Exhibit 99.1
Black Ridge Oil & Gas Announces
Third Quarter 2015 Results
MINNETONKA, Minn., November 12, 2015 -
Black Ridge Oil & Gas, Inc. ("the Company") (OTCQB: ANFC), a growth-oriented exploration and production company focused
on non-operated Bakken and Three Forks properties, today announced financial and operating results for the three and
nine months ended September 30, 2015.
Third Quarter 2015 Company Highlights
| · | Ended quarter with $26.65 million drawn
from our senior secured facility, a net reduction of $3.1 million from the end of the second quarter of 2015 |
| · | Monetized $6.3 million of hedges and used
proceeds to pay down debt |
| · | Quarterly production increased 41% over
the third quarter of 2014 to 98.9 thousand barrels of oil equivalent (“MBoe”), an average of approximately 1,075 barrels
of oil equivalent per day (“Boe/d”) |
| · | Oil and gas sales totaled $3.6 million,
a decrease of 33% over the second quarter of 2015 and a decrease of 39% from the third quarter of 2014 |
| · | Added 50 gross (1.92 net) wells, increasing
our total producing well count to 341 gross (10.88 net), an increase of 48% over the third quarter of 2014 |
| · | Recorded $9.0 million of adjusted EBITDA,
including $6.3 million from the liquidation of derivative contracts prior to their contractual maturity |
| · | Recorded GAAP net loss for the quarter
of $0.60 per diluted share, impacted by a non-cash impairment of $31.0 million ($0.65 per diluted share, net of tax effect). The
impairment is primarily the result of low oil prices |
| · | Continued the development of the Teton
project (1.76 net wells) with strong initial production rates |
Liquidity Position
and Borrowing Base
Black Ridge ended
the quarter with $26.65 million drawn on its $34 million senior secured revolving credit facility. The borrowing base
was adjusted by our lender as part of a regularly scheduled redetermination to $33 million effective October 1, 2015 and will adjust
down to $32 million on November 16, 2015. The reduction in borrowing base is the net effect of lower commodity prices and monetization
of hedges, substantially offset by Teton project development. The next redetermination date is scheduled for April 1, 2016.
We currently have no obligations to enter into new hedging agreements, but may choose to opportunistically do so in accord with
our lending partners. Until we see sustained improvement in oil prices, the Company’s future acquisition and development
activity is likely to be focused within the Merced joint venture. With limited development within the base business, the Company
expects the current borrowing base and cash flows to meet our liquidity needs.
Teton Project Update and Production Guidance
In October 2015, 19 of the 23 wells in
our Teton project were turned over to full production, with the remaining four wells scheduled to be turned over to production
in mid-December once facilities are connected. All of the 19 wells are producing at rates near or above our expectations based
on very positive flow-back rates achieved early in the second quarter. With the startup delay, the Teton project contributed only
199 boe/d during the third quarter. We expect production contribution to increase significantly during the fourth quarter.
Management Comment
”The Company is excited by the initial
results from our Teton project and we look forward to full production and cash flow from this asset,” said Ken DeCubellis,
Chief Executive Officer. “As we look forward to the remainder of 2015 and into 2016, the Company’s focus will be maintaining
liquidity by allocating our free cash flow to debt reduction and finding acquisition opportunities for our joint venture with Merced.”
Hedging Update
In the third quarter
of 2015, the Company realized a $7,456,284 gain on settled derivatives, of which $1,201,284 was from settlements on their scheduled
maturity dates and $6,255,000 was from the liquidation of our 2018, 2017, and the majority of our 2016 derivative contracts prior
to their scheduled maturity dates. As of September 30, 2015, the Company’s net derivative asset was $2,693,561. The following
table summarizes the Company’s open crude oil swap contracts as of September 30, 2015:
| |
|
Oil |
|
Weighted Average |
| Term |
|
(barrels) |
|
Price ($ per Bbl) |
| 2015: |
|
|
|
|
| Q4 |
|
57,750 |
|
72.40 |
| 2016: |
|
|
|
|
| Q2 |
|
29,000 |
|
75.84 |
In addition to the open crude oil swap contracts,
the Company has entered into costless collar contracts. The costless collars are used to establish floor and ceiling prices on
anticipated crude oil production. There were no premiums paid or received by us related to the costless collar contracts. The following
table reflects open costless collar crude oil contracts as of September 30, 2015:
| | |
Oil | | |
Floor/Ceiling | | |
| |
| Term | |
(Barrels) | | |
Price (WTI) | | |
Basis | |
| Costless Collars – Crude Oil | |
| | | |
| | | |
| | |
| 10/01/2015 – 12/31/2015 | |
| 9,000 | | |
| $75.00/$95.60 | | |
| NYMEX | |
| 01/01/2016 – 06/30/2016 | |
| 3,334 | | |
| $80.00/$89.50 | | |
| NYMEX | |
2015 Operating and Financial Results
The following table presents selected operating
and financial data for the periods indicated.
