46	$	6.04		(26	)
Effect of natural gas hedges on average price (per Mcf)	$	–	$	–
Natural gas net of hedging (per Mcf)	$	4.46	$	6.04		(26	)
Per Boe including settled derivatives	$	74.08	$	85.75		(14	)
Operating Expenses (per Boe):
Production Expenses	$	9.27	$	10.53		(12	)
Production Taxes	$	7.55	$	9.34		(19	)
G&A Expense	$	9.91	$	21.14		(53	)
Depletion, Depreciation, Amortization and Accretion	$	32.26	$	34.36		(6	)

2

Year-End 2014 Results

For the full year 2014, Company production increased to 291.8 Mboe, an average of 799 Boe/d, representing a 168% increase over 2013 production of 108.8 MBoe. Oil and gas sales were $21.1 million, compared to $9.3 million in 2013, an increase of 127%. The increase in production and revenues was due to the completion of an additional 94 gross (3.01 net) wells in 2014.

During 2014, the Company realized an average price of $78.64 per Bbl of oil compared to an average price of $89.58 per Bbl of oil in 2013. The Company’s production was comprised of 88% oil and 12% natural gas and natural gas liquids in 2014 on a Boe basis.

Lease operating expenses for 2014 were $2.7 million, or $9.27 per Boe, compared to $1.1 million, or $10.53 per Boe, for 2013.

General and administrative expenses (“G&A”) for 2014 were $2.9 million, or $9.91 per Boe, compared to $2.3 million, or $21.14 per Boe for 2013. Cash G&A (non-GAAP, excludes stock-based compensation expense) was $2.3 million, or $7.93 per Boe for 2014 compared to $1.7 million, or $15.22 per Boe for 2013.

The Company recorded $14.4 million of adjusted EBITDA in 2014, representing an increase of 145% from $5.9 million of adjusted EBITDA in 2013. Adjusted EBITDA is a non-GAAP financial measure. Please refer to the reconciliation in this release for additional information about this measure.

Fourth Quarter 2014 Operating and Financial Results

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

	Three Months Ended
	December 31,
	2014		2013		% Change
Net Production:
Oil (Bbl)		91,686		29,394		212
Natural Gas (Mcf)		106,683		21,135		405
Barrel of Oil Equivalent (Boe)		109,467		32,916		233
Average Daily Production (Boe/d)		1,190		358		233
Average Sales Prices:
Oil (per Bbl)	$	62.35	$	84.24		(26	)
Effect of oil hedges on average price (per Bbl)	$	10.48	$	2.54
Oil net of hedging (per Bbl)	$	72.83	$	86.78		(16	)
Natural Gas (per Mcf)	$	2.90	$	5.94		(51	)
Effect of natural gas hedges on average price (per Mcf)	$	–	$	–
Natural gas net of hedging (per Mcf)	$	2.90	$	5.94		(51	)
Per Boe including settled derivatives	$	63.82	$	81.31		(22	)
Operating Expenses (per Boe):
Production Expenses	$	8.52	$	10.11		(16	)
Production Taxes	$	5.64	$	8.90		(37	)
G&A Expense	$	7.28	$	17.76		(59	)
Depletion, Depreciation, Amortization and Accretion	$	30.85	$	32.89		(6	)

3

Fourth Quarter 2014 Results

During the fourth quarter of 2014, Company production totaled 109.5 Mboe, an average of 1,190 Boe/d, representing a sequential increase of 56% over third quarter 2014 production of 70.0 Mboe and a year-over-year increase of 233% over 32.9 Mboe in the fourth quarter of 2013.

Oil and gas sales, which exclude the effect of derivatives, totaled $6.0 million in the fourth quarter of 2014, compared to $2.6 million in the fourth quarter of 2013, an increase of 132%.

Average realized prices for the fourth quarter of 2014, before the effect of commodity derivatives, were $62.35 per Bbl of oil and $2.90 per Mcf of natural gas, compared to $84.24 per Bbl of oil and $5.94 per Mcf of natural gas in the fourth quarter of 2013.

Lease operating expenses for the fourth quarter of 2014 were $932 thousand, or $8.52 per Boe, compared to $333 thousand, or $10.11 per Boe for the fourth quarter of 2013, a decrease of 16% on a per Boe basis.

General and administrative expenses (“G&A”) for the fourth quarter of 2014 were $797 thousand, or $7.28 per Boe, compared to $584 thousand, or $17.76 per Boe for the fourth quarter of 2013. Cash G&A (non-GAAP, excludes stock-based compensation expense) was $651 thousand, or $5.95 per Boe for the fourth quarter of 2014 compared to $442 thousand, or $13.44 per Boe for the fourth quarter of 2013.

The Company recorded $4.8 million of adjusted EBITDA in the fourth quarter of 2014, representing a 143% increase over $2.0 million of adjusted EBITDA in the fourth quarter of 2013. Adjusted EBITDA is a non-GAAP financial measure. Please refer to the reconciliation in this release for additional information about this measure.

