•the impact of governmental regulation, taxes, market changes and world ~~events.~~

events; and

•global or national health concerns, including health epidemics such as the coronavirus outbreak beginning at the beginning of 2020.

You generally can identify our forward-looking statements by the words “anticipate,” “believe,” budgeted,” “continue,” “could,” “estimate,” “expect,” “forecast,” “goal,” “intend,” “may,” “objective,” “plan,” “potential,” “predict,” “projection,” “scheduled,” “should,” or other similar words. Such statements rely on assumptions and involve risks, uncertainties, and other important factors, many of which are beyond our control, including, but not limited to, those relating to a worldwide economic downturn, availability of financing, our dependence on our exploratory drilling activities, the volatility of and changes in oil and gas prices, the need to replace reserves depleted by production, operating risks of oil and gas operations, our dependence on our key personnel, factors that affect our ability to manage our growth and achieve our business strategy, results, delays and uncertainties that may be encountered in drilling, development or production, interpretations and impact of oil and gas reserve estimation and disclosure requirements, activities and approvals of our partners and parties with whom we have alliances, technological changes, capital requirements, the timing and amount of borrowing base determinations (including determinations by lenders) and availability under our senior secured credit facility, evaluations of us by lenders under our senior secured credit facility, other actions by lenders, the potential impact of government regulations, including current and proposed legislation and regulations related to hydraulic fracturing, oil and natural gas drilling, air emissions and climate change, regulatory determinations, litigation, competition, the uncertainty of reserve information and future net revenue estimates, acquisition risks, availability of equipment and crews, actions by midstream and other industry participants, weather, our ability to obtain permits and licenses, the results of audits and assessments, the failure to obtain certain bank and lease consents, the existence and resolution of title defects, new taxes and impact fees, delays, costs and difficulties relating to our

joint ventures, actions by joint venture parties, results of exploration activities, the availability and completion of land acquisitions, costs of oilfield services, completion and connection of wells, our ability to adhere to our proposed drilling schedule, potential expiration of leases on undeveloped leasehold assets under certain conditions, and other important factors detailed in this annual report.

We have based our forward-looking statements on our management’s beliefs and assumptions based on information available to our management at the time the statements are made. We caution you that assumptions, beliefs, expectations, intentions and projections about future events may and often do vary materially from actual results. Therefore, we cannot assure you that actual results will not differ materially from those expressed or implied by our forward-looking statements.

Some of the important factors that could cause actual results to differ from those expressed or implied in forward-looking statements are described under Part I, ~~“Item~~Item 1A. Risk ~~Factors”~~ Factors and in other sections of this annual report. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual outcomes may vary materially from those indicated. All subsequent written and oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by reference to these risks and uncertainties. You should not place undue reliance on our forward-looking statements. Each forward-looking statement speaks only as of the date of the particular statement, and, except as required by law, we undertake no duty to update or revise any forward-looking statement.

Certain terms used herein relating to the oil and gas industry are defined in ~~“Glossary~~Glossary of Certain Defined ~~Terms”~~Terms included above.

~~Presentation~~

Risk Factors Summary

The following is a summary of ~~Information~~

~~On July 5, 2016, Lonestar Resources US Inc.,~~the principal risks that could adversely affect our business, operations and financial results. Please refer to Item 1A “Risk Factors” of this Form 10-K below for additional discussion of the risks summarized in this Risk Factors Summary.

Risks Related to the Oil and Natural Gas Industry and Our Business

•Oil, natural gas and NGL prices are volatile, and an extended decline in these prices may adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments.

•The current outbreak of COVID-19 has adversely impacted our business, financial condition, liquidity and results of operations and is likely to have a ~~Delaware corporation, acquired~~continuing adverse impact for a significant period of time.

•Our future cash flows and results of operations are highly dependent on our ability to develop additional oil and natural gas resources, which involves high risk activities with many uncertainties.

•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.

•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.

•We may not adhere to our proposed drilling schedule and our identified drilling locations are subject to many uncertainties that could materially alter the occurrence or timing of their drilling.

•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.

•Development of our estimated proved undeveloped reserves, or PUDs, may take longer than expected and may not be ultimately developed or produced. SEC rules could limit our ability to book additional PUDs in the future.

•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.

•Certain of our undeveloped leasehold assets and may not ultimately be developed or become commercially productive and are subject to leases that will expire over the next several years unless production is established or we extend the terms of such leases.

•Our estimated proved reserves are based on many assumptions that may turn out to be inaccurate and any significant inaccuracies in these estimates could materially affect the actual quantities and present value of such reserves.

•We depend upon several significant customers for the sale of most of our crude oil, natural gas and NGL production.

•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.

•We have incurred losses from operations for various periods since our inception and may continue to do so in the future.

•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.

•Our inability to market our crude oil and natural gas could adversely affect our business.

•Increased costs of capital and general economic conditions could adversely affect our business and future growth.

•The crude oil and natural gas industry is intensely competitive and many of our competitors have resources that are greater than ours. In addition, we may not be able to keep pace with technological developments in our industry.

•We may incur losses as a result of title deficiencies.

•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.

Risks Related to Our Financing, Investments and Indebtedness

•Any significant reduction in our borrowing base under the Credit Facility may negatively impact our ability to fund our operations.

•Our hedging transactions expose us to counterparty credit risk and our derivative activities could result in financial losses or reduce our income.

•Our level of indebtedness may increase, reducing our financial flexibility, and the terms of the Credit Facility may restrict our operations, particularly our ability to respond to changes or to take certain actions.

•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.

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.

•Our operations are subject to health, safety and environmental laws and regulations that may expose us to significant costs and liabilities.

•Conservation measures and technological advances could reduce demand for crude oil, natural gas and NGLs.

•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 ~~issued~~water we use economically and ~~outstanding ordinary shares~~in an environmentally safe manner.

•Climate change laws and regulations restricting emissions of ~~Lonestar Resources Limited,~~“greenhouse gases” could result in increased operating costs while the ~~former parent company~~physical effects of climate change could disrupt our production and cause us to incur significant costs.

•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.

Risks Related to Strategic Transactions

•We may be subject to risks in connection with acquisitions, and the integration of significant acquisitions may be difficult.

•We have elected not to be subject to the provisions of Section 203 of the ~~Lonestar group~~Delaware General Corporation Law regulating corporate takeovers.

•Our certificate of ~~companies, pursuant to a Scheme of Arrangement under Australian law that was approved by the Federal Court of Australia on June 28, 2016,~~incorporation and by Lonestar Resources Limited’s shareholders at a meeting of shareholders, which approval was obtained in March 2016 (the “Reorganization”). The purpose of the Reorganization was to reorganize the operations of Lonestar Resources Limited, an Australian corporation, into a structure whereby the ultimate parent company of the Lonestar group of companies would be a Delaware corporation. In connection with the Reorganization, the ordinary shares of Lonestar Resources Limited were delisted from the Australian Securities Exchange, and the Class A common stock of Lonestar Resources US Inc. began trading on the Nasdaq Global Select Market on July 5, 2016 under the ticker symbol “LONE”.

Lonestar Resources America, Inc. (“LRAI”), a subsidiary of Lonestar Resources Limited prior to the Reorganization, has been the U.S. operating company for the Lonestar group of companies since February 2013. Following the Reorganization, LRAI continued in the role of U.S. operating company for Lonestar Resources US Inc.

Unless the context otherwise requires, references to “Lonestar,” “we,” “us,” “our,” and “the Company” refer to (i) Lonestar Resources Limited and its subsidiaries prior to the Reorganization and (ii) Lonestar Resources US Inc. and its subsidiaries upon completion of the Reorganization, as applicable. General information about us can be found on our website at www.lonestarresources.com. The information available on or through our website, or about us on any other website, is neither incorporated into, nor part of, this report. Our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and other filings that we make with the SEC,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.

Risks Related to Our Emergence from Chapter 11 Bankruptcy

•We recently emerged from bankruptcy, which could adversely affect our business and relationships, and the composition of our board of directors changed significantly.

•Our actual financial results after emergence from bankruptcy may not be comparable to our historical financial information as a result of the implementation of the Plan and our adoption of fresh start accounting.

•Our ability to use our net operating loss carryforwards may be limited as a result of our emergence from bankruptcy.

Risks Related to Other General Factors

•The loss of any ~~amendments~~of our key personnel could adversely affect our financial condition, the results of operations and ~~exhibits to those reports, will~~future growth.

•Acts of terrorism could have a material adverse effect on our financial condition, results of operations and cash flows.

•Our business could be ~~available free~~negatively impacted by security threats, including cyber-security threats.

•Our bylaws designate the Court of ~~charge through~~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 ~~website as soon as reasonably practicable after we file or furnish them to the SEC. Information is also available on the SEC website at www.sec.gov for our U.S. filings.~~

stockholders.

~~PAR~~T

PART I

Item 1. Business.

~~Overview~~

~~We are~~

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 ~~company,~~reserves as of December 31, 2020, of which 74% is oil and NGLs. Our operations are focused on the ~~acquisition,~~exploration, development and production of unconventional oil, ~~NGLs~~natural gas liquids and natural gas ~~properties~~ 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 ~~conventional~~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 ~~on Eagle Ford acreage,~~cuts. Uncertainty about the ~~“Eagle Ford”), where~~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 ~~78,197~~72,529 gross ~~(58,262~~(52,861 net) acres ~~in what we believe to be the formation’s crude oil and condensate windows~~ as of December 31, ~~2017.~~2020 (Successor). We operate in one industry segment, which is the exploration, development and production of oil, ~~NGLs~~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, ~~2017,~~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, ~~2017,~~2020 (Successor), we operated ~~81%~~97% of our Eagle Ford position and approximately ~~89%~~94% of our net acreage was held by production, or HBP. Third-party engineers have identified ~~254~~240 gross ~~(187~~(135 net) horizontal drilling locations on our Eagle Ford acreage.

We currently plan to invest the majority of our ~~2018~~2021 capital budget in the horizontal development of our Eagle Ford properties and have allocated between ~~$95~~$45 million and ~~$100~~$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 ~~7,000~~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, ~~2017:~~

Gross

Net

Average
Working

Identified
Drilling
Locations
(1)(2)

Producing
Wells

Average
Daily
Production

Capex

Planned Wells
(Net) (3)

Acreage

Acreage

Interest

Gross

Net

Gross

Net

Boe/d

2018

2018
Eagle Ford

Western

16,635

14,904

90%

49

46

59

55

3,453

34%

4
Central

47,273

33,065

70%

173

125

151

113

2,394

66%

11
Eastern

14,289

10,293

72%

32

16

28

17

648

0%

0
Total

78,197

58,262

75%

254

187

238

185

6,495

100%

15

~~(1)~~

Potential drilling locations are identified based on analysis of relevant geologic and engineering data. Our total identified drilling locations include 170 gross (141 net) locations that were associated with proved undeveloped reserves, or PUDs, as of December 31, 2017. The remaining drilling locations were not associated with proved reserves as of December 31, 2017, however, based on our analysis of our drilling results, the drilling results of offset operators and applicable geologic and engineering data, we believe these locations are prospective for development.

2020 (Successor):

~~(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.


	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) 2021
				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

~~(3)~~

~~Planned Wells (Net) represents our optimal planned drilling results based on our currently budgeted capital expenditures.~~

(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, ~~2017:~~

2020 (Successor):

	Oil Wells				Gas Wells				Total
	Producing Wells				Producing Wells				Producing Wells					Oil Producing Wells		Gas Producing Wells		Total Producing Wells
	Gross		Net		Gross		Net		Gross		Net			Gross	Net	Gross	Net	Gross	Net
Eagle Ford													Eagle Ford
Western		55		53		4		2		59		55	Western	51	49	14	13	65	61
Central		151		113	—		—			151		113	Central	166	118	20	19	186	138
Eastern		28		17	—		—			28		17	Eastern	14	9	—	—	14	9
Total		234		183		4		2		238		185	Total	231	176	34	32	265	208

Our Properties

Our Eagle Ford ~~Shale Properties~~

~~Our Eagle Ford area~~ net production for the year ended December 31, ~~2017~~2020 was ~~6,495 Boe/~~13,587 BOE/d, comprised of ~~4,328~~6,713 Bbls/d of oil, ~~1,069~~3,142 Bbls/d of NGLs and ~~6,588~~22,393 Mcf/d of natural gas, from ~~238~~265 gross ~~(184.7~~(208 net) producing wells.

~~In June 2017, we significantly expanded our operations in~~ For the Central Eagle Ford Shale by acquiring oil and gas properties in Karnes, Gonzales, DeWitt, Lavaca and Fayette Counties, Texas in two separate transactions for $116.6 million. The acquisitions included approximately 30,219 gross acres (21,238eleven months ended November 30, 2020 (Predecessor), net ~~acres) and 1,763 Boe/~~production was 13,744 BOE/d, comprised of 6,772 Bbls/d of ~~production from acquisition date to~~oil, 3,169 Bbls/d of NGLs and 22,816 Mcf/d of natural gas. For the one month ended December 31, ~~2017. At~~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 ~~time we completed the acquisitions, our net acreage increased by 59% to~~closing date and were producing approximately ~~57,172 net acres.~~

200 BOE/d.

As of December 31, ~~2017,~~2020 (Successor), according to our reserve report, our Eagle Ford properties had proved reserves of ~~73.6 MMBoe,~~79.2 MMBOE, of which ~~84%~~74% was crude oil and NGLs and ~~25%~~37% was proved developed producing, or PDP. The ~~Standard~~Standardized Measure of our ~~Eagle Ford~~ proved reserves as of December 31, ~~2017~~2020 was ~~$479.6~~$330.3 million, and the PV-10(1) of our ~~Eagle Ford~~ proved reserves as of December 31, ~~2017~~2020 (Successor) was ~~$538.3~~$366.0 million using SEC pricing, and ~~44% of such PV-10 was PDP. The PV-10 of our Eagle Ford proved reserves as of December 31, 2017 was $647.6 million using NYMEX strip pricing, and 42%~~61% of such PV-10 was PDP. See ~~“Summary Historical Reserve~~Oil and ~~Operating Data”.~~

Natural Gas Data below for more information.

Third-party engineers have identified ~~254~~240 gross ~~(187~~(134 net) horizontal drilling locations on our acreage, of which ~~61%~~66% are expected to be drilled using lateral lengths of or greater than 7,000 feet and ~~95%~~31% are expected to be drilled using lateral lengths of or greater than ~~5,000~~10,000 feet.

Western Eagle Ford. As of December 31, ~~2017,~~2020 (Successor), our Western Eagle Ford region was comprised of ~~16,634~~16,761 gross ~~(14,904~~(14,770 net) acres in Dimmit, La Salle and Frio Counties. As of December 31, ~~2017,~~2020 (Successor), we operated 100% of this acreage, and approximately ~~96%~~89% of this net acreage was HBP. We plan on allocating ~~34%~~62% of our ~~2018~~2021 capital budget to our Western Eagle Ford acreage.

Central Eagle Ford. Our Central Eagle Ford region, as of December 31, ~~2017,~~2020 (Successor), was comprised of ~~47,273~~45,998 gross ~~(33,065~~(31,591 net) acres in Gonzales, Karnes, Fayette and Wilson Counties. As of December 31, ~~2017,~~2020 (Successor), we operated ~~100%~~90% of this acreage, and approximately 95% of this net acreage was HBP. We plan on allocating ~~66%~~38% of our ~~2018~~2021 capital budget to this area.

Eastern Eagle Ford. Our Eastern Eagle Ford region, as of December 31, ~~2017,~~2020 (Successor), was comprised of ~~14,288~~9,770 gross ~~(10,293~~(6,500 net) acres in Brazos and Robertson Counties. ~~Approximately 61%~~100% of this net acreage was HBP, and as of December 31, ~~2017,~~2020 (Successor), we operated ~~100%~~97% of this acreage. We do not plan on allocating any of our ~~2018~~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~~Oil and Natural Gas Data—~~PV-10”~~ PV-10 below for more information and a reconciliation of PV-10 to our Standardized Measure.

~~Non-Core Properties~~

We have historically maintained conventional oil and natural gas properties located in 13 counties in Texas, including long-lived reserves in the Canyon, Delaware Sand, Hackberry, Caddo, Cockfield and Jackson formations. For the year ended December 31, 2016, production from our conventional assets averaged 404 Boe/d which represented 7% of our total net reported production for the year. Consistent with our plan to divest non-core assets and reduce our outstanding indebtedness, on June 15, 2016, we sold a portion of these assets for $2.2 million. On September 26, 2016, we entered into an agreement to sell the remaining assets for $14.0 million, and this transaction closed on October 31, 2016.

Business Strategies

Our primary business objective is to increase reserves, production and cash flows at attractive rates of return on invested capital. We are focused on exploiting long-lived, unconventional oil, NGLs and natural gas reserves from the ~~crude oil window of the~~ Eagle Ford ~~Shale.~~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, ~~2017,~~2020 (Successor), we were producing from ~~238~~265 gross ~~(184.7~~(208 net) Eagle Ford wells and we intend to deploy all our capital budget for ~~2018~~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. For example, in the past we have executed on this strategy through our Joint Development Agreement with IOG Capital L.P. (‘‘IOG’’). This agreement allowed for working interest-level participation with IOG participating on a promoted basis for funding farm-ins. This was a wellbore-only agreement that allowed us to develop acreage or hold expiring acreage while maintaining some upside through a specified return hurdle earn-in and all of the upside associated with future development of offsetting wells.

•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 ~~81%~~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 ~~use cash on hand and borrowings~~execute a capital program which is funded from ~~our revolving credit facility, combined with our~~ cash flow from operations ~~to continue executing a capital expenditure program that we believe will help us achieve steady growth of production,~~while generating meaningful free cash flow ~~and proved reserves.~~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 ~~predicable~~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 ~~approximately 58,262~~52,861 net acres in the Eagle Ford as of December 31, ~~2017. We believe this unconventional~~2020 (Successor). Our production has access to expansive pipeline transportation infrastructure which allows us to sell our crude oil, NGL’s and natural gas ~~formation has~~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 ~~almost~~ all of our ~~2018~~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 ~~fifteen~~fourteen times, from 3,710 net acres in 2011 (Predecessor) to ~~58,262~~52,861 net acres as of December 31, ~~2017.~~2020 (Successor). We placed 1210 gross ~~(11.3~~(8.4 net) and 517 gross ~~(3.7~~(15.7 net) Eagle Ford wells onstream during ~~2017~~2020 and ~~2016,~~2019, respectively. We had a total of ~~238~~265 gross ~~(184.7~~(208 net) producing wells in the Eagle Ford, ~~Shale,~~ as of December 31, ~~2017.~~2020 (Successor). Our average total production for ~~2017~~2020 was ~~6,495 Boe/~~13,587 BOE/d, all of which ~~100%~~ was from the Eagle Ford. Between December 31, 2016 and December 31, 2017, our total proved reserves increased by approximately 33.1 MMBoe, from 40.5 MMBoe to 73.6 MMBoe. Our proved developed reserves increased by approximately 7.3 MMBoe, from 11.0 MMBoe to 18.3 MMBoe. Our five-year average reserve replacement ratio is approximately 778%, which we believe demonstrates our ability to grow reserves year over year. We believe the location and concentration of our project areas within the Eagle Ford provide us an opportunity to continue to increase production, lower costs and further delineate our proved reserves.

•Demonstrated ability to adapt and employ leading drilling and completion techniques. We are focused on enhancing our drilling, completion and production techniques to maximize recovery of hydrocarbons. Industry techniques, with respect to drilling and completion, have significantly evolved over the past several years, resulting in increased initial production rates and recoverable hydrocarbons per well through the implementation of longer laterals and more tightly-spaced fracture stimulation stages. We continuously evaluate industry results and methods and monitor the results of other operators to improve our operating practices, and we expect that our drilling and completion techniques will continue to improve and evolve. We have demonstrated a track record of innovation and operational improvement in the past through our partnership with Schlumberger, the Geo-Engineered Completion Alliance (“GECA”)~~, which terminated during the first quarter of 2017.~~. This Alliance utilized a variety of technologies intended to focus our wells in precise, optimal intervals of the Eagle Ford and utilize analysis of advanced logs run through the laterals to assist in the design of non-geometric fracture stimulation stages, which in combination with diverters, were intended to stimulate a greater percentage of the lateral on a cost-effective basis. We continue to use these technologies which can be provided by several energy service companies.

•Multi-year drilling inventory in existing and emerging resource plays. Third-party engineers have identified ~~254~~240 gross ~~(187~~(134 net) horizontal drilling locations on our Eagle Ford acreage. As of December 31, ~~2017,~~2020 (Successor), these identified drilling locations included ~~170~~117 gross ~~(141~~(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.

~~Oil-weighted reserves~~•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 ~~production. Our net proved reserves at December 31, 2017 were comprised of approximately 69% oil, and our net average daily production for the year~~month ended December 31, ~~2017~~2020 (Successor), our total field operating expenses (including lease operating' gas gathering, processing and ~~2016 was comprised of 67% oil~~transportation; production taxes and ~~55% oil, respectively. Given the current commodity price environment~~ad valorem taxes) totaled $6.90 and ~~resulting disparity between oil and natural gas prices on a Boe basis, we believe~~$7.19 per BOE, respectively, in our ~~high percentage of oil reserves, compared to our overall reserve base, is a key strength.~~

•

~~Low field operating expenses~~. Even in light of low oil prices, we expect to generate sufficient cash margins on the operation of our Eagle Ford acreage due to our low cash operating costs. For the year ended December 31, 2017, our total field operating expenses (including lease operating expenses per Boe of $7.07 and production taxes of $2.33 per Boe) totaled $9.40 per Boe in our project areas.

project areas.

•Hedging ~~position~~.position. As of ~~December 31, 2017,~~March 29, 2021 (Successor), we had oil derivative contracts in place ~~hedges~~for 2021 covering approximately ~~4,695~~5,255 Bbls/d ~~for 2018~~ at an average price of ~~approximately $52.64~~$45.17 per Bbl. This includes a two-way collar with an effective floor and ceiling of $50.00 and $59.45, respectively. We believe that these hedges help insulate us from oil price volatility on approximately 70% of our expected crude oil production in 2018. In addition, we currently have oil derivative contracts in place ~~additional hedges~~ for ~~2019 and 2020. Our 2019 hedges cover approximately 4,030~~2022 consisting of 3,062 Bbls/d ~~for calendar year 2019~~ at ~~a volume-weighted~~an average price of ~~approximately $49.64~~$47.03 per Bbl. ~~Our 2020~~As of March 29, 2021 (Successor), we also had derivative ~~contracts consist of 1,119 Bbls/d through June at a price of $48.90 per Bbl. Additionally, we have also entered into~~ contracts to hedge our ~~2018~~2021 natural gas production covering ~~5,000~~13,251 MMBtu/d at a weighted average price of ~~$3.09~~$3.02 per MMBtu.

In ~~January 2018,~~addition, we ~~entered into additional WTI swaps covering 2018, 2019, and 2020. The 2018 WTI swaps cover~~currently have natural gas derivative contracts in place for 2022 consisting of 6,233 MMBtu/d at a ~~total of 230,700 barrels for the period of March 2018 through December 2018 at an~~weighted average ~~strike~~ price of ~~$61.77. The addition of~~$2.77 per MMBtu. We believe that these ~~swaps increased~~hedges help mitigate our ~~total 2018 crude~~exposure to oil ~~hedge position coverage to a total of approximately 5,326 Bbls/d at an average strike~~and natural gas price of $53.72 per barrel. The 2019 WTI swaps cover a total of 328,500 barrels for the period of January 2019 through December 2019 at an average strike price of $58.25. These additional 2019 swaps increased our total 2019 crude oil hedge position coverage to a total of approximately 4,930 Bbls/d at an average strike price of $51.21. The 2020 WTI swaps cover a total of 411,200 barrels for the period of January 2020 through December 2020 at an average strike price of $55.06. These additional 2020 swaps increased our total 2020 crude oil hedge position coverage to a total of approximately 1,680 Bbls/d at an average strike price of $53.02.

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, ~~2017~~2020 (Successor) and ~~2016.~~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.

As of December 31,

2017

2016

Estimated Proved Reserves (1)

Eagle Ford Shale:

Oil (MBbls)

50,701

24,288

NGLs (MBbls)

10,875

7,466

Natural Gas (MMcf)

71,874

52,714

Total Estimated Proved Reserves (MBoe) (2)

73,555

40,540

Estimated Proved Developed Reserves

Eagle Ford Shale:

Oil (MBbls)

12,657

6,268

NGLs (MBbls)

2,846

2,274

Natural Gas (MMcf)

17,034

14,734

Total Estimated Proved Developed Reserves
(MBoe)(2)

18,342

10,998

Estimated Proved Undeveloped Reserves

Eagle Ford Shale:

Oil (MBbls)

38,044

18,021

NGLs (MBbls)

8,029

5,191

Natural Gas (MMcf)

54,840

37,980

Total Estimated Proved Undeveloped Reserves
(MBoe)(2)

55,213

29,542

Standardized Measure (millions) (3)

$
479.6

$
145.8

PV-10 (millions)(4)

$
538.3

$
166.5

Oil and Gas Prices Used (1) :

Oil — NYMEX-WTI per Bbl

$
51.34

$
42.75

Natural Gas — NYMEX-Henry Hub per MMBtu

2.98

2.46

~~(1)~~

Our estimated net proved reserves and related Standardized Measure were determined using index prices for crude oil and natural gas, without giving effect to commodity derivative contracts, held constant throughout the life of our properties. The prices are based on the average prices during the 12-month period prior to the ending date of the period covered, determined as the unweighted arithmetic average of the prices in effect on the first day of the month for each month within such period, unless prices were defined by contractual arrangements, and are adjusted, by lease, for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price realized at the wellhead. NGL pricing used as approximately 30% of corresponding crude oil prices.

