Item 1. Business.
Overview
We are an independent oil and natural gas company, focused on the acquisition, development and production of unconventional oil, NGLs and natural gas properties in the Eagle Ford Shale in Texas (collectively with other conventional production on Eagle Ford acreage, the “Eagle Ford”), where we have accumulated approximately 78,197 gross (58,262 net) acres in what we believe to be the formation’s crude oil and condensate windows as of December 31, 2017. We operate in one industry segment, which is the exploration, development and production of oil, NGLs and natural gas. Our current operational activities and consolidated revenues are generated from markets exclusively in the United States, and, as of December 31, 2017, we had no long-lived assets located outside the United States.
Our primary operational focus is on our Eagle Ford position in eleven Texas counties, and our properties in the Eagle Ford are divided into three distinct regions: Western Eagle Ford (comprised of Dimmit, La Salle and Frio Counties), Central Eagle Ford (comprised of Gonzales, Karnes, Fayette, Wilson, DeWitt and Lavaca Counties) and Eastern Eagle Ford (comprised of Brazos and Robertson Counties). As of December 31, 2017, we operated 81% of our Eagle Ford position and approximately 89% of our acreage was held by production, or HBP. Third-party engineers have identified 254 gross (187 net) horizontal drilling locations on our Eagle Ford acreage.
We currently plan to invest the majority of our 2018 capital budget in the horizontal development of our Eagle Ford properties and have allocated between $95 million and $100 million to drilling and completion activities to develop these assets. We have historically grown our Eagle Ford leasehold position through organic leasing activities, farm-ins, acquisitions, and other structures. We believe our management team’s extensive experience and our reputation as an operator in the basin provide us with relationships and contacts that could serve as a platform for expanded opportunities to grow our acreage footprint.
We seek to deploy advanced drilling, completion and production techniques across our unconventional acreage with a goal of minimizing completed well costs and maximizing per-well hydrocarbon recoveries. Increasingly, we utilize 3-D seismic imaging to plan our lateral programs while utilizing log-based petrophysical analysis to optimize our drilling targets within distinct horizons within the Eagle Ford section. We are also frequently drilling laterals in excess of 7,000 feet in an effort to maximize per-well recoveries and economic returns. Further, we are utilizing thru-bit logging in our laterals to design non-geometric completions which allow for the use of diverters while increasing proppant concentrations in an effort to make our fracture stimulations more effective. Additionally, we employ active choke management to optimize pressure drawdowns in an effort to maximize liquid hydrocarbon recoveries.
The following table presents summary data for each of our primary project areas as of December 31, 2017:
(1)
Potential drilling locations are identified based on analysis of relevant geologic and engineering data. Our total identified drilling locations include 170 gross (141 net) locations that were associated with proved undeveloped reserves, or PUDs, as of December 31, 2017. The remaining drilling locations were not associated with proved reserves as of December 31, 2017, however, based on our analysis of our drilling results, the drilling results of offset operators and applicable geologic and engineering data, we believe these locations are prospective for development.
(2)
The drilling locations on which we actually drill will depend on the availability of capital, regulatory approval, commodity prices, costs, actual drilling results and other factors. Any drilling activities we are able to conduct on these identified locations may not be successful and may not result in our adding additional proved reserves to our existing reserves. See “Risk Factors”. In addition, we may not be able to raise the substantial amount of capital that would be necessary to drill such locations.
(3)
Planned Wells (Net) represents our optimal planned drilling results based on our currently budgeted capital expenditures.
The following table presents the number of productive oil and gas wells attributable to the Company’s project areas as of December 31, 2017:
Our Eagle Ford Shale Properties
Our Eagle Ford area net production for the year ended December 31, 2017 was 6,495 Boe/d, comprised of 4,328 Bbls/d of oil, 1,069 Bbls/d of NGLs and 6,588 Mcf/d of natural gas, from 238 gross (184.7 net) producing wells.
In June 2017, we significantly expanded our operations in the Central Eagle Ford Shale by acquiring oil and gas properties in Karnes, Gonzales, DeWitt, Lavaca and Fayette Counties, Texas in two separate transactions for $116.6 million. The acquisitions included approximately 30,219 gross acres (21,238 net acres) and 1,763 Boe/d of production from acquisition date to December 31, 2017. At the time we completed the acquisitions, our net acreage increased by 59% to approximately 57,172 net acres.
As of December 31, 2017, according to our reserve report, our Eagle Ford properties had proved reserves of 73.6 MMBoe, of which 84% was crude oil and NGLs and 25% was proved developed producing, or PDP. The Standard Measure of our Eagle Ford proved reserves as of December 31, 2017 was $479.6 million, and the PV-10(1) of our Eagle Ford proved reserves as of December 31, 2017 was $538.3 million using SEC pricing, and 44% of such PV-10 was PDP. The PV-10 of our Eagle Ford proved reserves as of December 31, 2017 was $647.6 million using NYMEX strip pricing, and 42% of such PV-10 was PDP. See “Summary Historical Reserve and Operating Data”.
Third-party engineers have identified 254 gross (187 net) horizontal drilling locations on our acreage, of which 61% are expected to be drilled using lateral lengths of or greater than 7,000 feet and 95% are expected to be drilled using lateral lengths of, or greater than, 5,000 feet.
Western Eagle Ford. As of December 31, 2017, our Western Eagle Ford region was comprised of 16,634 gross (14,904 net) acres in Dimmit, La Salle and Frio Counties. As of December 31, 2017, we operated 100% of this acreage, and approximately 96% of this net acreage was HBP. We plan on allocating 34% of our 2018 capital budget to our Western Eagle Ford acreage.
Central Eagle Ford. Our Central Eagle Ford region, as of December 31, 2017, was comprised of 47,273 gross (33,065 net) acres in Gonzales, Karnes, Fayette and Wilson Counties. As of December 31, 2017, we operated 100% of this acreage, and approximately 95% of this net acreage was HBP. We plan on allocating 66% of our 2018 capital budget to this area.
Eastern Eagle Ford. Our Eastern Eagle Ford region, as of December 31, 2017, was comprised of 14,288 gross (10,293 net) acres in Brazos and Robertson Counties. Approximately 61% of this net acreage was HBP, and as of December 31, 2017, we operated 100% of this acreage. We do not plan on allocating any of our 2018 capital budget to our Eastern Eagle Ford acreage.
(1) PV-10 is a non-GAAP financial measure and represents the present value of estimated future cash inflows from proved crude oil and natural gas reserves, less future development and production costs, discounted at 10% per annum to reflect timing of future cash inflows using the unweighted arithmetic average of the first-day-of-the-month price for each of the preceding twelve months. PV-10 differs from the Standardized Measure because it does not include the effect of future income taxes. See “Oil and Natural Gas Data-PV-10” below for more information and a reconciliation of PV-10 to our Standardized Measure.
Non-Core Properties
We have historically maintained conventional oil and natural gas properties located in 13 counties in Texas, including long-lived reserves in the Canyon, Delaware Sand, Hackberry, Caddo, Cockfield and Jackson formations. For the year ended December 31, 2016, production from our conventional assets averaged 404 Boe/d which represented 7% of our total net reported production for the year. Consistent with our plan to divest non-core assets and reduce our outstanding indebtedness, on June 15, 2016, we sold a portion of these assets for $2.2 million. On September 26, 2016, we entered into an agreement to sell the remaining assets for $14.0 million, and this transaction closed on October 31, 2016.
Business Strategies
Our primary business objective is to increase reserves, production and cash flows at attractive rates of return on invested capital. We are focused on exploiting long-lived, unconventional oil, NGLs and natural gas reserves from the crude oil window of the Eagle Ford Shale. Key elements of our business strategy include:
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Develop our Eagle Ford leasehold positions. We intend to continue developing our acreage position to maximize the value of our resource potential and generate returns for our stockholders through continuing to utilize best-in-class drilling and completion techniques at the lowest possible costs. Through the conversion of our resource base to developed reserves, we will seek to increase our production and cash flow, thereby increasing the value of our reserves. As of December 31, 2017, we were producing from 238 gross (184.7 net) Eagle Ford wells and we intend to deploy all our capital budget for 2018 on the development of our Eagle Ford acreage.
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Pursue organic leasing, strategic acquisitions, and other structures to continue to develop and grow our production and leasehold position. We believe that we will be able to continue to identify and acquire additional acreage and producing assets in the Eagle Ford. By leveraging our longstanding relationships in this area, we intend to expand our Eagle Ford acreage. We also intend to continue to find creative ways to fund our continued development while maintaining financial discipline and seeking to maximize returns from our projects. We have successfully used farm-ins and drilling commitments as means of adding prospective Eagle Ford acreage by committing to drilling activity as opposed to deploying capital with lease acquisition costs. For example, in the past we have executed on this strategy through our Joint Development Agreement with IOG Capital L.P. (‘‘IOG’’). This agreement allowed for working interest-level participation with IOG participating on a promoted basis for funding farm-ins. This was a wellbore-only agreement that allowed us to develop acreage or hold expiring acreage while maintaining some upside through a specified return hurdle earn-in and all of the upside associated with future development of offsetting wells.
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Leverage our extensive operational expertise and concentration of our operating areas to reduce costs and enhance returns. We are focused on continuously improving our operating measures. We intend to leverage the magnitude and concentration of our acreage within the Eagle Ford in our operating areas, as well as our experience within our areas of operation to capture economies of scale, including multiple-well pad drilling, and utilizing centralized production and fluid-handling facilities. Our management and operating team has significant industry and operating experience, and it regularly evaluates our operating measures against those of other operators in our area in order to improve our performance and identify additional opportunities to optimize our drilling and completion techniques and make informed decisions about our capital expenditure program and drilling activity.
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Maintain operational control over our drilling and completion operations. We operate 81% of the Eagle Ford wells in which we have a working interest and intend to maintain a high degree of operational control over substantially all of our producing locations. We believe that continuing to exercise a high degree of control over our acreage position will provide us with flexibility to manage our drilling program and optimize our returns and profitability.
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Maintain and enhance financial liquidity and flexibility. We intend to use cash on hand and borrowings from our revolving credit facility, combined with our cash flow from operations, to continue executing a capital expenditure program that we believe will help us achieve steady growth of production, cash flow and proved reserves. Furthermore, we intend to continue to employ a hedging strategy on our PDP production to achieve more predicable cash flow and to reduce our exposure to adverse fluctuations in oil, NGLs and natural gas prices. We regularly assess the futures markets for opportunities to enter into additional hedging contracts. Generally, we have entered into additional hedges when we believe that they are additive to our borrowing base and/or lock-in rates of return which exceed our hurdle rates. Further, we have strived to enter into unique and strategically-effective arrangements to reduce our outstanding indebtedness and improve our financial liquidity. We intend to continue to seek out such opportunities to improve our balance sheet and financial flexibility.
Our Competitive Strengths
We possess a number of competitive strengths that we believe will allow us to successfully execute our business strategies.
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Geographic focus in one of North America’s leading unconventional oil plays. We have assembled a leasehold position of approximately 58,262 net acres in the Eagle Ford as of December 31, 2017. We believe this unconventional oil and natural gas formation has one of the higher rates of return among such formations in North America. In addition to leveraging our technical expertise in our project areas, our geographically-concentrated acreage position allows us to establish economies of scale with respect to drilling, production, operating and administrative costs. Based on our drilling and production results and well-established offset operator activity in and around our project areas, we believe there are relatively low geologic risks and ample repeatable drilling opportunities across our core operating areas in the Eagle Ford where we have devoted almost all of our 2018 drilling capital budget.
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Experienced management team. Our top eight executives average 30 years of industry experience. We have assembled what we believe to be a strong technical staff of geoscientists, field operations managers and engineers with significant experience drilling horizontal wells including fracture stimulation of unconventional formations, which has resulted in reserve and production growth. In addition, our management team has extensive expertise and operational experience in the oil and natural gas industry with a proven track record of successfully negotiating, executing and integrating acquisitions. Members of our management team have previously held positions with major and large independent oil and natural gas companies.
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Demonstrated ability to increase acreage position and drive growth of oil production and reserves. We have increased our Eagle Ford net acreage by over fifteen times, from 3,710 net acres in 2011 to 58,262 net acres as of December 31, 2017. We placed 12 gross (11.3 net) and 5 gross (3.7 net) Eagle Ford wells onstream during 2017 and 2016, respectively. We had a total of 238 gross (184.7 net) producing wells in the Eagle Ford Shale, as of December 31, 2017. Our average total production for 2017 was 6,495 Boe/d, of which 100% was from the Eagle Ford. Between December 31, 2016 and December 31, 2017, our total proved reserves increased by approximately 33.1 MMBoe, from 40.5 MMBoe to 73.6 MMBoe. Our proved developed reserves increased by approximately 7.3 MMBoe, from 11.0 MMBoe to 18.3 MMBoe. Our five-year average reserve replacement ratio is approximately 778%, which we believe demonstrates our ability to grow reserves year over year. We believe the location and concentration of our project areas within the Eagle Ford provide us an opportunity to continue to increase production, lower costs and further delineate our proved reserves.
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Demonstrated ability to adapt and employ leading drilling and completion techniques. We are focused on enhancing our drilling, completion and production techniques to maximize recovery of hydrocarbons. Industry techniques, with respect to drilling and completion, have significantly evolved over the past several years, resulting in increased initial production rates and recoverable hydrocarbons per well through the implementation of longer laterals and more tightly-spaced fracture stimulation stages. We continuously evaluate industry results and methods and monitor the results of other operators to improve our operating practices, and we expect that our drilling and completion techniques will continue to improve and evolve. We have demonstrated a track record of innovation and operational improvement in the past through our partnership with Schlumberger, the Geo-Engineered Completion Alliance (“GECA”), which terminated during the first quarter of 2017. This Alliance utilized a variety of technologies intended to focus our wells in precise, optimal intervals of the Eagle Ford and utilize analysis of advanced logs run through the laterals to assist in the design of non-geometric fracture stimulation stages, which in combination with diverters, were intended to stimulate a greater percentage of the lateral on a cost-effective basis. We continue to use these technologies which can be provided by several energy service companies.
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Multi-year drilling inventory in existing and emerging resource plays. Third-party engineers have identified 254 gross (187 net) horizontal drilling locations on our Eagle Ford acreage. As of December 31, 2017, these identified drilling locations included 170 gross (141 net) locations to which we have assigned proved undeveloped reserves. We believe our acreage is prospective for additional locations and plan to continue evaluating this acreage and monitoring industry activity in order to maximize our efficiency in developing this acreage. Furthermore, we are evaluating our acreage to identify and develop additional locations across our portfolio as we evaluate down-spacing in the Eagle Ford and accessing other stratigraphic horizons that lie above and below the Eagle Ford, such as the Austin Chalk, Buda, Georgetown, Woodbine and Wilcox formations. We believe our multi-year drilling inventory and exploration portfolio will help provide near-term growth in our production and reserves and highlight the long-term resource potential across our asset base.
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Oil-weighted reserves and production. Our net proved reserves at December 31, 2017 were comprised of approximately 69% oil, and our net average daily production for the year ended December 31, 2017 and 2016 was comprised of 67% oil and 55% oil, respectively. Given the current commodity price environment and resulting disparity between oil and natural gas prices on a Boe basis, we believe our high percentage of oil reserves, compared to our overall reserve base, is a key strength.
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Low field operating expenses. Even in light of low oil prices, we expect to generate sufficient cash margins on the operation of our Eagle Ford acreage due to our low cash operating costs. For the year ended December 31, 2017, our total field operating expenses (including lease operating expenses per Boe of $7.07 and production taxes of $2.33 per Boe) totaled $9.40 per Boe in our project areas.
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Hedging position. As of December 31, 2017, we had in place hedges covering approximately 4,695 Bbls/d for 2018 at an average price of approximately $52.64 per Bbl. This includes a two-way collar with an effective floor and ceiling of $50.00 and $59.45, respectively. We believe that these hedges help insulate us from oil price volatility on approximately 70% of our expected crude oil production in 2018. In addition, we have in place additional hedges for 2019 and 2020. Our 2019 hedges cover approximately 4,030 Bbls/d for calendar year 2019 at a volume-weighted average of approximately $49.64 per Bbl. Our 2020 derivative contracts consist of 1,119 Bbls/d through June at a price of $48.90 per Bbl. Additionally, we have also entered into contracts to hedge our 2018 natural gas production, covering 5,000 MMBtu/d at a weighted average price of $3.09 per MMBtu.
In January 2018, we entered into additional WTI swaps covering 2018, 2019, and 2020. The 2018 WTI swaps cover a total of 230,700 barrels for the period of March 2018 through December 2018 at an average strike price of $61.77. The addition of these swaps increased our total 2018 crude oil hedge position coverage to a total of approximately 5,326 Bbls/d at an average strike price of $53.72 per barrel. The 2019 WTI swaps cover a total of 328,500 barrels for the period of January 2019 through December 2019 at an average strike price of $58.25. These additional 2019 swaps increased our total 2019 crude oil hedge position coverage to a total of approximately 4,930 Bbls/d at an average strike price of $51.21. The 2020 WTI swaps cover a total of 411,200 barrels for the period of January 2020 through December 2020 at an average strike price of $55.06. These additional 2020 swaps increased our total 2020 crude oil hedge position coverage to a total of approximately 1,680 Bbls/d at an average strike price of $53.02.
Oil and Natural Gas Data
Estimated Proved Reserves
The following table presents estimated net proved oil, NGLs and natural gas reserves attributable to our properties and the Standardized Measure amounts associated with the estimated proved reserves attributable to our properties as of December 31, 2017 and 2016. We employ a technical staff of engineers and geoscientists that perform technical analysis of each producing well and undeveloped location. The staff uses industry-accepted practices to estimate, with reasonable certainty, the economically producible oil and gas reserves. The practices for estimating hydrocarbons-in-place include, but are not limited to, mapping, seismic interpretation, core analysis, log analysis, mechanical properties of formations, thermal maturity, well testing and flowing bottom-hole pressure analysis. We employ an independent petroleum engineer to estimate 100% of our proved reserves. The data below is based on our reserve report prepared by W.D. Von Gonten & Co. The Standardized Measure and PV-10 amounts shown in the table are not intended to represent the current market value of our estimated oil and natural gas reserves.
(1)
Our estimated net proved reserves and related Standardized Measure were determined using index prices for crude oil and natural gas, without giving effect to commodity derivative contracts, held constant throughout the life of our properties. The prices are based on the average prices during the 12-month period prior to the ending date of the period covered, determined as the unweighted arithmetic average of the prices in effect on the first day of the month for each month within such period, unless prices were defined by contractual arrangements, and are adjusted, by lease, for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price realized at the wellhead. NGL pricing used as approximately 30% of corresponding crude oil prices.
(2)
One Boe is equal to six Mcf of natural gas or one Bbl of oil or NGLs based on an industry-standard approximate energy equivalency. This is a physical correlation and does not reflect a value or price relationship between the commodities.
(3)
Standardized Measure is calculated in accordance with Accounting Standards Codification (“ASC”) Topic 932, Extractive Activities - Oil and Gas.
(4)
PV-10 is a non-GAAP financial measure and represents the present value of estimated future cash inflows from proved crude oil and natural gas reserves, less future development and production costs, discounted at 10% per annum to reflect timing of future cash inflows and using the unweighted arithmetic average of the first-day-of-the-month price for each of the preceding twelve months. PV-10 differs from the Standardized Measure because it does not include the effect of future income taxes. See below for a reconciliation of Standardized Measure to our PV-10.
The data in the table above represent estimates only. Oil, NGLs and natural gas reserve engineering is inherently a subjective process of estimating underground accumulations of oil, NGLs and natural gas that cannot be measured exactly. The accuracy of any reserve estimate is a function of the quality of available data and engineering and geological interpretation and judgment. Accordingly, reserve estimates may vary from the quantities of oil, NGLs and natural gas that are ultimately recovered.
Future prices realized for production and costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates. The Standardized Measure amounts shown above should not be construed as the current market value of our estimated oil, NGLs and natural gas reserves. The 10% discount factor used to calculate Standardized Measure, which is required by Financial Accounting Standards Board pronouncements, is not necessarily the most appropriate discount rate. The present value, no matter what discount rate is used, is materially affected by assumptions as to timing of future production, which may prove to be inaccurate.
PV-10
Certain of our oil and natural gas reserve disclosures included in this Annual Report on Form 10-K are presented on a PV-10 basis. PV-10 is the estimated present value of the future cash flows, less future development and production costs from our proved reserves before income taxes, discounted using a 10% discount rate. PV-10 is considered a non-GAAP financial measure because it does not include the effects of future income taxes, as is required in computing the Standardized Measure. We believe that the presentation of a pre-tax PV-10 value provides relevant and useful information because it is widely used by investors and analysts as a basis for comparing the relative size and value of our proved reserves to other oil and gas companies. Because many factors that are unique to each individual company may impact the amount and timing of future income taxes, the use of a pre-tax PV-10 value provides greater comparability when evaluating oil and gas companies. The PV-10 value is not a measure of financial or operating performance under U.S. GAAP, nor is it intended to represent the current market value of proved oil and gas reserves. The definition of PV-10 value, as defined above, may differ significantly from the definitions used by other companies to compute similar measures. As a result, the PV-10 value, as defined, may not be comparable to similar measures provided by other companies.
The following table provides a reconciliation of the Standardized Measure to PV-10:
Reconciliation of Proved Reserves
Our proved developed oil and natural gas reserves increased from 11.0 MMBoe at December 31, 2016, to 18.3 MMBoe at December 31, 2017, primarily due to production additions associated with the $116.6 million acquisitions of producing properties that closed June 15, 2017, which added an additional 81 gross (75.2 net) wells. During the year, we converted 2.0 MMBoe of Proved Undeveloped reserves to the Proved Developed Producing category and added 1.0 MMBoe through drilling on new properties, while producing 2.4 MMBoe during the year ended December 31, 2017. Our proved developed oil and natural gas reserves experienced revisions of 0.1 MMBoe due to the increase in SEC pricing.
Development of Proved Undeveloped Reserves
At December 31, 2017, our proved undeveloped reserves were approximately 55,213 MBoe, an increase of approximately 25,671 MBoe over our December 31, 2016 estimated proved undeveloped reserves of approximately 29,542 MBoe. In 2017, we added net proved undeveloped of 3,046 MBoe as a result of drilling and completion activities and 23,210 MBoe as a result of the acquisition of proved undeveloped reserves. During 2017, approximately 1,981 MBoe of proved undeveloped reserves, as of December 31, 2016, were converted to proved developed reserves as a result of drilling and completion activities during the year, and 1,396 MBoe of reserves were added to our proved undeveloped reserves as a result of revisions in estimates from 2016. Revisions of previous estimates were added primarily due the increase in SEC pricing.
All PUD drilling locations are scheduled to be drilled prior to the end of 2022. Over half of our current PUD locations were acquired or developed during 2017, and approximately half of the future development costs associated with our PUDs are anticipated to be incurred the last two years of our five-year development plan. The timing of our development schedule correlates with the projected increase in our production and the anticipated resulting free cash flow over the next five years.
Qualifications of Responsible Technical Persons
Internal Company Person. Thomas H. Olle, our Vice President-Reservoir Engineering, is the technical person primarily responsible for overseeing the preparation of our reserve estimates. Mr. Olle is also responsible for our interactions with and oversight of our independent third-party reserve engineers. Mr. Olle has more than 40 years of industry experience, with expertise in reservoir management and project development across a broad range of reservoir types. Mr. Olle previously held senior positions at Encore Acquisition Corp. and Burlington Resources. He holds a Bachelor of Science degree in Mechanical Engineering with Highest Honors from the University of Texas at Austin and is a member of the Society of Petroleum Engineers.
Independent Reserve Engineers. W.D. Von Gonten & Co. is an independent petroleum engineering and geological services firm. No director, officer or key employee of W.D. Von Gonten & Co. has any financial ownership in Lonestar. W.D. Von Gonten & Co.’s compensation for the required investigations and preparation of its report is not contingent upon the results obtained and reported, and W.D. Von Gonten & Co. has not performed other work for us or our affiliates that would affect its objectivity. The engineering information presented in W.D. Von Gonten & Co.’s reports was overseen by William D. Von Gonten, Jr., P.E. Mr. Von Gonten is an experienced reservoir engineer having been a practicing petroleum engineer since 1990. He has a Bachelor of Science degree in Petroleum Engineering from Texas A&M University and is a licensed Professional Engineer in the State of Texas.
Technology Used To Establish Proved Reserves
Our independent reserve engineers follow SEC rules and definitions in preparing their reserve estimates. Under SEC rules, proved reserves are those quantities of oil and natural gas that by analysis of geological, geochemical and engineering data can be estimated with reasonable certainty to be economically producible from a given date forward from known reservoirs, and under existing economic conditions, operating methods and government regulations. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil and natural gas actually recovered will equal or exceed the estimate. Reasonable certainty can be established using techniques that have been proven effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.
To establish reasonable certainty with respect to our estimated proved reserves, our independent reserve engineers employed technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used in the estimation of our reserves include electrical logs, radioactivity logs, core analyses, geologic maps and available downhole and production data, seismic data and well-test data. Reserves attributable to producing wells with sufficient production history were estimated using appropriate decline curves or other performance relationships. Reserves attributable to producing wells with limited production history and undeveloped locations were estimated using performance from analogous wells in the surrounding area and geologic data to assess the reservoir continuity. These wells were considered to be analogous based on production performance from the same formation and completion using similar techniques.
Internal Controls Over Reserves Estimation Process
Our estimated reserves at December 31, 2017 and 2016 for the Eagle Ford properties were prepared by W.D. Von Gonten & Co., independent reserve engineers. We expect to continue to have our reserve estimates prepared annually by our independent reserve engineers. Our internal professional staff works closely with W.D. Von Gonten & Co. to ensure the integrity, accuracy and timeliness of data that is furnished to them for their reserve estimation process. All of the production, expense and well-ownership information, maintained in our reserve engineering database, is provided to our independent engineers. In addition, we provide such engineers other pertinent data, such as seismic information, geologic maps, well logs, production tests, material balance calculations, well performance data, operating procedures, pricing differentials and relevant economic criteria, including lease operating statements. We make all requested information, as well as our pertinent personnel, available to our independent engineers in connection with their evaluation of our reserves. Year-end reserve estimates are reviewed by our Vice President-Reservoir Engineering, our Chief Executive Officer and other senior management, and revisions are communicated to our board of directors.
Oil and Natural Gas Production Prices and Costs
Production, Revenues and Price History
The following table sets forth information regarding net production of oil, NGLs and natural gas and certain price and cost information attributable to our properties, for the years ended December 31, 2017 and 2016.
Drilling Activity
The following table sets forth our operated and non-operated drilling activity for the years ended December 31, 2017 and 2016. In the table, “gross” refers to the total wells in which we have a working interest and “net” refers to gross wells multiplied by our working interest therein.
As of December 31, 2017, we were in process of drilling 2 gross (2.0 net) wells that are not included in the table above.
Acreage Data
The following table sets forth information relating to our leasehold acreage in the Eagle Ford. As of December 31, 2017, approximately 89% of our net Eagle Ford acreage was held by production.
As of December 31, 2017, we had leases across the Eagle Ford representing 1,476 net acres expiring in 2018, 803 net acres expiring in 2019, and 841 net acres expiring in 2020 and beyond. We anticipate that our current and future drilling plans, together with selected lease extensions, will address a significant portion of our leases expiring in the Eagle Ford in 2018.
Operations
General
We operate 81% of the Eagle Ford wells in which we have a working interest and intend to maintain a high degree of operational control over substantially all of our producing locations. As operator, we design and manage the development of a well and supervise operation and maintenance activities on a day-to-day basis. Independent contractors, engaged by us, provide all of the equipment and personnel associated with these activities. We employ petroleum engineers, geologists and land professionals who work to improve production rates, increase reserves and lower the cost of operating our oil and natural gas properties.
Marketing and Customers
For the year ended December 31, 2017, purchases by our largest five customers accounted for 35%, 20%, 16%, 14%, and 10%, of our total revenues.
Since the oil and natural gas that we sell are commodities for which there are a large number of potential buyers, and because of the adequacy of the infrastructure to transport oil and natural gas in the areas in which we operate, if we were to lose one or more customers, we believe that we could readily procure substitute or additional customers such that our production volumes would not be materially affected for any significant period of time.
Transportation
During the initial development of our fields, we consider all gathering and delivery infrastructure options in the area of our production. Our oil is transported from the wellhead to our tank batteries by our gathering systems. The oil is then transported by the purchaser by truck to a tank farm or by pipeline. Our natural gas is generally transported from the wellhead to the purchaser’s pipeline interconnection point through our gathering system.
Competition
We operate in a highly competitive environment for leasing and acquiring properties and in securing trained personnel. Our competitors include major and independent oil and natural gas companies that operate in our project areas. These competitors include, but are not limited to, Anadarko Petroleum Corporation, Chesapeake Energy Corporation, EP Energy Corporation, Carrizo Oil & Gas, Inc., Hunt Oil Company, Marathon Oil Corporation, Newfield Exploration Company and Stonegate Production Company. Many of our competitors have substantially greater financial, technical and personnel resources than we do, which can be particularly important in the areas in which we operate. As a result, our competitors may be able to pay more for productive crude oil and natural gas properties and exploratory prospects, as well as evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. Our ability to acquire additional properties and to find and develop reserves will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, there is substantial competition for capital available for investment in the oil and natural gas industry. We are also affected by the competition for and the availability of equipment, including drilling rigs and completion equipment. We are unable to predict when, or if, shortages of such equipment may occur or how they would affect our development and exploitation programs.
Seasonality of Business
Generally, but not always, the demand for natural gas decreases during the summer months and increases during the winter months, resulting in seasonal fluctuations in the price we receive for our natural gas production. Seasonal anomalies such as mild winters or hot summers sometimes lessen this fluctuation.
Title to Properties
Prior to completing an acquisition of producing oil and natural gas properties, we perform title reviews on significant leases, and depending on the materiality of properties, we may obtain an additional title opinion or conduct a review to ensure all title is current relative to previously obtained title opinions. As a result, title examinations have been obtained on a significant portion of our properties. After an acquisition, we review the assignments from the seller for scrivener’s and other errors and execute and record corrective assignments as necessary.
We typically conduct title review of all acquired properties, regardless of whether they have proved reserves. Prior to the commencement of drilling operations on any property, we update our title examination and perform curative work with respect to significant defects or customary assignments, if any. To the extent title opinions or other investigations reflect title defects on those properties, we are typically responsible for curing any title defects at our expense. We generally will not commence drilling operations on a property until we have cured any material title defects on such property.
We believe that we have satisfactory title to all of our material assets. Although title to these properties is subject to encumbrances in some cases, such as customary interests generally retained in connection with the acquisition of real property, customary royalty interests and contract terms and restrictions, liens under operating agreements, liens related to environmental liabilities associated with historical operations, liens for current taxes and other burdens, easements, restrictions and minor encumbrances customary in the oil and natural gas industry, we believe that none of these liens, restrictions, easements, burdens and encumbrances will materially detract from the value of these properties or from our interest in these properties or materially interfere with our use of these properties in the operation of our business. In addition, we believe that we have obtained sufficient rights-of-way grants and permits from public authorities and private parties for us to operate our business in all material respects.
Oil and Natural Gas Leases
The typical oil and natural gas lease agreement covering our properties provides for the payment of royalties to the mineral owner for all oil and natural gas produced from any well drilled on the leased premises. The lessor royalties and other leasehold burdens on our properties predominately range from 19.0% to 25.0% resulting in a net revenue interest to us ranging from 75.0% to 81.0%.
Regulation of the Oil and Natural Gas Industry
Our operations are substantially affected by federal, state and local laws and regulations. In particular, crude oil and natural gas production and related operations are, or have been, subject to price controls, taxes and numerous other laws and regulations. All of the jurisdictions in which we own or operate properties for crude oil and natural gas production have statutory provisions regulating the exploration for and production of crude oil and natural gas, including provisions related to permits for the drilling of wells, bonding requirements to drill or operate wells, the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, sourcing and disposal of water used in the drilling and completion process, and the abandonment of wells. Our operations are also subject to various conservation laws and regulations. These include regulation of the size of drilling and spacing units or proration units, the number of wells that may be drilled in an area, and the unitization or pooling of crude oil and natural gas wells, as well as regulations that generally prohibit the venting or flaring of natural gas and that impose certain requirements regarding the rateability or fair apportionment of production from fields and individual wells.
The regulatory burden on the industry increases the cost of doing business and affects profitability. Failure to comply with applicable laws and regulations can result in substantial penalties. Furthermore, such laws and regulations are frequently amended or reinterpreted, and new proposals that affect the crude oil and natural gas industry are regularly considered by Congress, the states, the Federal Energy Regulatory Commission (“FERC”) and the courts. We believe that we are in substantial compliance with all applicable laws and regulations and that our continued substantial compliance with existing requirements will not have a material adverse effect on our financial position, cash flows or results of operations. Nor are we currently aware of any specific pending legislation or regulation that is reasonably likely to be enacted, or for which we cannot predict the likelihood of enactment, and that is reasonably likely to have a material effect on our financial position, cash flows or results of operations.