2014 Proved Reserves

As of December 31, 2014, Black Ridge had estimated proved reserves of 5.4 MMBoe, of which 38% were classified as proved developed, and 90% was crude oil. These estimated proved reserves had a pre-tax PV10% value of $100.3 million, a 35% increase over 2013 proved reserves pre-tax PV10% value of $74.4 million. Reserve replacement for the Company in 2014 was 280%. The Company's estimated reserves were prepared by its independent reservoir engineering firm, Netherland, Sewell & Associates, Inc.

Reserve Category(1)	% of Reserves		Oil (MBbls)		Gas (MMcf)		2014 Mboe(2)		2013 Mboe		% Change			2014 PV-10(3) ($000's)
Proved Developed Producing		36%		1,688		1,276		1,901		998		90%		$	58,939
Proved Developed Non-Producing		2%		111		87		126		38		332%			4,743
Proved Undeveloped		62%		2,999		1,984		3,329		3,502		(5%	)		36,693
Total Proved		100%		4,798		3,347		5,356		4,538		18%		$	100,335

(1)	The SEC Pricing Proved Reserves table above values crude oil and natural gas reserve quantities and related discounted future net cash flows as of December 31, 2014 assuming a constant realized price of $83.26 per barrel of crude oil and a constant realized price of $7.10 per Mcf of natural gas. The values presented in both tables above were calculated by Netherland, Sewell & Associates, Inc.
(2)	BOE are computed based on a conversion ratio of one BOE for each barrel of crude oil and one BOE for every 6,000 cubic feet (i.e., 6 Mcf) of natural gas.

4

⁽³⁾ Pre-tax PV10% may be considered a non-GAAP financial measure as defined by the SEC and is derived from the standardized measure of discounted future net cash flows, which is the most directly comparable standardized financial measure. Pre-tax PV10% is computed on the same basis as the standardized measure of discounted future net cash flows but without deducting future income taxes. We believe Pre-tax PV10% is a useful measure for investors for evaluating the relative monetary significance of our crude oil and natural gas properties. We further believe investors may utilize our Pre-tax PV10% as a basis for comparison of the relative size and value of our reserves to other companies because many factors that are unique to each individual company impact the amount of future income taxes to be paid. Our management uses this measure when assessing the potential return on investment related to our crude oil and natural gas properties and acquisitions. However, Pre-tax PV10% is not a substitute for the standardized measure of discounted future net cash flows. Our Pre-tax PV10% and the standardized measure of discounted future net cash flows do not purport to present the fair value of our crude oil and natural gas reserves.

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 December 31, 2014.

Well	Operator	Location	WI(1)
Matilda Bay 1-15H	Slawson	Williams, ND	0.100
McCracken 2758 21-10 5B	Oasis	Roosevelt, MT	0.071
McCracken 2758 44-9 4B	Oasis	Roosevelt, MT	0.071
McCracken 2758 34-9 3B	Oasis	Roosevelt, MT	0.071
McCracken 2758 41-10 6B	Oasis	Roosevelt, MT	0.071
Ironbank 5-14-13TFH	Slawson	Williams, ND	0.055
Revolver 7-35TFH	Slawson	Mountrail, ND	0.016
CCU Powell 41-29MBH	Burlington Resources	Dunn, ND	0.008
CCU Olympian 11-2TFH	Burlington Resources	Dunn, ND	0.008
Jersey 23-6H1	Continental	Mountrail, ND	0.008
Jersey 24-6H3	Continental	Mountrail, ND	0.008
Jersey 25-6H	Continental	Mountrail, ND	0.008
Jersey 26-6H2	Continental	Mountrail, ND	0.008
Jersey 27-6H1	Continental	Mountrail, ND	0.008
Jersey 28-6H3	Continental	Mountrail, ND	0.008
Jersey 29-6XH	Continental	Mountrail, ND	0.008

⁽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 December 31, 2014.

Well	Operator	Location	WI(1)
Bootleg 6-14-15TFH	Slawson	Williams, ND	0.113
Bootleg 7-14-15TFH	Slawson	Williams, ND	0.113
Bootleg 8-14-15TF2H	Slawson	Williams, ND	0.113
Rainbow 10-19-18HBK	Samson Oil and Gas	Williams, ND	0.100
Teton 5-1-3TFSH	Burlington Resources	McKenzie, ND	0.088
Kings Canyon 6-8-34UTFH	Burlington Resources	McKenzie, ND	0.088
Kings Canyon 4-8-34UTFH	Burlington Resources	McKenzie, ND	0.088

