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): August 13, 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 August 13, 2015, Black Ridge Oil & Gas, Inc. (“Black Ridge”) issued a press release regarding its financial results for the second quarter of 2015 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. These measures 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 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.
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. In addition, Black Ridge will be presenting at EnerCom's The Oil & Gas Conference® on Tuesday, August 18, 2015, in Denver, Colorado regarding its operations and business and will present the materials in the PowerPoint slide presentation 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) |
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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: August 13, 2015 |
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Exhibit 99.1
Black Ridge Oil & Gas Announces Second Quarter 2015 Results
MINNETONKA, Minn., August 13, 2015 - Black Ridge Oil & Gas, Inc. ("the Company") (OTCQB: ANFC), a growth-oriented exploration and production company focused on non-operated Bakken and Three Forks properties, today announced financial and operating results for the three and six months ended June 30, 2015.
Second Quarter 2015 Company Highlights
· | Quarterly production increased 57% over the second quarter of 2014 to 102.2 thousand barrels of oil equivalent (“MBoe”), an average of approximately 1,123 barrels of oil equivalent per day (“Boe/d”) |
· | Oil and gas sales totaled $5.1 million, an increase of 75% over the first quarter of 2015 and a decrease of 9% from the second quarter of 2014 |
· | Added 5 gross (0.17 net) wells, increasing our total producing well count to 291 gross (8.96 net), an increase of 43% over the second quarter of 2014 |
· | Recorded $3.6 million of adjusted EBITDA, equal to the EBITDA generated in the second quarter of 2014 |
· | Reduced general and administrative expenses to $7.15 per Boe, a decrease of 27% from the second quarter of 2014 |
· | Recorded GAAP net loss for the quarter of $0.39 per diluted share, impacted by a non-cash impairment of $21.6 million ($0.34 per diluted share, net of tax effect) |
· | Announced the formation of a strategic partnership with Merced Capital, focused on acquiring non-operated assets in the Williston Basin |
· | Continued the development of the Teton project (1.76 net wells) with strong initial production rates |
· | During and subsequent to the second quarter, entered into swap contracts to sell an additional 237,000 barrels of oil at a weighted average price of $60.40. |
Teton Project Update and Production Guidance
The drilling, completion and flowback of the Teton project is running ahead of the Company’s original plan, and the daily production volumes achieved during the flowback phase were higher than our initial estimates. The transition from flowback to full production will occur after all of the Teton wells are connected to permanent production facilities, and at this stage, the natural gas tie-in is running behind schedule. While we are very encouraged by the production rates achieved during flowback, we are not updating our full year production guidance of 1,200 Boe/d until we receive clarity on the timing of the facility completion.
The following table summarizes the flowback status of the Teton project as of August 10, 2015. The operator’s flowback procedure limited production to less than 15,000 barrels of oil per well. Flowback commenced in late June and is expected to end on approximately August 15.
WELL | W.I. | Current Status | Flowback Information | ||
Bbls Oil Produced | MCF Gas Produced | # of Days | |||
Teton 2-8-10MBH | 8.4% | Flowback Complete, Waiting on Facilities | 14,839 | 24,020 | 6 |
Teton 6-8-10MBH | 8.4% | Flowback Complete, Waiting on Facilities | 14,656 | 27,510 | 6 |
Teton 7-8-10MBH | 8.4% | Flowback Complete, Waiting on Facilities | 14,785 | 22,171 | 7 |
Teton 8-8-10TFSH | 8.4% | Flowback Complete, Waiting on Facilities | 14,789 | 21,645 | 7 |
Teton 5-1-3TFSH | 8.4% | Flowback Complete, Waiting on Facilities | 14,732 | 16,173 | 8 |
Teton 6-8-10TFSH | 8.4% | Flowback Complete, Waiting on Facilities | 14,883 | 23,203 | 8 |
Teton 5-8-10MBH | 8.4% | Flowback Complete, Waiting on Facilities | 14,280 | 21,591 | 8 |
Teton 7-1-3TFSH | 8.4% | Flowback Complete, Waiting on Facilities | 14,835 | 25,283 | 8 |
Kings Canyon 6-1-27MBH | 8.4% | Flowback Complete, Waiting on Facilities | 14,699 | 10,225 | 9 |
Kings Canyon 7-8-34MBH | 8.4% | Flowback Complete, Waiting on Facilities | 14,805 | 28,901 | 9 |
Teton 3-8-10MBH | 8.4% | Flowback Complete, Waiting on Facilities | 14,861 | 23,839 | 9 |
Kings Canyon 2-8-34UTFH | 8.4% | Flowback Complete, Waiting on Facilities | 14,224 | 14,066 | 11 |
Kings Canyon 4-8-34UTFH | 8.4% | Flowback Complete, Waiting on Facilities | 14,696 | 19,730 | 11 |
Kings Canyon 6-8-34UTFH | 8.4% | Flowback Complete, Waiting on Facilities | 14,087 | 25,180 | 11 |
Kings Canyon 4-1-27MTFH | 8.4% | Flowback Complete, Waiting on Facilities | 14,691 | 11,371 | 11 |
Kings Canyon 4-8-34MBH | 8.4% | Flowback Complete, Waiting on Facilities | 12,806 | 16,552 | 12 |
Kings Canyon 5-8-34UTFH | 8.4% | Flowback Complete, Waiting on Facilities | 14,764 | 17,500 | 12 |
Kings Canyon 6-1-27MTFH | 8.4% | Flowback in Process | 11,391 | 13,050 | 8 |
Kings Canyon 3-1-27MTFH | 8.4% | Flowback in Process | 9,701 | 14,606 | 11 |
RemingTeton 8-8-10 MBH | 6.3% | Flowback Complete, Waiting on Facilities | 14,805 | 20,641 | 7 |
TetoNorman 1-1-3UTFH | 6.3% | Flowback Complete, Waiting on Facilities | 14,736 | 16,696 | 9 |
LaCanyon 8-8-34MBH | 2.1% | Flowback Complete, Waiting on Facilities | 14,794 | 25,880 | 7 |
DeKing 1-8-34MBH-ULW | 2.1% | Flowback Complete, Waiting on Facilities | 14,713 | 22,758 | 9 |
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Management Comment
”The Company is excited by the initial results from our Teton project and we look forward to full production and cash flow from this asset,” said Ken DeCubellis, Chief Executive Officer. “We added additional hedges in May and July to protect our balance sheet, maintain ample cash flow and preserve our asset value during this down cycle in oil prices. As we look forward to the remainder of 2015 and 2016, the Company’s focus will be on allocating our free cash flow to debt reduction and finding acquisition opportunities for our joint venture with Merced.”