Regulation of Sales and Transportation of Oil
Our sales of oil are affected by the availability, terms and cost of transportation. Interstate transportation of oil by pipeline is regulated by FERC pursuant to the Interstate Commerce Act of 1887 (“ICA”), the Energy Policy Act of 1992 (“EPAct”), and the rules and regulations promulgated under those laws. The ICA and its implementing regulations require that tariff rates for interstate service on oil pipelines, including interstate pipelines that transport oil and refined products (collectively referred to as “petroleum pipelines”), be just and reasonable and non-discriminatory and that such rates and terms and conditions of service be filed with FERC. EPAct deemed certain interstate petroleum pipeline rates then in effect to be just and reasonable under the ICA, which are commonly referred to as “grandfathered rates.” Pursuant to EPAct, FERC also adopted a generally applicable rate-making methodology, which, as currently in effect, allows petroleum pipelines to change their rates provided they do not exceed prescribed ceiling levels that are tied to changes in the Producer Price Index for Finished Goods (“PPI”), plus 1.3%. For the five-year period beginning July 1, 2016, the index will be PPI plus 1.23%.
FERC has also established cost-of-service rate-making, market- based rates and settlement rates as alternatives to the indexing approach. A pipeline may file rates based on its cost of service if there is a substantial divergence between its actual costs of providing service and the rate resulting from application of the index. A pipeline may charge market-based rates if it establishes that it lacks significant market power in the affected markets. Further, a pipeline may establish rates through settlement with all current non-affiliated shippers.
Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates vary from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any way that is of material difference from those of our competitors that are similarly situated.
Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all similarly situated shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by prorationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our similarly situated competitors.
Regulation of Transportation and Sales of Natural Gas
Historically, the transportation and sale for resale of natural gas in interstate commerce has been regulated by FERC under the Natural Gas Act of 1938 (“NGA”), the Natural Gas Policy Act of 1978 (“NGPA”) and regulations issued under those statutes. In the past, the federal government has regulated the prices at which natural gas could be sold. While sales by producers of natural gas can currently be made at market prices, Congress could re-enact price controls in the future. Deregulation of wellhead natural gas sales began with the enactment of the NGPA and culminated in the adoption of the Natural Gas Wellhead Decontrol Act, which removed all price controls affecting wellhead sales of natural gas effective January 1, 1993.
FERC regulates interstate natural gas, transportation rates and terms and conditions of service, which affect the marketing of natural gas that we produce as well as the revenues we receive for sales of our natural gas. Since 1985, FERC has endeavored to make natural gas transportation more accessible to natural gas buyers and sellers on an open and non-discriminatory basis. FERC has stated that open access policies are necessary to improve the competitive structure of the interstate natural gas pipeline industry and to create a regulatory framework that will put natural gas sellers into more direct contractual relations with natural gas buyers by, among other things, unbundling the sale of natural gas from the sale of transportation and storage services. Beginning in 1992, FERC issued a series of orders, beginning with Order No. 636, to implement its open access policies. As a result, the interstate pipelines’ traditional role of providing the sale and transportation of natural gas as a single service has been eliminated and replaced by a structure under which pipelines provide transportation and storage service on an open access basis to others that buy and sell natural gas. Although FERC’s orders do not directly regulate natural gas producers, they are intended to foster increased competition within all phases of the natural gas industry.
In 2000, FERC issued Order No. 637 and subsequent orders, which imposed a number of additional reforms designed to enhance competition in natural gas markets. Among other things, Order No. 637 revised FERC’s pricing policy by waiving price ceilings for short-term released capacity for a two-year experimental period and effected changes in FERC regulations relating to scheduling procedures, capacity segmentation, penalties, rights of first refusal and information reporting.
Gathering services, which occur upstream of jurisdictional transmission services, are regulated by the states onshore and in state waters. Although FERC has set forth a general test for determining whether facilities perform a non-jurisdictional gathering function or a jurisdictional transmission function, FERC’s determinations as to the classification of facilities is done on a case-by-case basis. To the extent that FERC issues an order that reclassifies transmission facilities as gathering facilities and, depending on the scope of that decision, our costs of getting gas to point of sale locations may increase. State regulation of natural gas gathering facilities generally includes various safety, environmental and, in some circumstances, non-discriminatory take requirements. Although such regulation has not generally been affirmatively applied by state agencies, natural gas gathering may receive greater regulatory scrutiny in the future.
Intrastate natural gas transportation and facilities are also subject to regulation by state regulatory agencies, and certain transportation services provided by intrastate pipelines are also regulated by FERC. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services vary from state to state. Insofar as such regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable basis, we believe that the regulation of similarly situated intrastate natural gas transportation in any states in which we operate and ship natural gas on an intrastate basis will not affect our operations in any way that is of material difference from those of our competitors. Like the regulation of interstate transportation rates, the regulation of intrastate transportation rates affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas.
Regulation of Environmental and Occupational Safety and Health Matters
Our exploration, development, production and processing operations are subject to various federal, state and local laws and regulations relating to health and safety, the discharge of materials and environmental protection. These laws and regulations may, among other things: require the acquisition of permits to conduct exploration, drilling and production operations; govern the amounts and types of substances that may be released into the environment in connection with oil and natural gas drilling and production; restrict the way we handle or dispose of our wastes; limit or prohibit construction or drilling activities in sensitive areas, such as wetlands, wilderness areas, or areas inhabited by endangered or threatened species; require investigatory and remedial actions to
mitigate pollution conditions caused by our operations or attributable to former operations; and impose obligations to reclaim and abandon well sites and pits. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations and the issuance of orders enjoining some or all of our operations in affected areas.
These laws and regulations may also restrict the rate of crude oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the crude oil and gas industry increases the cost of doing business in the industry and consequently affects profitability. In addition, Congress and federal and state agencies frequently revise environmental, health and safety laws and regulations, and any changes that result in more stringent and costly emissions control, waste handling, disposal, clean-up and remediation requirements for the crude oil and gas industry could have a significant impact on our operating costs.
The clear trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, and thus, any changes in environmental laws and regulations or re-interpretations of enforcement policies that result in more stringent and costly waste handling, storage, transport, disposal, or remediation requirements could have a material adverse effect on our operations and financial position in the future. We may be unable to pass on such increased compliance costs to our customers. Moreover, accidental releases or spills may occur in the course of our operations, and we cannot assure you that we will not incur significant costs and liabilities as a result of such releases or spills, including any third party claims for damage to property, natural resources or persons. We maintain insurance against costs of clean-up operations, but we are not fully insured against all such risks. While we believe that we are in substantial compliance with existing environmental laws and regulations and that current requirements would not have a material adverse effect on our financial condition or results of operations, there is no assurance that this will continue in the future.
The following is a summary of the more significant existing environmental, health and safety laws and regulations to which our business operations are subject and for which compliance in the future may have a material adverse effect on our capital expenditures, results of operations or financial position.
Hazardous Substances and Waste Handling
The federal Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), also known as the Superfund law, and comparable state laws impose liability without regard to fault or the legality of the original conduct on certain classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. CERCLA exempts “petroleum, including oil or any fraction thereof” from the definition of “hazardous substance” unless specifically listed or designated under CERCLA. While the EPA interprets CERCLA to exclude oil and fractions of oil, hazardous substances that are added to petroleum or that increase in concentration as a result of contamination of the petroleum during use are not considered part of the petroleum and are regulated under CERCLA as a hazardous substance.
Responsible persons under CERCLA include current and prior owners or operators of the site where the release occurred and entities that disposed or arranged for the disposal of the hazardous substances found at the site. Under CERCLA, these “responsible persons” may be subject to strict, joint and several liabilities for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources, and for the costs of certain health studies. CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances or other pollutants into the environment. We generate materials in the course of our operations that may be regulated as hazardous substances.
We also generate solid and hazardous wastes that are subject to the requirements of the Resource Conservation and Recovery Act, as amended (“RCRA”), and comparable state statutes. The RCRA imposes requirements on the generation, storage, treatment, transportation and disposal of hazardous wastes. In the course of our operations we generate petroleum hydrocarbon wastes and ordinary industrial wastes that may be regulated as hazardous wastes. The RCRA regulations specifically exclude from the definition of hazardous waste drilling fluids, produced waters and other wastes associated with the exploration, development or production of oil, natural gas or geothermal energy. Following the filing of a lawsuit in the U.S. District Court for the District of Columbia in May 2016 by several non-governmental environmental groups against the EPA for the agency’s failure to timely assess its RCRA Subtitle D criteria regulations for oil and gas wastes, the EPA and the environmental groups entered into an agreement that was finalized in a consent decree issued by the District Court on December 28, 2016. Under the decree, the EPA is required to propose no later than March 15, 2019, a rulemaking for revision of certain Subtitle D criteria regulations pertaining to oil and gas wastes or sign a determination that revision of the regulations is not necessary. If the EPA proposes a rulemaking for revised oil and as waste regulations, the Consent Decree requires that the EPA take final action following notice and comment rulemaking no later than July 15, 2021. A loss of the RCRA exclusion for drilling fluids, produced waters and related wastes could result in an increase in our costs and drilling operations to manage and dispose of generated wastes and a corresponding decrease in their drilling operations, which developments could have a material adverse effect on our business. In addition, Legislation has been proposed in Congress from time to time that would reclassify certain natural gas and oil exploration and production wastes as “hazardous wastes,” which would make the reclassified wastes subject to much more stringent handling, disposal and cleanup requirements. No such effort has been successful to date.
We currently own or lease, and have in the past owned or leased, properties that have been used for numerous years to explore and produce crude oil and natural gas. Although we have utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons and wastes may have been disposed of or released on or under the properties owned or leased by us or on or under the other locations where these hydrocarbons and wastes have been taken for treatment or disposal. In addition, certain of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons and wastes was not under our control. These properties and wastes disposed thereon may be subject to CERCLA, RCRA and analogous state laws. Under these laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property (including groundwater contaminated by prior owners or operators) and to perform remedial operations to prevent future contamination.
Water Discharges
The Federal Water Pollution Control Act, as amended, or the Clean Water Act (“CWA”), and analogous state laws impose restrictions and controls regarding the discharge of pollutants into waters of the United States. Pursuant to the CWA and analogous state laws, permits must be obtained to discharge pollutants into state waters or waters of the United States. Any such discharge of pollutants into regulated waters must be performed in accordance with the terms of the permits issued by the EPA or analogous state agencies. The CWA and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including jurisdictional wetlands, unless authorized by an appropriately issued permit. Spill prevention, control and countermeasure requirements under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. In addition, the CWA and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. Currently, storm water discharges from crude oil and natural gas exploration, production, processing or treatment operations, or transmission facilities are exempt from regulation under the CWA.
In May 2015, the EPA issued final rules attempting to clarify the federal jurisdictional reach over waters of the United States but this rule was stayed nationwide by the U.S. Sixth Circuit Court of Appeals as that appellate court and several other district courts ponder lawsuits opposing implementation of the rule. In January 2017, the U.S. Supreme Court accepted review of the rule to determine whether jurisdiction rests with the federal district or appellate courts. On March 6, 2017, the U.S. Department of Justice filed a motion with the U.S. Supreme Court requesting the Court to stay the suit regarding which courts should hear challenges to this rule. In November 2017, the EPA and the Army Corps of Engineers issued a notice to rescind the Clean Water Rule and re-codify the regulatory text that existed prior to 2015 defining “water of the United States.” On January 22, 2018, the U.S. Supreme Court unanimously held that challenges to the 2015 rules could only be raised in federal district courts and remanded and the case back to U.S. District Courts. The EPA and the Army Corps of Engineers then issued a stay of the rule’s effective date until February 6, 2020 and the U.S. District Court for North Dakota, covering 13 states, issued a stay that remains in effect. Litigation is ongoing challenging the actions of the EPA and the Army Corps of Engineers and at this time, it is unclear what impact these actions will have on the implementation of the 2015 rule. Federal and state regulatory agencies can impose administrative, civil and criminal penalties, as well as other enforcement mechanisms for noncompliance with discharge permits or other requirements of the CWA and analogous state laws and regulations.
Air Emissions
The Clean Air Act, as amended (“CAA”), and comparable state laws and regulations restrict the emission of air pollutants from many sources, including oil and natural gas operations, and impose various monitoring and reporting requirements. These laws and regulations may require us to obtain preapproval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and comply with stringent air permit requirements, or utilize specific equipment or technologies to control emissions. Obtaining permits has the potential to delay the development of oil and natural gas projects. We may be required to incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions. For example, the EPA also issued CAA regulations relevant to hydraulic fracturing in 2012, including a new source performance standard for volatile organic chemicals (“VOCs”) and sulfur dioxide (“SO2”) emissions with expanded applicability to natural gas operations, as well as a new air toxics standard. These rules create significant new technology requirements for controlling wellhead emissions from our operations. The EPA has made several changes to these rules in response to industry and environmental group legal challenges and administrative petitions, including, most recently, a decision to include a specific performance standard for methane in the rules (discussed further below). In general, there is increasing interest in and focus on regulation of methane emissions from oil and natural gas operations, and hydraulic fracturing operations in particular, under the CAA.
In June 2016, the EPA published final rules establishing new air emission controls for methane emissions from certain new, modified or reconstructed equipment and processes in the oil and natural gas source category, including production, processing, transmission and storage activities. The EPA’s final rules include the NSPS to limit methane emissions from equipment and processes across the oil and natural gas source category. The rules also extend limitations on VOC emissions to sources that were unregulated under the previous NSPS at Subpart OOOO. Affected methane and VOC sources include hydraulically fractured (or re-fractured) oil and natural gas well completions, fugitive emissions from well sites and compressors, and pneumatic pumps. Several states and industry groups have filed suit before the D.C. Circuit challenging EPA’s implementation of the methane rule and legal authority to issue the methane rules. On June 12, 2017, EPA proposed a two year stay of the fugitive emissions, pneumatic pump and professional engineer certification requirements in the methane rule while the agency reconsiders the rule. In May 2016, the EPA also announced its intention to impose methane emission standards for existing sources, and in February 2018, new standards for methane emission from oil and gas wells were proposed by the Trump Administration, currently subject to a 60-day comment period. The EPA also finalized separate rules under the CAA in June 2016 regarding criteria for aggregating multiple sites into a single source for air-quality permitting purposes applicable to the oil and gas industry. This rule could cause small facilities (such as tank batteries and compressor stations), on an aggregate basis, to be deemed a major source, thereby triggering more stringent air permitting requirements, which in turn could result in operational delays or require us to install costly pollution control equipment. In addition, in October 2015, the EPA issued a final rule under the CAA, lowering the NAAQS for ground-level ozone from the current standard of 75 ppb for the current 8-hour primary and secondary ozone standards to 70 ppb for both standards. The final rule became effective on December 28, 2015 and was challenged in courts. The D.C. Circuit struck down parts of the rule in February 2018, and a final implementation rule is expected in 2018. States are expected to implement more stringent permitting and pollution control requirements as a result of the final rule, which could apply to our operations.
We cannot predict future regulatory requirements in this area or the cost to comply with such requirements. The adoption and implementation of any regulations imposing reporting obligations on, or limiting emissions of greenhouse gases from, our equipment and operations could require us to incur costs to reduce emissions of greenhouse gases associated with our operations or could adversely affect demand for the oil and natural gas we produce. We further note that states are authorized to regulate methane emissions within their boundaries provided their requirements are not weaker than federal rules.
Regulation of GHG Emissions
Climate and related energy policy, laws and regulations could change quickly, and substantial uncertainty exists about the nature of many potential developments that could impact the sources and uses of energy. In December 2015, the United States and 194 other countries, adopted the Paris Agreement, committing to work towards limiting global warming and agreeing to a monitoring and review process of GHG emissions. This will heighten political pressure on the United States to ensure continued compliance with enforcement measures resulting from the Clean Air Act and to bring forward further actions to reduce GHGs in the period post 2030. On October 4, 2016, the E.U. ratified the Paris Agreement, thus meeting the threshold for the agreement to come into force. On June 1, 2017, President Trump announced that the United States planned to withdraw from the Paris Agreement and to seek negotiations either to reenter the Paris Agreement on different terms or establish a new framework agreement. The Paris Agreement provides for a four-year exit process beginning when it took effect in November 2016, which would result in an effective exit date of November 2020. The United States’ adherence to the exit process is uncertain and/or the terms on which the United States may reenter the Paris Agreement or a separately negotiated agreement are unclear at this time.
The EPA requires the reporting of GHGs from specified large GHG emission sources, including GHGs from petroleum and natural gas systems that emit more than 25,000 tons of GHGs per year. Reporting is required from onshore and offshore petroleum and natural gas production, natural gas processing, transmission and distribution, underground natural gas storage and liquefied natural gas import, export and storage. While new legislation requiring GHG controls is not expected at the national level in the near term, almost one-half of the states have taken actions to monitor and/or reduce emissions of GHGs, including obligations on utilities to purchase renewable energy and GHG cap and trade programs. Although most of the state level initiatives have to date focused on large sources of GHG emissions, such as coal-fired electric plants, it is possible that smaller sources of emissions could become subject to GHG emission limitations or allowance purchase requirements in the future.
Any one of these climate change regulatory and legislative initiatives could have a material adverse effect on our business, financial condition and results of operations. Legislation or regulations that may be adopted to address climate change could also affect the markets for our products by making our products more or less desirable than competing sources of energy. To the extent that our products are competing with higher GHG emitting energy sources, such as coal, our products would become more desirable in the market with more stringent limitations on GHG emissions. To the extent that our products are competing with lower GHG emitting energy sources, such as solar and wind, our products would become less desirable in the market with more stringent limitations on GHG emissions. We cannot predict with any certainty at this time how these possibilities may affect our operations.
Finally, increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods and other climatic events. If any such effects were to occur, they could adversely affect or delay demand for the oil or natural gas we produce or otherwise cause us to incur significant costs in preparing for or responding to those effects.
Hydraulic Fracturing Activities
The federal Safe Drinking Water Act (“SDWA”) and comparable state statutes may restrict the disposal, treatment or release of water produced or used during crude oil and natural gas development. Subsurface emplacement of fluids (including disposal wells) is governed by federal or state regulatory authorities that, in some cases, include the state oil and gas regulatory authority or the state’s environmental authority. We utilize hydraulic fracturing in our operations as a means of maximizing the productivity of our wells and operate saltwater disposal wells to dispose of produced water. The federal Energy Policy Act of 2005 amended the Underground Injection Control (“UIC”) provisions of the SDWA to expressly exclude hydraulic fracturing without diesel additives from the definition of “underground injection.” However, the U.S. Senate and House of Representatives have considered several bills in recent years to end this exemption, as well as other exemptions for crude oil and gas activities under U.S. environmental laws.
Federal agencies have also begun to directly regulate hydraulic fracturing. The EPA has asserted federal regulatory authority over, and issued permitting guidance for, hydraulic fracturing involving diesel additives under the SDWA’s UIC Program. As a result, service providers or companies that use diesel products in the hydraulic fracturing process are expected to be subject to additional permitting requirements or enforcement actions under the SDWA. The EPA has also issued CAA regulations relevant to hydraulic fracturing in 2012, including the NSPS for VOC and SO2 emissions with expanded applicability to natural gas operations and new national emission standards for hazardous air pollutants standards for air toxics (although the Trump Administration has indicated an intent to review this rule). Also, in June 2016, the EPA finalized rules to prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants. These regulatory developments are indicative of increasing federal regulatory activity related to hydraulic fracturing, which has the potential to create additional permitting, technology, recordkeeping and site study requirements, among others, for our business. In addition, federal agencies have started to assert regulatory authority over the process. In December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources, concluding that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources under certain circumstances. The U.S. Bureau of Land Management (the “BLM”) had developed comprehensive regulations for hydraulic fracturing on federal land in 2015 subject to extensive litigation challenges and in December 2017, the BLM filed notice that it was withdrawing the rules. The State of California and environmental groups filed a lawsuit against BLM seeking to enforce the rules and such litigation is ongoing.
State governments in the areas where we operate have adopted or are considering adopting additional requirements relating to hydraulic fracturing that could restrict its use in certain circumstances or make it more costly to utilize. Such measures may address any risk to drinking water, the potential for hydrocarbon migration and disclosure of the chemicals used in fracturing. A majority of states around the country, including Texas, have also adopted some form of fracturing fluid disclosure law to compel disclosure of fracturing fluid ingredients and additives that are not subject to trade secret protection. Other states, such as Ohio and Texas, have begun to study potential seismic risks related to underground injection of fracturing fluids. For example, on October 28, 2014, the Texas Railroad Commission, or TRC, published a new rule governing permitting or re-permitting of disposal wells that would require, among other things, the submission of information on seismic events occurring within a specified radius of the disposal well location, as well as logs, geologic cross sections and structure maps relating to the disposal area in question. If the permittee or an applicant of a disposal well permit fails to demonstrate that the saltwater or other fluids are confined to the disposal zone or if scientific data indicates such a disposal well is likely to be or determined to be contributing to seismic activity, then the TRC may deny, modify, suspend or terminate the permit application or existing operating permit for that well.
Any enforcement actions or requirements of additional studies or investigations by governmental authorities where we operate could increase our operating costs and cause delays or interruptions of our operations.
At this time, it is not possible to estimate the potential impact on our business of these state and local actions or the enactment of additional federal or state legislation or regulations affecting hydraulic fracturing.
ESA and Migratory Birds
The federal Endangered Species Act, as amended (“ESA”), restricts activities that may affect endangered and threatened species or their habitats. Pursuant to the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat. Moreover, as a result of a settlement approved by the U.S. District Court for the District of Columbia in September 2011, the U.S. Fish and Wildlife Service is required to make a determination on listing of more than 250 species as endangered or threatened under the ESA by no later than completion of the Agency’s 2017 fiscal year. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. While some of our facilities may be located in areas that are designated as habitats for endangered or threatened species, we believe that we are in substantial compliance with the ESA and the Migratory Bird Treaty Act. However, the designation of previously unidentified endangered or threatened species or habitats in areas where our operations are conducted could cause us to incur increased costs arising from species protection measures or could result in limitations on our exploration and production activities that could have an adverse impact on our ability to develop and produce reserves. If we were to have a portion of our leases designated as critical or suitable habitat, it could have a material adverse impact on the value of our leases.
National Environmental Policy Act
Our operations on federal lands are subject to the National Environmental Policy Act, or NEPA. Under NEPA, federal agencies, including the Department of the Interior must evaluate major agency actions having the potential to significantly impact the environment. This review can entail a detailed evaluation including an Environmental Impact Statement. This process can result in significant delays and may result in additional limitations and costs associated with projects on federal lands.
OSHA
We are subject to a number of federal and state laws and regulations, including the federal Occupational Safety and Health Act, as amended (the “OSH Act”), and comparable state statutes, whose purpose is to protect the health and safety of workers. In addition, the OSH Act’s hazard communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act, and comparable state statutes require that information be maintained concerning hazardous materials used, produced or released in our operations and that this information be provided to employees, state and local government authorities and citizens. In March 2016, OSHA amended its legal requirements, publishing a final rule that established a more stringent permissible exposure limit for exposure to respirable crystalline silica and provided other provisions to protect employees, such as requirements for exposure assessment, methods for controlling exposure, respiratory protection, medical surveillance, hazard communication, and recordkeeping. This final rule became effective in June 2016. However, several industry groups have filed suit in the D.C. Circuit to halt implementation of the rule. Increasing concerns about worker safety at drill sites may lead to increased regulation and enforcement or related tort claims by our employees. We believe that we are in substantial compliance with all applicable laws and regulations relating to worker health and safety.
Related Permits and Authorizations
Many environmental laws require us to obtain permits or other authorizations from state, federal and/or Tribal agencies before initiating certain drilling, construction, production, operation or other oil and natural gas activities, and to maintain these permits and compliance with their requirements for on-going operations. These permits are generally subject to protest, appeal or litigation, which can in certain cases delay or halt projects and cease production or operation of wells, pipelines and other operations.
We have not experienced any material adverse effect from compliance with environmental requirements; however, there is no assurance that this will continue. We did not have any material capital or other nonrecurring expenditures in connection with complying with environmental laws or environmental remediation matters in 2017, nor do we anticipate that such expenditures will be material in 2018.
Related Insurance
We maintain insurance against some risks associated with above or underground contamination that may occur as a result of our development activities. However, this insurance is limited to activities at the well site and there can be no assurance that this insurance will continue to be commercially available or that this insurance will be available at premium levels that justify its purchase by us. The occurrence of a significant event that is not fully insured or indemnified against could have a materially adverse effect on our financial condition and operations. Further, we have no coverage for gradual, long-term pollution events.
Employees
As of December 31, 2017, we had 50 employees, including seven engineers and geoscientists, four land professionals and ten field operating personnel. None of these employees are represented by labor unions or covered by any collective bargaining agreement. We believe that our relations with our employees are satisfactory.
We also contract for the services of independent consultants involved in land, engineering, regulatory, accounting, financial and other disciplines as needed.
Formation Transactions
Lonestar Resources US Inc. was incorporated Delaware in December 2015 for purposes of effecting our corporate reorganization, which was completed in July 5, 2016 (the “Reorganization”), pursuant to a Scheme Implementation Agreement (the “Scheme”), dated December 28, 2015, between the Company and Lonestar Resources Limited (our “Predecessor”), an Australian company and our former parent company.
Prior to the Reorganization, our business was owned and operated under our Predecessor, whose ordinary shares were listed on the Australian Securities Exchange (“ASX”). Pursuant to the Scheme, the Company acquired all of the issued and outstanding ordinary shares of our Predecessor, and each of our Predecessor’s shareholders received one share of our Class A common stock for every two ordinary shares of our Predecessor such shareholder held.
In connection with the Reorganization, we filed a registration statement on Form 10 (“Form 10”) to register our Class A common stock pursuant to Section 12(b) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). Following the effectiveness of the registration statement and in connection with the completion of the Reorganization, the ordinary shares of our Predecessor were delisted from the ASX, and our Class A common stock was listed on the Nasdaq Global Select Market (“Nasdaq”).
Recent Events
Eagle Ford Acquisitions
In June 2017, we completed two acquisitions of oil and natural gas properties in the Central Eagle Ford with Battlecat Oil & Gas, LLC (“Battlecat”) and SN Marquis LLC (“Marquis”), which included approximately 30,219 gross acres (21,238 net acres) and 1,763 Boe/d of production from acquisition date to December 31, 2017. At the time we completed the acquisitions, our net acreage increased by 59% to approximately 57,172 net acres. Consideration for the acquisitions, after closing adjustments, consisted of $99 million in cash and approximately 2.7 million shares of the Company’s newly issued Series B Preferred Stock valued at $11.6 million (see below).
Acquisition Financing Transactions
In June 2017, in connection with the acquisitions noted above, we issued 5,400 shares of Series A-1 Convertible Participating Preferred Stock (“Series A-1 Preferred Stock”) and 74,600 shares of Series A-2 Convertible Participating Preferred Stock (“Series A-2 Preferred Stock”) to Chambers Energy Capital (“Chambers”) for proceeds of $80.0 million. Also, on June 15, 2017, in connection with the acquisitions, we issued 1,184,632 and 1,500,000 shares of Series B Preferred Stock as part of the consideration paid.
Pursuant to the terms of our agreement with Chambers, we held a stockholder meeting in November 2017, and obtained at the meeting stockholder approval for issuance of shares of the Company’s Class A voting common stock for conversion of all shares of Series A-1 Preferred Stock and Series A-2 Preferred Stock (upon their conversion to shares of Series A-1 Preferred Stock). As a result of the stockholder approval, all outstanding Series A-2 Preferred Stock was converted to Series A-1 Preferred Stock. Also, in November 2017, in accordance with the terms of the Series B Preferred Stock Certificate of Designations, all of the outstanding shares of the Company’s Series B Preferred Stock were converted on a one-for-one basis into shares of the Company’s Class A voting common stock.
Issuance of 11.250% Senior Notes
In January 2018, we issued $250.0 million of 11.250% senior notes due 2023 (the “11.250% Senior Notes”) to U.S.-based institutional investors. The net proceeds of $244.4 million were used to fully retire the 8.750% Senior Notes due 2018 (the “8.750% Senior Notes”), which included principal, interest and prepayment premium totaling approximately $162.0 million. The remaining net proceeds were used to reduce borrowings under our credit facility.
Item 1A.
Item 1A. Risk Factors.
Risks Related to the Oil and Natural Gas Industry and Our Business
Oil, natural gas and NGL prices are volatile. A substantial or extended decline in the price of these commodities may adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments.
Our revenues, profitability, liquidity, ability to access capital and future growth prospects are highly dependent on the prices we receive for our oil, natural gas and NGLs. The prices of these commodities are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil, natural gas and NGLs have been volatile, and this volatility may continue in the future. The prices we receive for our production and the levels of our production depend on numerous factors beyond our control. These factors include, but are not limited to, the following:
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worldwide and regional economic and political conditions;
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the domestic and global supply of, and demand for, oil, natural gas and NGLs;
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the cost of exploring for, developing, producing and marketing oil, natural gas and NGLs;
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the proximity, capacity, cost and availability of oil, natural gas and NGL pipelines and other transportation facilities;
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the price and quantity of imports of foreign oil, natural gas and NGLs;
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the level of global oil, natural gas and NGL exploration and production;
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the level of global oil, natural gas and NGL inventories;
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weather conditions and natural disasters;
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domestic and foreign governmental laws, regulations and taxes;
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volatile trading patterns in commodities futures markets;
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price and availability of competitors’ supplies of oil, natural gas and NGLs;
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the actions of the Organization of Petroleum Exporting Countries (“OPEC”) and the ability of OPEC and other producing nations to agree to and maintain production levels;
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technological advances affecting energy consumption; and
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the price and availability of alternative fuels.
Further, oil, natural gas and NGL prices do not necessarily fluctuate in direct relationship to each other. Because approximately 69% of our estimated proved reserves as of December 31, 2017 was attributed to oil, our financial results are more sensitive to movements in oil prices.
As of December 31, 2017, we had in place hedges covering approximately 4,695 Bbls/d for 2018 at an average price of approximately $52.64 per Bbl. To the extent we are unhedged, we have significant exposure to adverse changes in the prices of oil and natural gas that could materially and adversely affect our business and results of operations.
WTI oil prices have declined from over $100 per bbl in September 2014 to $60.42 per bbl at December 31, 2017. Such a decline in oil price, if sustained, will have a material impact on our annual revenues and has caused us to take actions to reduce the costs of drilling and our operations.
Prolonged further sustained declines in oil, natural gas or NGL prices may act to reduce our cash flows further and adversely affect our financial condition. In the event of further sustained declines, our liquidity could be reduced, our access to equity or long-term debt might be restricted, and our ability to meet our capital expenditure obligations and financial commitments might be adversely affected. We may choose to defer drilling activity and/or production from existing wells for a number of reasons, including the following:
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drilling activity is sanctioned on the expectation of matching the drilling budget with operating cash flows and securing reasonable rates of returns based on the then prevailing oil, natural gas and NGL prices; if those prices decline and operating cash flows are reduced, there is a risk that drilling may be curtailed or postponed; and
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operating costs on our Eagle Ford properties are so low that production from these properties would likely continue to contribute to cash flows, but we may choose to defer production in the event that we consider there may be greater value in producing later.
Furthermore, prolonged sustained further declines in oil, natural gas or NGL prices may reduce the amount of oil, natural gas and NGLs we can produce economically and negatively impact the value of our estimated oil, natural gas and NGL reserves, the carrying value of our oil, natural gas and NGL reserves, the PV-10 valuations of our oil, natural gas and NGL reserves, and the standardized measure relating to oil, natural gas and NGL reserves.
Our future cash flows and results of operations are highly dependent on our ability to find, develop or acquire additional oil and natural gas resources.
Our business strategy is to generate profit through the acquisition, exploration, development and production of crude oil and natural gas reserves. Our future success therefore depends on our ability to find, develop or acquire additional crude oil and natural gas reserves that are economically recoverable. Our proved reserves generally decline when produced, unless we conduct successful exploration or development activities or acquire properties containing proved reserves or both. We may not be able to find, develop or acquire additional reserves on an economically viable basis. Furthermore, if crude oil and natural gas prices increase, the cost of finding, developing or acquiring additional reserves could also increase.
Drilling for and producing oil, natural gas and NGLs are high risk activities with many uncertainties that could adversely affect our business, financial condition or results of operations.
Exploration and development activities involve numerous risks beyond our control, including the risk that no commercially productive oil or natural gas reservoirs will be discovered and that drilling will not result in commercially viable oil or natural gas production. In addition, the future cost and timing of drilling, completing and operating wells is often uncertain. Drilling operations may be curtailed, delayed or cancelled as a result of a variety of factors, including:
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lack of prospective acreage available on acceptable terms;
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unexpected or adverse drilling conditions;
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elevated pressure or irregularities in geologic formations;
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equipment failures or accidents;
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adverse weather conditions;
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title problems;
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limited availability of financing upon acceptable terms;
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limitations in the market for oil, gas and NGLs;
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reductions in oil, NGLs and natural gas prices;
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compliance with governmental requirements, laws and regulations; and
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shortages or delays in the availability of drilling rigs, equipment and personnel.
