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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549
FORM 10-Q
(Mark One)
☒    QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 2021
OR
☐    TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from      to
Commission File Number: 001-37670
Lonestar Resources US Inc.
(Exact Name of Registrant as Specified in its Charter)
Delaware 81-0874035
(State or other jurisdiction of
incorporation or organization) 		(I.R.S. Employer
Identification No.)
111 Boland Street, Suite 301, Fort Worth, TX
76107
(Address of principal executive offices) (Zip Code)
Registrant’s telephone number, including area code: (817) 921-1889
Securities Registered Pursuant to Section 12(b) of the Act:
Title of Each Class Trading Symbol Name of Exchange on Which Registered
Common Stock, par value $0.001 per share LONE OTCQX Best Market

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes ý    No  ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).   Yes  ý    No  ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act:
Large accelerated filer ☐ Accelerated filer ☐
Non-accelerated filer ý Smaller reporting company ☒
Emerging growth company ☒
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.  ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ☐    No  ý
As of August 9, 2021, the registrant had 10,107,081 shares of common stock, par value $0.001 per share, outstanding.
i

Table of Contents
Page
PART I.
Item 1.
1
1
2
3
4
5
Item 2.
17
Item 3.
32
Item 4.
33
PART II.
34
Item 1.
34
Item 1A.
34
Item 2.
34
Item 6.
35
36

ii


PART I—FINANCIAL INFORMATION
Item 1. Financial Statements
Lonestar Resources US Inc.
Unaudited Condensed Consolidated Balance Sheets
(In thousands, except par value and share data)
June 30, 2021 December 31, 2020
Assets
Current assets
Cash and cash equivalents $ 18,788  $ 17,474 
Restricted cash 2,157  8,972 
Accounts receivable
Oil, natural gas liquid and natural gas sales 18,838  11,635 
Joint interest owners and others, net 1,418  4,076 
Derivative financial instruments —  1,703 
Prepaid expenses and other 1,710  1,118 
Total current assets 42,911  44,978 
Property and equipment
Oil and gas properties, using the successful efforts method of accounting
Proved properties 352,788  314,685 
Unproved properties 33,808  34,929 
Other property and equipment 19,692  19,680 
Less accumulated depreciation, depletion and amortization (12,982) (2,056)
Property and equipment, net 393,306  367,238 
Accounts receivable 6,256  6,053 
Derivative financial instruments —  395 
Other non-current assets 4,232  4,651 
Total assets $ 446,705  $ 423,315 
Liabilities and Stockholders’ Equity
Current liabilities
Accounts payable $ 10,929  $ 7,651 
Oil, natural gas liquid and natural gas sales payable 22,953  18,760 
Accrued liabilities 15,594  15,983 
Derivative financial instruments 43,539  7,938 
Current maturities of long-term debt 22,157  20,000 
Total current liabilities 115,172  70,332 
Long-term liabilities
Long-term debt 243,199  255,328 
Asset retirement obligations 3,707  4,573 
Derivative financial instruments 15,539  835 
Total long-term liabilities 262,445  260,736 
Commitments and contingencies (Note 10)
Stockholders’ equity
Common stock, $0.001 par value, 90,000,000 shares authorized, 10,107,081 and 10,000,149 shares issued and outstanding, respectively
10  10 
Additional paid-in capital 93,933  92,953 
Accumulated deficit (24,855) (716)
Total stockholders’ equity
69,088  92,247 
Total liabilities and stockholders’ equity $ 446,705  $ 423,315 

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.
1

Lonestar Resources US Inc.
Unaudited Condensed Consolidated Statements of Operations
(In thousands, except per share data)
Successor Predecessor Successor Predecessor
Three Months Ended June 30, 2021 Three Months Ended June 30, 2020 Six Months Ended June 30, 2021 Six Months Ended June 30, 2020
Revenues
Oil sales $ 36,369  $ 11,976  $ 64,234  $ 41,986 
Natural gas liquid sales 4,940  1,762  9,239  4,362 
Natural gas sales 4,718  3,482  12,365  7,902 
Total revenues 46,027  17,220  85,838  54,250 
Expenses
Lease operating 3,933  4,028  8,379  11,667 
Gas gathering, processing and transportation 1,520  875  3,062  3,025 
Production and ad valorem taxes 2,497  1,721  4,917  4,091 
Depreciation, depletion and amortization 5,860  16,575  11,169  40,929 
Loss on sale and disposal of oil and gas properties —  1,254  —  1,254 
Impairment of oil and gas properties —  —  —  199,908 
General and administrative 5,962  5,981  9,939  8,856 
Other (income) expense (143) 58  (138) (139)
Total expenses 19,629  30,492  37,328  269,591 
Income (loss) from operations 26,398  (13,272) 48,510  (215,341)
Other (expense) income
Interest expense (4,323) (10,512) (8,430) (22,122)
Change in fair value of warrants —  —  —  363 
(Loss) gain on derivative financial instruments (39,892) (21,141) (64,059) 80,029 
Total other (expense) income (44,215) (31,653) (72,489) 58,270 
Loss before income taxes (17,817) (44,925) (23,979) (157,071)
Income tax benefit (expense) —  4,332  (160) 5,687 
Net loss (17,817) (40,593) (24,139) (151,384)
Preferred stock dividends —  (2,308) —  (4,566)
Net loss income attributable to common stockholders $ (17,817) $ (42,901) $ (24,139) $ (155,950)
Net loss per common share
Basic $ (1.77) $ (1.70) $ (2.40) $ (6.20)
Diluted $ (1.77) $ (1.70) $ (2.40) $ (6.20)
Weighted average common shares outstanding
Basic 10,092,980  25,307,714  10,046,821  25,154,151 
Diluted 10,092,980  25,307,714  10,046,821  25,154,151 
See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.
2