| | |
Three Months Ended | | |
Nine Months Ended | |
| | |
September 30, | | |
September 30, | |
| | |
2015 | | |
2014 | | |
2015 | | |
2014 | |
| Net Production: | |
| | | |
| | | |
| | | |
| | |
| Oil (Bbl) | |
| 86,533 | | |
| 62,603 | | |
| 249,593 | | |
| 164,570 | |
| Natural gas (Mcf) | |
| 74,279 | | |
| 44,639 | | |
| 244,974 | | |
| 106,458 | |
| Barrel of oil equivalent (Boe) | |
| 98,933 | | |
| 70,043 | | |
| 290,422 | | |
| 182,313 | |
| | |
| | | |
| | | |
| | | |
| | |
| Average Sales Prices: | |
| | | |
| | | |
| | | |
| | |
| Oil (per Bbl) | |
$ | 37.83 | | |
$ | 84.17 | | |
$ | 43.86 | | |
$ | 87.71 | |
| Effect of oil hedges on average price (per Bbl) | |
$ | 13.88 | (a) | |
$ | (1.12 | ) | |
$ | 12.75 | (a) | |
$ | (2.73 | ) |
| Oil net of hedging (per Bbl) | |
$ | 51.71 | (a) | |
$ | 83.05 | | |
$ | 56.61 | (a) | |
$ | 84.98 | |
| Natural gas (per Mcf) | |
$ | 1.14 | | |
$ | 4.99 | | |
$ | 1.43 | | |
$ | 6.03 | |
| Realized price on a Boe basis, net of settled derivatives | |
$ | 46.10 | (a) | |
$ | 77.41 | | |
$ | 49.85 | (a) | |
$ | 80.23 | |
| | |
| | | |
| | | |
| | | |
| | |
| Average Production Costs: | |
| | | |
| | | |
| | | |
| | |
| Oil (per Bbl) | |
$ | 9.99 | | |
$ | 10.27 | | |
$ | 11.74 | | |
$ | 10.31 | |
| Natural gas (per Mcf) | |
$ | 0.30 | | |
$ | 0.61 | | |
$ | 0.41 | | |
$ | 0.72 | |
| Barrel of oil equivalent (per Boe) | |
$ | 8.97 | | |
$ | 9.57 | | |
$ | 10.44 | | |
$ | 9.73 | |
| Production Taxes (per Boe) | |
$ | 3.34 | | |
$ | 8.41 | | |
$ | 4.03 | | |
$ | 8.70 | |
| General and Administrative Expense (per Boe) | |
$ | 7.63 | | |
$ | 9.85 | | |
$ | 7.90 | | |
$ | 11.49 | |
| Depletion, Depreciation and Accretion (per Boe) | |
$ | 18.10 | | |
$ | 32.69 | | |
$ | 25.42 | | |
$ | 33.10 | |
(a)Excludes the effect of derivatives
settlement prior to their contractual settlement date.
Derivative Liquidation
During
the third quarter of 2015, we settled all of our 2017 and 2018 derivative contracts and the majority of our 2016 derivative
contracts prior to the expiration of their contractual maturities, resulting in cash proceeds totaling $6,255,000. The resulting
gain is included in our gain on settled derivatives for the three and nine months ended September 30, 2015.
Third Quarter 2015
Financial Results
In the third quarter
of 2015, oil and gas sales, excluding the impact of settled derivatives, were $3.4 million, a decrease of 39% as compared to the
third quarter of 2014. The Company realized an average price of $37.83 per barrel of oil, before the effects of hedging, and $1.14
per mcf of gas, representing decreases of 55% and 77%, respectively, as compared to the third quarter of 2014. The impact of weaker
commodity prices was partially offset by a 41% increase in production over the third quarter of 2014. The Company’s production
in the third quarter of 2015 was comprised of 87% oil and 13% natural gas and natural gas liquids, on a Boe basis.
For the third quarter
of 2015, the Company realized a gain on settled derivatives of $7.5 million, compared to a loss of $0.1 million in the third quarter
of 2014. The third quarter 2015 settlements include the $6.3 million gain from the derivative liquidation and $1.2 million realized
gain from the settlement of derivatives upon their contracted expiration date. The Company had a mark-to-market derivative loss
of $3.3 million in the third quarter of 2015 compared to a mark-to-market gain of $2.1 million in the third quarter of 2014. The
mark-to-market derivative loss in the third quarter of 2015 was primarily driven by the conversion of unrealized gains to realized
gains, partially offset by an increase in the value of remaining hedges in the portfolio.
Production expenses
for the third quarter of 2015 were $0.9 million, or $8.97 per Boe, compared to $0.7 million, or $9.57 per Boe,
for the third quarter of 2014. The decrease in production expense in the third quarter was primarily attributable to lower water
disposal costs as much of the new production brought on in the third quarter is from wells with lower water cuts.
Production taxes for
the third quarter of 2015 were $0.3 million, compared to $0.6 million, for the third quarter of 2014. Production taxes
as a percent of oil and gas sales were 9.8% for the third quarter of 2015, compared to 10.7% for the third quarter of 2014.
Depletion, depreciation,
amortization and accretion (“DD&A”) was $1.8 million, or $18.10 per Boe, in the third quarter of 2015, compared
to $2.3 million, or $32.69 per Boe, in the third quarter of 2014. The primary driver for the decrease in DD&A was the reduction
in the full cost pool caused by the impairment recorded in the second quarter of 2015.
As a result of the
currently prevailing low commodity prices and their effect on the proved reserve values of properties in 2015, we recorded a non-cash
ceiling test impairment of $31.0 million in the third quarter of 2015. The Company did not have any impairment of its proved oil
and gas properties in the third quarter of 2014. The impairment charge affected our reported net income but did not reduce our
cash flow.