5

Kings Canyon 4-8-34MBH	Burlington Resources	McKenzie, ND	0.088
Teton 2-8-10MBH	Burlington Resources	McKenzie, ND	0.088
Teton 3-8-10MBH	Burlington Resources	McKenzie, ND	0.088
Teton 8-8-10TFSH	Burlington Resources	McKenzie, ND	0.088
Teton 7-1-3TFSH	Burlington Resources	McKenzie, ND	0.088
Kings Canyon 7-8-34MBH	Burlington Resources	McKenzie, ND	0.088
Kings Canyon 5-8-34UTF	Burlington Resources	McKenzie, ND	0.088
Teton 5-8-10MBH	Burlington Resources	McKenzie, ND	0.088
Teton 6-8-10TFSH	Burlington Resources	McKenzie, ND	0.088
Teton 7-8-10MBH	Burlington Resources	McKenzie, ND	0.088
Kings Canyon 2-8-34UTFH	Burlington Resources	McKenzie, ND	0.088
Kings Canyon 3-1-27MTFH	Burlington Resources	McKenzie, ND	0.088
Kings Canyon 6-1-27MBH	Burlington Resources	McKenzie, ND	0.088
Kings Canyon 6-1-27MTFH	Burlington Resources	McKenzie, ND	0.088
Kings Canyon 4-1-27MTFH	Burlington Resources	McKenzie, ND	0.088
Teton 6-8-10MBH	Burlington Resources	McKenzie, ND	0.088
Billabong 2-13-14HBK	Slawson	Williams, ND	0.075
Remingteton 8-8-10MBH	Burlington Resources	McKenzie, ND	0.062
Ironbank 4-14-13TFH	Slawson	Williams, ND	0.055
Ironbank 7-14-13TFH	Slawson	Williams, ND	0.054
Ironbank 6-14-13TFH	Slawson	Williams, ND	0.054
DeKing 1-8-34MBH-ULW	Burlington Resources	McKenzie, ND	0.021
Gobbler 6-35-26TFH	Slawson	Mountrail, ND	0.008
Duletski Federal 14-12PH	Whiting	Billings, ND	0.008
Aaberg 8-5N-1H	Mountain Divide	Divide, ND	0.008
CCU Powell 41-29TFH	Burlington Resources	Dunn, ND	0.008
CCU Pullman 2-8-7MBH	Burlington Resources	Dunn, ND	0.008
CCU Pullman 5-8-7TFH	Burlington Resources	Dunn, ND	0.008
CCU Pullman 5-8-7MBH	Burlington Resources	Dunn, ND	0.008
CCU Pullman 6-8-7TFH	Burlington Resources	Dunn, ND	0.008
CCU Pullman 8-8-7TFH	Burlington Resources	Dunn, ND	0.008
CCU Pullman 7-8-7MBH	Burlington Resources	Dunn, ND	0.008
CCU Pullman 7-8-7TFH	Burlington Resources	Dunn, ND	0.008
CCU North Coast 31-25MBH	Burlington Resources	Dunn, ND	0.008
CCU North Coast 31-25TFH	Burlington Resources	Dunn, ND	0.008
CCU Pullman 6-8-7MBH	Burlington Resources	Dunn, ND	0.008
CCU Pullman 1-8-7TFH	Burlington Resources	Dunn, ND	0.008
CCU Pullman 3-8-7TFH	Burlington Resources	Dunn, ND	0.008
CCU Pullman 3-8-7MBH	Burlington Resources	Dunn, ND	0.008
CCU North Coast 4-8-23MBH	Burlington Resources	Dunn, ND	0.008
CCU North Coast 41-25MBH	Burlington Resources	Dunn, ND	0.008
CCU North Coast 4-8-23TFH	Burlington Resources	Dunn, ND	0.008
CCU Golden Creek 44-23TFH	Burlington Resources	Dunn, ND	0.008
CCU Golden Creek 44-23MBH	Burlington Resources	Dunn, ND	0.008
CCU North Coast 41-25TFH	Burlington Resources	Dunn, ND	0.008

6

CCU Main Streeter 24-24TFH	Burlington Resources	Dunn, ND	0.008
CCU Main Streeter 14-24MBH	Burlington Resources	Dunn, ND	0.008
CCU Dakotan 2-7-17MBH	Burlington Resources	Dunn, ND	0.008
CCU Dakotan 1-7-17TFH	Burlington Resources	Dunn, ND	0.008
CCU Dakotan 1-7-17MBH	Burlington Resources	Dunn, ND	0.008
CCU Dakotan 2-7-17TFH	Burlington Resources	Dunn, ND	0.008
CCU Dakotan 5-8-17TFH	Burlington Resources	Dunn, ND	0.008
CCU Dakotan 6-8-17MBH	Burlington Resources	Dunn, ND	0.008
CCU Dakotan 7-8-17TFH	Burlington Resources	Dunn, ND	0.008
CCU Dakotan 7-8-17MBH	Burlington Resources	Dunn, ND	0.008
CCU Dakotan 5-8-17MBH	Burlington Resources	Dunn, ND	0.008
CCU Dakotan 4-8-17TFH	Burlington Resources	Dunn, ND	0.008
Jersey 1-6H	Continental	Mountrail, ND	0.008
Jersey 3-6H1	Continental	Mountrail, ND	0.008
Jersey 2-6H2	Continental	Mountrail, ND	0.008
Jersey 7-6H	Continental	Mountrail, ND	0.008
Jersey 6-6H1	Continental	Mountrail, ND	0.008
Jersey 4-6H3	Continental	Mountrail, ND	0.008
Jersey 8-6H1	Continental	Mountrail, ND	0.008
Jersey 5-6H	Continental	Mountrail, ND	0.008
P Johnson 153-98-1-6-7-16H	Kodiak	Williams, ND	0.006
P Johnson 153-98-1-6-7-16HA	Kodiak	Williams, ND	0.006
Oakdale 2-13H1	Continental	Dunn, ND	0.006
Ryden 3-24H	Continental	Dunn, ND	0.006
Ryden 2-24AH1	Continental	Dunn, ND	0.006
Oakdale 5-13H	Continental	Dunn, ND	0.006
Oakdale 3-13H	Continental	Dunn, ND	0.006
Oakdale 4-13H1	Continental	Dunn, ND	0.006
Ryden 4-24H1	Continental	Dunn, ND	0.006

