Attached files
| file | filename |
|---|---|
| 8-K - 8-K - Lonestar Resources US Inc. | lone-8k_20170323.htm |
EX-99.1
Lonestar Resources Announces Year Ended 2016 Results
And Provides Operational Update
Fort Worth, Texas, March 23, 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 and year ended December 31, 2016.
2016 HIGHLIGHTS
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Lonestar reported net oil and gas production of 5,899 Boe/d during the twelve months ended December 31, 2016, compared to 6,408 Boe/d during the twelve months ended December 31, 2015. Two principal factors were responsible for the 8% decline in production. First, the Company completed the sale of its Conventional assets during the third and fourth quarters of 2016. These assets contributed an average of 590 Boe/d during the first half of 2016. Second, the Company’s Eagle Ford Shale production of 5,445 Boe/d represented a 4% decline, as the Company did not complete any new Eagle Ford Shale wells after the second quarter of 2016. |
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Adjusted EBITDAX for the year ended December 31, 2016 was $56.8 million compared to $84.3 million for the year ended December 31, 2015. The decline was due to a 21% decrease in the Company’s oil-equivalent price realization and an 8% reduction in oil and gas production. 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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In October, 2016, Lonestar concluded a sale of its remaining non-core Conventional assets. In total, the Company received a total of $15.8 million in net proceeds from the sale its Conventional assets which carried substantially higher operating costs than its core Eagle Ford Shale assets. With this sale, 100% of the Company’s producing assets are in the Eagle Ford Shale play. |
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During 2016, Lonestar reduced long-term debt outstanding from $307.0 million at December 31, 2015 to $212.3 million at December 31, 2016. Principal sources of debt reduction included the public offering of 13.8 million shares of Class A common stock, $15.8 million of net proceeds from the sale of the Company’s Conventional assets, and open market purchases of $68.2 million of the Company’s 8 ¾% Senior Unsecured Notes at significant discounts to par. At December 31, 2016, long-term debt outstanding was comprised of $43.5 million of Revolving Credit Facility, $17.0 million of Second Lien Senior Notes and $151.8 million of 8 ¾% Senior Unsecured Notes. At year-end 2016, Lonestar has $68.5 million of availability under its Revolving Credit Facility. |
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Lonestar recently announced Proved reserves PV-10 at NYMEX strip prices, as of December 31, 2016 (as described below, “Strip Pricing”). On this basis, the Company's proved reserves were 44.9 MMBOE and PV-10 was $382.0 million. These reserves are comprised of 27.0 million barrels of crude oil, 8.3 million barrels of NGLs and 57.9 Bcf of natural gas. On an energy equivalent basis, Lonestar’s reserves are 78% liquid hydrocarbons. |
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During the first quarter of 2017, Lonestar has entered into a series of transactions in the Eagle Ford Shale play which continue Lonestar’s track record of cost-efficient growth in its reserves base and drilling inventory. Lonestar has reached a series of agreements to acquire interests in a total of 2,565 gross / 1,920 net acres in Gonzales and La Salle Counties, Texas for a total cost of $9.1 million. Current production associated with these interests averaged an estimated 133 barrels of oil per day and 81 Mcf of natural gas per day, or 147 BOE per day. These properties were acquired through a combination of the purchase of working interests in producing properties, farm-in agreements and primary term lease acquisitions. The purchases represent a combination of increased working interests in Lonestar-operated properties in Gonzales County and the acquisition of undeveloped leasehold that is contiguous to the Company’s Cyclone asset in Gonzales County, as well as the acquisition of additional leasehold north of Lonestar’s Horned Frog asset in LaSalle County. In aggregate, this leasehold increases drilling inventory by up to 28 gross locations in well-established parts of the Eagle Ford Shale play. These new lease blocks are in areas where Lonestar has already demonstrated technical excellence, Cyclone and Horned Frog, and add mass to existing areas of operations. Lastly, lateral lengths on the acquired lease blocks will range from 7,000 feet to 10,000 feet, in keeping with the Company’s current emphasis on extended reach laterals. Additionally, the Company’s internally generated reserve estimate forecast proved and probable reserves of 6.7 MMBOE of which 0.4 MMBOE was Proved Developed Producing. |
Lonestar’s Chief Executive Officer, Frank D. Bracken, III, stated, “2016 was a transformational year for Lonestar. We moved the Company’s listing to the NASDAQ exchange. We sold our non-core Conventional assets. We completed our first U.S. stock offering that provided equity capital to restart our Eagle Ford Shale development program. Most importantly, we reduced long-term debt outstanding by $115.2 million in the last six months of the year, representing a 34% reduction. We anticipate increasing production sequentially in each quarter of 2017 by drilling extended reach laterals on our existing leasehold. Already in 2017, we have entered into a series of transactions that increase our reserves and drilling inventory and provide additional growth opportunities. With this excellent start to the year, we believe Lonestar is well-positioned to generate significant growth in shareholder value in 2017 and beyond.”