Liquidity Position and Borrowing Base
Black Ridge ended the quarter with $29.75 million drawn on its $34 million senior secured revolving credit facility. The next redetermination date is scheduled for October 1, 2015. The Company expects to fund 2015 development from availability under the borrowing base and cash flow from operations.
Hedging Update
In the second quarter of 2015, the Company realized an $847,198 gain on settled derivatives, and a $1,956,155 unrealized loss on mark-to-market adjustments to its outstanding derivatives contracts. As of June 30, 2015, the Company’s net derivative asset was $5,990,919. On July 22, 2015, the Company entered into new crude oil swap contracts for 18,000 barrels in 2H 2016 at $55.55, 42,000 barrels in 2017 at $57.95 and 96,000 barrels at $60.67 in 2018. The following table summarizes the Company’s open crude oil swap contracts as of August 12, 2015:
Oil | Weighted Average | |||
Term | (barrels) | Price ($ per Bbl) | ||
2015: | ||||
Q3 | 21,750 | 89.84 | ||
Q4 | 57,750 | 72.40 | ||
2016: | ||||
Q1 | 43,500 | 75.84 | ||
Q2 | 43,500 | 75.84 | ||
Q3 | 30,000 | 79.47 | ||
Q4 | 30,000 | 79.47 | ||
2017: | ||||
Q1 | 30,000 | 76.95 | ||
Q2 | 30,000 | 76.95 | ||
Q3 | 30,000 | 76.95 | ||
Q4 | 30,000 | 76.95 | ||
2018: | ||||
Q1 | 24,000 | 60.67 | ||
Q2 | 24,000 | 60.67 | ||
Q3 | 24,000 | 60.67 | ||
Q4 | 24,000 | 60.67 |
In addition to the open crude oil swap contracts, the Company has entered into costless collar contracts. The costless collars are used to establish floor and ceiling prices on anticipated crude oil production. There were no premiums paid or received by us related to the costless collar contracts. The following table reflects open costless collar crude oil contracts as of August 12, 2015:
Oil | Floor/Ceiling | |||||
Term | (Barrels) | Price (WTI) | Basis | |||
Costless Collars – Crude Oil | ||||||
07/01/2015 – 12/31/2015 | 18,000 | $75.00/$95.60 | NYMEX | |||
01/01/2016 – 06/30/2016 | 10,002 | $80.00/$89.50 | NYMEX |
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2015 Operating and Financial Results
The following table presents selected operating and financial data for the periods indicated.
Three Months Ended | Six Months Ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
2015 | 2014 | 2015 | 2014 | |||||||||||||
Net Production: | ||||||||||||||||
Oil (Bbl) | 90,118 | 58,812 | 163,041 | 101,967 | ||||||||||||
Natural gas (Mcf) | 72,381 | 37,482 | 170,695 | 61,819 | ||||||||||||
Barrel of oil equivalent (Boe) | 102,182 | 65,059 | 191,490 | 112,270 | ||||||||||||
Average Sales Prices: | ||||||||||||||||
Oil (per Bbl) | $ | 54.71 | $ | 91.27 | $ | 47.06 | $ | 89.88 | ||||||||
Effect of oil hedges on average price (per Bbl) | $ | 9.40 | $ | (4.47 | ) | $ | 12.15 | $ | (3.71 | ) | ||||||
Oil net of hedging (per Bbl) | $ | 64.11 | $ | 86.80 | $ | 59.21 | $ | 86.17 | ||||||||
Natural gas (per Mcf) | $ | 1.66 | $ | 4.97 | $ | 1.55 | $ | 6.78 | ||||||||
Realized price, net of settled derivatives (Boe) | $ | 57.71 | $ | 81.33 | $ | 51.79 | $ | 81.99 | ||||||||
Average Production Costs: | ||||||||||||||||
Oil (per Bbl) | $ | 12.50 | $ | 9.79 | $ | 12.68 | $ | 9.85 | ||||||||
Natural gas (per Mcf) | $ | 0.38 | $ | 0.53 | $ | 0.45 | $ | 0.75 | ||||||||
Barrel of oil equivalent (Boe) | $ | 11.29 | $ | 9.15 | $ | 11.19 | $ | 9.36 | ||||||||
Dahl Federal Recognition
During the second quarter of 2015, the Company recognized all well costs, revenues, and expenses related to the Dahl Federal 2-15H well back to the inception of the well in January of 2012. Due to uncertainties regarding the Company’s ownership of this interest related to the State of North Dakota’s claim to mineral rights under the Missouri River, the Company had not previously recognized any well costs, revenues, or expenses for this well. As these uncertainties are now resolved, in the second quarter of 2015, the Company recognized $1.3 million of oil and gas revenues, $83,000 of production expenses, $140,000 of production taxes, and production of 15,682 net Boe from prior periods. The Company also capitalized $0.9 million of well costs related to the drilling and completion of the well. Please see the Company’s 10-Q filing for additional information.
