Attached files
| file | filename |
|---|---|
| 8-K - 8-K - Lonestar Resources US Inc. | lone-8k_20170515.htm |
EX-99.1
Lonestar Resources Announces Results For The Three Months Ended March 31, 2017 And Provides Operational Update
Fort Worth, Texas, May 15, 2017 (PRNewswire) - Lonestar Resources US, Inc. (NASDAQ: LONE) (including its subsidiaries, “Lonestar,” “we,” “us,” “our” or the “Company”) reported today its financial and operating results for the three months ended March 31, 2017.
FIRST QUARTER HIGHLIGHTS
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Lonestar reported a 15% sequential increase in net oil and gas production during the three months ended March 31, 2017 (“1Q17”). Net oil and gas production averaged 5,266 Boe/d in the first quarter of 2017 compared to 4,560 Boe/d during three months ended December 31, 2016 (“4Q16”). Production growth was the result of the completion of new Eagle Ford Shale wells. The Company expects to grow production at an accelerated rate during the remainder of 2017 as completion activity accelerates into the second half of 2017. |
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Adjusted EBITDAX for the quarter ended March 31, 2017 was $11.5 million compared to $12.5 million for the quarter ended December 31, 2016. It should be noted that income associated with the favorable settlement of commodities hedges were $0.4 million in 1Q17 vs. $4.9 million in 4Q16. Please see “Non-GAAP Financial Measures” at the end of this release for the definition of Adjusted EBITDAX, a reconciliation of net income (loss) to Adjusted EBITDAX, and the reasons for its use. |
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Lonestar demonstrated exceptional cost control in the first quarter of 2017. The Company sequentially reduced Lease Operating and Gas Gathering Costs (“LOE”) by 15% for the three months ended March 31, 2017 to $3.0 million, as compared to $3.5 million for the three months ended December 31, 2016. Accomplishing these cost reductions at the same time that the Company produced 15% more oil and gas had an even more pronounced effect on per-unit operating costs. Lonestar cut LOE from $8.37 per Boe in 4Q16 to $6.24 per Boe in 1Q17, an improvement of 25%, sequentially. Lonestar expects continued improvement in unit operating costs as absolute costs are controlled and production is increased. |
Lonestar’s Chief Executive Officer, Frank D. Bracken, III, stated, “2017 is off to a strong start, as Lonestar has resumed production growth in the Eagle Ford Shale play with a 15% increase in production over 4Q16 results. Not only is production back in a growth mode, but Lonestar is exerting stringent cost control that is resulting in sharp reductions in cash costs, particularly on a unit-of-production basis, which is resulting in expanding margins.” Bracken added, “Our well results, discussed in this release, are validation of our highly technical approach to the Eagle Ford. I believe that we are on-track to accelerate production growth in the second half of the year, which should achieve improved liquidity and an expanded borrowing base heading into 2018.”
