EX-99.1 2 brog_8k-ex9901.htm PRESS RELEASE

Exhibit 99.1

Black Ridge Oil & Gas Announces Third Quarter 2014 Results

and Issues Fourth Quarter 2014 Average Production Guidance

of 950 to 1,100 Boe per day

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

Third Quarter 2014 Highlights

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

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

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

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

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

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

Fourth Quarter 2014 Guidance

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

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

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

Management Comment

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

Mandaree Update

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

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

1

Third Quarter 2014 Operating and Financial Results

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

|  | Three Months Ended |  |  |  |
|  | September 30, |  |  |  |
|  | 2014 |  |  | 2013 |  |  | % Change |
Net Production: |  |  |  |  |  |  |  |  |  |  |  |
Oil (Bbl) |  |  | 62,603 |  |  |  | 26,427 |  |  |  | 137 |
Natural Gas (Mcf) |  |  | 44,639 |  |  |  | 11,535 |  |  |  | 287 |
Barrel of Oil Equivalent (Boe) |  |  | 70,043 |  |  |  | 28,349 |  |  |  | 147 |
Average Daily Production (Boe/d) |  |  | 761 |  |  |  | 308 |  |  |  | 147 |
Average Sales Prices: |  |  |  |  |  |  |  |  |  |  |  |
Oil (per Bbl) |  | $ | 84.17 |  |  | $ | 96.07 |  |  |  | (12 | )
Effect of oil hedges on average price (per Bbl) |  | $ | (1.12 | ) |  | $ | (0.80 | ) |  |  |  |
Oil net of hedging (per Bbl) |  | $ | 83.05 |  |  | $ | 95.27 |  |  |  | (13 | )
Natural Gas (per Mcf) |  | $ | 4.99 |  |  | $ | 6.41 |  |  |  | (22 | )
Effect of natural gas hedges on average price (per Mcf) |  | $ | – |  |  | $ | – |  |  |  |  |
Natural gas net of hedging (per Mcf) |  | $ | 4.99 |  |  | $ | 6.41 |  |  |  | (22 | )
Per Boe including settled derivatives |  | $ | 77.41 |  |  | $ | 91.41 |  |  |  | (15 | )
Operating Expenses (per Boe): |  |  |  |  |  |  |  |  |  |  |  |
Production Expenses |  | $ | 9.57 |  |  | $ | 9.69 |  |  |  | (1 | )
Production Taxes |  | $ | 8.41 |  |  | $ | 9.56 |  |  |  | (12 | )
G&A Expense |  | $ | 9.85 |  |  | $ | 18.51 |  |  |  | (47 | )
Depletion, Depreciation, Amortization and Accretion |  | $ | 32.69 |  |  | $ | 37.83 |  |  |  | (14 | )

Third Quarter 2014 Operational Results

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

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

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

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

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

2

Third Quarter 2014 Financial Results

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

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

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

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

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

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

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

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

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

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

The Company recorded adjusted EBITDA of $3.6 million in the third quarter of 2014, an increase of 114% compared to adjusted EBITDA of $1.7 million in the third quarter of 2013 and equaling our record $3.6 million in the second quarter of 2014. Adjusted EBITDA is a non-GAAP financial measure. Please refer to the reconciliation in this release for additional information about this measure.