General and administrative
expenses (“G&A”) for the third quarter of 2015 were $0.8 million, or $7.63 per Boe, compared to $0.7 million,
or $9.85 per Boe, for the third quarter of 2014. Cash G&A (non-GAAP, excludes stock-based compensation expense) was $0.6 million,
or $6.09 per Boe, for the third quarter of 2015 compared to $0.5 million, or $7.79 per Boe, for the third quarter of 2014.
Interest expense,
net of capitalized interest, was $1.7 million in the third quarter of 2015, compared to $1.4 million in the third quarter of 2014.
The increase in interest expense was primarily due to additional borrowing to fund the Company’s capital development program.
The income tax benefit
recognized during the third quarter of 2015 was $-0- million, or 0.0% of the loss before income taxes, as compared to a net income
tax expense of $0.7 million, or 37.0% of the loss before income taxes, in the third quarter of 2014. The lower effective tax rate
in 2015 relates to a valuation allowance placed on the net deferred tax asset in the third quarter of 2015.
The Company recorded $9.0 million of adjusted
EBITDA in the third quarter of 2015, which includes the liquidated derivative gain of $6.3 million. Adjusted EBITDA was $3.6 million
for the third quarter of 2014. Adjusted EBITDA is a non-GAAP financial measure. Please refer to the reconciliation in this release
for additional information about this measure.
Acreage and Drilling
As of September 30, 2015, the Company controlled
approximately 8,509 net acres in the Williston Basin. Approximately 72% of the acreage is held by production with 341 gross (10.88
net) wells producing. Additionally, the Company had 0.26 net wells in development as of September 30, 2015.
Producing Wells
The following table
sets forth wells in which Black Ridge holds a participating interest that were completed during the quarter ending September 30,
2015:
| Well |
Operator |
Location |
WI(1) |
| Kings Canyon 5-8-34UTF |
Burlington Resources |
McKenzie, ND |
8.4% |
| Teton 5-8-10MBH |
Burlington Resources |
McKenzie, ND |
8.4% |
| Kings Canyon 2-8-34UTFH |
Burlington Resources |
McKenzie, ND |
8.4% |
| Kings Canyon 3-1-27MTFH |
Burlington Resources |
McKenzie, ND |
8.4% |
| Kings Canyon 4-1-27MTFH |
Burlington Resources |
McKenzie, ND |
8.4% |
| Kings Canyon 4-8-34MBH |
Burlington Resources |
McKenzie, ND |
8.4% |
| Kings Canyon 4-8-34UTFH |
Burlington Resources |
McKenzie, ND |
8.4% |
| Kings Canyon 6-1-27MBH |
Burlington Resources |
McKenzie, ND |
8.4% |
| Kings Canyon 6-1-27MTFH |
Burlington Resources |
McKenzie, ND |
8.4% |
| Kings Canyon 6-8-34UTFH |
Burlington Resources |
McKenzie, ND |
8.4% |
| Kings Canyon 7-8-34MBH |
Burlington Resources |
McKenzie, ND |
8.4% |
| Teton 2-8-10MBH |
Burlington Resources |
McKenzie, ND |
8.4% |
| Teton 3-8-10MBH |
Burlington Resources |
McKenzie, ND |
8.4% |
| Teton 5-1-3TFSH |
Burlington Resources |
McKenzie, ND |
8.4% |
| Teton 6-8-10MBH |
Burlington Resources |
McKenzie, ND |
8.4% |
| Teton 6-8-10TFSH |
Burlington Resources |
McKenzie, ND |
8.4% |
| Teton 7-1-3TFSH |
Burlington Resources |
McKenzie, ND |
8.4% |
| Teton 7-8-10MBH |
Burlington Resources |
McKenzie, ND |
8.4% |
| Teton 8-8-10TFSH |
Burlington Resources |
McKenzie, ND |
8.4% |
| Remingteton 8-8-10MBH |
Burlington Resources |
McKenzie, ND |
6.2% |
| Thorp Federal 11X-28A |
XTO |
Dunn, ND |
3.4% |
| LaCanyon 8-8-34MBH ULW |
Burlington Resources |
McKenzie, ND |
2.1% |
| EN-Weyrauch B-LW-154-93-3031H-1 |
Hess |
Mountrail, ND |
1.6% |
| CCU Boxcar 44-22PH |
Burlington Resources |
Dunn, ND |
0.8% |
| CCU Dakotan 1-7-17MBH |
Burlington Resources |
Dunn, ND |
0.8% |
| CCU Dakotan 1-7-17TFH |
Burlington Resources |
Dunn, ND |
0.8% |
| CCU Dakotan 2-7-17MBH |
Burlington Resources |
Dunn, ND |
0.8% |