Second Quarter 2015 Financial Results
In the second quarter of 2015, oil and gas sales, excluding the impact of settled derivatives, were $5.05 million, a decrease of 9% as compared to the second quarter of 2014. The Company realized an average price of $54.71 per barrel of oil and $1.66 per mcf of gas, representing decreases of 40% and 67%, respectively, as compared to the second quarter of 2014. The impact of weaker commodity prices was partially offset by a 57% increase in production over the second quarter of 2014. The Company’s production in the second quarter of 2015 was comprised of 88% oil and 12% natural gas and natural gas liquids, on a Boe basis.
For the second quarter of 2015, the Company realized a gain on settled derivatives of $0.8 million, compared to a loss of $0.3 million in the second quarter of 2014. The Company had a mark-to-market derivative loss of $2.0 million in the second quarter of 2015 compared to a mark-to-market loss of $0.9 million in the second quarter of 2014.
3 |
Production expenses for the second quarter of 2015 were $1.2 million, or $11.29 per Boe, compared to $0.6 million, or $9.15 per Boe, for the second quarter of 2014. The increase in production expense in the second quarter was primarily attributable to cleanout costs on producing wells subsequent to completion activities on offset locations in the Company’s Stockyard Creek project.
Production taxes for the second quarter of 2015 were $0.6 million, compared to $0.6 million, for the second quarter of 2014. Production taxes as a percent of revenue were 11.0% for the second quarter of 2015, compared to 10.7% for the second quarter of 2014.
Depletion, depreciation, amortization and accretion (“DD&A”) was $2.9 million, or $28.87 per Boe, in the second quarter of 2015, compared to $2.1 million, or $32.97 per Boe, in the second quarter of 2014.
As a result of the currently prevailing low commodity prices and their effect on the proved reserve values of properties in 2015, we recorded a non-cash ceiling test impairment of $21.6 million in the second quarter of 2015. The Company did not have any impairment of its proved oil and gas properties in the second quarter of 2014. The impairment charge affected our reported net income but did not reduce our cash flow.
General and administrative expenses (“G&A”) for the second quarter of 2015 were $0.7 million, or $7.15 per Boe, compared to $0.6 million, or $9.75 per Boe, for the second quarter of 2014. Cash G&A (non-GAAP, excludes stock-based compensation expense) was $0.6 million, or $5.65 per Boe, for the second quarter of 2015 compared to $0.5 million, or $7.52 per Boe, for the second quarter of 2014.
Interest expense, net of capitalized interest, was $1.6 million in the second quarter of 2015, compared to $1.3 million in the second quarter of 2014. The increase in interest expense was primarily due to additional borrowing to fund the Company’s capital development program.
The income tax benefit recognized during the second quarter of 2015 was $6.0 million, or 24.2% of the loss before income taxes, as compared to a net income tax benefit of $0.3 million, or 36.0% of the loss before income taxes, in the second quarter of 2014. The lower effective tax rate in 2015 relates to a valuation allowance placed on the net deferred tax asset in the second quarter of 2015.
The Company recorded $3.6 million of adjusted EBITDA in the second quarter of 2015, flat compared to 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.
Acreage and Drilling
As of June 30, 2015, the Company controlled approximately 8,600 net acres in the Williston Basin. Approximately 72% of the acreage is held by production with 291 gross (8.96 net) wells producing. Additionally, the Company had 2.04 net wells in development as of June 30, 2015.
4 |
Producing Wells
The following table sets forth wells in which Black Ridge holds a participating interest that were completed, acquired, or first recognized during the quarter ending June 30, 2015:
Well | Operator | Location | WI(1) |
Dahl Federal 2-15H | SM Energy | McKenzie, ND | 8.7% |
Tetonorman 1-1-3UTFH ULW | Burlington Resources | McKenzie, ND | 6.3% |
DeKing 1-8-34MBH-ULW | Burlington Resources | McKenzie, ND | 2.1% |
P Jackman 156-100-2-18-6-1H | Whiting | Williams, ND | 1.0% |
P Jackman 156-100-2-18-6-2H | Whiting | Williams, ND | 1.0% |
CCU North Coast 31-25TFH | Burlington Resources | Dunn, ND | 0.8% |
(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 June 30, 2015:
Well | Operator | Location | WI(1) |
Kings Canyon 5-8-34UTF | Burlington Resources | McKenzie, ND | 8.4% |
Teton 5-8-10MBH | Burlington Resources | McKenzie, ND | 8.4% |
Kings Canyon 6-1-27MBH | Burlington Resources | McKenzie, ND | 8.4% |
Kings Canyon 6-1-27MTFH | Burlington Resources | McKenzie, ND | 8.4% |
Kings Canyon 4-1-27MTFH | Burlington Resources | McKenzie, ND | 8.4% |
Kings Canyon 3-1-27MTFH | Burlington Resources | McKenzie, ND | 8.4% |
Kings Canyon 6-8-34UTFH | Burlington Resources | McKenzie, ND | 8.4% |
Kings Canyon 2-8-34UTFH | Burlington Resources | McKenzie, ND | 8.4% |
Kings Canyon 4-8-34UTFH | Burlington Resources | McKenzie, ND | 8.4% |