3

Liquidity Position

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

Hedging Update

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

|  | Swaps |  |  | Costless Collars |
Contract period |  | Volume (Bbls) |  |  | Weighted Average Price (per Bbl) |  |  | Volume (Bbls) |  |  | Weighted Average Floor/Ceiling Price (per Bbl)
2014: |  |  |  |  |  |  |  |  |  |  |  |  |  |
Q4 |  |  | 45,000 |  |  | $ | 94.49 |  |  |  | – |  |  | -
2015: |  |  |  |  |  |  |  |  |  |  |  |  |  |
Q1 |  |  | 21,750 |  |  | $ | 89.84 |  |  |  | 9,000 |  |  | $75.00 – $95.60
Q2 |  |  | 21,750 |  |  | $ | 89.84 |  |  |  | 9,000 |  |  | $75.00 – $95.60
Q3 |  |  | 21,750 |  |  | $ | 89.84 |  |  |  | 9,000 |  |  | $75.00 – $95.60
Q4 |  |  | 21,750 |  |  | $ | 89.84 |  |  |  | 9,000 |  |  | $75.00 – $95.60
2016: |  |  |  |  |  |  |  |  |  |  |  |  |  |
Q1 |  |  | 21,000 |  |  | $ | 89.73 |  |  |  | 5,001 |  |  | $80.00 – $89.50
Q2 |  |  | 21,000 |  |  | $ | 89.73 |  |  |  | 5,001 |  |  | $80.00 – $89.50
Q3 |  |  | 21,000 |  |  | $ | 89.73 |  |  |  | – |  |  | -
Q4 |  |  | 21,000 |  |  | $ | 89.73 |  |  |  | – |  |  | -
2017: |  |  |  |  |  |  |  |  |  |  |  |  |  | -
Q1 |  |  | 19,500 |  |  | $ | 87.18 |  |  |  | – |  |  | -
Q2 |  |  | 19,500 |  |  | $ | 87.18 |  |  |  | – |  |  | -
Q3 |  |  | 19,500 |  |  | $ | 87.18 |  |  |  | – |  |  | -
Q4 |  |  | 19,500 |  |  | $ | 87.18 |  |  |  | – |  |  | -

Well Update:

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

Well | Operator | Location | WI(1)
Mandaree 110-05H | EOG | McKenzie, ND | 12.5%
Mandaree 134-05H | EOG | McKenzie, ND | 12.5%
Mandaree 135-05H | EOG | McKenzie, ND | 12.5%
Mandaree 17-05H | EOG | McKenzie, ND | 12.5%
Mandaree 28-05H | EOG | McKenzie, ND | 12.5%
Bootleg 4-14-15TFH | Slawson | Williams, ND | 11.4%
Bootleg 5-14-15TFH | Slawson | Williams, ND | 11.4%
Wallace 1-6H | Continental | Williams, ND | 8.5%
Gladys 1-20H | Continental | Williams, ND | 2.0%
Miller 157-101-12D-1-3H | Halcon | Williams, ND | 1.1%
Miller 157-101-12D-1-4H | Halcon | Williams, ND | 1.1%
CCU Corral Creek 11-28MBH | Burlington Resources | Dunn, ND | 0.8%
CCU Corral Creek 21-28TFH | Burlington Resources | Dunn, ND | 0.8%
CCU Corral Creek 31-28MBH | Burlington Resources | Dunn, ND | 0.8%
CCU Corral Creek 31-28TFH | Burlington Resources | Dunn, ND | 0.8%
CCU Four Aces 24-21MBH | Burlington Resources | Dunn, ND | 0.8%
CCU Four Aces 24-21TFH | Burlington Resources | Dunn, ND | 0.8%
CCU Four Aces 34-21MBH | Burlington Resources | Dunn, ND | 0.8%
CCU Four Aces 34-21TFH | Burlington Resources | Dunn, ND | 0.8%
CCU Olympian 11-2MBH | Burlington Resources | Dunn, ND | 0.8%
CCU Olympian 21-2TFH | Burlington Resources | Dunn, ND | 0.8%
CCU Olympian 44-35MBH | Burlington Resources | Dunn, ND | 0.8%
CCU Olympian 44-35TFH | Burlington Resources | Dunn, ND | 0.8%
Bock Federal 44-7PH | Whiting | Stark, ND | 0.6%

| (1) | The working interests are based on Black Ridge’s internal records and may be subject to change by operators' third-party legal counsel in preparing final division order title opinions for each well.

4

“Drilling” Wells: The following table sets forth Bakken and Three Forks wells in which Black Ridge holds a participating interest that are either preparing to drill, drilling, awaiting completion or completing as of September 30, 2014.