Lonestar Resources US Inc.
Unaudited Condensed Consolidated Statements of Changes in Stockholders’ Equity (Deficit)
(In thousands, except share data)
Common Stock Additional
Paid-in
Capital 		Accumulated
Deficit
Total
Stockholders’
Equity
Shares Amount
Balance at December 31, 2020 (Successor) 10,000,149  $ 10  $ 92,953  $ (716) $ 92,247 
Net loss —  —  —  (6,322) (6,322)
Balance at March 31, 2021 (Successor) 10,000,149  10  92,953  (7,038) 85,925 
Stock-based compensation 106,932  —  980  —  980 
Net loss —  —  —  (17,817) (17,817)
Balance at June 30, 2021 (Successor) 10,107,081  $ 10  $ 93,933  $ (24,855) $ 69,088 
Class A Voting
Common Stock 		Series A-1
Preferred Stock 		Additional
Paid-in
Capital 		Accumulated
Deficit
Total
Stockholders’ (Deficit) Equity
Shares Amount Shares Amount
Balance at December 31, 2019 (Predecessor) 24,945,594  $ 142,655  100,328  $ —  $ 175,738  $ (197,506) $ 120,887 
Payment-in-kind dividends —  —  2,257  —  —  —  — 
Stock-based compensation 308,435  —  —  —  240  —  240 
Net loss —  —  —  —  —  (110,791) (110,791)
Balance at March 31, 2020 (Predecessor) 25,254,029  142,655  102,585  —  175,978  (308,297) 10,336 
Payment-in-kind dividends —  —  2,308  —  —  —  — 
Stock-based compensation 58,182  —  —  —  28  —  28 
Net loss —  —  —  —  —  (40,593) (40,593)
Balance at June 30, 2020 (Predecessor) 25,312,211  $ 142,655  104,893  $ —  $ 176,006  $ (348,890) $ (30,229)
See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.
3

Lonestar Resources US Inc.
Unaudited Condensed Consolidated Statements of Cash Flows
(In thousands)
Successor Predecessor
Six Months Ended June 30, 2021 Six Months Ended June 30, 2020
Cash flows from operating activities
Net loss $ (24,139) $ (151,384)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization 11,169  40,929 
Stock-based compensation 1,088  (1,998)
Deferred taxes —  (931)
Loss (gain) on derivative financial instruments 64,059  (80,029)
Settlements of derivative financial instruments (12,398) 23,998 
Impairment of oil and natural gas properties —  199,908 
Loss on disposal of property and equipment —  83 
Loss on sale of oil and gas properties —  1,254 
Non-cash interest expense 941  1,374 
Change in fair value of warrants —  (363)
Changes in operating assets and liabilities:
Accounts receivable (5,001) (189)
Prepaid expenses and other assets (703) (897)
Accounts payable and accrued expenses (7,619) (1,344)
Net cash provided by operating activities 27,397  30,411 
Cash flows from investing activities
Acquisition of oil and gas properties (1,612) (1,714)
Development of oil and gas properties (21,489) (72,824)
Proceeds from sale of oil and gas properties 337  2,837 
Purchases of other property and equipment (13) (636)
Net cash used in investing activities (22,777) (72,337)
Cash flows from financing activities
Proceeds from borrowings —  48,157 
Payments on borrowings (10,121) (8,109)
Net cash (used in) provided by financing activities (10,121) 40,048 
Net decrease in cash, cash equivalents and restricted cash (5,501) (1,878)
Cash, cash equivalents and restricted cash, beginning of the period 26,446  3,137 
Cash, cash equivalents and restricted cash, end of the period $ 20,945  $ 1,259 
Supplemental information:
Cash paid for interest $ 7,496  $ 21,036 
Non-cash investing and financing activities:
Change in asset retirement obligation $ (945) $ 24 
Change in liabilities for capital expenditures 15,326  (16,809)
See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.
4

