Attached files
| file | filename |
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| 8-K - FORM 8-K - Sow Good Inc. | brog_8k-032714.htm |
Exhibit 99.1
Black Ridge Oil & Gas Announces 2013 Fourth Quarter and Full Year Results
Pro Forma Q4 2013 Production of 482 Boe/d
PV10% of Proved Reserves of $74.4 million, Up 166% over $27.9 million in 2012
Annual Adjusted EBITDA from Oil and Gas Operations Up 126% to $5.5 Million
Annual Revenue up 51% to $9.1 Million
MINNETONKA, Minn., March 27, 2014 - 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, 2013.
Full Year 2013 Company Highlights
| · | Increased annual production 47% from 2012 to 108.8 thousand barrels of oil equivalent (“MBoe”), an average of approximately 298 barrels of oil equivalent per day (“Boe/d”) |
| · | Increased annual revenue 51% to $9.1 million from $6.0 million in 2012 |
| · | Increased total proved reserves, as determined by Netherland, Sewell & Associates, Inc., to 4.5 million Boe, an increase of 90% from 2012 |
| · | Increased pre-tax PV10% of the total proved reserves as of December 31, 2013 to $74.4 million, an increase of 166% from 2012 |
| · | Exited 2013 with production from 153 gross (4.87 net) wells, up from 66 gross (2.30 net) at the end of 2012, an increase of 112% on a net well basis |
| · | Recorded $5.5 million of adjusted EBITDA from oil and gas operations (excluding net settlement income), an increase of 126% from $2.4 million in 2012 |
Fourth Quarter 2013 Company Highlights
| · | Increased quarterly production to 32.9 MBoe, an average of 358 MBoe/d, representing a 61% increase over the fourth quarter of 2012 and a 16% increase over the third quarter of 2013 |
| · | Pro forma fourth quarter production including the Corral Creek acquisition, which closed on December 13, 2013, averaged 482 Boe/d |
| · | Increased revenue to $2.5 million, a 48% increase from the fourth quarter of 2012 |
| · | Completed or acquired 61 gross (1.65 net) wells during the quarter |
Corral Creek Acquisition
As previously disclosed, the Company closed on the Corral Creek acquisition on December 13, 2013. The year-end financial information provided herein by the Company reflects the impact of the acquired assets from the closing date to December 31, 2013 (19 days).
Management Comment
Ken DeCubellis, Black Ridge’s CEO, commented, “The Company had an outstanding year in 2013. We successfully executed on our key initiatives of acquiring high quality, core Bakken acreage with near-term development and securing financing to execute our aggressive growth plan. Looking ahead to 2014, we are encouraged by early results from both our Stockyard Creek and Corral Creek prospects and expect these assets to drive robust production growth in 2014 and beyond.”
| 1 |
Year-End 2013 Results
For the full year 2013, Company production increased to 108.8 Mboe, an average of 298 Boe/d, representing a 47% increase over 2012 production of 73.9 MBoe. Revenues were $9.1 million, compared to $6.0 million in 2012, an increase of 51%. The increase in production and revenues was due to the completion or purchase of an additional 87 gross (2.57 net) wells in 2013.
During 2013, the Company realized an average price of $89.58 per Bbl of oil compared to an average price of $83.27 per Bbl of oil in 2012. The Company’s production was comprised of 92% oil and 8% natural gas and natural gas liquids in 2013 on a Boe basis.
Lease operating expenses for 2013 were $1.1 million, or $10.53 per Boe, compared to $650 thousand, or $8.79 per Boe, for 2012.
General and administrative expenses (“G&A”) for 2013 were $2.3 million, or $21.14 per Boe, compared to $3.5 million, or $47.75 per Boe for 2012. Cash G&A (non-GAAP, excludes stock-based compensation expense) was $1.7 million, or $15.22 per Boe for 2013 compared to $2.2 million, or $30.33 per Boe for 2012. Included in the 2012 G&A expenses were one-time legal costs of $371 thousand associated with litigation settlement activity.
The Company recorded $5.5 million of adjusted EBITDA from oil and gas operations (excluding net settlement income) in 2013, representing an increase of 126% from $2.4 million in 2012. Adjusted EBITDA is a non-GAAP financial measure. Please refer to the reconciliation in this release for additional information about this measure.
Fourth Quarter 2013 Results
During the fourth quarter of 2013, Company production totaled 32.9 Mboe, an average of 358 Boe/d, representing a sequential increase of 16% over third quarter 2013 production of 28.4 Mboe and a year-over-year increase of 61% over 20.4 Mboe in the fourth quarter of 2012. Pro forma for the Corral Creek acquisition that closed December 13, 2013, fourth quarter production averaged 482 Boe/d.