Even if our exploitation, development and drilling efforts are successful, our wells, once completed, may not produce reserves of crude oil, NGLs or natural gas that are economically viable or that meet our prior estimates of economically recoverable reserves. Unsuccessful drilling activities could result in a significant decline in our production and revenues and materially impact our operations and financial position by reducing our available cash and liquidity. In addition, the potential for production decline rates for our wells could be greater than we expect. Because of the risks and uncertainties inherent to our businesses, our future drilling results may not be comparable to our historical results.
Our exploration, development and exploitation projects require substantial capital expenditures. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a decline in our oil and natural gas reserves with resulting adverse effects on our cash flow and liquidity.
The oil and natural gas industry is capital intensive. We currently make, and expect to continue to make, substantial capital expenditures for the acquisition, development and exploration of oil, natural gas and NGL reserves. We currently expect to allocate between $95 million and $100 million under our 2018 capital program to drilling and completing approximately 17 gross (15 net) wells across our properties in the Eagle Ford.
The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, crude oil and natural gas prices, actual drilling results, the availability of drilling rigs and other services and equipment, and regulatory, technological and competitive developments. A reduction in commodity prices from current levels may result in a decrease in our actual capital expenditures, which would negatively impact our ability to grow production.
Our cash flow from operations and access to capital are subject to a number of factors, including:
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our proved reserves;
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the amount of crude oil, natural gas and NGLs we are able to produce from existing wells;
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the prices at which our crude oil, natural gas and NGLs are sold;
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the costs at which our crude oil, natural gas and NGLs are extracted;
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global credit and securities markets;
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the ability and willingness of lenders and investors to provide capital and the cost of the capital; and
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our ability to acquire, locate and produce new reserves and the cost of such reserves.
If our revenues or the borrowing base under the Credit Facility decreases as a result of lower crude oil and natural gas prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations and growth at current levels. If additional capital is needed, we may not be able to obtain debt or equity financing on terms acceptable to us, if at all. If cash flow generated by our operations or available borrowings under the Credit Facility are not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to development of our properties, which in turn could lead to a decline in our reserves and production, and would adversely affect our business, financial condition and results of operations.
Any significant reduction in our borrowing base under the Credit Facility as a result of the periodic borrowing base redeterminations or otherwise may negatively impact our ability to fund our operations.
The Credit Facility limits the amounts we can borrow up to a borrowing base amount, which the lenders, in their sole discretion, determine semiannually on May 1 and November 1 of each year. The borrowing base depends on, among other things, our lenders’ evaluation of our oil and natural gas reserves. The lenders can unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under the Credit Facility. Any increase in the borrowing base requires the consent of the lenders holding 100% of the commitments. Effective January 4, 2018, we received notification that the borrowing base for the Credit Facility was maintained at $160 million, which represents the November 2017 redetermination. Our next scheduled borrowing base redetermination is scheduled for May 1, 2018.
In the future, we may not have access to adequate funding under the Credit Facility as a result of a decrease in our borrowing base due to the issuance of new indebtedness, the outcome of a subsequent borrowing base redetermination or an unwillingness or inability on the part of our lending counterparties to meet their funding obligations and the inability of other lenders to provide additional funding to cover any defaulting lender’s portion. Declines in commodity prices could result in a determination to lower the borrowing base in the future and, in such a case, we could be required to repay any indebtedness in excess of the redetermined borrowing base. As a result, we may be unable to implement our drilling and development plan, make acquisitions or otherwise carry out business plans or make required repayments under the Credit Facility, which would have a material adverse effect on our financial condition and results of operations and impair our ability to service our indebtedness.
Operating hazards, natural disasters or other interruptions of our operations could result in potential liabilities and substantial losses, which may not be fully covered by our insurance.
The oil and natural gas business involves significant operating hazards and risks such as:
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well blowouts;
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mechanical failures;
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fires and explosions;
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pipe or cement failures and casing collapses, which could release natural gas, oil, drilling fluids or hydraulic fracturing fluids;
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uncontrollable flows of oil, natural gas or well fluids;
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earthquakes and natural disasters;
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geologic formations with abnormal pressures;
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handling and disposal of materials, including drilling fluids and hydraulic fracturing fluids;
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pipeline ruptures or spills;
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releases of toxic gases; and
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other environmental hazards and risks.
Any of these hazards and risks can result in the loss of hydrocarbons, environmental pollution, personal injury claims and other damage to our properties and the property of others.
We maintain insurance against losses and liabilities in accordance with customary industry practices and in amounts that our management believes to be prudent. However, we are not insured against all operational risks and such coverage is not available to us. We do not carry business interruption insurance. We may elect not to carry insurance if our management believes that the cost of available insurance is excessive relative to the risks presented.
We could sustain significant losses and substantial liability for uninsured risks or in amounts in excess of existing insurance coverage. We cannot insure fully against pollution and environmental risks. We cannot assure investors that we will be able to maintain adequate insurance in the future at rates we consider reasonable or that any particular types of coverage will be available. The occurrence of an event not fully covered by insurance could have a material adverse effect on our financial position and results of operations.
Our planned exploratory drilling involves drilling in existing or emerging shale plays using some of the latest available horizontal drilling and completion techniques, which are subject to risks. As a result, drilling results may not meet our expectations for reserves or production.
Our operations involve utilizing some of the latest drilling and completion techniques as developed by us and our service providers in order to maximize cumulative recoveries and therefore generate the highest possible returns.
Risks that we face while drilling include, but are not limited to:
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landing our well bore in the desired formation;
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staying in the desired formation while drilling horizontally through the formation;
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running our casing the entire length of the well bore; and
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being able to run tools and other equipment consistently through the well bore.
Risks that we face while completing our wells include, but are not limited to:
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being able to fracture and stimulate the planned number of stages;
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being able to run tools the entire length of the well bore during completion operations; and
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successfully cleaning out the well bore after completion of the final fracture stimulation stage.
The results of our drilling in new or emerging formations are more uncertain initially than drilling results in areas that are more developed and have a longer history of established production. Newer or emerging formations and areas have limited or no production history, and, consequently, it is more difficult to predict future drilling results in these areas.
Ultimately, the success of these drilling and completion techniques can only be evaluated as more wells are drilled and production profiles are established over a sufficiently long time period. If our drilling does not meet our anticipated results or we are unable to execute our drilling program because of capital constraints, lease expirations, limited access to gathering systems and limited takeaway capacity and/or declines in crude oil and natural gas prices, the return on our investment in these areas may not be as attractive as we anticipate. Further, as a result of any of these developments, we could incur material write-downs of our oil and natural gas properties and the value of our undeveloped acreage could decline in the future.
We may not adhere to our proposed drilling schedule.
Our final determination of whether to drill any wells will be dependent on a number of factors, including:
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the results of our exploration efforts and the acquisition, review, and analysis of the seismic data;
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the availability of sufficient capital resources to us and the other participants for the drilling of the prospects;
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the approval of the prospects by the other participants after additional data has been compiled;
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economic and industry conditions at the time of drilling, including prevailing and anticipated prices for oil and gas and the availability and prices of drilling rigs and crews;
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the availability of leases and permits on reasonable terms for the prospects; and
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reprioritization of drilling schedule based on the acquisition of new properties.
Although we have identified or budgeted for numerous drilling prospects, we may not be able to lease or drill those prospects within our expected time frame or at all. Wells that are currently part of our capital plan may be based on statistical results of drilling activities in other 3-D project areas that we believe are geologically similar rather than on analysis of seismic or other data in the prospect area, in which case actual drilling and results are likely to vary, possibly materially, from those statistical results. In addition, our drilling schedule may vary from our expectations because of future uncertainties. In addition, our ability to produce oil and gas may be significantly affected by the availability and prices of hydraulic fracturing equipment and crews. There can be no assurance that these projects can be successfully developed or that any identified drill sites or budgeted wells will, if drilled, encounter reservoirs of commercially productive oil or gas. We may seek to sell or reduce all or a portion of our interest in a project area or with respect to prospects or budgeted wells within such project area.
SEC rules could limit our ability to book additional PUDs in the future.
SEC rules only permit, subject to limited exceptions, us to book our PUDs if they relate to wells scheduled to be drilled within five years after the date of booking. This requirement limits our ability to book additional PUDs as we pursue our drilling program. Moreover, we may be required to write down our PUDs if we do not drill those wells within the required five-year time frame.
Our identified drilling locations are subject to many uncertainties that could materially alter the occurrence or timing of their drilling. In addition, we may not be able to raise the substantial amount of capital that would be necessary to drill such locations.
Our final determination of whether to drill any scheduled or budgeted wells will be dependent on a number of factors, including:
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the ongoing review and analysis of geologic and engineering data;
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the availability of sufficient capital resources to us and the other participants to drill and complete the prospects;
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the approval of the prospects by other participants once additional data has been compiled;
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economic and industry conditions at the time of drilling, including prevailing and anticipated prices for crude oil, natural gas and NGLs and the availability and prices of drilling rigs and personnel;
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the ability to maintain, extend or renew leases and permits on reasonable terms for the prospects;
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additional due diligence;
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regulatory requirements and restrictions; and
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the opportunity to divert our drilling budget to preferred prospects on acquired acreage or to secure other acreage by farming in.
Although we have identified or budgeted for numerous drilling prospects, we may not be able to lease or drill those prospects within our expected time frame or at all. Wells that are currently part of our capital plan may be based on results of drilling activities in other areas that we believe are geologically similar to a prospect rather than on analysis of seismic or other data in the prospect area, in which case actual drilling and results are likely to vary, possibly materially, from results in other areas. In addition, our drilling schedule may vary from our expectations because of future uncertainties. In addition, our ability to produce oil and natural gas may be significantly affected by the availability and prices of equipment and personnel.
Our management team has specifically identified and scheduled certain drilling locations as an estimation of our future multi-year drilling activities on our existing acreage. These locations represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including crude oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, gathering system and pipeline transportation constraints, access to and availability of water sourcing and distribution systems, regulatory approvals and other factors. Because of these uncertain factors, we do not know if the numerous potential well locations we have identified will ever be drilled or if we will be able to produce natural gas or oil from these or any other potential locations. In addition, unless production is established within the spacing units covering the undeveloped acres on which some of the potential locations are obtained, the leases for such acreage will expire. Therefore, our actual drilling activities may materially differ from those presently identified.
In addition, we will require significant additional capital over a prolonged period in order to pursue the development of these locations, and we may not be able to raise or generate the capital required to do so. Any drilling activities we are able to conduct on these potential locations may not be successful or result in the addition of proved reserves to our overall proved reserves or may result in a downward revision of our estimated proved reserves, which could have a material adverse effect on our future business and results of operations.
The unavailability or high cost of additional drilling rigs, equipment, supplies, personnel and oilfield services could adversely affect our ability to execute our development plans within our budget and on a timely basis.
The demand for drilling rigs, pipe and other equipment and supplies, as well as for qualified and experienced field personnel to drill wells and conduct field operations, geologists, geophysicists, engineers and other professionals in the oil and natural gas industry, can fluctuate significantly, often in correlation with oil and natural gas prices, causing periodic shortages. Our operations are concentrated in areas in which the oil and gas industry has historically increased rapidly, and as a result, demand for such drilling rigs, equipment and personnel, as well as access to transportation, processing and refining facilities in these areas, and the costs for those items also increased. If we are unable to secure a sufficient number of drilling rigs at reasonable costs, we may not be able to drill all of our acreage before our leases expire.
Development of our estimated proved undeveloped reserves, or PUDs, may take longer than expected and may require higher levels of capital expenditures than we currently anticipate. Therefore, our estimated proved undeveloped reserves may not be ultimately developed or produced.
At December 31, 2017, approximately 75% of our total estimated proved reserves were classified as proved undeveloped reserves. Recovery of undeveloped reserves requires successful drilling and incurrence of significant capital expenditures. Our approximately 55.2 MMBoe of estimated proved undeveloped reserves will require an estimated $845.4 million of development capital over the next five years. Development of these undeveloped reserves may take longer and require higher levels of capital expenditures than we currently anticipate. Delays in the development of our reserves, increases in costs to drill and develop such reserves, or decreases in commodity prices will reduce the PV-10 value of our estimated proved undeveloped reserves and future net revenues estimated for such reserves and may result in some projects becoming uneconomic. In addition, delays in the development of reserves could require us to reclassify our proved undeveloped reserves as unproved reserves.
Further, our reserves data assumes that we can and will make these expenditures and that these operations will be conducted successfully. These assumptions, however, may not prove correct. If we choose not to spend the capital to develop these reserves, or if we are not otherwise able to successfully develop these reserves, we will be required to write them off. Any such write-offs of our reserves could reduce our ability to borrow and adversely affect our liquidity and available capital.
Our producing properties are located primarily in the Eagle Ford Shale of South Texas, making us vulnerable to risks associated with operating in one geographic area.
All of our production during the year ended December 31, 2017 was derived from our properties in the Eagle Ford Shale region of South Texas. As a result of this geographic concentration, we may be disproportionately exposed to the effect of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, processing or transportation capacity constraints, market limitations, weather events or interruption of the processing or transportation of crude oil or natural gas. Additionally, we may be exposed to additional risks, such as changes in field-wide rules and regulations that could cause us to permanently or temporarily shut-in many or all of our wells within the Eagle Ford.
Approximately 70% of our net Eagle Ford Shale leasehold acreage is undeveloped, and that acreage may not ultimately be developed or become commercially productive, which could cause us to lose rights under our leases and result in a material adverse effect on our crude oil, natural gas and NGLs reserves and future production and, therefore, our future cash flow and income.
As of December 31, 2017, approximately 70% of our net Eagle Ford leasehold acreage is undeveloped, or acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of crude oil, natural gas and NGLs regardless of whether such acreage contains proved reserves. Unless production is established on the undeveloped acreage covered by our leases, such leases will expire. Our future crude oil, natural gas and NGLs reserves and production and, therefore, our future cash flow and income, are highly dependent on successfully developing our undeveloped leasehold acreage and holding on to such leases.
Certain of our undeveloped leasehold assets are subject to leases that will expire over the next several years unless production is established on units containing the acreage or we timely exercise our contractual rights to extend the terms of such leases by continuous operations or the payment of lease extension payments or delay rentals.
Leases on oil and natural gas properties typically have a primary term of three to five years, after which they expire unless, prior to expiration, a well is drilled and production of hydrocarbons in paying quantities is established, applicable lease extension payments or delay rentals are made, or such lease is otherwise maintained pursuant to any applicable continuous operations provision. If our leases or term assignments on our undeveloped properties expire and we are unable to renew the leases, we will lose our right to develop the related properties. The primary term of the leases for 1,476 net acres that is not currently held by production will expire at the end of 2018 if such leases are not extended. Although we seek to actively manage our undeveloped properties, our drilling plans for these areas are subject to change based upon various factors, including drilling results, oil and natural gas prices, the availability and cost of capital, drilling and productions costs, availability of drilling services and equipment, gathering system and pipeline transportation constraints, and regulatory approvals. If commodity prices remain low, we may be required to delay our drilling plans and, as a result, may lose our right to develop the related properties.
Our estimated proved reserves are based on many assumptions that may turn out to be inaccurate and any significant inaccuracies in these reserve estimates or underlying assumptions could materially affect the actual quantities and present value of such reserves.
There are uncertainties inherent in estimating crude oil and natural gas reserves and their estimated value, including many factors beyond our control. The reserve data in this Annual Report on Form 10-K represents only estimates. Reservoir engineering is a subjective and inexact process of estimating underground accumulations of crude oil and natural gas that cannot be measured in an exact manner and is based on assumptions that may vary considerably from actual results. Reservoir engineering also requires economic assumptions about matters such as crude oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Accordingly, actual production, crude oil and natural gas prices, revenues, taxes, operating expenses, expenditures and quantities of recoverable crude oil and natural gas reserves will likely vary, possibly materially, from estimates. Any significant variance in our estimates or the accuracy of our assumptions could materially affect the estimated quantities and present value of reserves shown in this Annual Report on Form 10-K.
We depend upon several significant customers for the sale of most of our crude oil, natural gas and NGL production. The loss of one or more of these customers could adversely affect our revenues in the short term.
For the year ended December 31, 2017, purchases by our largest five customers accounted for 35%, 20%, 16%, 14%, and 10% respectively, of our total revenues. While we believe that we can procure substitute or additional customers to offset the loss of one or more of our current customers, there is no assurance that we would be successful in doing so on terms acceptable to us or at all. The loss of one or more of such customers could limit our access to suitable markets for the crude oil, natural gas and NGLs we produce. The availability of a ready market for any crude oil, natural gas and/or NGLs we produce depends on numerous factors beyond the control of our management, including but not limited to the extent of domestic production and imports of crude oil, the proximity and capacity of pipelines, the availability of skilled labor, materials and equipment, the effect of state and federal regulation of crude oil and natural gas production and federal regulation of crude oil, natural gas and NGLs sold in interstate commerce. We cannot assure you that we will continue to have ready access to suitable markets for our future crude oil, natural gas and NGL production.
Our hedging transactions expose us to counterparty credit risk.
Currently, all of our hedging arrangements are concentrated with three counterparties, each of which are lenders under the Credit Facility. If these counterparties fail to perform their obligations, we may suffer financial loss or be prevented from realizing the benefits of favorable price changes in the physical market for our crude oil, natural gas and NGLs.
The present value of future net revenues from our proved reserves will not necessarily be the same as the current market value of our estimated oil and natural gas reserves.
The discounted future net cash flows in this Annual Report on Form 10-K is not necessarily the same as the current market value of our estimated crude oil and natural gas reserves. The current requirements for crude oil and natural gas reserve estimation and disclosures require the estimated discounted future net cash flows from proved reserves to be based on the average of the sales price on the first day of each month in the applicable year, with costs determined as of the date of the estimate. Actual future net cash flows also will be affected by various factors, including:
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the actual prices we receive for crude oil and natural gas;
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our actual operating costs in producing crude oil and natural gas;
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the amount and timing of actual production;
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supply and demand for crude oil and natural gas;
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increases or decreases in consumption of crude oil and natural gas; and
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changes in governmental laws and regulations or taxation.
In addition, the 10% discount factor we use when calculating discounted future net cash flows for reporting requirements may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and gas industry in general.
We have incurred losses from operations for various periods since our inception and may continue to do so in the future.
We incurred a net loss from operations of approximately $31.3 million for the year ended December 31, 2017. Our development of, and participation in, an increasingly larger number of prospects has required, and will continue to require, substantial capital expenditures. The uncertainty and factors described throughout this “Risk Factors” section may impede our ability to economically find, develop and acquire oil and natural gas reserves. As a result, we may not be able to operate profitability and may not receive positive cash flows from operating activities in the future, which could adversely affect our business and the trading price of our Class A voting common stock.
Our derivative activities could result in financial losses or could reduce our income.
Because crude oil and natural gas prices are subject to volatility, we may periodically enter into price-risk-management transactions such as fixed-rate swaps, costless collars, puts, calls and basis differential swaps to reduce our exposure to price declines associated with a portion of our oil and natural gas production and thereby achieve a more predictable cash flow. The use of these arrangements limits our ability to benefit from increases in the prices of crude oil and natural gas. Our derivative arrangements may apply to only a portion of our production, thereby providing only partial protection against declines in crude oil and natural gas prices.
These arrangements may expose us to the risk of financial loss in certain circumstances, including instances in which production is less than expected, our customers fail to purchase contracted quantities of crude oil and natural gas or a sudden, unexpected event materially impacts crude oil or natural gas prices. In addition, the counterparties under our derivatives contracts may fail to fulfill their contractual obligations to us.
If crude oil and natural gas prices decrease, we may be required to write-down the carrying values of our crude oil and natural gas properties.
We review our proved crude oil and natural gas properties for impairment whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. Based on specific market factors and circumstances at the time of prospective impairment reviews and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write down the carrying value of our crude oil and natural gas properties, which may result in a decrease in the amount we can borrow under our credit facility. A write-down constitutes a non-cash charge to earnings. We may incur impairment charges in the future, which could have a material adverse effect on our ability to borrow under our credit facility and adversely impact our results of operations and liquidity for the periods in which such charges are taken.
Our inability to market our crude oil and natural gas could adversely affect our business.
Market conditions or the unavailability of satisfactory crude oil and natural gas transportation arrangements may hinder our access to crude oil and natural gas markets or delay production. The availability of a ready market for our crude oil and natural gas production depends on a number of factors, including the demand for and supply of crude oil and natural gas and the proximity of reserves to pipelines and gathering facilities. Our ability to market our production depends in substantial part on the availability and capacity of gathering systems, pipelines and processing facilities owned and operated by third parties. Our failure to obtain such services on favorable terms could adversely impact our business and results of operations.
Our productive properties may be located in areas with limited or no access to pipelines, thereby requiring compression facilities or delivery by other means, such as trucking and train. Such restrictions on our ability to sell our crude oil or natural gas may have several adverse effects, including higher transportation costs, fewer potential purchasers (thereby potentially resulting in a lower selling price) or, in the event we were unable to market and sustain production from a particular lease for an extended period of time, possibly causing us to lose leases due to the lack of commercially established production.
We generally deliver our crude oil and natural gas production through gathering systems and pipelines that we do not own under interruptible or short-term transportation agreements. Under the interruptible transportation agreements, the transportation of our crude oil and natural gas production may be interrupted due to capacity constraints on the applicable system, for maintenance or repair of the system or for other reasons as dictated by the particular agreements. We may also enter into firm transportation arrangements for additional production in the future. Because we are obligated to pay fees on minimum volumes to our service providers under firm transportation agreements regardless of actual volume throughput, these firm transportation agreements may be significantly more costly than interruptible or short-term transportation agreements, which could adversely affect our business and results of operations.
A portion of our crude oil and natural gas production in any region may be interrupted, or shut in, from time to time for numerous reasons, including as a result of weather conditions, accidents, loss of pipeline or gathering system access, or field personnel issues or strikes. We may also voluntarily curtail production in response to market conditions. If a substantial amount of our production is interrupted or curtailed, it could adversely affect our business and results of operations.
If we fail to establish and maintain proper internal controls, our ability to produce accurate financial statements or comply with applicable regulations could be impaired.
Section 404(a) of the Sarbanes-Oxley Act requires that, beginning with our annual report for the year ended December 31, 2017, our management assess and report annually on the effectiveness of our internal control over financial reporting and identify any material weaknesses in our internal control over financial reporting. Once we are no longer an emerging growth company, Section 404(b) of the Sarbanes-Oxley Act will require our independent registered public accounting firm to issue an annual report that addresses the effectiveness of our internal control over financial reporting.
On November 21, 2016, our management identified a material weakness in the financial close process for the nine months ended September 30, 2016 relating to a failure to properly classify cash flows related to our gain on redemption of bonds, and concluded that our internal control over financial reporting as of September 30, 2016 was ineffective. Although this material weakness was remediated, the presence of further material weaknesses could result in financial statement errors which, in turn, could lead to errors in our financial reports and/or delays in our financial reporting, which could require us to restate our operating results or our auditors may be required to issue a qualified audit report.
In order to maintain and improve the effectiveness of our disclosure controls and procedures and internal control over financial reporting, we will need to expend additional resources and provide additional management oversight. Implementing any appropriate changes to our internal controls may require specific compliance training of our directors and employees, entail substantial costs in order to modify our existing accounting systems, take a significant period of time to complete and divert management’s attention from other business concerns. These changes may not, however, be effective in maintaining the adequacy of our internal control.
If either we are unable to conclude that we have effective internal control over financial reporting or, at the appropriate time, our independent auditors are unwilling or unable to provide us with an unqualified report on the effectiveness of our internal control over financial reporting as required by Section 404(b) of the Sarbanes-Oxley Act, investors may lose confidence in our operating results, the price of our Class A common stock could decline and we may be subject to litigation or regulatory enforcement actions. In addition, if we are unable to meet the requirements of Section 404 of the Sarbanes-Oxley Act, we may not be able to remain listed on Nasdaq.
The terms of the Credit Facility may restrict our operations, particularly our ability to respond to changes or to take certain actions.
The Credit Facility contain a number of restrictive covenants that impose significant operating and financial restrictions on us and may limit our ability to engage in acts that may be in our long-term best interest, including restrictions on our ability, subject to satisfaction of certain conditions, to:
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incur additional indebtedness and guarantee indebtedness;
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pay dividends or make other distributions or repurchase or redeem capital stock;
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prepay, redeem or repurchase certain debt;
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issue certain preferred stock or similar equity securities;
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make loans and investments;
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sell assets;
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incur liens;
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enter into transactions with affiliates;
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alter the businesses we conduct;
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enter into agreements restricting our subsidiaries’ ability to pay dividends; and
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consolidate, amalgamate, merge or sell all or substantially all of our assets.
In addition, the restrictive covenants in the Credit Facility require us to maintain specified financial ratios and satisfy other financial condition tests. Our ability to meet those financial ratios and tests can be affected by events beyond our control, and we may be unable to meet them.
A breach of the covenants or restrictions or under the Credit Facility could result in an event of default under the applicable indebtedness. Such a default may allow the creditors to accelerate the related debt and may result in the acceleration of any other debt to which a cross-acceleration or cross-default provision applies. In the event our lenders accelerate the repayment of our borrowings, we and our subsidiaries may not have sufficient assets to repay that indebtedness.
As a result of these restrictions contained in the Credit Facility, we may be limited in how we conduct our business, unable to raise additional debt or equity financing to operate during general economic or business downturns or unable to compete effectively or to take advantage of new business opportunities. These restrictions may further affect our ability to grow in accordance with our strategy. In addition, our financial results, our substantial indebtedness and our credit ratings could adversely affect the availability and terms of our current and future financing.
Our level of indebtedness may increase, reducing our financial flexibility.
We intend to fund our capital expenditures in 2018 through cash flow from operations and from borrowings under the Credit Facility and, if necessary, through debt or equity financings. Our ability to make the necessary capital investment to maintain or expand our asset base and develop oil and natural gas reserves will be impaired if cash flow from operations is reduced and external sources of capital become limited or unavailable. If we incur additional debt for these or other purposes, the related risks that we now face could intensify and we could face additional risks. Our level of debt could adversely affect our business and results of operations in several important ways, including the following:
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a portion of our cash flow from operations would be used to pay interest on borrowings;
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the covenants contained in our credit facilities limit our ability to borrow additional funds, pay dividends, dispose of assets or issue shares of preferred stock and otherwise may affect our flexibility in planning for, and reacting to, changes in general business and economic conditions;
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a high level of debt may impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general corporate or other purposes;
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a leveraged financial position would make us more vulnerable to economic downturns and decreases in commodity prices and could limit our ability to withstand competitive pressures; and
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a debt that we incur under our credit facilities will be at variable rates, which could make us vulnerable to an increase in interest rates.
We may not be able to generate sufficient cash to service all of our indebtedness and may be forced to take other actions to satisfy our obligations under applicable debt instruments, which may not be successful.
Our ability to make scheduled payments on or to refinance our indebtedness obligations, including the Credit Facility and senior notes, depends on our financial condition and operating performance, which are subject to prevailing economic and competitive conditions and certain financial, business and other factors beyond our control. We may not be able to maintain a level of cash flow from operating activities sufficient to permit us to pay the principal, premium, if any, and interest on our indebtedness.
If our cash flow and capital resources are insufficient to fund debt service obligations, we may be forced to reduce or delay investments and capital expenditures, sell assets, seek additional capital or restructure or refinance indebtedness which would have a material adverse effect on our business and operations.
Increased costs of capital could adversely affect our business.
Our business and operating results can be adversely affected by factors such as the availability, terms and cost of capital and increases in interest rates. Changes in any one or more of these factors could cause our cost of doing business to increase, limit our access to capital, limit our ability to pursue acquisition opportunities, reduce our cash flows available for drilling and place us at a competitive disadvantage. Disruptions in the global financial markets may lead to an increase in interest rates or a contraction in credit availability, which would impact our ability to finance our operations. We will require continued access to capital for the foreseeable future. A significant reduction in the availability of credit could materially and adversely affect our business, results of operations and financial condition.
The crude oil and natural gas industry is intensely competitive and many of our competitors have resources that are greater than ours.
The oil and natural gas industry is highly competitive. Public integrated and independent oil and gas companies, private equity backed and private operators are all active bidders for desirable crude oil and natural gas properties as well as the equipment and personnel required to operate those properties. Many of these companies have substantially greater financial resources, staff and facilities than we do. There is a risk that increased industry competition will adversely impact our ability to purchase assets or secure services at prices that will allow us to generate sufficient returns on investment in the future.
We may not be able to keep pace with technological developments in our industry.
The oil and natural gas industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. As others use or develop new technologies, we may be placed at a competitive disadvantage or may be forced by competitive pressures to implement those new technologies at substantial costs. In addition, other oil and natural gas companies may have greater financial, technical and personnel resources that allow them to enjoy technological advantages and that may in the future allow them to implement new technologies before we can. We may not be able to respond to these competitive pressures or implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use now or in the future were to become obsolete, our business, financial condition or results of operations could be materially and adversely affected.
The loss of any of our key personnel could adversely affect our business, financial condition, the results of operations and future growth.
We are reliant on a number of key members of our executive management team, and we do not have employment agreements with any of them. Loss of such personnel may have an adverse effect on our performance. Certain areas in which we operate are highly competitive regions and competition for qualified personnel is intense. We may be unable to hire suitable field personnel for our technical team or there may be periods of time where a particular position remains vacant while a suitable replacement is identified and appointed. Our ability to manage our growth will require us to continue to train, motivate and manage our employees and to attract, motivate and retain additional qualified personnel. We may not be successful in attracting and retaining the personnel required to grow and operate our business profitably.
Our ability to manage growth will have an impact on our business, financial condition and results of operations.
Our growth historically has been achieved through the acquisition of leaseholds and the expansion of our drilling programs. Future growth may place strains on our financial, technical, operational and administrative resources and cause us to rely more on project partners and independent contractors, potentially adversely affecting our financial position and results of operations. Our ability to grow will depend on a number of factors, including:
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our ability to obtain leases or options on properties;
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our ability to identify and acquire new exploratory prospects;
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our ability to develop existing prospects;
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our ability to continue to retain and attract skilled personnel;
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our ability to maintain or enter into new relationships with project partners and independent contractors;
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the results of our drilling programs;
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commodity prices; and
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our access to capital.
We may not be successful in upgrading our technical, operational and administrative resources or increasing our internal resources sufficiently to provide certain of the services currently provided by third parties, and we may not be able to maintain or enter into new relationships with project partners and independent contractors on financially attractive terms, if at all. If we are unable to achieve or manage growth, it may materially and adversely affect our business, results of operations and financial condition.
We may incur losses as a result of title deficiencies.
We may lose title to, or interests in, our leases and other properties if the conditions to which those interests are subject are not satisfied or if we do not have sufficient funds available to meet the commitments.
The existence of title differences with respect to our crude oil and natural gas properties could reduce their value or render such properties worthless, which would have a material adverse effect on our business and financial results. We do not obtain title insurance and have not obtained drilling title opinions on all of our crude oil and natural gas properties. As is customary in the industry in which we operate, we generally rely upon the judgment of crude oil and natural gas lease brokers or independent landmen who perform the field work in examining records in the appropriate governmental offices and abstract facilities before attempting to acquire or place under lease a specific mineral interest and before drilling a well on a leased tract, and we generally make title investigations and receive title opinions of local counsel before we commence drilling operations. In some cases, we perform curative work to correct deficiencies in the marketability or adequacy of the title assigned to us. In cases involving more serious title problems, the amount paid for affected crude oil and natural gas leases can be lost, and the target area can become undrillable. While we undertake to cure all title deficiencies prior to drilling, the failure of title may not be discovered until after a well is drilled, in which case we may lose the lease, our investment in the well and the right to produce all or a portion of the minerals under the property. A significant portion of our acreage is undeveloped leasehold, which has a greater risk of title defects than developed acreage.
Our operations are subject to health, safety and environmental laws and regulations that may expose us to significant costs and liabilities.
The conduct of exploring for, and producing oil, natural gas and NGLs may expose our personnel and other third parties to potentially dangerous working environments. Occupational health and safety legislation and regulations differ in each jurisdiction. If any of our employees suffer injury or death, compensation payments or fines may have to be paid, and such circumstances could result in the loss of a license or permit required to carry on the business, or other legislative sanction, all of which have the potential to materially and adversely affect our business, results of operations and financial condition.
There is an inherent risk of incurring significant environmental costs and liabilities in the performance of our operations, some of which may be material, due to our handling of petroleum hydrocarbons and wastes, our emissions to air and water, the underground injection or other disposal of our wastes and historical industry operations and waste disposal practices. Under certain environmental laws and regulations, we may be liable, regardless of whether we were at fault, for the full cost of removing or remediating contamination, even when multiple parties contributed to the release and the contaminants were released in compliance with all applicable laws. In addition, accidental spills or releases on our properties may expose us to significant liabilities that could have a material adverse effect on our financial condition and results of operations. Aside from government agencies, the owners of properties where our wells are located, the operators of facilities where our petroleum hydrocarbons or wastes are taken for reclamation or disposal and other private parties may be able to sue us to enforce compliance with environmental laws and regulations, as well as collect penalties for violations or obtain damages for any related personal injury or property damage. Some sites we operate are located near current or former third-party oil and natural gas operations or facilities, and there is a risk that contamination has migrated from those sites to ours. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly material handling, emission, waste management or clean-up requirements could require us to make significant expenditures to attain and maintain compliance or may otherwise materially and adversely affect our business, results of operations and financial condition. We may not be able to recover some or any of these costs from insurance.