| CCU Dakotan 2-7-17TFH |
Burlington Resources |
Dunn, ND |
0.8% |
| CCU Dakotan 3-8-17MBH |
Burlington Resources |
Dunn, ND |
0.8% |
| CCU Dakotan 4-8-17TFH |
Burlington Resources |
Dunn, ND |
0.8% |
| CCU Dakotan 5-8-17MBH |
Burlington Resources |
Dunn, ND |
0.8% |
| CCU Dakotan 5-8-17TFH |
Burlington Resources |
Dunn, ND |
0.8% |
| CCU Dakotan 6-8-17MBH |
Burlington Resources |
Dunn, ND |
0.8% |
| CCU Dakotan 7-8-17MBH |
Burlington Resources |
Dunn, ND |
0.8% |
| CCU Dakotan 7-8-17TFH |
Burlington Resources |
Dunn, ND |
0.8% |
| CCU Gopher 1-2-15TFH |
Burlington Resources |
Dunn, ND |
0.8% |
| CCU Gopher 2-2-15MBH |
Burlington Resources |
Dunn, ND |
0.8% |
| CCU Olympian 31-2MBH |
Burlington Resources |
Dunn, ND |
0.8% |
| CCU Powell 41-29TFH |
Burlington Resources |
Dunn, ND |
0.8% |
| CCU Red River 8-2-15MBH |
Burlington Resources |
Dunn, ND |
0.8% |
| P Johnson 153-98-1-6-7-16H |
Whiting |
Williams, ND |
0.6% |
| P Johnson 153-98-1-6-7-16HA |
Whiting |
Williams, ND |
0.6% |
| P Pankowski 153-98-4-6-7-13H |
Whiting |
Williams, ND |
0.6% |
| P Pankowski 153-98-4-6-7-13HA |
Whiting |
Williams, ND |
0.6% |
| Burr Federal 10-26H |
Continental |
Mountrail, ND |
0.5% |
| Burr Federal 11-26H |
Continental |
Mountrail, ND |
0.5% |
| Burr Federal 12-26H1 |
Continental |
Mountrail, ND |
0.5% |
| Burr Federal 13-26H |
Continental |
Mountrail, ND |
0.5% |
| Burr Federal 14-26H |
Continental |
Mountrail, ND |
0.5% |
| Burr Federal
9-26H1 |
Continental |
Mountrail,
ND |
0.5% |
(1)The
working interests are based on Black Ridge's internal records and may be subject to change by operators' third-party legal counsel
in preparing final division order title opinions for each well.
"Drilling" Wells
The following table
sets forth wells in which Black Ridge holds a participating interest that were either preparing to drill, drilling, awaiting completion
or completing as of September 30, 2015:
| Well |
Operator |
Location |
WI(1) |
| EN-VP AND R- ###-##-####H-5 |
Hess |
Mountrail, ND |
3.1% |
| EN-VP AND R- ###-##-####H-6 |
Hess |
Mountrail, ND |
3.1% |
| P Berger 156-100-14-7-6-3H |
Whiting |
Williams, ND |
1.0% |
| P Berger 156-100-14-7-6-4H |
Whiting |
Williams, ND |
1.0% |
| Aaberg 8-5N-1H |
Mountain Divide |
Divide, ND |
0.8% |
| CCU Atlantic Express 13-19TFH |
Burlington Resources |
Dunn, ND |
0.8% |
| CCU Atlantic Express 23-19MBH |
Burlington Resources |
Dunn, ND |
0.8% |
| CCU Atlantic Express 41-30MBH |
Burlington Resources |
Dunn, ND |
0.8% |
| CCU Audubon 3-7-22TFH |
Burlington Resources |
Dunn, ND |
0.8% |
| CCU Bison Point 24-34MBH |
Burlington Resources |
Dunn, ND |
0.8% |
| CCU Bison Point 24-34TFH |
Burlington Resources |
Dunn, ND |
0.8% |
| CCU Bison Point 34-34MBH |
Burlington Resources |
Dunn, ND |
0.8% |
| CCU Bison Point 34-34TFH |
Burlington Resources |
Dunn, ND |
0.8% |
| CCU Boxcar 4-7-22TFH |
Burlington Resources |
Dunn, ND |
0.8% |
| CCU Burner 31-26TFH |
Burlington Resources |
Dunn, ND |
0.8% |
| CCU Golden Creek 34-23TFH |
Burlington Resources |
Dunn, ND |
0.8% |
| CCU Olympian 21-2MBH |
Burlington Resources |
Dunn, ND |
0.8% |
| CCU Olympian 31-2TFH |
Burlington Resources |
Dunn, ND |
0.8% |
| CCU Pacific Express 12-19TFH |
Burlington Resources |
Dunn, ND |
0.8% |
| CCU Plymouth 11-29MBH |
Burlington Resources |
Dunn, ND |
0.8% |
| CCU Plymouth 11-29TFH |
Burlington Resources |
Dunn, ND |
0.8% |
| CCU Plymouth 21-29TFH |
Burlington Resources |
Dunn, ND |
0.8% |
| CCU Red River 7-2-15TFH |
Burlington Resources |
Dunn, ND |
0.8% |
| Jersey 1-6H |
Continental |
Mountrail, ND |
0.8% |
| Jersey 2-6H2 |
Continental |
Mountrail, ND |
0.8% |
| Jersey 3-6H1 |
Continental |
Mountrail, ND |
0.8% |
| Jersey 5-6H |
Continental |
Mountrail,
ND |
0.8% |
(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.