OPERATIONAL UPDATE
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Lonestar reported net oil and gas production of 4,560 Boe/d during the three months ended December 31, 2016 (“4Q16”), compared to 5,921 Boe/d during the three months ended September 30, 2016 (“3Q16”). Two principal factors were responsible for the 23% decline in production. First, the Company completed the sale of its Conventional assets during the quarter. These assets contributed 436 BOEPD during 3Q16. Second, the Company had not completed any new Eagle Ford Shale wells since the second quarter of 2016. |
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4Q16 production volumes consisted of 2,457 barrels of oil per day (54%), 984 barrels of NGLs per day (22%), and 6,717 Mcf of natural gas per day (24%). The Company’s production mix for the fourth quarter of 2016 was 75% liquid hydrocarbons. Including 2016 results, Lonestar’s four year reserves replacement is 405% and four year all-sources F&D cost averages $11.56 per BOE. |
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Lonestar’s lease operating expenses for the fourth quarter of 2016 were $3.5 million, representing a 30% decrease over 4Q15 lease operating expenses of $4.5 million. |
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Crude oil hedging continues to be an important element of Lonestar’s strategy. We believe crude oil hedging provides increased visibility to cash flow streams and associated liquidity in the current crude oil price environment, and augments the Company’s borrowing base. For 2017 our total crude oil hedge position coverage is approximately 2,877 barrels of oil per day at an average strike price of $53.77 per barrel, and for 2018 our total crude oil hedge position coverage is approximately 2,500 barrels of oil per day at an average strike price of $55.33 per barrel. 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 central Dimmit County, no new wells were completed during the three months ended December 31, 2016. Production rates from the four producing wells continued to outperform the third-party engineering projections. The Asherton leasehold is held by production, and Lonestar does not current plan drilling activity here in 2017. However, at year-end 2016, Lonestar converted its 6 remaining 5,000-foot PUD locations into three 10,000-foot PUD locations. |
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Burns Ranch Area –In August 2016, Lonestar executed a lease swap agreement with another operator and consolidated Lonestar’s leasehold position so that we can now drill at our own discretion. Following the lease swap, Lonestar has a remaining 20 gross/18.4 net laterals averaging 8,200 lateral feet. On January 5, 2017, Lonestar recently 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. These wells were drilled to an average measured depth of 18,007 feet and were drilled from spud to total depth in an average of 13.3 days. Lonestar utilized BroadBand diverters on the #8H, #9H and #10H, which allowed Lonestar to set stage spacing at 300 foot increments, reducing the number of frac 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. |
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The Burns Ranch #8H, which has a perforated interval of 9,518 feet and was fracture stimulated with a proppant concentration of 1,487 lbs/ft., registered 30-day rates of 509 bbl/d and 621 Mcf/d, or 667 Boe/d on a three-stream basis. |
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The Burns Ranch #10H, which has a perforated interval of 8,456 feet and was fracture stimulated with a proppant concentration of 2,025 lbs/ft., registered 30-day rates of 560 bbl/d and 453 Mcf/d, or 675 Boe/d on a three-stream basis. |