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Lonestar reported a 15% sequential increase in net oil and gas production during the three months ended March 31, 2017 (“1Q17”). Net oil and gas production averaged 5,266 Boe/d in the first quarter of 2017 compared to 4,560 Boe/d during three months ended December 31, 2016 (“4Q16”). Production growth was the result of the completion of new Eagle Ford Shale wells. |
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1Q17 production volumes consisted of 3,250 barrels of oil per day (62%), 927 barrels of NGLs per day (17%), and 6,528 Mcf of natural gas per day (21%). The Company’s production mix for the first quarter of 2017 was 79% liquid hydrocarbons. While 1Q17 production volumes increased 15%, crude oil production increased 32% sequentially, which increased the Company’s crude oil mix from 54% in 4Q16 to 62% in 1Q17, improving the profitability of Lonestar’s production. |
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Lonestar has commenced an active drilling and completion program for 2017. After having completed only 5.0 gross / 3.8 net wells in the first half of 2016, Lonestar plans to drill 12 net wells during 2017. With the 2017 program underway, production has regained upward momentum, with a 15% sequential improvement in 1Q17. |
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Lonestar’s non-tax cash operating cost structure saw significant sequential improvement in the three months ended March 31, 2017, which was achieved through stringent cost control and expanding production volumes: |
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Lease Operating Expense was reduced from $3.5 million in 4Q16 to $3.0 million in 1Q17, a sequential reduction of 15%. On a unit-of-production basis, LOE per Boe was reduced 25% sequentially, from $8.27 per Boe in 4Q16 to $6.24 per Boe in 1Q17. |
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General & Administrative Expense was reduced from $2.8 million in 4Q16 to $2.5 million in 1Q17, a sequential reduction of 12%. On a unit-of-production basis, G&A per Boe was reduced 22% sequentially, from $6.72 per Boe in 4Q16 to $5.26 per Boe in 1Q17. |
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Interest Expense was reduced from $9.9 million in 4Q16 to $5.0 million in 1Q17, a sequential reduction of 49%. On a unit-of-production basis, interest per Boe was reduced 55% sequentially, from $23.69 per Boe in 4Q16 to $10.62 per Boe in 1Q17. |
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2,000 barrels of oil per day with a weighted average strike price of $54.88 per barrel and two-way collars covering 500 barrels per day, which provide an effective floor of $50.00 per Bbl and an effective ceiling of $59.45 per Bbl. Additionally, we have also entered into contracts to hedge our natural gas production, covering 7,000 MMBTU/Day at a weighted average price of $3.36 per MMBtu for 2017. |
EAGLE FORD SHALE TREND- WESTERN REGION
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Asherton – In Dimmit County, no new wells were completed during the three months ended March 31, 2017. The Asherton leasehold is held by production, and Lonestar does not currently plan drilling activity here in 2017. |
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Beall Ranch – In Dimmit County, no new wells were completed during the three months ended March 31, 2017. The Beall Ranch leasehold is held by production, and Lonestar does not currently plan any drilling activity here in 2017. |
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Burns Ranch Area – Lonestar holds 4,830 gross / 4,013 net acres in the Burns Ranch. Lonestar has drilled 6 extended reach laterals in Burns Ranch, and has 20 gross/18.4 net laterals remaining in its inventory which average 8,200 lateral feet. On January 5, 2017, Lonestar completed fracture stimulation operations on the Burns Ranch Eagle Ford #8H, #9H and #10H wells with lateral lengths of approximately 9,620, 9,440 and 8,460 feet, respectively. Lonestar utilized diverters on the #8H, #9H and #10H, which allowed Lonestar to set stage spacing at 300 foot increments, compared to 250-foot spacing on previous wells at Burns Ranch, reducing the number of fracture stages and associated costs while achieving a designed proppant concentration of up to 2,000 pounds per foot in two of these wells, the highest in the Company’s history. |
Lonestar is pleased to report continued excellent performance out of its three new wells drilled at Burns Ranch. Lonestar is highly focused on maintaining lower Gas-Oil-Ratios (“GOR”) in our Generation 5 wells, as we believe that the rapid increase in GOR that we experienced in our Generation 3 wells impaired oil EUR’s. As a result, we have been more stringent in our choke management techniques on our Generation 4 and Generation 5 wells. Lonestar is encouraged with the results of our Generation 5 wells thus far. At 45% pressure drawdown, our Generation 3 wells had recovered 28,250 barrels of oil. By contrast, our Generation 5 wells have achieved over 50,000 barrels of oil recovery with 45% pressure drawdown, an improvement of 79%. We believe this improvement to date is the result of the increased effectiveness of the Generation 5 well completions in contacting additional reservoir rock volume that allows for a more complex fracture volume in the same fracture half-length, resulting in better fracture and drainage efficiency.