Revenues for the fourth quarter of 2013 were $2.5 million, compared to $1.7 million in the fourth quarter of 2012, an increase of 48%.
Average realized prices for the fourth quarter of 2013, before the effect of commodity derivatives, were $84.24 per Bbl of oil and $5.94 per Mcf of natural gas, compared to $85.15 per Bbl of oil and $5.90 per Mcf of natural gas in the fourth quarter of 2012.
Lease operating expenses for the fourth quarter of 2013 were $333 thousand, or $10.11 per Boe, compared to $222 thousand, or $10.85 per Boe, for the fourth quarter of 2012.
General and administrative expenses (“G&A”) for the fourth quarter of 2013 were $584 thousand, or $17.76 per Boe, compared to $575 thousand, or $28.13 per Boe for the fourth quarter of 2012. Cash G&A (non-GAAP, excludes stock-based compensation expense) was $442 thousand, or $13.44 per Boe for the fourth quarter of 2013 compared to $424 thousand, or $20.75 per Boe for the fourth quarter of 2012.
The Company recorded $1.6 million of adjusted EBITDA from oil and gas operations (excluding net settlement income) in the fourth quarter of 2013, representing an 83% increase over $878 thousand in the fourth quarter of 2012. Adjusted EBITDA is a non-GAAP financial measure. Please refer to the reconciliation in this release for additional information about this measure.
2013 Proved Reserves
As of December 31, 2013, Black Ridge had estimated proved reserves of 4.5 MMBoe, of which 23% were classified as proved developed, and 90% was crude oil. These estimated proved reserves had a pre-tax PV10% value of $74.4 million, a 166% increase over 2012 proved reserves pre-tax PV10% value of $27.9 million. Reserve replacement for the Company in 2013 was 1,980%. The Company's estimated reserves were prepared by its independent reservoir engineering firm, Netherland, Sewell & Associates, Inc.
| 2 |
| Reserve Category | % of Reserves | Oil (MBbls) | Gas (MMcf) | 2013 Mboe | 2012 Mboe | % Change | 2013 PV-10 ($000's) | |||||||||||||||||||||
| Proved Developed Producing | 22% | 895 | 615 | 998 | 509 | 96% | $ | 32,379 | ||||||||||||||||||||
| Proved Developed Non-Producing | 1% | 32 | 38 | 38 | – | n/a | 1,609 | |||||||||||||||||||||
| Proved Undeveloped | 77% | 3,147 | 2,126 | 3,502 | 1,875 | 87% | 40,389 | |||||||||||||||||||||
| Total Proved | 100% | 4,074 | 2,779 | 4,538 | 2,384 | 90% | $ | 74,377 | ||||||||||||||||||||
____________
| (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, 2013 assuming a constant realized price of $88.93 per barrel of crude oil and a constant realized price of $8.25 per Mcf of natural gas. The values presented in both tables above were calculated by Netherland, Sewell & Associates, Inc. | |
| (2) |
BOE are computed based on a conversion ratio of one BOE for each barrel of crude oil and one BOE for every 6,000 cubic feet (i.e., 6 Mcf) of natural gas. | |
| (3) |
Pre-tax PV10% may be considered a non-GAAP financial measure as defined by the SEC and is derived from the standardized measure of discounted future net cash flows, which is the most directly comparable standardized financial measure. Pre-tax PV10% is computed on the same basis as the standardized measure of discounted future net cash flows but without deducting future income taxes. We believe Pre-tax PV10% is a useful measure for investors for evaluating the relative monetary significance of our crude oil and natural gas properties. We further believe investors may utilize our Pre-tax PV10% as a basis for comparison of the relative size and value of our reserves to other companies because many factors that are unique to each individual company impact the amount of future income taxes to be paid. Our management uses this measure when assessing the potential return on investment related to our crude oil and natural gas properties and acquisitions. However, Pre-tax PV10% is not a substitute for the standardized measure of discounted future net cash flows. Our Pre-tax PV10% and the standardized measure of discounted future net cash flows do not purport to present the fair value of our crude oil and natural gas reserves. |
Liquidity Position
In August 2013, Black Ridge closed on a $50 million senior secured revolving credit facility and a $75 million second lien term loan facility. The initial capital available to the Company was $32 million, nearly double the availability from the Company’s previous financing. In connection with the December closing of the Corral Creek acquisition, the capital available to the Company was increased to $43 million. As of December 31, 2013, the Company had drawn $33 million from these facilities.
