Attached files
| file | filename |
|---|---|
| 8-K - CURRENT REPORT ON FORM 8-K - Sow Good Inc. | blackridge_8k.htm |
| EX-99.2 - PRESENTATION - Sow Good Inc. | blackridge_ex9902.htm |
Exhibit 99.1
Black Ridge Oil & Gas Announces 2014 Fourth Quarter and Full Year Results
MINNETONKA, Minn., March 30, 2015 - Black Ridge Oil & Gas, Inc. ("the Company") (OTCQB: ANFC), a growth-oriented exploration and production company focused on non-operated Bakken and Three Forks properties, today announced financial and operating results for the three months and year ended December 31, 2014.
2014 Company Highlights
| · | Annual production increased 168% to 291.8 thousand barrels of oil equivalent (“MBoe”), an average of approximately 799 barrels of oil equivalent per day (“Boe/d”) |
| · | Oil and gas sales increased 127% to $21.1 million |
| · | Total proved reserves increased 18% to 5.4 MMBoe |
| · | Pre-tax PV-10% of the total proved reserves as of December 31, 2014 increased 35% to $100.3 million |
| · | Ended 2014 with production from 247 gross (7.88 net) wells, up from 153 gross (4.87 net) at the end of 2013, an increase of 62% on a net well basis |
| · | Recorded $14.4 million of adjusted EBITDA, representing an increase of 145% from 2013 |
| · | Fourth quarter production increased to 1,190 Boe/d, a 233% increase over the fourth quarter of 2013 and a 56% sequential increase over the third quarter of 2014 |
Acreage and Drilling
As of December 31, 2014, the Company controlled approximately 10,000 net acres in the Williston Basin. Approximately 63% of the acreage is held by production. In 2014, the Company added 3.01 net wells to production, ending the year with a total producing well count of 7.88 net wells. Additionally, the Company had 2.8 additional net wells in development at year end.
Management Comment
Ken DeCubellis, Black Ridge’s CEO, commented, “We are proud of our execution and growth in 2014. Our disciplined process for making investment decisions has the Company on a solid foundation as we closed out 2014. Now, all of our attention has shifted to executing a plan to manage through the commodity price downturn. Measured production growth, within the context of available liquidity and prudent balance sheet risk, and our continued focus on making investment decisions that exceed our internal rate of return threshold are the pillars of our plan that will help guide the Company through the down cycle.”
2015 Capital Program and Production Guidance
The Company expects 2015 capital expenditures to total approximately $16 million. The Company expects additional cash expenditures of approximately $9 million related to wells in process and accrued as of December 31, 2014. Black Ridge expects to bring 2.8 net wells online during the year, with the majority of the additions coming in the third and fourth quarters. The Company’s Teton and Corral Creek Unit projects are expected to comprise approximately 75% of the net well additions. These two projects, located in core of the Williston Basin in eastern McKenzie and northern Dunn counties, respectively, are expected to meet or exceed the Company’s return thresholds based on current oil prices. As the price environment dictates, the Company may look to strategically divest mature producing assets. Total Company production is expected to average approximately 1,100 boe/d in 2015.
Liquidity Position and Borrowing Base
Black Ridge ended the year with $22.6 million drawn on its $35 million senior secured revolving credit facility. Subsequent to year-end, the senior secured borrowing base was re-determined to $34 million. The next redetermination date is scheduled for October 1, 2015.
| 1 |
Hedging Update
In 2014, the Company realized a $511,451 gain on settled derivatives and a $7,793,421 unrealized gain on mark-to-market adjustments to its outstanding derivatives contracts. The following table summarizes the Company’s open derivatives contracts as of December 31, 2014.
| Weighted Average Price of | |||||
| Open Commodity Swap Contracts | |||||
| Weighted | |||||
| Volumes | Average | ||||
| Year | (Bbl) | Price (WTI) | |||
| 2015 | 87,000 | $ | 89.84 | ||
| 2016 | 84,000 | $ | 89.73 | ||
| 2017 | 78,000 | $ | 87.18 | ||
In addition to the open commodity swap contracts, the Company has entered into costless collar contracts. The costless collars are used to establish floor and ceiling prices on anticipated crude oil production. There were no premiums paid or received by us related to the costless collar contracts. The following table reflects open costless collar contracts as of December 31, 2014.
| Oil | Floor/Ceiling | |||||
| Term | (Barrels) | Price (WTI) | Basis | |||
| Costless Collars – Crude Oil | ||||||
| 01/01/2015 – 12/31/2015 | 36,000 | $75.00/$95.60 | NYMEX | |||
| 01/01/2016 – 06/30/2016 | 10,002 | $80.00/$89.50 | NYMEX |
2014 Operating and Financial Results
The following table presents selected operating and financial data for the periods indicated.