Kings Canyon 4-8-34MBH | Burlington Resources | McKenzie, ND | 8.4% |
Teton 5-1-3TFSH | Burlington Resources | McKenzie, ND | 8.4% |
Teton 2-8-10MBH | Burlington Resources | McKenzie, ND | 8.4% |
Teton 3-8-10MBH | Burlington Resources | McKenzie, ND | 8.4% |
Teton 6-8-10TFSH | Burlington Resources | McKenzie, ND | 8.4% |
Teton 8-8-10TFSH | Burlington Resources | McKenzie, ND | 8.4% |
Teton 7-8-10MBH | Burlington Resources | McKenzie, ND | 8.4% |
Teton 6-8-10MBH | Burlington Resources | McKenzie, ND | 8.4% |
Teton 7-1-3TFSH | Burlington Resources | McKenzie, ND | 8.4% |
Kings Canyon 7-8-34MBH | Burlington Resources | McKenzie, ND | 8.4% |
Remingteton 8-8-10MBH | Burlington Resources | McKenzie, ND | 6.2% |
Thorp Federal 11X-28A | XTO | Dunn, ND | 3.4% |
LaCanyon 8-8-34MBH ULW | Burlington Resources | McKenzie, ND | 2.1% |
EN-Weyrauch B-LW-154-93-3031H-1 | Hess | Mountrail, ND | 1.6% |
P Berger 156-100-14-7-6-4H | Whiting | Williams, ND | 1.0% |
P Berger 156-100-14-7-6-3H | Whiting | Williams, ND | 1.0% |
5 |
Aaberg 8-5N-1H | Mountain Divide | Divide, ND | 0.8% |
CCU Powell 41-29TFH | Burlington Resources | Dunn, ND | 0.8% |
CCU Dakotan 2-7-17MBH | Burlington Resources | Dunn, ND | 0.8% |
CCU Dakotan 1-7-17TFH | Burlington Resources | Dunn, ND | 0.8% |
CCU Dakotan 1-7-17MBH | Burlington Resources | Dunn, ND | 0.8% |
CCU Dakotan 2-7-17TFH | Burlington Resources | Dunn, ND | 0.8% |
CCU Dakotan 5-8-17TFH | Burlington Resources | Dunn, ND | 0.8% |
CCU Dakotan 6-8-17MBH | Burlington Resources | Dunn, ND | 0.8% |
CCU Dakotan 7-8-17TFH | Burlington Resources | Dunn, ND | 0.8% |
CCU Dakotan 7-8-17MBH | Burlington Resources | Dunn, ND | 0.8% |
CCU Dakotan 5-8-17MBH | Burlington Resources | Dunn, ND | 0.8% |
CCU Dakotan 4-8-17TFH | Burlington Resources | Dunn, ND | 0.8% |
CCU Dakotan 3-8-17MBH | Burlington Resources | Dunn, ND | 0.8% |
CCU Gopher 1-2-15TFH | Burlington Resources | Dunn, ND | 0.8% |
CCU Gopher 2-2-15MBH | Burlington Resources | Dunn, ND | 0.8% |
CCU Red River 7-2-15TFH | Burlington Resources | Dunn, ND | 0.8% |
CCU Red River 8-2-15MBH | Burlington Resources | Dunn, ND | 0.8% |
CCU Bison Point 24-34TFH | Burlington Resources | Dunn, ND | 0.8% |
CCU Bison Point 24-34MBH | Burlington Resources | Dunn, ND | 0.8% |
CCU Bison Point 34-34TFH | Burlington Resources | Dunn, ND | 0.8% |
CCU Bison Point 34-34MBH | Burlington Resources | Dunn, ND | 0.8% |
CCU Olympian 21-2MBH | Burlington Resources | Dunn, ND | 0.8% |
CCU Olympian 31-2TFH | Burlington Resources | Dunn, ND | 0.8% |
CCU Olympian 31-2MBH | Burlington Resources | Dunn, ND | 0.8% |
CCU Golden Creek 34-23TFH | Burlington Resources | Dunn, ND | 0.8% |
CCU Burner 31-26TFH | Burlington Resources | Dunn, ND | 0.8% |
Jersey 1-6H | Continental | Mountrail, ND | 0.8% |
Jersey 3-6H1 | Continental | Mountrail, ND | 0.8% |
Jersey 2-6H2 | Continental | Mountrail, ND | 0.8% |
Jersey 5-6H | Continental | Mountrail, ND | 0.8% |
P Johnson 153-98-1-6-7-16H | Whiting | Williams, ND | 0.6% |
P Johnson 153-98-1-6-7-16HA | Whiting | Williams, ND | 0.6% |
P Pankowski 153-98-4-6-7-13H | Whiting | Williams, ND | 0.6% |
P Pankowski 153-98-4-6-7-13HA | Whiting | Williams, ND | 0.6% |
Burr Federal 10-26H | Continental | Mountrail, ND | 0.5% |
Burr Federal 9-26H1 | Continental | Mountrail, ND | 0.5% |
Burr Federal 11-26H | Continental | Mountrail, ND | 0.5% |
Burr Federal 12-26H1 | Continental | Mountrail, ND | 0.5% |
Burr Federal 13-26H | Continental | Mountrail, ND | 0.5% |
Burr Federal 14-26H | Continental | Mountrail, ND | 0.5% |
(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 Loss and Adjusted EBITDA
In addition to reporting net loss as defined under GAAP, we also present Adjusted Net Loss and Adjusted EBITDA. We define Adjusted Net Loss as net loss, excluding (i) net income (loss) on the mark-to-market of derivatives, net of tax and (ii) impairment of oil and gas properties, net of tax. We define Adjusted EBITDA as earnings (loss) before (i) interest expense, (ii) income taxes, (iii) depreciation, depletion and amortization, (iv) impairment of oil and gas properties, (v) accretion of abandonment liability, (vi) income (losses) on the mark-to-market of derivatives, and (vii) non-cash expenses relating to share based payments recognized under ASC Topic 718. We believe the use of non-GAAP financial measures provides useful information to investors regarding our current financial performance; however, Adjusted Net 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 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 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 Loss and Adjusted EBITDA to net loss, GAAP, is included below:
Reconciliation of Net Loss to Adjusted Net Loss
Three Months Ended | Six Months Ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
2015 | 2014 | 2015 | 2014 | |||||||||||||
Net loss | $ | (18,669,638 | ) | $ | (543,360 | ) | $ | (19,942,574 | ) | $ | (924,920 | ) | ||||
Add back: | ||||||||||||||||
Loss on mark-to-market of derivatives, net of tax (a) | 1,467,155 | 555,124 | 1,191,826 | 690,159 | ||||||||||||