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Lonestar is highly focused on maintaining lower Gas-Oil-Ratios in our Gen 5 wells, as we believe that the rapid increase in GOR that we experienced in our Gen 3 wells impaired oil EUR’s. As a result, we have been more stringent in our choke management techniques on our Gen 4 and Gen 5 wells. Lonestar is encouraged with the results of our Gen 5 wells thus far- at 30% pressure drawdown, our Gen 3 wells had recovered 15,900 barrels of oil. By contrast, our Gen 5 wells have achieved 30,000 barrels of oil recovery with 30% pressure drawdown, an improvement of 89%. We believe the results to date are the result of the increased effectiveness of the Gen 5 completions in contacting additional reservoir rock volume via a more complex fracture volume in the same fracture half-length, resulting in better frac and drainage efficiency. |
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Horned Frog – In southern La Salle County, no new wells were completed during the three months ended December 31, 2016. Lonestar currently plans to drill two 8,000-foot laterals at Horned Frog during 2017, in which the Company will own 100% WI / 80% NRI. During the first quarter of 2017, Lonestar reached agreements to acquire working interests in 1,426 gross / 1,071 net acres in a block just north of the Company’s Horned Frog property. The leasehold, which was assembled via more than a dozen primary term leases and a farm-in agreement, was acquired at a total cost of $0.9 million. Depending on ultimate spacing, which could range from 500-feet to 700 feet-per well, the lease block will accommodate 7 to 11 extended reach laterals ranging from 7,400 feet and 10,000 feet in length. The Company’s internal reserves estimates for the acquired interests are 4.3 million barrels of oil equivalent. |
EAGLE FORD SHALE TREND- CENTRAL REGION
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acres which are contiguous to the Company’s current leasehold. The leases were acquired at a total cost of $0.7 million, and increase the number of extended-reach drilling locations at Cyclone from 26 to 33. The Company’s internal reserves estimates for the newly- acquired interests are 2.1 million barrels of oil equivalent. Lonestar plans to drill two 2-well pads, commencing in April. The Cyclone #4H & #5H have been permitted with planned TD’s of 19,100 feet, indicating planned perforated intervals of 10,000 feet. Lonestar expects to have an 86.5% WI in these wells. Lonestar plans to file permits next week for the Cyclone #26H and #27H, with planned TD’s of 18,000 feet, indicating planned perforated intervals of 9,000 feet. Lonestar expects to have a 100% WI in these wells. |
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Harvey Johnson- Lonestar holds a 50% working interest and operates six Eagle Ford Shale wells, the Harvey Johnson #1H-#6H. Lonestar has executed a definitive agreement to purchase a 33.5% working interest in the Harvey Johnson Eagle Ford Shale unit for $7.6 million. The acquisition adds an estimated 133 barrels of oil per day and 81 Mcf of natural gas per day, or 147 BOE per day, as indicated by March, 2017 production. The acquisition also includes a 33.5% working interest in the 967 acre unit, roughly half of which is undeveloped. Proved Developed Producing reserves associated with the transaction are 0.4 MMBOE, 85% of which are crude oil. Additional reserves potential exists in the undeveloped leasehold, which can accommodate 8 laterals when pooled with offsetting acreage. |
EAGLE FORD SHALE TREND- EASTERN REGION
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Brazos & Robertson Counties – In February, 2017, Lonestar commenced drilling the Wildcat #B1H well in Brazos County, Texas with a projected total depth of 19,700 feet. Lonestar owns a 50% working interest in the Wildcat #B1H well. The well is currently drilling ahead at a depth of 19,400 feet and is expected to reach total depth today. Upon completion of the #B1H well, Lonestar plans to mobilize the rig to drill four wells at Cyclone in Gonzales County. |
CONFERENCE CALL DETAILS
Lonestar will host a live conference call on Thursday, March 23, 2017 at 4:00 PM CDT to discuss the fourth quarter 2016 results and operational highlights.