Lonestar Resources US Inc.
Notes to Unaudited Condensed Consolidated Financial Statements
Note 1. Basis of Presentation
Organization and Nature of Operations
Lonestar Resources US Inc. (“Lonestar” or the “Company”) is an independent oil and natural gas company focused on the exploration, development and production of unconventional oil, natural gas liquids and natural gas in the Eagle Ford Shale play in South Texas.
Interim Financial Statements
The accompanying unaudited condensed consolidated financial statements (“Unaudited Condensed Consolidated Financial Statements”) of Lonestar Resources US Inc., and its subsidiaries have been prepared in accordance with the rules and regulations of the Securities and Exchange Commission (“SEC”) and do not include all of the information and footnotes required by accounting principles generally accepted in the United States (“GAAP”) for complete financial statements. These financial statements and the notes thereto should be read in conjunction with our Annual Report on Form 10-K for the year ended December 31, 2020 filed on March 31, 2021, as supplemented by our amendment on Form 10-K/A filed with the SEC on April 30, 2021 (the “Form 10-K”). Unless indicated otherwise or the context requires, the terms “we,” “our,” “us,” “Company” or “Lonestar,” refer to Lonestar Resources US Inc. and its subsidiaries.
The results of operations for the interim periods shown in this report are not necessarily indicative of results to be expected for the year.  In management’s opinion, the accompanying Unaudited Condensed Consolidated Financial Statements include all adjustments of a normal recurring nature necessary for a fair statement of our consolidated financial position as of June 30, 2021 and our consolidated results of operations for the three and six months ended June 30, 2021 and June 30, 2020.

Emergence from Voluntary Reorganization Under Chapter 11 of the Bankruptcy Code

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, 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.

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 on November 30, 2020 (the “Effective Date”). In January 2021, the Successor’s (as defined below) new common stock commenced trading on the OTCQX Best Market under the ticker symbol “LONE”.

Comparability of Financial Statements to Prior Periods

The Company applied Fresh Start Accounting on the Effective Date. Accordingly, the Company’s Unaudited Condensed Consolidated Financial Statements and Notes to Unaudited Condensed Consolidated Financial Statements after November 30, 2020, are not comparable to the Unaudited Condensed Consolidated Financial Statements and Notes to Unaudited Condensed Consolidated Financial Statements through that date. To facilitate financial statement presentations, we refer to the reorganized company in these Condensed Consolidated Financial Statements and Notes as the “Successor,” which is effectively a new reporting entity for financial reporting purposes, for periods subsequent to November 30, 2020, and the “Predecessor” for periods prior to and including November 30, 2020. In connection with our reorganization, the Company experienced a change in control as the outstanding common and preferred shares of the Predecessor were canceled and substantially all of the Successor’s new common stock was issued to the Predecessor’s bondholders.


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Furthermore, our Unaudited Condensed Consolidated Financial Statements and Notes to Unaudited Condensed Consolidated Financial Statements have been presented with a “black line” division to delineate, where applicable, the lack of comparability between the Predecessor and Successor. Accordingly, our results of operations, financial position and cash flows for the Successor periods are not comparable.

Reclassifications

Certain prior-period amounts have been reclassified to conform to the current period presentation. Such reclassifications had no impact on the Company’s reported total revenues, expenses, net loss, current assets, total assets, current liabilities, total liabilities or stockholders’ equity.

Cash, Cash Equivalents and Restricted Cash

The Company considers all highly-liquid investments to be cash equivalents if they have maturities of three months or less when purchased. The following table provides a reconciliation of cash, cash equivalents and restricted cash as reported within the Unaudited Condensed Consolidated Balance Sheets to “Cash, cash equivalents and restricted cash at the end of the period” as reported within the Unaudited Condensed Consolidated Statements of Cash Flows:
Successor Predecessor
In thousands June 30, 2021 June 30, 2020
Cash and cash equivalents $ 18,788  $ 1,259 
Restricted cash, current 2,157  — 
Total cash, cash equivalents and restricted cash shown in the Unaudited Condensed Consolidated Statements of Cash Flows $ 20,945  $ 1,259 
Restricted cash, current in the table above represents funds reserved to cover the balance of the PPP (as defined below) 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.

COVID-19

During the first half and through early-August 2021, the oil and natural gas industry has experienced continued improvement in commodity prices as compared to the same period in 2020, primarily resulting from (i) improvements in oil demand as the impact from COVID-19 has begun to abate (although, as of early-August 2021, the COVID-19 Delta variant was showing significant spread globally causing uncertainty regarding future economic impacts) and (ii) actions taken by the Organization of Petroleum Exporting Countries, Russia and certain other oil-exporting countries (“OPEC+”) to reduce the worldwide supply of oil through coordinated production cuts. As a result, West Texas Intermediate (“WTI”) oil prices have increased from $48.52 per barrel at December 31, 2020 to as high as $73.95 per barrel in late-July 2021. Prices for natural gas and NGLs were also much higher during the first half and through early-August 2021 than they were for the same period in 2020. While oil prices have continued to improve in 2021, the general outlook for the oil and natural gas industry for the remainder of the year remains uncertain, and the Company can provide no assurances as to when or to what extent economic disruptions resulting from COVID-19 and the corresponding decreases in oil demand may impact the Company.

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 three and six months ended June 30, 2020 and 2021, respectively.