In addition, our operations and financial performance may be adversely affected by governmental action, including delay, inaction, policy change or the introduction of new, or amendment of or changes in interpretation of existing legislation or regulations, particularly in relation to access to infrastructure, environmental regulation (including in respect of carbon emissions and management), royalties and production and exploration licensing. Federal and state regulators are increasingly targeting greenhouse gas emissions from oil and gas operations. While these regulatory efforts are evolving, they may require the installation of emission controls or mandate other action that may result in increased costs of operation, delay, uncertainty or exposure to liability.
Hydraulic fracturing has recently come under increased scrutiny and could be the subject of further regulation that could impact the timing and cost of development.
Hydraulic fracturing is an important and commonly used process in the completion of unconventional crude oil and natural gas wells. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into deep rock formations to stimulate crude oil or natural gas production. Currently, hydraulic fracturing is primarily regulated in the United States at the state level, which generally focuses on regulation of well design, pressure testing and other operating practices. However, some states and local jurisdictions across the United States, including states in which we operate, have begun adopting more restrictive regulation, including measures such as:
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required disclosure of chemicals used during the hydraulic fracturing process;
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restrictions on wastewater disposal activities;
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required baseline and post-drilling sampling of water supplies in close proximity to hydraulic fracturing operations;
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new municipal or state land use regulations, such as changes in setback requirements, which may restrict drilling locations or related activities;
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financial assurance requirements, such as the posting of bonds, to secure site restoration obligations; and
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local moratoria or even bans on crude oil and natural gas development utilizing hydraulic fracturing in some communities.
The Texas Railroad Commission recently adopted rules and regulations requiring that the well operator disclose the list of chemical ingredients subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) for disclosure on an internet website and also file the list of chemicals with the Texas Railroad Commission with the well completion report. The total volume of water used to hydraulically fracture a well also must be disclosed to the public and filed with the Texas Railroad Commission. Any increased federal, state, local, foreign, or international regulation of hydraulic fracturing could reduce the volume of reserves that we can economically recover, which could materially and adversely affect our revenues and results of operations.
At the U.S. federal level, the EPA has asserted federal regulatory authority pursuant to the SDWA over certain hydraulic fracturing activities involving the use of diesel fuels and published permitting guidance in February 2014 addressing the performance of such activities. Also, in May 2014, the EPA issued an Advance Notice of Proposed Rulemaking to collect data on chemicals used in hydraulic fracturing operations under Section 8 of the Toxic Substances Control Act. To date, no other action has been taken. Further, the EPA finalized regulations under the CWA in June 2016 that prohibit wastewater discharges from hydraulic fracturing and certain other natural gas operations to publicly owned wastewater treatment plants. Also, in December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources. The final report concluded that "water cycle" activities associated with hydraulic fracturing may impact drinking water resources "under some circumstances," noting that the following hydraulic fracturing water cycle activities and local- or regional-scale factors are more likely than others to result in more frequent or more severe impacts: water withdrawals for fracturing in times or areas of low water availability; surface spills during the management of fracturing fluids, chemicals or produced water; injection of fracturing fluids into wells with inadequate mechanical integrity; injection of fracturing fluids directly into groundwater resources; discharge of inadequately treated fracturing wastewater to surface waters; and disposal or storage of fracturing wastewater in unlined pits. In addition, the BLM finalized rules in March 2015 that impose new or more stringent standards for performing hydraulic fracturing on federal and American Indian lands (which was challenged in a U.S. federal trial court, resulting in a decision in June 2016 against the rule, an appeal of that decision, and a U.S. federal appeals court ruling in September 2017 dismissing the appeals and vacating the trial court decision); the rule is currently the subject of a July 2017 proposal by the BLM to rescind it.
There has been increasing public controversy regarding hydraulic fracturing with regard to use of fracturing fluids, impacts on drinking water supplies, use of water and the potential for impacts on surface water, and groundwater and, the potential for the disposal of produced water in underground formations to trigger earthquakes, and effects on the environment generally. A number of lawsuits and enforcement actions have been initiated across the country relating to hydraulic fracturing practices. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations as well as make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In addition, if hydraulic fracturing is further regulated at the federal or state level, our fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also to attendant permitting delays and potential increases in costs. Such legislative changes could cause us to incur substantial compliance costs, and compliance or the consequences of any failure to comply by us could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the impact on our business of newly enacted or potential federal or state legislation governing hydraulic fracturing.
Should we fail to comply with all applicable FERC administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines.
Under the Domenici-Barton Energy Policy Act of 2005 (“EP Act of 2005”), the Federal Energy Regulatory Commission (“FERC”) has civil penalty authority under the Natural Gas Act of 1938 (the “NGA”) and the Natural Gas Policy Act (“NGPA”) to impose penalties for current violations of up to $1,213,503 per day for each violation and disgorgement of profits associated with any violation. While our operations have not been regulated by FERC as a natural gas company under the NGA, FERC has adopted regulations that may subject certain of our otherwise non-FERC jurisdictional operations to FERC annual reporting and posting requirements. We also must comply with the anti-market manipulation rules enforced by FERC. Additional rules and legislation pertaining to those and other matters may be considered or adopted by FERC from time to time. Failure to comply with those regulations in the future could subject us to civil penalty liability.
Conservation measures and technological advances could reduce demand for crude oil, natural gas and NGLs.
Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to crude oil, natural gas and NGLs, technological advances in fuel economy and energy generation devices could reduce demand for crude oil, natural gas and NGLs. The impact of the changing demand for crude oil, natural gas and NGLs services and products may have a material adverse effect on our business, financial condition, results of operations and cash flows.
Our ability to produce crude oil and natural gas economically and in commercial quantities could be impaired if we are unable to acquire adequate supplies of water for our drilling operations or are unable to dispose of or recycle the water we use economically and in an environmentally safe manner.
Drilling activities require the use of water. For example, the hydraulic fracturing process that we employ to produce commercial quantities of oil and natural gas from many reservoirs, including in the Eagle Ford, requires the use and disposal of significant quantities of water. In certain areas, there may be insufficient local aquifer capacity to provide a source of water for drilling activities due to drought conditions. Water must be obtained from other sources and transported to the drilling site. The effects of climate change may further exacerbate water scarcity in certain regions. If we are unable to obtain water to use in our operations from local sources, we may be unable to economically produce our reserves, which could have an adverse effect on our financial condition, results of operations and cash flows.
Our inability to secure sufficient amounts of water, or to dispose of or recycle the water used in our operations, could adversely impact our operations in certain areas. Moreover, the imposition of new environmental initiatives and regulations could include restrictions on our ability to conduct certain operations such as hydraulic fracturing or disposal of waste, including, but not limited to, produced water, drilling fluids and other materials associated with the exploration, development or production of crude oil and natural gas. In particular, regulatory focus on disposal of produced water and drilling waste through underground injection has increased because of alleged links between such injection and regional seismic impacts in disposal areas. For example, regulators in some states, including Texas, have responded to the potential concern that the injection of produced water (and other waste water from oil and gas operations) into underground disposal wells may trigger seismic activity.
Compliance with environmental regulations and permit requirements governing the withdrawal, storage, use and discharge of surface water or groundwater necessary for hydraulic fracturing of wells may increase our operating costs and cause delays, interruptions or termination of our operations, the extent of which cannot be predicted, all of which could materially and adversely affect our business, results of operations and financial condition.
Climate change laws and regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the crude oil and natural gas that we produce while the physical effects of climate change could disrupt our production and cause us to incur significant costs in preparing for or responding to those effects.
In connection with the EPA finding that emissions of carbon dioxide, methane and other greenhouse gases (“GHGs”) present an endangerment to public health and the environment, the EPA has adopted regulations under existing provisions of the Clean Air Act (“CAA”) that, among other things, require reduced GHG emissions from certain large stationary sources, and the monitoring and reporting of GHG emissions from specified onshore and offshore oil and gas production sources in the United States on an annual basis, which include certain of our operations. In May 2016, the EPA released final regulations intended to reduce methane emissions from the oil and gas industry, including throughout the natural gas supply chain. The regulations could affect us indirectly by affecting our customer base or by directly regulating our operations. In either case, increased costs of operation and exposure to liability could result. However, on June 12, 2017, EPA proposed a two year stay of the fugitive emissions, pneumatic pump and professional engineer certification requirements in the methane rule while the agency reconsiders the rule. The EPA has also announced that it intends to propose similar standards for existing sources but the change in Presidential Administrations may impact any existing source rule. The EPA also finalized rules in 2016 that clarify when crude oil and natural gas sites should be aggregated for purposes of air permitting, which could increase our compliance and permitting costs.
In addition, Congress has considered legislation to restrict or regulate emissions of greenhouse gases, such as carbon dioxide and methane that are understood to contribute to global warming. While comprehensive climate legislation will likely not be passed by either house of Congress in the near future, energy legislation and other initiatives continue to be proposed that may be relevant to greenhouse gas emissions issues. In December 2016, the United States was one of 175 countries to adopt the Paris Agreement at the 21st Conference of Parties, which requires member countries to review and “represent a progression” in their intended nationally determined contributions, which set GHG emission reduction goals, every five years beginning in 2020. On October 4, 2016, the E.U. ratified the Paris Agreement, thus meeting the threshold for the agreement to come into force. On June 1, 2017, President Trump announced that the United States planned to withdraw from the Paris Agreement and to seek negotiations either to reenter the Paris Agreement on different terms or establish a new framework agreement. The Paris Agreement provides for a four-year exit process beginning when it took effect in November 2016, which would result in an effective exit date of November 2020. The United States’ adherence to the exit process is uncertain and/or the terms on which the United States may reenter the Paris Agreement or a separately negotiated agreement are unclear at this time.
Acts of terrorism (including eco-terrorism and cyber-attacks) could have a material adverse effect on our financial condition, results of operations and cash flows.
Our assets and operations, and the assets and operations of our providers of gas gathering, processing, transportation and fractionation services, may be targets of terrorist activities (including eco-terrorist and cyber-terrorist activities) that could disrupt our business or cause significant harm to our operations, such as full or partial disruption to our ability to produce, process, transport, market or distribute natural gas, NGLs and oil. Acts of terrorism, as well as events occurring in response to or in connection with acts of terrorism, could cause environmental and other repercussions that could result in a significant decrease in revenues or significant reconstruction or remediation costs, which could have a material adverse effect on our financial condition, results of operations and cash flows. In addition, acts of terrorism, and the threat of such acts, could result in volatility in the prices for natural gas, NGLs and oil and could affect the markets for such commodities.
Our business could be negatively impacted by security threats, including cyber-security threats, and other disruptions.
As an oil and natural gas producer, we face various security threats, including cyber-security threats to gain unauthorized access to sensitive information or to render data or systems unusable, threats to the safety of our employees, threats to the security of our facilities and infrastructure or third-party facilities and infrastructure, such as processing plants and pipelines, and threats from terrorist acts. Cyber-security attacks in particular are evolving and include, but are not limited to, malicious software, attempts to gain unauthorized access to data, and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information and corruption of data. Although we utilize various procedures and controls to monitor and protect against these threats and to mitigate our exposure to such threats, there can be no assurance that these procedures and controls will be sufficient in preventing security threats from materializing. If any of these events were to materialize, they could lead to losses of sensitive information, critical infrastructure, personnel or capabilities essential to our operations and could have a material adverse effect on our reputation, financial position, results of operations or cash flows.
Our ability to use our net operating loss carryforwards may be limited.
As of December 31, 2017, we had approximately $99.4 million of U.S. federal net operating loss carryforwards (“NOLs”). Our NOLs begin to expire in 2030. Utilization of these NOLs depends on many factors, including our future income, which cannot be assured. In addition, Section 382 of the Internal Revenue Code of 1986, as amended (“Section 382”), generally imposes an annual limitation on the amount of taxable income that may be offset by NOLs when a corporation has undergone an “ownership change” (as determined under Section 382). Generally, a change of more than 50% in the ownership of a corporation’s stock, by value, over a three-year period constitutes an ownership change for U.S. federal income tax purposes. Any unused annual limitation may be carried over to later years. We have previously experienced an ownership change and may experience more ownership changes in the future, which would result in an annual limitation under Section 382. The limitations arising from our prior ownership change or from any ownership change that may arise in the future may prevent utilization of our NOLs prior to their expiration. Future ownership changes or regulatory changes could further limit our ability to utilize our NOLs. To the extent we are not able to offset our future income with our NOLs, this could adversely affect our operating results and cash flows if we attain profitability.
The recently passed comprehensive tax reform bill could adversely affect our business and financial condition.
On December 22, 2017, President Trump signed into law the Tax Cuts and Jobs Act, which significantly reforms the Code. The TCJA, among other things, contains significant changes to corporate taxation, including a permanent reduction of the corporate income tax rate, a partial limitation on the deductibility of business interest expense, limitation of the deduction for certain NOLs to 80% of current year taxable income, an indefinite carryforward of certain NOLs, immediate deductions for certain new investments instead of deductions for depreciation expense over time and the modification or repeal of many business deductions and credits. We continue to examine the impact of this tax reform legislation, and as its overall impact is uncertain, we note that the TCJA could adversely affect our business and financial condition. The impact of this tax reform legislation on holders of our common stock is also uncertain and could be adverse.
General economic conditions could adversely affect our business and future growth.
Instability in the global financial markets may have a material impact on our liquidity and financial condition, and we may ultimately face major challenges if conditions in the financial markets were to materially change or worsen. Our ability to access the capital markets or to borrow money may be restricted or may be more expensive at a time when we would need to raise capital, which could have an adverse effect on our flexibility to react to changing economic and business conditions and on our ability to fund our operations and capital expenditures in the future. Such economic conditions could have an impact on our customers, causing them to fail to meet their obligations to us. In addition, such changes could have an impact on the liquidity of our operating partners, resulting in delays in operations or their failure to make required payments.
Also, market conditions could have an impact on our crude oil and natural gas derivative instruments if our counterparties are unable to perform their obligations or seek bankruptcy protection, which could lead to reductions in the demand for crude oil and natural gas, or reductions in the prices of oil and natural gas or both, which could have an adverse impact on our financial position, results of operations and cash flows. While the ultimate outcome and impact of changing economic conditions cannot be predicted, they may materially and adversely affect our business, results of operations and financial condition.
Changes in the differential between benchmark prices of crude oil and natural gas and the reference or regional index price used to price our actual crude oil and natural gas sales could have a material adverse effect on our results of operations and financial condition.
The reference or regional index prices that we use to price our crude oil and natural gas sales reflect a discount to the relevant benchmark prices. The difference between the benchmark price and the price we reference in our sales contracts is called a differential. We cannot accurately predict crude oil and natural gas differentials. Changes in differentials between the benchmark price for crude oil and natural gas and the reference or regional index price we reference in our sales contracts could materially and adversely affect our business, results of operations and financial condition.
Recent federal legislation could have an adverse impact on our ability to use derivative instruments to reduce the effects of commodity prices, interest rates and other risks associated with our business.
Historically, we have entered into a number of commodity derivative contracts in order to hedge a portion of our crude oil and natural gas production. Under the Dodd-Frank Wall Street Reform and Consumer Protection Act (“Dodd-Frank Act”), the Commodity Futures Trading Commission (“CFTC”) issued regulations setting position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. Certain bona fide hedging transactions are exempt from these limits. The position limits regulation was vacated by the United States District Court for the District of Columbia in September 2012. The CFTC has appealed the District Court’s decision and its Chairman has stated that the agency is working on developing a new proposed rulemaking to address position limits. The CFTC has finalized other regulations, including critical rulemakings on the “swap” and “swap dealer” definitions, swap dealer registration, swap data reporting and mandatory clearing, among others. The Dodd-Frank Act and CFTC rules also will require us in connection with certain derivatives activities to comply with clearing and trade-execution requirements (or take steps to qualify for an exemption to such requirements). In addition, new regulations may require us to comply with margin requirements although these regulations are not finalized and their application to us is uncertain at this time. The legislation may also require the counterparties to our derivative contracts to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty.
The new legislation and any new regulations could:
•
significantly increase the cost of some derivative contracts (including through requirements to post collateral that could adversely affect our available liquidity);
•
materially alter the terms of some derivative contracts;
•
reduce the availability of some derivatives to protect against risks we encounter;
•
reduce our ability to monetize or restructure our existing derivative contracts; and
•
potentially increase our exposure to less creditworthy counterparties.
If we reduce our use of derivatives as a result of the new legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Increased volatility may make us less attractive to certain types of investors. Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of crude oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to crude oil and natural gas. If the new legislation and regulations result in lower commodity prices, our revenues could be adversely affected. Any of these consequences could adversely affect our financial condition and results of operations.
We may be subject to risks in connection with acquisitions, and the integration of significant acquisitions may be difficult.
In accordance with our business strategies, we periodically evaluate acquisitions of reserves, properties, prospects and leaseholds and other strategic transactions that appear to fit within our overall business strategy. The successful acquisition of producing properties requires an assessment of several factors, including:
•
recoverable reserves;
•
future crude oil and natural gas prices and their appropriate differentials;
•
development and operating costs; and
•
potential environmental and other liabilities.
The accuracy of these assessments is inherently uncertain. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and potential recoverable reserves. Inspections may not always be performed on every well, and environmental problems may not be observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. We often are not entitled to contractual indemnification for environmental liabilities and acquire properties on an “as is” basis.
Significant acquisitions and other strategic transactions may also involve other risks, including:
•
diversion of our management’s attention to evaluating, negotiating and integrating significant acquisitions and strategic transactions;
•
the challenge and cost of integrating acquired operations, information management and other technology systems and business cultures with those of our operations while carrying on our ongoing business;
•
difficulty associated with coordinating geographically separate organizations; and
•
the challenge of attracting and retaining personnel associated with acquired operations.
The process of integrating operations could cause an interruption of, or loss of momentum in, the activities of our business. Our senior management may be required to devote considerable amounts of time to this integration process, which will decrease the time they will have to manage our business. If our senior management is not able to effectively manage the integration process, or if any significant business activities are interrupted as a result of the integration process, our business could suffer.
In addition, even if we successfully integrate an acquisition, it may not be possible to realize the full benefits we may expect, including with respect to estimated proved reserves, production volume or cost savings from operating synergies, within our expected time frame. Anticipated benefits of an acquisition may also be offset by operating losses relating to changes in commodity prices in crude oil and natural gas industry conditions, risks and uncertainties relating to the exploratory prospects of the combined assets or operations, or an increase in operating or other costs or other difficulties. Failure to realize the benefits we anticipate from an acquisition may materially and adversely affect our business, results of operations and financial condition.
Our certificate of incorporation and bylaws, as well as Delaware law, contain provisions that could discourage acquisition bids or merger proposals, which may adversely affect the market price of our Class A voting common stock.
Certain provisions in our certificate of incorporation and bylaws could make it more difficult for a third party to acquire control of us, even if the change of control would be beneficial to our stockholders, including:
•
requiring advance notice of stockholder intention to put forth director nominees or bring up other business at a stockholders’ meeting;
•
requiring the affirmative vote of 66 2/3% of the voting power of all then outstanding shares of Class A common stock entitled to vote in order for stockholders to adopt, amend or repeal any provision of our bylaws or certificate of incorporation; and
•
providing that the number of directors shall be fixed from time to time by our board of directors pursuant to a resolution adopted by a majority of the total number of authorized directors (whether or not there exist any vacancies in previously authorized directorships) or by the stockholders. Newly created directorships resulting from any increase in our authorized number of directors will be filled only by a majority vote of our board of directors then in office, whether or not such directors number less than a quorum, and directors so chosen will serve for a term expiring at the annual meeting of stockholders at which the term of office to which they have been elected expires or until such director’s successor shall have been duly elected and qualified.
In addition, we entered into a Board Representation Agreement (“Board Representation Agreement”) with EF Realisation and securities purchase agreements with Chambers and Leucadia National Corporation pursuant to which these stockholders are each entitled to nominate a number of directors so long as certain ownership thresholds are maintained. Please read Note 14. Related Party Activities.
Our bylaws designate the Court of Chancery of the State of Delaware as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by our stockholders, which could limit our stockholders’ ability to obtain a favorable judicial forum for disputes with us or our directors, officers, employees or agents.
Our bylaws provide that, unless we consent in writing to the selection of an alternative forum, the Court of Chancery of the State of Delaware will, to the fullest extent permitted by applicable law, be the sole and exclusive forum for (i) any derivative action or proceeding brought on our behalf, (ii) any action asserting a claim of breach of a fiduciary duty owed by any of our directors, officers, employees or agents to us or our stockholders, (iii) any action asserting a claim arising pursuant to any provision of the Delaware General Corporation Law (the “DGCL”), our certificate of incorporation or our bylaws, or (iv) any action asserting a claim against us that is governed by the internal affairs doctrine, in each such case subject to such Court of Chancery having personal jurisdiction over the indispensable parties named as defendants therein. Any person or entity purchasing or otherwise acquiring any interest in shares of our capital stock will be deemed to have notice of, and consented to, the provisions of our certificate of incorporation described in the preceding sentence. This choice of forum provision may limit a stockholder’s ability to bring a claim in a judicial forum that it finds favorable for disputes with us or our directors, officers, employees or agents, which may discourage such lawsuits against us and such persons. Alternatively, if a court were to find these provisions of our bylaws inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions, which could adversely affect our business, financial condition or results of operations.
Item 1B.
Item 1B. Unresolved Staff Comments.
None.
Item 2.
Item 2. Properties.
Information regarding our properties is included in Item 1. Business under “- Overview - Our Eagle Ford Shale Properties”, “-Non-Core Properties”, “-Oil and Natural Gas Data”, and “-Oil and Natural Gas Production Prices and Costs” above and in “Note 3. Acquisitions and Divestitures” of the Notes to our Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data.”
In addition to the properties used in our operations, we lease office space in Fort Worth, Texas. On August 2, 2017, the Company closed on the purchase of an office building in Fort Worth, Texas, with an acquisition price approximating $10 million. In February 2018, the Company moved its corporate headquarters to the office building from the leased office space.
Item 3.
Item 3. Legal Proceedings.
From time to time, we are party to certain legal actions and claims arising in the ordinary course of business. While the outcome of these events cannot be predicted with certainty, management does not expect these matters to have a materially adverse effect on our financial position or results of operations.
Item 4.
Item 4. Mine Safety Disclosures.
Not applicable.
Executive Officers and Directors
The following table provides information regarding the Company’s executive officers and directors (ages are as of March 23, 2018):
Frank D. Bracken, III is our Chief Executive Officer. Mr. Bracken has served in this position since January 2012 and has served as a director and Chief Executive Officer of Lonestar Resources, Inc., our wholly-owned subsidiary, since January 2012. Mr. Bracken previously served as Senior Managing Director of Sunrise Securities from September 2008 to December 2011 and as Managing Director of Jefferies LLC from November 1999 to August 2008. During that time, Mr. Bracken led oil and natural gas transactions, spanning from public and private equity and debt offerings to joint ventures in the Haynesville Shale to one of the first purchases of a publicly-traded oil & gas company by a private equity firm. As Chief Financial Officer and a member of the board of directors at Gerrity Oil & Gas Corp, an NYSE-listed exploration and production company, Mr. Bracken was responsible for corporate budgeting and development, acquisitions, equity and debt financing in public and private offerings, and acquisitions and divestitures. Mr. Bracken holds a Bachelors of Arts degree from Yale University.
Barry D. Schneider is our Chief Operating Officer. Mr. Schneider has served in this position since May 2014. Prior to joining us, Mr. Schneider held the position of Vice President-Northern Region for Denbury Resources, Inc. from January 2012 to May 2014. Mr. Schneider was at Denbury for 15 years and held positions of increasing responsibility. After holding the positions of Vice President, Production & Operations, Mr. Schneider was promoted to Vice President-East Region in October 2009 and held that position until January 2012 when he became responsible for Denbury’s Northern Region business unit. Prior to Denbury, Mr. Schneider was employed by Wiser Oil and Conoco-Philips. Mr. Schneider received his B.S. in Natural Gas Engineering from Texas A&M-Kingsville in 1985.
Douglas W. Banister is our Chief Financial Officer. Mr. Banister has served in this position since January 2014 and previously served as Chief Accounting Officer of Lonestar Resources, Inc., our wholly-owned subsidiary, since August 2010. Mr. Banister is a Certified Public Accountant with 30 years of experience in finance, planning, negotiating and business development. Mr. Banister began his career in public accounting with Ernst & Young, where he served in various accountant roles between June 1984 and December 1987. Between December 1987 and April 1990, Mr. Banister served as Corporate Controller for D.R. Horton, Inc. and, between October 2004 and October 2005, served as VP of finance for Richmond American Homes. Mr. Banister holds a B.B.A. from Texas Wesleyan University with an emphasis in accounting.
Thomas H. Olle is our Vice President-Reservoir Engineering. Mr. Olle has served in this position since August 2010. Mr. Olle has over 35 years of oil and gas industry experience in multiple facets of the business, such as reservoir management and management of unconventional resource development projects including horizontal well field development and tertiary recovery projects. Mr. Olle also has significant experience with reserve evaluation and reporting, production engineering and operations, and business development functions including acquisitions, divestitures and new ventures. During his tenure at Encore Acquisition Company, Mr. Olle served as Vice President-Strategic Solutions and also held executive positions responsible for asset management and engineering. He also served as Senior Engineering Advisor for Burlington Resources from December 1985 to March 2002 and District Reservoir Engineer for Southland Royalty Company from May 1982 to December 1985. Mr. Olle holds a Bachelor’s of Science in Mechanical Engineering with Highest Honors from the University of Texas in Austin.
Jana Payne was appointed our Vice-President of Geosciences in November 2015, bringing over 25 years of experience in the oil and gas industry. Prior to joining us, Ms. Payne held the position of Senior Exploitation Manager and Geologist at Halcon Resources, Inc. from November 2012 to May 2015. Ms. Payne spent eight years at Petrohawk Energy Inc. from June 2004 to October 2012 (and subsequently BHP Billiton following its acquisition of Petrohawk) as Geologic Manager and Senior Geologist, where her initial mapping of the Eagle Ford shale led to the discovery of the first commercial Eagle Ford Shale well and acquisition of over 300,000 acres by the Company. Ms. Payne’s early career was as a geologist at Marathon Oil Co. and Petroleum Geo-Services, Inc. Ms. Payne has published works in learned journals and holds an MSc and BSc in geology from the University of Texas at Arlington.
Gregory R. Packer was appointed our Vice President, General Counsel & Corporate Secretary in October 2017. Prior to his appointment, Greg held the position of Senior Vice President, General Counsel & Corporate Secretary of Howard Energy Partners, a midstream company with operations in the Eagle Ford shale, Marcellus shale and Permian Basin. Before joining Howard Energy, Gregory practiced corporate and securities law at Latham & Watkins LLP, where he represented public and private companies and private equity sponsors in a wide range of transactions, including company formation, private and public mergers and acquisitions, as well as accessing equity and debt markets through private and public offerings, including initial public offerings. Mr. Packer is a graduate of the University of Chicago Law School, where he was a Lowenstein Scholar. Prior to attending law school, Mr. Packer obtained both Master’s and Bachelor’s degrees in accounting from Brigham Young University, where he was a G. Roger Victor Scholar.
John Pinkerton has served as a Director since August 2014 and became Chairman of the Board in August 2016. He was a director of Range Resources Corporation (NYSE: RRC) since 1989 and was Chairman of its Board of Directors from 2008 until January 2015. He joined Range as President in 1990 and served as Chief Executive Officer from 1992 until 2012. Prior to joining Range, Mr. Pinkerton served in various capacities at Snyder Oil Corporation for twelve years, including the position of Senior Vice President. Mr. Pinkerton received his Bachelor of Arts degree in Business Administration from Texas Christian University, where he now serves on the board of trustees, and a Master’s degree from the University of Texas at Arlington. During his 27-year tenure Range Resources grew from its small cap origins to be a $13 billion dollar enterprise with a pre-eminent position in the Marcellus Shale. As CEO of Range Resources, Mr. Pinkerton established the technical expertise to enable a drilling-led strategy complemented by bolt-on acquisitions where synergies would enhance growth. This resulted in a rapid and impressive increase in the scale of the business, and seven consecutive years of double-digit growth in both production and reserves (adjusted for debt). Mr. Pinkerton has widespread skill in the management, acquisition and divestiture of oil and gas properties-including related corporate financing activities-hedging, risk analysis and the evaluation of drilling programs. He has represented the industry in policy matters, serving on the executive committee of America’s Natural Gas Alliance. We believe that Mr. Pinkerton’s experience at oil and natural gas exploration companies qualify him for service on our board of directors.
Henry B. Ellis has served as a director since October 2016. Mr. Ellis presently serves as managing director and Chief Executive Officer of Bassett California Co. and The Bassett Company. He previously served as a director of several other boards including Bluebonnet Savings Bank and State National Bank, and served as President of Mbank, El Paso and Chairman and CEO of Grayson County Bank. Mr. Ellis received his Bachelor of Arts degree in Business Administration from Texas Christian University. We believe that Mr. Ellis’ financial experience in the banking industry qualifies him for service on our board of directors.
Daniel R. Lockwood has served as a director since May 2014. He also serves as Vice-President of New Tech Global and is responsible for overseeing and managing NTG engineering and project management services. Mr. Lockwood is a graduate of the Colorado School of Mines with a degree in Petroleum Engineering. Dan joined New Tech Engineering in 2000 and brings with him more than 35 years of engineering and management experience and is considered one of the industry’s leading experts in Shale Operations. We believe that Mr. Lockwood’s engineering and management experience in the oil and gas industry qualifies him for service on our board of directors.
John H. Murray has served as a director since October 2016. Mr. Murray is Co-Founder, Executive Chairman and Chief Compliance Officer of Ecofin Limited, roles he has held since its incorporation in June 1991. Before founding Ecofin Limited, John headed the corporate finance department and was a member of the management committee of Swiss Bank Corporation’s London- based investment banking business. Prior to joining Swiss Bank Corporation, he worked for Morgan Stanley Group Inc. holding various corporate finance positions in the firm’s offices in New York, London, Sydney and Melbourne, an office which he headed. Mr. Murray is a non-executive director of the Ecofin Vista Long/Short Fund Limited and the Ecofin Global Renewable Infrastructure Fund Limited and of the BlackRock Frontiers Investment Trust plc. Mr. Murray earned his BA in Economics from Williams College and an MBA from Harvard Business School. We believe that Mr. Murray’s financial experience in the investment banking industry qualifies him for service in our board of directors.
Matthew B. Ockwood has served as a director since November 2017. Mr. Ockwood is a Managing Director of Chambers Energy Management, a Houston-based investment firm focused on providing flexible capital to the energy industry. While at Chambers Energy, Mr. Ockwood has led or participated in the execution of dozens of distinct oil and gas transactions ranging from secured debt to common equity. Prior to joining Chambers Energy, Mr. Ockwood was employed by Lehman Brothers where he worked in the Natural Resources investment banking group. Mr. Ockwood holds a B.B.A in Finance, summa cum laude, and a Certificate in Leadership Study and Development from Texas A&M University. We believe that Mr. Ockwood’s financial experience in the investment banking industry for a diverse set of energy clients qualifies him for service on our board of directors.
Stephen H. Oglesby has served as a director since March 2017. Before joining the company, Mr. Oglesby served as Head of Energy, US Commercial Bank at Citibank, where he managed multiple offices and oversaw financial services provided to various private and public companies in the oil and gas industry, from December 2003 to January 2017. Mr. Oglesby previously served on the board of directors of various private companies, including Advanced Coiled Tubing, where he served as Chairman of its board of directors, Blackwell Plastics, and Goodman Manufacturing. Mr. Oglesby holds a Bachelor of Science in Accounting from Southern Illinois University. We believe that Mr. Oglesby is qualified to serve on our board of directors because of his extensive experience in financial services for diversified corporate and energy clients, and his background in finance and accounting.
Phillip Z. Pace has served as a director since June 2017. Mr. Pace is a Partner of Chambers Energy Management, a Houston-based investment firm focused on opportunistic credit investments in the energy industry. Mr. Pace has extensive experience in energy finance, including 19 years in oil and gas equity research. Mr. Pace joined Lehman Brothers in September 2008 after his retirement from Credit Suisse as Vice Chairman of the energy investment banking group. Mr. Pace received his Bachelor of Business Administration degree in Finance from Texas A&M University and has the Chartered Financial Analyst designation. We believe that Mr. Pace’s financial experience in the investment banking industry for a diverse set of energy clients qualifies him for service on our board of directors.
Dr. Christopher Rowland has served as a director of Lonestar since January 2013. He is also director of Special Situations for Ecofin Limited, where he is responsible for initiating and monitoring and realizing investments. Prior to joining Ecofin Limited in 2006, Dr. Rowland formed and led equity research teams over a 20-year period at several investment banks, including Merrill Lynch and Dresdner Klienwort Benson. Apart from his career as a research analyst, Dr. Rowland spent time setting up an alternative generator to buy coal-fired power stations in 1993. He has a Ph.D. for his research into the economics of UK oil taxation and holds a MSc (Econ) from the University of London and a BSc in Economics from the University of Bath. We believe that Dr. Rowland’s academic background in economics and his professional experience in finance and energy investment qualify him to serve on our board of directors.