| Year Ended | ||||||||||||
| December 31, | ||||||||||||
| 2014 | 2013 | % Change | ||||||||||
| Net Production: | ||||||||||||
| Oil (Bbl) | 256,256 | 99,979 | 156 | |||||||||
| Natural Gas (Mcf) | 213,141 | 52,973 | 302 | |||||||||
| Barrel of Oil Equivalent (Boe) | 291,780 | 108,808 | 168 | |||||||||
| Average Daily Production (Boe/d) | 799 | 298 | 168 | |||||||||
| Average Sales Prices: | ||||||||||||
| Oil (per Bbl) | $ | 78.64 | $ | 89.58 | (12 | ) | ||||||
| Effect of oil hedges on average price (per Bbl) | $ | 1.99 | $ | 0.54 | ||||||||
| Oil net of hedging (per Bbl) | $ | 80.63 | $ | 90.12 | (11 | ) | ||||||
| Natural Gas (per Mcf) | $ | 4.46 | $ | 6.04 | (26 | ) | ||||||
| Effect of natural gas hedges on average price (per Mcf) | $ | – | $ | – | ||||||||
| Natural gas net of hedging (per Mcf) | $ | 4.46 | $ | 6.04 | (26 | ) | ||||||
| Per Boe including settled derivatives | $ | 74.08 | $ | 85.75 | (14 | ) | ||||||
| Operating Expenses (per Boe): | ||||||||||||
| Production Expenses | $ | 9.27 | $ | 10.53 | (12 | ) | ||||||
| Production Taxes | $ | 7.55 | $ | 9.34 | (19 | ) | ||||||
| G&A Expense | $ | 9.91 | $ | 21.14 | (53 | ) | ||||||
| Depletion, Depreciation, Amortization and Accretion | $ | 32.26 | $ | 34.36 | (6 | ) | ||||||
| 2 |
Year-End 2014 Results
For the full year 2014, Company production increased to 291.8 Mboe, an average of 799 Boe/d, representing a 168% increase over 2013 production of 108.8 MBoe. Oil and gas sales were $21.1 million, compared to $9.3 million in 2013, an increase of 127%. The increase in production and revenues was due to the completion of an additional 94 gross (3.01 net) wells in 2014.
During 2014, the Company realized an average price of $78.64 per Bbl of oil compared to an average price of $89.58 per Bbl of oil in 2013. The Company’s production was comprised of 88% oil and 12% natural gas and natural gas liquids in 2014 on a Boe basis.
Lease operating expenses for 2014 were $2.7 million, or $9.27 per Boe, compared to $1.1 million, or $10.53 per Boe, for 2013.
General and administrative expenses (“G&A”) for 2014 were $2.9 million, or $9.91 per Boe, compared to $2.3 million, or $21.14 per Boe for 2013. Cash G&A (non-GAAP, excludes stock-based compensation expense) was $2.3 million, or $7.93 per Boe for 2014 compared to $1.7 million, or $15.22 per Boe for 2013.
The Company recorded $14.4 million of adjusted EBITDA in 2014, representing an increase of 145% from $5.9 million of adjusted EBITDA in 2013. Adjusted EBITDA is a non-GAAP financial measure. Please refer to the reconciliation in this release for additional information about this measure.
Fourth Quarter 2014 Operating and Financial Results
The following table presents selected operating and financial data for the periods indicated.
| Three Months Ended | ||||||||||||
| December 31, | ||||||||||||
| 2014 | 2013 | % Change | ||||||||||
| Net Production: | ||||||||||||
| Oil (Bbl) | 91,686 | 29,394 | 212 | |||||||||
| Natural Gas (Mcf) | 106,683 | 21,135 | 405 | |||||||||
| Barrel of Oil Equivalent (Boe) | 109,467 | 32,916 | 233 | |||||||||
| Average Daily Production (Boe/d) | 1,190 | 358 | 233 | |||||||||
| Average Sales Prices: | ||||||||||||
| Oil (per Bbl) | $ | 62.35 | $ | 84.24 | (26 | ) | ||||||
| Effect of oil hedges on average price (per Bbl) | $ | 10.48 | $ | 2.54 | ||||||||
| Oil net of hedging (per Bbl) | $ | 72.83 | $ | 86.78 | (16 | ) | ||||||
| Natural Gas (per Mcf) | $ | 2.90 | $ | 5.94 | (51 | ) | ||||||
| Effect of natural gas hedges on average price (per Mcf) | $ | – | $ | – | ||||||||
| Natural gas net of hedging (per Mcf) | $ | 2.90 | $ | 5.94 | (51 | ) | ||||||
| Per Boe including settled derivatives | $ | 63.82 | $ | 81.31 | (22 | ) | ||||||
| Operating Expenses (per Boe): | ||||||||||||
| Production Expenses | $ | 8.52 | $ | 10.11 | (16 | ) | ||||||
| Production Taxes | $ | 5.64 | $ | 8.90 | (37 | ) | ||||||
| G&A Expense | $ | 7.28 | $ | 17.76 | (59 | ) | ||||||
| Depletion, Depreciation, Amortization and Accretion | $ | 30.85 | $ | 32.89 | (6 | ) | ||||||
| 3 |
Fourth Quarter 2014 Results
During the fourth quarter of 2014, Company production totaled 109.5 Mboe, an average of 1,190 Boe/d, representing a sequential increase of 56% over third quarter 2014 production of 70.0 Mboe and a year-over-year increase of 233% over 32.9 Mboe in the fourth quarter of 2013.
Oil and gas sales, which exclude the effect of derivatives, totaled $6.0 million in the fourth quarter of 2014, compared to $2.6 million in the fourth quarter of 2013, an increase of 132%.
Average realized prices for the fourth quarter of 2014, before the effect of commodity derivatives, were $62.35 per Bbl of oil and $2.90 per Mcf of natural gas, compared to $84.24 per Bbl of oil and $5.94 per Mcf of natural gas in the fourth quarter of 2013.