Impairment of oil and gas properties, net of tax (b) | 16,229,000 | – | 16,229,000 | – | ||||||||||||
Adjusted net income (loss) | $ | (973,483 | ) | $ | 11,764 | $ | (2,521,748 | ) | $ | (234,761 | ) | |||||
Weighted average common shares outstanding - basic and fully diluted | 47,979,990 | 47,979,990 | 47,979,990 | 47,979,990 | ||||||||||||
Net income (loss) per common share – basic and fully diluted | $ | (0.39 | ) | $ | (0.01 | ) | $ | (0.42 | ) | $ | (0.02 | ) | ||||
Add: | ||||||||||||||||
Change due to loss on mark-to- market of derivatives, net of tax | 0.03 | 0.01 | 0.03 | 0.01 | ||||||||||||
Change due to impairment of oil and gas properties, net of tax | 0.34 | – | 0.34 | – | ||||||||||||
Adjusted net income (loss) per common share – basic and fully diluted | $ | (0.02 | ) | $ | 0.00 | $ | (0.05 | ) | $ | (0.01 | ) |
(a)Adjusted to reflect tax expense, computed based on our effective tax rate of approximately 25% in 2015 and 37% in 2014, of $489,000 and $326,000 for the three month ended June 30, 2015 and 2014, respectively, and $397,000 and $405,000 for the six months ended June 30, 2015 and 2014, respectively.
(b)Adjusted to reflect tax expense, computed based on our effective tax rate of approximately 25% in 2015 and 37% in 2014, of $5,410,000 and $-0- for the three month ended June 30, 2015 and 2014, respectively, and $5,410,000 and $-0- for the six months ended June 30, 2015 and 2014, respectively.
7 |
Reconciliation of Net Loss to Adjusted EBITDA
Black Ridge Oil & Gas, Inc.
Reconciliation of Adjusted EBITDA
(Unaudited)
Three Months Ended | Six Months Ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
2015 | 2014 | 2015 | 2014 | |||||||||||||
Net income (loss) | $ | (18,669,638 | ) | $ | (543,360 | ) | $ | (19,942,574 | ) | $ | (924,920 | ) | ||||
Add back: | ||||||||||||||||
Interest expense, net, excluding amortization of warrant based financing costs | 1,385,837 | 1,136,603 | 2,792,657 | 2,065,981 | ||||||||||||
Income tax provision | (5,957,649 | ) | (305,715 | ) | (6,593,040 | ) | (589,738 | ) | ||||||||
Depreciation, depletion, and amortization | 2,941,753 | 2,139,733 | 5,576,052 | 3,734,590 | ||||||||||||
Impairment of oil and gas properties | 21,639,000 | – | 21,639,000 | – | ||||||||||||
Accretion of abandonment liability | 7,932 | 5,148 | 15,861 | 9,653 | ||||||||||||
Share based compensation | 314,162 | 301,241 | 635,514 | 599,003 | ||||||||||||
Loss on mark-to market of derivatives | 1,956,154 | 881,124 | 1,588,826 | 1,095,159 | ||||||||||||
Adjusted EBITDA | $ | 3,617,551 | $ | 3,614,774 | $ | 5,712,296 | $ | 5,989,728 |
Our Adjusted EBITDA for the three and six month periods ending June 30, 2015 includes income from the Dahl Federal 2-15H well recognized in the current period from activity in prior periods of $1,040,397 and $1,027,995, respectively.
8 |
BLACK RIDGE OIL & GAS, INC.
CONDENSED BALANCE SHEETS
June 30, | December 31, | |||||||
2015 | 2014 | |||||||
ASSETS | (Unaudited) | |||||||
Current assets: | ||||||||
Cash and cash equivalents | $ | 214,583 | $ | 94,682 | ||||
Derivative instruments, current | 3,007,135 | 3,571,803 | ||||||
Accounts receivable | 4,091,371 | 5,740,171 | ||||||
Prepaid expenses | 46,351 | 41,387 | ||||||
Total current assets | 7,359,440 | 9,448,043 | ||||||
Property and equipment: | ||||||||
Oil and natural gas properties, full cost method of accounting: | ||||||||
Proved properties | 124,205,553 | 112,418,105 | ||||||
Unproved properties | 1,258,138 | 591,121 | ||||||
Other property and equipment | 139,004 | 139,004 | ||||||
Total property and equipment | 125,602,695 | 113,148,230 | ||||||
Less, accumulated depreciation, amortization, depletion and allowance for impairment | (46,117,576 | ) | (18,902,524 | ) | ||||
Total property and equipment, net | 79,485,119 | 94,245,706 | ||||||
Derivative instruments, long-term | 2,983,784 | 4,007,942 | ||||||
Debt issuance costs, net | 510,239 | 701,019 | ||||||
Total assets | $ | 90,338,582 | $ | 108,402,710 | ||||
LIABILITIES AND STOCKHOLDERS' EQUITY | ||||||||
Current liabilities: | ||||||||
Accounts payable | $ | 10,166,181 | $ | 10,291,262 | ||||
Accrued expenses | 91,155 | 57,435 | ||||||
Total current liabilities | 10,257,336 | 10,348,697 | ||||||
Asset retirement obligations | 344,360 | 286,804 | ||||||
Revolving credit facilities and long term debt, net of discounts of $1,665,862 and $2,072,483, respectively | 60,026,143 | 51,834,603 | ||||||
Deferred tax liability | – | 6,593,040 | ||||||
Total liabilities | 70,627,839 | 69,063,144 | ||||||
Commitments and contingencies | – | – | ||||||
Stockholders' equity: | ||||||||
Preferred stock, $0.001 par value, 20,000,000 shares authorized, no shares issued and outstanding | – | – | ||||||
Common stock, $0.001 par value, 500,000,000 shares authorized, 47,979,990 shares issued and outstanding | 47,980 | 47,980 | ||||||
Additional paid-in capital | 33,965,465 | 33,651,714 | ||||||
Retained earnings (accumulated deficit) | (14,302,702 | ) | 5,639,872 | |||||
Total stockholders' equity | 19,710,743 | 39,339,566 | ||||||
Total liabilities and stockholders' equity | $ | 90,338,582 | $ | 108,402,710 |
9 |
BLACK RIDGE OIL & GAS, INC.