Adjusted Net Loss and Adjusted EBITDA
In addition to reporting
net income (loss) as defined under GAAP, we also present Adjusted Net Income (Loss) and Adjusted EBITDA. We define Adjusted Net
Income (Loss) as net income (loss), excluding (i) net income (loss) on the mark-to-market of derivatives, net of tax and (ii) impairment
of oil and gas properties, net of tax. We define Adjusted EBITDA as income (loss) before (i) interest expense, (ii) income taxes,
(iii) depreciation, depletion and amortization, (iv) impairment of oil and gas properties, (v) accretion of abandonment liability,
(vi) income (losses) on the mark-to-market of derivatives, and (vii) non-cash expenses relating to share based payments recognized
under ASC Topic 718. We believe the use of non-GAAP financial measures provides useful information to investors regarding our current
financial performance; however, Adjusted Net Income (Loss) and Adjusted EBITDA do not represent, and should not be considered alternatives
to GAAP measurements. We believe these measures are useful in evaluating our fundamental core operating performance. Specifically,
we believe the non-GAAP Adjusted Net Income (Loss) and Adjusted EBITDA results provide useful information to both management and
investors by excluding certain income and expenses that our management believes are not indicative of our core operating results.
Although we use Adjusted Net Income (Loss) and Adjusted EBITDA to manage our business, including the preparation of our annual
operating budget and financial projections, we believe that non-GAAP financial measures have limitations and do not reflect all
of the amounts associated with our results of operations as determined in accordance with GAAP and that these measures should only
be used to evaluate our results of operations in conjunction with the corresponding GAAP financial measures. A reconciliation of
Adjusted Net Income (Loss and) Adjusted EBITDA to net income (loss), GAAP, is included below:
Reconciliation of Net Loss to Adjusted
Net Income (Loss)
| | |
Three Months Ended | | |
Nine Months Ended | |
| | |
September 30, | | |
September 30, | |
| | |
2015 | | |
2014 | | |
2015 | | |
2014 | |
| Net income (loss) | |
$ | (28,920,487 | ) | |
$ | 1,190,716 | | |
$ | (48,863,061 | ) | |
$ | 265,796 | |
| Add back: | |
| | | |
| | | |
| | | |
| | |
| Loss (income) on mark-to-market of derivatives, net of tax (a) | |
| 3,297,358 | | |
| (1,352,798 | ) | |
| 4,300,184 | | |
| (663,639 | ) |
| Impairment of oil and gas properties, net of tax (b) | |
| 30,995,000 | | |
| – | | |
| 46,318,000 | | |
| – | |
| Adjusted net income (loss) | |
$ | 5,371,871 | | |
$ | (162,082 | ) | |
$ | 1,755,123 | | |
$ | (397,843 | ) |
| | |
| | | |
| | | |
| | | |
| | |
| Weighted average common shares outstanding - basic | |
| 47,979,990 | | |
| 47,979,990 | | |
| 47,979,990 | | |
| 47,979,990 | |
| | |
| | | |
| | | |
| | | |
| | |
| Weighted average common shares outstanding - fully diluted | |
| 47,979,990 | | |
| 49,588,039 | | |
| 47,979,990 | | |
| 49,824,437 | |
| | |
| | | |
| | | |
| | | |
| | |
| Net income (loss) per common share – basic | |
$ | (0.60 | ) | |
$ | 0.02 | | |
$ | (1.02 | ) | |
$ | 0.01 | |
| Add: | |
| | | |
| | | |
| | | |
| | |
| Change due to loss (income) on mark-to-market of derivatives, net of tax | |
| 0.07 | | |
| (0.03 | ) | |
| 0.09 | | |
| (0.01 | ) |
| Change due to impairment of oil and gas properties, net of tax | |
| 0.65 | | |
| – | | |
| 0.97 | | |
| – | |
| Adjusted net income (loss) per common share – basic | |
$ | 0.11 | | |
$ | (0.00 | ) | |
$ | 0.04 | | |
$ | (0.01 | ) |
| | |
| | | |
| | | |
| | | |
| | |
| Net income (loss) per common share – fully diluted | |
$ | (0.60 | ) | |
$ | 0.02 | | |
$ | (1.02 | ) | |
$ | 0.01 | |
| Add: | |
| | | |
| | | |
| | | |
| | |
| Change due to loss (income) on mark-to- market of derivatives, net of tax | |
| 0.07 | | |
| (0.03 | ) | |
| 0.09 | | |
| (0.01 | ) |
| Change due to impairment of oil and gas properties, net of tax | |
| 0.65 | | |
| – | | |
| 0.97 | | |
| – | |
| Adjusted net income (loss) per common share – fully diluted | |
$ | 0.11 | | |
$ | (0.00 | ) | |
$ | 0.04 | | |
$ | (0.01 | ) |
(a)Adjusted to reflect tax expense
(benefit), computed based on our effective tax rate of approximately 0% and 12% for the three and nine months ended September 30, 2015,
and 37% in both the three and nine months ended September 30, 2014, consisting of $-0- and $795,000 for the three month
ended September 30, 2015 and 2014, respectively, and ($586,000) and $389,000 for the nine months ended September 30, 2015 and 2014,
respectively.
(b)Adjusted to reflect tax expense,
computed based on our effective tax rate of approximately 0% and 12% for the three and nine months ended September 30, 2015,
and 37% in both the three and nine months ended September 30, 2014, consisting of $8,369,000 and $-0- for the three month
ended September 30, 2015 and 2014, respectively, and $14,211,000 and $-0- for the nine months ended September 30, 2015 and 2014,
respectively.