Lease operating expenses for the fourth quarter of 2014 were $932 thousand, or $8.52 per Boe, compared to $333 thousand, or $10.11 per Boe for the fourth quarter of 2013, a decrease of 16% on a per Boe basis.
General and administrative expenses (“G&A”) for the fourth quarter of 2014 were $797 thousand, or $7.28 per Boe, compared to $584 thousand, or $17.76 per Boe for the fourth quarter of 2013. Cash G&A (non-GAAP, excludes stock-based compensation expense) was $651 thousand, or $5.95 per Boe for the fourth quarter of 2014 compared to $442 thousand, or $13.44 per Boe for the fourth quarter of 2013.
The Company recorded $4.8 million of adjusted EBITDA in the fourth quarter of 2014, representing a 143% increase over $2.0 million of adjusted EBITDA in the fourth quarter of 2013. Adjusted EBITDA is a non-GAAP financial measure. Please refer to the reconciliation in this release for additional information about this measure.
2014 Proved Reserves
As of December 31, 2014, Black Ridge had estimated proved reserves of 5.4 MMBoe, of which 38% were classified as proved developed, and 90% was crude oil. These estimated proved reserves had a pre-tax PV10% value of $100.3 million, a 35% increase over 2013 proved reserves pre-tax PV10% value of $74.4 million. Reserve replacement for the Company in 2014 was 280%. The Company's estimated reserves were prepared by its independent reservoir engineering firm, Netherland, Sewell & Associates, Inc.
| Reserve Category(1) | % of Reserves | Oil (MBbls) | Gas (MMcf) | 2014 Mboe(2) | 2013 Mboe | % Change | 2014 PV-10(3) ($000's) | |||||||||||||||||||||
| Proved Developed Producing | 36% | 1,688 | 1,276 | 1,901 | 998 | 90% | $ | 58,939 | ||||||||||||||||||||
| Proved Developed Non-Producing | 2% | 111 | 87 | 126 | 38 | 332% | 4,743 | |||||||||||||||||||||
| Proved Undeveloped | 62% | 2,999 | 1,984 | 3,329 | 3,502 | (5% | ) | 36,693 | ||||||||||||||||||||
| Total Proved | 100% | 4,798 | 3,347 | 5,356 | 4,538 | 18% | $ | 100,335 | ||||||||||||||||||||
| (1) | The SEC Pricing Proved Reserves table above values crude oil and natural gas reserve quantities and related discounted future net cash flows as of December 31, 2014 assuming a constant realized price of $83.26 per barrel of crude oil and a constant realized price of $7.10 per Mcf of natural gas. The values presented in both tables above were calculated by Netherland, Sewell & Associates, Inc. | |
| (2) | BOE are computed based on a conversion ratio of one BOE for each barrel of crude oil and one BOE for every 6,000 cubic feet (i.e., 6 Mcf) of natural gas. |
| 4 |
| (3) | Pre-tax PV10% may be considered a non-GAAP financial measure as defined by the SEC and is derived from the standardized measure of discounted future net cash flows, which is the most directly comparable standardized financial measure. Pre-tax PV10% is computed on the same basis as the standardized measure of discounted future net cash flows but without deducting future income taxes. We believe Pre-tax PV10% is a useful measure for investors for evaluating the relative monetary significance of our crude oil and natural gas properties. We further believe investors may utilize our Pre-tax PV10% as a basis for comparison of the relative size and value of our reserves to other companies because many factors that are unique to each individual company impact the amount of future income taxes to be paid. Our management uses this measure when assessing the potential return on investment related to our crude oil and natural gas properties and acquisitions. However, Pre-tax PV10% is not a substitute for the standardized measure of discounted future net cash flows. Our Pre-tax PV10% and the standardized measure of discounted future net cash flows do not purport to present the fair value of our crude oil and natural gas reserves. |
Producing Wells
The following table sets forth wells in which Black Ridge holds a participating interest that were completed or acquired during the quarter ending December 31, 2014.
| Well | Operator | Location | WI(1) |
| Matilda Bay 1-15H | Slawson | Williams, ND | 0.100 |
| McCracken 2758 21-10 5B | Oasis | Roosevelt, MT | 0.071 |
| McCracken 2758 44-9 4B | Oasis | Roosevelt, MT | 0.071 |
| McCracken 2758 34-9 3B | Oasis | Roosevelt, MT | 0.071 |
| McCracken 2758 41-10 6B | Oasis | Roosevelt, MT | 0.071 |
| Ironbank 5-14-13TFH | Slawson | Williams, ND | 0.055 |
| Revolver 7-35TFH | Slawson | Mountrail, ND | 0.016 |
| CCU Powell 41-29MBH | Burlington Resources | Dunn, ND | 0.008 |
| CCU Olympian 11-2TFH | Burlington Resources | Dunn, ND | 0.008 |
| Jersey 23-6H1 | Continental | Mountrail, ND | 0.008 |
| Jersey 24-6H3 | Continental | Mountrail, ND | 0.008 |
| Jersey 25-6H | Continental | Mountrail, ND | 0.008 |
| Jersey 26-6H2 | Continental | Mountrail, ND | 0.008 |
| Jersey 27-6H1 | Continental | Mountrail, ND | 0.008 |
| Jersey 28-6H3 | Continental | Mountrail, ND | 0.008 |
| Jersey 29-6XH | Continental | Mountrail, ND | 0.008 |
(1)The working interests are based on Black Ridge's internal records and may be subject to change by operators' third-party legal counsel in preparing final division order title opinions for each well.