CONDENSED STATEMENTS OF OPERATIONS
(Unaudited)
For the Three Months | For the Six Months | |||||||||||||||
Ended June 30, | Ended June 30, | |||||||||||||||
2015 | 2014 | 2015 | 2014 | |||||||||||||
Oil and gas sales | $ | 5,050,080 | $ | 5,553,997 | $ | 7,936,536 | $ | 9,584,417 | ||||||||
Gain (loss) on settled derivatives | 847,198 | (262,719 | ) | 1,980,619 | (378,882 | ) | ||||||||||
Loss on the mark-to-market of derivatives | (1,956,155 | ) | (881,124 | ) | (1,588,826 | ) | (1,095,159 | ) | ||||||||
Total revenues | 3,941,123 | 4,410,154 | 8,328,329 | 8,110,376 | ||||||||||||
Operating expenses: | ||||||||||||||||
Production expenses | 1,153,663 | 595,591 | 2,143,520 | 1,103,054 | ||||||||||||
Production taxes | 555,152 | 591,525 | 841,344 | 996,832 | ||||||||||||
General and administrative | 730,445 | 634,109 | 1,540,453 | 1,404,882 | ||||||||||||
Depletion of oil and gas properties | 2,937,744 | 2,131,545 | 5,567,776 | 3,718,477 | ||||||||||||
Impairment of oil and gas properties | 21,639,000 | – | 21,639,000 | – | ||||||||||||
Accretion of discount on asset retirement obligations | 7,932 | 5,148 | 15,861 | 9,653 | ||||||||||||
Depreciation and amortization | 4,009 | 8,188 | 8,276 | 16,113 | ||||||||||||
Total operating expenses | 27,027,945 | 3,966,106 | 31,756,230 | 7,249,011 | ||||||||||||
Net operating income (loss) | (23,086,822 | ) | 444,048 | (23,427,901 | ) | 861,365 | ||||||||||
Other income (expense): | ||||||||||||||||
Other income | 6,707 | – | 6,707 | – | ||||||||||||
Interest (expense) | (1,547,172 | ) | (1,293,123 | ) | (3,114,420 | ) | (2,376,023 | ) | ||||||||
Total other income (expense) | (1,540,465 | ) | (1,293,123 | ) | (3,107,713 | ) | (2,376,023 | ) | ||||||||
Loss before provision for income taxes | (24,627,287 | ) | (849,075 | ) | (26,535,614 | ) | (1,514,658 | ) | ||||||||
Provision for income taxes | 5,957,649 | 305,715 | 6,593,040 | 589,738 | ||||||||||||
Net loss | $ | (18,669,638 | ) | $ | (543,360 | ) | $ | (19,942,574 | ) | $ | (924,920 | ) | ||||
Weighted average common shares outstanding - basic | 47,979,990 | 47,979,990 | 47,979,990 | 47,979,990 | ||||||||||||
Weighted average common shares outstanding - fully diluted | 47,979,990 | 47,979,990 | 47,979,990 | 47,979,990 | ||||||||||||
Net loss per common share - basic | $ | (0.39 | ) | $ | (0.01 | ) | $ | (0.42 | ) | $ | (0.02 | ) | ||||
Net loss per common share - fully diluted | $ | (0.39 | ) | $ | (0.01 | ) | $ | (0.42 | ) | $ | (0.02 | ) |
10 |
BLACK RIDGE OIL & GAS, INC.