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Frog area by 1,426 gross / 1,071 net acres, for a total cost of $0.9 million. Lonestar’s total position in the Horned Frog area now stands at 5,828 gross / 4,642 net acres. Our leasehold provides Lonestar with an inventory of a minimum of 24 extended reach laterals with lateral lengths 7,400 to 10,000 feet. Lonestar currently plans to drill two wells in the Horned Frog area in the second half of 2017. |
EAGLE FORD SHALE TREND- CENTRAL REGION
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Cyclone – After acquiring an additional 526 net acres contiguous to our Cyclone leasehold at a cost of $0.7 million during the first quarter of 2017, Lonestar had a total of 3,064 gross / 2,860 net acres on its Cyclone property as of March 31, 2017, which can accommodate a total 35 laterals with average lateral lengths exceeding 8,100 feet. The Company is in the process of drilling 4 extended reach laterals at Cyclone. The Cyclone #4H has reached total depth of 19,136 feet, has been logged and cased. The Cyclone #5H has reached total depth of 19,100 feet and is undergoing completion operations. Fracture stimulation operations on the Cyclone #4H and #5H are scheduled to commence on May 29, 2017, with flowback operations anticipated in the late second quarter of 2017. Lonestar has an 86.5% working interest (“WI”) in these wells. Following completion of the Cyclone #5H, Lonestar plans to mobilize the rig to drill the Cyclone #26H and #27H, with planned total depths of 18,000 feet and anticipated perforated intervals of 9,000 feet. Lonestar has a 100% WI in these wells. None of these four locations had Proved reserves assigned to them as of December 31, 2016. |
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Pirate – In southwest Wilson County, Lonestar took advantage of an open frac slot with its vendor and improved crude oil pricing, and elected to complete the Pirate #M1H and #N1H wells, which were previously drilled-uncompleted (“DUC’s”). The wells were completed with an average perforated interval of 7,101 feet. Lonestar holds a 100% WI / 76.4% net revenue interest (“NRI”) in these wells. The wells were fracture-stimulated with an average proppant concentration of 1,450 pounds per foot over 23 stages per well, utilizing diverters, which allowed us to fracture on 300-foot stage spacing. The Pirate #M1H tested 311 bbl/d and 120 Mcf/d, or 331 Boe/d on a 28/64” choke. The Pirate #N1H tested 482 bbl/d and 215 Mcf/d, or 518 Boe/d on a 24/64”. After being place on jet pump, the 25 days of production leading up to May 11, 2017, the two wells averaged 394 bbl/d and 210 Mcf/d, or 429 Boe/d. |
EAGLE FORD SHALE TREND- EASTERN REGION
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1,119 BOE per day with a flowing tubing pressure of 4,000 psi, consisting of 648 barrels of oil per day and 2,824 Mcf of natural gas per day, with crude oil gravity averaging 48.8o API and BTU content of 1,332 for the gas stream. After gas processing, current wellhead production rates equate to sales volumes of 1,475 BOE per day, consisting of 648 barrels of oil per day (44%), 510 barrels of natural gas liquids (35%) and 1,881 Mcf per day of natural gas (21%). While preliminary, the results of the Wildcat B1H are encouraging, as Lonestar has a sizable leasehold position in the Wildcat Area, and notably, has not booked any Proved reserves to the area. Lonestar has 9,555 gross / 6,420 net acres in the Wildcat area, which holds 38 extended-reach drilling locations, based on 800-foot spacing. |
CONFERENCE CALL DETAILS
Lonestar will host a live conference call on Monday, May 15, 2017 at 9:00 AM CDT to discuss the first quarter 2017 results and operational highlights.
To access the conference call, participants should dial:
USA: 800-681-8606
International: +1 303-223-2690
A playback of the conference call will be available on the Investor Relations section of Company’s website beginning approximately May 16, 2017. The playback will be available for approximately 2 weeks.
ABOUT LONESTAR RESOURCES US, INC.
Lonestar is an independent oil and natural gas company, focused on the development, production and acquisition of unconventional oil, natural gas liquids (“NGLs”) and natural gas properties in the Eagle Ford Shale in Texas, where we accumulated approximately 43,246 gross (36,069 net) acres in what we believe to be the formation’s crude oil and condensate windows, as of March 31, 2017. As of March 31, 2017, we also held and are conducting resource evaluation on approximately 44,084 gross (28,655 net) acres in the West Poplar area of the Bakken-Three Forks trend in Roosevelt County, Montana. For more information, please visit www.lonestarresources.com.