~~(2)~~

One Boe is equal to six Mcf of natural gas or one Bbl of oil or NGLs based on an industry-standard approximate energy equivalency. This is a physical correlation and does not reflect a value or price relationship between the commodities.


	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

~~(3)~~

~~Standardized Measure is calculated in accordance with Accounting Standards Codification (“ASC”) Topic 932, Extractive Activities — Oil and Gas.~~

~~(4)~~

PV-10 is a non-GAAP financial measure and represents the present value of estimated future cash inflows from proved crude oil and natural gas reserves, less future development and production costs, discounted at 10% per annum to reflect timing of future cash inflows and using the unweighted arithmetic average of the first-day-of-the-month price for each of the preceding twelve months. PV-10 differs from the Standardized Measure because it does not include the effect of future income taxes. See below for a reconciliation of Standardized Measure to our PV-10.

(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:


	December 31,					Successor		Predecessor
In millions	2017		2016		In millions	December 31, 2020		December 31, 2019
Standardized measure of discounted future net cash flows	$	479.6	$	145.8
Standardized measure of discounted future net cash flows (GAAP measure)					Standardized measure of discounted future net cash flows (GAAP measure)	$	330.3	$	738.8
Discounted estimated future income taxes		58.7		20.7	Discounted estimated future income taxes	35.7		95.4
PV-10	$	538.3	$	166.5
PV-10 (Non-GAAP measure)					PV-10 (Non-GAAP measure)	$	366.0	$	834.2

Reconciliation of Proved Reserves

Our proved developed oil and natural gas reserves ~~increased~~decreased from ~~11.0 MMBoe~~33.0 MMBOE at December 31, ~~2016,~~2019 (Predecessor), to ~~18.3 MMBoe~~29.7 MMBOE at December 31, ~~2017,~~2020 (Successor), primarily due production and revisions to ~~production additions associated with~~prior estimates partially offset by the ~~$116.6 million acquisitions~~conversion of ~~producing properties that closed June 15, 2017,~~proved undeveloped to proved developed through our drilling program, which ~~added an additional 81~~brought 10 gross ~~(75.2 net) wells. During the year, we converted 2.0 MMBoe of Proved Undeveloped reserves to the Proved Developed Producing category~~wells online during 2020 and added ~~1.0 MMBoe through drilling on new properties, while producing 2.4 MMBoe during the year ended December 31, 2017.~~3.9 MMBOE of proved reserves. Our proved developed oil and natural gas reserves experienced negative revisions of ~~0.1 MMBoe~~2.1 MMBOE primarily due to ~~the increase in~~reductions caused by lower SEC pricing.


		Proved Developed Reserves ~~(Mboe)~~			(MBOE)
As of December 31, ~~2016~~ 2019 (Predecessor)		33,012			~~10,998~~
Extensions and ~~Discoveries~~ discoveries		—			~~974~~
~~Purchases of minerals in place~~				~~6,637~~
~~Sales of reserves in place~~		—
~~Revisions of prior estimates~~		~~112~~
~~Production~~		~~(2,360~~	)
Conversion of proved undeveloped to proved developed	3,872		~~1,981~~
Sales of minerals in place		(134)
Revisions of prior estimates		(2,091)
Production		(4,973)
As of December 31, ~~2017~~ 2020 (Successor)		29,686			~~18,342~~

Development of Proved Undeveloped Reserves

At December 31, ~~2017,~~2020 (Successor), our proved undeveloped reserves were approximately ~~55,213 MBoe,~~49.5 MMBOE, an ~~increase~~decrease of approximately ~~25,671 MBoe over~~18.1 MMBOE from our December 31, ~~2016~~2019 (Predecessor) estimated proved undeveloped reserves of approximately ~~29,542 MBoe.~~67.6 MMBOE. In ~~2017,~~2020, we added ~~net~~ proved undeveloped reserves of ~~3,046 MBoe~~6.0 MMBOE as a result of drilling and completion activities, ~~and 23,210 MBoe as a result of the acquisition~~approximately 3.9 MMBOE of proved undeveloped ~~reserves. During 2017, approximately 1,981 MBoe of proved undeveloped~~ reserves ~~as of December 31, 2016,~~ were converted to proved developed reserves as a result of drilling and completion activities during the year and ~~1,396 MBoe~~19.2 MMBOE of reserves were ~~added to~~removed from our proved undeveloped reserves as a result of revisions in estimates from ~~2016.~~2019. Revisions of previous estimates were ~~added~~ primarily cause by the reclassification of wells due to the ~~increase~~decrease in SEC pricing.

All PUD drilling locations are scheduled to be drilled prior to the end of 2022. Over half of our current PUD locations were acquired or developed during 2017, and approximately half of the future development costs associated with our PUDs are anticipated to be incurred the last two years of our five-year development plan.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)~~			(MBOE)
As of December 31, ~~2016~~ 2019 (Predecessor)		67,636			~~29,542~~
Extensions and Discoveries		6,016			~~3,046~~
~~Purchases of minerals in place~~				~~23,210~~
~~Sales of minerals in place~~		—
~~Revisions of prior estimates~~		~~1,396~~
Conversion of proved undeveloped to proved developed	(3,872)		~~(1,981~~	)
Sales of minerals in place		(1,076)
Revisions to prior estimates		(19,166)
As of December 31, ~~2017~~ 2020 (Successor)		49,538			~~55,213~~

Qualifications of Responsible Technical Persons

Internal Company Person.Thomas H. Olle, our Vice President-Reservoir Engineering, is the technical person primarily responsible for overseeing the preparation of our reserve estimates. Mr. Olle is also responsible for our interactions with and oversight of our independent third-party reserve engineers. Mr. Olle has more than 40 years of industry experience, with expertise in reservoir management and project development across a broad range of reservoir types. Mr. Olle previously held senior positions at Encore Acquisition Corp. and Burlington Resources. He holds a Bachelor of Science degree in Mechanical Engineering with Highest Honors from the University of Texas at Austin and is a member of the Society of Petroleum Engineers.

Independent Reserve Engineers.W.D. Von Gonten & Co. is an independent petroleum engineering and geological services firm. No director, officer or key employee of W.D. Von Gonten & Co. has any financial ownership in Lonestar. W.D. Von Gonten & Co.’s compensation for the required investigations and preparation of its report is not contingent upon the results obtained and reported, and W.D. Von Gonten & Co. has not performed other work for us or our affiliates that would affect its objectivity. The engineering information presented in W.D. Von Gonten & Co.’s reports was overseen by William D. Von Gonten, Jr., P.E. Mr. Von Gonten is an experienced reservoir engineer having been a practicing petroleum engineer since 1990. He has a Bachelor of Science degree in Petroleum Engineering from Texas A&M University and is a licensed Professional Engineer in the State of Texas.

Technology Used To Establish Proved Reserves

Our independent reserve engineers follow SEC rules and definitions in preparing their reserve estimates. Under SEC rules, proved reserves are those quantities of oil and natural gas that by analysis of geological, geochemical and engineering data can be estimated with reasonable certainty to be economically producible from a given date forward from known reservoirs, and under existing economic conditions, operating methods and government regulations. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil and natural gas actually recovered will equal or exceed the estimate. Reasonable certainty can be established using techniques that have been proven effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

To establish reasonable certainty with respect to our estimated proved reserves, our independent reserve engineers employed technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used in the estimation of our reserves include electrical logs, radioactivity logs, core ~~analyses,~~analysis, geologic maps and available ~~downhole~~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, ~~2017~~2020 (Successor) and ~~2016 for the Eagle Ford properties~~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, ~~our~~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, for the years ended December 31, 2017 and 2016.~~

properties:

Year ended December 31,



2017

2016

Production

   Oil (Bbls/day):

      Western Eagle Ford

1,873

2,069

      Central Eagle Ford

2,104

658

      Eastern Eagle Ford

351

279

   Total Eagle Ford

4,328

3,006

      Conventional assets

—

248

      Total Oil

4,328

3,254

   Natural Gas Liquids (Bbls/day):

      Western Eagle Ford

739

1,080

      Central Eagle Ford

166

24

      Eastern Eagle Ford

164

57

   Total Eagle Ford

1,069

1,161

      Conventional assets

—

5

      Total Natural Gas Liquids

1,069

1,166

   Natural Gas (Mcf/day):

      Western Eagle Ford

5,046

7,561

      Central Eagle Ford

749

139

      Eastern Eagle Ford

793

267

   Total Eagle Ford

6,588

7,967

      Conventional assets

—

905

      Total Natural Gas

6,588

8,872

   Average daily production (Boe/d)

6,495

5,899

   Average Daily Sales Price:

      Oil ($/Bbl)

$
50.96

$
39.43

   Natural Gas Liquids ($/Bbl)

18.48

9.03

      Natural Gas ($/Mcf)

2.73

2.21

   Average Unit Cost ($/Boe):

      Lease operating expenses

$
7.07

$
7.52

      Production taxes

2.33

1.52

      Depreciation, depletion and amortization

22.30

21.80


	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, ~~2017~~2020 and ~~2016. In the table, “gross” refers to the total wells in which we have a working interest and “net” refers to gross wells multiplied by our working interest therein.~~

Year ended December 31,

2017

2016

Gross

Net

Gross

Net

Development Wells:

Productive

12.0

11.3

5.0

3.8

Dry

—

—

—

—

Exploratory Wells:

Productive

—

—

—

—

Dry

—

—

—

—

Total Wells:

Productive

12.0

11.3

5.0

3.8

Dry

—

—

—

—

2019. As of December 31, ~~2017,~~2020, we ~~were in process of drilling 2 gross (2.0 net)~~had three wells that ~~are not included in the table above.~~

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 ~~Data~~

The following table sets forth ~~information relating to~~ our ~~leasehold~~ acreage ~~in the Eagle Ford. As of December 31, 2017, approximately 89% of our net Eagle Ford acreage was held by production.~~

As of December 31, 2017

Developed Acreage

Undeveloped Acreage

Total Acreage

Gross

Net

Gross

Net

Gross

Net

Western Region

6,385

6,032

10,249

8,872

16,634

14,904

Central Region

13,460

9,948

33,813

23,117

47,273

33,065

Eastern Region

1,393

951

12,896

9,342

14,289

10,293

Total Eagle Ford

21,238

16,931

56,958

41,331

78,196

58,262

As of December 31, 2017, we had leases across the Eagle Ford representing 1,476 net acres expiring in 2018, 803 net acres expiring in 2019, and 841 net acres expiring in 2020 and beyond. We anticipate that our current and future drilling plans, together with selected lease extensions, will address a significant portion of our leases expiringposition 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 ~~2018.~~

~~Operations~~

2021, 4% (1,216 acres) in 2022 and 5% (1,559 acres) in 2023.

General

We operate ~~81%~~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, ~~2017, purchases by our largest five customers~~2019 (Predecessor), six purchasers accounted for ~~35%, 20%, 16%, 14%, and~~ 10%, or more of our ~~total revenues.~~

~~Since the~~ oil and natural gas ~~that we sell are commodities for which there are a large number of potential buyers,~~revenues: Shell Trading (US) Company (23%), Texla Energy Management (17%), Enterprise Crude Oil LLC (16%), Ace Gathering, Inc. (14%), GulfMark Energy, Inc. (13%) and ~~because of the adequacy of the infrastructure~~NGL Crude Logistics LLC (10%).

Our ability to ~~transport~~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 ~~areas in which we operate, if we were to lose one or more customers, we believe~~demand for oil and natural gas, the effects of weather, and the effects of state and federal regulation. There is no assurance that we ~~could readily procure substitute or additional customers such that~~will always be able to market all of our production ~~volumes would not be materially affected for any significant period of time.~~

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, ~~Anadarko Petroleum Corporation,~~ Chesapeake Energy Corporation, EP Energy Corporation, ~~Carrizo~~EOG Resources, Inc., Magnolia Oil & Gas ~~Inc., Hunt Oil Company,~~Corporation, Marathon Oil Corporation, ~~Newfield Exploration Company~~SilverBow Resources, Inc. Penn Virginia Corporation and ~~Stonegate Production Company.~~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 ~~19.0%~~20.0% to 25.0% resulting in a net revenue interest to us ranging from 75.0% to ~~81.0%~~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 ~~rateability~~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 ~~will be~~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 ~~rate-making, market- based~~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 ~~determinations~~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, ~~and, depending on the scope of that decision,~~ our costs of getting gas to point of sale locations may increase. State regulation of natural gas gathering facilities generally includes various safety, environmental and, in some circumstances, non-discriminatory take requirements. Although such regulation has not generally been affirmatively applied by state agencies, natural gas gathering may receive greater regulatory scrutiny in the future.

Intrastate natural gas transportation and facilities are also subject to regulation by state regulatory agencies, and certain transportation services provided by intrastate pipelines are also regulated by FERC. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services vary from state to state. Insofar as such regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable basis, we believe that the regulation of similarly situated intrastate natural gas transportation in any states in which we operate and ship natural gas on an intrastate basis will not affect our operations in any way that is of material difference from those of our competitors. Like the regulation of interstate transportation rates, the regulation of intrastate transportation rates affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas.

Regulation of Environmental and Occupational Safety and Health Matters

Our exploration, development, production and processing operations are subject to various federal, state and local laws and regulations relating to health and safety, the discharge of materials 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.

~~Responsible persons~~

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 ~~“responsible persons”~~“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 iswas 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. IfAfter undertaking its review, the EPA ~~proposes~~signed a ~~rulemaking for revised~~determination in 2019 concluding that it does not need to regulate oil and ~~as waste regulations,~~gas exploration and production wastes, and specifically “drilling fluids, produced waters, and other wastes associated with the ~~Consent Decree requires that~~exploration, development or production of oil, gas or geothermal energy,” because the ~~EPA take final action following notice and comment rulemaking no later than July 15, 2021. A~~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~~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~~“waters of the United States but this rule was stayed nationwide by the U.S. Sixth Circuit Court of Appeals as that appellate court and several other district courts ponder lawsuits opposing implementation of the rule. In January 2017, the U.S. Supreme Court accepted review of the rule to determine whether jurisdiction rests with the federal district or appellate courts. On March 6, 2017, the U.S. Department of Justice filed a motion with the U.S. Supreme Court requesting the Court to stay the suit regarding which courts should hear challenges to this rule.States” (the “WOTUS Rule”). In November 2017, the EPA and the Army Corps of Engineers issued a notice to rescind the ~~Clean Water~~WOTUS Rule and re-codify the regulatory text that existed prior to 2015 defining “water of the United States.” ~~On January 22, 2018, the U.S. Supreme Court unanimously held that challenges to the 2015 rules could only be raised in federal district courts and remanded and the case back to U.S. District Courts.~~ The EPA and the Army Corps of Engineers ~~then~~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 ~~stay~~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 ~~rule’s effective date until February 6, 2020 and~~pollutants through groundwater is the ~~U.S. District Court for North Dakota, covering 13 states, issued~~“functional equivalent” of a ~~stay that~~direct discharge from the point source into navigable waters. As such, uncertainty remains ~~in effect. Litigation is ongoing challenging~~with respect to the ~~actions~~scope of the ~~EPA and~~federal government’s jurisdiction under the ~~Army Corps of Engineers and at this time, it is unclear what impact these actions will have on the implementation of the 2015 rule.~~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. ~~Several states~~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 ~~filed suit before~~separately challenged both the ~~D.C. Circuit challenging~~original 2016 Subpart OOOOa standards and the EPA’s attempts to delay the implementation of the methane rule and legal authority to issue the methane rules. On June 12, 2017, EPA proposed a two year stay of the fugitive emissions, pneumatic pump and professional engineer certification requirements in the methane rule while the agency reconsiders the rule. In May 2016, the EPA also announced its intention to impose methane emission standards for existing sources, and in February 2018, new standards for methane emission from oil and gas wells were proposed by the Trump ~~Administration, currently subject~~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 ~~60-day comment period.~~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 ~~a final~~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 ~~rule is expected in 2018.~~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. This will heighten political pressure on the United States to ensure continued compliance with enforcement measures resulting from the Clean Air Act and to bring forward further actions to reduce GHGs in the period post 2030. On October 4, 2016, the E.U. ratified the Paris Agreement, thus meeting the threshold for the agreement to come into force. On June 1, 2017, President Trump announced that the United States planned to withdraw from the Paris Agreement and to seek negotiations either to reenter the Paris Agreement on different terms or establish a new framework agreement. ~~The Paris Agreement provides for a four-year exit~~President Trump formally initiated the withdrawal process ~~beginning when it took effect~~ in November ~~2016,~~2019, which ~~would result~~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 ~~United States’ adherence to the exit process is uncertain and/or the terms on which the United States may reenter~~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 ~~separately negotiated agreement~~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 ~~unclear at this time.~~

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. ~~While new legislation requiring GHG controls is not expected at the national level in the near term,~~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 ~~federal Energy Policy Act of 2005~~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”) ~~had~~ developed comprehensive regulations for hydraulic fracturing on federal land in 2015 that were subject to extensive litigation ~~challenges and in~~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 ~~2017,~~2020, nor do we anticipate that such expenditures will be material in ~~2018.~~

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, ~~2017,~~2020 (Successor), we had 5075 employees, including ~~seven~~14 engineers and geoscientists, ~~four~~11 land professionals and ~~ten~~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 ~~contract~~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 ~~services~~professional growth and advancement based on merit. Our Code of ~~independent consultants involved~~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 ~~land, engineering, regulatory, accounting, financial~~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 ~~disciplines as needed.~~

~~Formation Transactions~~

~~Lonestar Resources US Inc. was incorporated Delaware in December 2015 for purposes~~employment decisions based on job and business-related criteria. We evaluate ways to enhance awareness of effecting our corporate reorganization, which was completed in July 5, 2016 (the “Reorganization”), pursuant to a Scheme Implementation Agreement (the “Scheme”), dated December 28, 2015, between the Company and ~~Lonestar Resources Limited (our “Predecessor”),~~promote diversity and inclusion on an ~~Australian company and our former parent company.~~

Prior to the Reorganization, our business was owned and operated under our Predecessor, whose ordinary shares were listed on the Australian Securities Exchange (“ASX”). Pursuant to the Scheme, the Company acquired all of the issued and outstanding ordinary shares of our Predecessor, and each of our Predecessor’s shareholders received one share of our Class A common stock for every two ordinary shares of our Predecessor such shareholder held.

In connection with the Reorganization, we filed a registration statement on Form 10 (“Form 10”) to register our Class A common stock pursuant to Section 12(b) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). Following the effectiveness of the registration statement and in connection with the completion of the Reorganization, the ordinary shares of our Predecessor were delisted from the ASX, and our Class A common stock was listed on the Nasdaq Global Select Market (“Nasdaq”).

~~Recent Events~~

~~Eagle Ford Acquisitions~~

In June 2017, we completed two acquisitions of oil and natural gas properties in the Central Eagle Ford with Battlecat Oil & Gas, LLC (“Battlecat”) and SN Marquis LLC (“Marquis”), which included approximately 30,219 gross acres (21,238 net acres) and 1,763 Boe/d of production from acquisition date to December 31, 2017. At the time we completed the acquisitions, our net acreage increased by 59% to approximately 57,172 net acres. Consideration for the acquisitions, after closing adjustments, consisted of $99 million in cash and approximately 2.7 million shares of the Company’s newly issued Series B Preferred Stock valued at $11.6 million (see below).

ongoing basis.

~~Acquisition Financing Transactions~~

In June 2017, in connection with the acquisitions noted above, we issued 5,400 shares of Series A-1 Convertible Participating Preferred Stock (“Series A-1 Preferred Stock”) and 74,600 shares of Series A-2 Convertible Participating Preferred Stock (“Series A-2 Preferred Stock”) to Chambers Energy Capital (“Chambers”) for proceeds of $80.0 million. Also, on June 15, 2017, in connection with the acquisitions, we issued 1,184,632 and 1,500,000 shares of Series B Preferred Stock as part of the consideration paid.

Pursuant to the terms of our agreement with Chambers, we held a stockholder meeting in November 2017, and obtained at the meeting stockholder approval for issuance of shares of the Company’s Class A voting common stock for conversion of all shares of Series A-1 Preferred Stock and Series A-2 Preferred Stock (upon their conversion to shares of Series A-1 Preferred Stock). As a result of the stockholder approval, all outstanding Series A-2 Preferred Stock was converted to Series A-1 Preferred Stock. Also, in November 2017, in accordance with the terms of the Series B Preferred Stock Certificate of Designations, all of the outstanding shares of the Company’s Series B Preferred Stock were converted on a one-for-one basis into shares of the Company’s Class A voting common stock.

~~Issuance of 11.250% Senior Notes~~

In January 2018, we issued $250.0 million of 11.250% senior notes due 2023 (the “11.250% Senior Notes”) to U.S.-based institutional investors. The net proceeds of $244.4 million were used to fully retire the 8.750% Senior Notes due 2018 (the “8.750% Senior Notes”), which included principal, interest and prepayment premium totaling approximately $162.0 million. The remaining net proceeds were used to reduce borrowings under our credit facility.

Item 1A. 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;

In addition, the restrictive covenants in the Credit Facility require us to maintain specified financial ratios and satisfy other financial condition tests. Our ability to meet those financial ratios and tests can be affected by events beyond our control, and we may be unable to meet them.

A breach of the covenants or restrictions or under the Credit Facility could result in an event of default under the applicable indebtedness. Such a default may allow the creditors to accelerate the related debt and may result in the acceleration of any other debt to which a cross-acceleration or cross-default provision applies. In the event our lenders accelerate the repayment of our borrowings, we and our subsidiaries may not have sufficient assets to repay that indebtedness.

As a result of these restrictions contained in the Credit Facility, we may be limited in how we conduct our business, unable to raise additional debt or equity financing to operate during general economic or business downturns or unable to compete effectively or to take advantage of new business opportunities. These restrictions may further affect our ability to grow in accordance with our strategy. In addition, our financial results, our substantial indebtedness and our credit ratings could adversely affect the availability and terms of our current and future financing.

We intend to fund our capital expenditures in 2018 through cash flow from operations and from borrowings under the Credit Facility and, if necessary, through debt or equity financings. Our ability to make the necessary capital investment to maintain or expand our asset base and develop oil and natural gas reserves will be impaired if cash flow from operations is reduced and external sources of capital become limited or unavailable. If we incur additional debt for these or other purposes, the related risks that we now face could intensify and we could face additional risks. Our level of debt could adversely affect our business and results of operations in several important ways, including the following:

We may not be able to generate sufficient cash to service all of our indebtedness and may be forced to take other actions to satisfy our obligations under applicable debt instruments, which may not be successful.

Our ability to make scheduled payments on or to refinance our indebtedness obligations, including the Credit Facility and senior notes, depends on our financial condition and operating performance, which are subject to prevailing economic and competitive conditions and certain financial, business and other factors beyond our control. We may not be able to maintain a level of cash flow from operating activities sufficient to permit us to pay the principal, premium, if any, and interest on our indebtedness.

If our cash flow and capital resources are insufficient to fund debt service obligations, we may be forced to reduce or delay investments and capital expenditures, sell assets, seek additional capital or restructure or refinance indebtedness which would have a material adverse effect on our business and operations.

If we reduce our use of derivatives as a result of the new legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Increased volatility may make us less attractive to certain types of investors. Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of crude oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to crude oil and natural gas. If the new legislation and regulations result in lower commodity prices, our revenues could be adversely affected. Any of these consequences could adversely affect our financial condition and results of operations.

~~We may be subject to risks in connection with acquisitions, and the integration of significant acquisitions may be difficult.~~

In accordance with our business strategies, we periodically evaluate acquisitions of reserves, properties, prospects and leaseholds and other strategic transactions that appear to fit within our overall business strategy. The successful acquisition of producing properties requires an assessment of several factors, including:

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:~~

The process of integrating operations could cause an interruption of, or loss of momentum in, the activities of our business. Our senior management may be required to devote considerable amounts of time to this integration process, which will decrease the time they will have to manage our business. If our senior management is not able to effectively manage the integration process, or if any significant business activities are interrupted as a result of the integration process, our business could suffer.

In addition, even if we successfully integrate an acquisition, it may not be possible to realize the full benefits we may expect, including with respect to estimated proved reserves, production volume or cost savings from operating synergies, within our expected time frame. Anticipated benefits of an acquisition may also be offset by operating losses relating to changes in commodity prices in crude oil and natural gas industry conditions, risks and uncertainties relating to the exploratory prospects of the combined assets or operations, or an increase in operating or other costs or other difficulties. Failure to realize the benefits we anticipate from an acquisition may materially and adversely affect our business, results of operations and financial condition.

Our certificate of incorporation and bylaws, as well as Delaware law, contain provisions that could discourage acquisition bids or merger proposals, which may adversely affect the market price of our Class A voting common stock.

Certain provisions in our certificate of incorporation and bylaws could make it more difficult for a third party to acquire control of us, even if the change of control would be beneficial to our stockholders, including:

In addition, we entered into a Board Representation Agreement (“Board Representation Agreement”) with EF Realisation and securities purchase agreements with Chambers and Leucadia National Corporation pursuant to which these stockholders are each entitled to nominate a number of directors so long as certain ownership thresholds are maintained. Please read Note 14. Related Party Activities.

Our bylaws designate the Court of Chancery of the State of Delaware as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by our stockholders, which could limit our stockholders’ ability to obtain a favorable judicial forum for disputes with us or our directors, officers, employees or agents.

~~Frank D. Bracken, III~~ is our Chief Executive Officer. Mr. Bracken has served in this position since January 2012 and has served as a director and Chief Executive Officer of Lonestar Resources, Inc., our wholly-owned subsidiary, since January 2012. Mr. Bracken previously served as Senior Managing Director of Sunrise Securities from September 2008 to December 2011 and as Managing Director of Jefferies LLC from November 1999 to August 2008. During that time, Mr. Bracken led oil and natural gas transactions, spanning from public and private equity and debt offerings to joint ventures in the Haynesville Shale to one of the first purchases of a publicly-traded oil & gas company by a private equity firm. As Chief Financial Officer and a member of the board of directors at Gerrity Oil & Gas Corp, an NYSE-listed exploration and production company, Mr. Bracken was responsible for corporate budgeting and development, acquisitions, equity and debt financing in public and private offerings, and acquisitions and divestitures. Mr. Bracken holds a Bachelors of Arts degree from Yale University.