Black Ridge expects to continue to use these two new facilities as well as cash flow from operations to accelerate the growth of the Company’s footprint in the Bakken and Three Forks trends through potential working interest and/or leasehold purchases and development of wells on the Company’s existing leases.
Operational Update
As of December 31, 2013, the Company owned interests in 153 gross (4.87 net) producing wells. Additionally, the Company owned interest in 55 gross (1.40 net) wells that were preparing to drill, drilling, awaiting completion, or completing (“drilling”) as of December 31, 2013. A full list of producing and “drilling” wells is available at www.blackridgeoil.com.
As of December 31, 2013, the Company controlled approximately 10,000 net acres prospective for the Bakken and Three Forks formations. Additionally, the Company controlled approximately 4,200 net acres in southeastern Dunn County that do not appear to hold commercially economic reserve quantities and their respective leases will not be renewed or extended upon expiration in the first half of 2014.
| 3 |
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, 2013.
| Well | Operator | Location | WI(1) | |
| Gorhman 14-31TFH | Burlington Resources | Dunn, ND | 0.193 | |
| Gorhman 24-31MBH | Burlington Resources | Dunn, ND | 0.193 | |
| Rogers-Federal #1-15 | XTO Energy | Williams, ND | 0.183 | |
| Peter 4-2H | SM Energy | Divide, ND | 0.125 | |
| Teton 21-3H | Burlington Resources | McKenzie, ND | 0.125 | |
| Charlotte #1-12-1H | Mountain Divide | Divide, ND | 0.083 | |
| Lincoln USA 16-1H | Marathon | Dunn, ND | 0.064 | |
| Raymond 1-21AH | Continental | Williams, ND | 0.043 | |
| Metz 6094 13-1H | Oasis | Burke, ND | 0.040 | |
| Halliday 1-11-2H 1 | Hunt | Dunn, ND | 0.031 | |
| Halliday 2-11-2H | Hunt | Dunn, ND | 0.031 | |
| Halliday 3-11-2H | Hunt | Dunn, ND | 0.031 | |
| Hansen Ranch 14-10H | Marathon | Dunn, ND | 0.031 | |
| Hansen Ranch 34-10TFH | Marathon | Dunn, ND | 0.031 | |
| Hansen Ranch USA 44-10H | Marathon | Dunn, ND | 0.031 | |
| Hansen Ranch USA 44-10TFH | Marathon | Dunn, ND | 0.031 | |
| Margaret 5-8 #4H | Statoil | McKenzie, ND | 0.020 | |
| Margaret 5-8 #6H | Statoil | McKenzie, ND | 0.020 | |
| Little Muddy 11H | Triangle | Williams, ND | 0.009 | |
| Little Muddy 13H | Triangle | Williams, ND | 0.009 | |
| CCU Audubon 41-27H | Burlington Resources | Dunn, ND | 0.008 | |
| CCU Bison Point 14-34H | Burlington Resources | Dunn, ND | 0.008 | |
| CCU Bison Point 44-34MBH | Burlington Resources | Dunn, ND | 0.008 | |
| CCU Bison Point 44-34TFH | Burlington Resources | Dunn, ND | 0.008 | |
| CCU Boxcar 21-15H | Burlington Resources | Dunn, ND | 0.008 | |
| CCU Burner 21-26MBH | Burlington Resources | Dunn, ND | 0.008 | |
| CCU Burner 21-26TFH | Burlington Resources | Dunn, ND | 0.008 | |
| CCU Burner 41-26H | Burlington Resources | Dunn, ND | 0.008 | |
| CCU Carol 44-31H | Burlington Resources | Dunn, ND | 0.008 | |
| CCU Columbian 24-36H | Burlington Resources | Dunn, ND | 0.008 | |
| CCU Corral Creek 41-28TFH | Burlington Resources | Dunn, ND | 0.008 | |
| CCU Corral Creek 41-28MBH | Burlington Resources | Dunn, ND | 0.008 | |
| CCU Corral Creel 34-33H | Burlington Resources | Dunn, ND | 0.008 | |
| CCU Four Aces 11-16H | Burlington Resources | Dunn, ND | 0.008 | |
| CCU Four Aces 44-21MBH | Burlington Resources | Dunn, ND | 0.008 | |
| CCU Four Aces 44-21TFH | Burlington Resources | Dunn, ND | 0.008 | |
| CCU Golden Creek 24-23MBH | Burlington Resources | Dunn, ND | 0.008 | |
| CCU Golden Creek 34-23MBH | Burlington Resources | Dunn, ND | 0.008 | |
| CCU Meriwether 14-19MBH | Burlington Resources | Dunn, ND | 0.008 | |
| CCU Meriwether 14-19TFH | Burlington Resources | Dunn, ND | 0.008 | |
| CCU Meriwether 24-19MBH | Burlington Resources | Dunn, ND | 0.008 | |