To access the conference call, participants should dial:
USA: 800-671-7032
International: +1 303-223-4377
A playback of the conference call will be available on the Investor Relations section of Company’s website beginning approximately March 23, 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 41,274 gross (34,170 net) acres in what we believe to be the formation’s crude oil and condensate windows, as of December 31, 2016. As of December 31, 2016, we also held a portfolio of conventional, long-lived, crude oil-weighted onshore assets in Texas 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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December 31, 2016 |
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December 31, 2015 |
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Assets |
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Current assets |
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|
|
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|
|
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Cash and cash equivalents |
|
$ |
6,068 |
|
|
$ |
4,322 |
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|
Accounts receivable: |
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|
|
|
|
|
|
|
|
Oil, natural gas liquid and natural gas sales |
|
|
4,680 |
|
|
|
5,043 |
|
|
Joint interest owners and other, net |
|
|
867 |
|
|
|
1,305 |
|
|
Related parties |
|
|
847 |
|
|
|
279 |
|
|
Derivative financial instruments |
|
|
1,730 |
|
|
|
33,219 |
|
|
Prepaid expenses and other |
|
|
2,631 |
|
|
|
724 |
|
|
|
|
|
|
|
|
|
|
|
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Total current assets |
|
|
16,823 |
|
|
|
44,892 |
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|
|
|
|
|
|
|
|
|
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Oil and gas properties, net, using the successful efforts method of accounting |
|
|
439,228 |
|
|
|
488,100 |
|
|
Other property and equipment, net |
|
|
1,421 |
|
|
|
2,223 |
|
|
Derivative financial instruments |
|
|
— |
|
|
|
2,864 |
|
|
Other noncurrent assets |
|
|
1,561 |
|
|
|
1,580 |
|
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Restricted certificates of deposit |
|
|
76 |
|
|
|
77 |
|
|
|
|
|
|
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|
|
|
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Total assets |
|
$ |
459,109 |
|
|
$ |
539,736 |
|
Consolidated Balance Sheets (continued)
(In thousands, except share and per share data)
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December 31, 2016 |
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December 31, 2015 |
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Liabilities and Stockholders’ Equity |
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Current liabilities |
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|
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Accounts payable |
|
$ |
14,894 |
|
|
$ |
18,027 |
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|
Accounts payable – related parties |
|
|
1,135 |
|
|
|
45 |
|
|
Oil, natural gas liquid and natural gas sales payable |
|
|
3,568 |
|
|
|
3,870 |
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Accrued liabilities |
|
|
9,947 |
|
|
|
8,276 |
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|
Accrued liabilities – related parties |
|
|
224 |
|
|
|
125 |
|
|
Derivative financial instruments |
|
|
2,985 |
|
|
|
— |
|
|
|
|
|
|
|
|
|
|
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Total current liabilities |
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|
32,753 |
|
|
|
30,343 |
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|
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|
|
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|
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Long-term debt |
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|
204,122 |
|
|
|
301,926 |
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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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|
38,020 |
|
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|
16,013 |
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Other non-current liabilities |
|
|
6,052 |
|
|
|
1,000 |
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|
Equity warrant liability |