"Drilling" Wells
The following table sets forth wells in which Black Ridge holds a participating interest that were either preparing to drill, drilling, awaiting completion or completing as of December 31, 2014.
| Well | Operator | Location | WI(1) |
| Bootleg 6-14-15TFH | Slawson | Williams, ND | 0.113 |
| Bootleg 7-14-15TFH | Slawson | Williams, ND | 0.113 |
| Bootleg 8-14-15TF2H | Slawson | Williams, ND | 0.113 |
| Rainbow 10-19-18HBK | Samson Oil and Gas | Williams, ND | 0.100 |
| Teton 5-1-3TFSH | Burlington Resources | McKenzie, ND | 0.088 |
| Kings Canyon 6-8-34UTFH | Burlington Resources | McKenzie, ND | 0.088 |
| Kings Canyon 4-8-34UTFH | Burlington Resources | McKenzie, ND | 0.088 |
| 5 |
| Kings Canyon 4-8-34MBH | Burlington Resources | McKenzie, ND | 0.088 |
| Teton 2-8-10MBH | Burlington Resources | McKenzie, ND | 0.088 |
| Teton 3-8-10MBH | Burlington Resources | McKenzie, ND | 0.088 |
| Teton 8-8-10TFSH | Burlington Resources | McKenzie, ND | 0.088 |
| Teton 7-1-3TFSH | Burlington Resources | McKenzie, ND | 0.088 |
| Kings Canyon 7-8-34MBH | Burlington Resources | McKenzie, ND | 0.088 |
| Kings Canyon 5-8-34UTF | Burlington Resources | McKenzie, ND | 0.088 |
| Teton 5-8-10MBH | Burlington Resources | McKenzie, ND | 0.088 |
| Teton 6-8-10TFSH | Burlington Resources | McKenzie, ND | 0.088 |
| Teton 7-8-10MBH | Burlington Resources | McKenzie, ND | 0.088 |
| Kings Canyon 2-8-34UTFH | Burlington Resources | McKenzie, ND | 0.088 |
| Kings Canyon 3-1-27MTFH | Burlington Resources | McKenzie, ND | 0.088 |
| Kings Canyon 6-1-27MBH | Burlington Resources | McKenzie, ND | 0.088 |
| Kings Canyon 6-1-27MTFH | Burlington Resources | McKenzie, ND | 0.088 |
| Kings Canyon 4-1-27MTFH | Burlington Resources | McKenzie, ND | 0.088 |
| Teton 6-8-10MBH | Burlington Resources | McKenzie, ND | 0.088 |
| Billabong 2-13-14HBK | Slawson | Williams, ND | 0.075 |
| Remingteton 8-8-10MBH | Burlington Resources | McKenzie, ND | 0.062 |
| Ironbank 4-14-13TFH | Slawson | Williams, ND | 0.055 |
| Ironbank 7-14-13TFH | Slawson | Williams, ND | 0.054 |
| Ironbank 6-14-13TFH | Slawson | Williams, ND | 0.054 |
| DeKing 1-8-34MBH-ULW | Burlington Resources | McKenzie, ND | 0.021 |
| Gobbler 6-35-26TFH | Slawson | Mountrail, ND | 0.008 |
| Duletski Federal 14-12PH | Whiting | Billings, ND | 0.008 |
| Aaberg 8-5N-1H | Mountain Divide | Divide, ND | 0.008 |
| CCU Powell 41-29TFH | Burlington Resources | Dunn, ND | 0.008 |
| CCU Pullman 2-8-7MBH | Burlington Resources | Dunn, ND | 0.008 |
| CCU Pullman 5-8-7TFH | Burlington Resources | Dunn, ND | 0.008 |
| CCU Pullman 5-8-7MBH | Burlington Resources | Dunn, ND | 0.008 |
| CCU Pullman 6-8-7TFH | Burlington Resources | Dunn, ND | 0.008 |
| CCU Pullman 8-8-7TFH | Burlington Resources | Dunn, ND | 0.008 |
| CCU Pullman 7-8-7MBH | Burlington Resources | Dunn, ND | 0.008 |
| CCU Pullman 7-8-7TFH | Burlington Resources | Dunn, ND | 0.008 |
| CCU North Coast 31-25MBH | Burlington Resources | Dunn, ND | 0.008 |
| CCU North Coast 31-25TFH | Burlington Resources | Dunn, ND | 0.008 |
| CCU Pullman 6-8-7MBH | Burlington Resources | Dunn, ND | 0.008 |
| CCU Pullman 1-8-7TFH | Burlington Resources | Dunn, ND | 0.008 |
| CCU Pullman 3-8-7TFH | Burlington Resources | Dunn, ND | 0.008 |
| CCU Pullman 3-8-7MBH | Burlington Resources | Dunn, ND | 0.008 |
| CCU North Coast 4-8-23MBH | Burlington Resources | Dunn, ND | 0.008 |
| CCU North Coast 41-25MBH | Burlington Resources | Dunn, ND | 0.008 |
| CCU North Coast 4-8-23TFH | Burlington Resources | Dunn, ND | 0.008 |
| CCU Golden Creek 44-23TFH | Burlington Resources | Dunn, ND | 0.008 |
| CCU Golden Creek 44-23MBH | Burlington Resources | Dunn, ND | 0.008 |
| CCU North Coast 41-25TFH | Burlington Resources | Dunn, ND | 0.008 |
| 6 |
| CCU Main Streeter 24-24TFH | Burlington Resources | Dunn, ND | 0.008 |
| CCU Main Streeter 14-24MBH | Burlington Resources | Dunn, ND | 0.008 |
| CCU Dakotan 2-7-17MBH | Burlington Resources | Dunn, ND | 0.008 |
| CCU Dakotan 1-7-17TFH | Burlington Resources | Dunn, ND | 0.008 |
| CCU Dakotan 1-7-17MBH | Burlington Resources | Dunn, ND | 0.008 |
| CCU Dakotan 2-7-17TFH | Burlington Resources | Dunn, ND | 0.008 |
| CCU Dakotan 5-8-17TFH | Burlington Resources | Dunn, ND | 0.008 |
| CCU Dakotan 6-8-17MBH | Burlington Resources | Dunn, ND | 0.008 |
| CCU Dakotan 7-8-17TFH | Burlington Resources | Dunn, ND | 0.008 |
| CCU Dakotan 7-8-17MBH | Burlington Resources | Dunn, ND | 0.008 |
| CCU Dakotan 5-8-17MBH | Burlington Resources | Dunn, ND | 0.008 |