FORWARD-LOOKING STATEMENTS
This press release contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. All statements contained in this press release that do not relate to matters of historical fact should be considered forward-looking statements, including, without limitation, beliefs and expectations with respect to: discovery and development of crude oil, NGLs and natural gas reserves; drilling and completion of wells and the size of Lonestar’s leasehold; cash flows and liquidity, including statements regarding the expected benefits of the Company’s crude oil hedging; availability and terms of capital; timing, amount and rate of future production of crude oil, NGLs and
natural gas; Lonestar’s business strategy, including its partnership with Schlumberger and the GECA; and the expected benefits from the GECA.
These forward-looking statements are based on management's current expectations. These statements are neither promises nor guarantees, but involve known and unknown risks, uncertainties and other important factors that may cause our actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by the forward-looking statements, including, but not limited to, the following: volatility of oil, natural gas and NGL prices, and potential write-down of the carrying values of crude oil and natural gas properties; ability to successfully replace proved producing reserves; substantial capital expenditures required exploration, development and exploitation projects; potential liabilities resulting from operating hazards, natural disasters or other interruptions; risks related using the latest available horizontal drilling and completion techniques; uncertainties tied to lengthy period of development of identified drilling locations, which could increase costs and materially alter the occurrence or timing of their drilling; unexpected delays and cost overrun related to the development of estimated proved undeveloped reserves; concentration risk related to properties, which are located primarily in the Eagle Ford Shale of South Texas; loss of lease on undeveloped leasehold acreage that may result from lack of development or commercialization, which could materially adversely affect Lonestar’s crude oil, natural gas and NGLs reserves and future production; inaccuracies in assumptions made in estimating proved reserves; Lonestar’s limited control over activities in properties Lonestar does not operate; customer concentration risk; potential inconsistency between the present value of future net revenues from Lonestar’s proved reserves and the current market value of Lonestar’s estimated oil and natural gas reserves; risks related to derivative activities; covenant restrictions related to the revolving credit facility and the indenture that governs 8.75% Senior Notes due 2019; losses resulting from title deficiencies; risks related to health, safety and environmental laws and regulations; additional regulation of hydraulic fracturing, which has recently come under increased scrutiny; reduced demand for crude oil, natural gas and NGLs resulting from conservation measures and technological advances; inability to acquire adequate supplies of water for our drilling operations or to dispose of or recycle the used water economically and in an environmentally safe manner; climate change laws and regulations restricting emissions of “greenhouse gases” that may increase operating costs and reduce demand for the crude oil and natural gas; fluctuations in the differential between benchmark prices of crude oil and natural gas and the reference or regional index price used to price actual crude oil and natural gas sales; recent federal legislation that may have adverse impact on ability to use derivative instruments to reduce the effects of commodity prices, interest rates and other risks associated with the business; and risks in connection with acquisitions and integration. These and other important factors discussed under the caption "Risk Factors" in the Company's Registration Statement on Form 10, as amended and filed with the Securities and Exchange Commission, or the SEC, on June 9, 2016, along with our other reports filed with the SEC could cause actual results to differ materially from those indicated by the forward-looking statements made in this press release. Any such forward-looking statements represent management's estimates as of the date of this press release. While we may elect to update such forward-looking statements at some point in the future, we disclaim any obligation to do so, even if subsequent events
cause our views to change. These forward-looking statements should not be relied upon as representing our views as of any date subsequent to the date of this press release.
(Financial Statements to Follow)
Lonestar Resources US Inc.