Reconciliation of Net Loss to Adjusted
EBITDA
| | |
Three Months Ended | | |
Nine Months Ended | |
| | |
September 30, | | |
September 30, | |
| | |
2015 | | |
2014 | | |
2015 | | |
2014 | |
| Net income (loss) | |
$ | (28,920,487 | ) | |
$ | 1,190,716 | | |
$ | (48,863,061 | ) | |
$ | 265,796 | |
| Add back: | |
| | | |
| | | |
| | | |
| | |
| Interest expense, net, excluding amortization of warrant based financing
costs | |
| 1,519,058 | | |
| 1,280,674 | | |
| 4,311,715 | | |
| 3,346,655 | |
| Income tax provision | |
| – | | |
| 700,587 | | |
| (6,593,040 | ) | |
| 110,849 | |
| Depreciation, depletion, and amortization | |
| 1,782,590 | | |
| 2,283,917 | | |
| 7,358,642 | | |
| 6,018,507 | |
| Impairment of oil and gas properties | |
| 30,995,000 | | |
| – | | |
| 52,634,000 | | |
| – | |
| Accretion of abandonment liability | |
| 8,039 | | |
| 5,833 | | |
| 23,900 | | |
| 15,486 | |
| Share based compensation | |
| 314,374 | | |
| 302,961 | | |
| 949,888 | | |
| 901,964 | |
| Loss (gain) on mark-to market of derivatives | |
| 3,297,358 | | |
| (2,147,798 | ) | |
| 4,886,184 | | |
| (1,052,639 | ) |
| | |
| | | |
| | | |
| | | |
| | |
| Adjusted EBITDA | |
$ | 8,995,932 | | |
$ | 3,616,890 | | |
$ | 14,708,228 | | |
$ | 9,606,618 | |
Our adjusted EBITDA for the nine month periods
ended September 30, 2015 includes income from the Dahl Federal well that was recognized in the current period based on
activity in prior periods of $1,027,995.
BLACK RIDGE OIL & GAS, INC.
CONDENSED
BALANCE SHEETS
| | |
September 30, | | |
December 31, | |
| | |
2015 | | |
2014 | |
| | |
(Unaudited) | | |
| |
| ASSETS | |
| | | |
| | |
| | |
| | | |
| | |
| Current assets: | |
| | | |
| | |
| Cash and cash equivalents | |
$ | 58,599 | | |
$ | 94,682 | |
| Derivative instruments, current | |
| 2,693,561 | | |
| 3,571,803 | |
| Accounts receivable | |
| 3,861,923 | | |
| 5,740,171 | |
| Prepaid expenses | |
| 49,107 | | |
| 41,387 | |
| Total current assets | |
| 6,663,190 | | |
| 9,448,043 | |
| | |
| | | |
| | |
| Property and equipment: | |
| | | |
| | |
| Oil and natural gas properties, full cost method of accounting: | |
| | | |
| | |
| Proved properties | |
| 128,083,460 | | |
| 112,418,105 | |
| Unproved properties | |
| 803,718 | | |
| 591,121 | |
| Other property and equipment | |
| 139,004 | | |
| 139,004 | |
| Total property and equipment | |
| 129,026,182 | | |
| 113,148,230 | |
| Less, accumulated depreciation, amortization, depletion and allowance for impairment | |
| (78,895,166 | ) | |
| (18,902,524 | ) |
| Total property and equipment, net | |
| 50,131,016 | | |
| 94,245,706 | |
| | |
| | | |
| | |
| Derivative instruments, long-term | |
| – | | |
| 4,007,942 | |
| Debt issuance costs, net | |
| 463,792 | | |
| 701,019 | |
| | |
| | | |
| | |
| Total assets | |
$ | 57,257,998 | | |
$ | 108,402,710 | |
| | |
| | | |
| | |
| LIABILITIES AND STOCKHOLDERS' EQUITY | |
| | | |
| | |
| | |
| | | |
| | |
| Current liabilities: | |
| | | |
| | |
| Accounts payable | |
$ | 8,438,772 | | |
$ | 10,291,262 | |
| Accrued expenses | |
| 65,207 | | |
| 57,435 | |
| Total current liabilities | |
| 8,503,979 | | |
| 10,348,697 | |
| | |
| | | |
| | |
| Asset retirement obligations | |
| 353,095 | | |
| 286,804 | |
| Revolving credit facilities and long term debt, net of discounts of
$1,461,093 and $2,072,483, respectively | |
| 57,458,543 | | |
| 51,834,603 | |
| Deferred tax liability | |
| – | | |
| 6,593,040 | |
| | |
| | | |
| | |
| Total liabilities | |
| 66,315,617 | | |
| 69,063,144 | |
| | |
| | | |
| | |
| Commitments and contingencies | |
| – | | |
| – | |
| | |
| | | |
| | |
| Stockholders' equity: | |
| | | |
| | |
| Preferred stock, $0.001 par value, 20,000,000 shares authorized, no shares
issued and outstanding | |
| – | | |
| – | |
| Common stock, $0.001 par value, 500,000,000 shares authorized, 47,979,990
shares issued and outstanding | |
| 47,980 | | |
| 47,980 | |
| Additional paid-in capital | |
| 34,117,590 | | |
| 33,651,714 | |
| Retained earnings (accumulated deficit) | |
| (43,223,189 | ) | |
| 5,639,872 | |
| Total stockholders' equity | |
| (9,057,619 | ) | |
| 39,339,566 | |
| | |
| | | |
| | |
| Total liabilities and stockholders' equity | |
$ | 57,257,998 | | |
$ | 108,402,710 | |
BLACK RIDGE OIL & GAS, INC.