| CCU Dakotan 4-8-17TFH | Burlington Resources | Dunn, ND | 0.008 |
| Jersey 1-6H | Continental | Mountrail, ND | 0.008 |
| Jersey 3-6H1 | Continental | Mountrail, ND | 0.008 |
| Jersey 2-6H2 | Continental | Mountrail, ND | 0.008 |
| Jersey 7-6H | Continental | Mountrail, ND | 0.008 |
| Jersey 6-6H1 | Continental | Mountrail, ND | 0.008 |
| Jersey 4-6H3 | Continental | Mountrail, ND | 0.008 |
| Jersey 8-6H1 | Continental | Mountrail, ND | 0.008 |
| Jersey 5-6H | Continental | Mountrail, ND | 0.008 |
| P Johnson 153-98-1-6-7-16H | Kodiak | Williams, ND | 0.006 |
| P Johnson 153-98-1-6-7-16HA | Kodiak | Williams, ND | 0.006 |
| Oakdale 2-13H1 | Continental | Dunn, ND | 0.006 |
| Ryden 3-24H | Continental | Dunn, ND | 0.006 |
| Ryden 2-24AH1 | Continental | Dunn, ND | 0.006 |
| Oakdale 5-13H | Continental | Dunn, ND | 0.006 |
| Oakdale 3-13H | Continental | Dunn, ND | 0.006 |
| Oakdale 4-13H1 | Continental | Dunn, ND | 0.006 |
| Ryden 4-24H1 | Continental | Dunn, ND | 0.006 |
(1)The working interests are based on Black Ridge's internal records and may be subject to change by operators' third-party legal counsel in preparing final division order title opinions for each well.
| 7 |
Adjusted Net Income (Loss) and Adjusted EBITDA
In addition to reporting net income (loss) as defined under GAAP, we also present Adjusted Net Income (Loss) and Adjusted EBITDA. We define Adjusted Net Income (Loss) as net income excluding settlement income, net of settlement expenses, and tax. We define Adjusted EBITDA as net income before (i) interest expense, (ii) income taxes, (iii) depreciation, depletion and amortization, (iv) accretion of abandonment liability, and (v) non-cash expenses relating to share based payments recognized under ASC Topic 718. We believe the use of non-GAAP financial measures provides useful information to investors regarding our current financial performance; however, Adjusted Net Income (Loss) and Adjusted EBITDA do not represent, and should not be considered alternatives to GAAP measurements. We believe these measures are useful in evaluating our fundamental core operating performance. Specifically, we believe the non-GAAP Adjusted Net Income (Loss) and Adjusted EBITDA results provide useful information to both management and investors by excluding certain income and expenses that our management believes are not indicative of our core operating results. Although we use Adjusted Net Income (Loss) and Adjusted EBITDA to manage our business, including the preparation of our annual operating budget and financial projections, we believe that non-GAAP financial measures have limitations and do not reflect all of the amounts associated with our results of operations as determined in accordance with GAAP and that these measures should only be used to evaluate our results of operations in conjunction with the corresponding GAAP financial measures. A reconciliation of Adjusted Net Income (Loss) and Adjusted EBITDA to Net Income, GAAP, are included below:
| 8 |
Reconciliation of Net Income (Loss) to Adjusted Net Income (Loss)
| Three Months Ended December 31, | Years Ended December 31, | |||||||||||||||
| 2014 | 2013 | 2014 | 2013 | |||||||||||||
| Net income (loss) | $ | 4,086,084 | $ | (195,508 | ) | $ | 4,351,880 | $ | (402,659 | ) | ||||||
| Subtract: | ||||||||||||||||
| Loss (gain) on mark-to-market of derivatives, net of tax (a) | (4,245,782 | ) | 105,451 | (4,909,421 | ) | 134,676 | ||||||||||
| Settlement income, net of tax (b) | – | (227,505 | ) | – | (227,505 | ) | ||||||||||
| Adjusted net income (loss) | $ | (159,698 | ) | $ | (317,562 | ) | $ | (557,541 | ) | $ | (495,488 | ) | ||||
| Weighted average common shares outstanding - basic | 47,979,990 | 47,979,990 | 47,979,990 | 47,979,990 | ||||||||||||
| Weighted average common shares outstanding - fully diluted | 48,815,177 | 47,979,990 | 49,179,725 | 47,979,990 | ||||||||||||
| Net income (loss) per common share - basic | $ | 0.09 | $ | 0.00 | $ | 0.09 | $ | (0.01 | ) | |||||||
| Subtract: | ||||||||||||||||
| Loss (gain) on mark-to-market of derivatives, net of tax | (0.09 | ) | 0.00 | (0.10 | ) | 0.00 | ||||||||||
| Settlement income per common share, net of tax | – | (0.00 | ) | – | (0.00 | ) | ||||||||||
| Adjusted net income (loss) per common share - basic | $ | 0.00 | $ | (0.00 | ) | $ | (0.01 | ) | $ | (0.01 | ) | |||||
| Net income (loss) per common share - fully diluted | $ | 0.08 | $ | 0.00 | $ | 0.09 | $ | (0.01 | ) | |||||||
| Subtract: | ||||||||||||||||