Well | Operator | Location | WI(1)
Bootleg 6-14-15TFH | Slawson | Williams, ND | 11.4%
Bootleg 7-14-15TFH | Slawson | Williams, ND | 11.3%
Bootleg 8-14-15TF2H | Slawson | Williams, ND | 11.3%
Matilda Bay 1-15H | Slawson | Williams, ND | 10.0%
Rainbow 10-19-18HBK | Samson Oil and Gas | Williams, ND | 10.0%
Billabong 2-13-14HBK | Slawson | Williams, ND | 7.5%
McCracken 2758 21-10 5B | Oasis | Roosevelt, MT | 7.1%
McCracken 2758 44-9 4B | Oasis | Roosevelt, MT | 7.1%
McCracken 2758 34-9 3B | Oasis | Roosevelt, MT | 7.1%
McCracken 2758 41-10 6B | Oasis | Roosevelt, MT | 7.1%
Teton 5-1-3TFSH | Burlington Resources | McKenzie, ND | 6.2%
Kings Canyon 6-8-34UTFH | Burlington Resources | McKenzie, ND | 6.2%
Ironbank 4-14-13TFH | Slawson | Williams, ND | 5.4%
Ironbank 5-14-13TFH | Slawson | Williams, ND | 5.4%
Ironbank 6-14-13TFH | Slawson | Williams, ND | 5.4%
Ironbank 7-14-13TFH | Slawson | Williams, ND | 5.4%
Revolver 7-35H | Slawson | Mountrail, ND | 1.6%
Little Muddy 10TFH | Triangle | Williams, ND | 0.9%
CCU Powell 41-29TFH | Burlington Resources | Dunn, ND | 0.8%
CCU Olympian 11-2TFH | Burlington Resources | Dunn, ND | 0.8%
CCU Pullman 2-8-7MBH | Burlington Resources | Dunn, ND | 0.8%
CCU Pullman 8-8-7TFH | Burlington Resources | Dunn, ND | 0.8%
CCU Pullman 7-8-7MBH | Burlington Resources | Dunn, ND | 0.8%
Jersey 23-6H1 | Continental | Mountrail, ND | 0.8%
Jersey 25-6H | Continental | Mountrail, ND | 0.8%
Jersey 26-6H2 | Continental | Mountrail, ND | 0.8%
Jersey 27-6H1 | Continental | Mountrail, ND | 0.8%
Jersey 28-6H3 | Continental | Mountrail, ND | 0.8%
Jersey 29-6XH | Continental | Mountrail, ND | 0.8%
CCU Powell 41-29MBH | Burlington Resources | Dunn, ND | 0.8%
CCU Pullman 6-8-7MBH | Burlington Resources | Dunn, ND | 0.8%
CCU Pullman 1-8-7TFH | Burlington Resources | Dunn, ND | 0.8%
CCU Pullman 3-8-7TFH | Burlington Resources | Dunn, ND | 0.8%
CCU Pullman 3-8-7MBH | Burlington Resources | Dunn, ND | 0.8%
CCU Pullman 5-8-7TFH | Burlington Resources | Dunn, ND | 0.8%
CCU Pullman 5-8-7MBH | Burlington Resources | Dunn, ND | 0.8%
CCU Pullman 6-8-7TFH | Burlington Resources | Dunn, ND | 0.8%
CCU Pullman 7-8-7TFH | Burlington Resources | Dunn, ND | 0.8%
CCU Golden Creek 44-23MBH | Burlington Resources | Dunn, ND | 0.8%

5

“Drilling” Wells (Continued):

Well | Operator | Location | WI(1)
Jersey 1-6H | Continental | Mountrail, ND | 0.8%
Jersey 3-6H1 | Continental | Mountrail, ND | 0.8%
Jersey 7-6H1 | Continental | Mountrail, ND | 0.8%
Jersey 6-6H2 | Continental | Mountrail, ND | 0.8%
Jersey 24-6H3 | Continental | Mountrail, ND | 0.8%
Aaberg 8-5N-1H | Mountain Divide | Divide, ND | 0.8%
CCU North Coast 21-25TFH | Burlington Resources | Dunn, ND | 0.8%
CCU North Coast 31-25MBH | Burlington Resources | Dunn, ND | 0.8%
CCU North Coast 4-8-23MBH | Burlington Resources | Dunn, ND | 0.8%
CCU North Coast 41-25MBH | Burlington Resources | Dunn, ND | 0.8%
CCU North Coast 4-8-23TFH | Burlington Resources | Dunn, ND | 0.8%
CCU Golden Creek 44-23TFH | Burlington Resources | Dunn, ND | 0.8%
CCU North Coast 41-25TFH | Burlington Resources | Dunn, ND | 0.8%
CCU Main Streeter 24-24TFH | Burlington Resources | Dunn, ND | 0.8%
CCU Main Streeter 14-24MBH | Burlington Resources | Dunn, ND | 0.8%
Jersey 2-6H2 | Continental | Mountrail, ND | 0.8%
Jersey 8-6H3 | Continental | Mountrail, ND | 0.8%
Jersey 5-6H | Continental | Mountrail, ND | 0.8%
Jersey 4-6H3 | Continental | Mountrail, ND | 0.8%
Oakdale 2-13H1 | Continental | Dunn, ND | 0.6%
Ryden 3-24H | Continental | Dunn, ND | 0.6%
Ryden 2-24AH1 | Continental | Dunn, ND | 0.6%
Oakdale 5-13H | Continental | Dunn, ND | 0.6%
Oakdale 3-13H | Continental | Dunn, ND | 0.6%
Oakdale 4-13H1 | Continental | Dunn, ND | 0.6%
Ryden 4-24H1 | Continental | Dunn, ND | 0.6%