~~Barry D. Schneider~~ is our Chief Operating Officer. Mr. Schneider has served in this position since May 2014. Prior to joining us, Mr. Schneider held the position of Vice President—Northern Region for Denbury Resources, Inc. from January 2012 to May 2014. Mr. Schneider was at Denbury for 15 years and held positions of increasing responsibility. After holding the positions of Vice President, Production & Operations, Mr. Schneider was promoted to Vice President-East Region in October 2009 and held that position until January 2012 when he became responsible for Denbury’s Northern Region business unit. Prior to Denbury, Mr. Schneider was employed by Wiser Oil and Conoco-Philips. Mr. Schneider received his B.S. in Natural Gas Engineering from Texas A&M—Kingsville in 1985.

~~Douglas W. Banister~~ is our Chief Financial Officer. Mr. Banister has served in this position since January 2014 and previously served as Chief Accounting Officer of Lonestar Resources, Inc., our wholly-owned subsidiary, since August 2010. Mr. Banister is a Certified Public Accountant with 30 years of experience in finance, planning, negotiating and business development. Mr. Banister began his career in public accounting with Ernst & Young, where he served in various accountant roles between June 1984 and December 1987. Between December 1987 and April 1990, Mr. Banister served as Corporate Controller for D.R. Horton, Inc. and, between October 2004 and October 2005, served as VP of finance for Richmond American Homes. Mr. Banister holds a B.B.A. from Texas Wesleyan University with an emphasis in accounting.

~~Thomas H. Olle~~ is our Vice President-Reservoir Engineering. Mr. Olle has served in this position since August 2010. Mr. Olle has over 35 years of oil and gas industry experience in multiple facets of the business, such as reservoir management and management of unconventional resource development projects including horizontal well field development and tertiary recovery projects. Mr. Olle also has significant experience with reserve evaluation and reporting, production engineering and operations, and business development functions including acquisitions, divestitures and new ventures. During his tenure at Encore Acquisition Company, Mr. Olle served as Vice President-Strategic Solutions and also held executive positions responsible for asset management and engineering. He also served as Senior Engineering Advisor for Burlington Resources from December 1985 to March 2002 and District Reservoir Engineer for Southland Royalty Company from May 1982 to December 1985. Mr. Olle holds a Bachelor’s of Science in Mechanical Engineering with Highest Honors from the University of Texas in Austin.

~~Jana Payne~~ was appointed our Vice-President of Geosciences in November 2015, bringing over 25 years of experience in the oil and gas industry. Prior to joining us, Ms. Payne held the position of Senior Exploitation Manager and Geologist at Halcon Resources, Inc. from November 2012 to May 2015. Ms. Payne spent eight years at Petrohawk Energy Inc. from June 2004 to October 2012 (and subsequently BHP Billiton following its acquisition of Petrohawk) as Geologic Manager and Senior Geologist, where her initial mapping of the Eagle Ford shale led to the discovery of the first commercial Eagle Ford Shale well and acquisition of over 300,000 acres by the Company. Ms. Payne’s early career was as a geologist at Marathon Oil Co. and Petroleum Geo-Services, Inc. Ms. Payne has published works in learned journals and holds an MSc and BSc in geology from the University of Texas at Arlington.

~~Gregory R. Packer~~ was appointed our Vice President, General Counsel & Corporate Secretary in October 2017. Prior to his appointment, Greg held the position of Senior Vice President, General Counsel & Corporate Secretary of Howard Energy Partners, a midstream company with operations in the Eagle Ford shale, Marcellus shale and Permian Basin. Before joining Howard Energy, Gregory practiced corporate and securities law at Latham & Watkins LLP, where he represented public and private companies and private equity sponsors in a wide range of transactions, including company formation, private and public mergers and acquisitions, as well as accessing equity and debt markets through private and public offerings, including initial public offerings. Mr. Packer is a graduate of the University of Chicago Law School, where he was a Lowenstein Scholar. Prior to attending law school, Mr. Packer obtained both Master’s and Bachelor’s degrees in accounting from Brigham Young University, where he was a G. Roger Victor Scholar.

~~John Pinkerton~~ has served as a Director since August 2014 and became Chairman of the Board in August 2016. He was a director of Range Resources Corporation (NYSE: RRC) since 1989 and was Chairman of its Board of Directors from 2008 until January 2015. He joined Range as President in 1990 and served as Chief Executive Officer from 1992 until 2012. Prior to joining Range, Mr. Pinkerton served in various capacities at Snyder Oil Corporation for twelve years, including the position of Senior Vice President. Mr. Pinkerton received his Bachelor of Arts degree in Business Administration from Texas Christian University, where he now serves on the board of trustees, and a Master’s degree from the University of Texas at Arlington. During his 27-year tenure Range Resources grew from its small cap origins to be a $13 billion dollar enterprise with a pre-eminent position in the Marcellus Shale. As CEO of Range Resources, Mr. Pinkerton established the technical expertise to enable a drilling-led strategy complemented by bolt-on acquisitions where synergies would enhance growth. This resulted in a rapid and impressive increase in the scale of the business, and seven consecutive years of double-digit growth in both production and reserves (adjusted for debt). Mr. Pinkerton has widespread skill in the management, acquisition and divestiture of oil and gas properties—including related corporate financing activities—hedging, risk analysis and the evaluation of drilling programs. He has represented the industry in policy matters, serving on the executive committee of America’s Natural Gas Alliance. We believe that Mr. Pinkerton’s experience at oil and natural gas exploration companies qualify him for service on our board of directors.

~~Henry B. Ellis~~ has served as a director since October 2016. Mr. Ellis presently serves as managing director and Chief Executive Officer of Bassett California Co. and The Bassett Company. He previously served as a director of several other boards including Bluebonnet Savings Bank and State National Bank, and served as President of Mbank, El Paso and Chairman and CEO of Grayson County Bank. Mr. Ellis received his Bachelor of Arts degree in Business Administration from Texas Christian University. We believe that Mr. Ellis’ financial experience in the banking industry qualifies him for service on our board of directors.

~~Daniel R. Lockwood~~ has served as a director since May 2014. He also serves as Vice-President of New Tech Global and is responsible for overseeing and managing NTG engineering and project management services. Mr. Lockwood is a graduate of the Colorado School of Mines with a degree in Petroleum Engineering. Dan joined New Tech Engineering in 2000 and brings with him more than 35 years of engineering and management experience and is considered one of the industry’s leading experts in Shale Operations. We believe that Mr. Lockwood’s engineering and management experience in the oil and gas industry qualifies him for service on our board of directors.

~~John H. Murray~~ has served as a director since October 2016. Mr. Murray is Co-Founder, Executive Chairman and Chief Compliance Officer of Ecofin Limited, roles he has held since its incorporation in June 1991. Before founding Ecofin Limited, John headed the corporate finance department and was a member of the management committee of Swiss Bank Corporation’s London- based investment banking business. Prior to joining Swiss Bank Corporation, he worked for Morgan Stanley Group Inc. holding various corporate finance positions in the firm’s offices in New York, London, Sydney and Melbourne, an office which he headed. Mr. Murray is a non-executive director of the Ecofin Vista Long/Short Fund Limited and the Ecofin Global Renewable Infrastructure Fund Limited and of the BlackRock Frontiers Investment Trust plc. Mr. Murray earned his BA in Economics from Williams College and an MBA from Harvard Business School. We believe that Mr. Murray’s financial experience in the investment banking industry qualifies him for service in our board of directors.

~~Matthew B. Ockwood~~has served as a director since November 2017. Mr. Ockwood is a Managing Director of Chambers Energy Management, a Houston-based investment firm focused on providing flexible capital to the energy industry. While at Chambers Energy, Mr. Ockwood has led or participated in the execution of dozens of distinct oil and gas transactions ranging from secured debt to common equity. Prior to joining Chambers Energy, Mr. Ockwood was employed by Lehman Brothers where he worked in the Natural Resources investment banking group. Mr. Ockwood holds a B.B.A in Finance, summa cum laude, and a Certificate in Leadership Study and Development from Texas A&M University. We believe that Mr. Ockwood’s financial experience in the investment banking industry for a diverse set of energy clients qualifies him for service on our board of directors.

~~Stephen H. Oglesby~~ has served as a director since March 2017. Before joining the company, Mr. Oglesby served as Head of Energy, US Commercial Bank at Citibank, where he managed multiple offices and oversaw financial services provided to various private and public companies in the oil and gas industry, from December 2003 to January 2017. Mr. Oglesby previously served on the board of directors of various private companies, including Advanced Coiled Tubing, where he served as Chairman of its board of directors, Blackwell Plastics, and Goodman Manufacturing. Mr. Oglesby holds a Bachelor of Science in Accounting from Southern Illinois University. We believe that Mr. Oglesby is qualified to serve on our board of directors because of his extensive experience in financial services for diversified corporate and energy clients, and his background in finance and accounting.

~~Phillip Z. Pace~~ has served as a director since June 2017. Mr. Pace is a Partner of Chambers Energy Management, a Houston-based investment firm focused on opportunistic credit investments in the energy industry. Mr. Pace has extensive experience in energy finance, including 19 years in oil and gas equity research. Mr. Pace joined Lehman Brothers in September 2008 after his retirement from Credit Suisse as Vice Chairman of the energy investment banking group. Mr. Pace received his Bachelor of Business Administration degree in Finance from Texas A&M University and has the Chartered Financial Analyst designation. We believe that Mr. Pace’s financial experience in the investment banking industry for a diverse set of energy clients qualifies him for service on our board of directors.

~~Dr. Christopher Rowland~~ has served as a director of Lonestar since January 2013. He is also director of Special Situations for Ecofin Limited, where he is responsible for initiating and monitoring and realizing investments. Prior to joining Ecofin Limited in 2006, Dr. Rowland formed and led equity research teams over a 20-year period at several investment banks, including Merrill Lynch and Dresdner Klienwort Benson. Apart from his career as a research analyst, Dr. Rowland spent time setting up an alternative generator to buy coal-fired power stations in 1993. He has a Ph.D. for his research into the economics of UK oil taxation and holds a MSc (Econ) from the University of London and a BSc in Economics from the University of Bath. We believe that Dr. Rowland’s academic background in economics and his professional experience in finance and energy investment qualify him to serve on our board of directors.

~~Randy L. Wolsey~~ has served as a director since January 2017. Mr. Wolsey is the founder and since February 2015 has been a co-owner of Lone Oak Minerals, a private company involved in the acquisition and selling of oil and gas minerals. Since January 2012, he has also been the owner of Solana, a private company involved in oil and gas and real estate investments. He is also the founder and since June 2006 has been a co-owner of Tanglewood Exploration, a private company involved in oil and gas exploration and production. He previously held management positions at companies including Glen Rose Oil & Gas and Justin Exploration. Mr. Wolsey received his Bachelor of Arts degree in Political Science from Midwestern State University. We believe that Mr. Wolsey’s experience in the oil and gas industry qualifies him for service on our board of directors.

~~There are no family relationships among any of our directors or executive officers.~~

~~The closing market price of our common stock on March 23, 2018 was $4.04 per share. As of March 23, 2018, there were estimated 1,552 shareholders of record of our Class A common stock.~~

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.

~~All sales of unregistered securities within the last fiscal year have been previously reported in our Quarterly Reports on Form 10-Q and/or Current Reports on Form 8-K.~~

Production ~~volumes in 2017 were 6,495 Boe/d, an increase of 10% from 5,899 Boe/d for 2016. The increase in our average daily production was a result of 1) the acquisition of our Marquis and Battlecat properties~~ ~~that closed on June 15, 2017~~ and 2) an increase in the number of wells brought on-line in 2017 versus 2016. For the year ended December 31, 2017, approximately 67% of our production was crude oil, 16% was NGLs and 17% was natural gas.

The average wellhead price for our production in 2017 was $39.77 per Boe, which was 48% higher than the average price in 2016. Reported wellhead realizations were driven higher by an increase (approximately 18%) in WTI pricing and an increase (approximately 70%) in the Louisiana Light Sweet (“LLS”) spread between the periods. Additionally, pricing significantly increased due to our product mix becoming much more oil-centric, changing from 55% oil, 20% NGLs, and 25% natural gas in 2016 to 67% oil, 16% NGLs, and 17% natural gas in 2017. While the benchmark price rose sharply, our crude oil hedge positions were still able to add $1.97 per Bbl to our realizations or $1.31 per Boe.

Wellhead revenue in 2017 was $94.1 million, a 62% increase from $58.0 million in 2016. Even with the significant increase in benchmark prices, we were able to realize favorable crude oil hedge cash settlements, which added $3.1 million in gains on commodity derivatives for the year ended December 31, 2017.

The table below presents a detail of ~~costs and~~production expenses for ~~the periods indicated:~~

On January 4, 2018, the Company issued $250.0 million of 11.250% senior notes due 2023 (the “11.250% Senior Notes”) to U.S.-based institutional investors. The net proceeds of $244.4 million were used to fully retire the 8.750% Senior Notes, which included principal, interest and prepayment premium of approximately $162 million. The remaining net proceeds were used to reduce borrowings under the Credit Facility.

The 11.250% Senior Notes mature on January 1, 2023, and bear interest at the rate of 11.250% per year, payable on January 1 and July 1 of each year, beginning July 1, 2018. At any time prior to January 1, 2021, the Company may, on any one or more occasions, redeem up to 35% of the aggregate principal amount of the 11.250% Senior Notes with an amount of cash not greater than the net cash proceeds of certain equity offerings at a redemption price equal to 111.250% of the principal amounts redeemed, plus accrued and unpaid interest, provided that at least 65% of the aggregate principal amount of 11.250% Senior Notes originally issued remains outstanding immediately after such redemption and the redemption occurs within 180 days of the closing date of such equity offering.

At any time prior to January 1, 2021, the Company may, on any one or more occasions, redeem all or a part of the 11.250% Senior Notes at a redemption price equal to 100% of the principal amount redeemed, plus a “make-whole” premium and accrued and unpaid interest. On and after January 1, 2021, the Company may redeem the 11.250% Senior Notes, in whole or in part, plus accrued and unpaid interest, at the following redemption prices: 108.438% after January 1, 2021; 105.625% after January 1, 2022; and 100% after July 1, 2022. The indenture contains certain restrictions on the Company’s ability to incur additional debt, pay dividends on the Company’s common stock, make investments, create liens on the Company’s assets, engage in transactions with affiliates, transfer or sell assets, consolidate or merge, or sell substantially all of the Company’s assets.

On August 2, 2016, LRAI and the Company entered into a Securities Purchase Agreement (the “Purchase Agreement”) with Juneau Energy, LLC, as initial purchaser (the “Initial Purchaser”), Leucadia National Corporation (“Leucadia”), as guarantor of the Initial Purchaser’s obligations, the other purchasers party thereto (collectively, along with the Initial Purchaser, the “Purchasers”) and Jefferies, LLC, in its capacity as the collateral agent for the Purchasers, relating to the issuance and sale of (i) up to $49.9 million aggregate principal amount of the Second Lien Notes and (ii) five-year warrants to purchase up to an aggregate 998,000 shares of the Company’s Class A common stock at a price equal to $5.00 per share.

During 2016, LRAI issued $38.0 million in aggregate principal amount of Second Lien Notes and the Company issued warrants to purchase 760,000 shares of its Class A common stock. The Company recorded a warrant liability of approximately $5.1 million which was the fair value amount at the date of issuance. Proceeds from the Second Lien Notes issuance were used to repurchase approximately $68.2 million in aggregate principal amount of the 8.750% Senior Notes in privately negotiated open market repurchases with holders of such notes, and to pay related fees and expenses related to the foregoing. The repurchase amounts paid were approximately $36.2 million in cash. Net of related fees, such repurchases resulted in a gain on debt extinguishment of approximately $28.5 million.

In December 2016, LRAI repaid $21.0 million principal of the Second Lien Notes. In June 2017, LRAI repaid the remaining $17.0 million principal of the Second Lien Notes including an early payment premium of approximately $1.1 million with borrowings from the Company’s Senior Secured Credit Facility.

The table below summarizes our capital expenditures incurred for the year ended December 31, 2017. We plan to invest the majority of our 2018 capital budget for the horizontal development of our Eagle Ford Shale properties and have allocated between $95 million and $100 million to drilling and completion activities to develop these assets, and up to $10 million is allocated for leasehold acquisition expenditures.

~~Our board of directors reviews oil and natural gas hedging on a quarterly basis. Reports providing detailed analysis of our hedging activity are continually monitored.~~

Item 16. Form 10-K Summary

~~None.~~

~~Exhibit Index~~

Incorporated by Reference .
Exhibit Number

Description

Form

File No.

Exhibit

Filing
Date

Filed/
Furnished
Herewith
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

2.2

Purchase and Sale Agreement by and between Lonestar Resources US Inc. and Battlecat Oil & Gas, LLC, dated as of May 26, 2017

8-K

001-37670

2.1

6/2/17

2.3

Amendment No. 1, dated June 15, 2017, to the Purchase and Sale Agreement, by and between Lonestar Resources US Inc. and Battlecat Oil & Gas, LLC, dated May 26, 2017

8-K

001-37670

2.1

6/21/17

2.4

Purchase and Sale Agreement by and between Lonestar Resources US Inc. and SN Marquis LLC, dated as of May 26, 2017

8-K

001-37670

2.2

6/2/17

2.5

Amendment No. 1, dated June 15, 2017, to the Purchase and Sale Agreement by and between Lonestar Resources US Inc. and SN Marquis LLC, dated as of May 26, 2017

8-K

001-37670

2.2

6/21/17

3.1

Certificate of Incorporation of Lonestar Resources US Inc.

10-12B

001-37670

3.1

12/31/15

3.2

Certificate of Amendment to the Certificate of Incorporation of Lonestar Resources US Inc.

10-K

001-37670

3.2

3/23/17

3.3

Certificate of Amendment to Certificate of Incorporation of Lonestar Resources US Inc., dated May 24, 2017

8-K

001-37670

3.1

5/26/17

3.4

Amended and Restated Bylaws of Lonestar Resources US Inc.

8-K

001-37670

3.1

4/7/17

3.5

Certificate of Designations of Series B Convertible Preferred Stock

8-K

001-37670

3.1

6/21/17

3.6

Certificate of Designations of Series A-1 Convertible Participating Preferred Stock

8-K

001-37670

3.2

6/21/17

3.7

Certificate of Designations of Series A-2 Convertible Participating Preferred Stock

8-K

001-37670

3.3

6/21/17

4.1

Registration Rights Agreement dated August 2, 2016 by and among Lonestar Resources US Inc., Leucadia National Corporation and Juneau Energy, LLC.

8-K

001-37670

4.1

8/3/16

4.2

Amendment No. 1, dated June 15, 2017, to the Registration Rights Agreement by and among Lonestar Resources US Inc., Leucadia National Corporation and Juneau Energy, LLC (n/k/a JETX Energy, LLC)

8-K

001-37670

4.4

6/21/17

4.3

Registration Rights Agreement, dated October 26, 2016 between Lonestar Resources US Inc. and EF Realisation Company Limited

8-K

001-37670

4.1

11/1/16

4.4

Amendment No. 1, dated June 15, 2017, to the Registration Rights Agreement by and between Lonestar Resources US Inc. and EF Realisation Company Limited

8-K

001-37670

4.5

6/21/17

4.5

Registration Rights Agreement, dated as of June 15, 2017, by and between Lonestar Resources US Inc. and Battlecat Oil & Gas, LLC

8-K

001-37670

4.1

6/21/17

4.6

Registration Rights Agreement, dated as of June 15, 2017, by and between Lonestar Resources US Inc. and SN UR Holdings, LLC

8-K

001-37670

4.2

6/21/17

4.7

Registration Rights Agreement, dated as of June 15, 2017, by and between Lonestar Resources US Inc. and Chambers Energy Capital III, LP

8-K

001-37670

4.3

6/21/17

4.8

Indenture, dated as of January 4, 2018, by and among Lonestar Resources America Inc., the subsidiary guarantors named therein and UMB Bank, N.A. as Trustee.

8-K

001-37670

4.1

1/9/18

10.1†

Lonestar Resources US Inc. Amended and Restated 2016 Incentive Plan, as amended as of May 24, 2017

8-K

001-37670

10.1

5/26/17

10.2

Amended and Restated Securities Purchase Agreement by and between Lonestar Resources US Inc., and Chambers Energy Capital III, LP, dated June 15, 2017

8-K

001-37670

10.1

6/21/17

10.3

Credit Agreement, dated July 28, 2015, among Lonestar Resources America Inc., Citibank, N.A., as Administrative Agent, and the guarantors and lenders party thereto.

10-12B

001-37670

10.3

12/31/15

10.4

First Amendment to Credit Agreement, dated effective April 29, 2016, among Lonestar Resources America Inc., Citibank, N.A., as Administrative Agent, and the guarantors and lenders party thereto.

10-12B/A

001-37670

10.5

6/9/16

10.5

Second Amendment to Credit Agreement, dated effective May 19, 2016, among Lonestar Resources America Inc., Citibank, N.A., as Administrative Agent, and the guarantors and lenders party thereto.

10-12B/A

001-37670

10.6

6/9/16

10.6

Third Amendment to Credit Agreement and Limited Waiver, dated effective July 27, 2016, among Lonestar Resources America Inc., Citibank, N.A., as Administrative Agent, and the guarantors and lenders party thereto.

8-K

001-37670

10.1

8/2/16

10.7

Fourth Amendment to Credit Agreement dated effective November 23, 2016, among Lonestar Resources America Inc., Citibank N.A., as administrative agent, and lenders party thereto.

*
10.8

Fifth Amendment to Credit Agreement and Limited Waiver dated effective December 29, 2016, among Lonestar Resources America Inc., Citibank, N.A., as administrative agent and lenders party thereto.

*
10.9

Sixth Amendment and Joinder dated June 15, 2017 to the Credit Agreement dated July 28, 2015 by and among Lonestar Resources America, Inc., the subsidiary guarantors party thereto, the lenders party thereto and Citibank, N.A., Inc. as administrative agent and issuing bank.

8-K

001-37670

10.2

6/21/17

10.10

Limited Waiver, Borrowing Base Redetermination and Amendment No. 7 to Credit Agreement, dated as of January 4, 2018, by and among Lonestar Resources America Inc., the subsidiary guarantors party thereto, the lenders party thereto and Citibank, N.A., as administrative agent and issuing bank.

8-K

001-37670

10.1

1/9/18

10.11

Limited Waiver Agreement, dated as of March 28, 2018, among Lonestar Resources America Inc., the guarantor parties hereto, Citibank, N.A., as administrative agent and issuing bank, and lenders party thereto.

*

21.1
List of subsidiaries of Lonestar Resources US Inc.

*
23.1
Consent of BDO USA, LLP

*
23.2
Consent of W.D. Von Gonten & Co.

*
31.1
Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer

*
31.2
Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer

*
32.1
Section 1350 Certification of Chief Executive Officer

**
32.2
Section 1350 Certification of Chief Financial Officer

**
99.1
Report of W.D. Von Gonten & Co. regarding the Company’s estimated proved reserves as of December 31, 2016, dated February 14, 2017

10-K

001-37670

99.4

3/23/17

99.2
Report of W.D. Von Gonten & Co. regarding the Company’s estimated proved reserves as of December 31, 2017, dated February 20,2018

*
101.INS
XBRL Instance Document

*
101.SCH
XBRL Taxonomy Extension Schema Document

*
101.CAL
XBRL Taxonomy Extension Calculation Linkbase Document

*
101.DEF
XBRL Taxonomy Extension Definition Linkbase Document

*
101.LAB
XBRL Taxonomy Extension Label Linkbase Document

*
101.PRE
XBRL Taxonomy Extension Presentation Linkbase Document

*

None.

*	~~Filed herewith.~~

**	~~Furnished herewith~~

†	~~Management contract or compensatory plan or arrangement.~~

SIGNATURES

~~SIGNATURES~~

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, as amended, the Registrant has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized.


	LONESTAR RESOURCES US INC.

~~Date:~~ March ~~29, 2018~~ 31, 2021	~~By:~~	/s/ Frank D. Bracken, III
		Frank D. Bracken, III
		Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, this Report has been signed below by the following persons on behalf of the Registrant in the capacities and on the dates indicated.

~~Name~~

~~Title~~

~~Date~~

Name

Title

Date

/s/ Frank D. Bracken, III

Chief Executive Officer and Director

March ~~29, 2018~~

31, 2021

Frank D. Bracken, III

(Principal Executive Officer)

~~/s/ Douglas W. Banister~~

~~Chief Financial Officer~~

~~March 29, 2018~~

~~Douglas W. Banister~~

~~(Principal Financial Officer)~~

/s/ Jason N. Werth

Chief Accounting Officer

March ~~29, 2018~~

31, 2021

Jason N. Werth

(Principal Financial and Accounting Officer)

/s/ ~~John Pinkerton~~

Richard Burnett

Chairman of the Board

March ~~29, 2018~~

31, 2021

~~John Pinkerton~~

Richard Burnett

/s/ ~~Henry B. Ellis~~

Eric Long

Director

March ~~29, 2018~~

31, 2021

~~Henry B. Ellis~~

Eric Long

/s/ ~~Daniel R. Lockwood~~

Gary D. Packer

Director

March ~~29, 2018~~

31, 2021

~~Daniel R. Lockwood~~

Gary D. Packer

~~/s/ John H. Murray~~

~~Director~~

~~March 29, 2018~~

~~John H. Murray~~

/s/ Andrei Verona

Director

March 31, 2021

Andrei Verona

~~/s/ Matthew B. Ockwood~~

~~Director~~

~~March 29, 2018~~

~~Matthew B. Ockwood~~

~~/s/ Stephen H. Oglesby~~

~~Director~~

~~March 29, 2018~~

~~Stephen H. Oglesby~~

~~/s/ Phillip Z. Pace~~

~~Director~~

~~March 29, 2018~~

~~Phillip Z. Pace~~

~~/s/ Christopher Rowland~~

~~Director~~

~~March 29, 2018~~

~~Christopher Rowland~~

~~/s/ Randy L. Wolsey~~		~~Director~~		~~March 29, 2018~~
~~Randy L. Wolsey~~

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS


Report of Independent Registered Public Accounting Firm			~~F-2~~ 2

Consolidated Balance Sheets			~~F-3~~ 3

Consolidated Statements of Operations			~~F-4~~ 5

Consolidated Statements of Changes in Stockholders’ Equity			~~F-5~~ 6

Consolidated Statements of Cash Flows			~~F-6~~ 7

Notes to Consolidated Financial Statements			~~F-7~~ 8

F-1

Report of Independent Registered Public Accounting Firm

Board of Directors and Stockholders

Lonestar Resources US Inc.