| Loss (gain) on mark-to-market of derivatives, net of tax | (0.09 | ) | 0.00 | (0.10 | ) | 0.00 | ||||||||||
| Settlement income per common share, net of tax | – | (0.00 | ) | – | 0.00 | |||||||||||
| Adjusted net income (loss) per common share - fully diluted | $ | (0.01 | ) | $ | (0.00 | ) | $ | (0.01 | ) | $ | (0.01 | ) | ||||
(a) Adjusted to reflect tax (expense) benefit, computed based on our effective tax rates of approximately 37% in 2014 and 2013, of ($2,494,000) and $62,000, respectively, for the three months ended December 31, 2014 and 2013 and ($2,884,000) and $79,000, respectively, for the years ended December 31, 2014 and 2013.
(b) Adjusted to reflect tax expense, computed based on our effective tax rate of approximately 37% in 2013, of $134,000, for the three months and year ended December 31, 2013.
| 9 |
Reconciliation of Net Income (Loss) to Adjusted EBITDA
| Three Months Ended December 31, | Years Ended December 31, | |||||||||||||||
| 2014 | 2013 | 2014 | 2013 | |||||||||||||
| Net income (loss) | $ | 4,086,084 | $ | (195,508 | ) | $ | 4,351,880 | $ | (402,659 | ) | ||||||
| Add back: | ||||||||||||||||
| Interest expense, net, excluding amortization of warrant based financing costs | 1,309,414 | 706,231 | 4,656,069 | 2,072,129 | ||||||||||||
| Income tax provision | 2,448,346 | (83,442 | ) | 2,559,195 | (698,851 | ) | ||||||||||
| Depreciation, depletion, and amortization | 3,370,583 | 1,078,394 | 9,389,090 | 3,729,157 | ||||||||||||
| Accretion of abandonment liability | 6,875 | 4,245 | 22,361 | 9,019 | ||||||||||||
| Share-based compensation | 305,150 | 292,662 | 1,207,114 | 951,639 | ||||||||||||
| Losses (gains) on the mark-to-market of derivatives | (6,740,782 | ) | 167,451 | (7,793,421 | ) | 213,676 | ||||||||||
| Adjusted EBITDA | $ | 4,785,670 | $ | 1,970,033 | $ | 14,392,288 | $ | 5,874,110 | ||||||||
Our adjusted EBITDA includes settlement income, net of settlement expenses, of $361,505 for the three months and year ended December 31, 2013.
| 10 |
BLACK RIDGE OIL & GAS, INC.
BALANCE SHEETS
| December 31, | December 31, | |||||||
| 2014 | 2013 | |||||||
| ASSETS | ||||||||
| Current assets: | ||||||||
| Cash and cash equivalents | $ | 94,682 | $ | 1,150,347 | ||||
| Derivative instruments | 3,571,803 | – | ||||||
| Accounts receivable | 5,740,171 | 1,905,467 | ||||||
| Advances to operators | – | 1,214,662 | ||||||
| Prepaid expenses | 41,387 | 26,142 | ||||||
| Total current assets | 9,448,043 | 4,296,618 | ||||||
| Property and equipment: | ||||||||
| Oil and natural gas properties, full cost method of accounting | ||||||||
| Proved properties | 112,418,105 | 79,361,432 | ||||||
| Unproved properties | 591,121 | 2,798,795 | ||||||
| Other property and equipment | 139,004 | 115,482 | ||||||
| Total property and equipment | 113,148,230 | 82,275,709 | ||||||
| Less, accumulated depreciation, amortization, depletion and allowance for impairment | (18,902,524 | ) | (9,513,434 | ) | ||||
| Total property and equipment, net | 94,245,706 | 72,762,275 | ||||||
| Derivative instruments | 4,007,942 | – | ||||||
| Debt issuance costs, net | 701,019 | 772,883 | ||||||
| Total assets | $ | 108,402,710 | $ | 77,831,776 | ||||
| LIABILITIES AND STOCKHOLDERS' EQUITY | ||||||||
| Current liabilities: | ||||||||
| Accounts payable | $ | 10,291,262 | $ | 8,453,709 | ||||
| Accrued expenses | 57,435 | 4,813 | ||||||
| Derivative instruments | – | 139,065 | ||||||
| Total current liabilities | 10,348,697 | 8,597,587 | ||||||
| Derivative instruments | – | 74,611 | ||||||
| Asset retirement obligations | 286,804 | 160,665 | ||||||
| Revolving credit facility and long term debt, net of discounts of $2,072,483 and $2,645,582, respectively | 51,834,603 | 30,556,301 | ||||||
| Deferred tax liability | 6,593,040 | 4,033,845 | ||||||
| Total liabilities | 69,063,144 | 43,423,009 | ||||||
| Commitments and contingencies (See note 14) | – | – | ||||||
| Stockholders' equity: | ||||||||
| Preferred stock, $0.001 par value, 20,000,000 shares authorized, no shares issued and outstanding | – | – | ||||||
| Common stock, $0.001 par value, 500,000,000 shares authorized, 47,979,990 shares issued and outstanding | 47,980 | 47,980 | ||||||
| Additional paid-in capital | 33,651,714 | 33,072,795 | ||||||
| Retained earnings | 5,639,872 | 1,287,992 | ||||||
| Total stockholders' equity | 39,339,566 | 34,408,767 | ||||||
| Total liabilities and stockholders' equity | $ | 108,402,710 | $ | 77,831,776 | ||||
| 11 |
BLACK RIDGE OIL & GAS, INC.