|
|
1,565 |
|
|
|
— |
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Equity warrant liability - related parties |
|
|
2,994 |
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|
|
— |
|
|
Asset retirement obligations |
|
|
2,683 |
|
|
|
7,488 |
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Derivative financial instruments |
|
|
1,125 |
|
|
|
— |
|
|
|
|
|
|
|
|
|
|
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Total liabilities |
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|
292,714 |
|
|
|
356,770 |
|
|
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Commitments and contingencies |
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Stockholders’ equity |
|
|
|
|
|
|
|
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|
Class A voting common stock, $0.001 par value, 100,000,000 shares authorized, 21,822,015 and 7,521,788 issued and outstanding at December 31, 2016 and 2015, respectively |
|
|
142,652 |
|
|
|
142,638 |
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|
Class B non-voting common stock, $0.001 par value, 5,000 shares authorized, 2,500 and 0 issued and outstanding at December 31, 2016 and 2015, respectively |
|
|
— |
|
|
|
— |
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|
Additional paid-in capital |
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|
87,260 |
|
|
|
10,270 |
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|
Accumulated other comprehensive loss |
|
|
— |
|
|
|
(760 |
) |
|
Retained (deficit) earnings |
|
|
(63,517 |
) |
|
|
30,818 |
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|
|
|
|
|
|
|
|
|
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Total stockholders’ equity |
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|
166,395 |
|
|
|
182,966 |
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|
|
|
|
|
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Total liabilities and stockholders’ equity |
|
$ |
459,109 |
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|
$ |
539,736 |
|
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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Years Ended |
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December 31, |
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December 31, |
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2016 |
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2015 |
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2016 |
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2015 |
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Revenues |
(Unaudited) |
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|||||
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Oil sales |
$ |
10,550 |
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|
$ |
14,331 |
|
|
$ |
46,954 |
|
|
$ |
70,739 |
|
|
Natural gas sales |
|
1,717 |
|
|
|
2,732 |
|
|
|
7,165 |
|
|
|
6,823 |
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Natural gas liquid sales |
|
1,168 |
|
|
|
390 |
|
|
|
3,853 |
|
|
|
1,928 |
|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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Total revenues |
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13,435 |
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|
17,453 |
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|
57,972 |
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|
79,490 |
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Costs and expenses |
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|
|
|
|
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Lease operating and gas gathering |
|
3,468 |
|
|
|
4,524 |
|
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|
16,232 |
|
|
|
17,190 |
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Production, ad valorem, and severance taxes |
|
241 |
|
|
|
779 |
|
|
|
3,287 |
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|
|
4,982 |
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Rig standby expense |
|
— |
|
|
|
653 |
|
|
|
2,261 |
|
|
|
663 |
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Depletion, depreciation, and amortization |
|
8,587 |
|
|
|
18,967 |
|
|
|
46,888 |
|
|
|
58,828 |
|
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Accretion of asset retirement obligations |
|
20 |
|
|
|
54 |
|
|
|
180 |
|
