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

MINNETONKA, Minn., March 30, 2015 /PRNewswire/ -- Black Ridge Oil & Gas, Inc. ("the Company") 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.

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)

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)

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.

⁽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
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
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

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:

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 os 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.

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.

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

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)

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

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

To view the original version on PR Newswire, visit:http://www.prnewswire.com/news-releases/black-ridge-oil--gas-announces-2014-fourth-quarter-and-full-year-results-300057893.html

SOURCE Black Ridge Oil & Gas, Inc.

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