| (1) | 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.

Non-GAAP Financial Measures

In addition to reporting net income (loss) as defined under GAAP, we also present Adjusted Net Income (Loss) and Adjusted EBITDA. We define Adjusted Net Income (Loss) as net income, excluding net losses on the mark-to-market of derivatives, net of tax. We define Adjusted EBITDA as net income before (i) interest expense, (ii) income taxes, (iii) depreciation, depletion and amortization, (iv) accretion of abandonment liability, (v) losses on the mark-to-market of derivatives, and (vi) non-cash expenses relating to share based payments recognized under ASC Topic 718. We believe the use of non-GAAP financial measures provides useful information to investors regarding our current financial performance; however, Adjusted Net Income (Loss) and Adjusted EBITDA do not represent, and should not be considered alternatives to GAAP measurements. We believe these measures are useful in evaluating our fundamental core operating performance. Specifically, we believe the non-GAAP Adjusted Net Income (Loss) and Adjusted EBITDA results provide useful information to both management and investors by excluding certain income and expenses that our management believes are not indicative of our core operating results. Although we use Adjusted Net Income (Loss) and Adjusted EBITDA to manage our business, including the preparation of our annual operating budget and financial projections, we believe that non-GAAP financial measures have limitations and do not reflect all of the amounts associated with our results of operations as determined in accordance with GAAP and that these measures should only be used to evaluate our results of operations in conjunction with the corresponding GAAP financial measures. A reconciliation of Adjusted Net Income (Loss) and Adjusted EBITDA to Net Income, GAAP, is included below:

6

Black Ridge Oil & Gas, Inc.

Reconciliation of Adjusted Net Income (Loss)

(Unaudited)

|  | Three Months Ended |  |  | Nine Months Ended |
|  | September 30, |  |  | September 30, |
|  | 2014 |  |  | 2013 |  |  | 2014 |  |  | 2013 |
Net Income (Loss) |  | $ | 1,190,716 |  |  | $ | (223,664 | ) |  | $ | 265,796 |  |  | $ | (207,151 | )
Add back: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Loss (gain) on mark-to-market of derivatives, net of tax (a) |  |  | (1,352,798 | ) |  |  | 29,225 |  |  |  | (663,639 | ) |  |  | 29,225 |
Adjusted Net Income (Loss) |  | $ | (162,082 | ) |  | $ | (194,439 | ) |  | $ | (397,843 | ) |  | $ | (177,926 | )
Weighted average common shares outstanding - basic |  |  | 47,979,990 |  |  |  | 47,979,990 |  |  |  | 47,979,990 |  |  |  | 47,979,990 |
Weighted average common shares outstanding - fully diluted |  |  | 49,588,039 |  |  |  | 47,979,990 |  |  |  | 49,824,437 |  |  |  | 47,979,990 |
Net income (loss) per common share – basic |  | $ | 0.02 |  |  | $ | (0.00 | ) |  | $ | 0.01 |  |  | $ | (0.00 | )
Subtract: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Change due to loss (gain) on mark-to- market of derivatives, net of tax |  |  | (0.03 | ) |  |  | 0.00 |  |  |  | (0.01 | ) |  |  | 0.00 |
Adjusted Net Income (loss) per common share - basic |  | $ | (0.00 | ) |  | $ | (0.00 | ) |  | $ | (0.01 | ) |  | $ | (0.00 | )
Net income (loss) per common share - fully diluted |  |  | 0.02 |  |  |  | (0.00 | ) |  |  | 0.01 |  |  | $ | 0.00 |
Subtract: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Change due to loss (gain) on mark-to- market of derivatives, net of tax |  |  | (0.03 | ) |  |  | 0.00 |  |  |  | (0.01 | ) |  |  | 0.00 |
Adjusted Net Income (Loss) per common share - fully diluted |  | $ | (0.00 | ) |  | $ | (0.00 | ) |  | $ | (0.01 | ) |  | $ | (0.00 | )