⁽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.

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Adjusted Net Income (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 excluding settlement income, net of settlement expenses, and 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, and (v) non-cash expenses relating to share based payments recognized under ASC Topic 718. We believe the use of non-GAAP financial measures provides useful information to investors regarding our current financial performance; however, Adjusted 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, are included below:

8

Reconciliation of Net Income (Loss) to Adjusted Net Income (Loss)

	Three Months Ended December 31,						Years Ended December 31,
	2014			2013			2014			2013
Net income (loss)	$	4,086,084		$	(195,508	)	$	4,351,880		$	(402,659	)
Subtract:
Loss (gain) on mark-to-market of derivatives, net of tax (a)		(4,245,782	)		105,451			(4,909,421	)		134,676
Settlement income, net of tax (b)		–			(227,505	)		–			(227,505	)
Adjusted net income (loss)	$	(159,698	)	$	(317,562	)	$	(557,541	)	$	(495,488	)
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		48,815,177			47,979,990			49,179,725			47,979,990
Net income (loss) per common share - basic	$	0.09		$	0.00		$	0.09		$	(0.01	)
Subtract:
Loss (gain) on mark-to-market of derivatives, net of tax		(0.09	)		0.00			(0.10	)		0.00
Settlement income per common share, net of tax		–			(0.00	)		–			(0.00	)
Adjusted net income (loss) per common share - basic	$	0.00		$	(0.00	)	$	(0.01	)	$	(0.01	)
Net income (loss) per common share - fully diluted	$	0.08		$	0.00		$	0.09		$	(0.01	)
Subtract:
Loss (gain) on mark-to-market of derivatives, net of tax		(0.09	)		0.00			(0.10	)		0.00
Settlement income per common share, net of tax		–			(0.00	)		–			0.00
Adjusted net income (loss) per common share - fully diluted	$	(0.01	)	$	(0.00	)	$	(0.01	)	$	(0.01	)

^(a) Adjusted to reflect tax (expense) benefit, computed based on our effective tax rates of approximately 37% in 2014 and 2013, of ($2,494,000) and $62,000, respectively, for the three months ended December 31, 2014 and 2013 and ($2,884,000) and $79,000, respectively, for the years ended December 31, 2014 and 2013.

^(b) Adjusted to reflect tax expense, computed based on our effective tax rate of approximately 37% in 2013, of $134,000, for the three months and year ended December 31, 2013.

9

Reconciliation of Net Income (Loss) to Adjusted EBITDA

	Three Months Ended December 31,						Years Ended December 31,
	2014			2013			2014			2013
Net income (loss)	$	4,086,084		$	(195,508	)	$	4,351,880		$	(402,659	)
Add back:
Interest expense, net, excluding amortization of warrant based financing costs		1,309,414			706,231			4,656,069			2,072,129
Income tax provision		2,448,346			(83,442	)		2,559,195			(698,851	)
Depreciation, depletion, and amortization		3,370,583			1,078,394			9,389,090			3,729,157
Accretion of abandonment liability		6,875			4,245			22,361			9,019
Share-based compensation		305,150			292,662			1,207,114			951,639
Losses (gains) on the mark-to-market of derivatives		(6,740,782	)		167,451			(7,793,421	)		213,676
Adjusted EBITDA	$	4,785,670		$	1,970,033		$	14,392,288		$	5,874,110

Our adjusted EBITDA includes settlement income, net of settlement expenses, of $361,505 for the three months and year ended December 31, 2013.

10

BLACK RIDGE OIL & GAS, INC.