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The Company 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 Company 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 Company 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. To date, forgiveness has not been received. The PPP Loan is subject to any new guidance and new requirements released by the Department of the Treasury who has indicated that all companies that have received funds in excess of $2.0 million will be subject to a government (SBA) audit to further ensure PPP loans are limited to eligible borrowers in need.
Impairment of Long-Lived Assets
The carrying value of long-lived assets and certain identifiable intangibles 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.
The Company evaluates impairment of proved and unproved oil and gas properties on a region basis. On this basis, certain regions may be impaired because they are not expected to recover their entire carrying value from future net cash flows. As a result of this evaluation, the Predecessor recorded impairment of oil and gas properties of $199.9 million for the three months ended March 31, 2020, of which $199.0 million was proved and $0.9 million was unproved. The impairment was the result of removing development of proved undeveloped reserves (“PUDs”) and probable reserves from future net cash flows as the Predecessor could not assure that they would be developed going forward in light of continued depressed commodity prices and uncertainty regarding the Predecessor’s liquidity situation at the time.
Upon emergence from bankruptcy, the Company adopted fresh start accounting which resulted in its long-lived assets being recorded at their estimated fair value at the Effective Date. There were no material changes to the key cash flow assumptions and no triggering events since December 31, 2020; therefore, no impairment was identified in the three or six months ended June 30, 2021.
Net Loss per Common Share

Prior to the Effective Date, the Predecessor company used the two-class method to compute earnings per common share as its 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.

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 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.
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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 Successor Predecessor
Three Months Ended June 30, 2021 Three Months Ended June 30, 2020 Six Months Ended June 30, 2021 Six Months Ended June 30, 2020
Preferred stock —  17,101,727  —  16,913,597 
Warrants 1,111,110  760,000  1,111,110  760,000 
Stock appreciation rights —  1,010,000  —  1,010,000 
Restricted stock units 475,953  970,866  239,291  1,369,164 

Recent Accounting Pronouncements

Income Taxes. In December 2019, the Financial Accounting Standards Board (“FASB”) issued ASU 2019-12, Income Taxes (Topic 740) – Simplifying the Accounting for Income Taxes (“ASU 2019-12”). The objective of ASU 2019-12 is to simplify the accounting for income taxes by removing certain exceptions to the general principles in Topic 740 and to provide more consistent application to improve the comparability of financial statements. The amendments in this ASU were effective starting January 1, 2021 for the Company.

Financial Instruments — Credit Losses. In June 2016, the 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 amendment using a modified retrospective approach to the first reporting period in which the guidance is effective. The adoption of ASU 2016-13 is currently not expected to have a material effect on the Company’s Unaudited Condensed Consolidated Financial Statements.

Reference Rate Reform. In March 2020, the FASB issued ASU 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 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 (as defined below) 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 Unaudited Condensed Consolidated Financial Statements and related footnote disclosures.

Note 2. Derivative Instruments and Hedging Activities
Commodity Derivative Instruments
Lonestar enters into certain commodity derivative instruments to mitigate commodity price risk associated with a portion of its future oil, NGL and natural gas production and related cash flows. The oil, NGL and natural gas revenues and cash flows are affected by changes in commodity product prices, which are volatile and cannot be accurately predicted. The objective for entering into these commodity derivatives is to protect the operating revenues and cash flows related to a portion of the future oil, NGL and natural gas sales from the risk of significant declines in commodity prices.
Inherent in 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 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. As of June 30, 2021, the Company had no open physical delivery obligations.

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The following table summarizes Lonestar’s commodity derivative contracts as of June 30, 2021:
Contract Volumes Weighted
Commodity Type Period
Range (1)
(Bbls/Mcf per day) Average Price
Oil - WTI Swaps July - Dec 2021
$42.20 - $54.55
5,525  $ 46.33 
Oil - WTI Swaps Jan - Dec 2022
$44.83 - $51.44
3,062  47.03 
Oil - WTI Swaps Jan - Dec 2023
$52.00 - $56.15
2,362  54.25 
Natural Gas - Henry Hub Swaps July - Dec 2021
$2.93 - $3.05
13,550  2.98 
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 July 2021, the Company entered into additional Henry Hub natural gas swaps of 1,070,000 Mcf (8,770 Mcf per day) for the period of September 2021 through December 2021 at an average strike price of $4.02 per Mcf, Henry Hub natural gas swaps of 2,737,500 Mcf (7,500 Mcf per day) for the period of January 2022 through December 2022 at an average strike price of $3.38 per Mcf and Henry Hub natural gas swaps of 1,582,500 Mcf (8,743 Mcf per day) for the period of January 2023 through June 2023 at an average strike price of $3.02 per Mcf.
As of June 30, 2021, all of the Company’s economic derivative hedge positions were with large financial institutions, which are not known to the Company to be in default on their derivative positions. The Company is exposed to credit risk to the extent of non-performance by the counterparties in the derivative contracts discussed above; however, the Company does not anticipate non-performance by such counterparties. None of the Company’s derivative instruments contain credit-risk related contingent features.

Note 3. 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.