Fort Worth, Texas

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated balance sheets of Lonestar Resources US Inc. and its subsidiaries (the “Company”) ~~and subsidiaries~~ as of December 31, ~~2017~~2020 (Successor) and ~~2016,~~2019 (Predecessor) and the related consolidated statements of operations, of changes in ~~stockholders’~~stockholders' equity and of cash flows for the ~~years then~~periods from December 1 through December 31, 2020 (Successor) and January 1 through November 30, 2020 (Predecessor), and for the year ended ~~and~~December 31, 2019 (Predecessor) including the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company ~~and subsidiaries at~~as of December 31, ~~2017~~2020 (Successor) and ~~2016,~~2019 (Predecessor), and the results of ~~their~~its operations and ~~their~~its cash flows for the ~~years then~~periods from December 1, 2020 to December 31, 2020 (Successor) and January 1 through November 30, 2020 (Predecessor), and for each of the year ended, December 31, 2019 (Predecessor) in conformity with accounting principles generally accepted in the United States of America.

Change in Basis of Accounting

As discussed in Note 3 to the consolidated financial statements, upon emerging from bankruptcy proceedings on November 30, 2020, the Company became a new entity for financial reporting purposes and applied fresh-start accounting. The Company’s assets and liabilities were recorded at their estimated fair values, which differed materially from the previously recorded amounts. As a result, the consolidated financial statements for period following the application of fresh-start accounting are not comparable to the financial statements for previous periods.

Basis for Opinion

These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the ~~audits~~audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ BDO USA, LLP

We have served as the Company's auditor since 2013.

Dallas, Texas

March ~~29, 2018~~

31, 2021

F-2

PART I—~~FINANCI~~ALFINANCIAL INFORMATION

Item 8. Financial Statements.

Lonestar Resources US Inc.

Consolidated Balance Sheets

(In thousands, except share and per share data)

December 31,

2017

2016

Assets

Current assets

Cash and cash equivalents

$
2,538

$
6,068

Accounts receivable:

Oil, natural gas liquid and natural gas sales

12,289

4,680

Joint interest owners and other, net

794

867

Related parties

162

847

Derivative financial instruments

472

1,730

Prepaid expenses and other

2,365

2,631

Total current assets

18,620

16,823

Oil and gas properties, net, using the successful efforts method of accounting

571,163

439,228

Other property and equipment, net

14,099

1,421

Other noncurrent assets

2,918

1,561

Restricted certificates of deposit

—

76

Total assets

$
606,800

$
459,109

Liabilities and Stockholders’ Equity

Current liabilities

Accounts payable

$
25,901

$
14,894

Accounts payable – related parties

389

1,135

Oil, natural gas liquid and natural gas sales payable

8,747

3,568

Accrued liabilities

16,583

9,947

Accrued liabilities – related parties

—

224

Derivative financial instruments

12,336

2,985

Total current liabilities

63,956

32,753

Long-term liabilities

Long-term debt

301,155

204,122

Long-term debt - related parties

—

3,400

Deferred tax liability

8,105

38,020

Other non-current liabilities

1,316

6,052

Equity warrant liability

508

1,565

Equity warrant liability - related parties

963

2,994

Asset retirement obligations

5,649

2,683

Derivative financial instruments

9,802

1,125

Total liabilities

391,454

292,714

Commitments and contingencies

Stockholders’ equity

Class A voting common stock, $0.001 par value, 100,000,000 shares authorized, 24,506,647 and 21,822,015 issued and outstanding at December 31, 2017 and 2016, respectively

142,655

142,652

Class B non-voting common stock, $0.001 par value, 5,000 shares authorized, 2,500 issued and outstanding at December 31, 2017 and 2016, respectively

—

—

Series A-1 convertible participating preferred stock, $0.001 par value, and Series B convertible participating preferred stock, $0.001 par value, 83,968 and 0 shares, respectively, issued and outstanding at December 31, 2017, and none issued and outstanding at December 31, 2016

—

—

Additional paid-in capital

174,871

87,260

Accumulated deficit

(102,180
)

(63,517
)
Total stockholders’ equity

215,346

166,395

Total liabilities and stockholders’ equity

$
606,800

$
459,109


	Successor		Predecessor
	December 31, 2020		December 31, 2019
Assets
Current assets
Cash and cash equivalents	$	17,474	$	3,137
Restricted cash	8,972		0
Accounts receivable
Oil, natural gas liquid and natural gas sales	11,635		15,991
Joint interest owners and other, net	4,076		1,310

Derivative financial instruments	1,703		5,095
Prepaid expenses and other	1,118		2,208
Total current assets	44,978		27,741
Property and equipment
Oil and gas properties, using the successful efforts method of accounting
Proved properties	314,685		1,050,168
Unproved properties	34,929		76,462
Other property and equipment	19,680		21,401
Less accumulated depreciation, depletion, amortization and impairment	(2,056)		(464,671)
Property and equipment, net	367,238		683,360
Accounts receivable	6,053		0
Accounts receivable related party	0		5,816
Derivative financial instruments	395		1,754
Other non-current assets	4,651		2,108
Total assets	$	423,315	$	720,779

See accompanying Notes to Consolidated Financial Statements.

F-3

Lonestar Resources US Inc.

Consolidated ~~Statements of Operations~~

Balance Sheets

(In thousands, except share and per share data)

Year ended December 31,

2017

2016

Revenues

Oil sales
$
80,505

$
46,954

Natural gas sales

6,477

7,165

Natural gas liquid sales

7,086

3,853

Total revenues

94,068

57,972

Expenses

Lease operating and gas gathering

16,763

16,232

Production and ad valorem taxes

5,523

3,287

Rig standby expense

622

2,261

Depletion, depreciation, and amortization

52,718

46,888

Accretion of asset retirement obligations

139

180

Loss (gain) on sale of oil and gas properties

466

(74
)
Impairment of oil and gas properties

33,413

33,893

General and administrative (inclusive of $1.6 million and $0.4 million of stock-based compensation)

12,626

11,767

Acquisition costs

3,202

—

Other

(63
)

1,261

Total expenses

125,409

115,695

Loss from operations

(31,341
)

(57,723
)
Other income (expense)

Interest expense

(20,769
)

(22,840
)
Gain on redemption of bonds

—

28,480

Amortization of finance costs

(5,302
)

(6,743
)
Unrealized gain on warrants

3,088

568

Loss on derivative financial instruments

(14,080
)

(8,672
)
Total other expense, net

(37,063
)

(9,207
)
Loss before income taxes

(68,404
)

(66,930
)
Income tax benefit (expense)

29,741

(27,405
)
Net loss

(38,663
)

(94,335
)
Preferred stock dividends

(3,968
)

—

Net loss attributable to common stockholders
$
(42,631
)

$
(94,335
)

Net loss per common share

Basic
$
(1.92
)

$
(11.64
)
Diluted
$
(1.92
)

$
(11.64
)

Weighted Average Shares Outstanding

Basic

22,252,149

8,106,931

Diluted

22,252,149

8,106,931


	Successor		Predecessor
	December 31, 2020		December 31, 2019
Liabilities and Stockholders’ Equity
Current liabilities
Accounts payable	$	7,651	$	33,355
Accounts payable – related parties	0		189
Oil, natural gas liquid and natural gas sales payable	18,760		14,811
Accrued liabilities	15,983		26,905
Derivative financial instruments	7,938		8,564
Current maturities of long-term debt	20,000		247,000
Total current liabilities	70,332		330,824
Long-term liabilities
Long-term debt	255,328		255,068
Asset retirement obligations	4,573		7,055
Deferred tax liability, net	0		931
Equity warrant liability	0		129
Equity warrant liability - related parties	0		235
Derivative financial instruments	835		1,898
Other non-current liabilities	0		3,752
Total long-term liabilities	260,736		269,068
Commitments and contingencies (Note 15)	0		0
Stockholders’ equity
Predecessor common stock, $0.001 par value, 100,000,000 shares authorized, 24,945,594 shares issued and outstanding	—		142,655
Predecessor preferred stock, $0.001 par value, 100,328 shares issued and outstanding	—		0
Predecessor additional paid-in capital	—		175,738
Successor common stock, $0.001 par value, 90,000,000 shares authorized, 10,000,149 shares issued and outstanding	10		—
Successor additional paid-in capital	92,953		—
Accumulated deficit	(716)		(197,506)
Total stockholders’ equity	92,247		120,887
Total liabilities and stockholders’ equity	$	423,315	$	720,779

See accompanying Notes to Consolidated Financial Statements.

F-4

Lonestar Resources US Inc.

Consolidated Statements of Operations

(In thousands, except share and per share data)


	Successor		Predecessor
	Month Ended December 31, 2020		Eleven Months Ended November 30, 2020		Year Ended December 31, 2019
Revenues
Oil sales	$	8,112	$	80,244	$	157,873
Natural gas liquid sales	1,083		9,982		15,668
Natural gas sales	1,706		15,100		21,611
Total revenues	10,901		105,326		195,152
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
Loss on sale of oil and gas properties	0		1,337		33,508
Impairment of oil and gas properties	0		199,908		48,412
General and administrative	1,505		28,444		16,489
Acquisition costs and other	254		330		1,840
Total expenses	6,398		333,266		236,617
Income (loss) from operations	4,503		(227,940)		(41,465)
Other (expense) income
Interest expense	(1,476)		(35,411)		(43,879)
Unrealized gain on warrants	0		363		691
(Loss) gain on derivative financial instruments	(3,743)		66,699		(30,861)
Reorganization items, net	0		73,471		0
Total other (expense) income, net	(5,219)		105,122		(74,049)
Loss before income taxes	(716)		(122,818)		(115,514)
Income tax benefit	0		4,679		12,495
Net loss	(716)		(118,139)		(103,019)
Preferred stock dividends	0		(4,566)		(8,544)
Undeclared cumulative preferred stock dividends	0		(3,671)		0
Net loss attributable to common stockholders	$	(716)	$	(126,376)	$	(111,563)

Net loss per common share attributable to common stockholders
Basic	$	(0.07)	$	(5.00)	$	(4.48)
Diluted	$	(0.07)	$	(5.00)	$	(4.48)

Weighted Average Shares Outstanding
Basic	10,000,149		25,262,136		24,875,793
Diluted	10,000,149		25,262,136		24,875,793

See accompanying Notes to Consolidated Financial Statements.

F-5

Lonestar Resources US Inc.

Consolidated Statements of Changes in Stockholders’ Equity

(In thousands, except share data)

Class A

Series A-1

Series B

Additional

Accumulated Other

Total

Common Stock

Preferred Stock

Preferred Stock

Paid-in

Accumulated

Comprehensive

Stockholders'

Shares

Amount

Shares

Amount

Shares

Amount

Capital

Deficit

Loss

Equity

Balance at December 31, 2015

7,521,788

$
142,638

—

$
—

—

$
—

$
10,270

$
30,818

$
(760
)

$
182,966

Sale of common stock, net of offering costs

13,800,000

14

—

—

—

—

71,803

—

—

71,817

Shares issued for asset acquisition

500,227

—

—

—

—

—

5,499

—

—

5,499

Stock-based compensation

—

—

—

—

—

—

448

—

—

448

Foreign currency translation

—

—

—

—

—

—

(760
)

—

760

-

Net loss

—

—

—

—

—

—

—

(94,335
)

—

(94,335
)
Balance at December 31, 2016

21,822,015

$
142,652

—

$
—

—

$
—

$
87,260

$
(63,517
)

$
—

$
166,395

Shares issued for asset acquisitions

—

—

5,400

—

2,684,632

3

10,792

—

—

10,795

Conversion of Series A-2 Preferred

—

—

76,577

—

—

—

75,504

—

—

75,504

Conversion of Series B Preferred

2,684,632

3

—

—

(2,684,632
)

(3
)

—

—

—

—

Payment-in-kind dividends

—

—

1,991

—

—

—

—

—

—

Stock-based compensation

—

—

—

—

—

—

1,315

—

—

1,315

Net loss

—

—

—

—

—

—

—

(38,663
)

—

(38,663
)
Balance at December 31, 2017

24,506,647

$
142,655

83,968

$
—

—

$
—

$
174,871

$
(102,180
)

$
—

$
215,346


	Common Stock			Preferred Stock			Additional Paid-in Capital	Accumulated Deficit		Total Stockholders' Equity
	Shares	Amount		Shares	Amount



















Balances at December 31, 2018 (Predecessor)	24,645,825	$	142,655	91,784	$	—		$	174,379	$	(94,487)	$	222,547
Shares issued pursuant to stock-based compensation plan	299,769	—		—	—			—		—		—
Payment-in-kind dividends	—	—		8,544	—			—		—		—
Stock-based compensation	—	—		—	—			1,359		—		1,359
Net loss	—	—		—	—			—		(103,019)		(103,019)
Balances at December 31, 2019 (Predecessor)	24,945,594	$	142,655	100,328	$	—		$	175,738	$	(197,506)	$	120,887
Payment-in-kind dividends	—	$	—	4,566	$	—		$	—	$	—	$	—
Stock-based compensation	366,617	—		—	—			274		—		274
Net loss	—	—		—	—			—		(118,139)		(118,139)
Cancellation of Predecessor equity	(25,312,211)	(142,655)		(104,894)	—			(176,012)		315,645		(3,022)
Issuance of Successor common stock	10,000,149	10		—	—			91,864		—		91,874
Issuance of Successor warrants	—			—	—			1,089		—		1,089
Balances at November 30, 2020 (Predecessor)	10,000,149	$	10	0	$	—		92,953		$	0	$	92,963


Balances at December 1, 2020 (Successor)	10,000,149	$	10	0	$	—		$	92,953	$	0	$	92,963
Net loss	—	—		—	—			—		(716)		(716)
Balances at December 31, 2020 (Successor)	10,000,149	$	10	0	$	—		92,953		$	(716)	$	92,247

See accompanying Notes to Consolidated Financial Statements.

~~F-5~~

F-6

Lonestar Resources US Inc.

Consolidated Statements of Cash Flows

(In thousands)

Year Ended December 31,

2017

2016

Cash flows from operating activities

Net loss

$
(38,663
)

$
(94,335
)
Adjustments to reconcile net loss to net cash provided by operating activities:

Loss on disposal of oil and gas properties

—

35

Accretion of asset retirement obligations

139

180

Depreciation, depletion, and amortization

52,718

46,888

Stock-based compensation

1,629

448

Deferred taxes

(33,820
)

27,059

Gain on disposal of bonds

—

(28,480
)
Losses on derivative financial instruments

14,080

8,672

Settlements of derivative financial instruments

5,207

29,790

Impairment of oil and gas properties

33,413

33,893

Non-cash interest expense

4,571

7,581

Gain on warrants

(3,088
)

(568
)
Changes in operating assets and liabilities:

Accounts receivable

(6,851
)

234

Prepaid expenses and other assets

833

(1,856
)
Accounts payable and accrued expenses

13,278

(5,272
)
Net cash provided by operating activities

43,446

24,269

Cash flows from investing activities

Acquisition of oil and gas properties

(113,726
)

(4,340
)
Development of oil and gas properties

(81,875
)

(39,382
)
Proceeds from sales of oil and gas properties

—

16,174

Purchases of other property and equipment

(13,142
)

(233
)
Net cash used in investing activities

(208,743
)

(27,781
)

Cash flows from financing activities

Proceeds from borrowings and related party borrowings

123,968

72,063

Payments on borrowings and related party borrowings

(34,017
)

(134,697
)
Proceeds from sale of common stock, net of offering costs

—

72,807

Proceeds from sale of preferred stock

77,800

—

Cost to issue equity

(3,296
)

—

Payments of debt issuance costs

(2,685
)

(4,912
)
Changes in other notes payable

(3
)

(3
)
Net cash provided by financing activities

161,767

5,258

(Decrease) increase in cash and cash equivalents

(3,530
)

1,746

Cash and cash equivalents, beginning of the period

6,068

4,322

Cash and cash equivalents, end of the period

$
2,538

$
6,068

Supplemental information:

Cash paid for taxes

$
2,474

$
1,820

Cash paid for interest expense

20,389

23,691

Non-cash investing and financing activities:

Asset retirement obligation

$
2,827

$
(24
)
Increase in liabilities for capital expenditures

8,379

2,666

Preferred stock issued for business acquisitions

10,795

$
—

Common stock issued for asset acquisition

—

5,500

Cost to issue equity included in accounts payable

—

1,000


	Successor		Predecessor
	Month Ended December 31, 2020		Eleven Months Ended November 30, 2020		Year Ended December 31, 2019
Cash flows from operating activities
Net loss	$	(716)	$	(118,139)	$	(103,019)
Adjustments to reconcile net loss to net cash provided by operating activities
Noncash reorganization items, net	0		(85,483)		0
Depreciation, depletion and amortization	2,093		70,122		88,618
Stock-based compensation	0		(2,091)		1,822
Deferred taxes	0		(931)		(11,440)
Loss (gain) on derivative financial instruments	3,743		(66,699)		30,861
Settlements of derivative financial instruments	0		66,761		(3,550)
Impairment of oil and natural gas properties	0		199,908		48,412
Loss on sale or abandonment of property and equipment	0		1,337		34,560
Non-cash interest expense	131		2,002		2,652
Unrealized gain on warrants	0		(363)		(691)
Changes in operating assets and liabilities
Accounts receivable	3,499		(2,146)		(4,481)
Prepaid expenses and other assets	(49)		2,233		(623)
Accounts payable and accrued expenses	4,286		21,725		(2,799)
Net cash provided by operating activities	12,987		88,236		80,322

Cash flows from investing activities
Acquisition of oil and gas properties	(53)		(2,902)		(5,642)
Development of oil and gas properties	(247)		(100,436)		(148,438)
Proceeds from sales of oil and gas properties	0		11,913		11,470
Purchases of other property and equipment	(5)		(1,007)		(3,682)
Net cash used in investing activities	(305)		(92,432)		(146,292)

Cash flows from financing activities
Proceeds from borrowings	0		332,759		139,000
Payments on borrowings	(5,021)		(308,205)		(75,248)


Payments of financing fees	0		(4,710)		0
Net cash (used) provided by financing activities	(5,021)		19,844		63,752


Increase (decrease) in cash, cash equivalents and restricted cash	7,661		15,648		(2,218)
Cash, cash equivalents and restricted cash at beginning of the period	18,785		3,137		5,355
Cash, cash equivalents and restricted cash at end of the period	$	26,446	$	18,785	$	3,137

Supplemental information:
Cash paid for taxes	$	0	$	0	$	38
Cash received for income tax refunds	4,690		0		0
Cash paid for interest	0		28,081		41,217
Non-cash investing and financing activities:
Asset retirement obligation	$	177	$	(3,013)	$	(440)
Increase (decrease) in liabilities for capital expenditures	239		(39,501)		17,993
Conversion of senior notes and preferred stock into common stock	0		91,864		0

See accompanying Notes to Consolidated Financial Statements.

~~F-6~~

F-7

Lonestar Resources US Inc.

Notes to Consolidated Financial Statements

Note 1. Basis of Presentation

Organization and Nature of ~~Business and Presentation~~

Operations

Lonestar Resources US Inc. (the “Successor”) was incorporated in Delaware in December 2015 for purposes of effecting our corporate reorganization, which was completed on July 5, 2016 (the “Reorganization”), pursuant to a Scheme Implementation Agreement (the “Scheme”), dated December 28, 2015, between(“Lonestar” or the Successor and Lonestar Resources Limited (the “Predecessor”), an Australian company. Prior to the Reorganization, our business was owned and operated under our Predecessor, whose ordinary shares were listed on the Australian Securities Exchange (“ASX”). Pursuant to the Scheme, the Successor acquired all of the issued and outstanding ordinary shares of our Predecessor, and each of our Predecessor’s shareholders received one share of our Class A voting common stock (“Class A common stock”) for every two ordinary shares of our Predecessor such shareholder held. Prior to the Reorganization, the Successor had no business or operations, and following the Reorganization, the business and the operations of the Successor consist solely of the business and operations of the subsidiaries of the Predecessor. The reorganization was treated as a transaction among parties under common control and no gain or loss was recorded.

~~Lonestar Resources America, Inc. (“LRAI”~~“Company”) is ~~a Delaware registered U.S. holding~~an independent oil and natural gas company ~~formed~~focused on ~~January 31, 2013, which is engaged in~~ the exploration, development and production ~~acquisition, and sale~~ of unconventional oil, natural gas ~~liquid (“NGL”)~~liquids and natural gas ~~primarily~~ in the Eagle Ford Shale play in South ~~Texas through its wholly owned subsidiary, Lonestar Resources, Inc. Its executive offices are located in Fort Worth,~~ Texas. ~~LRAI was a wholly owned subsidiary~~

Emergence from Voluntary Reorganization Under Chapter 11 of the Predecessor, prior to the Reorganization. The majority of the activities of the Predecessor was carried out through LRAI. Unless the context otherwise requires, references to “Lonestar,” “we,” “us,” “our,” and “the Company” refer to (i) Lonestar Resources Limited and its subsidiaries prior to the Reorganization and (ii)Bankruptcy Code

On September 30, 2020 (the “Petition Date”), Lonestar Resources US Inc. and 21 of its directly and indirectly owned subsidiaries ~~upon completion~~(collectively, the “Debtors”), filed voluntary petitions (“Bankruptcy Petitions”) for relief under Chapter 11 (“Chapter 11”) of the ~~Reorganization,~~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 ~~applicable.~~

“debtors-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions 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. The Company emerged from bankruptcy and went effective with its plan of reorganization on November 30, 2020 (the “Effective Date”). In January 2021, the Successor's new common stock commenced trading on the OTCQX Best Market under the ticker symbol "LONE".

Bankruptcy Accounting

The consolidated financial statements have been prepared in accordance with the provisions of the Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 852, Reorganizations (“ASC 852”).

ASC 852 requires that the financial statements, for periods subsequent to filing of the Chapter 11 Proceedings, distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Accordingly, certain expenses, gains and losses that are realized or incurred in the bankruptcy proceedings are recorded in “reorganization items, net” on the consolidated statements of operations.

In accordance with ASC 852, the Company qualified for and adopted fresh start accounting (“Fresh Start Accounting”) upon emergence from Chapter 11, at which point the Company became a new entity for financial reporting because (i) the holders of the then existing voting shares of the Predecessor company received less than 50% of the voting shares of the Successor company outstanding upon emergence and (ii) 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.

Upon adoption of Fresh Start Accounting as reflected in Note 3. Fresh Start Accounting, the reorganization value derived from the enterprise value associated with the Plan was allocated to the Company’s identifiable tangible and intangible assets and liabilities in conformity with the procedures specified by ASC 805, Business Combinations. Deferred income tax amounts were determined in accordance with ASC 740 Income Taxes.

F-8

References to “Predecessor” relate to the Consolidated Balance Sheets as of December 31, 2019, and Consolidated Statements of Operations for the year ended December 31, 2019 and for the period from January 1, 2020 through and including the adjustments from the application of Fresh Start Accounting on November 30, 2020 (“Predecessor Period”). References to “Successor” relate to the Consolidated Balance Sheets of the reorganized Company as of December 31, 2020 and Consolidated Statements of Operations from December 1, 2020 through December 31, 2020 (“Successor Period”) and are not comparable to the Consolidated Financial Statements of the Predecessor as indicated by the “black line” division in the financials and footnote tables, which emphasizes the lack of comparability between amounts presented. In addition, Note 3. Fresh Start Accounting provides a summary of the Consolidated Balance Sheets as of November 30, 2020 in the first column, and then presents adjustments to reflect the Plan and fresh start impacts to derive the opening Successor Consolidated Balance Sheets as of November 30, 2020. The Company’s financial results for future periods following the application of Fresh Start Accounting will be different from historical trends and the differences may be material.

See Note 2. Emergence from Chapter 11 Bankruptcy Proceedings and Note 3. Fresh Start Accounting for additional details regarding the bankruptcy.

Principles of Reporting and Consolidation

The consolidated financial statements have been prepared using the accrual basis of accounting in accordance with accounting principles generally accepted in the United States of America ~~(“U.S.~~ ("GAAP”) and include the accounts of Lonestar and entities in which we hold a controlling financial interest. Undivided interests in oil and gas joint ventures are consolidated on a proportionate basis. All intercompany balances and transactions have been eliminated.