Randy L. Wolsey has served as a director since January 2017. Mr. Wolsey is the founder and since February 2015 has been a co-owner of Lone Oak Minerals, a private company involved in the acquisition and selling of oil and gas minerals. Since January 2012, he has also been the owner of Solana, a private company involved in oil and gas and real estate investments. He is also the founder and since June 2006 has been a co-owner of Tanglewood Exploration, a private company involved in oil and gas exploration and production. He previously held management positions at companies including Glen Rose Oil & Gas and Justin Exploration. Mr. Wolsey received his Bachelor of Arts degree in Political Science from Midwestern State University. We believe that Mr. Wolsey’s experience in the oil and gas industry qualifies him for service on our board of directors.
There are no family relationships among any of our directors or executive officers.
PART II
Item 5.
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
Our Class A common stock is listed on Nasdaq under the ticker symbol “LONE” and began trading on July 5, 2016 on the Nasdaq Global Select Market. The following table sets forth, for the periods indicated, the high and low sales prices per common share as reported on Nasdaq:
The closing market price of our common stock on March 23, 2018 was $4.04 per share. As of March 23, 2018, there were estimated 1,552 shareholders of record of our Class A common stock.
Dividend Policy
We currently intend to retain any earnings to fund the operation and expansion of our business and do not anticipate paying any cash dividends on our common stock for the foreseeable future. The declaration and payment of any dividends in the future by us will be subject to the sole discretion of our board of directors and will depend upon many factors, including our financial condition, earnings, capital requirements of our operating subsidiaries, covenants associated with certain of our debt obligations, legal requirements, regulatory constraints and other factors deemed relevant by our board of directors. Moreover, if we determine to pay any dividend on common stock in the future, there can be no assurance that we will continue to pay such dividends. In addition, under our debt agreements, we are not permitted to pay cash dividends on our common stock without the prior written consent of the lenders.
Use of Proceeds
All sales of unregistered securities within the last fiscal year have been previously reported in our Quarterly Reports on Form 10-Q and/or Current Reports on Form 8-K.
Repurchase of Equity Securities
None.
Item 6.
Item 6. Selected Financial Data.
On July 5, 2016, Lonestar Resources US Inc. (the “Successor”) acquired all of the issued and outstanding ordinary shares of Lonestar Resources Limited (the “Predecessor”) pursuant to a Scheme of Arrangement under Australian law (the “Reorganization”). The following table presents selected historical consolidated financial data of the Successor and the Predecessor, as applicable, as of the dates and for the periods indicated. The selected historical consolidated financial data as of, and for the years ended, December 31, 2017 and 2016 are derived from the audited financial statements appearing elsewhere in this Annual Report on Form 10-K. Historical results are not necessarily indicative of future results.
The selected historical consolidated financial data presented below should be read in conjunction with “Risk Factors,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our consolidated financial statements and the related notes and other financial data included elsewhere in this Annual Report on Form 10-K.
(1)
Includes pre-tax impairments of assets of $33.4 and $33.9 million for the years ended December 31, 2017 and 2016, respectively.
(2)
Includes gain on redemption of bonds of $28.5 million for the year ended December 31, 2016.
(3)
During 2017, the Battlecat and Marquis acquisitions added $109.8 million to oil and gas properties, and results from their operations were included beginning June 15 ,2017.
Summary Historical Reserve and Operating Data
The following table presents estimated net proved oil, NGLs and natural gas reserves attributable to our properties and the Standardized Measure amounts associated with the estimated proved reserves attributable to our properties as of December 31, 2017 and 2016. We employ a staff of engineers and geoscientists that perform technical analysis of each producing well and undeveloped location. The staff uses industry-accepted practices to estimate, with reasonable certainty, the economically producible oil and natural gas reserves. The practices for estimating hydrocarbons-in-place include, but are not limited to, mapping, seismic interpretation, core analysis, log analysis, mechanical properties of formations, thermal maturity, well testing and flowing bottom-hole pressure analysis. We employ an independent petroleum engineer to estimate 100% of our proved reserves. The data below is based on our reserve report prepared by W.D. Von Gonten & Co. for our Eagle Ford Shale properties. The Standardized Measure and PV-10 amounts shown in the table are not intended to represent the current market value of our estimated oil and natural gas reserves. Therefore, those reserves are not included in the table below.
(1)
Our estimated net proved reserves and related Standardized Measure were determined using index prices for crude oil and natural gas, without giving effect to commodity derivative contracts, held constant throughout the life of our properties. The prices are based on the average prices during the 12-month period prior to the ending date of the period covered, determined as the unweighted arithmetic average of the prices in effect on the first day of the month for each month within such period, unless prices were defined by contractual arrangements, and are adjusted by lease for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price realized at the wellhead. Our estimated net proved NYMEX reserves were prepared on the same basis as our SEC reserves, except for the use of pricing based on closing monthly futures prices as reported on the NYMEX for oil and natural gas on December 31, 2017 rather than using the average of the first-day-of-the-month prices for the prior 12 months in accordance with SEC guidance. Prices were in each case adjusted by lease for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead.
(2)
Our NYMEX reserves were determined using index prices for oil and natural gas, without giving effect to derivative transactions. The average future prices for benchmark commodities used in determining our NYMEX reserves were $ 59.55/Bbl for oil for 2018, $56.22 for 2019, $56.22 for 2020, $53.79 for 2021, $52.29 for 2022, $51.70 for 2023, $51.59 for 2024, $51.76 for 2025, $52.07 for 2026, and escalated 3% thereafter and $2.87/MMBtu for natural gas for 2018, $2.81 for 2019, $2.81 for 2020, $2.82 for 2021, $2.85 for 2022, $2.89 for 2023, $2.93 for 2024, $2.97 for 2025, $3.01 for 2026 and escalated 3% thereafter. NGL pricing used in determining our NYMEX reserves were approximately 30% of future crude oil prices.
We believe that the use of forward prices provides investors with additional useful information about our reserves, as the forward prices are based on the market’s forward-looking expectations of oil and natural gas prices as of a certain date. NYMEX futures prices are not necessarily a projection of future oil and natural gas prices. Investors should be careful to consider forward prices in addition to, and not as a substitute for, SEC prices, when considering our oil and natural gas reserves.
(3)
One Boe is equal to six Mcf of natural gas or one Bbl of oil or NGLs based on an industry-standard approximate energy equivalency. This is a physical correlation and does not reflect a value or price relationship between the commodities.
(4)
PV-10 is a non-GAAP financial measure and represents the present value of estimated future cash inflows from proved crude oil and natural gas reserves, less future development and production costs, discounted at 10% per annum to reflect timing of future cash inflows. PV-10 differs from the Standardized Measure because it does not include the effect of future income taxes. See “Oil and Natural Gas Data-PV-10” above for more information and a reconciliation of our standardized measure to PV-10 to our standardized measure.
(5)
Standardized Measure is calculated in accordance with ASC Topic 932, Extractive Activities - Oil and Gas.
The data in the table above represent estimates only. Oil, NGLs and natural gas reserve engineering is inherently a subjective process of estimating underground accumulations of oil, NGLs and natural gas that cannot be measured exactly. The accuracy of any reserve estimate is a function of the quality of available data and engineering and geological interpretation and judgment. Accordingly, reserve estimates may vary from the quantities of oil, NGLs and natural gas that are ultimately recovered.
Future prices realized for production and costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates. The Standardized Measure and PV-10 amounts shown above should not be construed as the current market value of our estimated oil, NGLs and natural gas reserves. The 10% discount factor used to calculate Standardized Measure, which is required by Financial Accounting Standards Board pronouncements, is not necessarily the most appropriate discount rate. The present value, no matter what discount rate is used, is materially affected by assumptions as to timing of future production, which may prove to be inaccurate.
Item 7.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
The following discussion and analysis should be read in conjunction with our consolidated financial statements and the related notes and other financial information included elsewhere in this Annual Report on Form 10-K. The following discussion contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Important factors that could cause or contribute to such differences include, but are not limited to, market prices for oil, natural gas and NGLs, production volumes, estimates of proved reserves, capital expenditures, economic and competitive conditions, regulatory changes and other uncertainties, as well as those factors discussed below and elsewhere in this Annual Report on Form 10-K, particularly in “Risk Factors” and “Cautionary Statement Regarding Forward-Looking Statements,” all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. We do not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law.
General Overview
We are 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 (the “Eagle Ford”), where we have accumulated approximately 78,196 gross (58,262 net) acres in what we believe to be the formation’s crude oil and condensate windows, as of December 31, 2017. We operate in one industry segment, which is the exploration, development and production of oil, NGLs and natural gas. Our current operational activities and consolidated revenues are generated from markets exclusively in the United States, and, as of December 31, 2017, we had no long-lived assets located outside the United States.
Operational Results. Total production for the year ended December 31, 2017, increased 10% from 2016, to 6,495 Boe/d, primarily due to the acquisition of our Marquis and Battlecat properties (see below) and placement of additional 12 gross / 11.3 net Eagle Ford wells onstream over the course of 2017.
See the table below for details of our drilling and completion activity:
In 2017, all of our drilling and completion capital expenditures were related to the Eagle Ford where, as of December 31, 2017, we were operating one rig. At December 31, 2017, our estimated net proved oil and gas reserves across all of our properties were 73.6 MMBoe, an increase of 33.1 MMBoe, or 82%, from December 31, 2016. Lonestar added 29.9 MMBoe through acquisitions, 4.0 MMBoe through extensions and discoveries, and 1.5 MMBoe through positive reserve revisions in the Eagle Ford while producing 2.3 MMBoe of production for the year ended December 31, 2017. See “Item 1. Business-Oil and Natural Gas Data-Estimated Proved Reserves” for additional discussion.
Our current 2018 capital expenditure plan includes $95.0 million to $100.0 million for drilling and completion and $10 million for leasehold acquisition expenditures. We have historically grown our Eagle Ford leasehold position through acquisitions, organic leasing activities, farm-ins and other structures. We believe our management team’s extensive experience in the play provides us with relationships and contacts that could serve as a platform for expanded opportunities to grow our acreage footprint.
Acquisition Activity. On May 30, 2017, Lonestar announced that it entered into definitive agreements with Battlecat Oil & Gas LLC (“Battlecat”) and SN Marquis LLC (“Marquis”) to acquire oil and gas properties in the Eagle Ford Shale play for a total purchase price of approximately $116.6 million, consisting of $105.0 million in cash and approximately 2.7 million shares of Lonestar Series B Preferred Stock. Lonestar closed the acquisitions on June 15, 2017. After closing adjustments, Lonestar paid total consideration of $99.0 million in cash and approximately 2.7 million shares of Lonestar Series B Preferred Stock.
Series A & B Preferred Stock. On June 15, 2017, the Company entered into an amended and restated securities purchase agreement (the “A&R SPA”) with Chambers Energy Capital (“Chambers”). On the same day, the Company closed the transactions contemplated by the A&R SPA (the “SPA Closing”) and issued to Chambers 5,400 shares of Series A-1 Preferred Stock and 74,600 shares of Series A-2 Preferred Stock. Pursuant to the terms of the SPA, the Company agreed to use commercially reasonable efforts to hold a stockholder meeting (the “Stockholder Meeting”) by no later than December 15, 2017 and to obtain at the meeting stockholder approval of the issuance of shares of the Company’s Class A voting common stock issuable upon conversion of all shares of Series A-1 Preferred Stock and Series A-2 Preferred Stock (upon their conversion to shares of Series A-1 Preferred Stock) issued or issuable pursuant to the A&R SPA (the “Stockholder Approval”). The Stockholder Meeting was held on November 3, 2017, and Stockholder Approval was obtained.
Senior Secured Credit Facility. As of December 31, 2017, the borrowing base and lender commitments for the $500 million Senior Secured Credit Facility with Citibank, N.A., as administrative agent, and other lenders party thereto (the “Credit Facility”) were $160.0 million. The borrowing base under the Credit Facility is determined semi-annually as of May 1 and November 1. On January 4, 2018, the Seventh Amendment and Limited Waiver, Borrowing Base Redetermination Agreement, and Amendment No. 7 to Credit Agreement dated January 4, 2018 (the “Seventh Amendment”) reaffirmed the borrowing base at $160.0 million. This January 2018 redetermination was deemed to constitute the regularly scheduled November 1, 2017 redetermination.
Second Lien Notes. During 2016, LRAI issued $38.0 million in aggregate principal amount of Second Lien Notes and the Company issued warrants to purchase 760,000 shares of its Class A common stock. The Company recorded an equity warrant liability of approximately $5.1 million which was the fair value of the warrants at the date of issuance. Proceeds from the Second Lien Notes issuance were used to repurchase approximately $68.2 million in aggregate principal amount of the 8.750% Senior Notes in privately negotiated open market repurchases with holders of such notes, and to pay related fees and expenses related to the foregoing. The repurchase amounts paid were approximately $36.2 million in cash. Net of related fees, such repurchases resulted in a gain on debt extinguishment of approximately $28.5 million. In December 2016, LRAI repaid $21.0 million principal of the Second Lien Notes with proceeds from the 2016 Common Stock Offering. In June 2017, LRAI repaid the remaining $17.0 million principal of the Second Lien Notes including an early payment premium of approximately $1.1 million with borrowings from the Company’s Senior Secured Credit Facility.
Financial Results. We recorded a net loss for the years ended December 31, 2017 and 2016 of $38.7 million, or $1.92 per share, and $94.3 million, or $11.64 per share, respectively. The loss for the year ended December 31, 2017 was driven by a $33.4 million impairment charge, a non-cash $17.2 million loss on our commodity derivative contracts related to the change in fair value of our derivative contracts and a $3.1 million gain on settlement of our commodity derivative contracts, which were partially offset by a $29.7 million income tax benefit. The loss for the year ended December 31, 2016 was driven by a $33.9 million impairment charge, $8.7 million of hedging losses on derivatives and $49.6 million of tax expense for a net operating loss write-down, which were partially offset by a $28.5 million gain on bond disposal.
Operating Results
The following discussion relates to our consolidated results of operations, financial condition and capital resources. You should read this discussion in conjunction with our consolidated financial statements and the notes thereto. Comparative results of operations for the period indicated are discussed below.
Results of operations for the year ended December 31, 2017 compared to the year ended December 31, 2016
Net Production
Production volumes in 2017 were 6,495 Boe/d, an increase of 10% from 5,899 Boe/d for 2016. The increase in our average daily production was a result of 1) the acquisition of our Marquis and Battlecat properties that closed on June 15, 2017 and 2) an increase in the number of wells brought on-line in 2017 versus 2016. For the year ended December 31, 2017, approximately 67% of our production was crude oil, 16% was NGLs and 17% was natural gas.
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Net production from our Eagle Ford assets averaged approximately 6,495 Boe/d for the year ended December 31, 2017, an 18% increase over the 5,495 Boe/d for the year ended December 31, 2016. Approximately 83% of our Eagle Ford production for the year ended December 31, 2017, was liquid hydrocarbons.
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There was no production from our conventional properties in 2017 due to the divestiture of all conventional properties in October 2016.
Average Sales Price
The average wellhead price for our production in 2017 was $39.77 per Boe, which was 48% higher than the average price in 2016. Reported wellhead realizations were driven higher by an increase (approximately 18%) in WTI pricing and an increase (approximately 70%) in the Louisiana Light Sweet (“LLS”) spread between the periods. Additionally, pricing significantly increased due to our product mix becoming much more oil-centric, changing from 55% oil, 20% NGLs, and 25% natural gas in 2016 to 67% oil, 16% NGLs, and 17% natural gas in 2017. While the benchmark price rose sharply, our crude oil hedge positions were still able to add $1.97 per Bbl to our realizations or $1.31 per Boe.
Revenues
Wellhead revenue in 2017 was $94.1 million, a 62% increase from $58.0 million in 2016. Even with the significant increase in benchmark prices, we were able to realize favorable crude oil hedge cash settlements, which added $3.1 million in gains on commodity derivatives for the year ended December 31, 2017.
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Wellhead revenues for our Eagle Ford assets in 2017 were $94.1 million, a 74% increase from $53.9 million in 2016 as a result of a 48% increase in wellhead price realizations coupled with a 18% increase in production in 2017 largely due to our acquisitions of the Battlecat and Marquis properties in June 2017.
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The Conventional properties were sold in October 2016.
Costs and Expenses
The table below presents a detail of costs and expenses for the periods indicated:
Lease Operating and Gas Gathering Expenses
Lease operating expenses are the costs incurred in the operation of producing properties and workover costs. Expenses for direct labor, water injection and disposal, utilities, materials and supplies comprise the most significant portion of our lease operating expenses. Lease operating expenses do not include general and administrative expenses or production and ad valorem taxes.
Our total lease operating expenses in 2017 were $16.8 million, an increase of 3% from $16.2 million in 2016. This increase was largely due to an 10% increase in production. On a unit-of-production basis, our lease operating expenses in 2017 was $7.07 per Boe, a decrease of 6% from $7.52 per Boe in 2016 due to operational efficiencies created from our Battlecat and Marquis acquisitions.
Production and Ad Valorem Taxes
Production and ad valorem taxes are paid on produced crude oil and natural gas based upon a percentage of gross revenues or at fixed rates established by state or local taxing authorities. In general, the production taxes we pay correlate to the changes in oil and natural gas revenues. We are also subject to ad valorem taxes in the counties where our production is located. Ad valorem taxes are generally based on the valuation of our oil and natural gas properties.
Our total production and ad valorem taxes in 2017 were $5.5 million, a 68% increase from $3.3 million in 2016, which correlates with the 62% increase in wellhead revenues.
Rig Standby Expense
During the year ended December 31, 2017, we incurred rig standby expense of $0.6 million related to the drilling rig we had under contract, a decrease of 73% from $2.3 million in 2016.
Depreciation, Depletion, Amortization and Accretion (DD&A)
Capitalized costs attributed to our proved properties are subject to depreciation and depletion. Depreciation and depletion of the cost of oil and natural gas properties is calculated using the unit-of-production method aggregating properties on a field basis. For leasehold acquisition costs and the cost to acquire proved properties, the reserve base used to calculate depreciation and depletion is the sum of proved developed reserves and proved undeveloped reserves. For development costs, the reserve base used to calculate depletion and depreciation is proved developed reserves only. Other property and equipment are carried at cost, and depreciation is calculated using the straight-line method over the estimated useful lives of the assets, ranging from 3 to 5 years.
DD&A in 2017 was $52.9 million, a 12% increase from $47.1 million in 2016, primarily due to a 10% increase in production in 2016.
Impairment of Oil and Gas Properties
The Company evaluates impairment of proved and unproved oil and gas properties on an area basis. On this basis, certain fields may be impaired because they are not expected to recover their entire carrying value from future net cash flows. As a result of this evaluation, we recorded impairment of unproved oil and natural gas properties of approximately $28.6 million and $4.8 million for the years ended December 31, 2017 and 2016, respectively, and impairment of proven oil and gas properties of $4.8 million and $29.1 million for the years ended December 31, 2017 and 2016, respectively. If pricing declines, it is reasonably likely that we may have to record impairment of our oil and gas properties subsequent to December 31, 2017.
General and Administrative (G&A) Expenses
G&A expense in 2017 was $11.0 million, a 3% decrease from $11.3 million in 2016. On a per Boe basis, G&A expense in 2017 was $4.64, a decrease of 12% from $5.24 in 2016. This decrease was primarily due to operational efficiencies created by our Battlecat and Marquis Acquisitions.
Interest Expense
Our interest expense in 2017 was $20.8 million, a decrease of 9% from $22.8 million in 2016, due primarily to the repurchase of $68.2 million of 8.750% Senior Notes in the second half of 2016.
Losses on Derivative Financial Instruments
In the year ended December 31, 2017, we recognized a non-cash $17.2 million loss on our commodity derivative contracts related to the change in fair value of our derivative contracts and a $3.1 million gain on settlement of our commodity derivative contracts. In the year ended December 31, 2016, we recognized a non-cash $36.4 million loss on our commodity derivative contracts related to the change in fair value of our derivative contracts and a $27.7 million gain on settlement of our commodity derivatives contracts. Settlement of the crude oil hedge positions in 2017 added $1.97 per barrel to crude oil price realization compared to $23.54 in 2016.
Income Taxes
As a result of the net loss before income tax of $68.4 million in the year ended December 31, 2017 and net loss before income tax of $66.9 million from the year ended December 31, 2016, we recorded income tax benefit of $29.7 million and an income tax expense of $27.4 million in the year ended December 31, 2017 and 2016, respectively. Our 2017 tax provision was affected by a $6.3 million benefit due to revaluation of our deferred tax assets and liabilities (see below), while our 2016 provision was affected by a write-down of $49.6 million for net operating losses.
Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to reverse. As a result of the reduction in the U.S. corporate income tax rate from 35% to 21% under the Tax Cuts and Jobs Act (the “Act”), we revalued our deferred tax assets and liabilities at December 31, 2017, which resulted in a $6.3 million benefit.
The corporate alternative minimum tax (“AMT”) for tax years beginning in January 1, 2018 has also been repealed. The Act provides that existing AMT credit carryovers are refundable beginning in 2018. As of December 31, 2017, the Company had AMT credit carryovers of $2.4 million that are expected to be fully refunded by 2022.
The deductibility of interest expense for tax years beginning in January 1, 2018 has been limited to 30% of earnings before interest, taxes, depreciation, and amortization for the four years ending 2021. Deductibility of interest expense for tax years beginning in January 1, 2022 will then be limited to 30% of earnings before interest and taxes thereafter. We have not yet evaluated the impact of this provision.
The Act is a comprehensive bill containing other provisions, and the ultimate impact from the Act may differ from our estimates as of December 31, 2017 due to changes in the interpretations and assumptions made by us as well as additional regulatory guidance that may be issued.
Liquidity and Capital Resources
We expect that our primary source of liquidity will be cash flows generated by operating activities and borrowings under our $500,000,000 Credit Facility.
We have historically financed our acquisition and development activity through cash flows generated by operating activities, borrowings under our Credit Facility, and equity and bond issuances.
At December 31, 2017, we had $2.5 million in cash and cash equivalents and approximately $17.4 million of availability under our Credit Facility. We believe that our existing cash and cash equivalents, cash expected to be generated from operations and the availability of borrowing under our Credit Facility will be sufficient to meet our liquidity requirements, operating expenses, anticipated capital expenditures and payments due under our existing credit facility and notes outstanding for at least the next 12 months.
On January 4, 2018, the Company issued $250.0 million of 11.250% senior notes due 2023 (the “11.250% Senior Notes”) to U.S.-based institutional investors. The net proceeds of $244.4 million were used to fully retire the 8.750% Senior Notes, which included principal, interest and prepayment premium of approximately $162 million. The remaining net proceeds were used to reduce borrowings under the Credit Facility by $80 million.
Senior Secured Credit Facility
On July 28, 2015, LRAI closed a Credit Agreement for a $500 million Senior Secured Credit Facility with Citibank, N.A., as administrative agent, and other lenders party thereto. The Credit Facility had a maturity date of October 16, 2018 as of December 31, 2017. Consequent to redeeming the 8.750% Senior Notes (as defined below) in January 2018, the Credit Facility’s maturity date was extended to July 28, 2020. As of December 31, 2017, and 2016, $142.1 million and $43.5 million was borrowed, respectively, under the Credit Facility. Borrowing availability was approximately $17.4 million at December 31, 2017.
The Credit Facility may be used for loans and, subject to a $2.5 million sub-limit, letters of credit, and provides for a commitment fee of 0.375% to 0.5% based on the unused portion of the borrowing base under the Credit Facility.
As of December 31, 2017, the borrowing base and lender commitments for the Credit Facility were $160.0 million. The borrowing base under the Credit Facility is determined semi-annually as of May 1 and November 1. On January 4, 2018, the Seventh Amendment and Limited Waiver, Borrowing Base Redetermination Agreement, and Amendment No. 7 to Credit Agreement dated January 4, 2018 (the “Seventh Amendment”) reaffirmed the borrowing base at $160.0 million. This January 2018 redetermination constituted the regularly scheduled November 1 determination.
Borrowings under the Credit Facility, at LRAI’s election, bear interest at either: (i) an alternate base rate (“ABR”) equal to the higher of (a) the Prime Rate, (b) the Federal Funds Effective Rate plus 0.5% per annum, and (c) the adjusted LIBO rate of a three-month interest period on such day plus 1.0%; or (ii) the adjusted LIBO rate, which is the rate stated on Reuters screen LIBOR01 page, for one, two, three, six or twelve months, as adjusted for statutory reserve requirements for Eurocurrency liabilities, plus, in each of the cases described in clauses (i) and (ii) above, an applicable margin ranging from 1.50% to 2.50% for ABR loans and from 2.50% to 3.50% for adjusted LIBO rate loans (5.13% at December 31, 2017).
Subject to certain permitted liens, LRAI’s obligations under the Credit Facility have been secured by the grant of a first priority lien on no less than 80% of the value of the proved oil and gas properties of the Company and its subsidiaries (currently 90%).
The Credit Facility contains two financial covenants, as defined in the Credit Facility: (a) a minimum debt to EBITDAX ratio (discussed further below) and (b) a current ratio of not less than 1.0 to 1.0. As of December 31, 2017, the Company was in compliance with the minimum debt to EBITDAX ratio; however, the current ratio as of December 31, 2017 was approximately 0.7 to 1.0 due to low availability under the Credit Facility. Upon closing of the 11.250% Senior Notes, as defined below, in January 2018, the Credit Facility’s outstanding balance was paid down by $80.0 million, which increased the Credit Facility’s availability to a level sufficient for purposes of the current ratio. The Company obtained a limited waiver agreement for the current ratio violation from the Credit Facility’s lenders prior to issuance of the Company’s Form 10-K and Annual Report.
Effective as of July 27, 2016, LRAI entered into the Third Amendment to Credit Agreement and Limited Waiver (the “Third Amendment”) to (a) permit LRAI to incur the second lien obligations contemplated by the Securities Purchase Agreement with Leucadia National Corporation and others (as described below) and LRAI’s contemplated use of proceeds thereof, (b) increase the applicable margin for Eurodollar and ABR loans and letter of credit fees by 0.75% across all levels of the previously applicable pricing grid, (c) modify the fee payable on the actual daily unused amount of the aggregate commitments to a flat 0.50% across all levels of the pricing grid, (d) increase the minimum percentage of the value of LRAI’s oil and gas properties that must be mortgaged as collateral for the obligations under the Credit Agreement and the other loan documents from 80% to 90%, (e) modify the maximum leverage ratio thresholds from 4.0 to 1.0 to (i) 4.75 to 1.0 for the four quarterly periods ending June 30, 2016, (ii) 4.50 to 1.0 for the four quarterly periods ending September 30, 2016, (iii) 4.25 to 1.0 for the four quarterly periods ending December 31, 2016 and (iv) 4.00 to 1.0 for all periods thereafter, (f) prohibit distributions to the Predecessor for selling, general and administrative expenses after September 30, 2016 and (g) amend certain other provisions of the Credit Agreement as more specifically set forth in the Amendment.
In connection with closing the Marquis Acquisition and the Battlecat Acquisition, on June 15, 2017, LRAI entered into the Sixth Amendment and Joinder to Credit Agreement (the “Sixth Amendment”) to (i) increase the borrowing base from $112 million to $160 million until redetermined or adjusted in accordance with the Credit Agreement, (ii) modify the maximum leverage ratio threshold to be 4.0 to 1.0 for all periods, starting with the fiscal quarter ending September 30, 2017, and providing that EBITDAX (as defined in the Credit Agreement) shall be calculated at the end of each fiscal quarter using the results of the twelve-month period ending with that fiscal quarter end; provided, that EBITDAX shall be calculated (x) at the end of the fiscal quarter ending September 30, 2017 using an amount equal to the EBITDAX for such fiscal quarter, multiplied by four, (y) at the end of the fiscal quarter ending December 31, 2017 using an amount equal to the EBITDAX for the two fiscal quarter period ended on such date, multiplied by two and (z) at the end of the fiscal quarter ending March 31, 2018 using an amount equal to the EBITDAX for the three fiscal quarter period ended on such date, multiplied by four-thirds, (iii) permit LRAI to declare and pay dividends to the Company equal to the amount of any cash dividends declared and payable in accordance with the terms of the Company’s Certificate of Designations of Convertible Participating Preferred Stock, Series A-1, and Certificate of Designations of Convertible Participating Preferred Stock, Series A-2, subject to certain specified terms and conditions and (iv) amend certain other provisions of the Credit Agreement as more specifically set forth in the Sixth Amendment.
Securities Purchase Agreement and Second Lien Notes
On August 2, 2016, LRAI and the Company entered into a Securities Purchase Agreement (the “Purchase Agreement”) with Juneau Energy, LLC, as initial purchaser (the “Initial Purchaser”), Leucadia National Corporation (“Leucadia”), as guarantor of the Initial Purchaser’s obligations, the other purchasers party thereto (collectively, along with the Initial Purchaser, the “Purchasers”) and Jefferies, LLC, in its capacity as the collateral agent for the Purchasers, relating to the issuance and sale of (i) up to $49,900,000 aggregate principal amount of LRAI’s 12% senior secured second lien notes due 2021 (the “Second Lien Notes”) and (ii) five-year warrants to purchase up to an aggregate 998,000 shares of the Company’s Class A common stock at a price equal to $5.00 per share (the “Warrants” and, together with the Second Lien Notes, the “Securities”). The balance of these notes and warrants is reflected in our long-term debt - related parties and equity warrant liability - related parties on the face of the balance sheet.
The Second Lien Notes are secured by second-priority liens on substantially all of LRAI’s and its subsidiaries’ assets to the extent such assets secure obligations under the Credit Facility. During 2016, the LRAI issued $38.0 million in aggregate principal amount of Second Lien Notes and the Company issued Warrants to purchase 760,000 shares of the company’s Class A common stock. The Company recorded an equity warrant liability of approximately $5.1 million which was the fair value amount at the date of issuance. Proceeds from the Second Lien Notes issuance were used to repurchase approximately $68.2 million in aggregate principal amount of the 8.750% Senior Notes in privately negotiated open market repurchases with holders of such notes, and to pay related fees and expenses related to the foregoing. The repurchase amounts paid were approximately $36.2 million in cash. Net of related fees, such repurchases resulted in a gain on debt extinguishment of approximately $28.5 million.
In December 2016, LRAI repaid $21.0 million principal of the Second Lien Notes with proceeds from the offering of the Company’s Class A voting common stock that was completed on December 22, 2016 pursuant to a Registration Statement on Form S-1 (File No. 333-214265), which was declared effective on December 15, 2016 (the “2016 Common Stock Offering”). In June 2017, LRAI repaid the remaining $17.0 million principal of the Second Lien Notes including an early payment premium of approximately $1.1 million with borrowings from the Company’s Credit Facility.
2016 Common Stock Offering
On December 22, 2016, the Company issued 13.8 million shares of Class A common stock for approximately $79.4 million in gross proceeds. The Company applied a portion of the net proceeds from the offering to repurchase $21.0 million of its Second Lien Notes at a price of 101% of par, while also repaying $49.0 million of the Senior Secured Credit Facility and retiring a $2.1 million Repurchase Facilitation Agreement with Seaport Global.
Working Capital
Our working capital, which we define as current assets minus current liabilities, totaled ($44.2) million and ($15.9) million as of December 31, 2017 and December 31, 2016, respectively. Our collection of receivables has historically been timely, and losses associated with uncollectible receivables have historically not been significant. Our cash balances totaled $2.5 million and $6.1 million as of December 31, 2017 and 2016, respectively. Due to the amounts that accrue related to our drilling program, we may incur working capital deficits in the future. We expect that our cash flows from operating activities and availability under our credit agreement will be sufficient to fund our working capital needs. We expect that our pace of development, production volumes, commodity prices and differentials to NYMEX prices for our oil and natural gas production will be the largest variables affecting our working capital.
Historical Cash Flows
The following table summarizes our cash flows for the periods indicated, as shown on the consolidated statements of cash flows:
Net Cash Provided By Operating Activities
Net cash provided by operating activities increased $19.2 million from $24.3 million in the year ended December 31, 2016 to $43.4 million in the year ended December 31, 2017. Excluding changes in operating assets and liabilities, net cash provided by operating activities increased to $36.2 million for the year ended December 31, 2017 from $31.2 million for the year ended December 31, 2016. This increase was primarily attributable to higher oil and natural gas production and higher commodity prices realized during the year ended December 31, 2017, as compared to the year ended December 31, 2016.
Net Cash Used In Investing Activities
Net cash used in investing activities increased $181.0 million from $27.8 million in the year ended December 31, 2016 to $208.7 million in the year ended December 31, 2017. This was due to a $109.4 million increase in the acquisition of oil and gas properties as a result of the Marquis and Battlecat acquisitions, a $42.5 million increase in the development of oil and gas properties, and $12.9 million increase in purchases of other property and equipment offset by a decrease of $16.2 million in proceeds from sales of oil and gas properties for the year ended December 31, 2017.