_____________________________

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

Black Ridge Oil & Gas, Inc.

Reconciliation of Adjusted EBITDA

(Unaudited)

|  | Three Months Ended |  |  | Nine Months Ended |
|  | September 30, |  |  | September 30, |
|  | 2014 |  |  | 2013 |  |  | 2014 |  |  | 2013 |
Net Income (loss) |  | $ | 1,190,716 |  |  | $ | (223,664 | ) |  | $ | 265,796 |  |  | $ | (207,151 | )
Add Back: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Interest Expense, net, excluding amortization |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
of warrant based financing costs |  |  | 1,280,674 |  |  |  | 622,842 |  |  |  | 3,346,655 |  |  |  | 1,365,898 |
Income Tax Provision |  |  | 700,587 |  |  |  | (88,708 | ) |  |  | 110,849 |  |  |  | (615,409 | )
Depreciation, Depletion, and Amortization |  |  | 2,283,917 |  |  |  | 1,070,753 |  |  |  | 6,018,507 |  |  |  | 2,650,763 |
Accretion of Abandonment Liability |  |  | 5,833 |  |  |  | 1,811 |  |  |  | 15,486 |  |  |  | 4,774 |
Share Based Compensation |  |  | 302,961 |  |  |  | 263,379 |  |  |  | 901,964 |  |  |  | 658,977 |
Loss (gain) on mark-to market of derivatives |  |  | (2,147,798 | ) |  |  | 46,225 |  |  |  | (1,052,639 | ) |  |  | 46,225 |
Adjusted EBITDA |  | $ | 3,616,890 |  |  | $ | 1,692,638 |  |  | $ | 9,606,618 |  |  | $ | 3,904,077 |

7

Financial and Statistical Data Tables

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

BLACK RIDGE OIL & GAS, INC.