Use of Estimates

The preparation of the accompanying consolidated financial statements in conformity with GAAP requires management to make ~~informed judgments~~estimates and ~~estimates~~assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and ~~expenses. Management evaluates its~~expenses during the reporting periods. Depletion of oil and gas properties and impairment of proved and unproved oil and gas properties, in part, is determined using estimates of proved oil and ~~related assumptions regularly,~~gas reserves. There are numerous uncertainties inherent in the estimation of quantities of proved reserves and the projection of future rates of production and the timing of development expenditures. Similarly, evaluations for impairment of proved and unproved oil and gas properties are subject to numerous uncertainties including, ~~those~~among others, estimates of future recoverable reserves and commodity price outlooks. Significant estimates underlying these financial statements also include the estimated costs and timing of asset retirement obligations, the fair value of commodity derivatives, the fair value of warrants, restricted stock units and stock appreciation rights, accruals related to ~~proved reserves, the value of properties~~oil and ~~equipment, AROs,~~natural gas volumes and revenues, estimates related to income taxes, estimates used in determination of the reorganization values, enterprise value and the fair ~~values.~~value assets and liabilities recorded as a result of fresh-start accounting . Changes in facts and circumstances or additional information may result in revised estimates, actual results may differ from these estimates.

Reclassifications

Certain prior ~~year~~period amounts have been reclassified to conform to the current year ~~presentation, with~~presentation. Such reclassifications had no ~~effect~~impact on the ~~previously~~Company's reported ~~results of operations.~~

total revenues, expenses, net income, current assets, total assets, current liabilities, total liabilities or stockholders’ equity.

Cash, Cash Equivalents

and Restricted Cash

The Company considers all highly-liquid investments ~~with original~~to be cash equivalents if they have maturities of three months or less when ~~purchased~~purchased. The following table provides a reconciliation of cash, cash equivalents and restricted cash as reported within the Consolidated Balance Sheets to be"Cash, cash ~~equivalents.~~

equivalents and restricted cash at the end of the period" as reported within the Consolidated Statements of Cash Flows:


	Successor		Predecessor
In thousands	December 31, 2020		December 31, 2019
Cash and cash equivalents	$	17,474	$	3,137
Restricted cash, current	8,972		0
Total cash, cash equivalents and restricted cash shown in the Consolidated Statements of Cash Flows	$	26,446	$	3,137

F-9

Restricted cash, current in the table above represents escrow funds maintained by the Successor in accordance with the Plan, as well as funds reserved to cover the balance of the PPP Loan until the Successor receives the final loan forgiveness determination from the Small Business Administration (“SBA”), in accordance with SBA guidance, or until the PPP loan is repaid.

Concentrations and Credit Risk

~~The Company’s~~

Lonestar's financial instruments exposed to concentrations of credit risk consist primarily of cash and cash equivalents, accounts receivable and ~~accounts receivable. The Company places its cash and cash equivalents with reputable financial institutions.~~derivative receivables (see Note 4. Commodity Price Risk Activities). At times, the balances deposited may exceed amounts covered by insurance provided by the U.S. Federal Deposit Insurance Corporation (“FDIC”). The Company has not incurred any losses related to amounts in excess of FDIC limits.

Substantially all of the Company’s accounts receivable are due from either purchasers of oil, NGL and natural gas or working interest partners in oil and natural gas wells for which a subsidiary of the Company serves as the operator. Generally, operators of oil and natural gas properties have the right to offset future revenues against unpaid charges related to operated wells. The Company’s receivables are generally unsecured.

~~F-7~~

~~Oil, NGL~~

For the month ended December 31, 2020 (Successor), three purchasers accounted for 10% or more of the Company's oil and natural gas ~~revenues from Vitol~~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 the Company's 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 (US) Company (10%). For the year ended December 31, 2019 (Predecessor), six purchasers accounted for 10% or more of the Company's oil and natural gas revenues: Shell Trading (US) Company (23%), Texla Energy Management ~~Inc.~~(17%), ~~Trafigura AG,~~Enterprise Crude Oil LLC (16%), Ace Gathering, Inc. (14%), GulfMark Energy, Inc. (13%) and NGL Crude Logistics LLC ~~for the year ended~~(10%).

As of December 31, ~~2017, represented 35%~~2020 (Successor), ~~20%, 16%, 14%, and~~five purchasers accounted for 10%~~, respectively,~~ or more of ~~total revenues. Oil, NGL~~the Company's receivables related to oil and natural gas ~~revenues from~~sales: Enterprise Crude Oil, LLC (24%), Ace Gathering, Inc. (23%), Texla Energy Management Inc. (19%), NGL Crude Logistics LLC (14%), and Shell Trading (US) Company (10%). As of December 31, 2019 (Predecessor), three purchasers accounted for 10% or more of the Company's receivables related to oil and natural gas sales: Texla Energy Management Inc. (59%), ~~Trafigura AG,~~Ace Gathering, Inc. (13%) and BP Products North America LLC for the year ended December 31, 2016, represented 40%, 21%, 18% and 10%, respectively, of total revenues. Accounts receivable relating to oil, NGL and natural gas sales from Vitol Inc., Shell Trading (US) Company and NGL Crude Logistics LLC represented 59%, 19% and 17%, respectively, of total receivables at December 31, 2017. Accounts receivable relating to oil, NGL and natural gas sales from Shell Trading, Trafigura AG and Texla Energy Management, Inc. represented 49%, 30% and 13%, respectively, of total receivables at December 31, 2016.

(11%).

Oil and Natural Gas Properties

~~The Company~~

Lonestar uses the successful efforts method of accounting to account for its oil and natural gas properties. Under this method, costs of acquiring properties, costs of drilling successful exploration wells, and development costs are capitalized. The costs of exploratory wells are initially capitalized pending a determination of whether proved reserves have been found. At the completion of drilling activities, the costs of exploratory wells remain capitalized if a determination is made that proved reserves have been found. If no proved reserves have been found, the costs of each of the related exploratory wells are charged to expense. In some cases, a determination of proved reserves cannot be made at the completion of drilling, requiring additional testing and evaluation of the wells. The Company’s policy is to expense the costs of such exploratory wells if a determination of proved reserves has not been made within a 12-month period after drilling is complete. As of December 31, ~~2017,~~2020 (Successor) the Company did not have any capitalized exploratory well costs that were pending determination of proved reserves. All costs related to development wells, including related production equipment and lease acquisition costs, are capitalized when incurred, whether productive or nonproductive.

Capitalized costs attributed to the proved properties are subject to depreciation and depletion. Depreciation and depletion of the cost of oil and gas properties is calculated using the units-of-production method aggregating properties on a field basis. For leasehold acquisition costs and the cost to acquire proved properties, the reserve base used to calculate depreciation and depletion is the sum of proved developed reserves and proved undeveloped reserves. For ~~development~~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.

F-10

On the sale or retirement of a complete ~~or partial~~ unit of a proved property, the cost and related accumulated depreciation, depletion, and amortization are eliminated from the property accounts, and any gain or loss is recognized.

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.

Other Property and Equipment

Other property and equipment, consisting primarily of office, transportation and computer equipment, as well as our new corporate headquarters, is carried at cost. Depreciation is calculated using the straight-line method over the estimated useful lives of the assets, ranging from 3 to 5 years, with the exception of our corporate headquarters, which is 30 years. Major renewals and improvements are capitalized, while expenditures for maintenance and repairs are expensed as incurred. Upon sale or abandonment, the cost of the equipment and related accumulated depreciation are removed from the accounts, and any gain or loss is recognized.

Impairment of Long-Lived Assets

The carrying value of the oil and gas properties and other related property and equipment is periodically evaluated under the provisions of Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 360, ~~Property, Plant, and Equipment. ASC 360 requires~~ long-lived assets and certain identifiable intangibles ~~to be~~are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. When it is determined that the estimated future net cash flows of an asset will not be sufficient to recover its carrying amount, an impairment loss must be recorded to reduce the carrying amount to its estimated fair value. Judgments and assumptions are inherent in management’s estimate of undiscounted future cash flows and an asset’s fair value. These judgments and assumptions include such matters as the estimation of oil and gas reserve quantities, risks associated with the different categories of oil and gas reserves, the timing of development and production, expected future commodity prices, capital expenditures, production costs, and appropriate discount rates.

~~F-8~~

~~Under ASC 360, the~~

The Company evaluates impairment of proved and unproved oil and gas properties on ~~an area~~a region basis. On this basis, certain ~~fields~~regions may be impaired because they are not expected to recover their entire carrying value from future net cash flows. As a result of this evaluation, the ~~Company~~Predecessor recorded impairment ~~of unproved~~ oil and gas properties of ~~approximately $28.6 million and $4.8~~$199.9 million for the ~~years~~three months ended ~~December~~March 31, ~~2017~~2020, of which $199.0 million was proved and ~~2016, respectively,~~$0.9 million was unproved. The impairment was the result of removing development of PUD and ~~impairment~~probable reserves from future net cash flows as the Predecessor could not assure that they would be developed going forward in light of ~~proven oil~~continued depressed commodity prices and ~~gas properties of $4.8 million and $29.1 million for~~uncertainty regarding the ~~years ended December 31, 2017 and 2016, respectively. If pricing declines, it is reasonably likely that~~Predecessor's liquidity situation at the time.

Upon emergence from bankruptcy, the Company ~~may have~~adopted fresh start accounting which resulted in our long-lived assets being recorded at their estimated fair value at the Effective Date (see Note 3, Fresh Start Accounting, to ~~record~~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, 0 impairment ~~of its oil and gas properties subsequent to~~was identified in December ~~31, 2017.~~

2020.

Asset Retirement Obligations

~~The Company accounts for asset~~

Asset retirement obligations ~~under ASC 410,~~ ~~Asset Retirement and Environmental Obligations. ASC 410 requires legal obligations associated with the retirement of long-lived assets to be~~are 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,~~sheets, which is allocated to expense over the useful life of the asset. Periodic accretion of the discount on asset retirement obligations is recorded as anpart of depreciation, depletion and amortization ("DD&A") expense in the accompanying consolidated statement of operations. See Note 7, 8. Asset Retirement Obligations, for more information.

Revenue Recognition

~~The Company~~

Lonestar recognizes revenue ~~when it is realized or realizable and earned. Revenues are considered realized or realizable and earned when: (i) persuasive evidence of~~at an ~~arrangement exists, (ii) delivery has occurred~~amount that reflects the consideration to which we expect to be entitled in exchange for transferring goods or services ~~have been rendered, (iii) the seller’s price~~ to ~~the buyer is fixed or determinable and (iv) collectability is reasonably assured.~~

The Company follows the sales method of accounting for natural gas revenue, whereby revenue is recorded based on the Company’s share of volume sold, regardless of whether the Company has taken its proportional share of volume produced. A receivable or liability is recognized only to the extent that the Company has an imbalance on a ~~specific property greater than the expected remaining proved reserves. There were no imbalances at December 31, 2017 or 2016.~~

~~Fair Value of Financial Instruments~~

~~In accordance with the reporting requirements of ASC 825,~~ ~~Financial Instruments~~, the Company calculates the fair value of its assets and liabilities that qualify as financial instruments under this guidance and includes this additional information in the notes to consolidated financial statements when the fair value is different from the carrying value of those financial instruments. See Note 5, ~~Fair Value Measurements, for more information.~~

~~Income Taxes~~

~~The Company follows the asset and liability method in accounting for income taxes~~customer, using a five-step process, in accordance with ASC ~~740,~~ 606, Revenue from Contracts with Customers. See Note 6. Revenue Recognition.

F-11

Derivatives

The Company utilizes oil and natural gas derivative contracts to mitigate its exposure to commodity price risk associated with its future oil and natural gas production. These derivative contracts have historically consisted of fixed-price swaps, basis swaps, and collars. We do not apply hedge accounting; accordingly, all derivatives are recorded in the accompanying consolidated balance sheets at estimated fair value. The Company recognizes all changes in the fair values of its derivative contracts as gains or losses in the earnings of the periods in which they occur. See Note 4. Commodity Price Risk Activities for more information.

Income Taxes.

Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases, operating losses and tax credit carryforwards.

Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which these temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date.

The Company periodically evaluates the realizable tax benefits of deferred tax assets and records a valuation allowance, if required, based on an estimate of the amount of deferred tax assets the Company believes does not meet the more likely than not criteria of being realized. In certain circumstances, the deferred tax asset may exceed the amount permissible to be used under the tax law, for example, a net operating loss carryforward. In such cases it is appropriate to write-off the excess net operating loss. At December 31, 2016, the Company wrote off $141.7 million of its net operating loss carryforward. See Note ~~10,~~ 11. Income Taxes, for more information.

The Company evaluates uncertain tax positions, which requires significant judgments and estimates regarding the recoverability of deferred tax assets, the likelihood of the outcome of examinations of tax positions that may or may not be currently under review, and potential scenarios involving settlements of such matters. Changes in these estimates could materially impact the consolidated financial statements. NoNaN liability for material uncertain tax positions existed as of December 31, ~~2017~~2020 (Successor) or ~~2016.~~

~~F-9~~

December 31, 2019 (Predecessor).

Share-Based Payments

~~The Company~~

Lonestar accounts for equity-based awards in accordance with ASC 718, Compensation-Stock Compensation,, which requires companies to recognize in the statement of operations all share-based payments granted to employees based on their fair value. Share-based compensation is recognized by the Company on the graded vesting method over the requisite service period, which approximates the option vesting period of three years.

~~2. Recently Issued Accounting Pronouncements~~

~~Business Combinations.~~ ~~In January 2017,~~ Grants that can be settled in either cash or shares are treated as liabilities on the ~~FASB issued Accounting Standards Update (“ASU”) 2017-01,~~ ~~Business Combinations: Clarifying~~accompanying consolidated balance sheets.

All stock compensation plans and awards in effect during the ~~Definition~~Predecessor periods were cancelled on the Effective Date and no new stock compensation plans have been adopted by the Successor as of ~~a Business~~ ~~(“ASU 2017-01”)~~December 31, 2020.

COVID-19

The Company considered the impact of the ongoing COVID-19 pandemic on the assumptions and estimates used in ~~order~~the consolidated financial statements. The effects of COVID-19 and concerns regarding its global spread have negatively impacted global demand for crude oil and natural gas, which has and could continue to ~~clarify the definition of a business as it relates~~contribute to ~~whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. Effective January 1, 2018,~~price volatility, impact prices the Company ~~adopted ASU 2017-01, which will not have a material impact~~receives for crude oil, natural gas and NGLs, and materially and adversely affect the demand for and marketability of its production, as well as lead to temporary curtailment or shut-ins of production due to lack of downstream demand or storage capacity. The Company's estimates and assumptions were based on historical data and consideration of future market conditions. The potential additional impacts from COVID-19 on the Company’s ~~consolidated~~ financial ~~statements.~~

~~Leases.~~ position, results of operations and cash flows will depend on uncertain factors, including future developments and new information that may emerge regarding the severity and duration of COVID-19, the actions taken by authorities to contain it or treat its impact, and the availability and acceptance of vaccines, all of which are beyond the Company’s control and difficult to predict.

F-12

CARES Act

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 the Predecessor's or Successor's effective tax rates for the eleven months ended November 30, 2020 and one month ended December 31, 2020, respectively.

The Predecessor applied for, and received, a loan under the Paycheck Protection Program ("PPP") during the second quarter of 2020 in the amount of $2.2 million. The application for this loan required the Predecessor to, in good faith, certify that the current economic uncertainty made the loan request necessary to support the ongoing operations of the Company. This certification further required the Predecessor to take into account our current business activity and our ability to access other sources of liquidity sufficient to support ongoing operations in a manner that is not significantly detrimental to the business. The receipt of this loan, and the forgiveness of the loan, is dependent on the Company having initially qualified for the loan and qualifying for the forgiveness of such loan based on our future adherence to the forgiveness criteria. The PPP loan bears interest of 1% and, if not forgiven, has a maturity date of May 8, 2022. Prior to emergence from Chapter 11, the Predecessor applied for loan forgiveness and placed cash equal to the outstanding principal balance of the PPP loan in escrow pending the final forgiveness determination by the SBA, in accordance with SBA guidelines.

Net Loss per Common Share

Prior to the Effective Date, the Predecessor company used the two-class method is utilized to compute earnings per common share as our Class A Participating Preferred Stock (the "Preferred Stock") was considered a participating security. Under the two-class method, losses are allocated only to those securities that have a contractual obligation to share in the losses of the Company. The Preferred Stock was not obligated to absorb Company losses and accordingly was not allocated losses. Net income attributable to common stockholders is allocated between common stock and participating securities based on the weighted average number of common shares and participating securities outstanding for the period. Upon the Effective Date, the Preferred Stock was extinguished and the two-class method is no longer necessary to compute earnings per share for the Successor starting with the month ended December 31, 2020.

Basic earnings per share is computed by dividing the allocated net loss attributable to common stockholders by the weighted-average number of shares of common stock outstanding for the period.

Diluted earnings per share is computed similarly except that the denominator is increased to include dilutive potential common shares. Potential common shares for the Predecessor consisted of warrants, equity compensation awards and preferred stock, while potential common shares for the Successor consist of warrants. In ~~February 2016,~~certain circumstances adjustment to the numerator is also required for changes in income or loss resulting from the potential common shares. Basic weighted average common shares exclude shares of non-vested restricted stock. As these restricted shares vest, they will be included in the shares outstanding used to calculate basic earnings per share.

For the periods presented, there were no differences between the basic and diluted weighted average common shares. The following securities were excluded from the computation of diluted net loss per share, as their effect would have been antidilutive:


	Successor	Predecessor
	Month Ended December 31, 2020	Eleven Months Ended November 30, 2020	Year Ended December 31, 2019
Preferred stock	0	17,173,272	15,828,683
Warrants	1,111,110	760,000	760,000
Stock appreciation rights	0	1,010,000	1,010,000
Restricted stock units	0	1,344,006	1,555,676

F-13

Predecessor Divestiture

On March 22, 2019, the Predecessor completed the divestiture of its Pirate assets in Wilson County for an adjusted cash purchase price of $11.5 million, after closing adjustments, to a private third-party. The assets were comprised of 3,400 net undeveloped acres, 6 producing wells, held 7 proved undeveloped locations as of the closing date, and were producing approximately 200 BOE/d. The Predecessor recognized a loss of $33.5 million during the first quarter of 2019 in conjunction with the sale of the assets.

Recent Accounting Pronouncements

Income Taxes. In December 2019, the FASB issued ASU ~~2016-02,~~ ~~Leases~~ (“2019-12, Income Taxes (Topic 740) – Simplifying the Accounting for Income Taxes ("ASU ~~2016-02”~~2019-12”)~~, which will require organizations that lease assets~~. The objective of ASU 2019-12 is to ~~recognize on~~simplify the ~~balance sheet~~accounting for income taxes by removing certain exceptions to the ~~assets~~general principles in Topic 740 and ~~liabilities for~~to provide more consistent application to improve the ~~rights and obligations created by those leases.~~comparability of financial statements. The amendments in this ASU ~~2016-02 is~~are effective for ~~the annual period~~fiscal years beginning after December 15, ~~2018,~~2020, and early adoption is permitted. The Company is currently evaluating the impact this guidance may have on its consolidated financial statements and related footnote disclosures.

Financial Instruments — Credit Losses. In June 2016, the Financial Accounting Standards Board ("FASB”) issued ASU 2016-13, Financial Instruments – Credit Losses ("ASU 2016-13”). ASU 2016-13 changes the impairment model for most financial assets and certain other instruments, including trade and other receivables, and requires the use of a new forward-looking expected loss model that will result in the earlier recognition of allowances for losses. The amendments in this ASU are effective for fiscal years beginning after December 15, 2022 for Smaller Reporting Companies, which the Company currently is classified as, and interim periods within those fiscal years, and early adoption is permitted. Entities must adopt the ~~standard~~amendment using a modified retrospective ~~transition and apply~~approach to the first reporting period in which the guidance ~~to the earliest comparative period presented, with certain practical expedients that entities may elect to apply. Management~~ is ~~currently assessing the impact the~~effective. The adoption of ASU ~~2016-02 will~~2016-13 is currently not expected to have a material effect on ~~our~~the Company's consolidated financial statements.

~~Revenue Recognition.~~

Reference Rate Reform.In ~~May 2014,~~March 2020, the FASB issued ASU ~~2014-09,~~ ~~Revenue~~2020-04, Reference Rate Reform (Topic 848) (“ASU 2020-04”). ASU 2020-04 provides optional expedients and exceptions for applying GAAP to contracts, hedging relationships, and other transactions to ease financial reporting burdens related to the expected market transition from ~~Contracts~~the London Interbank Offered Rate (“LIBOR”) or another reference rate to alternative reference rates. The amendments in this ASU were effective upon issuance and generally can be applied to applicable contract modifications through December 31, 2022. Currently, the Company's Successor Credit Agreements are the Company's only contracts that makes reference to a LIBOR rate and the agreements outline the specific procedures that will be undertaken once an appropriate alternative benchmark is identified. The Company does not expect this guidance to have a significant impact on its consolidated financial statements and related footnote disclosures.

Note 2. Emergence from Voluntary Reorganization under Chapter 11

As noted above, on the Petition Date, Lonestar Resources US Inc. and 21 of its directly and indirectly owned subsidiaries filed Bankruptcy Petitions for relief under Chapter 11. In addition, on the Petition Date, the Debtors filed their Joint Prepackaged Plan of Reorganization with ~~Customers~~ ~~(“ASU 2014-09”~~the Bankruptcy Court (the “Plan”). ~~The objective~~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.

Plan of ~~ASU 2014-09 is greater consistency and comparability across industries by using a five-step model to recognize revenue from customer contracts.~~Reorganization

On the Effective ~~January 1, 2018,~~Date, the Company ~~adopted ASU 2014-09, using~~consummated the ~~modified retrospective method applied to contracts that were not completed as~~following reorganization transactions in accordance with the Plan:

•Adopted an amended and restated its certificate of ~~January 1, 2018. We have reviewed various contracts that represent our material revenue streams~~incorporation and determined that there was no material impact to our financial position, results of operations or liquidity. Upon adoption of this ASU, we were not required to record a cumulative adjustment to beginning retained earnings. The Company continues to review its implementation documentation and its evaluation of the new disclosure requirements is ongoing.

~~3. Acquisitions and Divestitures~~

~~New Corporate Headquarters~~

~~On August 2, 2017, the Company closed on the purchase of an office building in Fort Worth, Texas, with an acquisition price approximating $10 million.~~

~~Battlecat Acquisition~~

On June 15, 2017, the Company closed an acquisition with Battlecat Oil & Gas, LLC (“Battlecat”) whereby the Company acquired oil and gas properties in the Eagle Ford Shale play in DeWitt, Gonzales and Karnes County, Texas (the “Battlecat Acquisition”). The total purchase consideration of approximately $59.8 million consisted of $55.0 million in cash and 1,184,632bylaws, which reserved for issuance 90,000,000 shares of ~~Series B Convertible Preferred Stock,~~common stock, par value $0.001 per share, ~~(“Series B Preferred~~(the “New Common Stock”) ~~at a value of approximately $4.8 million. Allocation of the purchase consideration was as follows: $56.3 million to proved reserves; $2.9 million to unproved reserves~~ and $0.6 million to unevaluated acreage and other assets. Additionally, the Company recorded an asset retirement obligation of approximately $0.2 million, resulting in fair value of net assets acquired of approximately $59.6 million. The Company accounted for the acquisition as a business combination under ASC 805. Acquisition-related costs of approximately $1.5 million were charged to Acquisition Costs in the Consolidated Statements of Operations. The effective date of the acquisition was April 1, 2017.

~~Marquis Acquisition~~

On June 15, 2017, the Company closed an acquisition with SN Marquis LLC (a subsidiary of Sanchez Energy Corporation) (“Marquis”) whereby the Company acquired oil and gas properties in the Eagle Ford Shale play in Fayette, Gonzales and Lavaca County, Texas (the “Marquis Acquisition”). The total purchase consideration of approximately $50.0 million consisted of $44.0 million in cash and 1,500,00010,000,000 shares of ~~Series B Preferred Stock at a~~preferred stock, par value ~~of approximately $6.0 million. Allocation of the purchase price was as follows: $48.0 million to proved reserves; $0.6 to unproved reserves~~$0.001 per share;

•Cancelled all outstanding common and $1.4 million to land, building and other assets. Additionally, the Company recorded an asset retirement obligation of approximately $1.9 million, resulting in fair value of net assets acquired of approximately $48.1 million. The Company accounted for the acquisition as a business combination under ASC 805. Acquisition-related costs of approximately $1.2 million were charged to Acquisition Costs in the Consolidated Statements of Operations. The effective date of the acquisition was January 1, 2017.

~~F-10~~

~~Pro Forma Operating Results (unaudited)~~

The following unaudited pro forma combined financial information for the years ended December 31, 2017 and 2016, is based on the historical consolidated financial statements of the Company adjusted to reflect as if the Battlecat Acquisition and the Marquis Acquisition had closed and related financing had occurred on January 1, 2016. The unaudited pro forma combined financial information includes adjustments primarily for revenues and expenses for the acquired properties, depreciation, depletion, amortization and accretion, and interest expense. The unaudited pro forma combined financial statements give effect to the events set forth below:

The issuance of 5,400 shares of Series A-1 Preferred Stock and 74,600 shares of Series A-2 Preferred Stock (each as defined below) to Chambers Energy Capital III, LP (“Chambers”) for $80 million to finance a portion of the Battlecat Acquisition and the Marquis Acquisition, at an initial conversion price of $6.00 per share, subject to certain adjustments including preferred ~~dividends.~~

~~The borrowing of approximately $24 million on our Credit Facility to finance a portion of the Battlecat Acquisition and the Marquis Acquisition and the related adjustment to interest expense.~~

~~The issuance of 1,500,000~~ shares of the ~~Company’s Series B Preferred Stock~~Predecessor and the Predecessor's equity compensation plan and related unvested shares.