| CCU Meriwether 24-19TFH | Burlington Resources | Dunn, ND | 0.008 | |
| CCU Meriwether 34-19TFH | Burlington Resources | Dunn, ND | 0.008 | |
| CCU Meriwether 44-19MBH | Burlington Resources | Dunn, ND | 0.008 | |
| CCU Meriwether 44-19TFH | Burlington Resources | Dunn, ND | 0.008 | |
| CCU North Coast 11-25H | Burlington Resources | Dunn, ND | 0.008 | |
| CCU Powell 11-29MBH | Burlington Resources | Dunn, ND | 0.008 | |
| CCU Powell 11-29TFH | Burlington Resources | Dunn, ND | 0.008 | |
| CCU Powell 14-32H | Burlington Resources | Dunn, ND | 0.008 | |
| CCU Powell 21-29MBH | Burlington Resources | Dunn, ND | 0.008 | |
| CCU Powell 21-29TFH | Burlington Resources | Dunn, ND | 0.008 | |
| CCU Prairie Rose 11-30TFH | Burlington Resources | Dunn, ND | 0.008 | |
| CCU Prairie Rose 21-30MBH | Burlington Resources | Dunn, ND | 0.008 | |
| CCU Prairie Rose 24-31H | Burlington Resources | Dunn, ND | 0.008 | |
| CCU Prairie Rose 31-30MBH | Burlington Resources | Dunn, ND | 0.008 | |
| CCU Prairie Rose 31-30TFH | Burlington Resources | Dunn, ND | 0.008 | |
| CCU Prairie Rose 41-30MBH | Burlington Resources | Dunn, ND | 0.008 | |
| CCU William 14-20H | Burlington Resources | Dunn, ND | 0.008 | |
| CCU William 24-20MBH | Burlington Resources | Dunn, ND | 0.008 | |
| CCU William 24-20TFH | Burlington Resources | Dunn, ND | 0.008 | |
| CCU William 34-20TFH | Burlington Resources | Dunn, 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.
| 4 |
"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, 2013.
| Well | Operator | Location | WI(1) |
| Coopers 2-15-14HBK | Slawson Exploration | Williams, ND | 0.084 |
| Little Creature 1-15-14H | Slawson Exploration | Williams, ND | 0.084 |
| Tooheys 4-15-14HBK | Slawson Exploration | Williams, ND | 0.084 |
| E Rennerfeldt 1-13H | Slawson Exploration | Williams, ND | 0.081 |
| E Rennerfeldt 2-13H | Slawson Exploration | Williams, ND | 0.081 |
| Inga Federal 41X-29C | XTO Energy | Dunn, ND | 0.079 |
| Inga Federal 41X-29D | XTO Energy | Dunn, ND | 0.079 |
| Inga Federal 41X-29H | XTO Energy | Dunn, ND | 0.079 |
| Pasternak Trust 157-100-19C-18-2H | Halcon Resources | Williams, ND | 0.078 |
| Pasternak Trust 157-100-19C-18-3H | Halcon Resources | Williams, ND | 0.078 |
| Billabong 2-13-14HBK | Samson Oil and Gas | Williams, ND | 0.075 |
| Blackdog 3-13-14H | Slawson Exploration | Williams, ND | 0.075 |
| Duckstein 1-13-14HTF | Slawson Exploration | Williams, ND | 0.075 |
| Orlynne 2-3H | SM Energy | Divide, ND | 0.055 |
| Margaret 5-8 #3TFH-R | Statoil | McKenzie, ND | 0.020 |
| Margaret 5-8 #5TFH | Statoil | McKenzie, ND | 0.020 |
| Moline 157-100-20D-17-2H | Halcon Resources | Williams, ND | 0.016 |
| Moline 157-100-20D-17-3H | Halcon Resources | Williams, ND | 0.016 |
| Amy 2-5H1 | Continental | Stark, ND | 0.015 |
| Miller 157-101-12D-1-2H | Halcon Resources | Williams, ND | 0.011 |
| Miller 157-101-12D-1-3H | Halcon Resources | Williams, ND | 0.011 |
| Miller 157-101-12D-1-4H | Halcon Resources | Williams, ND | 0.011 |
| CCU Burner 41-26MBH | Burlington Resources | Dunn, ND | 0.008 |
| CCU Burner 41-26TFH | Burlington Resources | Dunn, ND | 0.008 |
| CCU Columbian 14-36TFH | Burlington Resources | Dunn, ND | 0.008 |
| CCU Columbian 24-36TFH | Burlington Resources | Dunn, ND | 0.008 |
| CCU Columbian 33-1MBH | Burlington Resources | Dunn, ND | 0.008 |
| CCU Columbian 33-1TFH | Burlington Resources | Dunn, ND | 0.008 |
| CCU Columbian 43-1MBH | Burlington Resources | Dunn, ND | 0.008 |
| CCU Columbian 43-1TFH | Burlington Resources | Dunn, ND | 0.008 |
| CCU Corral Creek 11-28TFH | Burlington Resources | Dunn, ND | 0.008 |
| CCU Four Aces 14-21TFH | Burlington Resources | Dunn, ND | 0.008 |
| CCU Mainstreeter 14-24TFH | Burlington Resources | Dunn, ND | 0.008 |
| CCU North Coast 11-25TFH | Burlington Resources | Dunn, ND | 0.008 |