Net Cash Provided By Financing Activities
Net cash provided by financing activities increased $156.5 million from $5.3 million provided during the year ended December 31, 2016 to $161.8 million provided in the year ended December 31, 2017. This was due to an increase in bank borrowings, net of payments, of approximately $152.6 million, $77.8 million in proceeds from the sale of preferred stock and a decrease in payments of debt issuance costs of $2.2 million, offset by a decrease in proceeds of $72.8 million from the issuance of Class A voting common stock and costs to issue equity of $3.3 million for the year ended December 31, 2017.
Derivative Instruments
The following table provides a summary of our derivative contracts as of December 31, 2017:
The above derivative contracts aggregate to 1,713,500 barrels or 4,695 Bbls/d for 2018, 1,471,100 Bbls or 4,030 Bbls/d for 2019, and 203,600 Bbls or 1,120 Bbls/d for 2020. Our 2018 derivative contracts consist of 4,195 Bbls/d swaps at a volume-weighted average price of $51.83 and two-way collars covering 500 Bbls/d with a price ceiling of $59.45. Our 2019 derivative contracts consist of 4,030 Bbls/d swaps at a volume weighted-average price of $49.64. Our 2020 derivative contracts consist of 1,119 Bbls/d from January thru June at a price of $48.90 per Bbl.
In January 2018, we entered into additional WTI crude oil swaps for 2018, 2019, and 2020. The 2018 WTI swaps cover a total of 230,700 barrels for the period of March 2018 through December 2018 at an average strike price of $61.77. The addition of these swaps increased our total 2018 crude oil hedge position coverage to a total of approximately 5,326 Bbls/d at an average strike price of $53.72 per barrel. The 2019 WTI swaps cover a total of 328,500 barrels for the period of January 2019 through December 2019 at an average strike price of $58.25. These additional 2019 swaps increased our total 2019 crude oil hedge position coverage to a total of approximately 4,930 Bbls/d at an average strike price of $51.21. The 2020 WTI swaps cover a total of 411,200 barrels for the period of January 2020 through December 2020 at an average strike price of $55.06. These additional 2020 swaps increased our total 2020 crude oil hedge position coverage to a total of approximately 1,680 Bbls/d at an average strike price of $53.02.
The above natural gas derivative contract equates to 5,000 MMBtu per day for 2018.
Indebtedness
As of December 31, 2017, we had an aggregate of $301.2 million of indebtedness, including $142.1 million drawn on our Credit Facility, $151.8 million (less an unamortized discount of $0.9 million and debt issuance costs of $0.5 million) on our 8.750% Senior Notes, $7.9 million of mortgage debt, and $0.8 million of other long-term notes.
On January 4, 2018, the Company issued $250.0 million of 11.250% Senior Notes to U.S.-based institutional investors. The net proceeds of $244.4 million were used to fully retire the 8.750% Senior Notes, which included principal, interest and a prepayment premium of approximately $162 million. The remaining net proceeds were used to reduce borrowings under the Credit Facility.
Senior Secured Credit Facility
As of December 31, 2017, LRAI had outstanding borrowings of approximately $142.1 million under the Credit Facility, which was subject to an average interest rate of approximately 5.13% during the year ended December 31, 2017. Additionally, the Credit Facility may be used for loans and, to a $2.5 million sub-limit, letters of credit, and provides for a commitment fee of 0.375% to 0.5% based on the unused portion of the borrowing base under the Credit Facility. As of December 31, 2017, the borrowing base and lender commitments for the Credit Facility were $160.0 million. The borrowing base under the Credit Facility is determined semi-annually as of May 1 and November 1. On January 4, 2018, the Seventh Amendment and Limited Waiver, Borrowing Base Redetermination Agreement, and Amendment No. 7 to Credit Agreement dated January 4, 2018 (the “Seventh Amendment”) reaffirmed the borrowing base at $160.0 million. This January 2018 redetermination was deemed to constitute the regularly scheduled November 1, 2017 redetermination.
8.750% Senior Notes
LRAI issued $220 million aggregate principal amount of the 8.750% Senior Notes in April 2014 under an indenture among LRAI, its subsidiary guarantors and Wells Fargo Bank, National Association, as trustee. Lonestar Resources US Inc. is not a party to the indenture.
The 8.750% Senior Notes mature on April 15, 2019 and accrue interest at a rate of 8.750% per annum, payable semi-annually in arrears on April 15 and October 15 of each year until the maturity date. The 8.750% Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by each subsidiary of LRAI.
During 2016, the Company repurchased $68.2 million in aggregate principal amount of the 8.750% Senior Notes resulting in approximately $28.5 million gain on disposal, bringing the balance to $151.8 million as of December 31, 2016.
In January 2018, the Company redeemed the 8.750% Senior Notes in whole using the proceeds from the 11.250% Senior Notes, as defined below.
11.250% Senior Notes
On January 4, 2018, the Company issued $250.0 million of 11.250% senior notes due 2023 (the “11.250% Senior Notes”) to U.S.-based institutional investors. The net proceeds of $244.4 million were used to fully retire the 8.750% Senior Notes, which included principal, interest and prepayment premium of approximately $162 million. The remaining net proceeds were used to reduce borrowings under the Credit Facility.
The 11.250% Senior Notes mature on January 1, 2023, and bear interest at the rate of 11.250% per year, payable on January 1 and July 1 of each year, beginning July 1, 2018. At any time prior to January 1, 2021, the Company may, on any one or more occasions, redeem up to 35% of the aggregate principal amount of the 11.250% Senior Notes with an amount of cash not greater than the net cash proceeds of certain equity offerings at a redemption price equal to 111.250% of the principal amounts redeemed, plus accrued and unpaid interest, provided that at least 65% of the aggregate principal amount of 11.250% Senior Notes originally issued remains outstanding immediately after such redemption and the redemption occurs within 180 days of the closing date of such equity offering.
At any time prior to January 1, 2021, the Company may, on any one or more occasions, redeem all or a part of the 11.250% Senior Notes at a redemption price equal to 100% of the principal amount redeemed, plus a “make-whole” premium and accrued and unpaid interest. On and after January 1, 2021, the Company may redeem the 11.250% Senior Notes, in whole or in part, plus accrued and unpaid interest, at the following redemption prices: 108.438% after January 1, 2021; 105.625% after January 1, 2022; and 100% after July 1, 2022. The indenture contains certain restrictions on the Company’s ability to incur additional debt, pay dividends on the Company’s common stock, make investments, create liens on the Company’s assets, engage in transactions with affiliates, transfer or sell assets, consolidate or merge, or sell substantially all of the Company’s assets.
Securities Purchase Agreement and Second Lien Notes
On August 2, 2016, LRAI and the Company entered into a Securities Purchase Agreement (the “Purchase Agreement”) with Juneau Energy, LLC, as initial purchaser (the “Initial Purchaser”), Leucadia National Corporation (“Leucadia”), as guarantor of the Initial Purchaser’s obligations, the other purchasers party thereto (collectively, along with the Initial Purchaser, the “Purchasers”) and Jefferies, LLC, in its capacity as the collateral agent for the Purchasers, relating to the issuance and sale of (i) up to $49.9 million aggregate principal amount of the Second Lien Notes and (ii) five-year warrants to purchase up to an aggregate 998,000 shares of the Company’s Class A common stock at a price equal to $5.00 per share.
During 2016, LRAI issued $38.0 million in aggregate principal amount of Second Lien Notes and the Company issued warrants to purchase 760,000 shares of its Class A common stock. The Company recorded a warrant liability of approximately $5.1 million which was the fair value amount at the date of issuance. Proceeds from the Second Lien Notes issuance were used to repurchase approximately $68.2 million in aggregate principal amount of the 8.750% Senior Notes in privately negotiated open market repurchases with holders of such notes, and to pay related fees and expenses related to the foregoing. The repurchase amounts paid were approximately $36.2 million in cash. Net of related fees, such repurchases resulted in a gain on debt extinguishment of approximately $28.5 million.
In December 2016, LRAI repaid $21.0 million principal of the Second Lien Notes. In June 2017, LRAI repaid the remaining $17.0 million principal of the Second Lien Notes including an early payment premium of approximately $1.1 million with borrowings from the Company’s Senior Secured Credit Facility.
Capital Expenditures
Historical capital expenditures
The table below summarizes our capital expenditures incurred for the year ended December 31, 2017. We plan to invest the majority of our 2018 capital budget for the horizontal development of our Eagle Ford Shale properties and have allocated between $95 million and $100 million to drilling and completion activities to develop these assets, and up to $10 million is allocated for leasehold acquisition expenditures.
Critical Accounting Policies and Estimates
The preparation of our financial statements requires us to make estimates and judgments that can affect the reported amounts of assets, liabilities, revenues and expenses, as well as the disclosure of contingent assets and liabilities at the date of our financial statements. We analyze our estimates and judgments, including those related to oil, NGLs and natural gas revenues, oil and natural gas properties, impairment of long-lived assets, fair value of derivative instruments, asset and retirement obligations and income taxes, and we base our estimates and judgments on historical experience and various other assumptions that we believe to be reasonable under the circumstances. Actual results may vary from our estimates. The policies of particular importance to the portrayal of our financial position and results of operations and that require the application of significant judgment or estimates by our management are described below. As of December 31, 2017, there were no significant changes to any of our critical accounting policies and estimates.
Estimates of Reserve Quantities
Reserve estimates are inexact and may change as additional information becomes available. Furthermore, estimates of oil and gas reserves are projections based on engineering data. There are uncertainties inherent in the interpretation of such data, as well as the projection of future rates of production and timing of development expenditures. Reservoir engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact way. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation, and judgment. Accordingly, there can be no assurance that ultimately, the reserves will be produced, nor can there be assurance that the proved undeveloped reserves will be developed within the period anticipated. All reserve reports prepared by the independent third-party reserve engineers are reviewed by our senior management team, including the Chief Executive Officer and Senior Vice President-Operations. Estimated reserves are often subject to future revisions, certain of which could be substantial, based on the availability of additional information, including reservoir performance, new geological and geophysical data, additional drilling, technological advancements, price changes and other economic factors. Changes in oil and gas prices can lead to a decision to start-up or shut-in production, which can lead to revisions in reserve quantities. Reserve revisions will inherently lead to adjustments of DD&A rates. We cannot predict the types of reserve revisions that will be required in future periods. A 10% increase or decrease in our estimates of total proved reserves at December 31, 2017 would have decreased or increased our DD&A expense of proved oil and gas properties by approximately $4.4 million or 8.5% or $5.4 million or 10.4%, respectively, for the year ended December 31, 2017.
Oil and Natural Gas Properties
We use the successful efforts method of accounting to account for our oil and gas properties. Under this method, costs of acquiring properties, costs of drilling successful exploration wells, and development costs are capitalized. The costs of exploratory wells are initially capitalized pending a determination of whether proved reserves have been found. At the completion of drilling activities, the costs of exploratory wells remain capitalized if a determination is made that proved reserves have been found. If no proved reserves have been found, the costs of each of the related exploratory wells are charged to expense. In some cases, a determination of proved reserves cannot be made at the completion of drilling, requiring additional testing and evaluation of the wells. Our policy is to expense the costs of such exploratory wells if a determination of proved reserves has not been made within a 12-month period after drilling is complete. All costs related to development wells, including related production equipment and lease acquisition costs, are capitalized when incurred, whether productive or nonproductive.
Capitalized costs attributed to the proved properties are subject to depreciation and depletion. Depreciation and depletion of the cost of oil and gas properties is calculated using the units-of-production method aggregating properties on a field basis. For leasehold acquisition costs and the cost to acquire proved properties, the reserve base used to calculate depreciation and depletion is the sum of proved developed reserves and proved undeveloped reserves. For development costs, the reserve base used to calculate depletion and depreciation is proved developed reserves only.
Unproved properties consist of costs incurred to acquire unproved leases. Unproved lease acquisition costs are capitalized until the leases expire or when the Company specifically identifies leases that will revert to the lessor, at which time the Company expenses the associated unproved lease acquisition costs. The expensing of the unproved lease acquisition costs is recorded as an impairment of oil and gas properties in the consolidated statement of operations, as applicable. Unproved oil and gas property costs are transferred to proven oil and gas properties if the properties are subsequently determined to be productive or are assigned proved reserves. Unproved oil and gas properties are assessed periodically for impairment based on remaining lease terms, drilling results, reservoir performance, future plans to develop acreage, and other relevant factors.
It is common for operators of oil and natural gas properties to request that joint interest owners pay for large expenditures, typically for drilling new wells, in advance of the work commencing. This right to call for cash advances is typically found in the joint operating agreement that joint interest owners in a property adopt. As an operator, we record these advance payments in other current liabilities and relieve this account when the actual expenditure is billed by us in the monthly joint interest billing statement.
On the sale or retirement of a complete or partial unit of a proved property, the cost and related accumulated depreciation, depletion, and amortization are eliminated from the property accounts, and any gain or loss is recognized.
Impairment of Long-Lived Assets
The carrying value of the oil and gas properties and other related property and equipment is periodically evaluated under the provisions of Accounting Standards Codification (“ASC”) 360, Property, Plant, and Equipment. ASC 360 requires long-lived assets and certain identifiable intangibles to be reviewed for impairment whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. When it is determined that the estimated future net cash flows of an asset will not be sufficient to recover its carrying amount, an impairment loss must be recorded to reduce the carrying amount to its estimated fair value. Judgments and assumptions are inherent in management’s estimate of undiscounted future cash flows and an asset’s fair value. These judgments and assumptions include such matters as the estimation of oil and gas reserve quantities, risks associated with the different categories of oil and gas reserves, the timing of development and production, expected future commodity prices, capital expenditures, production costs, and appropriate discount rates.
Under ASC 360, the Company evaluates impairment of proved and unproved oil and gas properties on an area basis. On this basis, certain fields may be impaired because they are not expected to recover their entire carrying value from future net cash flows.
Derivative Financial Instruments
We use derivative financial instruments to hedge our exposure to changes in commodity prices arising in the normal course of business. The principal derivatives that may be used are commodity price swap, option and costless collar contracts. The use of these instruments is subject to policies and procedures as approved by our board directors. We do not trade in derivative financial instruments for speculative purposes. None of our derivative contracts have been designated as cash flow hedges for accounting purposes. Derivative financial instruments are initially recognized at cost, if any, which approximates fair value. Subsequent to initial recognition, derivative financial instruments are recognized at fair value. The derivatives are valued on a mark-to-market valuation, and the gain or loss on re-measurement to fair value is recognized through the statement of operations. The estimated fair value of our derivative instruments requires substantial judgment. These values are based upon, among other things, option pricing models, futures prices, volatility, time to maturity and credit risk. The values we report in our financial statements change as these estimates are revised to reflect actual results, changes in market conditions or other factors, many of which are beyond our control.
The counterparties to our derivative instruments are not known to be in default on their derivative positions. However, we are exposed to credit risk to the extent of nonperformance by the counterparty in the derivative contracts. We believe credit risk is minimal and do not anticipate such nonperformance by such counterparties.
Asset Retirement Obligations (ARO)
We account for asset retirement obligations under ASC 410, Asset Retirement and Environmental Obligations. ASC 410 requires legal obligations associated with the retirement of long-lived assets to be recognized at their fair value at the time that the obligations are incurred. Oil and gas producing companies incur such a liability upon acquiring or drilling a well. Under ASC 410, an asset retirement obligation is recorded as a liability at its estimated present value at the asset’s inception, with an offsetting increase to producing properties in the accompanying consolidated balance sheet, which is allocated to expense over the useful life of the asset. Periodic accretion of the discount on asset retirement obligations is recorded as an expense in the accompanying consolidated statement of operations. The estimation of future costs associated with the dismantlement, abandonment and restoration requires the use of estimated costs in future periods that, in some cases, will not be incurred until a number of years in the future. Such cost estimates could be subject to revisions in subsequent years due to changes in regulatory requirement, technological advances and other factors that are difficult to predict.
There are many variables in estimating AROs. We primarily use the remaining estimated useful life from the year-end independent third-party reserve reports in estimating when abandonment could be expected for each property based on field or industry practices. We expect to see our calculations impacted significantly if interest rates move from their current levels, as the credit-adjusted-risk-free-rate is one of the variables used on a quarterly basis. Our technical team has developed a standard cost estimate based on the historical costs, industry quotes and depth of wells. Unless we expect a well’s plugging cost to be significantly different than a normal abandonment, we use this estimate. The resulting estimate, after application of an inflation factor and a discount factor, could differ from actual results.
Income Taxes
We follow the asset and liability method in accounting for income taxes in accordance with ASC 740, Income Taxes. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases, operating losses and tax credit carryforwards.
Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which these temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. In addition, a valuation allowance is established to reduce any deferred tax asset for which it is determined that it is more likely than not that some portion of the deferred tax asset will not be realized.
Changes in our expectations regarding our future taxable income (which is materially impacted by volatility in commodity prices), can result in our recording of a valuation allowance against our deferred tax assets. We would record this valuation allowance when our judgment is that our existing U.S. federal net operating loss carryforwards are not, on a more-likely-than-not basis, recoverable in future years. We will continue to evaluate the need for a valuation allowance based on current and expected earnings and other factors and adjust it accordingly.
We evaluate uncertain tax positions, which requires significant judgments and estimates regarding the recoverability of deferred tax assets, the likelihood of the outcome of examinations of tax positions that may or may not be currently under review, and potential scenarios involving settlements of such matters. Changes in these estimates could materially impact the consolidated financial statements.
Recently Issued Accounting Pronouncements
See “Note 2. Recently Issued Accounting Pronouncements” of the Notes to Consolidated Financial Statements for discussion of the recent accounting pronouncements.
Off-Balance Sheet Arrangements
We do not have any off-balance sheet arrangements.
Item 7A.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.
We are exposed to a variety of financial market risks including interest rate, commodity prices, foreign exchange and liquidity risk. Our risk management focuses on the volatility of commodity markets and protecting cash flow in the event of declines in commodity pricing. We utilize derivative financial instruments to hedge certain risk exposures. Our financial instruments consist mainly of deposits with banks, short-term investments, accounts receivable, derivative financial instruments, our Senior Secured Credit Facility, bonds and payables. The main purpose of non-derivative financial instruments is to raise finance for our operations.
Financial risk management is carried out by our management. Our board of directors sets financial risk management policies and procedures to which our management is required to adhere. Our management identifies and evaluates financial risks and enters into financial risk instruments to mitigate these risk exposures in accordance with the policies and procedures outlined by our board of directors.
Commodity Price Risk
As a result of our operations, we are exposed to commodity price risk arising from fluctuations in the prices of crude oil, NGLs and natural gas. The demand for, and prices of, crude oil, NGLs and natural gas, are dependent on a variety of factors, including supply and demand, weather conditions, the price and availability of alternative fuels, actions taken by governments and international cartels and global economic and political developments. The following table shows the fair value of our derivative contracts and the hypothetical result from a 10% change in commodity prices at December 31, 2017. We remain at risk for possible changes in the market value of commodity derivative instruments; however, such risks could be mitigated by price changes in the underlying physical commodity (in thousands):
Our board of directors reviews oil and natural gas hedging on a quarterly basis. Reports providing detailed analysis of our hedging activity are continually monitored. We sell our oil and natural gas on market using NYMEX market spot rates reduced for basis differentials in the basins from which we produce. We use forward contracts to manage our commodity price risk exposure.
Our primary commodity risk management objective is to reduce volatility in our cash flows. Management makes recommendations on hedging that are approved by the board of directors before implementation. We enter into hedges for oil using NYMEX futures or over-the-counter derivative financial instruments with only certain well-capitalized counterparties which have been approved by our board of directors.
Presently, all of our hedging arrangements are concentrated with three counterparties, each of which are lenders under the Credit Facility. If these counterparties fail to perform their obligations, we may suffer financial loss or be prevented from realizing the benefits of favorable price changes in the physical market.
The result of oil market prices exceeding our swap prices or collar ceilings requires us to make payment for the settlement of our hedge derivatives, if owed by us, generally up to three business days before we receive market price cash payments from our customers. This could have a material adverse effect on our cash flows for the period between hedge settlement and payment for revenues earned.
The following table provides a summary of our derivative contracts as of December 31, 2017:
The above derivative contracts aggregate to 1,713,500 Bbls or 4,695 Bbls/d for 2018, 1,471,100 Bbls or 4,030 Bbls/d for 2019, and 203,600 Bbls or 1,120 Bbls/d for 2020. Our 2018 derivative contracts consist of 4,195 Bbls/d swaps at a volume weighted average price of $51.83 and and two- way collars covering 500 Bbls/d with a price ceiling of $59.45. Our 2019 derivative contracts consist of 4,030 Bbls/d swaps at a volume weighted average price of $49.64 and two-way collars covering 500 Bbls/d with a price ceiling of $59.45. Our 2020 derivative contracts consist of 1,119 Bbls/d thru June at a price of $48.90 per Bbl.
In January 2018, we entered into additional WTI crude oil swaps covering 2018, 2019, and 2020. The 2018 WTI crude oil swaps cover a total of 230,700 barrels for the period of March 2018 through December 2018 at an average strike price of $61.77. The addition of these swaps increased our total 2018 crude oil hedge position coverage to a total of approximately 5,326 Bbls/d at an average strike price of $53.72 per barrel. The 2019 WTI crude oil swaps cover a total of 328,500 barrels for the period of January 2019 through December 2019 at an average strike price of $58.25. These additional 2019 swaps increased our total 2019 crude oil hedge position coverage to a total of approximately 4,930 Bbls/d at an average strike price of $51.21. The 2020 WTI crude oil swaps cover a total of 411,200 barrels for the period of January 2020 through December 2020 at an average strike price of $55.06. These additional 2020 swaps increased our total 2020 crude oil hedge position coverage to a total of approximately 1,680 Bbls/d at an average strike price of $53.02.
The above natural gas derivative contract equates to 5,000 MMBtu per day for 2018.
Counterparty and Customer Credit Risk
In connection with our hedging activity, we have exposure to financial institutions in the form of derivative transactions. The counterparties on our derivative instruments currently in place have investment-grade credit ratings. We expect that any future derivative transactions we enter into will be with these counterparties or our lenders under our Senior Secured Credit Facility that will carry an investment-grade credit rating.
We are also subject to credit risk due to concentration of our oil and natural gas receivables with certain significant customers. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. We review the credit rating, payment history and financial resources of our customers, but we do not require our customers to post collateral.
Interest Rate Risk
As of December 31, 2017, we had $142.1 million outstanding under the Credit Facility, which is subject to floating market rates of interest. Borrowings under the Credit Facility bear interest at a fluctuating rate that is tied to an adjusted base rate or LIBOR, at our option. Any increase in this interest rate can have an adverse impact on our results of operations and cash flow. Based on borrowings outstanding at December 31, 2017, a 100-basis-point change in interest rates would change our annualized interest expense by approximately $0.4 million.
Item 8.
Item 8. Financial Statements and Supplementary Data.
The financial statements and supplementary information required by this Item appears on pages through of this Annual Report on Form 10-K.
Item 9.
Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure.
None.
Item 9A.
Item 9A. Controls and Procedures.
Disclosures Controls and Procedures
We carried out an evaluation, under the supervision and with the participation of our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d15(e) of the Exchange Act) as of the end of the period covered by this report. Based on this evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of the end of the period covered by this report.
The design of any system of disclosure controls and procedures is based upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated objectives under all future events, no matter how remote, or that the degree of compliance with the policies or procedures may not deteriorate. Because of its inherent limitations, disclosure controls and procedures may not prevent or detect all misstatements. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives.
Management’s Report on Internal Control Over Financial Reporting
Management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Rule 13a-15(f) under the Exchange Act. Management, with the participation of our Chief Executive Officer and Chief Financial Officer, has assessed the effectiveness of our internal control over financial reporting as of the end of the period covered by this report based on the framework established in “Internal Control-Integrated Framework (2013 framework)”, issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management has concluded that our internal control over financial reporting was effective as of the end of the period covered by this report. Our system of internal control over financial reporting was designed to provide reasonable assurance regarding the preparation and fair presentation of published financial statements in accordance with accounting principles generally accepted in the United States.
All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance and may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Because we are an “emerging growth company” under the JOBS Act, our independent registered public accounting firm, BDO USA, LLP, is not required to issue an attestation report on our internal control over financial reporting.
Changes in Internal Controls
There was no change in our internal control over financial reporting during the quarter ended December 31, 2017 that materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
Item 9B.
Item 9B. Other Information.
None.
PART III
Item 10.
Item 10. Directors, Executive Officers and Corporate Governance.
Our board of directors has adopted a Code of Business Conduct and Ethics applicable to all officers, directors, and employees, which is available on our website at www.lonestarresources.com in the “Shareholder Information” section under “Governance.” We intend to satisfy the disclosure requirement under Item 5.05 of Form 8-K regarding amendment to, or waiver from, a provision of our Code of Business Conduct and Ethics, as well as Nasdaq’s requirements to disclose waivers with respect to directors and executive officer, by posting such information on our website at the address and location specified above.
The information concerning our executive officers and directors in response to this item is contained above in part under the caption “Executive Officers and Directors” at the end of Part I of this Annual Report on Form 10-K. The remainder of the response to this item is contained in the Proxy Statement for our 2018 Annual Meeting of Stockholders and is incorporated herein by reference.
Item 11.
Item 11. Executive Compensation.
The information required by this item will be included in our Proxy Statement for our 2018 Annual Meeting of Stockholders, and is incorporated herein by reference.
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.
The information required by this item will be included in our Proxy Statement for our 2018 Annual Meeting of Stockholders, and is incorporated herein by reference.
Item 13.
Item 13. Certain Relationships and Related Transactions, and Director Independence.
The information required by this item will be included in our Proxy Statement for our 2018 Annual Meeting of Stockholders, and is incorporated herein by reference.
Item 14.
Item 14. Principal Accounting Fees and Services.
The information required by this item will be included in our Proxy Statement for our 2018 Annual Meeting of Stockholders, and is incorporated herein by reference.
PART IV
Item 15.
Item 15. Exhibits, Financial Statement Schedules.
(a)(1)
Financial Statements
See the “Index to Consolidated Financial Statements on page below for the list of financial statements filed as part of this report.
(a)(2)
Financial Statements Schedules
All schedules have been omitted because they are not required or because the required information is given in the Consolidated Financial Statements or Notes thereto set forth below beginning on page.
(a)(3)
Exhibits
See the Exhibit Index immediately following the signature of this Annual Report on Form 10-K. The exhibits listed in the Exhibit Index below are filed or incorporated by reference as part of this Annual Report on Form 10-K.
Item 16. Form 10-K Summary
None.
Exhibit Index
4.6
Registration Rights Agreement, dated as of June 15, 2017, by and between Lonestar Resources US Inc. and SN UR Holdings, LLC
8-K
001-37670
4.2
6/21/17
4.7
Registration Rights Agreement, dated as of June 15, 2017, by and between Lonestar Resources US Inc. and Chambers Energy Capital III, LP
8-K
001-37670
4.3
6/21/17
4.8
Indenture, dated as of January 4, 2018, by and among Lonestar Resources America Inc., the subsidiary guarantors named therein and UMB Bank, N.A. as Trustee.
8-K
001-37670
4.1
1/9/18
10.1†
Lonestar Resources US Inc. Amended and Restated 2016 Incentive Plan, as amended as of May 24, 2017
8-K
001-37670
10.1
5/26/17
10.2
Amended and Restated Securities Purchase Agreement by and between Lonestar Resources US Inc., and Chambers Energy Capital III, LP, dated June 15, 2017
8-K
001-37670
10.1
6/21/17
10.3
Credit Agreement, dated July 28, 2015, among Lonestar Resources America Inc., Citibank, N.A., as Administrative Agent, and the guarantors and lenders party thereto.
10-12B
001-37670
10.3
12/31/15
10.4
First Amendment to Credit Agreement, dated effective April 29, 2016, among Lonestar Resources America Inc., Citibank, N.A., as Administrative Agent, and the guarantors and lenders party thereto.
10-12B/A
001-37670
10.5
6/9/16
10.5
Second Amendment to Credit Agreement, dated effective May 19, 2016, among Lonestar Resources America Inc., Citibank, N.A., as Administrative Agent, and the guarantors and lenders party thereto.
10-12B/A
001-37670
10.6
6/9/16
10.6
Third Amendment to Credit Agreement and Limited Waiver, dated effective July 27, 2016, among Lonestar Resources America Inc., Citibank, N.A., as Administrative Agent, and the guarantors and lenders party thereto.
8-K
001-37670
10.1
8/2/16
10.7
Fourth Amendment to Credit Agreement dated effective November 23, 2016, among Lonestar Resources America Inc., Citibank N.A., as administrative agent, and lenders party thereto.
*
10.8
Fifth Amendment to Credit Agreement and Limited Waiver dated effective December 29, 2016, among Lonestar Resources America Inc., Citibank, N.A., as administrative agent and lenders party thereto.
*
10.9
Sixth Amendment and Joinder dated June 15, 2017 to the Credit Agreement dated July 28, 2015 by and among Lonestar Resources America, Inc., the subsidiary guarantors party thereto, the lenders party thereto and Citibank, N.A., Inc. as administrative agent and issuing bank.
8-K
001-37670
10.2
6/21/17
10.10
Limited Waiver, Borrowing Base Redetermination and Amendment No. 7 to Credit Agreement, dated as of January 4, 2018, by and among Lonestar Resources America Inc., the subsidiary guarantors party thereto, the lenders party thereto and Citibank, N.A., as administrative agent and issuing bank.
8-K
001-37670
10.1
1/9/18
10.11
Limited Waiver Agreement, dated as of March 28, 2018, among Lonestar Resources America Inc., the guarantor parties hereto, Citibank, N.A., as administrative agent and issuing bank, and lenders party thereto.
*
21.1
List of subsidiaries of Lonestar Resources US Inc.
*
23.1
Consent of BDO USA, LLP
*
23.2
Consent of W.D. Von Gonten & Co.
*
31.1
Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer
*
31.2
Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer
*
32.1
Section 1350 Certification of Chief Executive Officer
**
32.2
Section 1350 Certification of Chief Financial Officer
**
99.1
Report of W.D. Von Gonten & Co. regarding the Company’s estimated proved reserves as of December 31, 2016, dated February 14, 2017
10-K
001-37670
99.4
3/23/17
99.2
Report of W.D. Von Gonten & Co. regarding the Company’s estimated proved reserves as of December 31, 2017, dated February 20,2018
*
101.INS
XBRL Instance Document
*
101.SCH
XBRL Taxonomy Extension Schema Document
*
101.CAL
XBRL Taxonomy Extension Calculation Linkbase Document
*
101.DEF
XBRL Taxonomy Extension Definition Linkbase Document
*
101.LAB
XBRL Taxonomy Extension Label Linkbase Document
*
101.PRE
XBRL Taxonomy Extension Presentation Linkbase Document
*
*
Filed herewith.
**
Furnished herewith
†
Management contract or compensatory plan or arrangement.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, as amended, the Registrant has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized.
Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, this Report has been signed below by the following persons on behalf of the Registrant in the capacities and on the dates indicated.
Name
Title
Date
/s/ Frank D. Bracken, III
Chief Executive Officer and Director
March 29, 2018
Frank D. Bracken, III
(Principal Executive Officer)
/s/ Douglas W. Banister
Chief Financial Officer
March 29, 2018
Douglas W. Banister
(Principal Financial Officer)
/s/ Jason N. Werth
Chief Accounting Officer
March 29, 2018
Jason N. Werth
(Principal Accounting Officer)
/s/ John Pinkerton
Chairman of the Board
March 29, 2018
John Pinkerton
/s/ Henry B. Ellis
Director
March 29, 2018
Henry B. Ellis
/s/ Daniel R. Lockwood
Director
March 29, 2018
Daniel R. Lockwood
/s/ John H. Murray
Director
March 29, 2018
John H. Murray
/s/ Matthew B. Ockwood
Director
March 29, 2018
Matthew B. Ockwood
/s/ Stephen H. Oglesby
Director
March 29, 2018
Stephen H. Oglesby
/s/ Phillip Z. Pace
Director
March 29, 2018
Phillip Z. Pace
/s/ Christopher Rowland
Director
March 29, 2018
Christopher Rowland
/s/ Randy L. Wolsey
Director
March 29, 2018
Randy L. Wolsey
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets
Consolidated Statements of Operations
Consolidated Statements of Changes in Stockholders’ Equity
Consolidated Statements of Cash Flows
Notes to Consolidated Financial Statements
Report of Independent Registered Public Accounting Firm
Board of Directors and Stockholders
Lonestar Resources US Inc.
Fort Worth, Texas
Opinion on the Consolidated Financial Statements
We have audited the accompanying consolidated balance sheets of Lonestar Resources US, Inc. (the “Company”) and subsidiaries as of December 31, 2017 and 2016, the related consolidated statements of operations, changes in stockholders’ equity, and cash flows for the years then ended, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company and subsidiaries at December 31, 2017 and 2016, and the results of their operations and their cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.
/s/ BDO USA, LLP
We have served as the Company's auditor since 2013.
Dallas, Texas
March 29, 2018
PART I-FINANCIAL INFORMATION
Item 8. Financial Statements.
Lonestar Resources US Inc.
Consolidated Balance Sheets
(In thousands, except share and per share data)
See accompanying Notes to Consolidated Financial Statements.
Lonestar Resources US Inc.