CONDENSED BALANCE SHEETS

|  | September 30, |  |  | December 31, |
|  | 2014 |  |  | 2013 |
ASSETS |  |  | (Unaudited) |  |  |  |  |
Current assets: |  |  |  |  |  |  |  |
Cash and cash equivalents |  | $ | 28,239 |  |  | $ | 1,150,347 |
Derivative instruments |  |  | 287,421 |  |  |  | – |
Accounts receivable |  |  | 3,139,049 |  |  |  | 1,905,467 |
Advances to operators |  |  | 2,656,697 |  |  |  | 1,214,662 |
Prepaid expenses |  |  | 72,058 |  |  |  | 26,142 |
Total current assets |  |  | 6,183,464 |  |  |  | 4,296,618 |
Property and equipment: |  |  |  |  |  |  |  |
Oil and natural gas properties, full cost method of accounting: |  |  |  |  |  |  |  |
Proved properties |  |  | 104,227,772 |  |  |  | 79,361,432 |
Unproved properties |  |  | 2,151,044 |  |  |  | 2,798,795 |
Other property and equipment |  |  | 126,613 |  |  |  | 115,482 |
Total property and equipment |  |  | 106,505,429 |  |  |  | 82,275,709 |
Less, accumulated depreciation, amortization, depletion and allowance for impairment |  |  | (15,531,941 | ) |  |  | (9,513,434 | )
Total property and equipment, net |  |  | 90,973,488 |  |  |  | 72,762,275 |
Derivative instruments |  |  | 551,542 |  |  |  | – |
Debt issuance costs, net |  |  | 797,341 |  |  |  | 772,883 |
Total assets |  | $ | 98,505,835 |  |  | $ | 77,831,776 |
LIABILITIES AND STOCKHOLDERS' EQUITY |  |  |  |  |  |  |  |
Current liabilities: |  |  |  |  |  |  |  |
Accounts payable |  | $ | 12,484,201 |  |  | $ | 8,453,709 |
Accrued expenses |  |  | 66,236 |  |  |  | 4,813 |
Current portion of derivative instruments |  |  | – |  |  |  | 139,065 |
Total current liabilities |  |  | 12,550,437 |  |  |  | 8,597,587 |
Derivative instruments |  |  | – |  |  |  | 74,611 |
Asset retirement obligations |  |  | 237,966 |  |  |  | 160,665 |
Revolving credit facilities and long term debt, net of discounts of $2,274,346 and $2,645,582, respectively |  |  | 46,464,881 |  |  |  | 30,556,301 |
Deferred tax liability |  |  | 4,144,694 |  |  |  | 4,033,845 |
Total liabilities |  |  | 63,397,978 |  |  |  | 43,423,009 |
Commitments and contingencies (See note 15) |  |  | – |  |  |  | – |
Stockholders' equity: |  |  |  |  |  |  |  |
Preferred stock, $0.001 par value, 20,000,000 shares authorized, no shares issued and outstanding |  |  | – |  |  |  | – |
Common stock, $0.001 par value, 500,000,000 shares authorized, 47,979,990 shares issued and outstanding |  |  | 47,980 |  |  |  | 47,980 |
Additional paid-in capital |  |  | 33,506,089 |  |  |  | 33,072,795 |
Retained earnings |  |  | 1,553,788 |  |  |  | 1,287,992 |
Total stockholders' equity |  |  | 35,107,857 |  |  |  | 34,408,767 |
Total liabilities and stockholders' equity |  | $ | 98,505,835 |  |  | $ | 77,831,776 |

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BLACK RIDGE OIL & GAS, INC.

CONDENSED STATEMENTS OF OPERATIONS

(Unaudited)

|  | For the Three Months |  |  | For the Nine Months |
|  | Ended September 30, |  |  | Ended September 30, |
|  | 2014 |  |  | 2013 |  |  | 2014 |  |  | 2013 |
Oil and gas sales |  | $ | 5,492,326 |  |  | $ | 2,612,640 |  |  | $ | 15,076,743 |  |  | $ | 6,674,940 |
Loss on settled derivatives |  |  | (70,253 | ) |  |  | (21,184 | ) |  |  | (449,135 | ) |  |  | (21,184 | )
Gain (loss) on the mark-to-market of derivatives |  |  | 2,147,798 |  |  |  | (46,225 | ) |  |  | 1,052,639 |  |  |  | (46,225 | )
Total revenues |  |  | 7,569,871 |  |  |  | 2,545,231 |  |  |  | 15,680,247 |  |  |  | 6,607,531 |
Operating expenses: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Production expenses |  |  | 670,404 |  |  |  | 274,756 |  |  |  | 1,773,458 |  |  |  | 813,023 |
Production taxes |  |  | 588,923 |  |  |  | 271,116 |  |  |  | 1,585,755 |  |  |  | 722,986 |
General and administrative |  |  | 690,189 |  |  |  | 524,849 |  |  |  | 2,095,071 |  |  |  | 1,715,287 |
Depletion of oil and gas properties |  |  | 2,275,703 |  |  |  | 1,064,921 |  |  |  | 5,994,180 |  |  |  | 2,633,309 |
Accretion of discount on asset retirement obligations |  |  | 5,833 |  |  |  | 1,811 |  |  |  | 15,486 |  |  |  | 4,774 |
Depreciation and amortization |  |  | 8,214 |  |  |  | 5,832 |  |  |  | 24,327 |  |  |  | 17,454 |
Total operating expenses |  |  | 4,239,266 |  |  |  | 2,143,285 |  |  |  | 11,488,277 |  |  |  | 5,906,833 |
Net operating income |  |  | 3,330,605 |  |  |  | 401,946 |  |  |  | 4,191,970 |  |  |  | 700,698 |
Other income (expense): |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Interest income |  |  | 972 |  |  |  | 148 |  |  |  | 972 |  |  |  | 341 |
Interest (expense) |  |  | (1,440,274 | ) |  |  | (714,466 | ) |  |  | (3,816,297 | ) |  |  | (1,523,599 | )
Total other income (expense) |  |  | (1,439,302 | ) |  |  | (714,318 | ) |  |  | (3,815,325 | ) |  |  | (1,523,258 | )
Income (loss) before provision for income taxes |  |  | 1,891,303 |  |  |  | (312,372 | ) |  |  | 376,645 |  |  |  | (822,560 | )
Provision for income taxes |  |  | (700,587 | ) |  |  | 88,708 |  |  |  | (110,849 | ) |  |  | 615,409 |
Net income (loss) |  | $ | 1,190,716 |  |  | $ | (223,664 | ) |  | $ | 265,796 |  |  | $ | (207,151 | )
Weighted average common shares outstanding - basic |  |  | 47,979,990 |  |  |  | 47,979,990 |  |  |  | 47,979,990 |  |  |  | 47,979,990 |
Weighted average common shares outstanding - fully diluted |  |  | 49,588,039 |  |  |  | 47,979,990 |  |  |  | 49,824,437 |  |  |  | 47,979,990 |
Net income (loss) per common share - basic |  | $ | 0.02 |  |  | $ | (0.00 | ) |  | $ | 0.01 |  |  | $ | (0.00 | )
Net income (loss) per common share - fully diluted |  | $ | 0.02 |  |  | $ | (0.00 | ) |  | $ | 0.01 |  |  | $ | (0.00 | )