| CCU Powell 31-29MBH | Burlington Resources | Dunn, ND | 0.008 |
| CCU Powell 41-29MBH | Burlington Resources | Dunn, ND | 0.008 |
| CCU Powell 41-29TFH | Burlington Resources | Dunn, ND | 0.008 |
| CCU William 14-20MBH | Burlington Resources | Dunn, ND | 0.008 |
| CCU William 14-20TFH | Burlington Resources | Dunn, ND | 0.008 |
| CCU William 34-20MBH | Burlington Resources | Dunn, ND | 0.008 |
| CCU William 44-20MBH | Burlington Resources | Dunn, ND | 0.008 |
| CCU William 44-20TFH | Burlington Resources | Dunn, ND | 0.008 |
| Kelter 7-12H3 | Oasis | Williams, ND | 0.004 |
| Kelter 7-1H2 | Oasis | Williams, ND | 0.004 |
| Kelter 7-1HTF3 | Oasis | Williams, ND | 0.004 |
| Kelter 7-6HTF | Oasis | Williams, ND | 0.004 |
| Kelter 7-6HTF2 | Oasis | Williams, ND | 0.004 |
| Archer 14-25TFH | Burlington Resources | McKenzie, ND | 0.002 |
| Archer 24-25MBH | Burlington Resources | McKenzie, ND | 0.002 |
| Archer 24-25TFH | Burlington Resources | McKenzie, ND | 0.002 |
| Archer 34-25TFH | Burlington Resources | McKenzie, ND | 0.002 |
| Archer 44-25MBH | Burlington Resources | McKenzie, ND | 0.002 |
| Archer 44-25TFH | Burlington Resources | McKenzie, ND | 0.002 |
| P Scanlan 153-98-16-9-5-12H | Kodiak | Williams, ND | 0.001 |
| P Scanlan 153-98-16-9-5-5H | Kodiak | Williams, ND | 0.001 |
(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.
| 5 |
Hedging Update
The following table reflects the weighted average price of open commodity swap derivative contracts as of December 31, 2013, by year with associated volumes.
Weighted Average Price of
Open Commodity Swap Contracts
| Weighted | ||||||||
| Volumes | Average | |||||||
| Year | (Bbl) | Price (WTI) | ||||||
| 2014 | 84,000 | $ | 93.95 | |||||
| 2015 | 24,000 | $ | 88.28 | |||||
In addition to the open commodity swap contracts, we have 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, 2013.
| 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 | |||||
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:
| 6 |
Reconciliation of Net Income (Loss) to Adjusted Net Income (Loss)
| Three Months Ended December 31, | Years Ended December 31, | |||||||||||||||
| 2013 | 2012 | 2013 | 2012 | |||||||||||||
| Net income (loss) | $ | (195,508 | ) | $ | 2,934,202 | $ | (402,659 | ) | $ | 4,911,410 | ||||||
| Subtract: | ||||||||||||||||
| Settlement income, net of tax (a) | (227,505 | ) | (3,078,252 | ) | (227,505 | ) | (6,355,895 | ) | ||||||||
| Adjusted net income (loss) | $ | (423,013 | ) | $ | (144,050 | ) | $ | (630,164 | ) | $ | (1,444,485 | ) | ||||
| Weighted average common shares outstanding - basic | 47,979,990 | 47,979,990 | 47,979,990 | 47,789,225 | ||||||||||||
| Weighted average common shares outstanding - fully diluted | 47,979,990 | 48,220,062 | 47,979,990 | 48,061,239 | ||||||||||||
| Net income (loss) per common share - basic | $ | (0.00 | ) | $ | 0.06 | $ | (0.01 | ) | $ | 0.10 | ||||||
| Subtract: | ||||||||||||||||
| Settlement income per common share, net of tax | (0.00 | ) | (0.06 | ) | (0.00 | ) | (0.13 | ) | ||||||||
| Adjusted net income (loss) per common share - basic | $ | (0.01 | ) | $ | (0.00 | ) | $ | (0.01 | ) | $ | (0.03 | ) | ||||
| Net income (loss) per common share - fully diluted | $ | (0.00 | ) | $ | 0.06 | $ | (0.01 | ) | $ | 0.10 | ||||||
| Subtract: | ||||||||||||||||
| Settlement income per common share, net of tax | (0.00 | ) | (0.06 | ) | (0.00 | ) | (0.13 | ) | ||||||||
| Adjusted net income (loss) per common share - fully diluted | $ | (0.01 | ) | $ | (0.00 | ) | $ | (0.01 | ) | $ | (0.03 | ) | ||||
(a) Adjusted to reflect tax expense, computed based on our effective tax rates of approximately 37% in 2013 and 43% in 2012, of $134,000 and $2,323,000, respectively, for the three months ended December 31, 2013 and 2012 and $134,000 and $4,790,000, respectively, for the years ended December 31, 2013 and 2012.