|
|
214 |
|
|
Loss (gain) on sale of oil and gas properties |
|
1,404 |
|
|
|
(625 |
) |
|
|
(74 |
) |
|
|
— |
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|
Impairment of oil and gas properties |
|
2,811 |
|
|
|
28,623 |
|
|
|
33,893 |
|
|
|
28,623 |
|
|
Stock-based compensation |
|
135 |
|
|
|
839 |
|
|
|
448 |
|
|
|
2,585 |
|
|
General and administrative |
|
2,818 |
|
|
|
3,730 |
|
|
|
11,319 |
|
|
|
10,825 |
|
|
Other expense (income) |
|
217 |
|
|
|
(53 |
) |
|
|
1,261 |
|
|
|
— |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses |
|
19,701 |
|
|
|
57,491 |
|
|
|
115,695 |
|
|
|
123,910 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss from operations |
|
(6,266 |
) |
|
|
(40,038 |
) |
|
|
(57,723 |
) |
|
|
(44,420 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income (expense) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense |
|
(9,939 |
) |
|
|
(6,092 |
) |
|
|
(29,583 |
) |
|
|
(24,577 |
) |
|
(Loss) gain on redemption of bonds |
|
(883 |
) |
|
|
— |
|
|
|
28,480 |
|
|
|
— |
|
|
Unrealized gain on warrants |
|
1,179 |
|
|
|
— |
|
|
|
568 |
|
|
|
— |
|
|
(Loss) gain on derivative financial instruments |
|
(5,267 |
) |
|
|
8,653 |
|
|
|
(8,672 |
) |
|
|
27,609 |
|
|
Other expense |
|
— |
|
|
|
(1,066 |
) |
|
|
— |
|
|
|
(1,066 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other income (expense), net |
|
(14,910 |
) |
|
|
1,495 |
|
|
|
(9,207 |
) |
|
|
1,966 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss before income taxes |
|
(21,176 |
) |
|
|
(38,543 |
) |
|
|
(66,930 |
) |
|
|
(42,454 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax (expense) benefit |
|
(37,759 |
) |
|
|
13,702 |
|
|
|
(27,405 |
) |
|
|
15,121 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss |
$ |
(58,935 |
) |
|
$ |
(24,841 |
) |
|
$ |
(94,335 |
) |
|
$ |
(27,333 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other comprehensive (loss) income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss |
$ |
(58,935 |
) |
|
$ |
(24,841 |
) |
|
$ |
(94,335 |
) |
|
$ |
(27,333 |
) |
|
Foreign currency translation adjustments |
|
- |
|
|
|
41 |
|
|
|
— |
|
|
|
12 |
|
|
Comprehensive loss |
$ |
(58,935 |
) |
|
$ |
(24,800 |
) |
|
$ |
(94,335 |
) |
|
$ |
(27,321 |
) |
Consolidated Statements of Cash Flows
(In thousands)
|
|
|
Years Ended |
|
|||||
|
|
|
December 31, |
|
|||||
|
|
|
2016 |
|
|
2015 |
|
||
|
Operating activities |
|
|
|
|
|
|
|
|
|
Net loss |
|
$ |
(94,335 |
) |
|
$ |
(27,333 |
) |
|
Adjustments to reconcile net loss to net cash provided by operating activities: |
|
|
|
|
|
|
|
|
|
Loss on disposal of oil and gas properties |
|
|
35 |
|
|
|
629 |
|
|
Accretion of asset retirement obligations |
|
|
180 |
|
|
|
214 |
|
|
Depreciation, depletion, and amortization |
|
|
46,888 |
|
|
|
58,828 |
|
|
Stock-based compensation |
|
|
448 |
|
|
|
2,585 |
|
|
Deferred taxes |
|
|
27,059 |
|
|
|
(15,497 |
) |
|
Loss (gain) on derivative financial instruments |
|
|
8,672 |
|
|
|
(27,609 |
) |
|
Settlements of derivative financial instruments |
|
|
29,790 |
|
|
|
35,284 |
|
|
Gain on redemption of bonds |
|
|
(28,480 |
) |
|
|
— |
|
|
Impairment of oil and gas properties |
|
|
33,893 |
|
|
|
28,623 |
|
|
Non-cash interest expense |
|
|
7,581 |
|
|
|
1,100 |
|
|
Unrealized gain on warrants |
|
|
(568 |
) |
|
|
— |
|
|
Changes in operating assets and liabilities: |
|
|
|
|
|
|
|
|
|
Accounts receivable |
|
|
234 |
|
|
|
10,857 |
|
|
Prepaid expenses and other assets |
|
|
(1,856 |
) |
|
|
223 |
|
|
Accounts payable and accrued expenses |
|
|
(5,272 |
) |
|
|
(17,065 |
) |
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities |
|
|
24,269 |
|
|
|
50,839 |
|
|
|
|
|
|
|
|
|
|
|
|
Investing activities |
|
|
|
|
|
|
|
|
|
Acquisition of oil and gas properties |
|
|
(4,340 |
) |
|
|
(8,723 |
) |
|
Development of oil and gas properties |
|
|
(39,382 |
) |
|
|
(85,458 |
) |
|
Proceeds from sales of oil and gas properties |
|
|
16,174 |
|
|
|
— |
|
|
Purchases of other property and equipment |
|
|
(233 |
) |
|
|
(337 |
) |
|
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities |
|
|
(27,781 |
) |
|
|
(94,518 |
) |
|
|
|
|
|
|
|
|
|
|
|
Financing activities |
|
|
|
|
|
|
|
|
|
Proceeds from borrowings and related party borrowings |
|
|
72,063 |
|
|
|
140,514 |
|
|
Payments on borrowings and related party borrowings |
|
|
(134,697 |
) |
|
|