Consolidated Balance Sheets
(In thousands, except share and per share data)
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March 31, 2017 |
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December 31, 2016 |
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Assets |
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(Unaudited) |
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Current assets |
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|
|
|
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Cash and cash equivalents |
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$ |
3,884 |
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$ |
6,068 |
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Accounts receivable: |
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|
|
|
|
|
|
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|
Oil, natural gas liquid and natural gas sales |
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|
6,194 |
|
|
|
4,680 |
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Joint interest owners and other, net |
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|
599 |
|
|
|
867 |
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|
Related parties |
|
|
1,711 |
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|
|
847 |
|
|
Derivative financial instruments |
|
|
2,980 |
|
|
|
1,730 |
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|
Prepaid expenses and other |
|
|
2,773 |
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|
|
2,631 |
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|
|
|
|
|
|
|
|
|
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Total current assets |
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18,141 |
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16,823 |
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|
|
|
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Oil and gas properties, net, using the successful efforts method of accounting |
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442,311 |
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439,228 |
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Other property and equipment, net |
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1,273 |
|
|
|
1,421 |
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Derivative financial instruments |
|
|
2,015 |
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|
|
— |
|
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Other noncurrent assets |
|
|
1,645 |
|
|
|
1,561 |
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Restricted certificates of deposit |
|
|
76 |
|
|
|
76 |
|
|
|
|
|
|
|
|
|
|
|
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Total assets |
|
$ |
465,461 |
|
|
$ |
459,109 |
|
Consolidated Balance Sheets (continued)
(In thousands, except share and per share data)
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March 31, 2017 |
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December 31, 2016 |
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Liabilities and Stockholders’ Equity |
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(Unaudited) |
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|
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Current liabilities |
|
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Accounts payable |
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$ |
11,356 |
|
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$ |
14,894 |
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Accounts payable – related parties |
|
|
253 |
|
|
|
1,135 |
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|
Oil, natural gas liquid and natural gas sales payable |
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|
4,050 |
|
|
|
3,568 |
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Accrued liabilities |
|
|
14,821 |
|
|
|
9,947 |
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|
Accrued liabilities – related parties |
|
|
126 |
|
|
|
224 |
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|
Derivative financial instruments |
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145 |
|
|
|
2,985 |
|
|
|
|
|
|
|
|
|
|
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Total current liabilities |
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30,751 |
|
|
|
32,753 |
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|
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|
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|
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Long-term debt |
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214,450 |
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204,122 |
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Long-term debt - related parties |
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— |
|
|
|
3,400 |