STATEMENTS OF OPERATIONS
| For the Three Months | For the Years | |||||||||||||||
| Ended December 31, | Ended December 31, | |||||||||||||||
| 2014 | 2013 | 2014 | 2013 | |||||||||||||
| Oil and gas sales | $ | 6,026,080 | $ | 2,601,716 | $ | 21,102,823 | $ | 9,276,656 | ||||||||
| Gain on settled derivatives | 960,586 | 74,666 | 511,451 | 53,482 | ||||||||||||
| Gain (loss) on the mark-to-market of derivatives | 6,740,782 | (167,451 | ) | 7,793,421 | (213,676 | ) | ||||||||||
| Total revenues | $ | 13,727,448 | $ | 2,508,931 | $ | 29,407,695 | $ | 9,116,462 | ||||||||
| Operating expenses: | ||||||||||||||||
| Production expenses | 932,305 | 332,663 | 2,705,763 | 1,145,686 | ||||||||||||
| Production taxes | 617,746 | 292,921 | 2,203,501 | 1,015,907 | ||||||||||||
| General and administrative | 796,570 | 584,470 | 2,891,641 | 2,299,757 | ||||||||||||
| Depletion of oil and gas properties | 3,365,772 | 1,071,847 | 9,359,952 | 3,705,156 | ||||||||||||
| Accretion of discount on asset retirement obligations | 6,875 | 4,245 | 22,361 | 9,019 | ||||||||||||
| Depreciation and amortization | 4,811 | 6,547 | 29,138 | 24,001 | ||||||||||||
| Total operating expenses | 5,724,079 | 2,292,693 | 17,212,356 | 8,199,526 | ||||||||||||
| Net operating income | 8,003,369 | 216,238 | 12,195,339 | 916,936 | ||||||||||||
| Other income (expense): | ||||||||||||||||
| Interest income | – | 67 | 972 | 408 | ||||||||||||
| Interest (expense) | (1,468,939 | ) | (856,760 | ) | (5,285,236 | ) | (2,380,359 | ) | ||||||||
| Settlement income | – | 380,982 | – | 380,982 | ||||||||||||
| Settlement expense | – | (19,477 | ) | – | (19,477 | ) | ||||||||||
| Total other income (expense) | (1,468,939 | ) | (495,188 | ) | (5,284,264 | ) | (2,018,446 | ) | ||||||||
| Income (loss) before provision for income taxes | 6,534,430 | (278,950 | ) | 6,911,075 | (1,101,510 | ) | ||||||||||
| Provision for income taxes | (2,448,346 | ) | 83,442 | (2,559,195 | ) | 698,851 | ||||||||||
| Net income (loss) | $ | 4,086,084 | $ | (195,508 | ) | $ | 4,351,880 | $ | (402,659 | ) | ||||||
| Weighted average common shares outstanding - basic | 47,979,990 | 47,979,990 | 47,979,990 | 47,979,990 | ||||||||||||
| Weighted average common shares outstanding - fully diluted | 48,815,177 | 47,979,990 | 49,179,725 | 47,979,990 | ||||||||||||
| Net income (loss) per common share - basic | $ | 0.09 | $ | (0.00 | ) | $ | 0.09 | $ | (0.01 | ) | ||||||
| Net income (loss) per common share - fully diluted | $ | 0.08 | $ | (0.00 | ) | $ | 0.09 | $ | (0.01 | ) | ||||||
| 12 |
BLACK RIDGE OIL & GAS, INC.