CONDENSED STATEMENTS OF CASH FLOWS
(Unaudited)
For the Six Months | ||||||||
Ended June 30, | ||||||||
2015 | 2014 | |||||||
CASH FLOWS FROM OPERATING ACTIVITIES | ||||||||
Net loss | $ | (19,942,574 | ) | $ | (924,920 | ) | ||
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | ||||||||
Depletion of oil and gas properties | 5,567,776 | 3,718,477 | ||||||
Depreciation and amortization | 8,276 | 16,113 | ||||||
Amortization of debt issuance costs | 190,780 | 145,307 | ||||||
Accretion of discount on asset retirement obligations | 15,861 | 9,653 | ||||||
Loss on the mark-to-market of derivatives | 1,588,826 | 1,095,159 | ||||||
Accrued payment in kind interest applied to long term debt | 634,919 | 472,712 | ||||||
Amortization of original issue discount on debt | 84,858 | 60,288 | ||||||
Amortization of debt discounts, warrants | 321,763 | 310,042 | ||||||
Common stock options issued to employees and directors | 313,751 | 288,961 | ||||||
Deferred income taxes | (6,593,040 | ) | (589,738 | ) | ||||
Impairment of oil and natural gas properties | 21,639,000 | – | ||||||
Decrease (increase) in current assets: | ||||||||
Accounts receivable | 1,648,800 | (2,835,328 | ) | |||||
Prepaid expenses | (4,964 | ) | (15,812 | ) | ||||
Increase (decrease) in current liabilities: | ||||||||
Accounts payable | 36,328 | 203,177 | ||||||
Accrued expenses | 33,720 | 58,040 | ||||||
Net cash provided by operating activities | 5,544,080 | 2,012,131 | ||||||
CASH FLOWS FROM INVESTING ACTIVITIES | ||||||||
Proceeds from sale or swap of oil and gas properties | 103,000 | 1,360,920 | ||||||
Purchases of oil and gas properties and development capital expenditures | (12,677,179 | ) | (11,731,981 | ) | ||||
Advances to operators | – | (3,491,089 | ) | |||||
Purchases of other property and equipment | – | (11,131 | ) | |||||
Net cash used in investing activities | (12,574,179 | ) | (13,873,281 | ) | ||||
CASH FLOWS FROM FINANCING ACTIVITIES | ||||||||
Advances from revolving credit facilities and long term debt | 10,600,000 | 18,700,000 | ||||||
Repayments on revolving credit facilities | (3,450,000 | ) | (7,850,000 | ) | ||||
Debt issuance costs | – | (54,782 | ) | |||||
Net cash provided by financing activities | 7,150,000 | 10,795,218 | ||||||
NET CHANGE IN CASH | 119,901 | (1,065,932 | ) | |||||
CASH AT BEGINNING OF PERIOD | 94,682 | 1,150,347 | ||||||
CASH AT END OF PERIOD | $ | 214,583 | $ | 84,415 | ||||
SUPPLEMENTAL INFORMATION: | ||||||||
Interest paid | $ | 2,174,153 | $ | 1,457,540 | ||||
Income taxes paid | $ | – | $ | – | ||||
NON-CASH INVESTING AND FINANCING ACTIVITIES: | ||||||||
Net change in accounts payable for purchase of oil and gas properties | $ | (161,409 | ) | $ | (98,778 | ) | ||
Advances to operators applied to development of oil and gas properties | $ | – | $ | 2,131,043 | ||||
Capitalized asset retirement costs, net of revision in estimate | $ | 41,695 | $ | 40,712 |
11 |
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.
Make sure you are first 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
Black Ridge Oil & Gas, Inc.
Ken DeCubellis, Chief Executive Officer
952-426-1241
www.blackridgeoil.com
12 |
Exhibit 99.2
August Update OTCQB: ANFC Focused Growth in the Williston Basin August 13, 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 general economic or industry conditions, 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 - Teton project completed and flowing back at strong initial production rates - Formed joint venture with Merced Capital, focused on acquisition of Williston Basin non - operated assets - Looking Forward - Focus majority of cash flow on debt reduction and balance sheet improvement - Acquire assets via Merced JV Black Ridge Operational Focus: Bakken / Three Forks Fairway North Dakota Montana Williston Basin
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 Liquidity, Balance Sheet Reporting, Controls, Regulatory C ompliance Cash Flow: IRR >30% Black Ridge Focus Merced Capital Black Ridge JV Focus
- 2.00 4.00 6.00 8.00 10.00 12.00 14.00 Producing "Drilling" Permitted www.blackridgeoil.com 6 Focus Shifting to Production and Cash Flow 10.6 0.5 Black Ridge Oil & Gas’ Net Wells (as of 7/31/15) - 2.69 net wells brought into production in 2015, dominated by Teton project (1.76 net) - 66% growth in producing net wells year over year - Primary focus is leveraging our strong base of producing assets for cash flow generation to pay down debt
0 200 400 600 800 1,000 1,200 1,400 2011 2012 2013 2014 2015 (projected) www.blackridgeoil.com 7 Production Ramping Up in High Return Areas Net Production BOE/d - 1H 2015 average production: 1,058 boe /d - Production gains in 2H 2015 from Teton project startup
$0 $5 $10 $15 $20 $25 $30 $35 $40 Cadence Chambers Outstanding Debt Total Availability Capital Structure www.blackridgeoil.com 8 Outstanding Debt, $MM (as of 06/30/15) Cadence Revolving Facility Senior Secured $34mm borrowing base (1) $4.25mm available LIBOR + 300/350 bps Matures: Jan 2017 Chambers Term Loan Subordinated $31.9mm drawn including PIK LIBOR + 900 bps, 400 bps PIK Matures: June 2017 (1) Borrowing base redetermined from $35mm to $34mm in March 2015
0 100 200 300 400 500 600 700 800 Q3 2015 Q4 2015 1st Half 2016 2nd Half 2016 2017 2018 Swaps Costless Collars Hedging Summary 9 www.blackridgeoil.com $72.40 $89.84 $75.84 $79.47 $80.00 - 89.50 Barrels Hedged (Bo/d), WTI ($/ Bbl , Swap Price i s Weighted Average) (1) $76.95 $75.00 - 95.60 $75.00 - 95.60 (1) Please reference hedging summary in appendix. $60.67