•Provided for the following settlement of claims and interests in the Predecessor as follows:

◦Holders of claims on the Predecessor Senior Secured Credit Facility (the "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;

F-14

▪A second-out senior secured term loan credit facility in an amount equal to ~~SN UR Holdings, LLC (a subsidiary~~$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 ~~Sanchez Energy Corporation).~~

~~The issuance~~the 11.25% Senior Notes due 2023 (the "Prepetition Notes Claims") received distributions of ~~1,184,632~~a pro rata share of 96% of 10,000,149 shares of New Common Stock issued on the ~~Company’s Series B Preferred~~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 ~~Battlecat Oil & Gas, LLC.~~

dilution by the MIP and the new warrants);

~~Conversion~~•Holders of ~~Series B Preferred Stock to~~Predecessor Class A ~~voting~~ common stock ~~on November 3, 2017.~~

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); and

•General unsecured creditors were paid in full in cash.

Year Ended December 31,

In thousands

2017

2016

Pro forma total revenues

$
107,853

$
91,532

Pro forma net loss attributable to common stockholders

(48,888
)

(46,093
)
Pro forma net loss per common share, basic and diluted

(1.99
)

(4.27
)
•Incurred “success fees” of $4.7 million; and

~~Pro forma~~

•Reserved approximately $6.8 million to pay professional fees associated with the Chapter 11 Proceedings that were yet to be approved by the Bankruptcy Court.

Reorganization Items, Net

Any expenses, gains and losses that are realized or incurred as of or subsequent to the Petition Date and as a direct result of the bankruptcy proceedings and adjustments to ~~net income (loss) attributable~~reflect the carrying value of certain liabilities subject to ~~common stockholders consists of depreciation, depletion, amortization and accretion calculations, additional interest expense,~~compromise at their estimated allowed claim amounts, as such adjustments ~~for income tax (expense) benefit, and dividends~~were determined, are recorded under “Reorganization Items, Net” on ~~preferred stock issued to complete the acquisitions.~~

~~The Company has included in its~~our Consolidated Statements of Operations ~~revenues of $2.20 million and $13.2 million and direct operating expenses of $0.6 million and $3.81 million~~ for the ~~period from June 15, 2017~~Predecessor and consist of the following:


	Predecessor
In Thousands	Period from September 30, 2020 through November 30, 2020
Unamortized discounts and debt issuance costs	$	(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

Liabilities Subject to ~~December 31, 2017 related~~Compromise

Liabilities and obligations whose treatment and satisfaction were dependent on the outcome of the Chapter 11 Proceedings and have been segregated and classified as liabilities subject to compromise on the Predecessor’s consolidated balance sheets at the amounts that were allowed, or that the Company estimated would be allowed, as claims in the Chapter 11 Proceedings. See Note 3. Fresh Start Accounting for further information on the composition of liabilities subject to compromise and satisfaction pursuant to the ~~properties acquired~~Plan.

Note 3. Fresh-Start Accounting

All conditions required for the adoption of fresh-start accounting were met when the Plan became effective, 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 ~~Battlecat~~Company’s consolidated financial statements and ~~Marquis transactions, respectively.~~

~~Juneau Transaction~~

~~On August 2, 2016,~~resulted in the Company ~~entered into~~becoming a ~~purchase~~new entity for financial reporting purposes. As a result of the application of fresh-start accounting and ~~sale agreement~~the effects of the implementation of the Plan, the financial statements on or prior to the Effective Date are not comparable with ~~Juneau Energy, LLC (“Juneau”) whereby~~the financial statements after the Effective Date.

Upon the application of fresh-start accounting, the Company ~~obtained~~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 74 Income Taxes. Reorganization value represents the fair value of the Successor Company’s assets before considering liabilities.

F-15

Reorganization Value

Under ASC 852, the Successor Company must determine an ~~undivided 50%~~enterprise value to be assigned to the debt and equity of ~~Juneau’s interest in two producing wells~~the emerging company as of the date of adoption of fresh-start accounting. In the disclosure statement associated with the Plan, which was confirmed by the Bankruptcy Court, the Company estimated a range of enterprise values to be approximately $290 million to $415 million, with a midpoint of $353 million. The Company deemed it appropriate to use the midpoint between the low end and ~~each well’s respective~~high end of the range to determine the final enterprise value of $353 million.

The enterprise value was derived using an asset-based valuation methodology of estimated proved reserves, undeveloped acreage, and other financial information, considerations and projections, applying a combination of the income, cost and market approaches as of the fresh-start reporting date of November 30, 2020.

The Company’s principal assets are its oil and natural gas ~~leases covering approximately 1,300 net mineral acres located in Brazos County, Texas. The total consideration paid by~~properties. For purposes of estimating the ~~Company was $5.5 million payable in 500,227 shares~~fair value of the Company’s ~~Class A voting common stock.~~

4.proved, probable, and possible reserves, an income approach was used which estimated fair value based on the anticipated cash flows associated with the Company’s reserves, including future operating and development costs. Within the income approach, the reserve categories were risked and discounted using a weighted average cost of capital rate of 10.5%. The proved reserve locations were limited to wells expected to be drilled, at that time, in the Company’s 5-year development plan while the probable and possible reserves included wells that are expected to be drilled in year 2025 and beyond. Commodity ~~Price Risk Activities~~

~~The Company has implemented a strategy to reduce~~prices utilized in the ~~effects~~determination of ~~volatility~~the fair value of oil and natural gas ~~prices~~properties were based on the New York Mercantile Exchange (“NYMEX”) strip as of the Effective Date for years 2020 through 2022 and then escalated at an inflation rate of 2% through the end of the life of the reserves. In estimating the fair value of the Company’s ~~results~~undeveloped acreage, a market approach was used in which a review of ~~operations~~recent transactions was considered. See further discussion below in the Fresh-start accounting adjustments for the specific assumptions used in the valuation of the Company’s various other assets.

The fair value of the Successor’s exit financing (revolving credit facility and term loan facility) was estimated based on the Discounted Cash Flow (“DCF”) approach, taking into consideration credit quality of the Company and the yield of the instruments. The Company concluded that the terns of the exit financing are at fair value.

The fair value of the Successor warrants was estimated by ~~securing fixed-price contracts~~applying a Monte Carlo simulation model (“MCSM”) to incorporate the Minimum Equity Value hurdle of $100 million for the Warrants.

The MCSM approach was employed to simulate future equity value in a risk-neutral framework. For each simulation path, the equity value for Lonestar was simulated from the Valuation Date to the Expiration Date to see if the simulated equity value met the Minimum Equity Value Threshold during the 3-year measurement period for each tranche of the Warrants. The volatility input used in the simulation was based on a set of guideline public companies (“GPC”). Specifically, the GPC’s equity volatilities were calculated as the average of the 3-year historical volatility and implied volatility, which was then adjusted for leverage. The risk-free interest rate was based on the yields on U.S. Treasury Strips with a remaining term of 3.0-year, which is commensurate with the remaining contractual term of the Warrants as sourced from Capital IQ.

Although the Company believes the assumptions and estimates used to develop enterprise value and reorganization value are reasonable and appropriate, different assumptions and estimates could materially impact the analysis and resulting conclusions. The assumptions used in estimating these values are inherently uncertain and require judgment. The following table reconciles the Company’s Enterprise value to the estimated fair value of the Successor’s common stock as of November 30, 2020:


In thousands	As of November 30, 2020
Enterprise value	$	353,000
Plus: Cash and cash equivalents and restricted cash (excluding funds held in the professional fee escrow of $6.8 million)	11,970
Less: Fair value of debt	(272,007)
Fair Value of Successor equity	$	92,963

F-16

The following table reconciles the enterprise value to its reorganization value of Successor’s assets to be allocated to the Company’s individual assets as of the Effective Date:


In thousands	As of November 30, 2020
Enterprise value	$	353,000
Plus: Cash and cash equivalents and restricted cash (excluding funds held in the professional fee escrow of $6.8 million)	11,970
Current liabilities (excluding current portion of long-term debt)	41,459
Non-current liabilities excluding long-term debt	4,846
Mortgage obligations related to Boland Building LLC	8,328
Reorganization value of Successor's assets to be allocated	$	419,603

Balance Sheet

The adjustments included in the following fresh start consolidated balance sheet reflect the effects of the transactions contemplated by the Plan and executed by the Company on the Effective Date (reflected in the column “Reorganization Adjustments”) as well as fair value and other required accounting adjustments resulting from the implementation of fresh start accounting (reflected in the column “Fresh Start Adjustments”). The explanatory notes provide additional information with regard to the adjustments recorded, the methods used to determine the estimated fair values and significant assumptions.


	As of November 30, 2020
In thousands	Predecessor		Reorganization Adjustments		(1)	Fresh Start Adjustments			Successor
Current assets
Cash and cash equivalents	$	40,565	$	(30,752)	(2)	$	—		$	9,813
Restricted Cash	2,157		6,815		(3)	—			8,972
Accounts receivable
Oil, natural gas liquid and natural gas sales	10,354		—			—			10,354
Joint interest owners and other, net	1,458		—			—			1,458
Derivative financial instruments	916		—			—			916
Prepaid expenses and other	8,403		100		(4)	—			8,503
Total current assets	63,853		(23,837)			—			40,016
Property and equipment
Oil and gas properties, using the successful efforts method of accounting
Proved properties	1,100,211		—			(786,239)		(16)	313,972
Unproved properties	77,382		—			(42,457)		(16)	34,925
Other property and equipment	21,862		—			(2,188)		(16)	19,674
Less accumulated depreciation, depletion, amortization and impairment	(734,231)		—			734,231		(16)	—
Property and equipment, net	465,224		—			(96,653)			368,571
Accounts receivable	6,053		—			—			6,053
Derivative financial instruments	216		—			—			216
Other non-current assets	209		4,538		(5)	—			4,747
Total assets	$	535,555	$	(19,299)		$	(96,653)		$	419,603

F-17


	As of November 30, 2020
In thousands	Predecessor		Reorganization Adjustments		(1)	Fresh Start Adjustments			Successor
Liabilities and Stockholders’ Equity
Current liabilities
Accounts payable	$	8,606	$	(1,898)	(6)	$	—		$	6,708
Oil, natural gas liquid and natural gas sales payable	17,507		—			—			17,507
Accrued liabilities	8,972		3,951		(7)	—			12,923
Derivative financial instruments	4,321		—			—			4,321
Current maturities of long-term debt	286,759		(264,602)		(8)	—			22,157
Total current liabilities	326,165		(262,549)			—			63,616
Long-term liabilities
Long-term debt	8,991		249,602		(9)	(402)		(17)	258,191
Asset retirement obligations	7,327		—			(2,969)		(18)	4,358
Deferred tax liability, net	—		—			—			—
Equity warrant liability	—		—			—			—
Derivative financial instruments	485		—			—			485
Other non-current liabilities	(10)		—			—			(10)
Total long-term liabilities	16,793		249,602			(3,371)			263,024
Liabilities subject to compromise	271,110		(271,110)		(10)	—			—
Total liabilities	614,068		(284,057)			(3,371)			326,640
Stockholders’ equity
Predecessor common stock	142,655		(142,655)		(11)	—			—
Predecessor preferred stock	—		—		(11)	—			—
Predecessor additional paid-in capital	176,012		138,980		(12)	(314,992)		(19)	—
Successor common stock	—		10		(13)	—			10
Successor additional paid-in capital	—		92,953		(14)	—			92,953
Accumulated deficit	(397,180)		175,470		(15)	221,710		(19)	—
Total stockholders’ equity	(78,513)		264,758			(93,282)			92,963
Total liabilities and stockholders’ equity	$	535,555	$	(19,299)		$	(96,653)		$	419,603

F-18


	Reorganization Adjustments
		Increase / (Decrease)

(1)	Represent amounts recorded as of the Effective Date for the implementation of the Plan, including, among other items, issuance of new debt, settlement Predecessor’s liabilities subject to compromise and issuance of the Successor’s common stock and warrants.

(2)	Changes in cash and cash equivalents include the following :
	Proceeds from Successor Senior Secured Credit Facility	$	224,602
	Proceeds from Successor Second Out Term Loan	60,000
	Payment of Predecessor Senior Secured Credit Facility	(284,602)
	Payment of Successor Senior Secured Credit Facility	(15,000)
	Payment of Predecessor Senior Secured Credit Facility interest and fees	(764)
	Payment of deferred financing fees for the Successor Senior Secured Credit Facility and Successor Second-Out Term Loan	(4,710)
	Payment to fund professional fee escrow	(6,815)
	Payment of professional fees including success fees	(3,373)
	Payment of bank fees	(90)
	Net change in cash and cash equivalents	$	(30,752)

(3)	Represents the funding of the professional fee escrow associated with the Chapter 11 Proceedings.

(4)	Represents the overpayment of professional fees.

(5)	Changes in other non-current assets include the following :

	Payment of deferred financing fees for the Senior Secured Credit Facility and Successor Second Out Term Loan	$	4,710
	Elimination of deferred financing fees on the Predecessor Senior Secured Credit Facility	(172)
	Net change in other non-current assets	$	4,538

(6)	The decrease in accounts payable represents the payment of previously accrued professional fees.

(7)	Net change in accrued liabilities include the following :

	Accrual of professional fees (success fees)	$	4,715
	Payment of Predecessor Senior Secured Credit Facility interest and fees	(764)
	Net change in other current liabilities	$	3,951

(8)	Net change in current maturities of long-term debt includes the following :

	Proceeds from Successor Second-Out Term Loan (current portion)	$	20,000
	Payment of Predecessor Senior Secured Credit Facility	(284,602)
	Net change in current maturities of long-term debt	$	(264,602)

(9)	Net change in long-term debt includes the following :

	Borrowings under Successor Senior Secured Credit Facility	$	224,602
	Borrowings under Successor Second-Out Term Loan (long-term portion)	40,000
	Payment of Successor Senior Secured Credit Facility	(15,000)
	Net change in long-term debt	$	249,602

F-19


		Increase / (Decrease)
(10)	Liabilities subject to compromise was settled in accordance with the Plan and the resulting gain were determined as follows:

	Liabilities subject to compromise consist of:
	11.25% Senior Notes	$	(250,000)
	Interest on 11.25% Senior Notes	(21,094)
	Stock compensation liability	(15)
	Acceleration of unvested predecessor stock compensation on the Effective Date	(21)
	Predecessor warrant liability	(1)
	Total liabilities subject to compromise	$	(271,131)


	Liabilities subject to compromise were settled as follows:
	Total liabilities subject to compromise	$	(271,131)
	Less: Distribution of Successor ordinary shares to creditors	88,199
	Less: Distribution of Successor warrants to creditors	1,089
	Gain on settlement of liabilities subject to compromise	$	(181,843)

(11)	Represents the cancellation of Predecessor ordinary and preferred shares at par value pursuant to the Plan.

(12)	Net change in Predecessor additional paid-in capital include the following :

	Cancellation of Predecessor ordinary and preferred shares	$	142,655
	Issuance of Successor ordinary shares to Predecessor preferred shareholders	(2,756)
	Issuance of Successor ordinary shares to Predecessor ordinary shareholders	(919)
	Net change in Predecessor additional paid-in capital	$	138,980

(13)	Represents the issuance of Successor ordinary shares to creditors, prior ordinary and preferred shareholders at par value.

(14)	Successor additional paid-in capital consists of:

	Issuance of Successor ordinary shares to creditors	$	88,189
	Issuance of Successor warrant to holders of the Predecessor Senior Secured Credit Facility	1,089
	Issuance of Successor ordinary shares to Predecessor preferred shareholders	2,756
	Issuance of Successor ordinary shares to Predecessor ordinary shareholders	919
	Total Successor additional paid in capital	$	92,953

F-20


		Increase / (Decrease)
(15)	Net change in accumulated deficit consists of the following :

	Gain on settlement of liabilities subject to compromise	$	181,843
	Acceleration of Predecessor stock compensation awards	(21)
	Accrual of professional fees (success fee)	(4,715)
	Payment of professional fees (success fee)	(1,375)
	Elimination of deferred financing fees on the Predecessor Senior Secured Credit Facility	(172)
	Payment of bank fees	(90)
	Net change in accumulated deficit	$	175,470

Fresh Start Adjustments

(16)	Reflects adjustments to present the proved oil and gas properties, unproved acreage and other property and equipment at their estimated fair values based on the valuation methodology discussed below as well as the elimination of accumulated depreciation, depletion, amortization and impairment. The following table summarizes the components of property, plant and equipment as of the Effective Date:
		Successor Fair Value		Predecessor Historical Value
	Proved properties	$	313,972	$	1,100,211
	Unproved properties	34,925		77,382
	Other property and equipment	19,674		21,862
		368,571		1,199,455
	Less accumulated depreciation, depletion, amortization and impairment	0		(734,231)
	Property and equipment, net	$	368,571	$	465,224

	For purposes of estimating the fair value of its other operating property and equipment, the Company used a combination of the market and cost approaches. A market approach was relied upon to value land and vehicles, and in this valuation approach, recent transactions of similar assets were utilized to determine the value from a market participant perspective. For the remaining other operating assets, a cost approach was used. The estimation of fair value under the cost approach was based on current replacement costs of the assets, less depreciation based on the estimated economic useful lives of the assets, age of the assets, physical deterioration, and obsolescence.

(17)	Reflects the fair value adjustment to the Boland LLC mortgage liability. The fair value of the Successor’s mortgage obligations related to Boland Building LLC (“Mortgages”) was estimated based on the DCF approach, which relies upon assumptions about the amount and timing of principal and interest payments and current market rates. In this analysis, the remaining interest and principal payments were discounted to present value using a pre-tax discount rate deemed to be reflective of a market yield for the Mortgages as of the Effective Date.

(18)	Adjustment to present at fair value the Company's asset retirement obligations (“ARO”) using assumptions as of the Effective Date, including an inflation factor of 2.5% and an estimated 30-year credit-adjusted risk-free rate of 10.5%.
		Increase / (Decrease)
(19)	The table below reflects the cumulative impact of Fresh Start Adjustments discussed above and the elimination of Predecessor capital in excess of par value and Predecessor accumulated deficit:

	Fresh start valuation adjustments	$	(93,282)
	Elimination of Predecessor Accumulated Deficit to Additional Paid In Capital	314,992
	Net Change in Accumulated Deficit	$	221,710

F-21

Note 4. Commodity Price Risk Activities

Lonestar enters into certain commodity derivative instruments to mitigate commodity price risk associated with a portion of its ~~expected~~future oil and natural gas production and related cash flows. The oil and natural gas revenues and cash flows are affected by changes in commodity product prices, which are volatile and cannot be accurately predicted. The objective for entering into these commodity derivatives is to protect the operating revenues and cash flows related to a portion of the future oil and natural gas sales ~~volumes.~~

from the risk of significant declines in commodity prices, which helps ensure the Company’s ability to fund the capital budget.

Inherent in ~~the Company’s~~Lonestar's fixed price contracts are certain business risks, including market risk and credit risk. Market risk is the risk that the price of oil and natural gas will change, either favorably or unfavorably, in response to changing market conditions. Credit risk is the risk of loss from ~~nonperformance~~non-performance by the Company’s counterparty to a contract. The Company does not currently require cash collateral from any of its counterparties nor does its counterparties require cash collateral from the Company. AtAs of December 31, ~~2017,~~2020 (Successor), the Company had no open physical delivery obligations.

~~The~~

Under the terms of Company's Successor Credit Facility, by no later than 90 days following the Effective Date, which can be extended at the discretion of the Lenders, the Company ~~enters into certain commodity derivative instruments~~is required to ~~mitigate commodity price risk associated with~~have hedges in place covering a ~~portion~~minimum of 80% of its ~~future oil, NGL~~anticipated production for the period of 36 consecutive calendar months following the Effective Date and ~~natural gas~~75% of its anticipated production ~~and related cash flows. The oil, NGL and natural gas revenues and cash flows are affected by changes in commodity product prices, which are volatile and cannot be accurately predicted. The objective~~ for ~~holding these commodity derivatives is to protect~~ the ~~operating revenues and cash flows related to a portion~~24 months immediately following the date of ~~the future oil, NGL and natural gas sales from the risk of significant declines in commodity prices, which helps ensure the Company’s ability to fund the capital budget.~~

~~F-11~~

~~The Company has not designated any of the commodity derivatives as hedges under the applicable accounting standards. Consequently, all changes in fair value of these derivatives are included~~each Swap Agreement Certificate (as defined in the ~~Consolidated Statements of Operations.~~

Agreement).

As of December 31, ~~2017,~~2020 (Successor), all of the ~~following derivative transactions were outstanding:~~

Instrument

Total Volume

Settlement Period

Fixed Price

Oil – WTI Fixed Price Swap

365,000 Bbl

January – December 2018

$
54.18

Oil – WTI Fixed Price Swap

182,500 Bbl

January – December 2018

55.65

Oil – WTI Fixed Price Swap

182,500 Bbl

January – December 2018

55.50

Oil – WTI Fixed Price Swap

292,000 Bbl

January – December 2018

47.10

Oil – WTI Fixed Price Swap

509,000 Bbl

January – December 2018

50.17

Oil – WTI Fixed Price Swap

508,900 Bbl

January – December 2019

50.40

Oil – WTI Fixed Price Swap

560,700 Bbl

January – December 2019

48.04

Oil – WTI Fixed Price Swap

401,500 Bbl

January – December 2019

50.90

Oil – WTI Fixed Price Swap

203,600 Bbl

January – June 2020

48.90

Natural Gas – Henry Hub NYMEX Fixed Price Swap

1,825,000 MMBtu

January – December 2018

3.09

Instrument

Total Volume

Settlement Period

Puts

Calls

Oil – 2 Way Collar

182,500 Bbl

January – December 2018

$
50.00

$
59.45

~~The above oil~~Company's outstanding derivative contracts ~~aggregate~~were subject to 1,713,500 Bbls or 4,695 Bbls/d for 2018; 1,471,100 Bbls or 4,030 Bbls/d for 2019; and 203,600 Bbls or 1,119 Bbls/d for 2020. The above natural gas derivative contract equates to 5,000 MMBtu/d for 2018. Allenforceable master netting arrangements whereby payables on those contracts can be offset against receivables from separate derivative contracts with the same counterparty. It is the Company's policy to classify derivative assets and liabilities on a gross basis on its balance sheets, even if the contracts are ~~carried~~subject to enforceable master netting arrangements.

The following table summarizes Lonestar's commodity derivative contracts as of December 31, 2020 (Successor):

Contract

Volume Hedged

Weighted

Commodity

Type

Period

Range (1)

(Bbls/Mcf per day)

Average Price

Oil - WTI

Swaps

Jan - Dec 2021

$42.20 - $47.09

4,146

43.05

Oil - WTI

Swaps

Jan - Dec 2022

$44.83 - $47.09

2,000

45.62

Natural Gas - Henry Hub

Swaps

Jan - Dec 2021

$2.86 - $3.28

11,991

3.03

Natural Gas - Henry Hub

Swaps

Jan - Dec 2022

$2.70 - $3.14

6,233

2.77

(1) Ranges presented for fixed-price swaps and basis swaps represent the lowest and highest fixed prices of all open contracts for the period presented.

During January 2021, the Company entered into additional WTI swaps of 184,000 (1,000 barrels per day) at ~~their fair value on~~an average strike price of $50.37 for the ~~balance sheet~~period of July through December 2021, in addition the company entered into additional WTI swaps of 90,500 (500 barrels per day) at an average strike of $49.17 for the period of January through June 2022. During February 2021, the company entered into additional WTI swaps of 221,000 (722 barrels per day) at an average strike price of $55.50 for the period of March through December 2021, in addition the company entered into additional WTI swaps of 297,000 (814 barrels per day) at an average strike of $49.82 for the period of January through December 2022 and ~~all changes in value are recorded in the Consolidated Statements~~entered into Henry Hub swaps for 460,000 MMBtu (5,000 MMBtu/d) at an average strike price of ~~Operations.~~

$2.93 per MMBtu.

As of December 31, ~~2017 and 2016,~~2020 (Successor), all of the Company’s ~~economic~~ derivative hedge positions were with large financial institutions, which are not known to the Company to be in default on their derivative positions. The Company is exposed to credit risk to the extent of non-performance by the counterparties in the derivative contracts discussed ~~above; however, the Company does not anticipate non-performance by such counterparties.~~above. None of the Company’s derivative instruments contain credit-risk related contingent features.

Note 5. Leases

Operating lease ROU assets are presented within Other Property and Equipment on the consolidated balance sheets as of December 31, 2019. The current portion of operating lease liabilities are presented within Accrued Liabilities, and the non-current portion of operating lease liabilities are presented within Other Non-Current Liabilities on the consolidated balance sheet.

F-22

Operating lease ROU assets and operating lease liabilities are recognized based on the present value of the future minimum lease payments over the lease term at commencement date. As most of the Company's leases do not provide an implicit rate, the Company uses an incremental collateralized borrowing rate based on the information available at commencement date, including lease term, in determining the present value of future payments. The operating lease ROU asset also includes any lease payments made and excludes lease incentives and initial direct costs incurred. The Company's lease terms may include options to extend or terminate the lease when it is reasonably certain that the option will be exercised. Operating lease expense is recognized on a straight-line basis over the lease term.

The Company's operating lease portfolio includes field equipment such as compressors and amine units, office space and office equipment. The Company currently does not have any financing leases.

Our compressor and amine unit arrangements are typically structured with a non-cancelable primary term of one to two-years and continue thereafter on a month-to-month basis subject to termination by either party with thirty days notice. The Company's compressor and amine unit rental agreements represent operating leases with a lease term that equals the primary non-cancelable contract term. Upon completion of the primary term, both parties have substantive rights to terminate the lease. As a result, enforceable rights and obligations do not exist under the rental agreement subsequent to the primary term.

The Company enters into daywork contracts for drilling rigs with third parties to support its drilling activities. The drilling rig arrangements are typically structured with a term that is in effect until drilling operations are completed on a contractually-specified well or well pad. Upon mutual agreement with the contractor, the Company typically has the option to extend the contract term for additional wells or well pads by providing thirty days notice prior to the end of the original contract term. Drilling rig arrangements represent short-term operating leases. The accounting guidance requires the Company to make an assessment at contract commencement if it is reasonably certain that it will exercise the option to extend the term.