9

BLACK RIDGE OIL & GAS, INC.

CONDENSED STATEMENTS OF CASH FLOWS

(Unaudited)

|  | For the Nine Months |
|  | Ended September 30, |
|  | 2014 |  |  | 2013 |
CASH FLOWS FROM OPERATING ACTIVITIES |  |  |  |  |  |  |  |
Net income (loss) |  | $ | 265,796 |  |  | $ | (207,151 | )
Adjustments to reconcile net income (loss) to net cash provided by operating activities: |  |  |  |  |  |  |  |
Depletion of oil and gas properties |  |  | 5,994,180 |  |  |  | 2,633,309 |
Depreciation and amortization |  |  | 24,327 |  |  |  | 17,454 |
Amortization of debt issuance costs |  |  | 229,936 |  |  |  | 691,928 |
Accretion of discount on asset retirement obligations |  |  | 15,486 |  |  |  | 4,774 |
Loss (gain) on the mark-to-market of derivatives |  |  | (1,052,639 | ) |  |  | 46,225 |
Accrued payment in kind interest applied to long term debt |  |  | 787,344 |  |  |  | 36,667 |
Amortization of original issue discount on debt |  |  | 102,566 |  |  |  | 6,457 |
Amortization of debt discounts, warrants |  |  | 468,670 |  |  |  | 49,170 |
Common stock warrants granted as financing costs |  |  | – |  |  |  | 108,190 |
Common stock options issued to employees and directors |  |  | 433,294 |  |  |  | 501,617 |
Deferred income taxes |  |  | 110,849 |  |  |  | (615,409 | )
Decrease (increase) in current assets: |  |  |  |  |  |  |  |
Accounts receivable |  |  | (1,233,582 | ) |  |  | (1,288,026 | )
Prepaid expenses |  |  | (45,916 | ) |  |  | 16,364 |
Increase (decrease) in current liabilities: |  |  |  |  |  |  |  |
Accounts payable |  |  | 223,779 |  |  |  | (216,975 | )
Accrued expenses |  |  | 61,423 |  |  |  | 35,250 |
Net cash provided by operating activities |  |  | 6,385,513 |  |  |  | 1,819,844 |
CASH FLOWS FROM INVESTING ACTIVITIES |  |  |  |  |  |  |  |
Proceeds from sale or swap of oil and gas properties |  |  | 1,360,920 |  |  |  | 500,031 |
Purchases of oil and gas properties and development capital expenditures |  |  | (17,410,744 | ) |  |  | (5,991,601 | )
Advances to operators |  |  | (5,742,272 | ) |  |  | (882,604 | )
Purchases of other property and equipment |  |  | (11,131 | ) |  |  | (1,301 | )
Net cash used in investing activities |  |  | (21,803,227 | ) |  |  | (6,375,475 | )
CASH FLOWS FROM FINANCING ACTIVITIES |  |  |  |  |  |  |  |
Advances from revolving credit facilities and long term debt |  |  | 24,150,000 |  |  |  | 22,000,000 |
Repayments on revolving credit facilities |  |  | (9,600,000 | ) |  |  | (13,048,844 | )
Debt issuance costs |  |  | (254,394 | ) |  |  | (725,887 | )
Net cash provided by financing activities |  |  | 14,295,606 |  |  |  | 8,225,269 |
NET CHANGE IN CASH |  |  | (1,122,108 | ) |  |  | 3,669,638 |
CASH AT BEGINNING OF PERIOD |  |  | 1,150,347 |  |  |  | 1,417,340 |
CASH AT END OF PERIOD |  | $ | 28,239 |  |  | $ | 5,086,978 |
SUPPLEMENTAL INFORMATION: |  |  |  |  |  |  |  |
Interest paid |  | $ | 2,411,463 |  |  | $ | 551,399 |
Income taxes paid |  | $ | – |  |  | $ | – |
NON-CASH INVESTING AND FINANCING ACTIVITIES: |  |  |  |  |  |  |  |
Net change in accounts payable for purchase of oil and gas properties |  | $ | 3,821,375 |  |  | $ | 2,277,913 |
Advances to operators paid in swap for oil and gas properties |  | $ | – |  |  | $ | (1,200,000 | )
Advances to operators applied to development of oil and gas properties |  | $ | 4,285,575 |  |  | $ | 2,212,323 |
Capitalized asset retirement costs, net of revision in estimate |  | $ | 61,815 |  |  | $ | 10,400 |
Fair value of detachable warrants granted in consideration of debt financing |  | $ | – |  |  | $ | 2,473,576 |