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Deferred tax liability |
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|
39,611 |
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38,020 |
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|
Other non-current liabilities |
|
|
6,107 |
|
|
|
6,052 |
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Equity warrant liability |
|
|
788 |
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|
|
1,565 |
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Equity warrant liability - related parties |
|
|
1,501 |
|
|
|
2,994 |
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Asset retirement obligations |
|
|
2,670 |
|
|
|
2,683 |
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Derivative financial instruments |
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|
— |
|
|
|
1,125 |
|
|
|
|
|
|
|
|
|
|
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Total liabilities |
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|
295,878 |
|
|
|
292,714 |
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Commitments and contingencies |
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Stockholders’ equity |
|
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|
|
|
|
|
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Class A voting common stock, $0.001 par value, 100,000,000 shares authorized, 21,822,015 issued and outstanding at March 31, 2017 and December 31, 2016, respectively |
|
|
142,652 |
|
|
|
142,652 |
|
|
Class B non-voting common stock, $0.001 par value, 5,000 shares authorized, 2,500 issued and outstanding at March 31, 2017 and December 31, 2016, respectively |
|
|
— |
|
|
|
— |
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|
Additional paid-in capital |
|
|
87,382 |
|
|
|
87,260 |
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|
Accumulated deficit |
|
|
(60,451 |
) |
|
|
(63,517 |
) |
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|
|
|
|
|
|
|
|
|
|
Total stockholders’ equity |
|
|
169,583 |
|
|
|
166,395 |
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and stockholders’ equity |
|
$ |
465,461 |
|
|
$ |
459,109 |
|
Consolidated Statements of Operations & Comprehensive Loss
(In thousands, except share and per share data)
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Three Months Ended |
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March 31, |
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2017 |
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2016 |
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Revenues |
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Oil sales |
$ |
14,489 |
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$ |
8,951 |
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Natural gas sales |
|
1,456 |
|
|
|
1,622 |
|
|
Natural gas liquid sales |
|
1,671 |
|
|
|
624 |
|
|
|
|
|
|
|
|
|
|
|
Total revenues |
|
17,616 |
|
|
|
11,197 |
|
|
|
|
|
|
|
|
|
|
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Costs and expenses |
|
|
|
|
|
|
|
|
Lease operating and gas gathering |
|
2,956 |
|
|
|
4,360 |
|
|
Production, ad valorem, and severance taxes |
|
1,037 |
|
|
|
916 |
|
|
Rig standby expense |
|
— |
|
|
|
313 |
|
|
Depletion, depreciation, and amortization |
|
12,122 |
|
|
|
15,139 |
|
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Accretion of asset retirement obligations |
|
20 |
|
|
|
56 |
|
|
Loss on sale of oil and gas properties |
|
142 |
|
|
|
— |
|
|
Stock-based compensation |
|
178 |
|
|
|
95 |
|
|
General and administrative |
|
2,492 |
|
|
|
2,773 |
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses |
|
18,947 |
|
|
|
23,652 |
|
|
|
|
|
|
|
|
|
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Loss from operations |
|
(1,331 |
) |
|
|
(12,455 |
) |
|
|
|
|
|
|
|
|
|
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Other income (expense) |
|
|
|
|
|
|
|
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Interest expense |
|
(5,032 |
) |
|
|
(6,124 |
) |
|
Unrealized gain on warrants |
|
2,270 |
|
|
|
— |
|
|
Gain on derivative financial instruments |
|
8,746 |
|
|
|
1,715 |
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Other expense |
|
— |
|
|
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(228 |
) |
|
|
|
|
|
|
|
|
|
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Total other income (expense), net |
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5,984 |
|
|
|
(4,637 |
) |
|
|
|
|
|
|
|
|
|
|
Income (loss) before income taxes |
|
4,653 |
|
|
|
(17,092 |
) |
|
|
|
|
|
|
|
|
|
|
Income tax (expense) benefit |
|
(1,587 |
) |
|
|
5,795 |
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) |
$ |
3,066 |
|
|
$ |
(11,297 |
) |
|
|
|
|
|
|
|
|
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|
Net income (loss) per common share |
|
|
|
|
|
|
|
|
Basic |
$ |
0.14 |
|
|
$ |
(1.50 |
) |
|
Diluted |
$ |
0.13 |
|
|
$ |
(1.50 |