The following table summarizes our revenues by product type for the three and six months ended June 30, 2021 and 2020:
In thousands Successor Predecessor Successor Predecessor
Three Months Ended June 30, 2021 Three Months Ended June 30, 2020 Six Months Ended June 30, 2021 Six Months Ended June 30, 2020
Oil $ 36,369  $ 11,976  $ 64,234  $ 41,986 
NGLs 4,940  1,762  9,239  4,362 
Natural gas 4,718  3,482  12,365  7,902 
Total revenues $ 46,027  $ 17,220  $ 85,838  $ 54,250 

As of June 30, 2021 and December 31, 2020 the accounts receivable balance representing amounts due or billable under the terms of contracts with purchasers was $18.8 million and $11.6 million, respectively.
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Note 4. Fair Value Measurements
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. Accounting Standards Codification (“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.
The following table presents the Company’s assets and liabilities that are measured at fair value on a recurring basis as of June 30, 2021 and December 31, 2020, for each fair value hierarchy level:
Fair Value Measurements Using
In thousands Quoted Prices in Active Markets
(Level 1) 		Significant Other Observable Inputs
(Level 2) 		Significant Unobservable Inputs
(Level 3) 		Total
June 30, 2021
Liabilities:
Derivative financial instruments $ —  $ (59,078) $ —  $ (59,078)
Stock-based compensation (108) (108)
Total $ (108) $ (59,078) $ —  $ (59,186)
December 31, 2020
Assets:
Derivative financial instruments $ —  $ 2,098  $ —  $ 2,098 
Liabilities:
Derivative financial instruments —  (8,773) —  (8,773)
Total $ —  $ (6,675) $ —  $ (6,675)
Assets and liabilities measured at fair value on a nonrecurring basis

Non-recurring fair value measurements include certain 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. 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.

Other fair value measurements

The book values of cash and cash equivalents, 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.

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Note 5. Accrued Liabilities
Accrued liabilities consisted of the following as of the dates indicated:
In thousands June 30, 2021 December 31, 2020
Bonus payable $ 1,231  $ 1,363 
Accrued well costs 9,160  1,752 
Third-party payments for joint-interest expenditures 1,017  5,178 
Accrued professional fees (success fees) —  4,710 
Ad valorem payable 2,307  869 
Other 1,879  2,111 
Total accrued liabilities $ 15,594  $ 15,983 
Note 6. Long-Term Debt
The following long-term debt obligations were outstanding as of the dates indicated:
In thousands June 30, 2021 December 31, 2020
Senior Secured Credit Facility $ 209,600  $ 209,600 
Second-Out Term Loan 45,000  55,000 
Mortgage debt 8,596  8,712 
PPP loan 2,157  2,157 
Other 249  261 
Total long-term debt 265,602  275,730 
Less unamortized discount (246) (402)
Total, net of unamortized discount 265,356  275,328 
Less current obligations (22,157) (20,000)
Long-term debt $ 243,199  $ 255,328 
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 and the May 1 redetermination was completed in August 2021, which also reaffirmed the $225 million borrowing base.
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.
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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 5.5% for the three and six months ended June 30, 2021. The undrawn portion of the aggregate lender commitments under the Successor Credit Facility is subject to a commitment fee of 1.0%. As of June 30, 2021, the Successor was in compliance with all debt covenants under the Successor Credit Facilities.

First Amendment

Effective August 6, 2021, the Company entered into the First Amendment and Borrowing Base Agreement (the “First Amendment”), which reaffirmed the $225 million borrowing base for the Successor Credit Facility pursuant to the scheduled May 1 redetermination and amended certain required swap agreements.

Predecessor Senior Secured Bank Credit Facility

From July 2015 through November 30, 2020, the Predecessor maintained a senior secured revolving credit facility with Citibank, N.A., as administrative agent, and other lenders party thereto. All of the Predecessor Credit Facility was refinanced by the Successor Credit Agreements on the Effective Date.

Extinguishment of Predecessor 11.25% Senior Notes

On the Effective Date, the Predecessor’s 11.25% Senior Notes due 2023 (the “11.25% Senior Notes”) were fully extinguished by issuing equity in the Successor to the holders of that debt.


Note 7. Stockholders’ Equity
Registration Rights Agreement

On the Effective Date, the Successor entered into a registration rights agreement (the “Registration Rights Agreement”) with certain parties who received certain shares of New Common Stock on the Effective Date (the “Holders”). The Registration Rights Agreement provides resale registration rights for the Holders’ registrable securities of the Successor.

Pursuant to the Registration Rights Agreement, Holders have customary underwritten offering and piggyback registration rights, subject to the limitations set forth in the Registration Rights Agreement. Under their underwritten offering registration rights, Holders have the right to demand the Successor to effectuate the distribution of any or all of its Registrable Securities by means of an underwritten offering pursuant to an effective registration statement; provided, however, that the expected gross offering price is equal to or greater than $50.0 million in the aggregate. The Successor is not obligated to effect an underwritten demand notice upon certain circumstances, including within 180 days of closing an underwritten offering. Under their piggyback registration rights, if at any time the Successor proposes to undertake a registered offering of New Common Stock for its own account, the Successor must give at least five business days’ notice to all Holders of Registrable Securities to allow them to include a specified number of their shares in the offering.