Reconciliation of Net Income (Loss) to Adjusted EBITDA
| Three Months Ended December 31, | Years Ended December 31, | |||||||||||||||
| 2013 | 2012 | 2013 | 2012 | |||||||||||||
| Net income (loss) | $ | (195,508 | ) | $ | 2,934,202 | $ | (402,659 | ) | $ | 4,911,410 | ||||||
| Add back: | ||||||||||||||||
| Interest expense, net, excluding amortization of warrant based financing costs |
|
|
706,231 |
|
|
|
377,472 |
|
|
|
2,072,129 |
|
|
|
873,754 |
|
| Income tax provision | (83,442 | ) | 2,089,971 | (698,851 | ) | 3,720,601 | ||||||||||
| Depreciation, depletion, and amortization | 1,078,394 | 715,540 | 3,729,157 | 2,467,688 | ||||||||||||
| Accretion of abandonment liability | 4,245 | 1,213 | 9,019 | 4,557 | ||||||||||||
| Common stock issued for terminated oil and gas acquisition |
|
|
– |
|
|
|
– |
|
|
|
– |
|
|
|
438,539 |
|
| Share-based compensation | 292,662 | 161,023 | 951,639 | 1,167,561 | ||||||||||||
| Unrealized loss on derivatives | 167,451 | – | 213,676 | – | ||||||||||||
| Adjusted EBITDA | $ | 1,970,033 | $ | 6,279,421 | $ | 5,874,110 | $ | 13,584,110 | ||||||||
Our adjusted EBITDA includes settlement income, net of settlement expenses, of $361,505 and $5,401,252 for the three months ended December 31, 2013 and 2012, respectively, and $361,505 and $11,145,895 for the years ended December 31, 2013 and 2012, respectively.
| 7 |
BLACK RIDGE OIL & GAS, INC.
BALANCE SHEETS
| December 31, | December 31, | |||||||
| 2013 | 2012 | |||||||
| ASSETS | ||||||||
| Current assets: | ||||||||
| Cash and cash equivalents | $ | 1,150,347 | $ | 1,417,340 | ||||
| Accounts receivable | 1,905,467 | 856,233 | ||||||
| Settlement receivable | – | 2,500,000 | ||||||
| Advances to operators | 1,214,662 | 1,350,295 | ||||||
| Prepaid expenses | 26,142 | 47,155 | ||||||
| Total current assets | 4,296,618 | 6,171,023 | ||||||
| Property and equipment: | ||||||||
| Oil and natural gas properties, full cost method of accounting | ||||||||
| Proved properties | 79,361,432 | 35,248,983 | ||||||
| Unproved properties | 2,798,795 | 9,055,513 | ||||||
| Other property and equipment | 115,482 | 85,917 | ||||||
| Total property and equipment | 82,275,709 | 44,390,413 | ||||||
| Less, accumulated depreciation, amortization, depletion and allowance for impairment | (9,513,434 | ) | (5,793,184 | ) | ||||
| Total property and equipment, net | 72,762,275 | 38,597,229 | ||||||
| Debt issuance costs, net | 772,883 | 657,702 | ||||||
| Total assets | $ | 77,831,776 | $ | 45,425,954 | ||||
| LIABILITIES AND STOCKHOLDERS' EQUITY | ||||||||
| Current liabilities: | ||||||||
| Accounts payable | $ | 8,453,709 | $ | 2,953,526 | ||||
| Settlement payable | – | 160,000 | ||||||
| Settlement accounts payable, related party | – | 116,234 | ||||||
| Accrued expenses | 4,813 | 61,666 | ||||||
| Current portion of derivative instruments | 139,065 | – | ||||||
| Total current liabilities | 8,597,587 | 3,291,426 | ||||||
| Derivative instruments | 74,611 | – | ||||||
| Asset retirement obligations | 160,665 | 67,145 | ||||||
| Revolving credit facilities and long term debt, net of discounts of $2,645,582 and $-0-, respectively | 30,556,301 | 5,748,844 | ||||||
| Deferred tax liability | 4,033,845 | 4,732,696 | ||||||
| Total liabilities | 43,423,009 | 13,840,111 | ||||||
| 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 | 33,072,795 | 29,847,212 | ||||||
| Retained earnings | 1,287,992 | 1,690,651 | ||||||
| Total stockholders' equity | 34,408,767 | 31,585,843 | ||||||
| Total liabilities and stockholders' equity | $ | 77,831,776 | $ | 45,425,954 | ||||
| 8 |
BLACK RIDGE OIL & GAS, INC.