Consolidated Statements of Operations
(In thousands, except share and per share data)
See accompanying Notes to Consolidated Financial Statements.
Lonestar Resources US Inc.
Consolidated Statements of Changes in Stockholders’ Equity
(In thousands, except share data)
See accompanying Notes to Consolidated Financial Statements.
Lonestar Resources US Inc.
Consolidated Statements of Cash Flows
(In thousands)
See accompanying Notes to Consolidated Financial Statements.
Lonestar Resources US Inc.
Notes to Consolidated Financial Statements
1. Nature of Business and Presentation
Lonestar Resources US Inc. (the “Successor”) was incorporated in Delaware in December 2015 for purposes of effecting our corporate reorganization, which was completed on July 5, 2016 (the “Reorganization”), pursuant to a Scheme Implementation Agreement (the “Scheme”), dated December 28, 2015, between the Successor and Lonestar Resources Limited (the “Predecessor”), an Australian company. Prior to the Reorganization, our business was owned and operated under our Predecessor, whose ordinary shares were listed on the Australian Securities Exchange (“ASX”). Pursuant to the Scheme, the Successor acquired all of the issued and outstanding ordinary shares of our Predecessor, and each of our Predecessor’s shareholders received one share of our Class A voting common stock (“Class A common stock”) for every two ordinary shares of our Predecessor such shareholder held. Prior to the Reorganization, the Successor had no business or operations, and following the Reorganization, the business and the operations of the Successor consist solely of the business and operations of the subsidiaries of the Predecessor. The reorganization was treated as a transaction among parties under common control and no gain or loss was recorded.
Lonestar Resources America, Inc. (“LRAI”) is a Delaware registered U.S. holding company formed on January 31, 2013, which is engaged in the exploration, development, production, acquisition, and sale of oil, natural gas liquid (“NGL”) and natural gas primarily in the Eagle Ford Shale play in South Texas through its wholly owned subsidiary, Lonestar Resources, Inc. Its executive offices are located in Fort Worth, Texas. LRAI was a wholly owned subsidiary of the Predecessor, prior to the Reorganization. The majority of the activities of the Predecessor was carried out through LRAI. Unless the context otherwise requires, references to “Lonestar,” “we,” “us,” “our,” and “the Company” refer to (i) Lonestar Resources Limited and its subsidiaries prior to the Reorganization and (ii) Lonestar Resources US Inc. and its subsidiaries upon completion of the Reorganization, as applicable.
Principles of Reporting and Consolidation
The consolidated financial statements have been prepared using the accrual basis of accounting in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”) and include the accounts of Lonestar and entities in which we hold a controlling financial interest. Undivided interests in oil and gas joint ventures are consolidated on a proportionate basis. All intercompany balances and transactions have been eliminated.
Use of Estimates
The preparation of the accompanying consolidated financial statements in conformity with GAAP requires management to make informed judgments and estimates that affect the reported amounts of assets, liabilities, revenues, and expenses. Management evaluates its estimates and related assumptions regularly, including those related to proved reserves, the value of properties and equipment, AROs, income taxes, and fair values. Changes in facts and circumstances or additional information may result in revised estimates, actual results may differ from these estimates.
Reclassifications
Certain prior year amounts have been reclassified to conform to current year presentation, with no effect on the previously reported results of operations.
Cash Equivalents
The Company considers all highly-liquid investments with original maturities of three months or less when purchased to be cash equivalents.
Concentrations and Credit Risk
The Company’s financial instruments exposed to concentrations of credit risk consist primarily of cash and cash equivalents and accounts receivable. The Company places its cash and cash equivalents with reputable financial institutions. At times, the balances deposited may exceed amounts covered by insurance provided by the U.S. Federal Deposit Insurance Corporation (“FDIC”). The Company has not incurred any losses related to amounts in excess of FDIC limits.
Substantially all of the Company’s accounts receivable are due from either purchasers of oil, NGL and natural gas or working interest partners in oil and natural gas wells for which a subsidiary of the Company serves as the operator. Generally, operators of oil and natural gas properties have the right to offset future revenues against unpaid charges related to operated wells. The Company’s receivables are generally unsecured.
Oil, NGL and natural gas revenues from Vitol Inc., Shell Trading (US) Company, Texla Energy Management, Inc., Trafigura AG, and NGL Crude Logistics LLC for the year ended December 31, 2017, represented 35%, 20%, 16%, 14%, and 10%, respectively, of total revenues. Oil, NGL and natural gas revenues from Shell Trading (US) Company, Texla Energy Management, Inc., Trafigura AG, and BP Products North America LLC for the year ended December 31, 2016, represented 40%, 21%, 18% and 10%, respectively, of total revenues. Accounts receivable relating to oil, NGL and natural gas sales from Vitol Inc., Shell Trading (US) Company, and NGL Crude Logistics LLC represented 59%, 19% and 17%, respectively, of total receivables at December 31, 2017. Accounts receivable relating to oil, NGL and natural gas sales from Shell Trading, Trafigura AG and Texla Energy Management, Inc. represented 49%, 30% and 13%, respectively, of total receivables at December 31, 2016.
Oil and Natural Gas Properties
The Company uses the successful efforts method of accounting to account for its oil and natural gas properties. Under this method, costs of acquiring properties, costs of drilling successful exploration wells, and development costs are capitalized. The costs of exploratory wells are initially capitalized pending a determination of whether proved reserves have been found. At the completion of drilling activities, the costs of exploratory wells remain capitalized if a determination is made that proved reserves have been found. If no proved reserves have been found, the costs of each of the related exploratory wells are charged to expense. In some cases, a determination of proved reserves cannot be made at the completion of drilling, requiring additional testing and evaluation of the wells. The Company’s policy is to expense the costs of such exploratory wells if a determination of proved reserves has not been made within a 12-month period after drilling is complete. As of December 31, 2017, the Company did not have any capitalized exploratory well costs that were pending determination of proved reserves. All costs related to development wells, including related production equipment and lease acquisition costs, are capitalized when incurred, whether productive or nonproductive.
Capitalized costs attributed to the proved properties are subject to depreciation and depletion. Depreciation and depletion of the cost of oil and gas properties is calculated using the units-of-production method aggregating properties on a field basis. For leasehold acquisition costs and the cost to acquire proved properties, the reserve base used to calculate depreciation and depletion is the sum of proved developed reserves and proved undeveloped reserves. For development costs, the reserve base used to calculate depletion and depreciation is proved developed reserves only.
Unproved properties consist of costs incurred to acquire unproved leases. Unproved lease acquisition costs are capitalized until the leases expire or when the Company specifically identifies leases that will revert to the lessor, at which time the Company expenses the associated unproved lease acquisition costs. The expensing of the unproved lease acquisition costs is recorded as an impairment of oil and gas properties in the consolidated statement of operations, as applicable. Unproved oil and gas property costs are transferred to proven oil and gas properties if the properties are subsequently determined to be productive or are assigned proved reserves. Unproved oil and gas properties are assessed periodically for impairment based on remaining lease terms, drilling results, reservoir performance, future plans to develop acreage, and other relevant factors.
On the sale or retirement of a complete or partial unit of a proved property, the cost and related accumulated depreciation, depletion, and amortization are eliminated from the property accounts, and any gain or loss is recognized.
Other Property and Equipment
Other property and equipment, consisting primarily of office, transportation and computer equipment, as well as our new corporate headquarters, is carried at cost. Depreciation is calculated using the straight-line method over the estimated useful lives of the assets, ranging from 3 to 5 years, with the exception of our corporate headquarters, which is 30 years. Major renewals and improvements are capitalized, while expenditures for maintenance and repairs are expensed as incurred. Upon sale or abandonment, the cost of the equipment and related accumulated depreciation are removed from the accounts, and any gain or loss is recognized.
Impairment of Long-Lived Assets
The carrying value of the oil and gas properties and other related property and equipment is periodically evaluated under the provisions of Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 360, Property, Plant, and Equipment. ASC 360 requires long-lived assets and certain identifiable intangibles to be reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. When it is determined that the estimated future net cash flows of an asset will not be sufficient to recover its carrying amount, an impairment loss must be recorded to reduce the carrying amount to its estimated fair value. Judgments and assumptions are inherent in management’s estimate of undiscounted future cash flows and an asset’s fair value. These judgments and assumptions include such matters as the estimation of oil and gas reserve quantities, risks associated with the different categories of oil and gas reserves, the timing of development and production, expected future commodity prices, capital expenditures, production costs, and appropriate discount rates.
Under ASC 360, the Company evaluates impairment of proved and unproved oil and gas properties on an area basis. On this basis, certain fields may be impaired because they are not expected to recover their entire carrying value from future net cash flows. As a result of this evaluation, the Company recorded impairment of unproved oil and gas properties of approximately $28.6 million and $4.8 million for the years ended December 31, 2017 and 2016, respectively, and impairment of proven oil and gas properties of $4.8 million and $29.1 million for the years ended December 31, 2017 and 2016, respectively. If pricing declines, it is reasonably likely that the Company may have to record impairment of its oil and gas properties subsequent to December 31, 2017.
Asset Retirement Obligations
The Company accounts for asset retirement obligations under ASC 410, Asset Retirement and Environmental Obligations. ASC 410 requires legal obligations associated with the retirement of long-lived assets to be recognized at their fair value at the time that the obligations are incurred. Oil and gas producing companies incur such a liability upon acquiring or drilling a well. Under ASC 410, an asset retirement obligation is recorded as a liability at its estimated present value at the asset’s inception, with an offsetting increase to producing properties in the accompanying consolidated balance sheet, which is allocated to expense over the useful life of the asset. Periodic accretion of the discount on asset retirement obligations is recorded as an expense in the accompanying consolidated statement of operations. See Note 7, Asset Retirement Obligations, for more information.
Revenue Recognition
The Company recognizes revenue when it is realized or realizable and earned. Revenues are considered realized or realizable and earned when: (i) persuasive evidence of an arrangement exists, (ii) delivery has occurred or services have been rendered, (iii) the seller’s price to the buyer is fixed or determinable and (iv) collectability is reasonably assured.
The Company follows the sales method of accounting for natural gas revenue, whereby revenue is recorded based on the Company’s share of volume sold, regardless of whether the Company has taken its proportional share of volume produced. A receivable or liability is recognized only to the extent that the Company has an imbalance on a specific property greater than the expected remaining proved reserves. There were no imbalances at December 31, 2017 or 2016.
Fair Value of Financial Instruments
In accordance with the reporting requirements of ASC 825, Financial Instruments, the Company calculates the fair value of its assets and liabilities that qualify as financial instruments under this guidance and includes this additional information in the notes to consolidated financial statements when the fair value is different from the carrying value of those financial instruments. See Note 5, Fair Value Measurements, for more information.
Income Taxes
The Company follows the asset and liability method in accounting for income taxes in accordance with ASC 740, Income Taxes. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases, operating losses and tax credit carryforwards.
Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which these temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date.
The Company periodically evaluates the realizable tax benefits of deferred tax assets and records a valuation allowance, if required, based on an estimate of the amount of deferred tax assets the Company believes does not meet the more likely than not criteria of being realized. In certain circumstances, the deferred tax asset may exceed the amount permissible to be used under the tax law, for example, a net operating loss carryforward. In such cases it is appropriate to write-off the excess net operating loss. At December 31, 2016, the Company wrote off $141.7 million of its net operating loss carryforward. See Note 10, Income Taxes, for more information.
The Company evaluates uncertain tax positions, which requires significant judgments and estimates regarding the recoverability of deferred tax assets, the likelihood of the outcome of examinations of tax positions that may or may not be currently under review, and potential scenarios involving settlements of such matters. Changes in these estimates could materially impact the consolidated financial statements. No liability for material uncertain tax positions existed as of December 31, 2017 or 2016.
Share-Based Payments
The Company accounts for equity-based awards in accordance with ASC 718, Compensation-Stock Compensation, which requires companies to recognize in the statement of operations all share-based payments granted to employees based on their fair value. Share-based compensation is recognized by the Company on the graded vesting method over the requisite service period, which approximates the option vesting period of three years.
2. Recently Issued Accounting Pronouncements
Business Combinations. In January 2017, the FASB issued Accounting Standards Update (“ASU”) 2017-01, Business Combinations: Clarifying the Definition of a Business (“ASU 2017-01”) in order to clarify the definition of a business as it relates to whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. Effective January 1, 2018, the Company adopted ASU 2017-01, which will not have a material impact on the Company’s consolidated financial statements.
Leases. In February 2016, the FASB issued ASU 2016-02, Leases (“ASU 2016-02”), which will require organizations that lease assets to recognize on the balance sheet the assets and liabilities for the rights and obligations created by those leases. ASU 2016-02 is effective for the annual period beginning after December 15, 2018, including interim periods within those fiscal years, and early adoption is permitted. Entities must adopt the standard using a modified retrospective transition and apply the guidance to the earliest comparative period presented, with certain practical expedients that entities may elect to apply. Management is currently assessing the impact the adoption of ASU 2016-02 will have on our consolidated financial statements.
Revenue Recognition. In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (“ASU 2014-09”). The objective of ASU 2014-09 is greater consistency and comparability across industries by using a five-step model to recognize revenue from customer contracts. Effective January 1, 2018, the Company adopted ASU 2014-09, using the modified retrospective method applied to contracts that were not completed as of January 1, 2018. We have reviewed various contracts that represent our material revenue streams and determined that there was no material impact to our financial position, results of operations or liquidity. Upon adoption of this ASU, we were not required to record a cumulative adjustment to beginning retained earnings. The Company continues to review its implementation documentation and its evaluation of the new disclosure requirements is ongoing.
3. Acquisitions and Divestitures
New Corporate Headquarters
On August 2, 2017, the Company closed on the purchase of an office building in Fort Worth, Texas, with an acquisition price approximating $10 million.
Battlecat Acquisition
On June 15, 2017, the Company closed an acquisition with Battlecat Oil & Gas, LLC (“Battlecat”) whereby the Company acquired oil and gas properties in the Eagle Ford Shale play in DeWitt, Gonzales and Karnes County, Texas (the “Battlecat Acquisition”). The total purchase consideration of approximately $59.8 million consisted of $55.0 million in cash and 1,184,632 shares of Series B Convertible Preferred Stock, par value $0.001 per share (“Series B Preferred Stock”) at a value of approximately $4.8 million. Allocation of the purchase consideration was as follows: $56.3 million to proved reserves; $2.9 million to unproved reserves and $0.6 million to unevaluated acreage and other assets. Additionally, the Company recorded an asset retirement obligation of approximately $0.2 million, resulting in fair value of net assets acquired of approximately $59.6 million. The Company accounted for the acquisition as a business combination under ASC 805. Acquisition-related costs of approximately $1.5 million were charged to Acquisition Costs in the Consolidated Statements of Operations. The effective date of the acquisition was April 1, 2017.
Marquis Acquisition
On June 15, 2017, the Company closed an acquisition with SN Marquis LLC (a subsidiary of Sanchez Energy Corporation) (“Marquis”) whereby the Company acquired oil and gas properties in the Eagle Ford Shale play in Fayette, Gonzales and Lavaca County, Texas (the “Marquis Acquisition”). The total purchase consideration of approximately $50.0 million consisted of $44.0 million in cash and 1,500,000 shares of Series B Preferred Stock at a value of approximately $6.0 million. Allocation of the purchase price was as follows: $48.0 million to proved reserves; $0.6 to unproved reserves and $1.4 million to land, building and other assets. Additionally, the Company recorded an asset retirement obligation of approximately $1.9 million, resulting in fair value of net assets acquired of approximately $48.1 million. The Company accounted for the acquisition as a business combination under ASC 805. Acquisition-related costs of approximately $1.2 million were charged to Acquisition Costs in the Consolidated Statements of Operations. The effective date of the acquisition was January 1, 2017.
Pro Forma Operating Results (unaudited)
The following unaudited pro forma combined financial information for the years ended December 31, 2017 and 2016, is based on the historical consolidated financial statements of the Company adjusted to reflect as if the Battlecat Acquisition and the Marquis Acquisition had closed and related financing had occurred on January 1, 2016. The unaudited pro forma combined financial information includes adjustments primarily for revenues and expenses for the acquired properties, depreciation, depletion, amortization and accretion, and interest expense. The unaudited pro forma combined financial statements give effect to the events set forth below:
•
The issuance of 5,400 shares of Series A-1 Preferred Stock and 74,600 shares of Series A-2 Preferred Stock (each as defined below) to Chambers Energy Capital III, LP (“Chambers”) for $80 million to finance a portion of the Battlecat Acquisition and the Marquis Acquisition, at an initial conversion price of $6.00 per share, subject to certain adjustments including preferred dividends.
•
The borrowing of approximately $24 million on our Credit Facility to finance a portion of the Battlecat Acquisition and the Marquis Acquisition and the related adjustment to interest expense.
•
The issuance of 1,500,000 shares of the Company’s Series B Preferred Stock to SN UR Holdings, LLC (a subsidiary of Sanchez Energy Corporation).
•
The issuance of 1,184,632 shares of the Company’s Series B Preferred Stock to Battlecat Oil & Gas, LLC.
•
Conversion of Series B Preferred Stock to Class A voting common stock on November 3, 2017.
Pro forma adjustments to net income (loss) attributable to common stockholders consists of depreciation, depletion, amortization and accretion calculations, additional interest expense, adjustments for income tax (expense) benefit, and dividends on preferred stock issued to complete the acquisitions.
The Company has included in its Consolidated Statements of Operations, revenues of $2.20 million and $13.2 million and direct operating expenses of $0.6 million and $3.81 million for the period from June 15, 2017 to December 31, 2017 related to the properties acquired in the Battlecat and Marquis transactions, respectively.
Juneau Transaction
On August 2, 2016, the Company entered into a purchase and sale agreement with Juneau Energy, LLC (“Juneau”) whereby the Company obtained an undivided 50% of Juneau’s interest in two producing wells and each well’s respective oil and gas leases covering approximately 1,300 net mineral acres located in Brazos County, Texas. The total consideration paid by the Company was $5.5 million payable in 500,227 shares of the Company’s Class A voting common stock.
4. Commodity Price Risk Activities
The Company has implemented a strategy to reduce the effects of volatility of oil and natural gas prices on the Company’s results of operations by securing fixed-price contracts for a portion of its expected sales volumes.
Inherent in the Company’s fixed price contracts, are certain business risks, including market risk and credit risk. Market risk is the risk that the price of oil and natural gas will change, either favorably or unfavorably, in response to changing market conditions. Credit risk is the risk of loss from nonperformance by the Company’s counterparty to a contract. The Company does not currently require collateral from any of its counterparties nor does its counterparties require collateral from the Company. At December 31, 2017, the Company had no open physical delivery obligations.
The Company enters into certain commodity derivative instruments to mitigate commodity price risk associated with a portion of its future oil, NGL and natural gas production and related cash flows. The oil, NGL and natural gas revenues and cash flows are affected by changes in commodity product prices, which are volatile and cannot be accurately predicted. The objective for holding these commodity derivatives is to protect the operating revenues and cash flows related to a portion of the future oil, NGL and natural gas sales from the risk of significant declines in commodity prices, which helps ensure the Company’s ability to fund the capital budget.
The Company has not designated any of the commodity derivatives as hedges under the applicable accounting standards. Consequently, all changes in fair value of these derivatives are included in the Consolidated Statements of Operations.
As of December 31, 2017, the following derivative transactions were outstanding:
The above oil derivative contracts aggregate to 1,713,500 Bbls or 4,695 Bbls/d for 2018; 1,471,100 Bbls or 4,030 Bbls/d for 2019; and 203,600 Bbls or 1,119 Bbls/d for 2020. The above natural gas derivative contract equates to 5,000 MMBtu/d for 2018. All derivative contracts are carried at their fair value on the balance sheet and all changes in value are recorded in the Consolidated Statements of Operations.
As of December 31, 2017 and 2016, all of the Company’s economic derivative hedge positions were with large financial institutions, which are not known to the Company to be in default on their derivative positions. The Company is exposed to credit risk to the extent of non-performance by the counterparties in the derivative contracts discussed above; however, the Company does not anticipate non-performance by such counterparties. None of the Company’s derivative instruments contain credit-risk related contingent features.
5. Fair Value Measurements
In accordance with ASC 820, Fair Value Measurements and Disclosures, fair value measurements are based upon inputs that market participants use in pricing an asset or liability, which are classified into two categories: observable inputs and unobservable inputs. Observable inputs represent market data obtained from independent sources, whereas unobservable inputs reflect a company’s own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. ASC 820 prioritizes the inputs used in measuring fair value into the following fair value hierarchy:
Level 1 - Quoted prices for identical assets or liabilities in active markets.
Level 2 - Quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability, and inputs derived principally from or corroborated by observable market data by correlation or other means.
Level 3 - Unobservable inputs for the asset or liability. The fair value input hierarchy level to which an asset or liability measurement falls in its entirety is determined based on the lowest level input that is significant to the measurement in its entirety.
Non-recurring fair value measurements include certain nonfinancial assets and liabilities as may be acquired in a business combination and thereby measured at fair value; impaired oil and natural gas property assessments; warrants issued in equity offerings and the initial recognition of asset retirement obligations for which fair value is used. These estimates are derived from historical costs as well as management’s expectation of future cost environments. As there is no corroborating market activity to support the assumptions used, the Company has designated these estimates as Level 3.
The following tables present the Company’s assets and liabilities that are measured at fair value on a recurring basis as of December 31, 2017 and 2016, for each fair value hierarchy level:
Level 3 Gains and Losses
The table below sets forth a summary of changes in the fair value of the Company’s Level 3 liability for the year ended December 31, 2017.
Long-Lived Assets
Due to declines in commodity prices and estimated reserves over the last three years, there were indications that the carrying value of certain oil and natural gas properties may be impaired and undiscounted future cash flows attributed to these assets indicated their carrying amounts were not expected to be recovered. Their fair value was measured using an income approach based upon internal estimates of future production levels, prices, drilling and operating costs and discount rates, which are Level 3 inputs. We also considered the potential sale of certain of these properties. During 2017, we impaired $4.8 million of proved undeveloped leasehold costs in Wilson County. During 2016, we impaired $21.1 million of proved undeveloped leasehold costs in Texas, in connection with the sale of the Company’s conventional oil and natural gas assets.
Other Fair Value Measurements
The book values of cash and cash equivalents, receivables for oil, NGL and natural gas sales, joint interest billings, notes and other receivables and accounts payable approximate fair value due to the short-term nature of these instruments. The carrying value of debt approximates fair value since it is subject to a short-term floating interest rate that approximates the rate available to the Company, except for bonds, which are recorded at amortized cost less debt issuance costs. The fair value of the 8.750% Senior Notes (as defined in Note 9 below) approximates $158.9 million as of December 31, 2017, and the notes are considered a Level 3 liability, as they are based on market transactions that occur infrequently as well as internally generated inputs. The Company’s other Level 3 financial liabilities measured at fair value consist of the warrant liability as of December 31, 2017. Significant unobservable inputs used in the fair value measurement of the warrants include the estimated term. Significant decreases in the estimated remaining period to exercise would result in a significantly lower fair value measurement.
6. Oil and Gas Properties
A summary of oil and gas properties follows:
7. Asset Retirement Obligations
Pursuant to ASC 410, Asset Retirement Obligations, the Company recognizes the fair value of its asset retirement obligations related to the plugging, abandonment, and remediation of oil and gas producing properties. The present value of the estimated asset retirement costs has been capitalized as part of the carrying amount of the related long-lived assets, which approximated $5.3 million as of December 31, 2017.
The liability has been accreted to its present value as of December 31, 2017. The Company evaluated its wells and has determined a range of abandonment dates through December 2066.
The following represents a reconciliation of the asset retirement obligations:
(1)
Revisions of previous estimates during the year ended December 31, 2017 are primarily attributable to changes in estimates of the timing of future costs for oilfield services required to plug and abandon wells.
8. Accrued Liabilities
Accrued liabilities consist of the following:
9. Long-Term Debt
Long-term debt consists of the following:
Senior Secured Credit Facility
On July 28, 2015, LRAI closed a Credit Agreement for a $500 million Senior Secured Credit Facility with Citibank, N.A., as administrative agent, and other lenders party thereto (as amended, supplemented or modified from time to time, the “Credit Facility”). The Credit Facility had a maturity date of October 16, 2018 as of December 31, 2017. Consequent to redeeming the 8.750% Senior Notes (as defined below) in January 2018, the Credit Facility’s maturity date was extended to July 28, 2020. Due to the Company’s ability and intent to refinance the 8.750% Notes as of December 31, 2017, the Credit Facility was classified as a long-term liability on the Consolidated Balance Sheets as of said date. See Note 16, Subsequent Events, for more information. As of December 31, 2017 and 2016, $142.1 and $43.5 million was borrowed, respectively, under the Credit Facility. Borrowing availability was approximately $17.4 million at December 31, 2017.
The Credit Facility may be used for loans and, subject to a $2.5 million sub-limit, letters of credit, and provides for a commitment fee of 0.375% to 0.5% based on the unused portion of the borrowing base under the Credit Facility.
As of December 31, 2017, the borrowing base and lender commitments for the Credit Facility were $160.0 million. The borrowing base under the Credit Facility is determined semi-annually as of May 1 and November 1. On January 4, 2018, the Seventh Amendment and Limited Waiver, Borrowing Base Redetermination Agreement, and Amendment No. 7 to Credit Agreement dated January 4, 2018 reaffirmed the borrowing base at $160.0 million. This January 2018 redetermination constituted the regularly scheduled November 1 determination. See Note 16, Subsequent Events, for more information.
Borrowings under the Credit Facility, at LRAI’s election, bear interest at either: (i) an alternate base rate (“ABR”) equal to the higher of (a) the Prime Rate, (b) the Federal Funds Effective Rate plus 0.5% per annum, and (c) the adjusted LIBO rate of a three-month interest period on such day plus 1.0%; or (ii) the adjusted LIBO rate, which is the rate stated on Reuters screen LIBOR01 page, for one, two, three, six or twelve months, as adjusted for statutory reserve requirements for Eurocurrency liabilities, plus, in each of the cases described in clauses (i) and (ii) above, an applicable margin ranging from 1.50% to 2.50% for ABR loans and from 2.50% to 3.50% for adjusted LIBO rate loans (5.13% at December 31, 2017).
Subject to certain permitted liens, LRAI’s obligations under the Credit Facility have been secured by the grant of a first priority lien on no less than 80% of the value of the proved oil and gas properties of the Company and its subsidiaries (currently 90%).
The Credit Facility contains two financial covenants, as defined in the Credit Facility: (a) a maximum debt to EBITDAX ratio (discussed further below) and (b) a current ratio of not less than 1.0 to 1.0. As of December 31, 2017, the Company was in compliance with the minimum debt to EBITDAX ratio; however, the current ratio as of December 31, 2017 was approximately 0.7 to 1.0 due to low availability under the Credit Facility. Upon closing of the 11.250% Senior Notes, as defined below, in January 2018, the Credit Facility’s outstanding balance was paid down by $80.0 million, which increased the Credit Facility’s availability to a level sufficient for purposes of the current ratio. The Company obtained a limited waiver agreement for the current ratio violation from the Credit Facility’s lenders prior to issuance of the Company’s Form 10-K and Annual Report.
In connection with closing the Marquis Acquisition and the Battlecat Acquisition, on June 15, 2017, LRAI entered into the Sixth Amendment and Joinder to Credit Agreement (the “Sixth Amendment”) to (i) increase the borrowing base from $112 million to $160 million until redetermined or adjusted in accordance with the Credit Facility, (ii) modify the maximum leverage ratio threshold to be 4.0 to 1.0 for all periods, starting with the fiscal quarter ending September 30, 2017, and providing that EBITDAX (as defined in the Credit Facility) shall be calculated at the end of each fiscal quarter using the results of the twelve-month period ending with that fiscal quarter end; provided, that EBITDAX shall be calculated (x) at the end of the fiscal quarter ending September 30, 2017 using an amount equal to the EBITDAX for such fiscal quarter, multiplied by four, (y) at the end of the fiscal quarter ending December 31, 2017 using an amount equal to the EBITDAX for the two fiscal quarter period ended on such date, multiplied by two and (z) at the end of the fiscal quarter ending March 31, 2018 using an amount equal to the EBITDAX for the three fiscal quarter period ended on such date, multiplied by four-thirds, (iii) permit LRAI to declare and pay dividends to the Company equal to the amount of any cash dividends declared and payable in accordance with the terms of the Company’s Certificate of Designations of Convertible Participating Preferred Stock, Series A-1, and Certificate of Designations of Convertible Participating Preferred Stock, Series A-2, subject to certain specified terms and conditions and (iv) amend certain other provisions of the Credit Facility as more specifically set forth in the Sixth Amendment.
8.750% Senior Notes
On April 4, 2014, LRAI issued, at par, $220.0 million of 8.750% Senior Unsecured Notes due April 15, 2019 (the “8.750% Senior Notes”) to U.S.-based institutional investors.
On or after April 15, 2016, LRAI could redeem the 8.750% Senior Notes in whole or in part at the redemption prices (expressed as percentages of the principal amount) set forth in the following table plus accrued and unpaid interest, if any, on the 8.750% Senior Notes redeemed, to the applicable date of redemption, if redeemed during the twelve-month period beginning on April 15 of the years indicated below:
The 8.750% Senior Notes has covenants that, among other things, limit the ability of LRAI and its subsidiaries to: incur indebtedness; pay dividends or make other distributions on stock; purchase or redeem stock or subordinated indebtedness; make investments; create liens; enter into transactions with affiliates; sell assets; refinance certain indebtedness; and merge with or into other companies or transfer substantially all of LRAI’s assets.
In January 2018, the Company redeemed the 8.750% Senior Notes in whole using proceeds from the 11.250% Senior Notes, as defined below. See Note 16, Subsequent Events, for more information.
Debt Issuance Costs
The Company capitalizes certain direct costs associated with the issuance of long-term debt and amortizes such costs over the lives of the respective debt. At December 31, 2017 and 2016, the Company had approximately $2.3 and $1.2 million, respectively, of debt issuance costs associated with issuance of the Senior Secured Credit Facility remaining that are being amortized over the lives of the respective debt which are recorded as Other Non-Current Assets in the Consolidated Balance Sheets.
Securities Purchase Agreement and Second Lien Notes
On August 2, 2016, the Company entered into a Securities Purchase Agreement with Juneau Energy, LLC, as initial purchaser (“Juneau”), Leucadia National Corporation (“Leucadia”), as guarantor of Juneau’s obligations, the other purchasers party thereto and Jefferies, LLC, in its capacity as the collateral agent for the purchasers, relating to the issuance and sale of (i) up to $49.9 million aggregate principal amount of LRAI’s 12% senior secured second lien notes due 2021 (the “Second Lien Notes”) and (ii) five-year warrants to purchase up to an aggregate 998,000 shares of the Company’s Class A voting common stock at a price equal to $5.00 per share (the “Warrants”). The balance of these notes and warrants is reflected in the Company’s Long-Term Debt - Related Parties and Equity Warrant Liability -Related Parties on the Consolidated Balance Sheets. The Second Lien Notes are secured by second-priority liens on substantially all of LRAI’s and its subsidiaries’ assets to the extent such assets secure obligations under the Credit Facility.
During 2016, LRAI issued $38.0 million in aggregate principal amount of Second Lien Notes and the Company issued the Warrants to purchase 760,000 shares of its Class A voting common stock. The Company recorded an equity warrant liability of approximately $5.1 million which was the fair value amount at the date of issuance. The Warrants were adjusted to fair value at December 31, 2017 which resulted in a gain on the Warrants of approximately $3.1 million for the year ended December 31, 2017, which is recorded in the Consolidated Statements of Operations. Proceeds from the Second Lien Notes issuance were used to repurchase approximately $68.2 million in aggregate principal amount of the 8.750% Senior Notes in privately negotiated open market repurchases with holders of such notes, and to pay related fees and expenses related to the foregoing. The repurchase amounts paid were approximately $36.2 million in cash. Net of related fees, such repurchases resulted in a gain on debt extinguishment of approximately $28.5 million.
In December 2016, LRAI repaid $21.0 million principal of the Second Lien Notes with proceeds from the offering of the Company’s Class A voting common stock that was completed on December 22, 2016 pursuant to a Registration Statement on Form S-1 (File No. 333-214265), which was declared effective on December 15, 2016 (the “2016 Common Stock Offering”). In June 2017, LRAI repaid the remaining $17.0 million principal of the Second Lien Notes including an early payment premium of approximately $1.1 million with borrowings from the Company’s Credit Facility.
Repurchase Facilitation Agreement
On October 26, 2016, effective September 29, 2016, Lonestar Resources US, Inc. (the “Company”), by and on behalf of itself and certain of its subsidiaries, entered into an Amended and Restated Repurchase Facilitation Agreement (the “Amended and Restated Agreement”) with Seaport Global Securities LLC, a Delaware limited liability company (“Seaport Global”). Pursuant to the Amended and Restated Agreement, Seaport Global has agreed to provide the Company with financing (“Gap Financing”) from time to time in connection with the repurchase of the 8.750% Senior Notes, to be acquired by Seaport Global on the Company’s behalf in one or more open market purchases. In December 2016, LRAI repaid the Gap Financing with proceeds from the 2016 Common Stock Offering.