BALANCE SHEETS

	December 31,			December 31,
	2014			2013
ASSETS
Current assets:
Cash and cash equivalents	$	94,682		$	1,150,347
Derivative instruments		3,571,803			–
Accounts receivable		5,740,171			1,905,467
Advances to operators		–			1,214,662
Prepaid expenses		41,387			26,142
Total current assets		9,448,043			4,296,618
Property and equipment:
Oil and natural gas properties, full cost method of accounting
Proved properties		112,418,105			79,361,432
Unproved properties		591,121			2,798,795
Other property and equipment		139,004			115,482
Total property and equipment		113,148,230			82,275,709
Less, accumulated depreciation, amortization, depletion and allowance for impairment		(18,902,524	)		(9,513,434	)
Total property and equipment, net		94,245,706			72,762,275
Derivative instruments		4,007,942			–
Debt issuance costs, net		701,019			772,883
Total assets	$	108,402,710		$	77,831,776
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	10,291,262		$	8,453,709
Accrued expenses		57,435			4,813
Derivative instruments		–			139,065
Total current liabilities		10,348,697			8,597,587
Derivative instruments		–			74,611
Asset retirement obligations		286,804			160,665
Revolving credit facility and long term debt, net of discounts of $2,072,483 and $2,645,582, respectively		51,834,603			30,556,301
Deferred tax liability		6,593,040			4,033,845
Total liabilities		69,063,144			43,423,009
Commitments and contingencies (See note 14)		–			–
Stockholders' equity:
Preferred stock, $0.001 par value, 20,000,000 shares authorized, no shares issued and outstanding		–			–
Common stock, $0.001 par value, 500,000,000 shares authorized, 47,979,990 shares issued and outstanding		47,980			47,980
Additional paid-in capital		33,651,714			33,072,795
Retained earnings		5,639,872			1,287,992
Total stockholders' equity		39,339,566			34,408,767
Total liabilities and stockholders' equity	$	108,402,710		$	77,831,776

11

BLACK RIDGE OIL & GAS, INC.

STATEMENTS OF OPERATIONS

	For the Three Months						For the Years
	Ended December 31,						Ended December 31,
	2014			2013			2014			2013
Oil and gas sales	$	6,026,080		$	2,601,716		$	21,102,823		$	9,276,656
Gain on settled derivatives		960,586			74,666			511,451			53,482
Gain (loss) on the mark-to-market of derivatives		6,740,782			(167,451	)		7,793,421			(213,676	)
Total revenues	$	13,727,448		$	2,508,931		$	29,407,695		$	9,116,462
Operating expenses:
Production expenses		932,305			332,663			2,705,763			1,145,686
Production taxes		617,746			292,921			2,203,501			1,015,907
General and administrative		796,570			584,470			2,891,641			2,299,757
Depletion of oil and gas properties		3,365,772			1,071,847			9,359,952			3,705,156
Accretion of discount on asset retirement obligations		6,875			4,245			22,361			9,019
Depreciation and amortization		4,811			6,547			29,138			24,001
Total operating expenses		5,724,079			2,292,693			17,212,356			8,199,526
Net operating income		8,003,369			216,238			12,195,339			916,936
Other income (expense):
Interest income		–			67			972			408
Interest (expense)		(1,468,939	)		(856,760	)		(5,285,236	)		(2,380,359	)
Settlement income		–			380,982			–			380,982
Settlement expense		–			(19,477	)		–			(19,477	)
Total other income (expense)		(1,468,939	)		(495,188	)		(5,284,264	)		(2,018,446	)
Income (loss) before provision for income taxes		6,534,430			(278,950	)		6,911,075			(1,101,510	)
Provision for income taxes		(2,448,346	)		83,442			(2,559,195	)		698,851
Net income (loss)	$	4,086,084		$	(195,508	)	$	4,351,880		$	(402,659	)
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		48,815,177			47,979,990			49,179,725			47,979,990
Net income (loss) per common share - basic	$	0.09		$	(0.00	)	$	0.09		$	(0.01	)
Net income (loss) per common share - fully diluted	$	0.08		$	(0.00	)	$	0.09		$	(0.01	)

12

BLACK RIDGE OIL & GAS, INC.