CONDENSED STATEMENTS OF OPERATIONS
(Unaudited)
| | |
For the Three Months | | |
For the Nine Months | |
| | |
Ended September 30, | | |
Ended September 30, | |
| | |
2015 | | |
2014 | | |
2015 | | |
2014 | |
| Oil and gas sales | |
$ | 3,359,684 | | |
$ | 5,492,326 | | |
$ | 11,296,220 | | |
$ | 15,076,743 | |
| Gain (loss) on settled derivatives | |
| 7,456,284 | | |
| (70,253 | ) | |
| 9,436,903 | | |
| (449,135 | ) |
| Gain (loss) on the mark-to-market of derivatives | |
| (3,297,358 | ) | |
| 2,147,798 | | |
| (4,886,184 | ) | |
| 1,052,639 | |
| Total revenues | |
| 7,518,610 | | |
| 7,569,871 | | |
| 15,846,939 | | |
| 15,680,247 | |
| | |
| | | |
| | | |
| | | |
| | |
| Operating expenses: | |
| | | |
| | | |
| | | |
| | |
| Production expenses | |
| 887,187 | | |
| 670,404 | | |
| 3,030,707 | | |
| 1,773,458 | |
| Production taxes | |
| 330,186 | | |
| 588,923 | | |
| 1,171,530 | | |
| 1,585,755 | |
| General and administrative | |
| 754,788 | | |
| 690,189 | | |
| 2,295,241 | | |
| 2,095,071 | |
| Depletion of oil and gas properties | |
| 1,778,580 | | |
| 2,275,703 | | |
| 7,346,356 | | |
| 5,994,180 | |
| Impairment of oil and gas properties | |
| 30,995,000 | | |
| – | | |
| 52,634,000 | | |
| – | |
| Accretion of discount on asset retirement obligations | |
| 8,039 | | |
| 5,833 | | |
| 23,900 | | |
| 15,486 | |
| Depreciation and amortization | |
| 4,010 | | |
| 8,214 | | |
| 12,286 | | |
| 24,327 | |
| Total operating expenses | |
| 34,757,790 | | |
| 4,239,266 | | |
| 66,514,020 | | |
| 11,488,277 | |
| | |
| | | |
| | | |
| | | |
| | |
| Net operating income (loss) | |
| (27,239,180 | ) | |
| 3,330,605 | | |
| (50,667,081 | ) | |
| 4,191,970 | |
| | |
| | | |
| | | |
| | | |
| | |
| Other income (expense): | |
| | | |
| | | |
| | | |
| | |
| Other income | |
| – | | |
| – | | |
| 6,707 | | |
| – | |
| Interest income | |
| – | | |
| 972 | | |
| – | | |
| 972 | |
| Interest (expense) | |
| (1,681,307 | ) | |
| (1,440,274 | ) | |
| (4,795,727 | ) | |
| (3,816,297 | ) |
| Total other income (expense) | |
| (1,681,307 | ) | |
| (1,439,302 | ) | |
| (4,789,020 | ) | |
| (3,815,325 | ) |
| | |
| | | |
| | | |
| | | |
| | |
| Income (loss) before provision for income taxes | |
| (28,920,487 | ) | |
| 1,891,303 | | |
| (55,456,101 | ) | |
| 376,645 | |
| | |
| | | |
| | | |
| | | |
| | |
| Provision for income taxes | |
| – | | |
| (700,587 | ) | |
| 6,593,040 | | |
| (110,849 | ) |
| | |
| | | |
| | | |
| | | |
| | |
| Net income (loss) | |
$ | (28,920,487 | ) | |
$ | 1,190,716 | | |
$ | (48,863,061 | ) | |
$ | 265,796 | |
| | |
| | | |
| | | |
| | | |
| | |
| | |
| | | |
| | | |
| | | |
| | |
| Weighted average common shares outstanding - basic | |
| 47,979,990 | | |
| 47,979,990 | | |
| 47,979,990 | | |
| 47,979,990 | |
| Weighted average common shares outstanding - fully diluted | |
| 47,979,990 | | |
| 49,588,039 | | |
| 47,979,990 | | |
| 49,824,437 | |
| | |
| | | |
| | | |
| | | |
| | |
| Net loss per common share - basic | |
$ | (0.60 | ) | |
$ | 0.02 | | |
$ | (1.02 | ) | |
$ | 0.01 | |
| Net loss per common share - fully diluted | |
$ | (0.60 | ) | |
$ | 0.02 | | |
$ | (1.02 | ) | |
$ | 0.01 | |
BLACK RIDGE OIL & GAS, INC.