(102,514 |
) |
|
Proceeds from sale of common stock, net of offering costs |
|
|
72,807 |
|
|
|
— |
|
|
Payments of debt issuance\settlement costs |
|
|
(4,912 |
) |
|
|
— |
|
|
Payments on other notes payable |
|
|
(3 |
) |
|
|
(3 |
) |
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by financing activities |
|
|
5,258 |
|
|
|
37,997 |
|
|
|
|
|
|
|
|
|
|
|
|
Effect of exchange rate changes on cash and cash equivalents |
|
|
— |
|
|
|
12 |
|
|
|
|
|
|
|
|
|
|
|
|
Increase (decrease) in cash and cash equivalents |
|
|
1,746 |
|
|
|
(5,670 |
) |
|
Cash and cash equivalents, beginning of the period |
|
|
4,322 |
|
|
|
9,992 |
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents, end of the period |
|
$ |
6,068 |
|
|
$ |
4,322 |
|
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 December 31, |
|
|
Year Ended December 31, |
|
||||||||||
|
($ in thousands) |
|
2016 |
|
|
2015 |
|
|
2016 |
|
|
2015 |
|
||||
|
Net Income (Loss) |
|
$ |
(58,935 |
) |
|
$ |
7,381 |
|
|
$ |
(94,335 |
) |
|
$ |
(27,333 |
) |
|
Income tax expense (benefit) |
|
|
37,759 |
|
|
|
4,360 |
|
|
|
27,405 |
|
|
|
(15,121 |
) |
|
Interest expense |
|
|
9,939 |
|
|
|
6,666 |
|
|
|
29,583 |
|
|
|
24,577 |
|
|
Exploration expense |
|
|
371 |
|
|
|
— |
|
|
|
382 |
|
|
|
222 |
|
|
Depletion, depreciation, amortization and accretion |
|
|
8,607 |
|
|
|
13,021 |
|
|
|
47,068 |
|
|
|
59,042 |
|
|
EBITDAX |
|
|
(2,259 |
) |
|
|
31,428 |
|
|
|
10,103 |
|
|
|
41,387 |
|
|
Rig Standby Expense (1) |
|
|
0 |
|
|
|
10 |
|
|
|
2,261 |
|
|
|
663 |
|
|
Non-recurring costs (2) |
|
|
308 |
|
|
|
25 |
|
|
|
1,556 |
|
|
|
1,226 |
|
|
Stock based compensation |
|
|
135 |
|
|
|
880 |
|
|
|
448 |
|
|
|
2,585 |
|
|
(Gain) loss on sale of properties |
|
|
1,404 |
|
|
|
— |
|
|
|
(74 |
) |
|
|
— |
|
|
Impairment of oil and gas properties |
|
|
2,811 |
|
|
|
— |
|
|
|
33,893 |
|
|
|
28,623 |
|
|
Unrealized (gain) loss on derivative financial instruments |
|
|
10,163 |
|
|
|
(10,668 |
) |
|
|
36,368 |
|
|
|
8,728 |
|
|
Unrealized (gain) loss on warrants |
|
|
(1,179 |
) |
|
|
— |
|
|
|
(568 |
) |
|
|
— |
|
|
Other (income) expense (3) |
|
|
1,119 |
|
|
|
18 |
|
|
|
(27,219 |
) |
|
|
1,066 |
|
|
Adjusted EBITDAX |
|
$ |
12,502 |
|
|
$ |
21,693 |
|
|
$ |
56,768 |
|
|
$ |
84,278 |
|
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
3 Represents a gain on redemption of bonds due to repurchase at a discount
Operating Results
|
|
|
For the three months ended December 31, |
|
|
For the year ended December 31, |
|
||||||||||
|
|
|
2016 |
|
|
2015 |
|
|
2016 |
|
|
2015 |
|
||||
|
Daily production volumes by product - |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil (MBbls) |
|
|
2,457 |
|
|
|
4,022 |
|
|
|
3,254 |
|
|
|
4,218 |
|
|
NGLs (MBbls) |
|
|
984 |
|
|
|
1,566 |
|
|
|
1,166 |
|
|
|
876 |
|
|
Natural gas (MMcf) |
|
|
6,717 |
|
|
|
13,484 |
|
|
|
8,872 |
|
|
|
7,887 |
|
|
Total barrels of oil equivalent (Boe/d) |
|
|
4,560 |
|
|
|
7,835 |
|
|
|
5,899 |
|
|
|
6,408 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Daily production volumes by region (Boe/d) - |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Eagle Ford Shale |
|
|
4,556 |
|
|
|
7,235 |
|
|
|
5,495 |
|
|
|
5,744 |
|
|
Conventional |
|
|
4 |
|
|
|
600 |
|
|
|
404 |
|
|
|
664 |
|
|
Total barrels of oil equivalent (Boe/d) |
|
|
4,560 |
|
|
|
7,835 |
|
|
|
5,899 |
|
|
|
6,407 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average realized prices - |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil ($ per Bbl) |
|
$ |
46.67 |
|
|
$ |
38.73 |
|
|
$ |
39.43 |
|
|
$ |
45.95 |
|
|
NGLs ($ per Bbl) |
|
|
12.89 |
|
|
|
7.39 |
|
|
|
9.03 |
|
|
|
6.03 |
|
|
Natural gas ($ per Mcf) |
|
|
2.80 |
|
|
|
1.72 |
|
|
|
2.21 |
|
|
|
2.37 |
|
|
Total Oil Equivalent, excluding the effect from hedging |
|
$ |
32.06 |
|
|
$ |
24.33 |
|
|
$ |
26.85 |
|
|
$ |
33.98 |
|
|
Total Oil Equivalent, including the effect from hedging |
|
$ |
43.73 |
|
|
$ |
37.33 |
|
|
$ |
39.68 |
|
|
$ |
49.52 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Expenses per BOE: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating and gas gathering |
|
$ |
8.37 |
|
|
$ |
6.28 |
|
|
$ |
7.52 |
|
|
$ |
7.35 |
|
|
Production, ad valorem, and severance taxes |
|
|
0.57 |
|
|
|
1.08 |
|
|
|
1.52 |
|
|
|
2.13 |
|
|
General and administrative |
|
|
6.72 |
|
|
|
5.17 |
|
|
|
5.24 |
|
|
|
4.62 |
|