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These registration rights are subject to certain conditions and limitations, including the right of the underwriters to limit the number of shares to be included in an offering and the Successor’s right to delay or withdraw a registration statement under certain circumstances. The Successor will generally pay all registration expenses in connection with its obligations under the Registration Rights Agreement, regardless of whether a registration statement is filed or becomes effective. The registration rights granted in the Registration Rights Agreement are subject to customary indemnification and contribution provisions, as well as customary restrictions such as blackout periods and, if an underwritten offering is contemplated, limitations on the number of shares to be included in the underwritten offering that may be imposed by the managing underwriter.

Warrant Agreements

On the Effective Date, pursuant to the terms of the Plan, the Successor entered into a Tranche 1 Warrant Agreement (the “Tranche 1 Warrant Agreement”) and issued warrants (the “Tranche 1 Warrants”) to holders of Allowed Prepetition RBL Claims (as defined in the Plan) or their permitted designees, as applicable, to purchase up to an aggregate of 555,555 shares of common stock in the Successor, par value $0.001 (the “New Common Stock”), at an exercise price of $0.001 per share of New Common Stock, subject to adjustment. The Tranche 1 Warrants may only be exercised at any time after the equity value of the Successor, as calculated pursuant to the Tranche 1 Warrant Agreement, shall have been greater than $100 million (“Valuation Condition”) and expire on November 30, 2023 (the “Expiration Date”).

On the Effective Date, pursuant to the terms of the Plan, the Company entered into a Tranche 2 Warrant Agreement (the “Tranche 2 Warrant Agreement” and, together with the Tranche 1 Warrant Agreement, the “Warrant Agreements”) and issued warrants (the “Tranche 2 Warrants” and, together with the Tranche 1 Warrants, the “Warrants”) to holders of Allowed Prepetition RBL Claims or their permitted designees, as applicable, to purchase up to an aggregate of 555,555 shares of the New Common Stock, at an exercise price of $0.001 per share of New Common Stock, subject to adjustment. The Tranche 2 Warrants may be exercised after the first anniversary of the issuance of the Successor Term Loan Facility if it shall not have been paid in full and if, after the first anniversary date, the Valuation Condition has been met. The Tranche 2 Warrants expire upon the Expiration Date.

All warrants are considered freestanding equity-classified instruments due to their detachable and separately exercisable features. Accordingly, the warrants are presented as a component of Stockholders’ Equity in accordance with ASC 815-40-25.
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Note 8. Stock-Based Compensation
Management Incentive Plan
In connection with the Company's emergence from bankruptcy, the Plan provided for the adoption of a management incentive plan. On April 31, 2021, the Lonestar Resources US Inc. 2021 Management Incentive Plan (the “MIP”) was approved and adopted by the Company’s board of directors. The aggregate number of the Company’s common shares reserved for issuance under the MIP is equal to 966,184 shares, which are available for issuance pursuant to awards granted to officers, other employees, directors and other service providers. The MIP provides for, among other things, the grant of incentive stock options, non-statutory stock options, restricted stock, restricted stock units, stock appreciation rights, dividend equivalents, other stock-based awards, cash awards, or any combination of the foregoing. As of June 30, 2021,awards covering 691,500 shares of the Company’s stock are outstanding under the MIP and 274,684 shares are available for future grants under the MIP, all of which could be issued in the form of restricted stock units. The incentive compensation program is administered by the Compensation Committee of the Company's Board of Directors.
Restricted Stock Units

On April 13, 2021, service-based restricted stock unit awards (“RSUs”) were granted to certain employees and directors under the MIP. One-third of the RSUs granted to employees vested and were immediately settled on the grant date, and the remaining unvested RSUs will vest in equal annual installments December 31, 2021, December 31, 2022, and December 31, 2023, subject to such employee’s continued employment with the Company on each applicable vesting date. One-half of the RSUs granted to directors vested and were immediately settled on the date of grant, and the remaining unvested RSUs will vest on December 31, 2021, subject to such director’s continued service on the Company’s board of directors through such vesting date. Shares of the Company’s common stock to be delivered to participants upon settlement are expected to be made available from authorized but unissued shares reserved under the MIP, however, the RSUs held by directors are eligible for settlement in cash at such directors’ discretion. As a result, RSUs granted to directors are accounted for as a liability on the Company's unaudited condensed consolidated balance sheet.
As of June 30, 2021, there was $1.7 million of unrecognized compensation expense related to the Company’s
RSUs held by employees. This unrecognized compensation cost is expected to be recognized over a weighted-average period of 2.5 years. For the three months ended June 30, 2021, the Company recognized $1.3 million, of stock-based compensation expense for the RSUs. The liability for directors' unvested RSUs on the accompanying consolidated balance sheet as of June 30, 2021 was $0.1 million.

A summary of the status of the Company's service-based RSU grants issued, and the changes during the six months ended June 30, 2021 is presented below:
Shares Weighted Average Fair Value per Share
Nonvested at December 31, 2020 —  $ — 
Granted 387,750  7.29 
Vested (143,250) 7.29 
Forfeited —  — 
Nonvested at June 30, 2021 244,500  10.28


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Performance-Based RSUs

In April 2021, performance-based restricted stock unit awards (“PSUs”) were granted to certain employees under the MIP. The PSUs are eligible to vest in equal annual installments on December 31, 2021, December 31, 2022, and December 31, 2023 (each installment, a “Tranche”), subject to such employee’s continued employment with the Company on each applicable vesting date. Whether the PSUs vest and become settled on each applicable vesting date depends on the achievement of certain performance criteria determined by the Company’s board of directors, which is set within 90 days of the applicable fiscal year with respect to each Tranche. The performance criteria determined by the Company’s board of directors is typically related to the Company’s performance for the preceding fiscal year against several key performance indicators, including free cash flow and spending metrics, as well as discretionary factors. Shares of the Company’s common stock to be delivered to participants upon settlement are expected to be made available from authorized but unissued shares reserved under the MIP.
As of June 30, 2021, there was $2.2 million of unrecognized compensation expense related to the Successor’s
non-vested PSUs. This unrecognized compensation cost is expected to be recognized over a weighted-average period of 3.6 years. For the three months ended June 30, 2021, the Company recognized $0.1 million, of stock-based compensation expense for the PSUs.
PSUs are valued using a Monte Carlo simulation. Expected volatilities utilized in the model were estimated using historical volatility of the Predecessor stock over a look-back term generally equivalent to the expected life of the award from the grant date.
A range of assumptions used in the Monte Carlo simulation valuation approach is as follows:
Six Months Ended June 30, 2021
Weighted-average fair value of PSUs granted $ 7.29 
Risk-free interest rate 0.21  %
Expected life 3.6
Expected volatility 125  %
Dividend yield — 

A summary of the status of the non-vested PSUs during the six months ended June 30, 2021 is as follows:
Shares Weighted Average Fair Value per Share
Non-vested at December 31, 2020 —  $ — 
Granted 303,750  7.29 
Vested —  — 
Forfeited —  — 
Non-vested at June 30, 2021 303,750  $ 10.28 
Note 9. Related-Party Activities
New Tech Global Ventures, LLC, and New Tech Global Environmental, LLC, companies in which a director of the Predecessor owns a limited partnership interest, have provided field engineering staff and consultancy services for the Company since 2013. The total cost for such services was approximately $0.5 million and $1.0 million for the three and six months ended June 30, 2020 (Predecessor). On the Effective Date, the director resigned from the Company’s Board.
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Note 10. Commitments and Contingencies
From time to time, Lonestar is subject to legal proceedings and claims that arise in the ordinary course of business. Like other crude oil and gas producers and marketers, the Company’s operations are subject to extensive and rapidly changing federal and state environmental, health and safety, and other laws and regulations governing air emissions, wastewater discharges and solid and hazardous waste management activities. The Company is not aware of any pending or overtly threatened legal action against it that could have a material impact on its business.
Gonzales County AMI
In February 2020, the Company announced that it had entered into a Joint Development Agreement (the “JDA”) in Gonzales County with one of the largest producers in the Eagle Ford which encompass an Area of Mutual Interest (the “AMI”) totaling approximately 15,000 acres.
The agreement calls for Lonestar to operate a minimum of three to four Eagle Ford Shale wells annually on behalf of the two companies through 2022 that are intended to hold-by-production approximately 6,000 gross acres within the AMI. The agreement gives Lonestar’s partner the option to participate in each well with a 50% working interest or to participate via a carried working interest that ranges from approximately 9 to 17%, depending on location.
Note 11. Subsequent Events
Penn Virginia Merger
On July 12, 2021, Penn Virginia Corporation (“Penn Virginia”) and the Company announced that they entered into a definitive merger agreement, (the “Merger Agreement”), pursuant to which Penn Virginia will acquire the Company in an all-stock transaction. Under the terms of the Merger Agreement, the Company’s shareholders will receive 0.51 shares of Penn Virginia for each of the Company’s shares. The transaction is expected to close in the second half of 2021, subject to the satisfaction of customary closing conditions, including obtaining the requisite shareholder and regulatory approvals. The transaction has been unanimously approved by the Boards of Directors of both companies. Consummation of the merger is subject to satisfaction of customary conditions.
The Merger Agreement contains certain termination rights for both the Company and Penn Virginia, including, among others, if the merger is not completed by November 26, 2021. On a termination of the Merger Agreement under certain circumstances, Penn Virginia may be required to pay the Company a termination fee of $6 million, or the Company may be required to pay Penn Virginia a termination fee of $3 million.