Due to the continuously evolving nature of the Company's drilling schedules and the potential volatility in commodity prices in an annual period, the Company's strategy to enter into shorter term drilling rig arrangements allows it the flexibility to respond to changes in our operating and economic environment. The Company exercises its discretion in choosing to extend or not extend contracts on a rig-by-rig basis depending on the conditions present at the time the contract expires. At the time of contract commencement, the Company has determined it cannot conclude with reasonable certainty if it will choose to extend the contract beyond its original term. Pursuant to the successful efforts method of accounting, these costs are capitalized as part of natural gas and oil properties on our balance sheet when paid.

The Company leases a small part of the corporate building it owns to a third-party, with a lease term that ends in 2023 and is non-cancelable. Third-party leasing income is insignificant and is included in Acquisition Costs and Other on the consolidated statements of operations.

The components of our total lease expense for 2020 and 2019 are as follows:


	Successor		Predecessor
In thousands	Month Ended December 31, 2020		Eleven Months Ended November 30, 2020		Year ended December 31, 2019
Operating Leases	$	0	$	45	$	273
Short-term leases(1)	246		2,665		2,766
Total lease expense	$	246	$	2,710	$	3,039
Short-term lease costs capitalized to oil and gas properties(2)	$	9	$	4,704	$	11,747

(1) Short-term leases represent expenses related to leases with a contract term of one year or less. The majority of these leases relate to field operating equipment and are included in lease operating expense and gas gathering, processing and transportation expense on the consolidated statement of operations.

(2) Short-term lease costs represent leases with a contract term of one year or less, the majority of which are related to drilling rigs and are capitalized as part of Oil and Gas Properties on the consolidated balance sheets.

F-23

Supplemental balance sheet information related to leases follows:


	Successor		Predecessor
In thousands, except lease term and discount rate data	December 31, 2020		December 31, 2019
Operating leases
Assets
Other property and equipment	$	0	$	45
Liabilities
Accrued liabilities	$	0	$	45


Weighted-average remaining lease term (years)	—		0.2
Weighted-average discount rate	0		5.0		%

Supplemental cash flow information related to leases follows:


	Successor		Predecessor
In thousands	Month Ended December 31, 2020		Eleven Months Ended November 30, 2020		Year ended December 31, 2019
Cash paid for amounts included in the measurement of lease liabilities
Operating cash flows for operating leases	$	0	$	45	$	273
Right-of-use assets obtained in exchange for lease obligations:
Operating leases	$	0	$	45	$	273

Note 6. Revenue Recognition

Operating revenues are comprised of sales of crude oil, NGLs and natural gas. Revenue is recognized when performance obligations under the terms of a contract with a customer are satisfied. The Company recognizes revenue when control has been transferred to the customer, generally at the time commodities reach an agreed-upon delivery point. Revenue is measured as the amount of consideration the Company expects to receive in exchange for transferring products and is generally based upon a negotiated formula, list or fixed price based on a market index. Typically, the Company sells its products directly to customers generally under agreements with payment terms less than 30 days.

Oil Revenues

Oil is sold at a contractually-specified index price plus or minus a differential; title and control of the product generally transfers at the delivery point specified in the contract, at which point related revenue is recognized. For those leases in which Lonestar operates with other working interest owners, the Company recognizes oil revenue proportionate to its entitled share of volumes sold. Currently, all of Lonestar’s oil production comes from the Eagle Ford Shale play in South Texas, and direct sales to four purchasers account for the majority of its oil sales.

The Company’s oil purchase contracts are generally written to provide month-to-month terms with a 30-day cancellation notice. Sales of Lonestar’s oil production are typically invoiced monthly based on actual volumes measured at the agreed-upon delivery point and stated contract pricing for the month.

F-24

NGLs and Natural Gas Revenues

The Company’s NGL and natural gas purchase contracts are generally structured such that Lonestar commits and dedicates for sale a specified volume of NGL and/or natural gas production per day from agreed-upon leases to a purchaser. NGLs and natural gas are sold at a percentage of index prices of each component less any stated deductions. Control transfers at the delivery point specified in the contract, which typically is stated as the inlet or tailgate of a plant where the produced NGLs and natural gas are processed for subsequent transportation and consumption. In certain situations, Lonestar takes processed natural gas in-kind from a processing plant for sale under a separate purchase agreement with a different delivery point. The stated delivery point determines whether certain conditioning, treating, transportation and fractionation fees associated with the sold NGLs and natural gas are treated as operating expenses (occurring before the delivery point) or as deductions to revenues (occurring after the delivery point).

For those leases in which Lonestar operates with other working interest owners, the Company recognizes NGL and natural gas revenue proportionate to its entitled share of volumes sold. Currently, all of Lonestar’s NGL and natural gas production comes from the Eagle Ford Shale play in South Texas. Sales of Lonestar’s NGL and natural gas production is typically invoiced monthly based on actual volumes at the agreed-upon delivery point and stated contract pricing and allocations for the month.

Lonestar uses a third-party broker for its NGL and natural gas marketing. In this capacity, the third-party is responsible for carrying out marketing activities such as submission of nominations, receipt of payments, submission of invoices and negotiation of contracts. In this agreement, Lonestar retains final approval of contracts and is not entitled to sales proceeds from the third-party until they are collected from the related purchasers. Commissions payable to the third-party broker for these services are treated as operating expenses in the financial statements.

Production Imbalances

Revenue is recorded based on the Company’s share of volumes sold, regardless of whether the Company has taken its proportional share of volumes produced. A receivable or liability is recognized only to the extent that the Company has an imbalance on a specific property greater than the expected remaining proved reserves. There were no imbalances at December 31, 2020 (Successor) and 2019 (Predecessor).

Significant Judgements

As noted above, the Company engages in various types of transactions in which midstream entities process its gas and subsequently market resulting NGLs and residue gas to third-party customers on Lonestar’s behalf. These types of transactions require judgement to determine whether Lonestar is the principal or the agent in the contract and, as a result, whether revenues are recorded gross or net.

The Company has determined that each unit of product represents a separate performance obligation under the terms of its purchase contracts, and therefore, future volumes are wholly unsatisfied. Therefore, the Company has utilized the practical expedient exempting a Company from disclosure of the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation.

Prior-Period Performance Obligations

The Company records revenue in the month production is delivered to the purchaser. Settlement statements for certain NGL and natural gas sales may not be received for 30 to 60 days after the date production is delivered, and as a result, Lonestar is required to estimate the amount of production that was delivered to the purchaser and the price that will be received for the sale of the product.

The Company records the differences between its estimates and the actual amounts received for product sales in the month that payment is received from the purchaser. Any identified differences between its revenue estimates and actual revenue received historically have not been significant. For the month ended December 31, 2020 (Successor), eleven months ended November 30, 2020 (Predecessor) and year ended December 31, 2019 (Predecessor), revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material.

F-25

Accounts Receivable and Other

Accounts receivable – Oil, natural gas liquid and natural gas sales consist of amounts due from purchasers for commodity sales from our Eagle Ford fields. Payments from purchasers are typically due by the last day of the month following the month of delivery. There was 0 bad debt expense for any period presented, and an allowance for uncollectible accounts is unnecessary. The Company’s operations do not result in any contract assets or liabilities on the accompanying consolidated balance sheets.

Note 7. Fair Value Measurements

~~In accordance with ASC 820,~~

Fair ~~Value Measurements and Disclosures, fair~~ value measurements are based upon inputs that market participants use in pricing an asset or liability, which are classified into two categories: observable inputs and unobservable inputs. Observable inputs represent market data obtained from independent sources, whereas unobservable inputs reflect a company’s own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. ASC 820 prioritizes the inputs used in measuring fair value into the following fair value hierarchy:

•Level 1 – Quoted prices for identical assets or liabilities in active markets.

•Level 2 – Quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability, and inputs derived principally from or corroborated by observable market data by correlation or other means.

•Level 3 – Unobservable inputs for the asset or liability. The fair value input hierarchy level to which an asset or liability measurement falls in its entirety is determined based on the lowest level input that is significant to the measurement in its entirety.

Assets and liabilities measured at fair value on a recurring basis

The following table presents Lonestar's assets and liabilities that are measured at fair value on a recurring basis as of December 31, 2020 (Successor) and 2019 (Predecessor):


	Fair Value Measurements Using
In thousands	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
December 31, 2020 (Successor)
Assets:
Commodity derivatives	$	0	$	2,098	$	0	$	2,098
Liabilities:
Commodity derivatives	0		(8,773)		0		(8,773)
Total	$	0	$	(6,675)	$	0	$	(6,675)

December 31, 2019 (Predecessor)
Assets:
Commodity derivatives	$	0	$	6,849	$	0	$	6,849
Liabilities:
Commodity derivatives	0		(10,462)		0		(10,462)
Warrants	0		0		(364)		(364)
Stock-based compensation	(1,792)		0		(573)		(2,365)
Total	$	(1,792)	$	(3,613)	$	(937)	$	(6,342)

F-26

Commodity Derivatives

The Company's commodity derivatives represent non-exchange-traded oil and natural gas fixed-price swaps that are based on NYMEX pricing and fixed-price basis swaps that are based on regional pricing other than NYMEX (e.g., Louisiana Light Sweet). The asset and liability measurements for the Company's commodity derivative contracts represent Level 2 inputs in the hierarchy, as they are valued based on observable inputs other than quoted prices.

Warrants

The fair value of the Predecessor's warrants is based on Black-Scholes valuations. In addition to the Predecessor's observable stock price, other significant inputs are considered unobservable, and the Company has designated these estimates as Level 3.

Stock-Based Compensation

The Predecessor's stock-based compensation includes the liability associated with restricted stock units ("RSUs") and stock appreciation rights ("SARs") dependent on the fair value of the Predecessor's publicly-traded common stock. The fair value of RSUs is measured based on measurable prices on a major exchange; the significant inputs to these asset exchange values represented Level 1 independent active exchange market price inputs. The Black-Scholes model used to determine the fair value of the SARs uses inputs, in addition to the Predecessor's observable stock price, that are considered unobservable; to this end the Predecessor has designated these estimates as Level 3. See Note 13. Stock-Based Compensation below for more information.

Level 3 gains and losses

The table below sets forth a summary of changes in the fair value of the Company’s Level 3 liabilities for the year ended December 31, 2020.


	Successor		Predecessor
In thousands	Month Ended December 31, 2020		Eleven Months Ended November 30, 2020		Year Ended December 31, 2019
Fair value of Level 3 instruments, beginning of period	$	0	$	(937)	$	(1,691)
Unrealized gains	0		0		754
Extinguishment of Level 3 instruments on Effective Date	0		937		0
Fair value of Level 3 instruments, end of period	$	0	$	0	$	(937)

Assets and liabilities measured at fair value on a nonrecurring basis

Non-recurring fair value measurements include certain ~~nonfinancial~~non-financial assets and liabilities as may be acquired in a business combination and thereby measured at fair value; impaired oil and natural gas property assessments; warrants issued in debt or equity offerings and the initial recognition of asset retirement obligations for which fair value is used. Non-recurring fair value measurements also include certain non-financial assets and liabilities as part of fresh-start accounting on the Effective Date (see Note 3. Fresh-Start Accounting). These estimates are derived from historical costs as well as management’s expectation of future cost environments. As there is no corroborating market activity to support the assumptions used, the Company has designated these estimates as Level 3.

~~F-12~~

~~The following tables present the Company’s assets and liabilities that are measured at~~

Other fair value ~~on a recurring basis as of December 31, 2017 and 2016, for each fair value hierarchy level:~~

measurements

Fair Value Measurements Using

In thousands

Quoted
Prices in
Active
Markets for
Identical
Assets
(Level 1)

Significant
Other
Observable
Inputs
(Level 2)

Significant
Unobservable
Inputs
(Level 3)

Total

December 31, 2017

Assets:

Commodity derivatives

$
—

$
472

$
—

$
472

Liabilities:

Commodity derivatives

—

(22,138
)

—

(22,138
)
Equity warrant liability

—

—

(508
)

(508
)
Equity warrant liability - related parties

—

—

(963
)

(963
)
Stock appreciation rights

—

—

(314
)

(314
)
Total

$
—

$
(21,666
)

$
(1,785
)

$
(23,451
)

December 31, 2016

Assets:

Commodity derivatives

$
—

$
1,730

$
—

$
1,730

Liabilities:

Commodity derivatives

—

(4,110
)

—

(4,110
)
Equity warrant liability

—

—

(1,565
)

(1,565
)
Equity warrant liability - related parties

—

—

(2,994
)

(2,994
)
Total

$
—

$
(2,380
)

$
(4,559
)

$
(6,939
)

~~Level 3 Gains and Losses~~

~~The table below sets forth a summary of changes in the fair value of the Company’s Level 3 liability for the year ended December 31, 2017.~~

In thousands

Equity Warrant Liability

Stock Appreciation Rights

Total

Balance at December 31, 2016

$
(4,559
)

$
—

$
(4,559
)
Purchases, sales, issuances and settlements (net)

—

(72
)

(72
)
Unrealized gains/(losses)

3,088

(242
)

2,846

Balance at December 31, 2017

$
(1,471
)

$
(314
)

$
(1,785
)

~~Long-Lived Assets~~

Due to declines in commodity prices and estimated reserves over the last three years, there were indications that the carrying value of certain oil and natural gas properties may be impaired and undiscounted future cash flows attributed to these assets indicated their carrying amounts were not expected to be recovered. Their fair value was measured using an income approach based upon internal estimates of future production levels, prices, drilling and operating costs and discount rates, which are Level 3 inputs. We also considered the potential sale of certain of these properties. During 2017, we impaired $4.8 million of proved undeveloped leasehold costs in Wilson County. During 2016, we impaired $21.1 million of proved undeveloped leasehold costs in Texas, in connection with the sale of the Company’s conventional oil and natural gas assets.

~~F-13~~

~~Other Fair Value Measurements~~

The book values of cash and cash equivalents, ~~receivables for oil, NGL and natural gas sales, joint interest billings, notes and other receivables~~accounts receivable and accounts payable approximate fair value due to the short-term nature of these instruments. The carrying value of debt approximates fair value since it is subject to a short-term floating interest rate that approximates the rate available to the ~~Company, except for bonds, which are recorded at amortized cost less debt issuance costs. The fair value of the 8.750% Senior Notes (as defined in~~ Company.

F-27

Note 9 below) approximates $158.9 million as of December 31, 2017, and the notes are considered a Level 3 liability, as they are based on market transactions that occur infrequently as well as internally generated inputs. ~~The Company’s other Level 3 financial liabilities measured at fair value consist of the warrant liability as of~~ ~~December 31, 2017.~~ Significant unobservable inputs used in the fair value measurement of the warrants include the estimated term. Significant decreases in the estimated remaining period to exercise would result in a significantly lower fair value measurement.

~~6. Oil and Gas Properties~~

~~A summary of oil and gas properties follows:~~

December 31,

In thousands

2017

2016

Proved properties and equipment

$
750,226

$
538,695

Unproved properties

78,655

72,584

Less accumulated depletion and impairment

(257,718
)

(172,051
)
Total oil and gas properties

$
571,163

$
439,228

7.8. Asset Retirement Obligations

~~Pursuant to ASC 410, Asset Retirement Obligations,~~ ~~the Company~~

Lonestar recognizes ~~the fair value of~~ its asset retirement obligations related to the plugging, abandonment and remediation of oil and gas producing properties. The present value of the estimated asset retirement costs has been capitalized as part of the carrying amount of the related long-lived ~~assets, which approximated $5.3 million as of December 31, 2017.~~

assets. The liability has been accreted to its present value as of December 31, ~~2017. The Company evaluated its wells and has determined a range of abandonment dates through December 2066.~~

2020 (Successor).

The following ~~represents~~provides a reconciliation of activity in the asset retirement ~~obligations:~~

obligations for 2020 and 2019:

Year Ended December 31,

In thousands

2017

2016

Asset retirement obligations at beginning of period

$
2,683

$
7,488

Wells drilled during the year

220

154

Wells acquired during the year

2,797

28

Wells sold during the year

—

(4,780
)
Accretion of discount

139

180

Revisions of previous estimates (1)

(190
)

(205
)
Wells plugged and abandoned during the year

—

(182
)
Asset retirement obligations at end of period

$
5,649

$
2,683


	Successor		Predecessor
In thousands	Month Ended December 31, 2020		Eleven Months Ended November 30, 2020		Year Ended December 31, 2019
Beginning asset retirement obligations	$	4,358	$	7,055	$	7,195
Wells drilled during the year	0		4		26


Wells sold during the year	0		0		(388)
Accretion expense	38		316		300
Revisions in estimated retirement obligations(1)	177		(3,017)		191
Wells plugged and abandoned during the year	0		0		(269)
Ending asset retirement obligations	$	4,573	$	4,358	$	7,055

~~(1)~~

~~Revisions of previous estimates during the year ended December 31, 2017~~(1)Revisions of previous estimates during months ended December 31, 2020 (Successor) and the year ended December 31, 2019 (Predecessor) are primarily attributable to changes in estimates ~~of the timing of future costs for oilfield services required to plug and abandon wells.~~

~~F-14~~

~~8. Accrued Liabilities~~

~~Accrued liabilities consist~~ of the ~~following:~~

timing of future costs for oilfield services required to plug and abandon wells. Revisions of previous estimates during the eleven months ended November 30, 2020 (Predecessor) are primarily due to the change in fair value resulting from the Company's fresh-start accounting (see Note 3. Fresh-Start Accounting)

Year Ended December 31,

In thousands

2017

2016

Bonus payable

$
2,250

$
2,155

Payroll payable

18

1

Accrued interest - 8.750% Senior Notes

2,768

2,924

Accrued interest - other

1,015

523

Accrued rent

156

298

Accrued well costs

8,386

3,366

Accrued severance, property, federal and franchise taxes

115

431

Accrued federal income tax

1,147

—

Other

728

249

Total accrued liabilities

$
16,583

$
9,947

Note 9. Accrued Liabilities

The following table provides detail of Lonestar's accrued liabilities as of December 31, 2020 (Successor) and 2019 (Predecessor):


	Successor		Predecessor
In thousands	December 31, 2020		December 31, 2019
Bonus payable	$	1,363	$	2,353
Accrued interest - 11.25% Senior Notes	0		14,063
Accrued well costs	1,752		8,932
Third party payments for joint interest expenditures	5,178		0
Accrued professional fees (success fees)	4,710		0
Other	2,980		1,557
Total accrued liabilities	$	15,983	$	26,905

F-28

Note 10. Long-Term Debt

~~Long-term~~

The following long-term debt ~~consists~~obligations were outstanding as of December 31, 2020 (Successor) and 2019 (Predecessor):


	Successor		Predecessor
In thousands	December 31, 2020		December 31, 2019
Successor Senior Secured Credit Facility	$	209,600	$	—
Successor Second-Out Term Loan	55,000		—
Predecessor Senior Secured Credit Facility	—		247,000
11.25% Senior Notes due 2023	—		250,000
Mortgage debt	8,712		8,931
PPP loan	2,157		—
Other	261		271
Total	275,730		506,202
Less unamortized discount	(402)		(3,375)
Less unamortized debt issuance costs	0		(759)
Total net of discount and debt issuance costs	275,328		502,068
Less current obligations(1)	(20,000)		(247,000)
Long-term debt	$	255,328	$	255,068

(1) Current obligations for the ~~following:~~

December 31,

In thousands

2017

2016

Credit Facility

$
142,080

$
43,500

Second Lien Notes

—

11,367

8.750% Senior Notes

151,848

151,848

Less unamortized discount on 8.750% Senior Notes

(949
)

(1,708
)
Less deferred financing costs on 8.750% Senior Notes

(474
)

(851
)
Less deferred financing costs on Second Lien Notes

—

(316
)
Mortgage debt

7,891

—

Other

759

282

Total long-term debt

$
301,155

$
204,122

Successor represent four quarterly $5.0 million principal payments due in 2021 and, for the Predecessor, the Senior Secured Credit Facility

~~On July 28, 2015, LRAI closed a Credit Agreement for a $500 million~~ obligations which were classified as current liabilities as of December 31, 2019.

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.

F-29

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. 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 (as amended, supplemented or modified from time to time,~~thereto. All of the “Credit Facility”). The Credit Facility had a maturity date of October 16, 2018 as of December 31, 2017. Consequent to redeeming the 8.750% Senior Notes (as defined below) in January 2018, the Credit Facility’s maturity date was extended to July 28, 2020. Due to the Company’s ability and intent to refinance the 8.750% Notes as of December 31, 2017, thePredecessor Credit Facility was ~~classified~~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.

The contractual interest expense on the 11.25% Notes is in excess of recorded interest expense by $4.7 millionfrom the Petition Date until the Effective Date and was not included as ~~a long-term liability~~interest expense on the Consolidated ~~Balance Sheets as~~Statements of ~~said date. See Note 16,~~ ~~Subsequent Events~~,Operations for ~~more information. As of December 31, 2017 and 2016, $142.1 and $43.5 million was borrowed, respectively, under~~ the ~~Credit Facility.~~ ~~Borrowing availability was approximately $17.4 million at December 31, 2017.~~

~~The Credit Facility may be used for loans and, subject to a $2.5 million sub-limit, letters of credit, and provides for a commitment fee of 0.375% to 0.5% based~~Predecessor period because the Company discontinued accruing interest on the ~~unused portion of the borrowing base under the Credit Facility.~~

As of December 31, 2017, the borrowing base and lender commitments for the Credit Facility were $160.0 million. The borrowing base under the Credit Facility is determined semi-annually as of May 1 and November 1. On January 4, 2018, the Seventh Amendment and Limited Waiver, Borrowing Base Redetermination Agreement, and Amendment No. 7 to Credit Agreement dated January 4, 2018 reaffirmed the borrowing base at $160.0 million. This January 2018 redetermination constituted the regularly scheduled November 1 determination. See Note 16, ~~Subsequent Events, for more information.~~

~~F-15~~

~~Borrowings under the Credit Facility, at LRAI’s election, bear interest at either: (i) an alternate base rate (“ABR”) equal~~11.25% Senior Notes subsequent to the higher of (a) the Prime Rate, (b) the Federal Funds Effective Rate plus 0.5% per annum, and (c) the adjusted LIBO rate of a three-month interest period on such day plus 1.0%; or (ii) the adjusted LIBO rate, which is the rate stated on Reuters screen LIBOR01 page, for one, two, three, six or twelve months, as adjusted for statutory reserve requirements for Eurocurrency liabilities, plus, in each of the cases described in clauses (i) and (ii) above, an applicable margin ranging from 1.50% to 2.50% for ABR loans and from 2.50% to 3.50% for adjusted LIBO rate loans (5.13% at December 31, 2017).

Subject to certain permitted liens, LRAI’s obligations under the Credit Facility have been secured by the grant of a first priority lien on no less than 80% of the value of the proved oil and gas properties of the Company and its subsidiaries (currently 90%).

The Credit Facility contains two financial covenants, as defined in the Credit Facility: (a) a maximum debt to EBITDAX ratio (discussed further below) and (b) a current ratio of not less than 1.0 to 1.0. As of December 31, 2017, the Company was in compliance with the minimum debt to EBITDAX ratio; however, the current ratio as of December 31, 2017 was approximately 0.7 to 1.0 due to low availability under the Credit Facility. Upon closing of the 11.250% Senior Notes, as defined below, in January 2018, the Credit Facility’s outstanding balance was paid down by $80.0 million, which increased the Credit Facility’s availability to a level sufficient for purposes of the current ratio. The Company obtained a limited waiver agreement for the current ratio violation from the Credit Facility’s lenders prior to issuance of the Company’s Form 10-K and Annual Report.

In connection with closing the Marquis Acquisition and the Battlecat Acquisition, on June 15, 2017, LRAI entered into the Sixth Amendment and Joinder to Credit Agreement (the “Sixth Amendment”) to (i) increase the borrowing base from $112 million to $160 million until redetermined or adjustedPetition Date in accordance with ASC 852. The Company did not make any interest payments on the Credit Facility, (ii) modify the maximum leverage ratio threshold to be 4.0 to 1.0 for all periods, starting with the fiscal quarter ending September 30, 2017, and providing that EBITDAX (as defined in the Credit Facility) shall be calculated at the end of each fiscal quarter using the results of the twelve-month period ending with that fiscal quarter end; provided, that EBITDAX shall be calculated (x) at the end of the fiscal quarter ending September 30, 2017 using an amount equal11.25% Senior Notes subsequent to the EBITDAX for such fiscal quarter, multiplied by four, (y) at the end of the fiscal quarter ending December 31, 2017 using an amount equal to the EBITDAX for the two fiscal quarter period ended on such date, multiplied by two and (z) at the end of the fiscal quarter ending March 31, 2018 using an amount equal to the EBITDAX for the three fiscal quarter period ended on such date, multiplied by four-thirds, (iii) permit LRAI to declare and pay dividends to the Company equal to the amount of any cash dividends declared and payable in accordance with the terms of the Company’s Certificate of Designations of Convertible Participating Preferred Stock, Series A-1, and Certificate of Designations of Convertible Participating Preferred Stock, Series A-2, subject to certain specified terms and conditions and (iv) amend certain other provisions of the Credit Facility as more specifically set forth in the Sixth Amendment.

~~8.750% Senior Notes~~

~~On April 4, 2014, LRAI issued, at par, $220.0 million of 8.750% Senior Unsecured Notes due April 15, 2019 (the “8.750% Senior Notes”) to U.S.-based institutional investors.~~

On or after April 15, 2016, LRAI could redeem the 8.750% Senior Notes in whole or in part at the redemption prices (expressed as percentages of the principal amount) set forth in the following table plus accrued and unpaid interest, if any, on the 8.750% Senior Notes redeemed, to the applicable date of redemption, if redeemed during the twelve-month period beginning on April 15 of the years indicated below:

Petition Date.

Year

Percentage

2017

104.375
%
2018 and thereafter

100.000
%

The 8.750% Senior Notes has covenants that, among other things, limit the ability of LRAI and its subsidiaries to: incur indebtedness; pay dividends or make other distributions on stock; purchase or redeem stock or subordinated indebtedness; make investments; create liens; enter into transactions with affiliates; sell assets; refinance certain indebtedness; and merge with or into other companies or transfer substantially all of LRAI’s assets.

~~In January 2018, the Company redeemed the 8.750% Senior Notes in whole using proceeds from the 11.250% Senior Notes, as defined below. See Note 16,~~ ~~Subsequent Events, for more information.~~

~~F-16~~

Debt Issuance Costs

On August 2, 2016, LRAI and the Company entered into a Securities Purchase Agreement (the “Purchase Agreement”) with Juneau, as initial purchaser, Leucadia as guarantor of Juneau’s obligations, the other purchasers party thereto and Jefferies, LLC, in its capacity as the collateral agent for the purchasers, relating to the issuance and sale of (i) up to $49.9 million aggregate principal amount of LRAI’s 12% senior secured second lien notes due 2021 (“Second Lien Notes”) and (ii) five-year warrants to purchase up to an aggregate 998,000 shares of the Company’s Class A voting common stock at a price equal to $5.00 per share (the “Warrants”). During 2016, LRAI issued $25.0 million in aggregate principal amount of Second Lien Notes and the Company issued Warrants to purchase 500,000 shares of its Class A voting common stock to Juneau. In December 2016, LRAI repaid to Juneau $21.0 million principal of the Second Lien Notes with proceeds from the 2016 Common Stock Offering.

In connection with entering into the Purchase Agreement, the Company also entered into a registration rights agreement and an equity commitment agreement, both dated as of August 2, 2016. Pursuant to the registration rights agreement, the Company has agreed to register for resale certain Class A voting common stock issued or issuable to Juneau and Leucadia, including those issuable upon exercise of the Warrants. Leucadia agreed, pursuant to the equity commitment agreement, to purchase a certain number of Class A voting common stock in case the Company elected to pursue an equity offering prior to December 31, 2016. Pursuant to the equity commitment agreement, Leucadia purchased 3,478,261 shares of Class A voting common stock (costing $20 million) through the 2016 Common Stock Offering, which closed on December 22, 2016. In connection with Leucadia’s equity commitment, the Company paid Leucadia on January 3, 2017 a $1.0 million fee, which was recorded as a reduction to additional paid-in capital. In the event Leucadia purchased not less than its commitment amount, the Company agreed to use commercially reasonable efforts to enter into arrangements to provide Leucadia with the right to appoint one director to the Board of the Company, provided that such right will terminate at such time as Leucadia and its affiliates own a number of shares of Class A voting common stock equal to less than 50% of the shares purchased by Leucadia and its affiliates in such offering. Leucadia has elected to take an observer position on the board of directors, with no voting rights.

On October 26, 2016, the Company entered into a Board Representation Agreement (the “Board Representation Agreement”) with EF Realisation Company Limited (“EF Realisation”). Under the Board Representation Agreement, for as long as EF Realisation, together with its affiliates, beneficially owns 15% or more of the issued and outstanding shares of the Company’s Class A voting common stock, it has the right to nominate up to, but no more than, two directors to serve on the Board and for as long as EF Realisation, together with its affiliates, beneficially owns at least 10% but less than 15% of the Company’s issued and outstanding shares of Class A voting common stock, it has the right to nominate up to, but no more than, one director to serve on the Board.

On October 26, 2016, the Company entered into a Registration Rights Agreement with EF Realisation, pursuant to which the Company agreed to register for resale Class A voting common stock indirectly owned by EF Realisation. The Company agreed to file a registration statement providing for the resale of Class A voting common stock held by EF Realisation no later than the earlier of (i) October 26, 2017, and (ii) 30 days after the date the Company first becomes eligible to file a registration statement on Form S-3. The Form S-3 registration statement was filed with the Securities and Exchange Commission on November 7, 2017, and is effective. The Company has also granted EF Realisation certain piggyback and demand registration rights.

Rent expense was approximately $439 and $375 thousand for the years ended December 31, 2017 and 2016, respectively. The Company relocated its corporate office to an owned building in February 2018 but will continue to be responsible for the minimum annual lease payments noted above regardless of subrental income, if any, the Company will receive from the property going forward.

As a result of the redemption of the 8.750% Senior Notes, the issuance of the 11.250% Senior Notes and the existing terms of the Credit Facility, the maturity date of the Credit Facility was extended in January 2018 from October 16, 2018, to July 28, 2020.


Delaware						81-0874035
(State or other jurisdiction of incorporation or organization)						(I.R.S. Employer Identification No.)

111 Boland Street, Suite ~~300,~~301, Fort Worth, TX						76107
(Address of principal executive offices)						(Zip Code)


Title of Each Class	Trading Symbol	Name of Exchange on Which Registered
~~Class A Voting~~ Common Stock, par value $0.001 ~~per share~~	LONE	~~Nasdaq Global Select~~OTCQX Best Market


					Page

PART I					~~Page~~
Item 1.			Business		6
~~PART I~~
~~Item 1.~~	~~Business~~	3
Item 1A.	Risk Factors			23 28
Item 1B.			Unresolved Staff Comments		43 53
Item 2.			Properties		43 53
Item 3.			Legal Proceedings		43 53
Item 4.			Mine Safety Disclosures		43 54

PART II
Item 5.			Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		47 55
~~Item 6.~~			~~Selected Financial Data~~	48
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations			51 56
Item 7A.			Quantitative and Qualitative Disclosures About Market Risk		65 74
Item 8.			Financial Statements and Supplementary Data		67 75
Item 9.			Changes in and Disagreements With Accountants on Accounting and Financial Disclosure		67 75
Item 9A.			Controls and Procedures		68 76
~~Item 9B.~~			~~Other Information~~		68

PART III
Item 10.			Directors, Executive Officers and Corporate Governance		69 78
Item 11.			Executive Compensation		69 80
Item 12.			Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		69 80
Item 13.			Certain Relationships and Related Transactions, and Director Independence		69 80
Item 14.			Principal Accounting Fees and Services		69 80

PART IV
Item 15 ~~Item 16~~ 15.			Exhibits Financial Statement Schedules		81
Item 16			Form 10-K Summary		70 70 85

	High		Low
2017
First Quarter	$	8.70	$	4.48
Second Quarter		5.65		3.31
Third Quarter		4.57		2.43
Fourth Quarter		4.15		3.13
2016
Third Quarter (beginning July 5, 2016)	$	16.00	$	5.99
Fourth Quarter		10.35		5.81


	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)	%

	Gross	Net	Average Working	Identified Drilling Locations (1)(2)		Producing Wells		Average Daily Production	Capex	Planned Wells (Net) (3)
	Acreage	Acreage	Interest	Gross	Net	Gross	Net	Boe/d	2018	2018
Eagle Ford
Western	16,635	14,904	90%	49	46	59	55	3,453	34%	4
Central	47,273	33,065	70%	173	125	151	113	2,394	66%	11
Eastern	14,289	10,293	72%	32	16	28	17	648	0%	0
Total	78,197	58,262	75%	254	187	238	185	6,495	100%	15

	As of December 31,
	2017		2016
Estimated Proved Reserves (1)
Eagle Ford Shale:
Oil (MBbls)		50,701		24,288
NGLs (MBbls)		10,875		7,466
Natural Gas (MMcf)		71,874		52,714
Total Estimated Proved Reserves (MBoe) (2)		73,555		40,540
Estimated Proved Developed Reserves
Eagle Ford Shale:
Oil (MBbls)		12,657		6,268
NGLs (MBbls)		2,846		2,274
Natural Gas (MMcf)		17,034		14,734
Total Estimated Proved Developed Reserves (MBoe)(2)		18,342		10,998
Estimated Proved Undeveloped Reserves
Eagle Ford Shale:
Oil (MBbls)		38,044		18,021
NGLs (MBbls)		8,029		5,191
Natural Gas (MMcf)		54,840		37,980
Total Estimated Proved Undeveloped Reserves (MBoe)(2)		55,213		29,542
Standardized Measure (millions) (3)	$	479.6	$	145.8
PV-10 (millions)(4)	$	538.3	$	166.5
Oil and Gas Prices Used (1) :
Oil — NYMEX-WTI per Bbl	$	51.34	$	42.75
Natural Gas — NYMEX-Henry Hub per MMBtu		2.98		2.46

	As of December 31, 2017
	Developed Acreage				Undeveloped Acreage				Total Acreage
	Gross		Net		Gross		Net		Gross		Net
Western Region		6,385		6,032		10,249		8,872		16,634		14,904
Central Region		13,460		9,948		33,813		23,117		47,273		33,065
Eastern Region		1,393		951		12,896		9,342		14,289		10,293
Total Eagle Ford		21,238		16,931		56,958		41,331		78,196		58,262

~~Name~~	~~Position~~	~~Age~~
~~Frank D. Bracken, III~~	~~Chief Executive Officer and Director~~		54
~~Barry D. Schneider~~	~~Chief Operating Officer~~		55
~~Douglas W. Banister~~	~~Chief Financial Officer~~		55
~~Thomas H. Olle~~	~~Vice President - Reservoir Engineering~~		63
~~Jana Payne~~	~~Vice President - Geosciences~~		56
~~Gregory R. Packer~~	~~Vice President - General Counsel & Corporate Secretary~~		38
~~John Pinkerton~~	~~Chairman~~		64
~~Henry Ellis~~	~~Director~~		68
~~Daniel R. Lockwood~~	~~Director~~		60
~~John H. Murray~~	~~Director~~		71
~~Matthew B. Ockwood~~	~~Director~~		34
~~Stephen H. Oglesby~~	~~Director~~		68
~~Phillip Z. Pace~~	~~Director~~		54
~~Dr. Christopher Rowland~~	~~Director~~		63
~~Randy L. Wolsey~~	~~Director~~		68

	Year Ended December 31,
In thousands except shares and per share amounts	2017			2016
Consolidated Statements of Operations Data:
Oil and gas revenues	$	94,068		$	57,972
Net loss (1)(2)		(38,663	)		(94,335	)
Net loss attributable to common stockholders		(42,631	)		(94,335	)
Net loss attributable to common stockholders per share:
Basic	$	(1.92	)	$	(11.64	)
Diluted		(1.92	)		(11.64	)
Weighted average number of common shares outstanding:
Basic		22,252,149			8,106,931
Diluted		22,252,149			8,106,931
Consolidated Balance Sheets Data (As of December 31):
Total assets (3)	$	606,800		$	459,109
Total long-term liabilities		327,498			259,961
Stockholder's equity		215,346			166,395

	SEC (1)				NYMEX (1)(2)
	As of December 31,
	2017		2016		2017
Estimated Proved Reserves(2)
Eagle Ford Shale:
Oil (MBbls)		50,701		24,288		52,463
NGLs (MBbls)		10,875		7,466		11,295
Natural Gas (MMcf)		71,874		52,714		74,885
Total Estimated Proved Reserves (MBoe)(3)		73,555		40,540		76,239
Estimated Proved Developed Reserves
Eagle Ford Shale:
Oil (MBbls)		12,657		6,268		13,497
NGLs (MBbls)		2,846		2,274		3,069
Natural Gas (MMcf)		17,034		14,734		18,455
Total Estimated Proved Developed Reserves (MBoe)(3)		18,342		10,998		19,642
Estimated Proved Undeveloped Reserves
Eagle Ford Shale:
Oil (MBbls)		38,044		18,021		38,965
NGLs (MBbls)		8,029		5,191		8,226
Natural Gas (MMcf)		54,840		37,980		56,431
Total Estimated Proved Undeveloped Reserves (MBoe)(3)		55,213		29,542		56,596
Standardized Measure (millions)(5)	$	479.6	$	145.8	N/A
PV-10 (millions)(4)	$	538.3	$	166.5	$	647.6
Oil and Gas Prices Used(2):
Oil—NYMEX-WTI per Bbl	$	51.34	$	42.75	N/A
Natural Gas—NYMEX-Henry Hub per MMBtu		2.98		2.46	N/A


	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


	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)	%


	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

	Year Ended December 31, 2017								As Of December 31, 2017
	Wells Drilled				Wells Brought on Production				Wells Drilled But Uncompleted				Wells Producing
Eagle Ford Region	Gross		Net		Gross		Net		Gross		Net		Gross		Net
Western		2.0		1.6		5.0		4.8		—		—		59.0		55.3
Central		6.0		5.8		6.0		6.0		2.0		1.8		151.0		112.5
Eastern		1.0		0.5		1.0		0.5		—		—		28.0		16.9
Total		9.0		7.9		12.0		11.3		2.0		1.8		238.0		184.7

~~Delaware~~	~~81-0874035~~

	Year Ended December 31,
In thousands, except per Boe	2017		2016		% Change
Operating Expenses:
Lease operating and gas gathering	$	16,763	$	16,232		3	%
Production and ad valorem taxes		5,523		3,287		68	%
Rig standby expense		622		2,261		-73	%
Depreciation, depletion, amortization and accretion		52,857		47,068		12	%
General and administrative (1)		10,997		11,319		-3	%

Operating Expenses per Boe:
Lease operating and gas gathering	$	7.07	$	7.52		-6	%
Production and ad valorem taxes		2.33		1.52		53	%
Rig standby expense		0.26		1.05		-75	%
Depreciation, depletion, amortization and accretion		22.30		27.06		-18	%
General and administrative (1)		4.64		5.24		-12	%
(1)Excludes stock-based compensation and acquisitions costs.


	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


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

Instrument	Total Volume	Settlement Period	Fixed Price
Oil – WTI Fixed Price Swap	365,000 Bbl	January – December 2018	$	54.18
Oil – WTI Fixed Price Swap	182,500 Bbl	January – December 2018		55.65
Oil – WTI Fixed Price Swap	182,500 Bbl	January – December 2018		55.50
Oil – WTI Fixed Price Swap	292,000 Bbl	January – December 2018		47.10
Oil – WTI Fixed Price Swap	509,000 Bbl	January – December 2018		50.17
Oil – WTI Fixed Price Swap	508,900 Bbl	January – December 2019		50.40
Oil – WTI Fixed Price Swap	560,700 Bbl	January – December 2019		48.04
Oil – WTI Fixed Price Swap	401,500 Bbl	January – December 2019		50.90
Oil – WTI Fixed Price Swap	203,600 Bbl	January – June 2020		48.90
Natural Gas – Henry Hub NYMEX Fixed Price Swap	1,825,000 MMBtu	January – December 2018		3.09

In thousands	December 31, 2017
Acquisition of oil and gas properties	$	113,726
Development of oil and gas properties		81,875
Purchases of other property and equipment		13,142
Total capital expenditures, net	$	208,743

				Hypothetical Change in Fair Value
	Fair Value			10% Increase In Commodity Price			10% Decrease In Commodity Price						Hypothetical Fair Value
(in thousands)										(in thousands)	Fair Value		10% Increase In Commodity Price		10% Decrease In Commodity Price
Swaps	$	(20,571	)	$	(39,424	)	$	(1,717	)	Swaps	$	(6,675)	$	5,791	$	(19,140)
Collars		(408	)		(1,362	)		545

~~Instrument~~	~~Total Volume~~	~~Settlement Period~~	~~Fixed Price~~
~~Oil – WTI Fixed Price Swap~~	~~365,000 Bbl~~	~~January – December 2018~~		~~$ 54.18~~
~~Oil – WTI Fixed Price Swap~~	~~182,500 Bbl~~	~~January – December 2018~~		~~55.65~~
~~Oil – WTI Fixed Price Swap~~	~~182,500 Bbl~~	~~January – December 2018~~		~~55.50~~
~~Oil – WTI Fixed Price Swap~~	~~292,000 Bbl~~	~~January – December 2018~~		~~47.10~~
~~Oil – WTI Fixed Price Swap~~	~~509,000 Bbl~~	~~January – December 2018~~		~~50.17~~
~~Oil – WTI Fixed Price Swap~~	~~508,900 Bbl~~	~~January – December 2019~~		~~50.40~~
~~Oil – WTI Fixed Price Swap~~	~~560,700 Bbl~~	~~January – December 2019~~		~~48.04~~
~~Oil – WTI Fixed Price Swap~~	~~401,500 Bbl~~	~~January – December 2019~~		~~50.90~~
~~Oil – WTI Fixed Price Swap~~	~~203,600 Bbl~~	~~January – June 2020~~		~~48.90~~
~~Natural Gas – Henry Hub NYMEX Fixed Price Swap~~	~~1,825,000 MMBtu~~	~~January – December 2018~~		~~3.09~~


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					*

		Incorporated by Reference .
Exhibit Number	Description	Form	File No.	Exhibit	Filing Date	Filed/ Furnished Herewith
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
2.2	Purchase and Sale Agreement by and between Lonestar Resources US Inc. and Battlecat Oil & Gas, LLC, dated as of May 26, 2017	8-K	001-37670	2.1	6/2/17
2.3	Amendment No. 1, dated June 15, 2017, to the Purchase and Sale Agreement, by and between Lonestar Resources US Inc. and Battlecat Oil & Gas, LLC, dated May 26, 2017	8-K	001-37670	2.1	6/21/17
2.4	Purchase and Sale Agreement by and between Lonestar Resources US Inc. and SN Marquis LLC, dated as of May 26, 2017	8-K	001-37670	2.2	6/2/17
2.5	Amendment No. 1, dated June 15, 2017, to the Purchase and Sale Agreement by and between Lonestar Resources US Inc. and SN Marquis LLC, dated as of May 26, 2017	8-K	001-37670	2.2	6/21/17
3.1	Certificate of Incorporation of Lonestar Resources US Inc.	10-12B	001-37670	3.1	12/31/15
3.2	Certificate of Amendment to the Certificate of Incorporation of Lonestar Resources US Inc.	10-K	001-37670	3.2	3/23/17
3.3	Certificate of Amendment to Certificate of Incorporation of Lonestar Resources US Inc., dated May 24, 2017	8-K	001-37670	3.1	5/26/17
3.4	Amended and Restated Bylaws of Lonestar Resources US Inc.	8-K	001-37670	3.1	4/7/17
3.5	Certificate of Designations of Series B Convertible Preferred Stock	8-K	001-37670	3.1	6/21/17
3.6	Certificate of Designations of Series A-1 Convertible Participating Preferred Stock	8-K	001-37670	3.2	6/21/17
3.7	Certificate of Designations of Series A-2 Convertible Participating Preferred Stock	8-K	001-37670	3.3	6/21/17
4.1	Registration Rights Agreement dated August 2, 2016 by and among Lonestar Resources US Inc., Leucadia National Corporation and Juneau Energy, LLC.	8-K	001-37670	4.1	8/3/16
4.2	Amendment No. 1, dated June 15, 2017, to the Registration Rights Agreement by and among Lonestar Resources US Inc., Leucadia National Corporation and Juneau Energy, LLC (n/k/a JETX Energy, LLC)	8-K	001-37670	4.4	6/21/17
4.3	Registration Rights Agreement, dated October 26, 2016 between Lonestar Resources US Inc. and EF Realisation Company Limited	8-K	001-37670	4.1	11/1/16
4.4	Amendment No. 1, dated June 15, 2017, to the Registration Rights Agreement by and between Lonestar Resources US Inc. and EF Realisation Company Limited	8-K	001-37670	4.5	6/21/17
4.5	Registration Rights Agreement, dated as of June 15, 2017, by and between Lonestar Resources US Inc. and Battlecat Oil & Gas, LLC	8-K	001-37670	4.1	6/21/17


	Class A				Series A-1				Series B						Additional						Accumulated Other			Total
	Common Stock				Preferred Stock				Preferred Stock						Paid-in			Accumulated			Comprehensive			Stockholders'
	Shares		Amount		Shares		Amount		Shares			Amount			Capital			Deficit			Loss			Equity
Balance at December 31, 2015		7,521,788	$	142,638		—	$	—		—		$	—		$	10,270		$	30,818		$	(760	)	$	182,966
Sale of common stock, net of offering costs		13,800,000		14		—		—		—			—			71,803			—			—			71,817
Shares issued for asset acquisition		500,227		—		—		—		—			—			5,499			—			—			5,499
Stock-based compensation		—		—		—		—		—			—			448			—			—			448
Foreign currency translation		—		—		—		—		—			—			(760	)		—			760			-
Net loss		—		—		—		—		—			—			—			(94,335	)		—			(94,335	)
Balance at December 31, 2016		21,822,015	$	142,652		—	$	—		—		$	—		$	87,260		$	(63,517	)	$	—		$	166,395
Shares issued for asset acquisitions		—		—		5,400		—		2,684,632			3			10,792			—			—			10,795
Conversion of Series A-2 Preferred		—		—		76,577		—		—			—			75,504			—			—			75,504
Conversion of Series B Preferred		2,684,632		3		—		—		(2,684,632	)		(3	)		—			—			—			—
Payment-in-kind dividends		—		—		1,991		—		—			—						—			—			—
Stock-based compensation		—		—		—		—		—			—			1,315			—			—			1,315
Net loss		—		—		—		—		—			—			—			(38,663	)		—			(38,663	)
Balance at December 31, 2017		24,506,647	$	142,655		83,968	$	—		—		$	—		$	174,871		$	(102,180	)	$	—		$	215,346

	Fair Value Measurements Using
In thousands	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)			Total
December 31, 2017
Assets:
Commodity derivatives	$	—	$	472		$	—		$	472
Liabilities:
Commodity derivatives		—		(22,138	)		—			(22,138	)
Equity warrant liability		—		—			(508	)		(508	)
Equity warrant liability - related parties		—		—			(963	)		(963	)
Stock appreciation rights		—		—			(314	)		(314	)
Total	$	—	$	(21,666	)	$	(1,785	)	$	(23,451	)

December 31, 2016
Assets:
Commodity derivatives	$	—	$	1,730		$	—		$	1,730
Liabilities:
Commodity derivatives		—		(4,110	)		—			(4,110	)
Equity warrant liability		—		—			(1,565	)		(1,565	)
Equity warrant liability - related parties		—		—			(2,994	)		(2,994	)
Total	$	—	$	(2,380	)	$	(4,559	)	$	(6,939	)

	Shares			Weighted Average Exercise Price Per Share		Weighted Average Remaining Contractual Term (in years)
Outstanding at December 31, 2016		191,750		$	15.00		0.25
Options vested and exercisable at December 31, 2016		191,750			15.00		0.25
Granted		—			—		—
Exercised		—			—		—
Canceled/expired		(116,750	)		—		—
Forfeited		(75,000	)		20.00		—
Outstanding at December 31, 2017		—		$	—		—
Options vested and exercisable at December 31, 2017		—		$	—		—

	Shares			Weighted Average Fair Value per Share		Weighted Average Remaining Contractual Term (in years)
Outstanding non-vested RSUs at December 31, 2016		—		$	—		—
Granted		740,409			5.57		3.0
Vested		—			—		—
Forfeited		(11,500	)		6.00		2.2
Outstanding non-vested RSUs at December 31, 2017		728,909		$	5.56		2.2


	Shares	Weighted Average Fair Value per Share
Outstanding non-vested RSUs at December 31, 2019 (Predecessor)	1,849,676	$	4.04
Granted	0	0
Vested	(866,800)	0.64
Forfeited	(102,623)	0
Cancelled	(880,253)	$	3.41
Outstanding non-vested RSUs at November 30, 2020 (Predecessor)	0	$	0

	Shares			Weighted Average Fair Value per Share		Weighted Average Exercise Price per share		Weighted Average Remaining Contractual Term (in years)
Outstanding non-vested SARs at December 31, 2016		—		$	—	$	—		—
Granted		700,000			6.00		7.20		5.0
Vested		—			—		—		—
Forfeited		(10,000	)		5.17		7.20		4.3
Outstanding non-vested SARs at December 31, 2017		690,000		$	3.97	$	7.20		4.3


	Shares	Weighted Average Exercise Price Per Share		Weighted Average Remaining Contractual Term (in years)
Outstanding at December 31, 2019 (Predecessor)	1,010,000	$	6.30	2.5
SARs vested and exercisable at December 31, 2019 (Predecessor)	606,250	6.65		2.4
Granted	0	0		—
Vested	198,750	0		—
Exercised	0	0		—
Forfeited	0	0		—
Cancelled	(805,000)	6.79		1.4
Outstanding at November 30, 2020 (Predecessor)	0	$	0	—
SARs vested and exercisable at November 30, 2020 (Predecessor)	0	$	0	—

In thousands	Future Minimum Payments
2018	$	412
2019		422
2020		432
2021		368
Total minimum lease payments	$	1,634

	Oil (MBbl)			NGLs (MBbl)			Gas (MMcf)			MBoe (1)
Net proved reserves
Reserves at December 31, 2015		23,551			7,154			56,982			40,202
New discoveries and extensions		5,865			795			—			6,660
Purchase of reserves in place		102			140			576			339
Reserves sold		(1,672	)		—			(2,256	)		(2,048	)
Revisions of prior year estimates		(2,367	)		(198	)		659			(2,456	)
Production		(1,191	)		(425	)		(3,247	)		(2,157	)
Reserves at December 31, 2016		24,288			7,466			52,714			40,540
New discoveries and extensions		3,203			468			2,093			4,021
Purchase of reserves in place		23,614			3,422			16,867			29,847
Reserves sold		—			—			—			—
Revisions of prior year estimates		1,176			(96	)		2,570			1,507
Production		(1,580	)		(385	)		(2,370	)		(2,360	)
Reserves at December 31, 2017		50,701			10,875			71,874			73,555
Proved Developed Reserves:
December 31, 2015		8,358			2,020			17,535			13,300
December 31, 2016		6,268			2,274			14,734			10,998
December 31, 2017		12,657			2,846			17,034			18,342
Proved Undeveloped Reserves:
December 31, 2015		15,193			5,134			39,447			26,902
December 31, 2016		18,021			5,191			37,980			29,542
December 31, 2017		38,044			8,029			54,840			55,213