Teton – McKenzie County, ND - Operator: ConocoPhillips - Twenty three gross (1.76 net) wells drilled and completed - Field cost estimates indicating significant savings from the initial AFE average of $9.1 million due to service cost reductions and operator efficiencies - Drilling, completion and flow - back activities ahead of original company plan - Timing for connection to permanent production facilities pending completion of natural gas line, which is behind schedule www.blackridgeoil.com 10 ( 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. Montana North Dakota Proposed Middle Bakken Proposed Three Forks 2 nd Bench Proposed Three Forks 1 st Bench T150N - R96W - 3 - 10 (2)
Teton – Initial Production Results - Initial flowback results are very strong, with wells averaging approximately 2,000 boe/d (81% oil) over a nine day average flowback period www.blackridgeoil.com 11 Well Name Working Interest Current Status Flowback Information Oil Produced ( bbls ) Gas Produced ( mcf ) # of Days Average ( Boe /d) Teton 2 - 8 - 10MBH 8.40% Flowback Complete, Waiting on Facilities 14,839 24,020 6 3,140 Teton 6 - 8 - 10MBH 8.40% Flowback Complete, Waiting on Facilities 14,656 27,510 6 3,207 Teton 7 - 8 - 10MBH 8.40% Flowback Complete, Waiting on Facilities 14,785 22,171 7 2,640 Teton 8 - 8 - 10TFSH 8.40% Flowback Complete, Waiting on Facilities 14,789 21,645 7 2,628 Teton 5 - 1 - 3TFSH 8.40% Flowback Complete, Waiting on Facilities 14,732 16,173 8 2,178 Teton 6 - 8 - 10TFSH 8.40% Flowback Complete, Waiting on Facilities 14,883 23,203 8 2,344 Teton 5 - 8 - 10MBH 8.40% Flowback Complete, Waiting on Facilities 14,280 21,591 8 2,235 Teton 7 - 1 - 3TFSH 8.40% Flowback Complete, Waiting on Facilities 14,835 25,283 8 2,381 Kings Canyon 6 - 1 - 27MBH 8.40% Flowback Complete, Waiting on Facilities 14,699 10,225 9 1,823 Kings Canyon 7 - 8 - 34MBH 8.40% Flowback Complete, Waiting on Facilities 14,805 28,901 9 2,180 Teton 3 - 8 - 10MBH 8.40% Flowback Complete, Waiting on Facilities 14,861 23,839 9 2,093 Kings Canyon 2 - 8 - 34UTFH 8.40% Flowback Complete, Waiting on Facilities 14,224 14,066 11 1,506 Kings Canyon 4 - 8 - 34UTFH 8.40% Flowback Complete, Waiting on Facilities 14,696 19,730 11 1,635 Kings Canyon 6 - 8 - 34UTFH 8.40% Flowback Complete, Waiting on Facilities 14,087 25,180 11 1,662 Kings Canyon 4 - 1 - 27MTFH 8.40% Flowback Complete, Waiting on Facilities 14,691 11,371 11 1,508 Kings Canyon 4 - 8 - 34MBH 8.40% Flowback Complete, Waiting on Facilities 12,806 16,552 12 1,297 Kings Canyon 5 - 8 - 34UTFH 8.40% Flowback Complete, Waiting on Facilities 14,764 17,500 12 1,473 Kings Canyon 6 - 1 - 27MTFH 8.40% Flowback in Process 11,391 13,050 8 1,696 Kings Canyon 3 - 1 - 27MTFH 8.40% Flowback in Process 9,701 14,606 11 1,103 RemingTeton 8 - 8 - 10 MBH 6.25% Flowback Complete, Waiting on Facilities 14,805 20,641 7 2,606 TetoNorman 1 - 1 - 3UTFH 6.25% Flowback Complete, Waiting on Facilities 14,736 16,696 9 1,947 LaCanyon 8 - 8 - 34MBH 2.15% Flowback Complete, Waiting on Facilities 14,794 25,880 7 2,730 DeKing 1 - 8 - 34MBH - ULW 2.15% Flowback Complete, Waiting on Facilities 14,713 22,758 9 2,056 Project Average 7.67% 14,242 20,113 9 1,984
Merced Black Ridge Partnership www.blackridgeoil.com 12 Transaction Structure New Acquisition Merced Black Ridge, LLC Black Ridge Affiliate of Merced Capital, L.P. Equity Capital Deal sourcing, Mgmt. services Management fee, Promote Co - invest 0% - 25% Working interest 75% - 100% Working interest - Merced Black Ridge, LLC - Merced provides equity capital, with initial target of $ 5 0 Million, subject to Merced approval - Capital used to acquire / develop non - operated assets in the Williston Basin - Black Ridge will source deals and manage day to day business - Black Ridge will receive management fee and participation in entity profits once investor hurdles are met - Strategic rationale for Black Ridge - Structure is non - dilutive to existing shareholders - Potential to achieve significant equity returns with its share of partnership profits - Option to co - invest in high return projects for up to 25% working interest (held directly in Black Ridge) - Creates a long - term partnership that is scalable and repeatable www.mercedcapital.com
For More Information www.blackridgeoil.com 13 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 14 Appendix
Hedging Summary 15 www.blackridgeoil.com Swaps Settlement Period Contract Date Oil (BBLS) Fixed Price 7/1/2015 - 12/31/2015 8/9/2013 12,000 $ 88.28 7/1/2015 - 12/31/2015 4/8/2014 10,500 $ 89.70 7/1/2015 - 12/31/2015 5/21/2014 6,000 $ 92.38 7/1/2015 - 12/31/2015 9/16/2014 15,000 $ 90.16 10/1/2015 - 12/31/2015 5/11/2015 36,000 $ 61.87 1/1/2016 - 12/31/2016 6/25/2014 60,000 $ 90.36 1/1/2016 - 12/31/2016 9/15/2014 24,000 $ 88.15 1/1/2016 - 6/30/2016 5/11/2015 45,000 $ 62.88 7/1/2016 - 12/31/2016 7/22/2015 18,000 $ 55.55 1/1/2017 - 12/31/2017 9/15/2014 78,000 $ 87.18 1/1/2017 - 12/31/2017 7/22/2015 42,000 $ 57.95 1/1/2018 - 12/31/2018 7/22/2015 96,000 $ 60.67 Costless Collars Settlement Period Contract Date Oil (BBLS) Floor / Ceiling 7/1/2015 - 12/31/2015 12/13/2013 18,000 $ 75.00 / 95.60 1/1/2016 - 6/30/2016 8/9/2013 10,002 $ 80.00 / 89.50
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