10. Income Taxes
The current and deferred components of income tax (benefit) expense are as follows:
The following table provides a reconciliation of the Company’s actual income tax provision amounts from the expected income tax provision amount by applying the U.S. federal statutory corporate income tax rate of 35% for the periods indicated:
The tax effects of the Company’s temporary differences that give rise to significant portions of the deferred tax assets and liabilities are presented below:
The net operating loss carryforward as of December 31, 2017, approximates $99.4 million and begins to expire in 2030.
On December 22, 2016, the Company completed a public offering of 13.8 million of its Class A common stock. A change of ownership, as defined under the provisions of Section 382 of the Internal Revenue Code (“IRC”) occurred on this date. A portion of our net operating loss and tax credit carryforwards will be limited in future periods. IRC Section 382 places limitations on the amount of taxable income which may be offset by tax carryforward attributes, such as net operating losses or tax credits after a change of ownership event. As a result of this ownership change, certain of our accumulated net operating losses will be subject to an annual limitation regarding their utilization against taxable income in future periods. The 2016 change creates an estimated annual utilization limit of approximately $1.0 million on our ability to utilize net operating losses generated prior to the ownership change event. Built-in gains associated with our deferred tax attributes on the date of the ownership change may increase the net operating loss utilization limit in future periods, allowing additional utilization of net operating losses generated prior to the date of the ownership change. Due to the ownership change and the resulting limitation on the utilization of net operating loss generated prior to the change, an estimated $141.7 million of the net operating loss carryforwards were written off in 2016. The Company has approximately $8.7 million of percentage depletion carryover which has no expiration.
On June 15, 2017, the Company entered into an amended and restated purchase agreement with Chambers Energy Capital III, LP (“Chambers”) where the Company closed transactions issuing Chambers 5,400 shares of Series A-1 Preferred Stock and 74,600 shares of Series A-2 Preferred Stock. These transactions created an additional change of ownership under the provision of Section 382 of the IRC. The 2017 change creates an additional estimated annual utilization limit of approximately $0.8 million on our ability to utilize net operating losses generated subsequent to the 2016 change in ownership, but prior to the June, 2017 change in ownership.
If the Company were to experience another ownership change in future periods, the net operating loss carryforwards may be subject to additional utilization limits
The Company files income tax returns in the United States federal jurisdiction and in various state jurisdictions. At December 31, 2017, there are no current examinations of federal or state jurisdictions in progress. The Company’s income tax returns related to fiscal years ended December 31, 2010 through 2017 remain open to possible examination by the tax authorities. The Company has not recorded any interest or penalties associated with uncertain tax positions.
Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to reverse. As a result of the reduction in the U.S. corporate income tax rate from 35% to 21% under the Tax Cuts and Jobs Act (the “Act”), the Company revalued its deferred tax assets and liabilities at December 31, 2017, which resulted in a $6.3 million benefit.
The corporate alternative minimum tax (“AMT”) for tax years beginning in January 1, 2018 has also been repealed. The Act provides that existing AMT credit carryovers are refundable beginning in 2018. As of December 31, 2017, the Company had AMT credit carryovers of $2.4 million that are expected to be fully refunded by 2022.
The deductibility of interest expense for tax years beginning in January 1, 2018 has been limited to 30% of earnings before interest, taxes, depreciation, and amortization for four years ending 2021. Deductibility of interest expense for tax years beginning in January 1, 2022 will then be limited to 30% of earnings before interest and taxes thereafter. The Company has not yet evaluated the impact of this provision.
The Act is a comprehensive bill containing other provisions, and the ultimate impact from the Act may differ from the Company’s estimates as of December 31, 2017 due to changes in the interpretations and assumptions made by the Company as well as additional regulatory guidance that may be issued.
11. Stockholders’ Equity
Preferred Stock
The Company is authorized to issue up to 10,000,000 shares of preferred stock with a par value of $0.001. The Company’s preferred stock may be entitled to preference over the common stock with respect to the distribution of assets of the Company in the event of liquidation, dissolution or winding-up of the Company, whether voluntarily or involuntarily, or in the event of any other distribution of assets of the Company among its shareholders for the purpose of the winding-up of its affairs. The authorized but unissued shares of the preferred stock may be divided into and issued in designated series from time to time by one or more resolutions adopted by the board of directors of the Company. The board, in their sole discretion, shall have the power to determine the relative powers, preferences and rights of each series of preferred stock.
Series A & B Preferred Stock
On June 15, 2017, in connection with financing the Battlecat and Marquis Acquisitions, the Company issued 5,400 shares of Series A-1 Convertible Participating Preferred Stock, par value $0.001 per share (the “Series A-1 Preferred Stock”) and 74,600 shares of Series A-2 Convertible Participating Preferred Stock, par value $0.001 per share (the “Series A-2 Preferred Stock” and, together with the Series A-1 Preferred Stock, the “Series A Preferred Stock”), to Chambers Energy Capital (“Chambers”). Also, on June 15, 2017, in connection with the Battlecat and Marquis Acquisitions, the Company issued 1,184,632 and 1,500,000 shares of Series B Preferred Stock to Battlecat and Marquis, respectively (see Note 3, Acquisitions and Divestitures).
Pursuant to the terms of the Chambers agreement, the Company agreed to use commercially reasonable efforts to hold a stockholder meeting (the “Stockholder Meeting”) to obtain stockholder approval of the issuance of shares of the Company’s Class A voting common stock issuable upon conversion of all shares of Series A-1 Preferred Stock and Series A-2 Preferred Stock (upon their conversion to shares of Series A-1 Preferred Stock) issued or issuable pursuant to the agreement (the “Stockholder Approval”). The Stockholder Meeting was held on November 3, 2017, and Stockholder Approval was obtained. As a result of the Stockholder Approval, all outstanding Series A-2 Preferred Stock was converted to Series A-1 Preferred Stock. Also, on November 3, 2017, in accordance with the terms of the Series B Certificate of Designations, all of the outstanding shares of the Company’s Series B Preferred Stock were converted on a one-for-one basis into shares of the Company’s Class A voting common stock.
After the Chambers agreement closing, and for so long as the Approved Holders (as defined) beneficially own at least 10% of the total number of outstanding shares of Class A voting common stock and Class B non-voting common stock (collectively, “Common Stock”) of the Company, on an as-converted basis, or at least 15% of the number of Series A Preferred Stock issued to Chambers, the Company cannot undertake certain actions without the prior consent of holders of a majority of all shares of Common Stock, on an as-converted basis, held by the Approved Holders. Prior to June 15, 2020, Chambers and its affiliates are prohibited from directly or indirectly engaging in any short sales involving the Common Stock or securities convertible into, or exercisable or exchanged for, Common Stock. Without the prior written consent of the board, the Approved Holders are subject to customary standstill restrictions until the earlier of (i) the two-year anniversary of the date the Approved Holders are no longer entitled to designate any director to the Board and (ii) the date the Company fails to fully declare and pay all accrued dividends on either series of the Series A Preferred Stock after there are no PIK Quarters (as defined below) remaining. In connection with the closing and the issuance of shares of Series A Preferred Stock, the Company entered into a registration rights agreement with Chambers (the “Chambers RRA”). Under the Chambers RRA, the Company has agreed to provide to Chambers certain customary demand and piggyback registration rights relating to Chambers’ ownership of Company stock. The Chambers RRA contains customary terms and conditions, including certain customary indemnification obligations.
The Series A-1 Preferred Stock ranks senior to Class A voting common stock with respect to dividend rights and rights upon the liquidation, winding-up or dissolution of the Company, and the series initially has a stated value of $1,000 per share. Holders of Series A-1 Preferred Stock are entitled to vote with holders of Class A voting common stock on an as-converted basis. Shares of Series A-1 Preferred Stock are convertible into shares of Class A voting common stock at the option of the holders of such Series A-1 Preferred Stock at a per share rate (the “Conversion Rate”) equal to the Stated Value of such share divided by six, subject to certain adjustments (the “Conversion Price”). The Company has the option to convert Series A-1 Preferred Stock to Class A voting common stock if the volume weighted average price of Class A voting common stock exceeds the following percentages of the Conversion Price for twenty out of thirty consecutive trading days: (i) 200%, if such mandatory conversion occurs prior to June 15, 2019, (ii) 175%, if such mandatory conversion occurs after June 15, 2019 but before June 15, 2020, and (iii) 150%, if such mandatory conversion occurs after June 15, 2020.
Holders of Series A Preferred Stock are entitled to cumulative dividends payable quarterly initially at a rate of 9% per annum (the “Dividend Rate”) in cash and, for any 12 quarters (“PIK Quarters”), at the Company’s option, (i) in the form of additional shares of the respective series of Series A Preferred Stock at a per share price equal to $975 or (ii) by increasing Stated Value, in lieu of cash (collectively, the “PIK Option”). After the 12 PIK Quarters, if the Company fails to fully declare and pay dividends in cash, then the Dividend Rate for Series A Preferred Stock will automatically increase by 5.0% per annum for the next succeeding dividend period and then an additional 1.0% for each successive dividend period, up to a maximum Dividend Rate of 20.0% per annum, until the Company pays dividends at such increased rate fully in cash for two consecutive quarters. In addition to dividends rights described above, holders of the Series A Preferred Stock are entitled to receive dividends or distributions declared or paid on Class A voting common stock on an as-converted basis. If on June 15, 2024, the Prevailing Price is less than the Conversion Price then in effect, the Dividend Rate for Series A-1 Preferred Stock will automatically increase to 20.0% per annum, payable only in cash, unless automatically converted as described above. However, the Company, at its option, may instead elect to exchange each share of Series A-1 Preferred Stock for senior unsecured notes of the Company with a two-year maturity, a 9.0% per annum coupon payable semi-annually in cash, and governed by terms substantially similar to the Company’s most recent high yield indenture at that time. After June 15, 2020, the Company may redeem shares of Series A Preferred Stock in cash at a per share amount equal to (i) 110% of the
Stated Value, if the redemption occurs prior to June 15, 2021, (ii) 105% of the Stated Value, if the redemption occurs prior to June 15, 2022, and (iii) 100% of the Stated Value, if the redemption occurs after June 15, 2022, in each case, plus any unpaid dividends.
For the third and fourth quarters of 2017, the Company elected the PIK Option for the Class A Preferred Stock dividend payment, which resulted in the issuance of 1,991 additional shares of Series A-1 Preferred Stock and 1,977 additional shares of Series A-2 Preferred Stock, which were subsequently converted to shares of Series A-1 Preferred Stock during the fourth quarter of 2017.
Common Stock Issuances
On November 3, 2017, as described above, the Company issued 2,684,632 shares of Class A voting common stock on a one-for-one basis in exchange for all of the of the Company’s outstanding Series B Preferred Stock.
On December 22, 2016, the Company completed the 2016 Common Stock Offering of 13.8 million shares of its Class A voting common stock at a price of $5.75 per share, for proceeds of approximately $71.8 million, net of offering costs. The Company used the net proceeds from the stock offering to repay borrowings under its Credit Facility, Second Lien Notes and to repay the debt owed under the Facilitation Agreement with Seaport Global.
On August 2, 2016, the Company entered into a purchase and sale agreement with Juneau Energy, LLC (“Juneau”) whereby the Company obtained an undivided 50% of Juneau’s interest in two producing wells and each well’s respective oil and gas leases covering approximately 1,300 net mineral acres located in Brazos County, Texas. The total consideration paid by the Company was $5.5 million payable in 500,227 shares of the Company’s Class A voting common stock.
In July 2016, the Company issued 2,500 shares of Class B non-voting common stock to Butterfly Flaps, Ltd., a Company in which Dr. Christopher Rowland (a director of the Company) owns an interest. The shares were issued for services to be performed by Butterfly Flaps, Ltd. in 2017. See Note 14, Related Party Activities, for more information.
12. Stock-Based Compensation and Other Incentives
Determining Fair Value of Stock Options
In determining the fair value of stock option grants, the Company utilized the following assumptions:
Valuation and Amortization Method. The Company estimates the fair value of stock option awards on the date of grant using the Black-Scholes-Merton valuation model. The fair value of all awards is expensed using the “graded-vesting method.”
Expected Life. The expected life of stock options granted represents the period of time that stock options are expected, on average, to be outstanding. The Company determined the expected life to be 3.5 years, for all stock options issued with three-year vesting periods and four-year grant expirations.
Expected Volatility. Using the Black-Scholes-Merton valuation model, the Company estimates the volatility of Predecessor’s common shares at the beginning of the quarter in which the stock option is granted. The volatility of 58.6% is based on weighted average historical movements of Predecessor’s common share price on the ASX over a period that approximates the expected life.
Risk-Free Interest Rate. The Company utilizes a risk-free interest rate equal to the rate of U.S. Treasury zero-coupon issues as of the date of grant with a term equivalent to the stock option’s expected life.
Expected Dividend Yield. The Predecessor and the Successor have not paid any cash dividends on its common shares, and the Successor does not anticipate paying any cash dividends in the foreseeable future. Consequently, a dividend yield of zero is utilized in the Black-Scholes-Merton valuation model.
Expected Forfeitures. The Company has experienced limited forfeitures and therefore has not discounted expenses for forfeitures at the reporting date.
Stock Option Activity
For the year ended December 31, 2017, no stock options were exercised. The following tables summarize certain information related to outstanding stock options under the Lonestar Resources Limited 2012 Employee Share Option Plan and the Lonestar Resources US Inc. 2016 Incentive Plan, which replaced the Lonestar Resources Limited 2012 Employee Share Option Plan following the Reorganization. The number of shares that may be issued under the 2016 Incentive Plan is 2.2 million shares. The number of shares available for issuance under the 2016 Incentive Plan is approximately 0.8 million shares.
Restricted Stock Units
In February 2017, the Company granted awards of restricted stock units (“RSUs”) covering 612,000 shares to certain of its employees. In August 2017, 100,000 units were issued to the Company’s chairman of the board of directors. In October 2017, 28,409 units were issued to the Company’s internal general counsel. The awards vest over a three-year period as follows: 40% on the first anniversary of issuance and 30% on each of the second and third anniversaries of issuance, such that the RSU’s will be fully vested on the third anniversary of issuance. The Company determines the fair value of granted RSUs based on the market price of the Class A voting common stock of the Company on the date of grant. RSUs will be paid in Class A voting common stock or cash, at the Company’s option, after the vesting of the applicable RSU. Compensation expense for granted RSUs is recognized over the vesting period.
Stock Appreciation Rights
In February 2017, the Company granted awards of stock appreciation rights (“SARs”) covering 700,000 shares to certain of its employees and its non-employee directors. The awards vest over a three-year period as follows: 40% on the first anniversary of issuance and 30% on each of the second and third anniversaries of issuance, such that the SAR’s will be fully vested on the third anniversary of issuance. The SARs will expire five-years after the date of issuance. The exercise price of the SAR is the fair market value of the Company’s Class A voting common stock on the date of the grant. The SAR entitles the holder to receive from the Company upon exercise of the exercisable portion of the SAR an amount determined by multiplying the excess of the fair market value of one share on the date of exercise over the exercise price per share by the number of shares with respect to which the SAR is exercised. SARs will be paid in cash or common stock at holder’s election once the SAR is vested, with the provision that the Company possesses sufficient liquidity to allow for cash settlement of the SAR. The SARs are being treated as a liability in the Consolidated Balance Sheets. The SAR liability is approximately $0.3 million for the year ended December 31, 2017.
Stock-Based Compensation Expense
For the year ended December 31, 2017 the Company recorded stock-based compensation expense for RSUs and SARs of approximately $1,315 and $314 thousand, respectively. For the year ended 2016, the Company recorded stock-based compensation expense for stock options granted using the fair-value method of approximately $448 thousand. As of December 31, 2017, the Company had approximately $2,725 and $629 thousand of unrecognized compensation cost related to unvested RSUs and SARs, respectively. As all outstanding stock options expired December 31, 2017, no unrecognized compensation cost existed at December 31, 2017.
401(k) Plan
The Company offers a 401(k) plan to which employees may contribute earnings subject to IRS limitations. The Company matches 100% of an employee’s contribution, up to 4% of compensation, as defined by the plan, which is vested immediately. During 2017 and 2016, the Company’s matching contributions to the 401(k) plan were approximately $147 and $155 thousand, respectively.
13. Earnings Per Share
Basic earnings or loss per share shown on the Consolidated Statements of Operations is computed on the basis of the weighted average number of common shares outstanding during the periods. Diluted earnings or loss per share is computed based upon the weighted average number of common shares outstanding plus the assumed issuance of common shares for all potentially dilutive securities to include warrants, equity compensation awards, and preferred equity shares under the as-converted method. The Company includes the number of stock options in the calculation of diluted weighted average shares outstanding when the grant date or exercise prices are less than the average market prices of the Company’s Class A common stock for the period. When a loss from operations exists, all potentially dilutive common shares outstanding are anti-dilutive and therefore excluded from the calculation of diluted weighted average shares outstanding. There is no dilutive effect for the years ended December 31, 2017 and 2016 as the Company reported a loss from operations for those periods.
The following table presents unaudited earnings per share of Lonestar Resources US Inc., assuming that the 1-for-2 reverse stock split upon Reorganization had occurred at the beginning of the year ended December 31, 2016:
14. Related Party Activities
Leucadia
On August 2, 2016, LRAI and the Company entered into a Securities Purchase Agreement (the “Purchase Agreement”) with Juneau, as initial purchaser, Leucadia as guarantor of Juneau’s obligations, the other purchasers party thereto and Jefferies, LLC, in its capacity as the collateral agent for the purchasers, relating to the issuance and sale of (i) up to $49.9 million aggregate principal amount of LRAI’s 12% senior secured second lien notes due 2021 (“Second Lien Notes”) and (ii) five-year warrants to purchase up to an aggregate 998,000 shares of the Company’s Class A voting common stock at a price equal to $5.00 per share (the “Warrants”). During 2016, LRAI issued $25.0 million in aggregate principal amount of Second Lien Notes and the Company issued Warrants to purchase 500,000 shares of its Class A voting common stock to Juneau. In December 2016, LRAI repaid to Juneau $21.0 million principal of the Second Lien Notes with proceeds from the 2016 Common Stock Offering.
In connection with entering into the Purchase Agreement, the Company also entered into a registration rights agreement and an equity commitment agreement, both dated as of August 2, 2016. Pursuant to the registration rights agreement, the Company has agreed to register for resale certain Class A voting common stock issued or issuable to Juneau and Leucadia, including those issuable upon exercise of the Warrants. Leucadia agreed, pursuant to the equity commitment agreement, to purchase a certain number of Class A voting common stock in case the Company elected to pursue an equity offering prior to December 31, 2016. Pursuant to the equity commitment agreement, Leucadia purchased 3,478,261 shares of Class A voting common stock (costing $20 million) through the 2016 Common Stock Offering, which closed on December 22, 2016. In connection with Leucadia’s equity commitment, the Company paid Leucadia on January 3, 2017 a $1.0 million fee, which was recorded as a reduction to additional paid-in capital. In the event Leucadia purchased not less than its commitment amount, the Company agreed to use commercially reasonable efforts to enter into arrangements to provide Leucadia with the right to appoint one director to the Board of the Company, provided that such right will terminate at such time as Leucadia and its affiliates own a number of shares of Class A voting common stock equal to less than 50% of the shares purchased by Leucadia and its affiliates in such offering. Leucadia has elected to take an observer position on the board of directors, with no voting rights.
EF Realisation
On October 26, 2016, the Company entered into a Board Representation Agreement (the “Board Representation Agreement”) with EF Realisation Company Limited (“EF Realisation”). Under the Board Representation Agreement, for as long as EF Realisation, together with its affiliates, beneficially owns 15% or more of the issued and outstanding shares of the Company’s Class A voting common stock, it has the right to nominate up to, but no more than, two directors to serve on the Board and for as long as EF Realisation, together with its affiliates, beneficially owns at least 10% but less than 15% of the Company’s issued and outstanding shares of Class A voting common stock, it has the right to nominate up to, but no more than, one director to serve on the Board.
On October 26, 2016, the Company entered into a Registration Rights Agreement with EF Realisation, pursuant to which the Company agreed to register for resale Class A voting common stock indirectly owned by EF Realisation. The Company agreed to file a registration statement providing for the resale of Class A voting common stock held by EF Realisation no later than the earlier of (i) October 26, 2017, and (ii) 30 days after the date the Company first becomes eligible to file a registration statement on Form S-3. The Form S-3 registration statement was filed with the Securities and Exchange Commission on November 7, 2017, and is effective. The Company has also granted EF Realisation certain piggyback and demand registration rights.
Amendment of Registration Rights Agreement
In connection with the consummation of the Battlecat Acquisition, the Marquis Acquisition and the Purchase Agreement, on June 15, 2017, the Company entered into (i) a first amendment to the registration rights agreement (the “Leucadia RRA Amendment”) with Leucadia and JETX Energy, LLC (f/k/a Juneau Energy, LLC), which amends the registration rights agreement, dated as of August 2, 2016, by and among the same parties, and (ii) a first amendment to registration rights agreement (the “EF RRA Amendment” and, together with the Leucadia RRA Amendment, the “RRA Amendments”) with EF Realisation, which amends the registration rights agreement, dated as of October 26, 2016, by and between the same parties. The RRA Amendments set forth the relative priorities, with respect to demand and piggyback registration rights, among each applicable party thereto, Battlecat, Marquis and Chambers under their respective registration rights agreements with the Company.
Other Related Party Transactions
Butterfly Flaps, Ltd, a company in which Dr. Christopher Rowland (a director of the Company) owns an interest, has performed consultancy work for the Company since 2013 covering various strategic, tax structuring and investor matters at a cost of approximately $25,000 per quarter. The consulting arrangement terminated effective December 31, 2016.
New Tech Global Ventures, LLC, a company in which Daniel R. Lockwood (a director of the Company) owns a limited partnership interest, has provided field engineering staff and consultancy services for the Company since 2013. The total cost for such services was approximately $1,015 and $655 thousand for the years ended December 31, 2017 and 2016, respectively.
15. Commitments and Contingencies
Litigation
The Company is subject to certain claims and litigation arising in the normal course of business. In the opinion of management, the outcome of such matters will not have a materially adverse effect on the consolidated results of operations or financial position of the Company.
Environmental Remediation
Various federal, state, and local laws and regulations covering the discharge of materials into the environment, or otherwise relating to the protection of the environment, may affect the Company’s operations and the costs of its oil and gas exploration, development, and production operations. The Company does not anticipate that it will be required in the near future to expend significant amounts in relation to the consolidated financial statements taken as a whole by reason of environmental laws and regulations, and appropriately no reserves have been recorded.
Lease Agreement
The Company entered into an operating lease agreement for its corporate office in October 2014 which will expire in October 2021. Future minimum annual lease payments are as follows:
Rent expense was approximately $439 and $375 thousand for the years ended December 31, 2017 and 2016, respectively. The Company relocated its corporate office to an owned building in February 2018 but will continue to be responsible for the minimum annual lease payments noted above regardless of subrental income, if any, the Company will receive from the property going forward.
Significant Contracts
As of December 31, 2017, the Company had one drilling rig under contract. The contract, which expires on July 19, 2018, provides for a drilling rate $18,500 per day through January 18, 2018, at which time the daily rate increases to $18,750 per day through the remainder of the term. The early termination fee equals 80% of the daily drilling rate times the number of days remaining on the contract term, which was approximately $2.7 million as of December 31, 2017.
In February 2018, the Company signed an additional rig under contract to drill four wells commencing in April 2018 and provides for a drilling rate of $20,000 per day. The early termination fee equals the greater of demobilization costs or $200,000, plus $200,000 for each undrilled well.
In March 2018, the Company signed a dedicated fleet contract that provides for hydraulic fracturing and wireline services at variable rates depending on the work performed. The early termination fee equals $133,000 for each of 15 scheduled wells that is not hydraulically fractured as of the date of termination. The contract expires on December 31, 2018.
16. Subsequent Events
11.250% Senior Notes
On January 4, 2018, the Company issued $250.0 million of 11.250% senior notes due 2023 (the “11.250% Senior Notes”) to U.S.-based institutional investors. The net proceeds of $244.4 million were used to fully retire the 8.750% Senior Notes, which included principal, interest and a prepayment premium of approximately $162 million (see Note 9. Long-Term Debt). The remaining net proceeds were used to reduce borrowings under the Credit Facility.
The 11.250% Senior Notes mature on January 1, 2023, and bear interest at the rate of 11.250% per year, payable on January 1 and July 1 of each year, beginning July 1, 2018. At any time prior to January 1, 2021, the Company may, on any one or more occasions, redeem up to 35% of the aggregate principal amount of the 11.250% Senior Notes with an amount of cash not greater than the net cash proceeds of certain equity offerings at a redemption price equal to 111.250% of the principal amounts redeemed, plus accrued and unpaid interest, provided that at least 65% of the aggregate principal amount of 11.250% Senior Notes originally issued remains outstanding immediately after such redemption and the redemption occurs within 180 days of the closing date of such equity offering.
At any time prior to January 1, 2021, the Company may, on any one or more occasions, redeem all or a part of the 11.250% Senior Notes at a redemption price equal to 100% of the principal amount redeemed, plus a “make-whole” premium as of, and accrued and unpaid interest.
On and after January 1, 2021, the Company may redeem the 11.250% Senior Notes, in whole or in part, plus accrued and unpaid interest, at the following redemption prices: 108.438% after January 1, 2021; 105.625% after January 1, 2022; and 100% after July 1, 2022.
The indenture contains certain restrictions on the Company’s ability to incur additional debt, pay dividends on the Company’s common stock, make investments, create liens on the Company’s assets, engage in transactions with affiliates, transfer or sell assets, consolidate or merger, or sell substantially all of the Company’s assets.
Credit Facility Amendment
On January 4, 2018, the Company entered into the Limited Waiver, Borrowing Base Redetermination Agreement, and Amendment No. 7 to the Credit Agreement, which included the following provisions:
•
maintained the borrowing base of $160 million until the next redetermination date;
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waived the borrowing base redetermination that would otherwise have occurred in connection with the incurrence of the 11.250% Senior Notes, and
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amended certain other provisions of the Credit Facility.
Extension of Credit Facility Maturity Date
As a result of the redemption of the 8.750% Senior Notes, the issuance of the 11.250% Senior Notes and the existing terms of the Credit Facility, the maturity date of the Credit Facility was extended in January 2018 from October 16, 2018, to July 28, 2020.
Lonestar Resources US Inc.
Unaudited Supplementary Information
SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES (UNAUDITED)
Capitalized Costs
The following table presents the Company’s aggregate capitalized costs relating to oil and gas activities at the end of the periods indicated:
Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development
The following table summarizes costs incurred in oil and natural gas property acquisition, exploration and development activities. Property acquisition costs are those costs incurred to purchase, lease or otherwise acquire property, including both undeveloped leasehold and the purchase of reserves in place. Exploration costs include costs of identifying areas that may warrant examination and examining specific areas that are considered to have prospects containing oil and natural gas reserves, including costs of drilling exploratory wells, geological and geophysical costs, and carrying costs on undeveloped properties. Development costs are incurred to obtain access to proved reserves, including the cost of drilling development wells, and to provide facilities for extracting, treating, gathering and storing the oil and natural gas.
Costs incurred also include new asset retirement obligations established, as well as changes to asset retirement obligations resulting from revisions in cost estimates or abandonment dates. Asset retirement obligations included in the table below were $2.8 million during the year ended December 31, 2017 and zero during the year ended December 31, 2016. See Note 7, Asset Retirement Obligations, for more information.
Results of Operations
The following presents the results of operations from oil and natural gas producing activities:
Crude Oil and Natural Gas Reserves
The reserve information presented below is based upon estimates of net proved oil and natural gas reserves that were prepared by W.D. Von Gonten & Co., independent petroleum engineers located in Houston. These oil and natural gas reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for undeveloped acreage. The reserve estimates represent our net revenue interest in our properties.
Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible in future years from known reservoirs under existing economic conditions, operating methods and governmental regulations (i.e. prices and costs of the date the estimate is made). The project to extract the hydrocarbons must have commenced or the interest owner must be reasonably certain that it will commence within a reasonable period of time.
Reservoir engineering, which is the process of estimating quantities of crude oil and natural gas reserves, is complex, requiring significant decisions in the evaluation of all available geological, geophysical, engineering and economic data for each reservoir. These estimates are dependent upon many variables, and changes occur as knowledge of these variables evolves. Therefore, these estimates are inherently imprecise, and are subject to considerable upward or downward adjustments. Actual production, revenues and expenditures with respect to reserves will likely vary from estimates, and such variances could be material. In addition, reserve estimates for properties which have not yet been drilled, or properties with a limited production history may be less reliable than estimates for properties with longer production histories. All of the Company’s reserves are located in the United States.
Estimated Quantities of Proved Reserves
(1)
MBoe (One thousand barrels of oil equivalent) is calculated by converting 6 MMcf of natural gas to 1 MBbl of oil. A MBbl (barrel) of oil is one thousand stock tank barrels, or 42 thousand U.S. gallons liquid volume, of crude oil or other liquid hydrocarbons.
The following is a discussion of the changes in the Company’s proved oil and natural gas reserves estimates for the years ended December 31, 2017 and 2016.
The Company’s proved oil and natural gas reserves increased to 73,555 MBoe at December 31, 2017 from 40,540 MBoe at December 31, 2016. The Company’s proved oil and natural gas reserves increased by 35,375 MBoe and the Company produced 2,360 MBoe during the year ended December 31, 2017, resulting in a net increase of 33,015 MBoe. An increase of 29,847 MBoe was the result of the purchase of reserves in place, which primarily came from reserves acquired through the Battlecat and Marquis Acquisitions in June 2017. An increase of 4,021 MBoe in 2017 was the result of new discoveries and extensions, which was primarily attributable to drilling operations in the Western and Central Eagle Ford. The Company’s proved oil and natural gas reserves also increased by 1,507 MBoe during 2017 due to revisions of prior estimates, which were attributable to better-than-projected well performance from certain wells and higher weighted-average oil and natural gas prices used to estimate proved reserves in 2017, as compared to 2016. The Company’s proved developed oil and natural gas reserves increased to 18,342 MBoe at December 31, 2017 from 10,998 MBoe at December 31, 2016, primarily due to proved developed reserves purchased as part of the Battlecat and Marquis Acquisitions in June 2017, as well as drilling operations in the Western and Central Eagle Ford. At December 31, 2017, the Company’s proved reserves were made up of approximately 84% oil and 16% natural gas and were approximately 25% proved developed and approximately 75% proved undeveloped.
The Company’s proved oil and natural gas reserves increased to 40,540 MBoe at December 31, 2016 from 40,202 MBoe at December 31, 2015. The Company’s proved oil and natural gas reserves increased by 2,495 MBoe and the Company produced 2,157 MBoe during the year ended December 31, 2016, resulting in a net increase of 338 MBoe. An increase of 6,660 MBoe in 2016 was the result of new discoveries and extensions, which was primarily attributable to drilling operations and associated offset locations. The Company’s proved oil and natural gas reserves decreased by 2,456 MBoe during 2016 due to revisions of prior estimates, which were attributable to lower weighted-average oil and natural gas prices used to estimate proved reserves in 2016, as compared to 2015. A decrease of 2,048 MBoe in 2016 was due to reserves sold, which resulted from the divesture of the Company’s conventional assets during the year. An increase of 339 MBoe was the result of the purchase of reserves in place, which primarily came from working interest acquisitions in the Eastern Eagle Ford. The Company’s proved developed oil and natural gas reserves decreased to 10,998 MBoe at December 31, 2016 from 13,330 MBoe at December 31, 2015, primarily due to the sale of conventional assets during 2016. At December 31, 2016, the Company’s proved reserves were made up of approximately 75% oil and 25% natural gas and were approximately 27% proved developed and approximately 73% proved undeveloped.
Standardized Measure of Discounted Future Net Cash Flows
Certain information concerning the assumptions used in computing the valuation of proved reserves and their inherent limitations are discussed below. The Company believes that such information is essential for a proper understanding and assessment of the data presented.
For the years ended December 31, 2017 and 2016, calculations were made using average prices of $51.34 and $42.75 per barrel of crude oil, respectively, and $2.98 and $2.46 per MCF of natural gas, respectively. NGL pricing used was approximately 30% of crude oil prices. Prices and costs are held constant for the life of the wells; however, prices are adjusted by well in accordance with sales contracts, energy content quality, transportation, compression and gathering fees, and regional price differentials.
These assumptions used to compute the standardized measure are those prescribed by the FASB and the SEC, and do not necessarily reflect the Company’s expectations of the actual net cash flow to be derived from those reserves, nor the present worth of the properties. Further, actual future net cash flows will be affected by factors such as the amount and timing of actual production, supply and demand for crude oil and natural gas, and changes in governmental regulations and tax rates. Sales prices of both crude oil and natural gas have fluctuated significantly in recent years.
Future development and production costs are computed by estimating the expenditures to be incurred in developing and producing the proved crude oil and natural gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions.
A 10% annual discount rate is used to reflect the timing of the future net cash flows relating to proved reserves.
The standardized measure of discounted future net cash flows was as follows:
Changes in the standardized measure of discounted future net cash flows relating to proved crude oil and nature gas reserves were as follows: