EDGAR 10-K Filing

Company CIK: 1661920
Filing Year: 2021
Filename: 1661920_10-K_2021_0001661920-21-000008.json

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ITEM 1. BUSINESS
Item 1. Business.
General
Lonestar Resources US Inc., a Delaware Corporation, is an independent exploration and production company with 79.2 MMBOE of estimated proved oil and natural gas reserves as of December 31, 2020, of which 74% is oil and NGLs. Our operations are focused on the exploration, development and production of unconventional oil, natural gas liquids and natural gas in the Eagle Ford Shale (the "Eagle Ford") play in South Texas.
As the context may require, the “Company”,“ Lonestar”, “we”, “our” or similar words refer to (i) Lonestar Resources US Inc. (“the Successor”) after November 30, 2020. References to historical activities of the “Company” prior to November 30, 2020, refer to activities of Lonestar Resources US Inc. (“the Predecessor”).
As discussed further below, on September 30, 2020 (the “Petition Date”), Lonestar Resources US Inc. and 21 of its directly and indirectly owned subsidiaries (collectively, the “Debtors”), filed voluntary petitions (“Bankruptcy Petitions”) for relief under Chapter 11 (“Chapter 11”) of the U.S. Bankruptcy Code (“Bankruptcy Code”) in the U.S. Bankruptcy Court for the Southern District of Texas (“Bankruptcy Court”). The Debtors’ Chapter 11 cases were administered jointly under the caption In re Lonestar Resources US Inc., et al., Case No. 20-34805 (collectively, the “Chapter 11 Proceedings”). During the pendency of the Chapter 11 Proceedings, the debtors in the Chapter 11 Proceedings (the “Debtors”), operated their businesses as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code. The Company emerged from bankruptcy and went effective with its plan of reorganization on November 30, 2020 (the “Effective Date”).
Prior to the Effective Date, the Predecessor company's common shares had been publicly traded on the NASDAQ since 2016. In January 2021, the Successor company's common shares began trading on the OTCQX Best Market. Our corporate headquarters is located at 111 Boland Street, Suite 301, Fort Worth, Texas, 76107 and our phone number is 817-921-1889. At December 31, 2020 (Successor), we had 75 employees, 29 of whom were employed in field operations or at our field offices. We make our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports, filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, available free of charge on or through our website, www.lonestarresources.com, as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. The SEC also maintains a website, http://www.sec.gov, which contains periodic reports on Forms 8-K, 10-Q and 10-K filed with the SEC, along with other reports, proxy and information statements and other information filed by Lonestar.
Emergence from Voluntary Reorganization Under Chapter 11 of the Bankruptcy Code
As noted above, on September 30, 2020, Lonestar Resources US Inc. and 21 of its directly and indirectly owned subsidiaries filed petitions for reorganization in a “prepackaged” voluntary bankruptcy under chapter 11 of the Bankruptcy Code. On November 12, 2020, the Bankruptcy Court entered an order (the “Confirmation Order”) confirming the chapter 11 plan of reorganization (the “Plan”) and approving the Disclosure Statement, and on November 30, 2020, the Plan became effective in accordance with its terms and the Company emerged from the Chapter 11 bankruptcy proceedings. In January 2021, the Successor's new common stock commenced trading on the OTCQX Best Market board under the ticker symbol "LONE". Key accomplishments of the Chapter 11 Restructuring include the following:
▪Eliminated approximately $390 million in aggregate debt obligations and preferred equity interests;
▪Reduced ongoing annual interest expense by over $28 million;
▪Significantly improved leverage ratios; and
▪Established a new $225 million senior secured credit facility and $60 million second-out term loan.
▪Adopted an amended and restated its certificate of incorporation and bylaws, which reserved for issuance 90,000,000 shares of common stock, par value $0.001 per share, (the “New Common Stock”) and 10,000,000 shares of preferred stock, par value $0.001 per share;
▪Appointed a new board of directors to replace the Predecessor's directors, consisting of four new independent members: Richard Burnett, Gary D. Packer, Andrei Verona and Eric Long, and one continuing member: Frank D. Bracken, III, Lonestar's Chief Executive Officer;
▪Provided for the following settlement of claims and interests in the Predecessor as follows:
•Holders of Prepetition RBL Claims received distributions of:
▪Cash in the amount of all accrued and unpaid interest;
▪A first-out senior secured revolving credit facility with total aggregate commitments of $225 million;
▪A second-out senior secured term loan credit facility in an amount equal to $60 million;
▪555,555 Tranche 1 warrants and 555,555 Tranche 2 warrants, reflecting up to a 10% ownership stake in the Successor company's equity interests;
▪Holders of Prepetition Notes Claims (as defined below) received distributions of a pro rata share of 96% of 10,000,149 shares of New Common Stock issued on the Effective Date, subject to dilution by a to-be-adopted management incentive plan (the "MIP") and the new warrants);
▪Holders of Predecessor preferred equity interests received distributions of a pro rata share of 3% of the New Common Stock in the Successor company (subject to dilution by the MIP and the new warrants); and
▪Holders of Predecessor Class A common stock received distributions of a pro rata share of 1% of the New Common Stock in the Successor company (subject to dilution by the MIP and new warrants).
▪General unsecured creditors were paid in full in cash.
For more information on the Chapter 11 Restructuring and related matters, refer to Note 2, Emergence from Voluntary Reorganization Under Chapter 11, and Note 10, Long-Term Debt, to the consolidated financial statements.
Fresh Start Accounting
Upon emergence from bankruptcy, we met the criteria and were required to adopt fresh start accounting in accordance with Accounting Standards Board Codification (“ASC”) Topic 852, Reorganizations, which on the Effective Date resulted in a new entity, the Successor, for financial reporting purposes, with no beginning retained earnings or deficit as of the fresh start reporting date. References to “Successor” re late to the financial position and results of operations of the Company subsequent to the Company’s emergence from bankruptcy on November 30, 2020, and references to “Predecessor” relate to the financial position and results of operations of the Company prior to, and including, November 30, 2020. In order to assist investors in understanding the comparability of our financial results for the applicable periods, we have provided certain comparative analysis on a combined basis, which management believes provides meaningful information to assist investors in understanding our financial results for the applicable period, but should not be considered in isolation, as a substitute for, or more meaningful than, independent results of the Predecessor and Successor periods for the year reported in accordance with GAAP.
Fresh start accounting requires that new fair values be established for the Company’s assets, liabilities and equity as of the date of emergence from bankruptcy, November 30, 2020, and therefore certain values and operational results of the consolidated financial statements subsequent to November 30, 2020 are not comparable to the Company’s consolidated financial statements prior to, and including November 30, 2020, principally due to the Effective Date re-evaluation of the fair value of our oil and natural gas properties, together with the conversion of $250 million of previously outstanding bond debt into new common stock in the Successor. The reorganization value derived from the range of enterprise values associated with the Plan was allocated to the Company’s identifiable tangible and intangible assets and liabilities based on their fair values. The Effective Date fair values of the Successor’s assets and liabilities differ materially from their recorded values as reflected on the historical balance sheet of the Predecessor and may materially affect our results of operations in Successor reporting periods.
For more information on fresh start accounting, refer to Note 3, Fresh Start Accounting to the consolidated financial statements.
Impact of the COVID-19 Pandemic
In March 2020, the World Health Organization declared the ongoing COVID-19 coronavirus (“COVID-19”) outbreak a pandemic, and the President of the United States declared the COVID-19 pandemic a national emergency. The COVID-19 pandemic has caused a rapid and precipitous drop in oil demand, which worsened an already deteriorated oil market that followed the early-March 2020 failure by the group of oil producing nations known as OPEC+ to reach an agreement over proposed oil production cuts. Uncertainty about the duration of the COVID-19 pandemic and its resulting economic consequences has resulted in abnormally high worldwide inventories of produced oil. While oil prices as of late-March 2021 have improved to the low-$60s per barrel, which is significantly higher than the low points experienced during the second quarter of 2020, the concerns and uncertainties around the balance of supply and demand for oil are expected to continue for some time. Because the realized oil prices we received during 2020 were significantly reduced, our operating cash flow and liquidity were adversely affected.
Overview
We have accumulated approximately 72,529 gross (52,861 net) acres as of December 31, 2020 (Successor). We operate in one industry segment, which is the exploration, development and production of oil, natural gas liquids ("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, 2020, 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: the 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, 2020 (Successor), we operated 97% of our Eagle Ford position and approximately 94% of our net acreage was held by production, or HBP. Third-party engineers have identified 240 gross (135 net) horizontal drilling locations on our Eagle Ford acreage.
We currently plan to invest the majority of our 2021 capital budget in the horizontal development of our Eagle Ford properties and have allocated between $45 million and $55 million to acquisition, 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 10,000 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, 2020 (Successor):
Gross
Acreage Net
Acreage Average
Working
Interest Identified
Drilling
Locations
(1)(2) Producing
Wells Average
Daily
Production
BOE/d Capex
2021 Planned Wells
(Gross) (3)
Gross Net Gross Net
Eagle Ford
Western 16,761 14,770 88% 35 25 65 61 7,348 62% 4
Central 45,998 31,591 69% 168 91 186 138 6,007 38% 6
Eastern 9,770 6,500 67% 37 18 14 9 232 -% -
Total 72,529 52,861 73% 240 134 265 208 13,587 100% 10
(1)Potential drilling locations are identified based on analysis of relevant geologic and engineering data. Our total identified drilling locations include 240 gross (134 net) locations that were associated with proved undeveloped reserves, or PUDs, as of December 31, 2020 (Successor). The remaining drilling locations were not associated with proved reserves as of December 31, 2020 (Successor), 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 (Gross) 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, 2020 (Successor):
Oil Producing Wells Gas Producing Wells Total Producing Wells
Gross Net Gross Net Gross Net
Eagle Ford
Western 51 49 14 13 65 61
Central 166 118 20 19 186 138
Eastern 14 9 - - 14 9
Total 231 176 34 32 265 208
Our Properties
Our Eagle Ford net production for the year ended December 31, 2020 was 13,587 BOE/d, comprised of 6,713 Bbls/d of oil, 3,142 Bbls/d of NGLs and 22,393 Mcf/d of natural gas, from 265 gross (208 net) producing wells. For the eleven months ended November 30, 2020 (Predecessor), net production was 13,744 BOE/d, comprised of 6,772 Bbls/d of oil, 3,169 Bbls/d of NGLs and 22,816 Mcf/d of natural gas. For the one month ended December 31, 2020 (Successor), net production was 11,896 BOE/d, comprised of 6,075 Bbls/d of oil, 2,851 Bbls/d of NGLs, and 17,817 Mcf/d of natural gas.
In March 2019 (Predecessor), we sold our Pirate assets in Wilson County for $12.3 million, before closing adjustments, to a private third-party. The assets were comprised of 3,400 net undeveloped acres, six producing wells, held seven proved undeveloped locations as of the closing date and were producing approximately 200 BOE/d.
As of December 31, 2020 (Successor), according to our reserve report, our Eagle Ford properties had proved reserves of 79.2 MMBOE, of which 74% was crude oil and NGLs and 37% was proved developed producing, or PDP. The Standardized Measure of our proved reserves as of December 31, 2020 was $330.3 million, and the PV-10(1) of our proved reserves as of December 31, 2020 (Successor) was $366.0 million using SEC pricing, and 61% of such PV-10 was PDP. See Oil and Natural Gas Data below for more information.
Third-party engineers have identified 240 gross (134 net) horizontal drilling locations on our acreage, of which 66% are expected to be drilled using lateral lengths of or greater than 7,000 feet and 31% are expected to be drilled using lateral lengths of or greater than 10,000 feet.
Western Eagle Ford. As of December 31, 2020 (Successor), our Western Eagle Ford region was comprised of 16,761 gross (14,770 net) acres in Dimmit, La Salle and Frio Counties. As of December 31, 2020 (Successor), we operated 100% of this acreage, and approximately 89% of this net acreage was HBP. We plan on allocating 62% of our 2021 capital budget to our Western Eagle Ford acreage.
Central Eagle Ford. Our Central Eagle Ford region, as of December 31, 2020 (Successor), was comprised of 45,998 gross (31,591 net) acres in Gonzales, Karnes, Fayette and Wilson Counties. As of December 31, 2020 (Successor), we operated 90% of this acreage, and approximately 95% of this net acreage was HBP. We plan on allocating 38% of our 2021 capital budget to this area.
Eastern Eagle Ford. Our Eastern Eagle Ford region, as of December 31, 2020 (Successor), was comprised of 9,770 gross (6,500 net) acres in Brazos and Robertson Counties. 100% of this net acreage was HBP, and as of December 31, 2020 (Successor), we operated 97% of this acreage. We do not plan on allocating any of our 2021 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.
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 Eagle Ford Shale in South Texas. Key elements of our business strategy include:
•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, 2020 (Successor), we were producing from 265 gross (208 net) Eagle Ford wells and we intend to deploy all our capital budget for 2021 on the development of our Eagle Ford acreage.
•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 Shale 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.
•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.
•Maintain operational control over our drilling and completion operations. We operate 97% 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.
•Maintain and enhance financial liquidity and flexibility. We intend to execute a capital program which is funded from cash flow from operations while generating meaningful free cash flow which will be primarily dedicated to the repayment of debt. Furthermore, we intend to continue to employ a hedging strategy on our PDP production to achieve more predictable 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.
•Geographic focus in one of North America’s leading unconventional oil plays. We have assembled a leasehold position of 52,861 net acres in the Eagle Ford as of December 31, 2020 (Successor). Our production has access to expansive pipeline transportation infrastructure which allows us to sell our crude oil, NGL’s and natural gas into markets garnering superior pricing. Furthermore, we benefit from readily available energy services. These advantages, combined with a prolific hydrocarbon resource, generates 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 all of our 2021 drilling capital budget.
•Experienced management team. Our top eight executives average over 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.
•Demonstrated ability to increase acreage position and drive growth of oil production and reserves. We have increased our Eagle Ford net acreage by over fourteen times, from 3,710 net acres in 2011 (Predecessor) to 52,861 net acres as of December 31, 2020 (Successor). We placed 10 gross (8.4 net) and 17 gross (15.7 net) Eagle Ford wells onstream during 2020 and 2019, respectively. We had a total of 265 gross (208 net) producing wells in the Eagle Ford, as of December 31, 2020 (Successor). Our average total production for 2020 was 13,587 BOE/d, all of which was from the Eagle Ford. 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.
•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”). 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.
•Multi-year drilling inventory in existing and emerging resource plays. Third-party engineers have identified 240 gross (134 net) horizontal drilling locations on our Eagle Ford acreage. As of December 31, 2020 (Successor), these identified drilling locations included 117 gross (109 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.
•Low lease operating expenses. Our vigilant attention to costs combined with the geographic concentration of our assets allows us to operate our Eagle Ford acreage at low cash operating costs. For the year eleven months ended November 30, 2020 (Predecessor) and month ended December 31, 2020 (Successor), our total field operating expenses (including lease operating' gas gathering, processing and transportation; production taxes and ad valorem taxes) totaled $6.90 and $7.19 per BOE, respectively, in our project areas.
•Hedging position. As of March 29, 2021 (Successor), we had oil derivative contracts in place for 2021 covering approximately 5,255 Bbls/d at an average price of $45.17 per Bbl. In addition, we currently have oil derivative contracts in place for 2022 consisting of 3,062 Bbls/d at an average price of $47.03 per Bbl. As of March 29, 2021 (Successor), we also had derivative contracts to hedge our 2021 natural gas production covering 13,251 MMBtu/d at a weighted average price of $3.02 per MMBtu. In addition, we currently have natural gas derivative contracts in place for 2022 consisting of 6,233 MMBtu/d at a weighted average price of $2.77 per MMBtu. We believe that these hedges help mitigate our exposure to oil and natural gas price volatility.
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, 2020 (Successor) and 2019 (Predecessor). 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.
Successor Predecessor
December 31, 2020 December 31, 2019
Estimated Proved Reserves(1)
Oil (MBbls) 39,054 49,808
NGLs (MBbls) 19,495 24,862
Natural Gas (MMcf) 124,050 155,871
Total Estimated Proved Reserves (MBOE)(2)
79,224 100,648
Estimated Proved Developed Reserves
Oil (MBbls) 14,489 15,945
NGLs (MBbls) 7,350 8,300
Natural Gas (MMcf) 47,087 52,605
Total Estimated Proved Developed Reserves (MBOE)(2)
29,686 33,012
Estimated Proved Undeveloped Reserves
Oil (MBbls) 24,565 33,863
NGLs (MBbls) 12,145 16,562
Natural Gas (MMcf) 76,963 103,266
Total Estimated Proved Undeveloped Reserves (MBOE)(2)
49,538 67,636
Standardized Measure (millions)(3)
$ 330.3 $ 738.8
PV-10 (millions)(4)
$ 366.0 $ 834.2
Oil and Gas Prices Used(1) :
Oil - NYMEX-WTI per Bbl $ 39.57 $ 55.69
Natural Gas - NYMEX-Henry Hub per MMBtu 1.99 2.58
(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, before they 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 was approximately 27% 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 (or constantly flat using the base commodity prices given for the flat pricing case). 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:
Successor Predecessor
In millions December 31, 2020 December 31, 2019
Standardized measure of discounted future net cash flows (GAAP measure) $ 330.3 $ 738.8
Discounted estimated future income taxes 35.7 95.4
PV-10 (Non-GAAP measure) $ 366.0 $ 834.2
Reconciliation of Proved Reserves
Our proved developed oil and natural gas reserves decreased from 33.0 MMBOE at December 31, 2019 (Predecessor), to 29.7 MMBOE at December 31, 2020 (Successor), primarily due production and revisions to prior estimates partially offset by the conversion of proved undeveloped to proved developed through our drilling program, which brought 10 gross wells online during 2020 and added 3.9 MMBOE of proved reserves. Our proved developed oil and natural gas reserves experienced negative revisions of 2.1 MMBOE primarily due to reductions caused by lower SEC pricing.
Proved Developed Reserves
(MBOE)
As of December 31, 2019 (Predecessor) 33,012
Extensions and discoveries -
Conversion of proved undeveloped to proved developed 3,872
Sales of minerals in place (134)
Revisions of prior estimates (2,091)
Production (4,973)
As of December 31, 2020 (Successor) 29,686
Development of Proved Undeveloped Reserves
At December 31, 2020 (Successor), our proved undeveloped reserves were approximately 49.5 MMBOE, an decrease of approximately 18.1 MMBOE from our December 31, 2019 (Predecessor) estimated proved undeveloped reserves of approximately 67.6 MMBOE. In 2020, we added proved undeveloped reserves of 6.0 MMBOE as a result of drilling and completion activities, approximately 3.9 MMBOE of proved undeveloped reserves were converted to proved developed reserves as a result of drilling and completion activities during the year and 19.2 MMBOE of reserves were removed from our proved undeveloped reserves as a result of revisions in estimates from 2019. Revisions of previous estimates were primarily cause by the reclassification of wells due to the decrease in SEC pricing.
All PUD drilling locations are scheduled to be drilled prior to the end of 2025. 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.
Proved Undeveloped Reserves
(MBOE)
As of December 31, 2019 (Predecessor) 67,636
Extensions and Discoveries 6,016
Conversion of proved undeveloped to proved developed (3,872)
Sales of minerals in place (1,076)
Revisions to prior estimates (19,166)
As of December 31, 2020 (Successor) 49,538
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 analysis, geologic maps and available down-hole 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, 2020 (Successor) and 2019 (Predecessor) 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, Chief Operating Officer, 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:
Successor Predecessor
Month ended December 31, 2020 Eleven Months ended November 30, 2020 Year ended December 31, 2019
Production
Oil (Bbls/day):
Western 2,678 2,559 2,840
Central 3,302 4,073 4,362
Eastern 94 140 173
Total Eagle Ford 6,075 6,772 7,375
NGLs (Bbls/day)
Western 2,107 2,145 2,349
Central 718 969 1,330
Eastern 26 55 70
Total Eagle Ford 2,851 3,169 3,749
Natural Gas (Mcf/day)
Western 13,088 16,077 15,465
Central 4,612 6,468 8,577
Eastern 117 271 333
Total Eagle Ford 17,817 22,816 24,375
Average daily production (BOE/d) 11,896 13,744 15,187
Average realized prices
Oil ($/Bbl) $ 43.08 $ 35.37 $ 58.64
NGLs ($/Bbl) 12.25 9.40 11.45
Natural Gas ($/Mcf) 3.09 1.98 2.43
Operating expenses per BOE
Lease operating $ 3.85 $ 4.44 $ 5.76
Gas gathering, processing and transportation 1.25 1.34 0.84
Production and ad valorem taxes 1.81 1.41 2.01
Depreciation, depletion and amortization 5.68 15.23 15.99
Drilling Activity
The following table sets forth our operated and non-operated drilling activity for the years ended December 31, 2020 and 2019. As of December 31, 2020, we had three wells that were drilled but uncompleted:
Year ended December 31,
2020 2019
Gross Net Gross Net
Development Wells:
Productive 7.0 5.4 14.0 13.2
Dry - - - -
Exploratory Wells:
Productive 3.0 3.0 3.0 2.5
Dry - - - -
Total Wells:
Productive 10.0 8.4 17.0 15.7
Dry - - - -
Oil and Gas Acreage
The following table sets forth our acreage position in the Eagle Ford at December 31, 2020 (Successor):
Developed Undeveloped Total
Gross Net Gross Net Gross Net
Western region 7,244 6,726 9,516 8,044 16,760 14,770
Central region 16,474 11,913 29,525 19,678 45,999 31,591
Eastern region 2,185 1,429 7,585 5,071 9,770 6,500
Total 25,903 20,068 46,626 32,793 72,529 52,861
The percentage of our net undeveloped acreage that is subject to expiration over the next three years, if not renewed, is approximately 2% (528 acres) in 2021, 4% (1,216 acres) in 2022 and 5% (1,559 acres) in 2023.
General
We operate 97% 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
Oil and natural gas sales are made on a day-to-day basis or under short-term contracts at the current area market price. We would not expect the loss of any single purchaser to have a material adverse effect upon our operations; however, the loss of a large single purchaser could potentially reduce the competition for our oil and natural gas production, which in turn could negatively impact the prices we receive. For the month ended December 31, 2020 (Successor), three purchasers accounted for 10% or more of our oil and natural gas revenues: Ace Gathering Inc. (31%), Texla Energy Management Inc. (24%) and Enterprise Crude Oil, LLC (24%), and for the eleven months ended November 30, 2020 (Predecessor), five purchasers accounted for 10% or more of our oil and natural gas revenues: Enterprise Crude Oil, LLC (23%), Texla Energy Management Inc. (22%), Ace Gathering Inc. (21%), NGL Crude Logistics, LLC (14%) and Shell Trading Company (US) Company (10%). For the year ended December 31, 2019 (Predecessor), six purchasers accounted for 10% or more of our oil and natural gas revenues: Shell Trading (US) Company (23%), Texla Energy Management (17%), Enterprise Crude Oil LLC (16%), Ace Gathering, Inc. (14%), GulfMark Energy, Inc. (13%) and NGL Crude Logistics LLC (10%).
Our ability to market oil and natural gas depends on many factors beyond our control, including the extent of domestic production and imports of oil and natural gas, available oil storage at Cushing, Oklahoma, and other inventory hubs, the proximity of our oil and natural gas production to pipelines and corresponding markets, the available capacity in such pipelines, the demand for oil and natural gas, the effects of weather, and the effects of state and federal regulation. There is no assurance that we will always be able to market all of our production or obtain favorable prices.
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, Chesapeake Energy Corporation, EP Energy Corporation, EOG Resources, Inc., Magnolia Oil & Gas Corporation, Marathon Oil Corporation, SilverBow Resources, Inc. Penn Virginia Corporation and Sundance Energy, Inc. 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 20.0% to 25.0% resulting in a net revenue interest to us ranging from 75.0% to 80.0%.
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 ratability 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. The 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 the 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 is PPI plus 1.23%. In December 2020, FERC issued an order establishing an index level of PPI plus 0.78% for the five-year period commencing July 1, 2021.
FERC has also established cost-of-service rates, 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 determination 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, 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 into the environment 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.
Uncertainty about the future course of regulation exists because of the recent change in U.S. presidential administrations. In January 2021, the current administration issued an executive order directing all federal agencies to review and take action to address any federal regulations, orders, guidance documents, policies and any similar agency actions promulgated during the prior administration that may be inconsistent with the current administration’s policies. As a result, it is unclear the degree to which certain recent regulatory developments may be modified or rescinded. The executive order also established an Interagency Working Group on the Social Cost of Greenhouse Gases (“Working Group”), which is called on to, among other things, develop methodologies for calculating the “social cost of carbon,” “social cost of nitrous oxide” and “social cost of methane.” Final recommendations from the Working Group are due no later than January 2022. Further regulation of air emissions, as well as uncertainty regarding the future course of regulation, could eventually reduce the demand for oil and natural gas. Also in January 2021, the current administration issued an executive order focused on addressing climate change (the 2021 Climate Change Executive Order). Among other things, the 2021 Climate Change Executive Order directed the Secretary of the Interior to pause new oil and natural gas leasing on public lands or in offshore waters pending completion of a comprehensive review of the federal permitting and leasing practices, consider whether to adjust royalties associated with coal, oil, and gas resources extracted from public lands and offshore waters, or take other appropriate action, to account for corresponding climate costs. The 2021 Climate Change Executive Order also directs the federal government to identify “fossil fuel subsidies” to take steps to ensure that, to the extent consistent with applicable law, federal funding is not directly subsidizing fossil fuels. Legal challenges to the suspension have already been filed and are currently pending.
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.
Potentially responsible parties 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 “potentially responsible parties” 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 was 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. After undertaking its review, the EPA signed a determination in 2019 concluding that it does not need to regulate oil and gas exploration and production wastes, and specifically “drilling fluids, produced waters, and other wastes associated with the exploration, development or production of oil, gas or geothermal energy,” because the states are adequately regulating such wastes under the Subtitle D provisions of the RCRA. However, a loss of the RCRA exclusion for drilling fluids, produced waters and related wastes in the future 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” (the “WOTUS Rule”). In November 2017, the EPA and the Army Corps of Engineers issued a notice to rescind the WOTUS Rule and re-codify the regulatory text that existed prior to 2015 defining “water of the United States.” The EPA and the Army Corps of Engineers formally repealed the rule in September 2019. In January 2020, the Trump administration published a final replacement rule, called the Navigable Waters Protection Rule, that purports to expressly define which categories or water may be federally regulated under the CWA. A federal district court issued a preliminary injunction preventing the Navigable Waters Protection Rule from taking effect in Colorado, but the rule is otherwise effective in every other state. The rule is currently under review by the administration, and additional litigation and administrative proceedings are expected in the future. In addition, in April 2020, the U.S. Supreme Court issued a decision finding that point source discharges to navigable waters through groundwater are subject to regulation under the Clean Water Act. The U.S. Supreme Court specifically held that the Clean Water Act requires a permit if the addition of the pollutants through groundwater is the “functional equivalent” of a direct discharge from the point source into navigable waters. As such, uncertainty remains with respect to the scope of the federal government’s jurisdiction under the CWA. 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 at Subpart OOOOa 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. In September 2018, the EPA proposed further amendments that would reduce the 2016 Subpart OOOOa standards’ fugitive emissions monitoring requirements and expand exceptions to controlling methane emissions from pneumatic pumps, among other changes. Various industry and environmental groups have separately challenged both the original 2016 Subpart OOOOa standards and the EPA’s attempts to delay the implementation of 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. In September 2020, the EPA finalized amendments to the NSPS that removed the transmission and storage segments from the oil and natural gas source category and rescinded the methane-specific requirements for production and processing facilities. However, as discussed above, the current administration issued an executive order in January 2021 that called on the EPA to, among other things, consider a proposed rule suspending, revising or rescinding the deregulatory amendments by September 2021. As a result, we cannot predict the scope of any final methane regulatory requirements or the costs of complying with such requirements. 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. In April 2018 and July 2018, the EPA issued area designations for all areas not addressed in the previous rule. States with moderate or high nonattainment areas must submit state implementation plans to EPA by October 2021. 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. 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. President Trump formally initiated the withdrawal process in November 2019, which resulted in an effective exit date of November 2020. However, the Biden administration issued the aforementioned 2021 Climate Change Executive Order that, among other things, commenced the process for the U.S. reentering the Paris Agreement. The U.S. officially rejoined the Paris Agreement on February 19, 2021.
The 2021 Climate Change Executive Order also directed the Secretary of the Interior to pause new oil and natural gas leasing on public lands or in offshore waters pending completion of a comprehensive review of the federal permitting and leasing practices, consider whether to adjust royalties associated with coal, oil, and gas resources extracted from public lands and offshore waters, or take other appropriate action, to account for corresponding climate costs. The 2021 Climate Change Executive Order also directs the federal government to identify “fossil fuel subsidies” to take steps to ensure that, to the extent consistent with applicable law, federal funding is not directly subsidizing fossil fuels. Legal challenges to the suspension have already been filed and are currently pending. The administration’s other January 2021 executive order established a Working Group to, among other things, develop methodologies for calculating the “social cost of carbon,” “social cost of nitrous oxide” and “social cost of methane.” Final recommendations from the Working Group are due no later than January 2022.
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. In addition, 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 EPAct 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”) developed comprehensive regulations for hydraulic fracturing on federal land in 2015 that were subject to extensive litigation challenges. 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. The U.S. Fish and Wildlife Service did not meet that deadline, but continues to consider the listing of additional species under the ESA. 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 2020, nor do we anticipate that such expenditures will be material in 2021.
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, 2020 (Successor), we had 75 employees, including 14 engineers and geoscientists, 11 land professionals and 29 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, as a company and as individuals, believe in “doing the right thing” and being passionate about our work with the goal that we all succeed together (including our employees, contractors, shareholders and the communities in which we operate). We also believe that great people and great assets create great opportunity, and these core values inform how we think about our business.
Compensation and benefits
We seek to provide fair, competitive compensation and comprehensive benefits to our employees. To ensure alignment with our short- and long-term objectives, our compensation programs consist of base pay, short-term incentives and long-term incentives, including stock grants. Our wide array of benefits include retirement plan dollar matching, health insurance for employees and their families, income protection and disability coverage, paid time off, wellness resources including exercise facilities, and financial wellness tools and resources.We invest in leadership training and professional development programs that will enable our employees to reach their potential and perform at their best.
Diversity and inclusion
We recognize that a diverse workforce provides the best opportunity to obtain unique perspectives, experiences and ideas to help our business succeed, and we are committed to providing a diverse and inclusive workplace to attract and retain talented employees. We maintain a work culture that treats all employees fairly and with respect, promotes inclusivity, and provides equal opportunities for the professional growth and advancement based on merit. Our Code of Business Conduct and Ethics prohibits discrimination or harassment against any employee or applicant on the basis of race, color, gender, religion,
age, national origin, citizenship status, military service or veteran status, sexual orientation or disability. In addition, we seek business partners who do not engage in prohibited discrimination in hiring or in their employment practices and who make decisions about hiring, salary, benefits, training opportunities, work assignments, advancement, discipline, termination, retirement and other employment decisions based on job and business-related criteria. We evaluate ways to enhance awareness of and promote diversity and inclusion on an ongoing basis.

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ITEM 1A. RISK FACTORS
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:
•worldwide and regional economic and political conditions;
•the domestic and global supply of, and demand for, oil, natural gas and NGLs;
•the cost of exploring for, developing, producing and marketing oil, natural gas and NGLs;
•the proximity, capacity, cost and availability of oil, natural gas and NGL pipelines and other transportation facilities;
•the price and quantity of imports of foreign oil, natural gas and NGLs;
•the level of global oil, natural gas and NGL exploration and production;
•the level of global oil, natural gas and NGL inventories;
•weather conditions and natural disasters;
•domestic and foreign governmental laws, regulations and taxes;
•volatile trading patterns in commodities futures markets;
•price and availability of competitors’ supplies of oil, natural gas and NGLs;
•the actions of OPEC and the ability of OPEC and other producing nations to agree to and maintain production levels;
•technological advances affecting energy consumption;
•the price and availability of alternative fuels;
•global or national health concerns, including health epidemics such as the coronavirus outbreak beginning in early 2020; and
•market perceptions of future prices, whether due to the foregoing factors and others.
Further, oil, natural gas and NGL prices do not necessarily fluctuate in direct relationship to each other. Because approximately 49% of our estimated proved reserves as of December 31, 2020 were attributed to oil, our financial results are more sensitive to movements in oil prices.
As of December 31, 2020 (Successor), we had in place hedges covering approximately 4,146 Bbls/d for 2021 at an average price of approximately $43.05 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.
From 2016 through 2020, the WTI spot price for oil averaged $51.21 per Bbl, which is down substantially from the $85.75 average for the prior five-year period. The Henry Hub average spot price from 2016 through 2020 of $2.65 per MMBtu similarly declined from $3.49 per MMBtu, which was the average for the prior five-year period. The commodity prices displayed even more dramatic volatility in 2020, during which the WTI spot price for oil briefly fell to a low of negative $38.98 per barrel on April 20, 2020 and the Henry Hub spot price reached a low of $1.33 on September 21, 2020. During these periods, NGLs, which are made up of ethane, propane, isobutene, normal butane and natural gasoline, all of which have different uses and different pricing characteristics, have suffered significant recent price declines. Such a decline in oil price, if sustained, will have a material impact on our annual revenues and has caused, and may in the future cause, us to take actions to reduce the costs of drilling and our operations. The coronavirus outbreak has weakened demand for oil, natural gas and NGLs, and these events have worsened an already deteriorated oil market that resulted from the early-March 2020 failure by the group of oil producing nations known as OPEC+ to reach an agreement over proposed oil production cuts.
Further declines or a prolonged depression in oil, natural gas or NGL prices may act to reduce our cash flows further and adversely affect our financial condition. In such case, 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:
•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
•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.
Further declines or a prolonged depression in oil, natural gas or NGL prices may also 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 reserve volumes, the carrying value of our oil, natural gas and NGL properties, the PV-10 valuations of our oil, natural gas and NGL reserves, and the Standardized Measure relating to oil, natural gas and NGL reserves. In addition, future declines or a prolonged depression may lead to a reduction in our borrowing base or a redetermination that results in a deficiency.
The current outbreak of COVID-19 has adversely impacted our business, financial condition, liquidity and results of operations and is likely to have a continuing adverse impact for a significant period of time.
The COVID-19 pandemic has caused a rapid and precipitous drop in demand for oil, which in turn has caused oil prices to plummet since the first week of March 2020, negatively affecting the Company’s cash flow, liquidity and financial position. Moreover, the uncertainty about the duration of the COVID-19 pandemic has caused storage constraints in the United States resulting from over-supply of produced oil. Oil prices are expected to continue to be volatile as a result of these events and the ongoing COVID-19 outbreak, and as changes in oil inventories, oil demand and economic performance are reported. We cannot predict when oil prices will improve and stabilize.
The current pandemic and uncertainty about its length and depth in future periods has caused the realized oil prices we have received since February 2020 to be significantly reduced, adversely affecting our operating cash flow and liquidity. Although we have reduced our 2020 capital expenditures budget, our lower levels of cash flow may require us to shut-in production that has become uneconomic.
The COVID-19 pandemic is rapidly evolving, and the ultimate impact of this pandemic is highly uncertain and subject to change. The extent of the impact of the COVID-19 pandemic on our operational and financial performance will depend on future developments, including the duration and spread of the pandemic, its severity, the actions to contain the disease or mitigate its impact, related restrictions on travel, the ability to distribute and the effectiveness of a vaccine, and the duration, timing and severity of the impact on domestic and global oil demand. The COVID-19 pandemic may also intensify the risks described in the other risk factors disclosed in this Item 1A. Risk Factors.
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:
•lack of prospective acreage available on acceptable terms;
•unexpected or adverse drilling conditions;
•elevated pressure or irregularities in geologic formations;
•equipment failures or accidents;
•adverse weather conditions;
•title problems;
•limited availability of financing upon acceptable terms;
•limitations in the market for oil, gas and NGLs;
•reductions in oil, NGLs and natural gas prices;
•compliance with governmental requirements, laws and regulations; and
•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 spend between $45 million and $55 million under our 2021 capital program to drill and complete approximately 10 gross wells across our properties in the Eagle Ford, which also includes funding for acquisitions.
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 prolonged period of lower commodity prices 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:
•our proved reserves;
•the amount of crude oil, natural gas and NGLs we are able to produce from existing wells;
•the prices at which our crude oil, natural gas and NGLs are sold;
•the costs at which our crude oil, natural gas and NGLs are extracted;
•global credit and securities markets;
•the ability and willingness of lenders and investors to provide capital and the cost of the capital; and
•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 we are unable to remedy any future event of default under the Credit Facility 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.
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:
•well blowouts;
•mechanical failures;
•fires and explosions;
•pipe or cement failures and casing collapses, which could release natural gas, oil, drilling fluids or hydraulic fracturing fluids;
•uncontrollable flows of oil, natural gas or well fluids;
•earthquakes and natural disasters;
•geologic formations with abnormal pressures;
•handling and disposal of materials, including drilling fluids and hydraulic fracturing fluids;
•pipeline ruptures or spills;
•releases of toxic gases; and
•other environmental hazards and risks.
Any of these hazards and risks can result in the loss of hydrocarbons, environmental pollution, personal injury or wrongful death 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, the results of which are subject to drilling and completion technique risks, and 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:
•landing our well bore in the desired formation;
•staying in the desired formation while drilling horizontally through the formation;
•running our casing the entire length of the well bore; and
•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:
•being able to fracture and stimulate the planned number of stages;
•being able to run tools the entire length of the well bore during completion operations; and
•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.
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:
•the ongoing review and analysis of geologic and engineering data;
•the availability of sufficient capital resources to us and the other participants to drill and complete the prospects;
•the approval of the prospects by other participants once additional data has been compiled;
•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;
•the ability to maintain, extend or renew leases and permits on reasonable terms for the prospects;
•additional due diligence;
•regulatory requirements and restrictions; and
•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 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:
•the ongoing review and analysis of geologic and engineering data;
•the availability of sufficient capital resources to us and the other participants to drill and complete the prospects;
•the approval of the prospects by other participants once additional data has been compiled;
•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;
•the ability to maintain, extend or renew leases and permits on reasonable terms for the prospects;
•additional due diligence;
•regulatory requirements and restrictions; and
•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. Our inability to borrow under the Credit Facility or other indebtedness,
whether because we are unable to remedy a future event of default under the Credit Facility or if our borrowing base is redetermined downward by the lenders, may also result in a downward revision of our estimated proved reserves and could result in additional impairment.
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, 2020, approximately 63% 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 49.5 MMBOE of estimated proved undeveloped reserves will require an estimated $449.8 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 inability to borrow under the Credit Facility or other indebtedness, whether because we are unable to remedy any future event of default under the Credit Facility or otherwise, may limit our ability to finance or develop our reserves as anticipated and may also require us to write off reserves which could result in additional impairments.
Our producing properties are located 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, 2020 (Successor) was derived from our properties in the Eagle Ford Shale play in 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 62% 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, 2020 (Successor), approximately 62% 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 528 net acres that is not currently held by production will expire at the end of 2021 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. 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.
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 month ended December 31, 2020 (Successor) and eleven months ended November 30, 2020 (Predecessor), purchases by our largest five customers accounted for 96% and 90%, 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 operating activities expose us to risk of financial loss if a customer fails to perform under a contract. Disruptions in the financial markets could lead to sudden decreases in a customer’s liquidity, which could make them unable to perform under the terms of the contract, and we may not be able to realize the benefit of the contract. We are unable to predict sudden changes in a customer’s creditworthiness or ability to perform. Even if we do accurately predict sudden changes, our ability to negate the risk may be limited depending upon market conditions and the contractual terms of the transactions. During periods of declining commodity prices, if any of our customers fail to pay their revenue accounts receivable when due, this could have a material adverse effect on our liquidity and results of operations.
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 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:
•the actual prices we receive for crude oil and natural gas;
•our actual operating costs in producing crude oil and natural gas;
•the amount and timing of actual production;
•supply and demand for crude oil and natural gas;
•increases or decreases in consumption of crude oil and natural gas; and
•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 $227.9 million for the eleven months ended November 30, 2020 (Predecessor), while we incurred a net profit from operations of $4.5 million for the month ended December 31, 2020 (Successor). 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 other risk factors disclosed in this Item 1A. Risk Factors 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 common stock.
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 or other indebtedness 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.
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.
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:
•our ability to obtain leases or options on properties;
•our ability to identify and acquire new exploratory prospects;
•our ability to develop existing prospects;
•our ability to continue to retain and attract skilled personnel;
•our ability to maintain or enter into new relationships with project partners and independent contractors;
•the results of our drilling programs;
•commodity prices; and
•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.
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.
Risks Related to Our Financing, Investments and Indebtedness
Any significant reduction in our borrowing base under the Credit Facility as a result of the periodic borrowing base redeterminations or any future violations of the covenants under the Credit Facility 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, with one interim “wildcard” redetermination available between scheduled redeterminations. 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 November 30, 2020, the borrowing base for the Credit Facility was $225.0 million. The first redetermination occurred on February 1, 2021, which reaffirmed the initial borrowing base of $225 million.
Borrowing availability was $15.0 million as of December 31, 2020 (Successor), which reflects $0.4 million of letters of credit outstanding.
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 outcome of a subsequent borrowing base redetermination, inability to access our available credit due to violations of covenants under the Credit Facility 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. Further or prolonged declines in commodity prices could result in a redetermination that lowers the borrowing base in the future and, in any such a redetermination, 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.
Uncertainty relating to the LIBOR calculation process and potential phasing out of LIBOR after 2021 may adversely affect the market value of our current or future debt obligations.
The London Inter-bank Offered Rate (“LIBOR”) and certain other interest “benchmarks” may be subject to regulatory guidance and/or reform that could cause interest rates under our current or future debt agreements to perform differently than in the past or cause other unanticipated consequences. The United Kingdom’s Financial Conduct Authority, which regulates LIBOR, has announced that it intends to stop encouraging or requiring banks to submit LIBOR rates after 2021, and it is unclear if LIBOR will cease to exist or if new methods of calculating LIBOR will evolve. If LIBOR ceases to exist or if the methods of calculating LIBOR change from their current form, interest rates on our debt obligations under our Credit Facility may be adversely affected.
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 and natural gas.
Our derivative activities expose us to risk of financial loss if a counterparty fails to perform under a contract. Disruptions in the financial markets could lead to sudden decreases in a counterparty’s liquidity, which could make them unable to perform under the terms of the contract, and we may not be able to realize the benefit of the contract. We are unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform. Even if we do accurately predict sudden changes, our ability to negate the risk may be limited depending upon market conditions and the contractual terms of the transactions. During periods of declining commodity prices, our derivative contract receivable positions generally increase, which increases our counterparty credit exposure. If any of our counterparties were to default on their obligations under a derivative contract, such a default could have a material adverse effect on our liquidity and results of operations, and could result in a larger percentage of our future production being subject to commodity price changes or increase the likelihood that our hedging strategy may not achieve its intended strategic purpose.
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.
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 contains 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:
•incur additional indebtedness and guarantee indebtedness;
•pay dividends or make other distributions or repurchase or redeem capital stock;
•prepay, redeem or repurchase certain debt;
•issue certain preferred stock or similar equity securities;
•make loans and investments;
•sell assets;
•incur liens;
•enter into transactions with affiliates;
•alter the businesses we conduct;
•enter into agreements restricting our subsidiaries’ ability to pay dividends; and
•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 under the Credit Facility could result in an event of default under the Credit Facility. Such a default may allow the lenders to accelerate the indebtedness thereunder 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 the 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 2021 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:
•a portion of our cash flow from operations would be used to pay interest on borrowings;
•the covenants contained in our Credit Facility 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;
•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;
•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
•debt that we incur under our Credit Facility 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, 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.
We may also, from time to time, repurchase or otherwise retire our debt. Such activities, if any, will depend on prevailing market conditions, contractual restrictions and other factors, and the amounts involved may or may not be material.
Risks Related to Regulatory Matters
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.
Under Section 404(a) of the Sarbanes-Oxley Act our management is required to 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.
In our Form 10-Q for the quarter ended September 30, 2020, we previously reported a material weakness relating to the operating effectiveness of controls over significant and unusual transactions - specifically relating to restructuring-related matters. This error was identified and corrected prior to the filing of our Form 10-Q but could have resulted in a material misstatement of the financial statements. During 2020, our management completed remediation measures related to this material weakness and concluded that our internal control over financial reporting was effective as of December 31, 2020. Completion of remediation does not provide assurance that our internal controls will continue to operate effectively.
If further material weaknesses are discovered, our financial statements could contain additional 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 cause our auditors to issue a qualified audit report. If we are unable to maintain effective internal control over financial reporting or disclosure controls and procedures, our ability to record, process and report financial information accurately, and to prepare financial statements within required time periods could be adversely affected, which could subject us to litigation or investigations requiring management resources and payment of legal and other expenses, negatively affect investor confidence in our financial statements and adversely impact our stock price.
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. For instance, in January 2021, the current administration issued an executive order directing all federal agencies to review and take action to address any federal regulations, orders, guidance documents, policies and any similar agency actions promulgated during the prior administration that may be inconsistent with the current administration’s policies. As a result, it is unclear the degree to which certain recent regulatory developments may be modified or rescinded 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:
•required disclosure of chemicals used during the hydraulic fracturing process;
•restrictions on wastewater disposal activities;
•required baseline and post-drilling sampling of water supplies in close proximity to hydraulic fracturing operations;
•new municipal or state land use regulations, such as changes in setback requirements, which may restrict drilling locations or related activities;
•financial assurance requirements, such as the posting of bonds, to secure site restoration obligations; and
•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 BLM rescinded the rule in December 2017.
There has been increasing public controversy regarding hydraulic fracturing with regard to the use of fracturing fluids, impacts on drinking water supplies, use of water and the potential for impacts on surface water, and groundwater, 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 approximately $1.3 million 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. In September 2020, the EPA finalized amendments to the 2016 regulations that removed the transmission and storage segments from the oil and natural gas source category and rescinded the methane-specific requirements for production and processing facilities. However, as discussed above, the current administration issued an executive order in January 2021 called on the EPA to, among other things, consider a proposed rule suspending, revising or rescinding the deregulatory amendments by September 2021. As a result, we cannot predict the scope of any final methane regulatory requirements or the costs of complying with such requirements. 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. 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. President Trump formally initiated the withdrawal process in November 2019, which resulted in an effective exit date of November 2020. However, the Biden administration issued executive orders recommitting the United States to the Paris Agreement that, among other things, commenced the process for the U.S. reentering the Paris Agreement. The U.S. officially rejoined the Paris Agreement on February 19, 2021.
The aforementioned 2021 Climate Change Executive Order directed the Secretary of the Interior to pause new oil and natural gas leasing on public lands or in offshore waters pending completion of a comprehensive review of the federal permitting and leasing practices, consider whether to adjust royalties associated with coal, oil, and gas resources extracted from public lands and offshore waters, or take other appropriate action, to account for corresponding climate costs. The 2021 Climate Change Executive Order also directs the federal government to identify “fossil fuel subsidies” to take steps to ensure that, to the extent consistent with applicable law, federal funding is not directly subsidizing fossil fuels. Legal challenges to the suspension have already been filed and are currently pending. The administration’s other January 2021 executive order established an Interagency Working Group on the Social Cost of Greenhouse Gases (“Working Group”) to, among other things, develop methodologies for calculating the “social cost of carbon,” “social cost of nitrous oxide” and “social cost of methane.” Final recommendations from the Working Group are due no later than January 2022. Given the long-term trend toward increasing regulation, future federal GHG regulations of the oil and gas industry remain a possibility.
Further regulation of air emissions, as well as uncertainty regarding the future course of regulation, could eventually reduce the demand for oil and natural gas. As previously mentioned, the current administration issued an executive order in January 2021 calling for substantial action on climate change, including, among other things, the increased use of zero-emissions vehicles by the federal government, the elimination of subsidies provided to the fossil fuel industry, and increased emphasis on climate-related risks across agencies and economic sectors. Other actions that could be pursued include more restrictive requirements for the development of pipeline infrastructure, as well as more restrictive GHG emissions limitations for oil and gas facilities.
Increased attention to ESG matters and conservation measures may adversely impact our business.
Increasing attention to climate change, societal expectations on companies to address climate change, investor and societal expectations regarding voluntary ESG disclosures, and consumer demand for alternative forms of energy may result in increased costs, reduced demand for our products, reduced profits, increased investigations and litigation, and negative impacts on our stock price and access to capital markets. Increasing attention to climate change and environmental conservation, for example, may result in demand shifts for oil and natural gas products and additional governmental investigations and private litigation against us. To the extent that societal pressures or political or other factors are involved, it is possible that such liability could be imposed without regard to our causation of or contribution to the asserted damage, or to other mitigating factors.
Moreover, while we create and publish voluntary disclosures regarding ESG matters from time to time, many of the statements in those voluntary disclosures are based on hypothetical expectations and assumptions that may or may not be representative of current or actual risks or events or forecasts of expected risks or events, including the costs associated therewith. Such expectations and assumptions are necessarily uncertain and may be prone to error or subject to misinterpretation given the long timelines involved and the lack of an established single approach to identifying, measuring and reporting on many ESG matters.
In addition, organizations that provide information to investors on corporate governance and related matters have developed ratings processes for evaluating companies on their approach to ESG matters. Such ratings are used by some investors to inform their investment and voting decisions. Unfavorable ESG ratings and recent activism directed at shifting funding away from companies with energy-related assets could lead to increased negative investor sentiment toward us and our industry and to the diversion of investment to other industries, which could have a negative impact on our stock price and our access to and costs of capital. Also, institutional lenders may decide not to provide funding for fossil fuel energy companies based on climate change related concerns, which could affect our access to capital for potential growth projects.
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. The Dodd-Frank Wall Street Reform and Consumer Protection Act (“Dodd-Frank Act”) provides for federal oversight of the over-the-counter (“OTC”) derivatives market and entities that participate in that market. The Dodd-Frank Act mandates that the US Commodity Futures Trading Commission (“CFTC”), the US Securities and Exchange Commission (“SEC”) and the prudential regulators adopt regulations implementing the derivatives-related provisions of the Dodd-Frank Act. While most of these regulations are already in effect, the implementation process is still ongoing and the CFTC continues to review and refine its initial rulemakings through additional interpretations and supplemental rulemakings. As a result, we cannot yet predict the ultimate effect of the regulations on our business and while most of the regulations have been adopted, any new regulations or modifications to existing regulations could significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. If we are limited in our use of derivatives in the future as a result of the Dodd-Frank Act 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.
The CFTC has re-proposed 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 would be exempt from these position limits, provided that various conditions are satisfied. The CFTC has also finalized a related aggregation rule that requires market participants to aggregate their positions with certain other persons under common ownership and control, unless an exemption applies, for purposes of determining whether the position limits have been exceeded. If adopted, the revised position limits rule and its finalized companion rule on aggregation may have an impact on our ability to hedge exposure to price fluctuation of certain commodities. In addition to the CFTC federal position limit regime, designated contract markets (“DCMs”) also have established position limit and accountability regimes. We may have to modify trading decisions or liquidate positions to avoid exceeding such limits or at the direction of the exchange to comply with accountability levels. Further, any such position limit regime, whether imposed at the federal-level or at the DCM-level may impose added operating costs to monitor compliance with such position limit levels, addressing accountability level concerns and maintaining appropriate exemptions, if applicable.
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 require that certain classes of swaps be cleared on a derivatives clearing organization and traded on a regulated exchange, unless exempt from such clearing and trading requirements, which could result in the application of certain margin requirements imposed by derivatives clearing organizations and their members. The CFTC and prudential regulators also recently adopted mandatory margin requirements for uncleared swaps entered into between swap dealers and certain other counterparties. We expect to qualify for and rely upon an end-user exception from the mandatory clearing and trade execution requirements for swaps entered into to hedge our commercial risks, in which case we would also qualify for an exemption from the uncleared swaps margin requirements. However, the application of the mandatory clearing and trade execution requirements and the uncleared swaps margin requirement to other market participants, such as swap dealers, may adversely affect the cost and availability of the swaps that we use for hedging.
In addition to the Dodd-Frank Act, the European Union and other foreign regulators have adopted and are implementing local reforms generally comparable with the reforms under the Dodd-Frank Act. Implementation and enforcement of these regulatory provisions may reduce our ability to hedge our market risks with non-US counterparties and may make transactions involving cross-border swaps more expensive and burdensome. Additionally, the lack of regulatory equivalency across jurisdictions may increase compliance costs and make it more difficult to satisfy our regulatory obligations.
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.
Potential future legislation or the imposition of new or increased taxes or fees may generally affect the taxation of natural gas and oil exploration and development companies and may adversely affect our operations and cash flows.
In past years, federal and state level legislation has been proposed that, if enacted into law, would make significant changes to tax laws, including to certain key U.S. federal and state income tax provisions currently available to natural gas and oil exploration and development companies. For example, President Biden has set forth several tax proposals that would, if enacted into law, make significant changes to U.S. tax laws. Such proposals include, but are not limited to, (i) an increase in the U.S. income tax rate applicable to corporations and (ii) the elimination of tax subsidies for fossil fuels. Congress could consider some or all of these proposals in connection with tax reform to be undertaken by the Biden administration. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could take effect. Additionally, states in which we operate or own assets may impose new or increased taxes or fees on natural gas and oil extraction. The passage of any legislation as a result of these proposals and other similar changes in U.S. federal income tax laws or the imposition of new or increased taxes or fees on natural gas and oil extraction could adversely affect our operations and cash flows.
Risks Related to Strategic Transactions
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.
We have elected not to be subject to the provisions of Section 203 of the Delaware General Corporation Law (the “DGCL”), regulating corporate takeovers.
In general, the provisions of Section 203 of the DGCL prohibit a Delaware corporation, including those whose securities are listed for trading on the OTCQX Best Market, from engaging in any business combination with any interested stockholder for a period of three years following the date that the stockholder became an interested stockholder, unless:
•prior to such time, the business combination or the transaction which resulted in the stockholder becoming an interested stockholder is approved by our board of directors;
•upon consummation of the transaction that resulted in the stockholder becoming an interested stockholder, the interested stockholder owned at least 85% of the voting stock of the corporation outstanding at the time the transaction commenced (excluding certain specified shares); or
•on or after such time the business combination is approved by our board of directors and authorized at a meeting of stockholders by the holders of at least two-thirds of the outstanding voting stock that is not owned by the interested stockholder.
Section 203 of the DGCL permits a Delaware corporation to elect not to be governed by the provisions of Section 203. Pursuant to our certificate of incorporation, we expressly elected not to be governed by Section 203. Accordingly, we are not subject to any anti-takeover effects or protections of Section 203 of the DGCL, although no assurance can be given that we will not elect to be governed by Section 203 of the DGCL pursuant to an amendment to our certificate of incorporation in the future.
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 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 written approval of our stockholders holding at least 60% of the total voting power of the then outstanding shares of our common stock (and the outstanding shares of any series of preferred stock of the Company entitled to vote with the Common Stock, voting together as a single class) 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 (i) a majority vote of our board of directors then in office, whether or not such directors number less than a quorum, (ii) a plurality vote of the holders of shares of our common stock (including shares of any series of preferred stock entitled to vote in an election of directors) at a duly called meeting of stockholders, or (iii) by written consent of holders of a majority of the shares of our common stock (including shares of any series of preferred stock entitled to vote in an election of directors). Directors so chosen shall hold office for the remainder of the full term to which the new directorship is allocated, and until such director’s successor shall have been elected and qualified or until such director’s earlier death, resignation or removal.
Risks Related to Our Emergence from Chapter 11 Bankruptcy
We recently emerged from bankruptcy, which could adversely affect our business and relationships.
It is possible that our having filed for bankruptcy and our recent emergence from the Chapter 11 bankruptcy proceedings could adversely affect our business and relationships with customers, vendors, contractors, employees or suppliers. Due to uncertainties, many risks exist, including the following:
•key suppliers could terminate their relationship or require financial assurances or enhanced performance;
•the ability to renew existing contracts and compete for new business may be adversely affected;
•the ability to attract, motivate and/or retain key executives and employees may be adversely affected;
•employees may be distracted from performance of their duties or more easily attracted to other employment opportunities; and
•competitors may take business away from us, and our ability to attract and retain customers may be negatively impacted.
The occurrence of one or more of these events could have a material and adverse effect on our operations, financial condition and reputation. We cannot assure you that having been subject to bankruptcy protection will not adversely affect our operations in the future.
Our actual financial results after emergence from bankruptcy are not comparable to our historical financial information as a result of the implementation of the Plan and the transactions contemplated thereby and our adoption of fresh start accounting.
In connection with the disclosure statement we filed with the Bankruptcy Court (the “Disclosure Statement”), and the hearing to consider confirmation of the Plan, we prepared projected financial information to demonstrate to the Bankruptcy Court the feasibility of the Plan and our ability to continue operations upon our emergence from bankruptcy. Those projections were prepared solely for the purpose of the bankruptcy proceedings and have not been, and will not be, updated on an ongoing basis and should not be relied upon by investors. Although the financial projections disclosed in our Disclosure Statement represent our view based on then current known facts and assumptions about the future operations of the Company there is no guarantee that the financial projections will be realized. We may not be able to meet the projected financial results or achieve projected revenues and cash flows assumed in projecting future business prospects. To the extent we do not meet the projected financial results or achieve projected revenues and cash flows, we may lack sufficient liquidity to continue operating as planned and may be unable to service our debt obligations as they come due or may not be able to meet our operational needs. Any one of these failures may preclude us from, among other things, taking advantage of future opportunities and growing our businesses.
In addition, upon our emergence from bankruptcy, we adopted fresh start accounting, as a consequence of which we allocated the reorganization value to our individual assets based on their estimated fair values. Accordingly, our financial condition and results of operations from and after the fresh start date are not comparable to the financial condition or results of operations reflected in our historical financial statements. Further, as a result of the implementation of the Plan and the transactions contemplated thereby, our historical financial information may not be indicative of our future financial performance.
Upon our emergence from bankruptcy, the composition of our board of directors changed significantly.
Pursuant to the Plan, the composition of the board of directors changed significantly. Upon emergence, the board of directors is now made up of five directors, of which four will not have previously served on the board of directors. The new directors have different backgrounds, experiences and perspectives from those individuals who previously served on the board of directors and, thus, may have different views on the issues that will determine the future of the Company. There is no guarantee that the new board will pursue, or will pursue in the same manner, our current strategic plans. As a result, the future strategy and plans of the Company may differ materially from those of the past.
Our ability to use our net operating loss carryforwards (“NOLs”) may be limited as a result of our emergence from bankruptcy.
In general, 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. Our emergence from Chapter 11 bankruptcy proceedings resulted in a change in ownership for purposes of the Section 382, which may limit our ability to utilize out NOLs to offset future taxable income.
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.
Risks Related to Other General Factors
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.
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 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 certificate of incorporation provides that, unless we consent in writing to the selection of an alternative forum, the Court of Chancery of the State of Delaware (the “Court of Chancery”) (or, if the Court of Chancery shall not have jurisdiction, another state court located within the state of Delaware, or if no state court located within the State of Delaware has jurisdiction, the federal district court for the District of Delaware), shall be the sole and exclusive forum for any stockholder of the Company (including a beneficial owner of stock) to bring (i) any derivative action or proceeding brought on behalf of the Company, (ii) any action asserting a claim of breach of a fiduciary duty owed by any director, officer or other employee of the Company to the Company or the Company’s stockholders, (iii) any action asserting a claim against the Company, its directors, officers or employees 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 the Company, its directors, officers or employees governed by the internal affairs doctrine, except as to each of (i) through (iv) above, subject to such Court of Chancery having personal jurisdiction over the indispensable parties named as defendants therein. The foregoing provision does not apply to claims under the Securities Act, the Exchange Act or any claim for which the U.S. federal courts have exclusive jurisdiction. 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.

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ITEM 1B. UNRESOLVED STAFF COMMENTS
Item 1B. Unresolved Staff Comments.
None.

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ITEM 2. PROPERTIES
Item 2. Properties.
Information regarding our oil and gas 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 1, Basis of Presentation - Acquisitions and Divestitures of the Notes to our Consolidated Financial Statements included in Item 8.

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ITEM 3. LEGAL PROCEEDINGS
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.
Chapter 11 Proceedings
On September 30, 2020, Lonestar Resources US Inc. and 21 of its directly and indirectly owned subsidiaries filed petitions for reorganization in a voluntary bankruptcy under chapter 11 of the Bankruptcy Code in the United States Bankruptcy Court for the Southern District of Texas under the caption In re Lonestar Resources US Inc., et al., Case No. 20-34805. On November 12, 2020, the Bankruptcy Court entered the Confirmation Order and on November 30, 2020, the Plan became effective in accordance with its terms and the Company emerged from the Chapter 11 bankruptcy proceedings. In December 2020, the Bankruptcy Court closed the chapter 11 cases of each of Lonestar Resources US Inc. and 20 of its directly and indirectly owned subsidiaries. The chapter 11 case captioned In re Lonestar Resources US Inc., et al., Case No. 20-34805 will remain pending until the final resolution of all outstanding claims.

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ITEM 4. MINE SAFETY DISCLOSURE
Item 4. Mine Safety Disclosures.
Not applicable.
PART II

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ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Our Predecessor's common stock was traded on the NASDAQ Global Select Market (the “NASDAQ”) under the symbol “LONE” until October 12, 2020. On October 1, 2020, the Predecessor received a letter from the NASDAQ notifying it that, as a result of the Chapter 11 Cases and in accordance with NASDAQ rules, the Predecessor's securities would be delisted at the opening of business on October 12, 2020. On October 12, 2020, the Predecessor's common stock commenced trading on the OTC Bulletin Board or "pink sheets" under the symbol “LONEQ”. NASDAQ filed a Form 25 on October 27, 2020 to delist the Predecessor's common stock which went into effect ten days after it was filed. On the Effective Date of November 30, 2020, all existing shares of our Predecessor's common stock were cancelled and we, as the Successor company, issued approximately 10.0 million shares of new common stock. Effective January 25, 2021, we commenced trading on the OTCQX Best Market under the symbol “LONE.”
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.
Purchase of Equity Securities by the Issuer and Affiliated Purchasers
None during the fourth quarter of 2020.

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ITEM 6. SELECTED FINANCIAL DATA

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS
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 Notes thereto included in Item 8, Financial Statements and Supplementary Information. Our discussion and analysis includes forward-looking information that involves risks and uncertainties and should be read in conjunction with Risk Factors under Item 1A of this Form 10-K, along with Forward-Looking Information at the end of this section for information on the risks and uncertainties that could cause our actual results to be materially different from our forward-looking statements.
Certain prior year financial statements are not comparable to our current year financial statements due to the adoption of fresh start accounting. References to “Successor” relate to the financial position and results of operations of the reorganized Company subsequent to November 30, 2020. References to “Predecessor” relate to the financial position and results of operations of the Company prior to, and including, November 30, 2020.
Overview
Lonestar Resources US Inc.is an independent exploration and production company with 79.2 MMBOE of estimated proved oil and natural gas reserves as of December 31, 2020, of which 74% is oil and NGLs. Our operations are focused on the exploration, development and production of unconventional oil, natural gas liquids and natural gas in the Eagle Ford Shale (the "Eagle Ford") play in South Texas.
Emergence from Voluntary Reorganization under Chapter 11
On September 30, 2020 (the “Petition Date”), Lonestar Resources US Inc., along with certain of its wholly-owned subsidiaries Lonestar Resources Intermediate Inc., LNR America Inc., Lonestar Resources America Inc., Amadeus Petroleum Inc., Albany Services, L.L.C., T-N-T Engineering, Inc., Lonestar Resources Inc., Lonestar Operating, LLC, Poplar Energy, LLC, Eagleford Gas, LLC, Eagleford Gas 2, LLC, Eagleford Gas 3, LLC, Eagleford Gas 4, LLC, Eagleford Gas 5, LLC, Eagleford Gas 6, LLC, Eagleford Gas 7, LLC, Eagleford Gas 8, LLC, Eagleford Gas 10, LLC, Eagleford Gas 11, LLC, Lonestar BR Disposal LLC, and La Salle Eagle Ford Gathering Line LLC (collectively, the “Debtors”) commenced voluntary cases (the “Chapter 11 Cases”) under chapter 11 of title 11 of the United States Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the Southern District of Texas (the “Bankruptcy Court”). The Chapter 11 Cases are being administered jointly under the caption In re Lonestar Resources US Inc., et al. Case No. 20-34805 (DRJ). Wholly-owned subsidiary, Boland Building, LLC, was not a Debtor and was not included in the Chapter 11 Cases.
In addition, on the Petition Date, the Debtors filed their Joint Prepackaged Plan of Reorganization with the Bankruptcy Court (the “Plan”). On November 12, 2020, the Bankruptcy Court entered its confirmation order (the “Confirmation Order”) approving and confirming the Plan. On November 30, 2020, (the “Effective Date”) the Plan became effective and was implemented in accordance with its terms.
On the Effective Date, the Company consummated the following reorganization transactions in accordance with the Plan:
•Adopted an amended and restated its certificate of incorporation and bylaws, which reserved for issuance 90,000,000 shares of common stock, par value $0.001 per share, (the “New Common Stock”) and 10,000,000 shares of preferred stock, par value $0.001 per share;
•Appointed a new board of directors to replace the Predecessor's directors, consisting of four new independent members: Richard Burnett, Gary D. Packer, Andrei Verona and Eric Long, and one continuing member: Frank D. Bracken, III, Lonestar's Chief Executive Officer;
•Provided for the following settlement of claims and interests in the Predecessor as follows:
◦Holders of Prepetition RBL Claims received distributions of:
▪Cash in the amount of all accrued and unpaid interest;
▪A first-out senior secured revolving credit facility with total aggregate commitments of $225 million;
▪A second-out senior secured term loan credit facility in an amount equal to $60 million;
▪555,555 Tranche 1 warrants and 555,555 Tranche 2 warrants, reflecting up to a 10% ownership stake in the Successor company's equity interests;
•Holders of Prepetition Notes Claims received distributions of a pro rata share of 96% of 10,000,149 shares of New Common Stock issued on the Effective Date, subject to dilution by a to-be-adopted management incentive plan (the "MIP") and the new warrants);
•Holders of Predecessor preferred equity interests received distributions of a pro rata share of 3% of the New Common Stock in the Successor company (subject to dilution by the MIP and the new warrants); and
•Holders of Predecessor Class A common stock received distributions of a pro rata share of 1% of the New Common Stock in the Successor company (subject to dilution by the MIP and new warrants).
•General unsecured creditors were paid in full in cash.
Fresh Start Accounting
Upon emergence from bankruptcy, the Company qualified for and adopted Fresh Start Accounting in accordance with ASC 852, which resulted in the Company becoming a new entity for financial reporting purposes because (1) the holders of the then existing voting shares of the Predecessor received less than 50 percent of the voting shares of the Successor upon emergence and (2) the reorganization value of the Company’s assets immediately prior to confirmation of the Plan was less than the total of all post-petition liabilities and allowed claims.
All conditions required for the adoption of fresh-start accounting were met when the Plan became effective, on November 30, 2020. The implementation of the Plan and the application of fresh-start accounting materially changed the carrying amounts and classifications reported in the Company’s consolidated financial statements and resulted in the Company becoming a new entity for financial reporting purposes. As a result of the application of fresh-start accounting and the effects of the implementation of the Plan, the financial statements on or prior to the effective date are not comparable with financial statements after the Effective Date.
Upon the application of fresh-start accounting, the Company allocated the reorganization value to its individual assets and liabilities in conformity with ASC 805, Business Combinations (“ASC 805”). The amount of deferred income taxes recorded was determined in accordance with ASC 740, Income Taxes. Reorganization value represents the fair value of the Successor Company’s assets before considering liabilities. The Effective Date fair values of the Company’s assets and liabilities differ materially from their previously recorded values as reflected on the historical balance sheets.
Market Developments and Response to Commodity Price Declines
In January and February 2020, NYMEX WTI oil prices averaged in the mid-$50s per Bbl range before a precipitous decline in oil prices that began in early March 2020 due to the combination of the COVID-19 coronavirus (“COVID-19”) pandemic and the failure of the group of oil producing nations known as OPEC+ to reach an agreement over proposed oil production cuts. While oil prices have improved from the low points experienced during the second quarter of 2020, the concerns and uncertainties around the balance of supply and demand for oil are expected to continue for some time.
The precipitous decline in oil prices that began in the latter part of the first quarter of 2020 caused us to reassess our original plans for 2020, and as a result the Company adopted the following operational and financial measures:
1.Reduced 2020 capital spending;
2.Deferred the remainder of our 2020 drilling program through the end of the year;
3.Implemented cost-reduction measures including negotiating reduced rates for water disposal, chemicals, rentals, and workovers;
4.Shut in or stored approximately 4,700 BOE per day of production during late-April and all of May 2020, primarily at our oil-rich fields in our Central Eagle Ford Area; and
5.Rebuilt our hedge portfolio starting October 2020 in anticipation of the Company's emergence from the Chapter 11 Proceedings. As of March 29, 2021 (Successor), we had oil derivative contracts in place for 2021 covering approximately 5,255 Bbls/d at an average price of $45.17 per Bbl. In addition, we currently have oil derivative contracts in place for 2022 consisting of 3,062 Bbls/d at an average price of $47.03 per Bbl. As of March 29, 2021 (Successor), we also had derivative contracts to hedge our 2021 natural gas production covering 13,251 MMBtu/d at a weighted average price of $3.02 per MMBtu. In addition, we currently have natural gas derivative contracts in place for 2022 consisting of 6,233 MMBtu/d at a weighted average price of $2.77 per MMBtu. We believe that these hedges help mitigate our exposure to oil and natural gas price volatility.
2020 Operational Highlights
As a result of Lonestar filing for bankruptcy and emerging from bankruptcy on November 30, 2020, our financial results are broken out between the Predecessor (the eleven months ended November 30, 2020) and the Successor period (the month ended December 31, 2020). For the Predecessor period, we recognized a net loss of $126.4 million attributable to common shareholders, and for the Successor period, we recognized a net loss of $0.7 million. The primary drivers of our financial net loss for the Predecessor period included the following:
•Impairment of oil and gas properties of $199.9 million, of which $199.0 million was proved and $0.9 million was unproved. These impairments resulted from removing PUDs and probable reserves from future development plans due to the continued depressed commodity prices and the uncertainly of Company's liquidity situation at the time.
•Reorganization items, net, resulted in an $73.5 million gain due to a gain on settlements of liabilities subject to compromise of $181.8 million, primarily representing the net impact of approximately $284.6 million of debt and accrued interest elimination, partially offset by fresh start accounting adjustments of $93.3 million and professional fees of $11.8 million.
On a comparative basis, we recognized net loss of $111.6 million, or $4.48 per diluted share, during 2019. The following reflects some of the primary drivers for our change in operating results between full-year 2020 and 2019:
•Oil and natural gas revenues decreased by $78.8 million (40%), with 25% of the decrease due to lower commodity prices and 15% due to lower production;
•Lease operating expenses decreased by $10.1 million (32%), primarily due to cost reduction measures in light of the low oil price environment;
•Commodity derivative expense decreased by $94.6 million ($63.7 million of income during 2020 compared to $30.9 million of expense during 2019), resulting from a $27.9 million increase in cash receipts upon settlement and an incremental $66.7 million decrease in noncash fair value losses between periods, and
•Impairment of oil and gas properties totaled $199.9 million during 2020 compared to $48.4 million during 2019. See Operating Results - Impairment of Oil and Gas Properties below for further details.
Pirate Divestiture
On March 22, 2019, we completed the divestiture of our Pirate assets in Wilson County for $12.3 million, before closing adjustments, to a private third-party. The assets were comprised of 3,400 net undeveloped acres, six producing wells, held seven proved undeveloped locations as of the closing date, and were producing approximately 200 BOE/d. We recognized a loss of $33.5 million during the first quarter of 2019 (Predecessor) in conjunction with the sale of the assets.
Operating Results
Certain of our operating results and statistics for each of the last two years are summarized below:
Successor Predecessor
In thousands, except per share and unit data Month Ended December 31, 2020 Eleven months Ended November 30, 2020 Year Ended December 31, 2019
Operating results
Net loss attributable to common stockholders $ (716) $ (126,376) $ (111,563)
Net loss income per common share -- basic(1)
(0.07) (5.00) (4.48)
Net loss income per common share -- diluted(1)
(0.07) (5.00) (4.48)
Net cash provided by operating activities 12,987 88,236 80,322
Operating revenues
Oil $ 8,112 $ 80,244 $ 157,873
NGLs 1,083 9,982 15,668
Natural gas 1,706 15,100 21,611
Total operating revenues $ 10,901 $ 105,326 $ 195,152
Total production volumes by product
Oil (Bbls) 188,322 2,268,715 2,692,020
NGLs (Bbls) 88,385 1,061,515 1,368,340
Natural gas (Mcf) 552,341 7,643,360 8,896,561
Total barrels of oil equivalent (6:1) 368,764 4,604,123 5,543,120
Daily production volumes by product
Oil (Bbls/d) 6,075 6,772 7,375
NGLs (Bbls/d) 2,851 3,169 3,749
Natural gas (Mcf/d) 17,817 22,816 24,374
Total barrels of oil equivalent (BOE/d) 11,896 13,744 15,187
Average realized prices
Oil ($ per Bbl) $ 43.08 $ 35.37 $ 58.64
NGLs ($ per Bbl) 12.25 9.40 11.45
Natural gas ($ per Mcf) 3.09 1.98 2.43
Total oil equivalent, excluding the effect from hedging ($ per BOE) 29.56 22.88 35.21
Total oil equivalent, including the effect from hedging ($ per BOE) 27.55 38.16 34.15
Operating and other expenses
Lease operating $ 1,418 $ 20,435 $ 31,925
Gas gathering, processing and transportation 461 6,182 4,656
Production and ad valorem taxes 667 6,508 11,169
Depreciation, depletion and amortization 2,093 70,122 88,618
General and administrative 1,505 28,444 16,489
Interest expense 1,476 35,411 43,879
Operating and other expenses per BOE
Lease operating and gas gathering $ 3.85 $ 4.44 5.76
Gas gathering, processing and transportation 1.25 1.34 0.84
Production and ad valorem taxes 1.81 1.41 2.01
Depreciation, depletion and amortization 5.68 15.23 15.99
General and administrative 4.08 6.18 2.97
Interest expense 4.00 7.69 7.92
(1) Basic and diluted earnings per share are calculated using the two-class method for the Predecessor periods. See Footnote 1. Basis of Presentation in the Notes to Consolidated Financial Statements included in Item 8.
Production
The table below summarizes our daily production volumes for the years ended 2020 and 2019, and for each of the quarters of 2020:
2020 Quarters Year ended December 31,
Q1 Q2 Q3 Q4 2020 2019 Change
Oil (Bbls/d) 7,236 6,365 7,190 6,064 6,713 7,375 (9) %
NGLs (Bbls/d) 3,335 2,939 3,325 2,968 3,142 3,749 (16) %
Natural Gas (Mcf/d) 23,191 24,211 23,424 18,773 22,393 24,374 (8) %
Total (BOE/d) 14,436 13,339 14,419 12,161 13,587 15,187 (11) %
Total production during 2020 averaged 13,587 BOE/d, a decrease of 11% compared to 2019. The annual decrease was primarily driven by curtailment of production during the second quarter of 2020 due to depressed commodity prices, as discussed above, and deferment of the drilling program in the third quarter of 2020 due to continued depressed commodity prices and preservation of liquidity while the Company went through reorganization.
Our production during 2020 was 73% oil and NGLs, approximately the same allocation as 2019.
Oil, NGL and Natural Gas Revenues
The table below summarizes our production revenues for 2020 and 2019:
Successor Predecessor
In thousands One Month Ended December 31, 2020 Eleven Months Ended November 30, 2020 Year Ended December 31, 2019
Oil $ 8,112 $ 80,244 $ 157,873
NGLs 1,083 9,982 15,668
Natural Gas 1,706 15,100 21,611
Total operating revenues $ 10,901 $ 105,326 $ 195,152
The changes in our oil, NGL and natural gas revenues are due to production quantities and commodity prices, as reflected in the following table (excluding any impact of our commodity derivative contracts):
Year ended December 31, 2020 vs 2019
In thousands Change in revenues Percentage change in revenues
Change in oil, NGL and natural gas revenues due to:
Decrease in production $ (20,078) (25) %
Decrease in commodity prices (58,816) (15) %
Total operating revenues $ (78,894) (40) %
Excluding the impact of our commodity derivative contracts, our net realized commodity prices and NYMEX differentials were as follows during 2020 and 2019:
Successor Predecessor
Month Ended December 31, 2020 Eleven Months Ended November 30, 2020 Year Ended December 31, 2019
Average net realized prices:
Oil ($/Bbl) $ 43.08 $ 35.37 $ 58.64
NGLs ($/Bbls) 12.25 9.40 11.45
Natural gas ($/Mcf) 3.09 1.98 2.43
Total ($/BOE) 29.56 22.88 35.21
Average NYMEX differentials
Oil per Bbl $ (4.01) $ (3.33) $ 1.61
Natural gas per Mcf (0.01) 0.50 (0.14)
Our average NYMEX oil differential decreased compared to 2019 due to the pricing components of MEH and CMA/Roll being approximately $4.38, or 86%, lower on average in 2019 compared to 2020.
Our natural gas NYMEX differentials are generally caused by movement in the NYMEX natural gas prices during the month, as most of our natural gas is sold on an index price that is set near the first of each month. While the percentage change in NYMEX natural gas differentials can be large, these differentials are seldom more than a dollar above or below NYMEX price.
Commodity Derivative Contracts
We utilize oil and natural gas derivative contracts to provide an economic hedge of our exposure to commodity price risk associated with anticipated future production and to provide more certainty to our future cash flows. These contracts have historically consisted of fixed-price swaps, collars and basis swaps.
The following table summarizes the net cash payments on the Company's commodity derivatives for 2020 and 2019:
Successor Predecessor
In thousands Month Ended December 31, 2020 Eleven Months Ended November 30, 2020 Year Ended December 31, 2019
Receipts (payments) on settlements of oil derivatives $ - $ 72,580 $ (5,902)
(Payments) receipts on settlements of natural gas derivatives - (3,189) 2,352
Total net commodity derivative receipts (payments) $ - $ 69,391 $ (3,550)
In order to provide a level of price protection to a portion of our oil production and to meet certain hedging requirements under our Successor senior secured bank credit facility, we have hedged a portion of our estimated oil and natural gas production in 2021 and 2022 using NYMEX fixed-price swaps. See Note 12, Commodity Price Risk Activities, to the consolidated financial statements for additional details of our outstanding commodity derivative contracts as of December 31, 2020 below for additional discussion. In addition, the following table summarizes our oil derivative contracts as of March 24, 2021:
Q1 2021 Q2 2021 Q3 2021 Q4 2021 1H 2022 2H 2022
Oil - WTI
Volumes Hedged (Bbls/d) 4,822 6,150 5,150 4,900 3,124 3,000
Swap Price $ 43.98 $ 46.66 $ 45.11 $ 44.53 $ 47.32 $ 46.73
Natural Gas - Henry Hub
Volumes Hedged (Mcf/d) 13,500 12,400 16,400 10,700 7,486 5,000
Swap Price $ 3.23 $ 2.88 $ 2.93 $ 3.05 $ 2.82 $ 2.70
On an accrual basis, our realized gain on derivative hedging instruments was $69.6 million, or $14.00 per BOE, for the combined Predecessor and Successor periods included within the year ended December 31, 2020, compared to a realized loss of $5.9 million, or $5.07 per BOE, during 2019. Included in the 2020 amount is $33.2 million, net ($39.9 million in oil hedges and negative $6.7 million in natural gas hedges, gross), which was realized upon termination of our hedging portfolio in September 2020 (Predecessor) prior to the commencement of the Chapter 11 Proceedings.
Production Expenses
The table below presents detail of production expenses for 2020 and 2019:
Successor Predecessor
In thousands, except expense per BOE: Month Ended December 31, 2020 Eleven Months Ended November 30, 2020 Year Ended December 31, 2019
Production expenses:
Lease operating $ 1,418 $ 20,435 $ 31,925
Gas gathering, processing and transportation 461 6,182 4,656
Production and ad valorem taxes 667 6,508 11,169
Depreciation, depletion and amortization 2,093 70,122 88,618
Production expenses per BOE:
Lease operating $ 3.85 $ 4.44 $ 5.76
Gas gathering, processing and transportation 1.25 1.34 0.84
Production and ad valorem taxes 1.81 1.41 2.01
Depreciation, depletion and amortization 5.68 15.23 15.99
Lease Operating and Gas Gathering
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.
Total lease operating expense was $21.9 million, or $4.39 per BOE, for the combined Predecessor and Successor periods included within the year ended December 31, 2020, compared to $31.9 million, or $5.76 per BOE, during 2019. Total gas gathering, processing and transportation expense was $6.6 million, or $1.34 per BOE for the combined Predecessor and Successor periods included within the year ended December 31, 2020, compared to $4.7 million, or $0.84 per BOE, during 2019. The decreases in lease operating expense on an absolute-dollar basis and per-BOE basis were primarily due to lower expenses across all expense categories, as we implemented cost reduction measures which included shutting down compressors, negotiating reductions with vendors and curtailing workovers in response to the significant decline in oil prices in 2020. Gas gathering, processing and transportation expense remained relatively constant between years as the Company prioritized maintaining its natural gas production through 2020. Natural gas prices did not drop to the extent oil prices did during the second and third quarter when the Company shut in a significant a significant amount of its production, primarily from its oil-rich wells in the Central Region.
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.
The following table provides detail of our production and ad valorem taxes for 2020 and 2019:
Successor Predecessor
In thousands Month Ended December 31, 2020 Eleven Months Ended November 30, 2020 Year Ended December 31, 2019
Production taxes $ 440 $ 4,015 $ 8,098
Ad valorem taxes 227 2,493 3,071
Total production and ad valorem tax expense $ 667 $ 6,508 $ 11,169
Production and ad valorem tax expense per BOE
Production taxes $ 1.19 $ 0.87 $ 0.90
Ad valorem taxes 0.62 0.54 0.55
Total production and ad valorem tax expense per BOE $ 1.81 $ 1.41 $ 1.44
Total production and ad valorem tax expense was $7.2 million, or $1.44 per BOE, for the combined Predecessor and Successor periods included within the year ended December 31, 2020, compared to $11.2 million, or $1.44 per BOE, during 2019. The decrease between periods was primarily due to the decrease in production taxes resulting from lower oil and natural gas revenues and production levels.
Depreciation, Depletion, and Amortization ("DD&A")
The table below provides detail of our DD&A expense for 2020 and 2019:
Successor Predecessor
In thousands Month Ended December 31, 2020 Eleven Months Ended November 30, 2020 Year Ended December 31, 2019
DD&A of proved oil and gas properties $ 1,889 $ 67,591 $ 86,867
Depreciation of other property and equipment 136 1,442 1,451
Accretion of asset retirement obligations 68 1,089 300
Total DD&A $ 2,093 $ 70,122 $ 88,618
DD&A per BOE
DD&A of proved oil and gas properties $ 5.12 $ 14.68 $ 15.68
Depreciation of other property and equipment 0.37 0.31 0.26
Accretion of asset retirement obligations 0.18 0.24 0.05
Total DD&A per BOE $ 5.67 $ 15.23 $ 15.99
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 well 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.
Total DD&A expense was $72.2 million, or $14.52 per BOE, for the combined Predecessor and Successor periods included within the year ended December 31, 2020, compared to $88.6 million, or $15.99 per BOE, during 2019. The combined Predecessor and Successor period decreases in oil and natural gas properties depletion and other property and equipment depreciation was primarily due to impairment charges we incurred during the first quarter of 2020 (Predecessor) after removing PUDs (see below, as well as lower depletable costs due to the step down in book value resulting from fresh start accounting.
Based upon fresh start accounting, oil and gas properties were recorded at fair value as of November 30, 2020. See Note 3, Fresh Start Accounting, to the consolidated financial statements for further discussion.
Impairment of Oil and Gas Properties
We evaluate impairment of proved and unproved oil and gas properties on a region basis. On this basis, certain regions may be impaired because they are not expected to recover their entire carrying value from future net cash flows.
During the fourth quarter of 2019 (Predecessor), we recorded impairment charges totaling approximately $48.4 million for our East Region properties in Brazos County, $33.9 million of which related to proved properties and $14.5 million which related to unproved properties. These impairments resulted from recent well results as well as a deterioration of commodity prices and the operating environment in the Region.
During the first quarter of 2020 (Predecessor), we recorded impairment charges totaling approximately $199.9 million across various Eagle Ford properties, of which $199.0 million was proved and $0.9 million was unproved. These impairments resulted from removing PUDs and probable reserves from future development plans due to the continued depressed commodity prices and the uncertainly of Company's liquidity situation at the time.
Upon emergence from bankruptcy, the Company adopted fresh start accounting which resulted in our long-lived assets being recorded at their estimated fair values at the Effective Date (see Note 3, Fresh Start Accounting, to the consolidated financial statements for additional information). There were no material changes to our key cash flow assumptions and no triggering events since the Company’s assets were revalued in fresh start accounting as of November 30, 2020; therefore, no impairment was identified in December 2020.
Loss on Sale of Oil and Gas Properties
On March 22, 2019, we completed the divestiture of our Pirate assets in Wilson County for $12.3 million, before closing adjustments, to a private third-party. The assets were comprised of 3,400 net undeveloped acres, six producing wells, held seven proved undeveloped locations as of the closing date, and were producing approximately 200 BOE/d. We recognized a loss of $33.5 million during the first quarter of 2019 (Predecessor) in conjunction with the sale of the assets.
General and Administrative Expense
Total general and administrative ("G&A") expense was $30.0 million, or $6.04 per BOE, for the combined Predecessor and Successor periods included within the year ended December 31, 2020, compared to $16.5 million, or $2.97 per BOE, during 2019. These increases primarily reflect professional fees incurred related to our restructuring efforts prior to the Petition Date and subsequent to the Effective Date.
Stock-based compensation included in G&A was a gain of $1.8 million in 2020 for the eleven months ended November 30, 2020, versus an expense of $2.5 million in 2019. On the Effective Date, all of the Predecessor's stock-based compensation plans were cancelled and the Successor Company did not implement any new stock-based compensation plans prior to December 31, 2020.
Interest Expense
The table below provides detail of the interest expense from our various long-term obligations for 2020 and 2019:
Successor Predecessor
In thousands Month Ended December 31, 2020 Eleven Months Ended November 30, 2020 Year Ended December 31, 2019
Interest expense on Successor Credit Facility $ 984 $ - $ -
Interest expense on Successor Term Loan Facility 344 - -
Interest expense on Predecessor Credit Facility (1)
- 11,599 12,449
Interest expense on Predecessor 11.25% Senior Notes - 21,094 28,125
Other interest expense 17 622 677
Total cash interest expense(2)
$ 1,345 $ 33,315 $ 41,251
Amortization of debt issuance costs and discounts(3)
131 2,096 2,628
Total interest expense $ 1,476 $ 35,411 $ 43,879
Per BOE:
Total cash interest expense(2)
$ 3.65 $ 7.24 $ 7.44
Total interest expense 4.00 7.69 7.92
(1) The contractual interest expense on the 11.25% Senior Notes is in excess of recorded interest expense by $4.7 million from the Petition Date until the Effective Date and was not included as interest expense on the Consolidated Statements of Operations for the Predecessor period because the Company discontinued accruing interest on the 11.25% Senior Notes subsequent to the Petition Date in accordance with ASC 852.
(2) Cash interest is presented on an accrual basis.
(3) Remaining discounts for the Predecessor 11.25% Senior Notes were written-off to “Reorganization items, net” in the Consolidated Statements of Operations on the Petition Date.
Cash interest was $34.7 million, or $6.97 per BOE, for the combined Predecessor and Successor periods included within the year ended December 31, 2020, compared to $41.3 million, or $6.97 per BOE, during 2019. The decrease between periods was primarily due to a decrease in the average debt principal outstanding, with the Successor period reflecting the full extinguishment of all outstanding obligations under the 11.25% Senior Secured Notes on the Effective Date, pursuant to the terms of the Plan, relieving approximately $250 million of debt by issuing equity in the Successor period to the holders of that debt.
See Note 10. Long-Term Debt in Notes to the Consolidated Financial Statements included in Item 8. Financial Statements for additional information about our long-term debt and interest expense.
Reorganization Items, Net
Reorganization items represent (i) expenses incurred during the Chapter 11 restructuring starting on the Petition Date as a direct result of the Plan, (ii) gains or losses from liabilities settled, and (iii) fresh start accounting adjustments and are recorded in “Reorganization items, net” in our Consolidated Statements of Operations. Professional service provider charges associated with our restructuring that were incurred before the Petition Date and after the Effective Date are recorded as general and administrative expenses in our Consolidated Statements of Operations.
The following table summarizes the losses (gains) on reorganization items, net:
Predecessor
In thousands Period from September 30, 2020 through November 30, 2020
Unamortized debt issuance costs and discounts $ (3,243)
Professional fees and other (11,847)
Fresh start valuation adjustments (93,282)
Gain on settlement of liabilities subject to compromise 181,843
Total reorganization items, net $ 73,471
Income Taxes
The table below provides further detail of our income tax benefit for 2020 and 2019:
In thousands, except per-BOE amounts and tax rates Successor Predecessor
Month Ended December 31, 2020 Eleven Months Ended November 30, 2020 Year Ended December 31, 2019
Current income tax benefit $ - $ (3,748) $ (1,055)
Deferred income tax benefit - (931) (11,440)
Total income tax benefit $ - $ (4,679) $ (12,495)
Average income tax benefit per BOE $ - $ (1.02) $ (2.25)
Effective tax rate - % (3.8) % (10.8) %
Total net deferred tax liability on balance sheet at period end $ - $ - $ 931
We have evaluated the impact of the Plan, including the change in control, resulting from our emergence from bankruptcy. The cancellation of debt income (“CODI”) realized upon emergence is excludable from income and resulted in a partial elimination of our available federal net operating loss carryforwards and tax credit carryforwards, as well as a partial reduction in tax basis in assets, in accordance with the attribute reduction and ordering rules of Section 108 of the Internal Revenue Code of 1986 (the “Code”). The reduction in the Company’s tax attributes for excludable CODI did not occur until the last day of the Company’s tax year, December 31, 2020. The final tax impacts of the bankruptcy emergence, as well as the Plan’s overall effect on the Company’s tax attributes which were refined based on the Company’s final financial position at December 31, 2020 as required under the Code.
As the tax basis of our assets, primarily our oil and gas properties, is in excess of the carrying value, as adjusted in fresh start accounting, the Successor is in a net deferred tax asset position at December 31, 2020. We evaluated our deferred tax assets in light of all available evidence as of the balance sheet date, including the tax impacts of the Chapter 11 Proceedings and the partial reduction of net operating losses and tax credits and partial reduction of tax basis in assets (collectively “tax attributes”). Given our cumulative loss position and the continued low oil price environment, we recorded a total valuation allowance of $37.5 million on our underlying deferred tax assets as of December 31, 2020. For the Successor period, the income tax benefit associated with the Successor’s pre-tax book loss was substantially offset by a change in valuation allowance.
Our deferred tax assets exceeded our deferred tax liabilities at December 31, 2019 (Predecessor) primarily due to tax consequences of the impairment of our Brazos properties during the fourth quarter; as a result, we established a valuation allowance against most of the deferred tax assets during the fourth quarter of 2019. With the exception of a $0.6 million deferred tax asset retained for existing refundable AMT credit carryovers we retained a full valuation allowance of $8.9 million at December 31, 2019 due to uncertainties regarding the future realization of our deferred tax assets. This deferred tax asset is included in the net deferred tax liability at December 31, 2019, which also includes deferred tax liabilities of $1.5 million for State taxes. See Note 11. Income Taxes in Notes to the Consolidated Financial Statements included in Item 8. Financial Statements for additional information about our income taxes.
CAPITOL RESOURCES AND LIQUIDITY
Our primary sources of capital and liquidity are our cash flows from operations and availability of borrowing capacity under our Successor Credit Facility. Our most significant cash outlays relate to our development capital expenditures and current period operating expenses.
The Company's primary needs for cash are for capital expenditures, acquisitions of oil and natural gas properties, payments of contractual obligations and working capital obligations. We have historically financed our business through cash flows from operations, borrowings under our Credit Facility and the issuance of bonds and equity offerings. As circumstances warrant, we may access the capital markets and issue equity or debt from time to time on an opportunistic basis in a continued effort to optimize our balance sheet and to fund our operations and capital expenditures in the future, dependent upon market conditions and available pricing. Uses of such proceeds may include repayment of our debt, development or acquisition of additional acreage or proved properties, and general corporate purposes. There can be no assurance that future funding transactions will be available on favorable terms, or at all, and we therefore cannot guarantee the outcome of any such transactions.
Cash flows for 2020 and 2019 are presented below:
In thousands Successor Predecessor
Month Ended December 31, 2020 Eleven Months Ended November 30, 2020 Year Ended December 31, 2019
Net cash provided by (used in):
Operating activities $ 12,987 $ 88,236 $ 80,322
Investing activities (305) (92,432) (146,292)
Financing activities (5,021) 19,844 63,752
Net change in cash, cash equivalents and restricted cash $ 7,661 $ 15,648 $ (2,218)
Net Cash Provided by Operating Activities
Net cash provided by operating activities was $101.2 million for the combined Successor and Predecessor periods included with the year ended December 31, 2020, compared to $80.3 million during 2019. Realized commodity derivative gains throughout the Predecessor period in 2020 in addition to the liquidation of our open commodity derivatives in September 2020, contributed to the increase between periods.
Net Cash Used in Investing Activities
Net cash used in investing activities was $92.7 million for the combined Successor and Predecessor periods included with the year ended December 31, 2020, compared to $146.3 million during 2019. This decrease is primarily due to lower drilling and development costs in 2020 due to curtailment of our drilling program starting in the second quarter of 2020 in response to lower commodity prices and liquidity conservation in anticipation of restructuring.
Net Cash Provided by Financing Activities
Net cash provided by financing activities was $14.8 million for the combined Successor and Predecessor periods included with the year ended December 31, 2020, compared to $63.8 million during 2019. This decrease primarily results from lower borrowings from our Predecessor Credit Facility during 2020. Currently, our availability under the Successor Credit Facility is $15.0 million and we are required to make quarterly paydowns on our Successor Term Loan Facility which will total $20.0 million annually in 2021.
Debt
Successor Senior Secured Credit Agreements
On the Effective Date, the Successor, through its subsidiary Lonestar Resources America Inc., entered into a new first-out senior secured revolving credit facility with Citibank, N.A., as administrative agent, and the other lenders from time to time party thereto (the “Successor Credit Facility”) and a second-out senior secured term loan credit facility (the “Successor Term Loan Facility” and, together with the Successor Credit Facility, the “Successor Credit Agreements”) by amending and restating the Company’s existing credit agreement (as so amended and restated, the “Predecessor Credit Facility”). The Successor Credit Facility provides for revolving loans in an aggregate amount of up to $225 million, subject to borrowing base capacity. Letters of credit are available up to the lesser of (a) $2.5 million and (b) the aggregate unused amount of commitments under the Successor Credit Facility then in effect. On the Effective Date, Lonestar Resources America Inc. borrowed $60.0 million in term loans under the Successor Term Loan Facility. The Successor Credit Agreements will mature on November 30, 2023. The term loans under the Successor Term Loan Facility amortize on a quarterly basis in an amount equal to $5.0 million, payable on the last day of March, June, September and December of each year. The Successor's obligations under the Successor Credit Agreements are guaranteed by all of the Successor's direct and indirect subsidiaries (subject to certain permitted exceptions) and will be secured by a lien on substantially all of the Successor's, Lonestar Resources America Inc.’s and the guarantors’ assets (subject to certain exceptions).
Borrowings and letters of credit under the Successor Credit Facility are limited by borrowing base calculations set forth therein. The initial borrowing base is $225 million, subject to redetermination. The borrowing base will be redetermined semiannually on or around May 1 and November 1 of each year, with one interim “wildcard” redetermination available between scheduled redeterminations. The first wildcard redetermination occurred on February 1, 2021, which reaffirmed the initial borrowing base of $225 million.
The Successor Credit Agreements contain customary covenants, including, but not limited to, restrictions on the Successor's ability and that of its subsidiaries to merge and consolidate with other companies, incur indebtedness, grant liens or security interests on assets, make acquisitions, loans, advances or investments, pay dividends, sell or otherwise transfer assets, or enter into transactions with affiliates.
The Successor Credit Facility contains certain financial performance covenants including the following:
•A Consolidated Total Debt to Consolidated EBITDAX covenant, with such ratio not to exceed 3.5 times; and
•A requirement to maintain a current ratio (i.e., Consolidated Current Assets to Consolidated Current Liabilities) of at least 0.95 times for the three months ended December 31, 2020 and 1.0 times each fiscal quarter thereafter. The current ratio excludes current derivative assets and liabilities, as well as the current amounts due under the Successor Term Loan Facility, from the ratio.
Borrowings under the Successor Credit Agreements bear interest at a floating rate at the Successor's option, which can be either an adjusted Eurodollar rate (the Adjusted LIBOR, subject to a 1% floor) plus an applicable margin of 4.50% per annum or a base rate determined under the Successor Credit Facility (the "ABR", subject to a 2% floor) plus an applicable margin of 3.50% per annum. The weighted average interest rate on borrowings under the Successor Credit Agreements was 5.8% for the month ended December 31, 2020 (Successor). The undrawn portion of the aggregate lender commitments under the Successor Credit Facility is subject to a commitment fee of 1.0%. As of December 31, 2020, the Successor was in compliance with all debt covenants under the Successor Credit Facilities.
Predecessor Senior Secured Bank Credit Facility
From July 2015 through November 30, 2020, the Predecessor maintained a senior secured revolving credit facility with Citibank, N.A., as administrative agent, and other lenders party thereto. All of the Predecessor Credit Facility was refinanced by the Successor Credit Agreements on the Effective Date.
Extinguishment of Predecessor 11.25% Senior Notes
On the Effective Date, the Predecessor's 11.25% Senior Notes due 2023 (the "11.25% Senior Notes") were fully extinguished by issuing equity in the Successor to the holders of that debt.
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, 2020 (Successor) and 2019 (Predecessor), the Company had approximately $4.6 million and $0.8 million, respectively, of debt issuance costs associated with the Successor Credit Facility and Predecessor Credit Facility, respectively, remaining that are being amortized over the lives of the respective debt which are recorded as Other Non-Current Assets in the accompanying unaudited condensed consolidated balance sheets.
Capital Expenditures
Historical capital expenditures
The table below summarizes our cash capital expenditures incurred for 2020:
Successor Predecessor
In thousands Month Ended December 31, 2020 Eleven Months Ended November 30, 2020
Acquisition of oil and gas properties $ 53 $ 2,902
Development of oil and gas properties 247 100,437
Purchases of other property and equipment 5 1,007
Total capital expenditures, net $ 305 $ 104,346
For the year ended December 31, 2020, our capital expenditures were funded with $101.2 million of cash flow from operations, with additional funds provided by borrowings on our Predecessor Credit Facility.
2021 Capital Spending
Capital spending levels are highly dependent on revenues, liquidity and our commitment to repay debt. We are currently expect expenditures, including acquisitions, of $45 million to $55 million. This program, as it currently stands, will allow for the drilling of 10 gross wells, all of which will be in our Eagle Ford position in South Texas. As previously noted, our 2021 capital expenditures may be adjusted as business conditions warrant and the amount, timing and allocation of such expenditures is largely discretionary and within our control. The aggregate amount of capital that we will expend may fluctuate materially based on market conditions, the actual costs to drill, complete and place on production operated wells, our drilling results, other opportunities that may become available to us and our ability to obtain capital.
Off-Balance Sheet Arrangements
We have operating leases relating to office space and other minor equipment leases. At December 31, 2020 (Successor), we had a total of $0.4 million of letters of credit outstanding under our Successor Credit Facility. From time-to-time, we enter into other off-balance sheet arrangements and transactions that give rise to off-balance sheet obligations, including non-operated drilling commitments, termination obligations under rig contracts, frac spread contracts, firm transportation, gathering, processing and disposal commitments, and contractual obligations for which the ultimate settlement amounts are not fixed and determinable, such as derivative contracts that are sensitive to future changes in commodity prices. See Note 15. Commitments and Contingencies in Notes to Consolidated Financial Statements in Item 8. Financial Statements for more information.
Critical Accounting Policies and Estimates
The preparation of financial statements in accordance with generally accepted accounting principles requires that we select certain accounting policies and make certain estimates and judgments regarding the application of those policies. Our significant accounting policies are included in Note 1. Basis of Presentation, of the Notes to Consolidated Financial Statements in Item 8. Financial Statements. These policies, along with the underlying assumptions and judgments by our management in their application, have a significant impact on our consolidated financial statements. Following is a discussion of our most critical accounting estimates, judgments and uncertainties that are inherent in the preparation of our financial statements.
Fresh Start Accounting
Upon emergence from bankruptcy, we met the criteria and were required to adopt fresh start accounting in accordance with Topic 852, Reorganizations, which on the Effective Date resulted in a new entity, the Successor, for financial reporting purposes, with no beginning retained earnings or deficit as of the fresh start reporting date. Fresh start accounting requires that new fair values be established for the Company’s assets, liabilities and equity as of the date of emergence from bankruptcy, November 30, 2020. The Effective Date fair values of the Successor’s assets and liabilities differ materially from their recorded values as reflected on the historical balance sheet of the Predecessor and required a number of estimates and judgments to be made. All estimates, assumptions, valuations and financial projections, including the fair value adjustments, financial projections, enterprise value and equity value, are inherently subject to significant uncertainties and the resolution of contingencies beyond our control. Accordingly, there is no assurance that the estimates, assumptions, valuations or financial projections will be realized, and actual results could vary materially. Among the most material of these judgments and estimates that were made were the following:
•Reorganization Value - The reorganization value derived from the range of enterprise values associated with the Plan was allocated to the Company’s identifiable tangible and intangible assets and liabilities based on their fair values. The value of the reconstituted entity (i.e., Successor) was based on management projections and the valuation models as determined by the Plan of Reorganization. We determined the enterprise and corresponding equity value of the Successor using various valuation approaches and methods, including: (i) income approach using a calculation of the present value of future cash flows based on our financial projections, (ii) the market approach using selling prices of similar assets and (iii) the cost approach.
•Oil and Natural Gas Properties - The fair value of our oil and natural gas properties was determined based on the discounted cash flows expected to be generated from these assets. The computations were based on market conditions and reserves in place as of the Effective Date. The fair value analysis was based on the Company’s estimated future production rates of proved and probable reserves as prepared by the Company’s internal reserves group. Discounted cash flow models were prepared using the estimated future revenues and operating costs for all developed wells and undeveloped properties comprising the proved and probable reserves. Future revenue estimates were based upon estimated future production rates and forward strip oil and natural gas prices and other factors. A risk adjustment factor was applied to each reserve category, consistent with the risk of the category. Discount factors utilized were derived using a weighted average cost of capital computation, which included an estimated cost of debt and equity for market participants with similar geographies and asset development type and varying corporate income tax rates based on the expected point of sale for each property’s produced assets.
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.
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 well 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 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. On the sale or retirement of a partial unit of a proved property, a pro-rata portion of the cost and related accumulated depreciation, depletion and amortization may be eliminated from the property accounts if the field depletion rate is significantly altered.
Impairment of Long-Lived Assets
The carrying value of proved oil and gas properties and other related property and equipment are 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.
The Company evaluates impairment of proved and unproved oil and gas properties on a region-level basis. On this basis, certain regions may be impaired because they are not expected to recover their entire carrying value from future net cash flows. Given current market conditions, it is reasonably possible that the Company's estimate of undiscounted future net cash flows may change in the future resulting in the need to impair the carrying value of its oil and natural gas properties.
During the fourth quarter of 2019 (Predecessor), we recorded impairment charges totaling approximately $48.4 million for our East Region properties in Brazos County, $33.9 million of which related to proved properties and $14.5 million which related to unproved properties. These impairments resulted from recent well results as well as a deterioration of commodity prices and the operating environment in the Region.
During the first quarter of 2020 (Predecessor), we recorded impairment charges totaling approximately $199.9 million across various Eagle Ford properties, of which $199.0 million was proved and $0.9 million was unproved. These impairments resulted from removing PUDs and probable reserves from future development plans due to the continued depressed commodity prices and the uncertainly of Company's liquidity situation at the time.
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.
Asset Retirement Obligations
We account for asset retirement obligations ("AROs") 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
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.
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.
On March 27, 2020, Congress enacted the Coronavirus Aid, Relief, and Economic Security Act (the “CARES Act”) to provide certain taxpayer relief as a result of the COVID-19 pandemic. The CARES Act included several favorable provisions that impacted income taxes, primarily the modified rules on the deductibility of business interest expense for 2019 and 2020, a five-year carryback period for net operating losses generated after 2017 and before 2021, and the acceleration of refundable alternative minimum tax credits. The CARES Act did not materially impact our effective tax rate for the eleven months ended November 30, 2020 (Predecessor) and month ended December 31, 2020 (Successor).
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 1. Basis of Presentation of the Notes to Consolidated Financial Statements in Item 8. Financial Statements for discussion of the recent accounting pronouncements.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.
We are exposed to a variety of financial market risks including interest rate, commodity prices 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 as of December 31, 2020 (Successor). 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:
Hypothetical Fair Value
(in thousands) Fair Value 10% Increase In Commodity Price 10% Decrease In Commodity Price
Swaps $ (6,675) $ 5,791 $ (19,140)
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 swap contracts to manage our commodity price risk exposure. Our primary commodity risk management objectives are to protect returns on our drilling and completion activity as well as 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.
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.
Interest Rate Risk
As of December 31, 2020 (Successor), we had $264.6 million outstanding under the Successor Credit Agreements, which are 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, 2020 (Successor), a 100-basis-point change in interest rates would change our annualized interest expense by approximately $2.5 million.
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 Successor Credit Agreements 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.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Item 8. Financial Statements and Supplementary Data.
The financial statements and supplementary information required by this Item appears starting on page of this Annual Report on Form 10-K.

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.

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ITEM 9A. CONTROLS AND PROCEDURES
Item 9A. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
As of the end of the period covered by this report, an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act) was performed under the supervision and with the participation of management, including our Chief Executive Officer and Chief Accounting Officer. Based on that evaluation, our Chief Executive Officer and Chief Accounting Officer concluded that our disclosure controls and procedures were effective as of December 31, 2020 to ensure that information that is required to be disclosed in the reports the Company files and submits under the Securities Exchange Act of 1934 is recorded, that it is processed, summarized and reported within the time periods specified in the SEC’s rules and forms; and that information that is required to be disclosed under the Exchange Act is accumulated and communicated to management, including our Chief Executive Officer and our Chief Accounting Officer, as appropriate, to allow timely decisions regarding required disclosures.
Remediation of Previous Material Weakness
Prior to filing the quarterly report on Form 10-Q for the period ended September 30, 2020, the Company identified a material weakness relating to the operating effectiveness of controls over significant and unusual transactions - specifically relating to restructuring-related matters. This error was identified and corrected prior to the filing of the Form 10-Q but could have resulted in a material misstatement of the financial statements. This error was the result of inadequate operating effectiveness of controls pertaining to the Company’s review of its bankruptcy-related accounting and disclosures.
To remediate the material weakness described above and enhance our internal control over financial reporting, management implemented additional internal training and incremental reviews of work performed by consultants for its bankruptcy-related accounting disclosures. As a result of this additional training, management has determined that the foregoing material weakness has been remediated as of December 31, 2020.
Changes in Internal Control over Financial Reporting
Other than the remediation efforts related to the material weakness noted above, during the fourth quarter of 2020, there were no changes in our internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Management’s Report on Internal Control over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) of the Securities Exchange Act of 1934, as amended.
Under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Accounting Officer, we 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 in “Internal Control - Integrated Framework” (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on that assessment, our Chief Executive Officer and our Chief Accounting Officer concluded that our internal control over financial reporting was effective, as of December 31, 2020, to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of our financial statements for external purposes in accordance with U.S. generally accepted accounting principles.
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.
Important Considerations
The effectiveness of our disclosure controls and procedures and our internal control over financial reporting is subject to various inherent limitations, including cost limitations, judgments used in decision making, assumptions about the likelihood of future events, the soundness of our systems, the possibility of human error, and the risk of fraud. Moreover, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions and the risk that the degree of compliance with policies or procedures may deteriorate over time. Because of these limitations, there can be no assurance that any system of disclosure controls and procedures or internal control over financial reporting will be successful in preventing all errors or fraud or in making all material information known in a timely manner to the appropriate levels of management.
PART III

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ITEM 9B. OTHER INFORMATION

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ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
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.
Information about our Executive Officers and Directors
The following table provides information regarding the Company’s executive officers and directors (ages are as of March 26, 2021):
Name Position Age
Frank D. Bracken, III Chief Executive Officer and Director 57
Barry D. Schneider Chief Operating Officer 58
Jason N. Werth Chief Accounting Officer 45
Thomas H. Olle Vice President - Reservoir Engineering 66
Jana Payne Vice President - Geosciences 59
Richard Burnett Chairman 47
Eric Long Director 51
Gary D. Packer Director 58
Andrei Verona Director 42
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.
Jason N. Werth is our Chief Accounting Officer. Mr. Werth has served in this position since February 2018. Prior to joining us, Mr. Werth held the position of Director of Audit at Denbury Resources, Inc., where during his eight-year tenure he also served as SEC Reporting Manager and Assistant Controller of Corporate Accounting. Prior to Denbury, Mr. Werth was employed by Grande Energy and Orix Capital. Mr. Werth started his professional career in public accounting with Arthur Andersen LLP and later PricewaterhouseCoopers LLP, where he was an Assurance Manager. Mr. Werth holds Bachelor of Business Administration and Masters of Science degrees from Texas A&M University. He is a licensed Certified Public Accountant in the State of Texas.
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.
Richard Burnett is the Chairman of our Board of Directors, a position he has held since November 2020. Mr. Burnett is the President and Chief Executive Officer of Silver Creek Oil & Gas. Mr. Burnett previously served as Chief Financial Officer of Covey Park Energy, where he was instrumental in the divestiture of the company. Before joining Covey Park Energy, Mr. Burnett served as the Chief Financial Officer of Double Eagle Energy Holdings II and served as the Vice President, Chief Financial Officer and Chief Accounting Officer of EXCO Resources, Inc. Prior to these roles, Mr. Burnett was a partner at KPMG LLP and a Manager at Arthur Anderson LLP. He also serves on the board of both US Well Services and Select Energy Services, as a Director and the Chairman of the Audit Committee. Mr. Burnett is a Certified Public Accountant in the State of Texas.
Eric Long is a member of our Board of Directors, a position he has held since November 2020. Mr. Long is a Managing Director and Portfolio Manager at EIG Global Energy Partners (EIG). Prior to joining EIG in 2014, Mr. Long was a senior investment banker with Goldman Sachs. During his tenure, Mr. Long advised companies on a broad range of transactions including mergers, acquisitions, divestitures, debt and equity financings and other strategic investment activities. Prior to joining Goldman Sachs, Mr. Long was a Director in the Transaction Services Group of PricewaterhouseCoopers in the energy practice. Mr. Long is a Chartered Financial Analyst (CFA). He holds a Bachelor of Arts degree from the University of Vermont and a Masters of Business Administration from the Wharton School at the University of Pennsylvania.
Gary D. Packer is a member of our Board of Directors, a position he has held since November 2020. Mr. Packer has over 35 years in the oil & gas industry. He previously served as the Chief Operating Officer and Executive Vice President of Newfield Exploration Company for 10 years where he oversaw the Company’s worldwide operations and regional businesses prior to their sale to Encana in 2019 (~$8B). Before joining Newfield in 1995, Mr. Packer served in various engineering roles of increasing responsibility at Amerada Hess Corporation and Tenneco Oil Company. He has also served on several boards, including Bennu Oil & Gas, LLC, Independent Petroleum Association of America and affiliated Energy Education Center, and Independent Petroleum Association of Mountain States. Mr. Packer currently serves as Chairman of Penn State’s Petroleum and Natural Gas Engineering Industry & Professional Advisory Council and Inspiration Ranch. Mr. Packer is a Registered Professional Engineer in the State of Texas.
Andrei Verona is a member of our Board of Directors, a position he has held since November 2020. Mr Verona is a Portfolio Manager at Saye Capital Management, an opportunistic credit hedge fund. He manages the corporate portion of the portfolio, which invests primarily in high yield and distressed bonds with a focus on restructurings and other event-driven opportunities. Before joining Saye Capital, Mr. Verona was a Vice President in Gleacher & Company's Investment Banking Group. At Gleacher he focused on middle market corporates, advising clients on in-court and out-of-court restructurings, financings, and M&A transactions. Prior to Gleacher, he was a Senior Associate in GSC Partners' Corporate Credit Group. Mr. Verona started his career in the convertible bond and structured credit groups at Pacific Investment Management Company (PIMCO). He graduated cum laude from the University of California Los Angeles with a degree in Economics. Mr. Verona is a director for lracore International, where he is the Audit Chair, and Unit Corporation, where he serves on the Audit and Compensation Committees.
There are no family relationships among any of our directors or executive officers.
The remainder of the response to this item is contained in the Proxy Statement for our 2021 Annual Meeting of Stockholders and is incorporated herein by reference.

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ITEM 11. EXECUTIVE COMPENSATION
Item 11. Executive Compensation.
The information required by this item will be included in our Proxy Statement for our 2021 Annual Meeting of Stockholders and is incorporated herein by reference.

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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
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 2021 Annual Meeting of Stockholders and is incorporated herein by reference.

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
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 2021 Annual Meeting of Stockholders and is incorporated herein by reference.

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ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
Item 14. Principal Accounting Fees and Services.
The information required by this item will be included in our Proxy Statement for our 2021 Annual Meeting of Stockholders and is incorporated herein by reference.
PART IV

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ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
Item 15. Exhibits, Financial Statement Schedules.
(a)(1) Financial Statements
The consolidated financial statements and related notes, together with the report of BDO USA, LLP, Independent Registered Public Accounting Firm, appear in Part II Item 8. Financial Statements and Supplementary Data of this Form 10-K.
(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.
(a)(3) Exhibits
The Exhibits listed below on the Exhibit Index are filed or incorporated by reference as part of this Form 10-K.
Exhibit Index
Exhibit Number Description Incorporated by Reference Filing
Date Filed/
Furnished
Herewith
Form File No. Exhibit
2.1 Scheme Implementation Agreement, by and between Lonestar Resources US Inc. and Lonestar Resources Limited, executed on December 28, 2015
10-12B 001-37670 2.1 12/31/15
3.1 Amended and Restated Certificate of Incorporation of Lonestar Resources US Inc.
8-K 001-37670 3.1 12/1/20
3.4 Second Amended and Restated Bylaws of Lonestar Resources US Inc.
8-K 001-37670 3.2 12/1/20
4.1 Registration Rights Agreement dated as of November 30, 2020, among Lonestar Resources US Inc. and the holders party thereto.
8-K 001-37670 10.2 12/1/20
4.2 Tranche 1 Warrant Agreement, dated November 30, 2020, by and between Lonestar Resources US Inc., Computershare Inc. and Computershare Trust Company, N.A., as warrant agent.
8-K 001-37670 10.3 12/1/20
4.3 Tranche 2 Warrant Agreement, dated November 30, 2020, by and between Lonestar Resources US Inc., Computershare Inc. and Computershare Trust Company, N.A., as warrant agent.
8-K 001-37670 10.4 12/1/20
4.4 Description of the Registrant's Securities Registered pursuant to Section 12 of the Securities Exchange Act of 1934
8-K 001-37670 10.4 12/1/20
10.1 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
10.2 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
10.3 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
10.4 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
10.5 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-K/A 001-37670 10.7 11/2/18
10.6 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-K/A 001-37670 10.8 11/2/18
10.7 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
10.8 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
10.9 Borrowing Base Redetermination Agreement and Amendment No. 8 to Credit Agreement.
8-K 001-37670 10.1 5/24/18
10.10 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.
10-K/A 001-37670 10.11 11/2/18
10.11 Ninth Amendment and Joinder to Credit Agreement dated November 15, 2018, among Lonestar Resources America Inc., the Guarantors party hereto, Citibank, N.A, as administrative agent and issuing bank, and lenders party thereto.
8-K 001-37670 10.1 11/19/18
10.12†
Lonestar Resources US Inc. Amended and Restated 2016 Incentive Plan, as amended and restated as of May 28, 2019
8-K 001-37670 10.1 5/28/19
10.13 Borrowing Base Redetermination and Tenth Amendment to Credit Agreement
8-K 001-37670 10.1 6/18/19
10.14 Limited Waiver and Eleventh Amendment to Credit Agreement
10-K 001-37670 10.15 4/13/20
10.15 Twelfth Amendment to Credit Agreement
8-K 001-37670 10.1 5/11/20
10.16 Waiver and Thirteenth Amendment to Credit Agreement
8-K 001-37670 10.1 6/17/20
10.17 Forbearance Agreement, Fourteenth Amendment, and Borrowing Base Agreement
10-Q 001-37670 10.3 7/2/20
10.18 Lonestar Resources US. Inc. Change in Control Severance Plan
10-Q 001-37670 10.4 7/2/20
10.19 Lonestar Resources US Inc. Change in Control Severance Plan Eligibility Notification (Executive)
10-Q 001-37670 10.5 7/2/20
10.20 Forbearance Agreement
8-K 001-37670 10.1 8/3/20
10.21 Amendment No. 1 to the Forbearance Agreement, Fourteenth Amendment, and Borrowing Base Agreement
8-K 001-37670 10.2 8/3/20
10.22 Amendment No. 2 to the Forbearance Agreement, Fourteenth Amendment, and Borrowing Base Agreement
8-K 001-37670 10.1 8/21/20
10.23 Restructuring Support Agreement, dated September 14, 2020 by and among the Company, Lonestar Resources America Inc., each other direct and indirect wholly-owned, domestic subsidiary of the Company party thereto and the Consenting Creditors.
8-K 001-37670 10.1 9/14/20
10.24 Joint Prepackaged Plan of Reorganization for Lonestar Resources US Inc. and Its Affiliate Debtors Under Chapter 11 of the Bankruptcy Code.
8-K 001-37670 10.1 11/12/20
10.25 Employment Agreement, dated November 30, 2020, by and between Lonestar Resources US Inc. and Frank D. Bracken, III.
8-K 001-37670 10.5 12/1/20
21.1 List of subsidiaries of Lonestar Resources US Inc.
*
23.1 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 Accounting Officer
*
32.1 Section 1350 Certification of Chief Executive Officer Executive Officer
**
32.2 Section 1350 Certification of Chief Accounting Officer Officer Accounting Officer
**
99.1 Report of W.D. Von Gonten & Co. regarding the Company’s estimated proved reserves as of December 31, 2019, dated February 12, 2020
10-K 001-37670 99.2 4/13/20
99.2 Report of W.D. Von Gonten & Co. regarding the Company’s estimated proved reserves as of December 31, 2020, dated March 22, 2021
*
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.