STATEMENTS OF CASH FLOWS

	For the Years
	Ended December 31,
	2014			2013
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	4,351,880		$	(402,659	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion of oil and gas properties		9,359,952			3,705,156
Depreciation and amortization		29,138			24,001
Amortization of debt issuance costs		326,258			749,920
Accretion of discount on asset retirement obligations		22,361			9,019
Loss (gain) on the mark-to-market of derivatives		(7,793,421	)		213,676
Accrued payment in kind interest applied to long term debt		1,105,203			201,883
Amortization of original issue discount on debt		144,904			28,362
Amortization of debt discounts, warrants		628,195			199,632
Common stock warrants granted as financing costs		–			108,190
Common stock options issued to employees and directors		578,919			643,817
Deferred income taxes		2,559,195			(698,851	)
Decrease (increase) in current assets:
Accounts receivable		(2,834,704	)		(1,049,234	)
Settlement receivable		–			2,500,000
Prepaid expenses		(15,245	)		21,013
Increase (decrease) in current liabilities:
Accounts payable		426,558			164,527
Settlement payable		–			(160,000	)
Settlement payable, related parties		–			(116,234	)
Accrued expenses		52,622			(56,853	)
Net cash provided by operating activities		8,941,815			6,085,365
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from sale or swap of oil and gas properties		1,441,929			608,387
Purchases of oil and gas properties and development capital expenditures		(24,739,407	)		(32,025,724	)
Advances to operators		(5,822,086	)		(882,604	)
Purchases of other property and equipment		(23,522	)		(38,472	)
Net cash used in investing activities		(29,143,086	)		(32,338,413	)
CASH FLOWS FROM FINANCING ACTIVITIES
Advances from revolving credit facilities and long term debt		29,800,000			41,150,000
Repayments on revolving credit facilities		(10,400,000	)		(14,298,844	)
Debt issuance costs		(254,394	)		(865,101	)
Net cash provided by financing activities		19,145,606			25,986,055
NET CHANGE IN CASH		(1,055,665	)		(266,993	)
CASH AT BEGINNING OF PERIOD		1,150,347			1,417,340
CASH AT END OF PERIOD	$	94,682		$	1,150,347
SUPPLEMENTAL INFORMATION:
Interest paid	$	3,401,028		$	1,104,688
Income taxes paid	$	–		$	–
NON-CASH INVESTING AND FINANCING ACTIVITIES:
Net change in accounts payable for purchase of oil and gas properties	$	1,410,995		$	5,335,656
Advances to operators received in swap for oil and gas properties	$	–		$	(1,200,000	)
Advances to operators applied to purchase of oil and gas properties	$	6,036,748		$	2,218,237
Advances to operators reclassified to accounts receivable	$	1,000,000		$	–
Capitalized asset retirement costs, net of revision in estimate	$	103,778		$	84,501
Fair value of detachable warrants granted in consideration of debt financing	$	–		$	2,473,576

13

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

www.blackridgeoil.com

14

EX-99.2

Exhibit 99.2

2014 Results and 2015 Plan OTCQB: ANFC Focused Growth in the Williston Basin March 30, 2015

Forward Looking Statements www.blackridgeoil.com 2 Statements made by representatives of Black Ridge Oil & Gas, Inc . (“Black Ridge” or the “Company”) during the course of this presentation that are not historical facts are “forward-looking statements” within the meaning of federal securities laws . These statements are based on certain assumptions and expectations made by the Company which reflect management’s experience, estimates and perception of historical trends, current conditions, anticipated future developments and other factors believed to be appropriate . No assurances can be given that such assumptions and expectations will occur as anticipated and actual results may differ materially from those implied or anticipated in the forward looking statements . Such statements are subject to a number of risks and uncertainties, many of which are beyond the control of the Company, and which include risks relating to the global financial crisis, our ability to obtain additional capital needed to implement our business plan, declines in prices and demand for gas, oil and natural gas liquids, loss of key personnel, lack of business diversification, reliance on strategic third-party relationships, ability to obtain rights to explore and develop oil and gas reserves, the rate of in - fill drilling on our leased acreage, financial performance and results, our indebtedness under our line of credit, our ability to replace reserves and efficiently develop our current reserves, our ability to make acquisitions on economically acceptable terms, our ability to effectively utilize hedging, our ability to become listed on a national exchange, and other important factors . Black Ridge undertakes no obligation to publicly update any forward-looking statements, whether as a result of new information or future events .

Black Ridge Overview www.blackridgeoil.com 3 Public company. OTCQB, Ticker: ANFC Bakken / Three Forks Shale Non - Operator Exploration and Production Company Approximately 9,400 net leasehold acres Production is approximately 85% oil, 15% natural gas and natural gas liquids Company strategy and performance have us well positioned to weather the current low oil price environment Key 2014 Highlights: Average Production up 168% to 799 boe /d Oil and Gas Sales up 127% to $21.1 million Total proved reserves up 18% to 5.4 MMBoe Adjusted EBITDA of $ 14.4mm (1) Q4 2014 average production of 1,190 boe /d, up 233% over Q4 2013 Black Ridge Operational Focus: Bakken / Three Forks Shale Oil North Dakota Montana Williston Basin (1) Adjusted EBITDA is a non - GAAP financial measure. See appendix for reconciliation.