) |
|
Weighted average common shares outstanding |
|
|
|
|
|
|
|
|
Basic |
|
21,822,015 |
|
|
|
7,522,025 |
|
|
Diluted |
|
22,833,615 |
|
|
|
7,522,025 |
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income (loss): |
|
|
|
|
|
|
|
|
Net income (loss) |
$ |
3,066 |
|
|
$ |
(11,297 |
) |
|
Foreign currency translation adjustments |
|
— |
|
|
|
1 |
|
|
Comprehensive income (loss) |
$ |
3,066 |
|
|
$ |
(11,296 |
) |
|
|
|
|
|
|
|
|
|
Consolidated Statements of Cash Flows
(In thousands)
|
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|
Three Months Ended |
|
|||||
|
|
|
March 31, |
|
|||||
|
|
|
2017 |
|
|
2016 |
|
||
|
Operating activities |
|
|
|
|
|
|
|
|
|
Net income (loss) |
|
$ |
3,066 |
|
|
$ |
(11,297 |
) |
|
Adjustments to reconcile net income (loss) to net cash provided by operating activities: |
|
|
|
|
|
|
|
|
|
Accretion of asset retirement obligations |
|
|
20 |
|
|
|
56 |
|
|
Depreciation, depletion, and amortization |
|
|
12,122 |
|
|
|
15,139 |
|
|
Stock-based compensation |
|
|
178 |
|
|
|
95 |
|
|
Deferred taxes |
|
|
1,591 |
|
|
|
(5,868 |
) |
|
Gain on derivative financial instruments |
|
|
(8,746 |
) |
|
|
(1,716 |
) |
|
Settlements of derivative financial instruments |
|
|
1,516 |
|
|
|
10,636 |
|
|
Impairment of oil and gas properties |
|
|
— |
|
|
|
23 |
|
|
Non-cash interest expense |
|
|
581 |
|
|
|
275 |
|
|
Unrealized gain on warrants |
|
|
(2,270 |
) |
|
|
— |
|
|
Changes in operating assets and liabilities: |
|
|
|
|
|
|
|
|
|
Accounts receivable |
|
|
(2,110 |
) |
|
|
688 |
|
|
Prepaid expenses and other assets |
|
|
(378 |
) |
|
|
(104 |
) |
|
Accounts payable and accrued expenses |
|
|
7,398 |
|
|
|
9,788 |
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities |
|
|
12,968 |
|
|
|
17,715 |
|
|
|
|
|
|
|
|
|
|
|
|
Investing activities |
|
|
|
|
|
|
|
|
|
Acquisition of oil and gas properties |
|
|
(1,563 |
) |
|
|
(2,065 |
) |
|
Development of oil and gas properties |
|
|
(19,076 |
) |
|
|
(14,587 |
) |
|
Purchases of other property and equipment |
|
|
(13 |
) |
|
|
(176 |
) |
|
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities |
|
|
(20,652 |
) |
|
|
(16,828 |
) |
|
|
|
|
|
|
|
|
|
|
|
Financing activities |
|
|
|
|
|
|
|
|
|
Proceeds from borrowings and related party borrowings |
|
|
9,000 |
|
|
|
7,000 |
|
|
Payments on borrowings and related party borrowings |
|
|
(2,500 |
) |
|
|
(8,000 |
) |
|
Cost to issue equity |
|
|
(1,000 |
) |
|
|
— |
|
|
Changes in other notes payable |
|
|
— |
|
|
|
(21 |
) |
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) financing activities |
|
|
5,500 |
|
|
|
(1,021 |
) |
|
|
|
|
|
|
|
|
|
|
|
Effect of exchange rate changes on cash and cash equivalents |
|
|
— |
|
|
|
1 |
|
|
|
|
|
|
|
|
|
|
|
|
Decrease in cash and cash equivalents |
|
|
(2,184 |
) |
|
|
(133 |
) |
|
Cash and cash equivalents, beginning of the period |
|
|
6,068 |
|
|
|
4,321 |
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents, end of the period |
|
$ |
3,884 |
|
|
$ |
4,188 |
|
|
|
|
|
|
|
|
|
|
|
|
Supplemental information: |
|
|
|
|
|
|
|
|
|
Cash paid for interest expense |
|
$ |
912 |
|
|
$ |
705 |
|
Reconciliation of Non-GAAP Financial Measures
Adjusted EBITDAX
Adjusted EBITDAX is not a measure of net income as determined by GAAP. Adjusted EBITDAX is a supplemental non-GAAP financial measure that is used by management and external users of the Company’s consolidated financial statements, such as industry analysts, investors, lenders and rating agencies. The Company defines Adjusted EBITDAX as net (loss) income before depreciation, depletion, amortization and accretion, exploration costs, non-recurring costs, (gain) loss on sales of oil and natural gas properties, impairment of oil and gas properties, stock-based compensation, interest expense, income tax (benefit) expense, rig standby expense, other income (expense) and unrealized (gain) loss on derivative financial instruments and unrealized (gain) loss on warrants.
Management believes Adjusted EBITDAX provides useful information to investors because it assists investors in the evaluation of the Company’s operating performance and comparison of the results of the Company’s operations from period to period without regard to its financing methods or capital structure. The Company excludes the items listed above from net income in arriving at Adjusted EBITDAX to eliminate the impact of certain non-cash items or because these amounts can vary substantially from company to company within its industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDAX should not be considered as an alternative to, or more meaningful than, net income as determined in accordance with GAAP. Certain items excluded from Adjusted EBITDAX are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of Adjusted EBITDAX. The Company’s computations of Adjusted EBITDAX may not be comparable to other similarly titled measures of other companies.