STATEMENTS OF CASH FLOWS
| For the Years | ||||||||
| Ended December 31, | ||||||||
| 2014 | 2013 | |||||||
| CASH FLOWS FROM OPERATING ACTIVITIES | ||||||||
| Net income (loss) | $ | 4,351,880 | $ | (402,659 | ) | |||
| Adjustments to reconcile net income (loss) to net cash provided by operating activities: | ||||||||
| Depletion of oil and gas properties | 9,359,952 | 3,705,156 | ||||||
| Depreciation and amortization | 29,138 | 24,001 | ||||||
| Amortization of debt issuance costs | 326,258 | 749,920 | ||||||
| Accretion of discount on asset retirement obligations | 22,361 | 9,019 | ||||||
| Loss (gain) on the mark-to-market of derivatives | (7,793,421 | ) | 213,676 | |||||
| Accrued payment in kind interest applied to long term debt | 1,105,203 | 201,883 | ||||||
| Amortization of original issue discount on debt | 144,904 | 28,362 | ||||||
| Amortization of debt discounts, warrants | 628,195 | 199,632 | ||||||
| Common stock warrants granted as financing costs | – | 108,190 | ||||||
| Common stock options issued to employees and directors | 578,919 | 643,817 | ||||||
| Deferred income taxes | 2,559,195 | (698,851 | ) | |||||
| Decrease (increase) in current assets: | ||||||||
| Accounts receivable | (2,834,704 | ) | (1,049,234 | ) | ||||
| Settlement receivable | – | 2,500,000 | ||||||
| Prepaid expenses | (15,245 | ) | 21,013 | |||||
| Increase (decrease) in current liabilities: | ||||||||
| Accounts payable | 426,558 | 164,527 | ||||||
| Settlement payable | – | (160,000 | ) | |||||
| Settlement payable, related parties | – | (116,234 | ) | |||||
| Accrued expenses | 52,622 | (56,853 | ) | |||||
| Net cash provided by operating activities | 8,941,815 | 6,085,365 | ||||||
| CASH FLOWS FROM INVESTING ACTIVITIES | ||||||||
| Proceeds from sale or swap of oil and gas properties | 1,441,929 | 608,387 | ||||||
| Purchases of oil and gas properties and development capital expenditures | (24,739,407 | ) | (32,025,724 | ) | ||||
| Advances to operators | (5,822,086 | ) | (882,604 | ) | ||||
| Purchases of other property and equipment | (23,522 | ) | (38,472 | ) | ||||
| Net cash used in investing activities | (29,143,086 | ) | (32,338,413 | ) | ||||
| CASH FLOWS FROM FINANCING ACTIVITIES | ||||||||
| Advances from revolving credit facilities and long term debt | 29,800,000 | 41,150,000 | ||||||
| Repayments on revolving credit facilities | (10,400,000 | ) | (14,298,844 | ) | ||||
| Debt issuance costs | (254,394 | ) | (865,101 | ) | ||||
| Net cash provided by financing activities | 19,145,606 | 25,986,055 | ||||||
| NET CHANGE IN CASH | (1,055,665 | ) | (266,993 | ) | ||||
| CASH AT BEGINNING OF PERIOD | 1,150,347 | 1,417,340 | ||||||
| CASH AT END OF PERIOD | $ | 94,682 | $ | 1,150,347 | ||||
| SUPPLEMENTAL INFORMATION: | ||||||||
| Interest paid | $ | 3,401,028 | $ | 1,104,688 | ||||
| Income taxes paid | $ | – | $ | – | ||||
| NON-CASH INVESTING AND FINANCING ACTIVITIES: | ||||||||
| Net change in accounts payable for purchase of oil and gas properties | $ | 1,410,995 | $ | 5,335,656 | ||||
| Advances to operators received in swap for oil and gas properties | $ | – | $ | (1,200,000 | ) | |||
| Advances to operators applied to purchase of oil and gas properties | $ | 6,036,748 | $ | 2,218,237 | ||||
| Advances to operators reclassified to accounts receivable | $ | 1,000,000 | $ | – | ||||
| Capitalized asset retirement costs, net of revision in estimate | $ | 103,778 | $ | 84,501 | ||||
| Fair value of detachable warrants granted in consideration of debt financing | $ | – | $ | 2,473,576 | ||||
| 13 |
Cautionary Statement as to Forward-Looking Statements
Certain statements contained herein, which are not historical, are forward-looking statements that are subject to risks and uncertainties not known or disclosed herein that could cause actual results to differ materially from those expressed herein. These statements may include projections and other "forward-looking statements" within the meaning of the federal securities laws. Any such projections or statements reflect management’s current views about future events and financial performance. No assurances can be given that such events or performance will occur as projected and actual results may differ materially from those projected. Important factors that could cause the actual results to differ materially from those projected include, without limitation, general economic or industry conditions nationally and/or in the communities in which our Company conducts business, volatility in commodity prices for crude oil and natural gas, environmental risks, legislation or regulatory requirements, conditions of the securities markets, our ability to raise capital or have access to debt financing, changes in accounting principles, policies or guidelines, financial or political instability, acts of war or terrorism, increases in operator costs, other economic, competitive, governmental, regulatory and technical factors affecting our Company's operations, products, services and prices and other risks inherent in the Company's businesses that are detailed in the Company's Securities and Exchange Commission ("SEC") filings. Readers are encouraged to review these risks in the Company's SEC filings.
About the Company
Black Ridge Oil & Gas is an oil and gas exploration and production company based in Minnetonka, Minnesota. Black Ridge's focus is exclusive to the Williston Basin Bakken and Three Forks trend in North Dakota and Montana. For additional information, visit the Company's website at www.blackridgeoil.com.
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Contact
Black Ridge Oil & Gas, Inc.
Ken DeCubellis, Chief Executive
Officer
952-426-1241
www.blackridgeoil.com
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