Why The Non - Operator Business Model? www.blackridgeoil.com 4 Ability to selectively invest in the highest return projects, without the need to control a drilling unit Knowledge and data from approximately 350 gross wells to make capital allocation decisions Low cost structure Fragmented nature of non - operator leaseholds will continue to provide growth opportunity as the play matures Flexible capex decision - making: option to participate in all well proposals from operating partners

Black Ridge Oil & Gas Strategy www.blackridgeoil.com 5 Deal Flow with Near - Term Development Disciplined Investment D ecisions and Asset Management Capital Availability Reporting, Controls, Regulatory C ompliance Cash Flow: IRR >30%

- 2.00 4.00 6.00 8.00 10.00 12.00 14.00 Producing "Drilling" Permitted www.blackridgeoil.com 6 Strong Development Pipeline to Feed Future Growth 8.6 2.4 Black Ridge Oil & Gas’ Net Wells (as of 2/28/15) Permitting activity has slowed down in recent months, driven by oil prices 2.4 net wells currently drilling, dominated by Teton project (1.76 net) 67% growth in producing net wells year over year

0 200 400 600 800 1,000 1,200 2011 2012 2013 2014 2015 (projected) www.blackridgeoil.com 7 Production Ramping Up in High Return Areas Net Production BOE/d

$0 $20 $40 $60 $80 $100 $120 0 1 2 3 4 5 6 MMboe PV10 MMboe 2011 2012 2013 2014 2014 @ Strip (2) YE 2014 Proved Reserves www.blackridgeoil.com 8 Pre - tax PV - 10%, $MM (1) (1) Based on SEC Pricing of $94.99/ Bbl of oil and $4.35/ MMBtu of natural gas, adjusted for local price differentials. Pre - tax PV - 10% may be considered a non - GAAP financial measure as defined by the SEC and is derived from the standardized measure of discounted future net cash flows, which is the most direc tly comparable standardized financial measure. (2) Internal estimate reflective of current strip pricing; reserves adjusted for local price differentials, expected extraction t ax changes and expected reductions to drilling and completion capex

General & Administrative Expenses www.blackridgeoil.com 9 $0 $10 $20 $30 $40 $50 $60 2011 2012 2013 2014 Cash G&A (1) , $/ boe (1) Cash G&A excludes stock - based compensation and is a non - GAAP financial measure.

$0 $5 $10 $15 $20 $25 $30 $35 $40 Cadence Chambers Outstanding Debt Total Availability Capital Structure www.blackridgeoil.com 10 Outstanding Debt, $MM (as of 12/31/14) Cadence Revolving Facility Senior Secured $34mm borrowing base (1) $11.4mm available LIBOR + 300/350 bps Matures: Jan 2017 Chambers Term Loan Subordinated $31.3mm drawn LIBOR + 900 bps, 400 bps PIK Matures: June 2017 (1) Borrowing base redetermined from $35mm to $34mm in March 2015

Mandaree – McKenzie County, ND Operator: EOG Resources – Antelope Extension Prospect Five Gross (0.62 net) Wells Producing IP rates very encouraging & above expectation (1) Potential Full Development (2) : 28 Gross (3.25 net) Wells on 640 - acre spacing 12 Middle Bakken Wells, 16 Three Forks Wells 100 net acres owned in adjacent spacing units: additional inventory of high value undeveloped locations www.blackridgeoil.com 11 (2) Based on publicly available data, NDIC Case File #22520 1 st Bench 2 nd Bench 3 rd Bench Middle Bakken Three Forks (1) October – December production records from NDIC unadjusted for well down time. Montana North Dakota Black Ridge interest excludes two previously drilled wells (shown in gray). T149N - R94W - 5 - 20,000 40,000 60,000 80,000 100,000 0 1 2 3 4 Mandaree 135-05H Mandaree 17-05H Mandaree 110-05H Mandaree 134-05H Mandaree 28-05H 600 EUR Month Culmulative BOEs

0 50,000 100,000 150,000 200,000 1 2 3 4 5 6 7 8 9 10 11 12 13 14 Teton – McKenzie County, ND Operator: Burlington Resources (ConocoPhillips) Twenty Eight Gross Well Spacing (1) Operator drilling twenty four wells (1.76 net) with six rigs First production expected in Q3 2015 Prolific area expected to deliver strong returns in today’s oil price environment Project will dominate 2015 capex budget www.blackridgeoil.com 12 ( 1) 2560 - acre spacing unit. Information based on publicly available data, NDIC Case File #21952 (2) Graphic is illustrative only. Actual wellbore locations and targets subject to change. (3) Production is adjusted for downtime. Comparison wells are NDIC #23645 - 23648 Montana North Dakota Proposed Middle Bakken Proposed Three Forks 2 nd Bench Proposed Three Forks 1 st Bench T150N - R96W - 3 - 10 (2) Cumulative BOE Three Forks Lateral Months of Production (3) Middle Bakken Lateral 600 MBoe EUR Curve Recent Burlington Offset Completions

Corral Creek – Dunn County, ND www.blackridgeoil.com 13 ~30,884 Gross Acres 0.77% Working Interest (WI) 3 Rig Drilling Program, 60 Well Inventory (1) Development Status: • 76 Wells Producing (0.59 Net Wells) • 32 Wells “Drilling” (0.25 Net Wells) • 8 Wells Permitted (0.06 Net Wells) ~2748 Gross Acres 6.43% WI 1 Well Producing Lincoln USA 16 - 1H: 348k bbls in 641 days Remaining Inventory (1) : 9+ Wells ~1280 Gross Acres 19.34% WI 2 Wells Producing Gorhman 24 - 31MBH Gorhman 14 - 31TFH Remaining Inventory (1) : 5+ Wells ~1280 Gross Acres 3.10% WI 4 Wells Producing Remaining Inventory (1) : 3+ Wells ~1280 Gross Acres 3.10% WI 3 Wells Producing Remaining Inventory (1) : 4+ Wells Corral Creek Unit Hansen Halliday Lincoln Gorhman Montana North Dakota T147N R93W T147N R95W T147N R94W (1) Remaining Inventory is based upon publicly available NDIC data and internal estimates.

0 50 100 150 200 250 300 350 400 2015 1st Half 2016 2nd Half 2016 2017 Swaps Collars Hedging Summary 14 www.blackridgeoil.com $89.73 $90.04 $89.73 $87.18 $75.00 - 95.60 $80.00 - 89.50 Barrels Hedged (Bo/d), WTI ($/ Bbl )

2015 Plan www.blackridgeoil.com 15 Company strategy, management execution has Black Ridge Oil & Gas on solid ground to weather current commodity price environment 4Q 2014 production of 1,190 BOE/d 4Q 2014 run rate leverage ratio < 3X (see appendix for reconciliation) Strong projects adding to reserve base 2015 Capital Program Expected development capex: $16 million (plus an additional $9 million accrued and incurred in 2014) Expected well development: 2.8 net wells Approximately 75% of net well starts attributable to Teton and CCU development projects 2015 average expected production: 1,100 boe /d Cadence Borrowing Base redetermined to $34 million, $22.6 drawn as of December 31, 2014 Company will monitor price and transaction environment to strategically divest mature producing assets with capital redeployed into higher return drilling projects.

For More Information www.blackridgeoil.com 16 Ken DeCubellis Chief Executive Officer ken.decubellis@blackridgeoil.com 952 - 426 - 1241 Stay Up to Date on Black Ridge Oil & Gas www.blackridgeoil.com

www.blackridgeoil.com 17 Appendix

Reconciliation of Net Income to Adjusted EBITDA www.blackridgeoil.com 18 Black Ridge Oil & Gas, Inc. Adjusted EBITDA by Quarter Three Months Ended March 31, June 30, September 30, December 31, 2014 2014 2014 2014 Net income (loss) $ (381,560) $ (543,360) $ 1,190,716 $ 4,086,084 Add Back: Interest expense, net, excluding amortization of warrant based financing costs 929,378 1,136,603 1,280,674 1,309,414 Income tax provision (284,023) (305,715) 700,587 2,448,346 Depreciation, depletion and amortization 1,594,857 2,139,733 2,283,917 3,370,583 Accretion of abandonment liability 4,505 5,148 5,833 6,875 Share based compensation 297,762 301,241 302,961 305,150 Unrealized loss (gain) on derivatives 214,035 881,124 (2,147,798) (6,740,782) Adjusted EBITDA $ 2,374,954 $ 3,614,774 $ 3,616,890 $ 4,785,670

Reconciliation of Net Debt Leverage Ratio www.blackridgeoil.com 19 Net Debt Leverage Ratio by Quarter Three months ended March 31, June 30, September 30, December 31, 2014 2014 2014 2014 Adjusted EBITDA $ 2,374,954 $ 3,614,774 $ 3,616,890 $ 4,785,670 X4 X4 X4 X4 Annualized adjusted EBITDA $ 9,499,816 $ 14,459,096 $ 14,467,560 $ 19,142,680 Long term debt, excluding unamortized of warrant costs and original issue discount 39,310,686 44,724,595 48,739,227 53,907,086 Less cash (60,606) (84,451) (28,239) (94,682) Net debt, excluding unamortized of warrant costs and original issue discount $ 39,250,080 $ 44,640,144 $ 48,710,988 $ 53,812,404 Net debt leverage ratio 4.13 3.09 3.37 2.81

Hedging Summary 20 www.blackridgeoil.com Swaps Settlement Period Contract Date Oil (BBLS) Fixed Price 01/01/2015 - 12/31/2015 8/9/2013 24,000 $ 88.28 01/01/2015 - 12/31/2015 4/8/2014 21,000 $ 89.70 01/01/2015 - 12/31/2015 5/21/2014 12,000 $ 92.38 01/01/2015 - 12/31/2015 9/16/2014 30,000 $ 90.76 01/01/2016 - 12/31/2016 6/25/2014 60,000 $ 90.36 01/01/2016 - 12/31/2016 9/15/2014 24,000 $ 88.15 01/01/2017 - 12/31/2017 9/15/2014 78,000 $ 87.18 Costless Collars Settlement Period Contract Date Oil (BBLS) Fixed Price 01/01/2015 - 12/31/2015 12/13/2013 36,000 $ 75.00/95.60 01/01/2016 - 06/30/2016 8/9/2013 10,002 $ 80.00/89.50