CONDENSED STATEMENTS OF CASH FLOWS
(Unaudited)
| | |
For the Nine Months | |
| | |
Ended September 30, | |
| | |
2015 | | |
2014 | |
| CASH FLOWS FROM OPERATING ACTIVITIES | |
| | | |
| | |
| Net income (loss) | |
$ | (48,863,061 | ) | |
$ | 265,796 | |
| Adjustments to reconcile net income (loss) to net cash provided by operating activities: | |
| | | |
| | |
| Depletion of oil and gas properties | |
| 7,346,356 | | |
| 5,994,180 | |
| Depreciation and amortization | |
| 12,286 | | |
| 24,327 | |
| Amortization of debt issuance costs | |
| 287,227 | | |
| 229,936 | |
| Accretion of discount on asset retirement obligations | |
| 23,900 | | |
| 15,486 | |
| Loss (gain) on the mark-to-market of derivatives | |
| 4,886,184 | | |
| (1,052,639 | ) |
| Accrued payment in kind interest applied to long term debt | |
| 962,550 | | |
| 787,344 | |
| Amortization of original issue discount on debt | |
| 127,378 | | |
| 102,566 | |
| Amortization of debt discounts, warrants | |
| 484,012 | | |
| 468,670 | |
| Common stock options issued to employees and directors | |
| 465,876 | | |
| 433,294 | |
| Deferred income taxes | |
| (6,593,040 | ) | |
| 110,849 | |
| Impairment of oil and natural gas properties | |
| 52,634,000 | | |
| – | |
| Decrease (increase) in current assets: | |
| | | |
| | |
| Accounts receivable | |
| 1,878,248 | | |
| (1,233,582 | ) |
| Prepaid expenses | |
| (7,720 | ) | |
| (45,916 | ) |
| Increase (decrease) in current liabilities: | |
| | | |
| | |
| Accounts payable | |
| 153,024 | | |
| 223,779 | |
| Accrued expenses | |
| 7,772 | | |
| 61,423 | |
| Net cash provided by operating activities | |
| 13,804,992 | | |
| 6,385,513 | |
| | |
| | | |
| | |
| CASH FLOWS FROM INVESTING ACTIVITIES | |
| | | |
| | |
| Proceeds from sale or swap of oil and gas properties | |
| 127,348 | | |
| 1,360,920 | |
| Purchases of oil and gas properties and development capital expenditures | |
| (17,968,423 | ) | |
| (17,410,744 | ) |
| Advances to operators | |
| – | | |
| (5,742,272 | ) |
| Purchases of other property and equipment | |
| – | | |
| (11,131 | ) |
| Net cash used in investing activities | |
| (17,841,075 | ) | |
| (21,803,227 | ) |
| | |
| | | |
| | |
| CASH FLOWS FROM FINANCING ACTIVITIES | |
| | | |
| | |
| Advances from revolving credit facilities and long term debt | |
| 14,000,000 | | |
| 24,150,000 | |
| Repayments on revolving credit facilities | |
| (9,950,000 | ) | |
| (9,600,000 | ) |
| Debt issuance costs | |
| (50,000 | ) | |
| (254,394 | ) |
| Net cash provided by financing activities | |
| 4,000,000 | | |
| 14,295,606 | |
| | |
| | | |
| | |
| NET CHANGE IN CASH | |
| (36,083 | ) | |
| (1,122,108 | ) |
| CASH AT BEGINNING OF PERIOD | |
| 94,682 | | |
| 1,150,347 | |
| CASH AT END OF PERIOD | |
$ | 58,599 | | |
$ | 28,239 | |
| | |
| | | |
| | |
| | |
| | | |
| | |
| SUPPLEMENTAL INFORMATION: | |
| | | |
| | |
| Interest paid | |
$ | 3,292,793 | | |
$ | 2,411,463 | |
| Income taxes paid | |
$ | – | | |
$ | – | |
| | |
| | | |
| | |
| NON-CASH INVESTING AND FINANCING ACTIVITIES: | |
| | | |
| | |
| Net change in accounts payable for purchase of oil and gas properties | |
$ | (2,005,514 | ) | |
$ | 3,821,375 | |
| Advances to operators applied to development of oil and gas properties | |
$ | – | | |
$ | 4,285,575 | |
| Capitalized asset retirement costs, net of revision in estimate | |
$ | 42,391 | | |
$ | 61,815 | |
Cautionary Statement
as to Forward-Looking Statements
Certain statements
contained herein, which are not historical, are forward-looking statements that are subject to risks and uncertainties not known
or disclosed herein that could cause actual results to differ materially from those expressed herein. These statements may include
projections and other "forward-looking statements" within the meaning of the federal securities laws. Any such projections
or statements reflect management’s current views about future events and financial performance. No assurances can be given
that such events or performance will occur as projected and actual results may differ materially from those projected. Important
factors that could cause the actual results to differ materially from those projected include, without limitation, general economic
or industry conditions nationally and/or in the communities in which our Company conducts business, volatility in commodity prices
for crude oil and natural gas, environmental risks, legislation or regulatory requirements, conditions of the securities markets,
our ability to raise capital or have access to debt financing, changes in accounting principles, policies or guidelines, financial
or political instability, acts of war or terrorism, increases in operator costs, other economic, competitive, governmental, regulatory
and technical factors affecting our Company's operations, products, services and prices and other risks inherent in the Company's
businesses that are detailed in the Company's Securities and Exchange Commission ("SEC") filings. Readers are encouraged
to review these risks in the Company's SEC filings.
About the Company
Black Ridge
Oil & Gas is an oil and gas exploration and production company based in Minnetonka, Minnesota. Black Ridge's focus is
exclusive to the Williston Basin Bakken and Three Forks trend in North Dakota and Montana. For additional
information, visit the Company's website at www.blackridgeoil.com.
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
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Contact
Black Ridge Oil & Gas, Inc.
Ken DeCubellis, Chief Executive
Officer
952-426-1241
www.blackridgeoil.com