STATEMENTS OF OPERATIONS
| For the Three Months | For the Years | |||||||||||||||
| Ended December 31, | Ended December 31, | |||||||||||||||
| 2013 | 2012 | 2013 | 2012 | |||||||||||||
| Oil and gas sales | $ | 2,601,716 | $ | 1,690,079 | $ | 9,276,656 | $ | 6,022,540 | ||||||||
| Gain on settled derivatives | 74,666 | – | 53,482 | – | ||||||||||||
| Losses on the mark-to-market of derivative instruments | (167,451 | ) | – | (213,676 | ) | – | ||||||||||
| Total revenues | $ | 2,508,931 | $ | 1,690,079 | $ | 9,116,462 | $ | 6,022,540 | ||||||||
| Operating expenses: | ||||||||||||||||
| Production expenses | 332,663 | 221,927 | 1,145,686 | 649,603 | ||||||||||||
| Production taxes | 292,921 | 165,792 | 1,015,907 | 692,527 | ||||||||||||
| General and administrative | 584,470 | 575,126 | 2,299,757 | 3,530,643 | ||||||||||||
| Depletion of oil and gas properties | 1,071,847 | 709,729 | 3,705,156 | 2,443,482 | ||||||||||||
| Accretion of discount on asset retirement obligations | 4,245 | 1,213 | 9,019 | 4,557 | ||||||||||||
| Depreciation and amortization | 6,547 | 5,811 | 24,001 | 24,206 | ||||||||||||
| Total operating expenses | 2,292,693 | 1,679,598 | 8,199,526 | 7,345,018 | ||||||||||||
| Net operating income (loss) | 216,238 | 10,481 | 916,936 | (1,322,478 | ) | |||||||||||
| Other income (expense): | ||||||||||||||||
| Interest income | 67 | 1,421 | 408 | 1,872 | ||||||||||||
| Interest (expense) | (856,760 | ) | (388,981 | ) | (2,380,359 | ) | (1,193,278 | ) | ||||||||
| Settlement income | 380,982 | 9,000,000 | 380,982 | 17,020,759 | ||||||||||||
| Settlement expense | (19,477 | ) | (3,598,748 | ) | (19,477 | ) | (5,874,864 | ) | ||||||||
| Total other income (expense) | (495,188 | ) | 5,013,692 | (2,018,446 | ) | 9,954,489 | ||||||||||
| Income (loss) before provision for income taxes | (278,950 | ) | 5,024,173 | (1,101,510 | ) | 8,632,011 | ||||||||||
| Provision for income taxes | 83,442 | (2,089,971 | ) | 698,851 | (3,720,601 | ) | ||||||||||
| Net income (loss) | $ | (195,508 | ) | $ | 2,934,202 | $ | (402,659 | ) | $ | 4,911,410 | ||||||
| Weighted average common shares outstanding - basic | 47,979,990 | 47,979,990 | 47,979,990 | 47,789,225 | ||||||||||||
| Weighted average common shares outstanding - fully diluted | 47,979,990 | 48,220,062 | 47,979,990 | 48,061,239 | ||||||||||||
| Net income (loss) per common share - basic | $ | (0.00 | ) | $ | 0.06 | $ | (0.01 | ) | $ | 0.10 | ||||||
| Net income (loss) per common share - fully diluted | $ | (0.00 | ) | $ | 0.06 | $ | (0.01 | ) | $ | 0.10 | ||||||
| 9 |
BLACK RIDGE OIL & GAS, INC.