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Upcoming Conference Presentation Schedule

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

SeeThruEquity Microcap Investor Conference

November 12, 2014

Convene Midtown East, New York, NY

Midwest Investment Conference

November 18, 2014

Cleveland Convention Center, Cleveland, OH

Cautionary Statement as to Forward-Looking Statements

Certain statements contained herein, which are not historical, are forward-looking statements that are subject to risks and uncertainties not known or disclosed herein that could cause actual results to differ materially from those expressed herein. These statements may include projections and other "forward-looking statements" within the meaning of the federal securities laws. Any such projections or statements reflect Black Ridge Oil & Gas current views about future events and financial performance. No assurances can be given that such events or performance will occur as projected and actual results may differ materially from those projected. Important factors that could cause the actual results to differ materially from those projected include, without limitation, general economic or industry conditions nationally and/or in the communities in which our Company conducts business, volatility in commodity prices for crude oil and natural gas, environmental risks, legislation or regulatory requirements, conditions of the securities markets, our ability to raise capital or have access to debt financing, changes in accounting principles, policies or guidelines, financial or political instability, acts of war or terrorism, increases in operator costs, other economic, competitive, governmental, regulatory and technical factors affecting our Company's operations, products, services and prices and other risks inherent in the Company's businesses that are detailed in the Company's Securities and Exchange Commission ("SEC") filings. Readers are encouraged to review these risks in the Company's SEC filings.

About Black Ridge Oil & Gas

Black Ridge Oil & Gas is a growth-oriented oil and gas exploration and production company based in Minnetonka, Minnesota. Black Ridge's focus is exclusive to the Williston Basin Bakken and Three Forks trend in North Dakota and Montana. Black Ridge Oil & Gas controls approximately 10,000 net acres prospective for Bakken and/or Three Forks development. For additional information, visit the Company's website at www.blackridgeoil.com.

To receive timely information on Black Ridge Oil & Gas when it hits the newswire, sign up for Black Ridge's email news alert system today at http://ir.stockpr.com/blackridgeoil/email-alerts.

Contact:

Ken DeCubellis

Chief Executive Officer

952-426-1241

ken.decubellis@blackridgeoil.com

Source: Black Ridge Oil & Gas, Inc.

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