The following table presents a reconciliation of Adjusted EBITDAX to the GAAP financial measure of net income (loss) for each of the periods indicated.
|
|
|
Three Months Ended March 31, |
|
|||||
|
($ in thousands) |
|
2017 |
|
|
2016 |
|
||
|
Net Income (Loss) |
|
$ |
3,066 |
|
|
$ |
(11,297 |
) |
|
Income tax expense (benefit) |
|
|
1,587 |
|
|
|
(5,795 |
) |
|
Interest expense |
|
|
5,032 |
|
|
|
6,124 |
|
|
Depletion, depreciation, amortization and accretion |
|
|
12,142 |
|
|
|
15,195 |
|
|
EBITDAX |
|
|
21,827 |
|
|
|
4,227 |
|
|
Rig standby expense (1) |
|
|
— |
|
|
|
313 |
|
|
Non-recurring costs (2) |
|
|
— |
|
|
|
323 |
|
|
Stock-based compensation |
|
|
178 |
|
|
|
95 |
|
|
Loss on sale of oil and gas properties |
|
|
142 |
|
|
|
— |
|
|
Unrealized (gain) loss on derivative financial instruments |
|
|
(8,339 |
) |
|
|
8,429 |
|
|
Unrealized gain on warrants |
|
|
(2,270 |
) |
|
|
— |
|
|
Other (income) expense |
|
|
(4 |
) |
|
|
206 |
|
|
Adjusted EBITDAX |
|
$ |
11,534 |
|
|
$ |
13,593 |
|
1 Represents a non-recurring cost associated with a rig contract that expired in July 2016
2 Non-recurring costs consist of General and Administrative Expenses related to the re-domiciliation to the NASDAQ
Operating Results
|
|
|
For the three months ended March 31, |
|
|||||
|
|
|
2017 |
|
|
2016 |
|
||
|
Daily production volumes by product - |
|
|
|
|
|
|
|
|
|
Crude oil (MBbls) |
|
|
3,250 |
|
|
|
3,414 |
|
|
NGLs (MBbls) |
|
|
927 |
|
|
|
1,404 |
|
|
Natural gas (MMcf) |
|
|
6,528 |
|
|
|
10,411 |
|
|
Total barrels of oil equivalent (Boe/d) |
|
|
5,266 |
|
|
|
6,553 |
|
|
|
|
|
|
|
|
|
|
|
|
Daily production volumes by region (Boe/d) - |
|
|
|
|
|
|
|
|
|
Eagle Ford Shale |
|
|
5,266 |
|
|
|
5,954 |
|
|
Conventional |
|
|
0 |
|
|
|
599 |
|
|
Total barrels of oil equivalent (Boe/d) |
|
|
5,266 |
|
|
|
6,553 |
|
|
|
|
|
|
|
|
|
|
|
|
Average realized prices - |
|
|
|
|
|
|
|
|
|
Crude oil ($ per Bbl) |
|
$ |
49.53 |
|
|
$ |
28.81 |
|
|
NGLs ($ per Bbl) |
|
|
20.02 |
|
|
|
4.90 |
|
|
Natural gas ($ per Mcf) |
|
|
2.48 |
|
|
|
1.71 |
|
|
Total Oil Equivalent, excluding the effect from hedging |
|
$ |
37.18 |
|
|
$ |
18.78 |
|
|
Total Oil Equivalent, including the effect from hedging |
|
$ |
38.04 |
|
|
$ |
35.79 |
|
|
|
|
|
|
|
|
|
|
|
|
Operating Expenses per BOE: |
|
|
|
|
|
|
|
|
|
Lease operating and gas gathering |
|
$ |
6.24 |
|
|
$ |
7.32 |
|
|
Production, ad valorem, and severance taxes |
|
|
2.19 |
|
|
|
1.54 |
|
|
Depreciation, depletion and amortization |
|
|
25.62 |
|
|
|
25.48 |
|
|
General and administrative |
|
|
5.26 |
|
|
|
4.65 |
|