STATEMENTS OF CASH FLOWS
| For the Years | ||||||||
| Ended December 31, | ||||||||
| 2013 | 2012 | |||||||
| CASH FLOWS FROM OPERATING ACTIVITIES | ||||||||
| Net income (loss) | $ | (402,659 | ) | $ | 4,911,410 | |||
| Adjustments to reconcile net income (loss) to net cash provided by operating activities: |
|
|
|
|
|
|
|
|
| Depletion of oil and gas properties | 3,705,156 | 2,443,482 | ||||||
| Depreciation and amortization | 24,001 | 24,206 | ||||||
| Amortization of debt issuance costs | 749,920 | 190,580 | ||||||
| Accretion of discount on asset retirement obligations | 9,019 | 4,557 | ||||||
| Losses on the mark-to-market of derivative instruments | 213,676 | – | ||||||
| Accrued payment in kind interest applied to long term debt | 201,883 | – | ||||||
| Amortization of original issue discount on debt | 28,362 | – | ||||||
| Amortization of debt discounts, warrants | 199,632 | – | ||||||
| Common stock issued for terminated oil and gas acquisition | – | 438,539 | ||||||
| Common stock warrants granted as financing costs | 108,190 | 271,933 | ||||||
| Common stock warrants granted as financing costs, related party | – | 45,719 | ||||||
| Common stock options issued to employees | 643,817 | 849,909 | ||||||
| Deferred income taxes | (698,851 | ) | 3,720,601 | |||||
| Decrease (increase) in current assets: | ||||||||
| Accounts receivable | (1,049,234 | ) | (183,230 | ) | ||||
| Settlement receivable | 2,500,000 | (2,500,000 | ) | |||||
| Prepaid expenses | 21,013 | (6,556 | ) | |||||
| Contingent consideration receivable | – | 6,008,602 | ||||||
| Increase (decrease) in current liabilities: | ||||||||
| Accounts payable | 164,527 | 119,610 | ||||||
| Accounts payable, related parties | – | (9,206 | ) | |||||
| Settlement payable | (160,000 | ) | 160,000 | |||||
| Settlement payable, related parties | (116,234 | ) | 116,234 | |||||
| Accrued expenses | (56,853 | ) | 61,666 | |||||
| Royalties payable, related party | – | (300,431 | ) | |||||
| Net cash provided by operating activities | 6,085,365 | 16,367,625 | ||||||
| CASH FLOWS FROM INVESTING ACTIVITIES | ||||||||
| Proceeds from sale of oil and gas properties | 608,387 | 1,893,649 | ||||||
| Purchases of oil and gas properties and development capital expenditures | (32,025,724 | ) | (21,213,070 | ) | ||||
| Advances to operators | (882,604 | ) | (1,977,188 | ) | ||||
| Purchases of other property and equipment | (38,472 | ) | (7,428 | ) | ||||
| Net cash used in investing activities | (32,338,413 | ) | (21,304,037 | ) | ||||
| CASH FLOWS FROM FINANCING ACTIVITIES | ||||||||
| Advances from revolving credit facilities and long term debt | 41,150,000 | 16,350,000 | ||||||
| Repayments on revolving credit facilities | (14,298,844 | ) | (10,601,156 | ) | ||||
| Debt issuance costs paid | (865,101 | ) | (796,233 | ) | ||||
| Net cash provided by financing activities | 25,986,055 | 4,952,611 | ||||||
| NET CHANGE IN CASH | (266,993 | ) | 16,199 | |||||
| CASH AT BEGINNING OF PERIOD | 1,417,340 | 1,401,141 | ||||||
| CASH AT END OF PERIOD | $ | 1,150,347 | $ | 1,417,340 | ||||
| SUPPLEMENTAL INFORMATION: | ||||||||
| Interest paid | $ | 1,104,688 | $ | 667,917 | ||||
| Income taxes paid | $ | – | $ | – | ||||
| NON-CASH INVESTING AND FINANCING ACTIVITIES: | ||||||||
| Net change in accounts payable for purchase of oil and gas properties | $ | 5,335,656 | $ | 195,995 | ||||
| Advances to operators received in swap for oil and gas properties | $ | (1,200,000 | ) | $ | – | |||
| Advances to operators applied to development of oil and gas properties | $ | 2,218,237 | $ | 626,893 | ||||
| Capitalized asset retirement costs, net of revision in estimate | $ | 84,501 | $ | 58,688 | ||||
| Liabilities relieved to additional paid-in capital | $ | – | $ | 183,015 | ||||
| Fair value of detachable warrants granted in consideration of debt financing | $ | 2,473,576 | $ | – | ||||
| 10 |
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
Brenda Blume, Director of Investor and Public Relations
952-582-4303
www.blackridgeoil.com
| 11 |