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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
The following discussion and analysis should be read in conjunction with our unaudited condensed consolidated financial statements (the “Unaudited Condensed Consolidated Financial Statements”) and Notes to Unaudited Condensed Consolidated Financial Statements included herein and our Consolidated Financial Statements and Notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2020, as supplemented by our amendment on Form 10-K/A filed with the SEC on April 30, 2021 (the “Form 10-K”), along with Management’s Discussion and Analysis of Financial Condition and Results of Operations contained in the Form 10-K. Any terms used but not defined herein have the same meaning given to them in the Form 10-K. Our discussion and analysis includes forward-looking information that involves risks and uncertainties and should be read in conjunction with Risk Factors under Item 1A of the Form 10-K, along with Forward Looking Information at the end of this section for information on the risks and uncertainties that could cause our actual results to be materially different than our forward-looking statements.
Certain prior-period financial statements are not comparable to our current-period financial statements due to the adoption of fresh start accounting. References to “Successor” relate to the financial position and results of operations of the reorganized Company subsequent to November 30, 2020. References to “Predecessor” relate to the financial position and results of operations of the Company prior to, and including, November 30, 2020.
OVERVIEW
Lonestar is an independent oil and natural gas company focused on the exploration, development and production of unconventional oil, natural gas liquids and natural gas in the Eagle Ford Shale play in South Texas.
Penn Virginia Merger
On July 12, 2021, Penn Virginia Corporation (“Penn Virginia”) and Lonestar announced that they entered into a definitive merger agreement, or (the “Merger Agreement”), pursuant to which Penn Virginia will acquire Lonestar in an all-stock transaction. Under the terms of the Merger Agreement, Lonestar’s shareholders will receive 0.51 shares of Penn Virginia for each of the Company’s shares. The transaction is expected to close in the second half of 2021, subject to the satisfaction of customary closing conditions, including obtaining the requisite shareholder and regulatory approvals. The transaction has been unanimously approved by the Boards of Directors of both companies. Consummation of the merger is subject to satisfaction of customary conditions.
The Merger Agreement contains certain termination rights for both Lonestar and Penn Virginia, including, among others, if the merger is not completed by November 26, 2021. On a termination of the Merger Agreement under certain circumstances, Penn Virginia may be required to pay Lonestar a termination fee of $6 million, or Lonestar may be required to pay Penn Virginia a termination fee of $3 million.
Emergence from Voluntary Reorganization under Chapter 11
On September 30, 2020 (the “Petition Date”), Lonestar Resources US Inc., along with certain of its wholly-owned subsidiaries Lonestar Resources Intermediate Inc., LNR America Inc., Lonestar Resources America Inc., Amadeus Petroleum Inc., Albany Services, L.L.C., T-N-T Engineering, Inc., Lonestar Resources Inc., Lonestar Operating, LLC, Poplar Energy, LLC, Eagleford Gas, LLC, Eagleford Gas 2, LLC, Eagleford Gas 3, LLC, Eagleford Gas 4, LLC, Eagleford Gas 5, LLC, Eagleford Gas 6, LLC, Eagleford Gas 7, LLC, Eagleford Gas 8, LLC, Eagleford Gas 10, LLC, Eagleford Gas 11, LLC, Lonestar BR Disposal LLC, and La Salle Eagle Ford Gathering Line LLC (collectively, the “Debtors”) commenced voluntary cases (the “Chapter 11 Cases”) under chapter 11 of title 11 of the United States Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the Southern District of Texas (the “Bankruptcy Court”). The Chapter 11 Cases were administered jointly under the caption In re Lonestar Resources US Inc., et al., Case No. 20-34805 (DRJ). Wholly-owned subsidiary, Boland Building, LLC, was not a Debtor and was not included in the Chapter 11 Cases.

In addition, on the Petition Date, the Debtors filed their Joint Prepackaged Plan of Reorganization with the Bankruptcy Court (the “Plan”). On November 12, 2020, the Bankruptcy Court entered its confirmation order (the “Confirmation Order”) approving and confirming the Plan. On November 30, 2020, (the “Effective Date”) the Plan became effective and was implemented in accordance with its terms.


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On the Effective Date, the Company consummated the following reorganization transactions in accordance with the Plan:

•Adopted an amended and restated its certificate of incorporation and bylaws, which reserved for issuance 90,000,000 shares of common stock, par value $0.001 per share, (the “New Common Stock”) and 10,000,000 shares of preferred stock, par value $0.001 per share;
•Appointed a new board of directors to replace the Predecessor’s directors, consisting of four new independent members: Richard Burnett, Gary D. Packer, Andrei Verona and Eric Long, and one continuing member: Frank D. Bracken, III, Lonestar’s Chief Executive Officer;
•Provided for the following settlement of claims and interests in the Predecessor as follows:
◦Holders of Prepetition RBL Claims received distributions of:
▪Cash in the amount of all accrued and unpaid interest;
▪A first-out senior secured revolving credit facility with total aggregate commitments of $225 million;
▪A second-out senior secured term loan credit facility in an amount equal to $60 million;
▪555,555 Tranche 1 warrants and 555,555 Tranche 2 warrants, reflecting up to a 10% ownership stake in the Successor company’s equity interests;
•Holders of Prepetition Notes Claims received distributions of a pro rata share of 96% of 10,000,149 shares of New Common Stock issued on the Effective Date, subject to dilution by a to-be-adopted management incentive plan (the “MIP”) and the new warrants;
•Holders of Predecessor preferred equity interests received distributions of a pro rata share of 3% of the New Common Stock in the Successor company (subject to dilution by the MIP and the new warrants);
•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); and
•General unsecured creditors were paid in full in cash.
Fresh Start Accounting
Upon emergence from bankruptcy, the Company qualified for and adopted fresh start accounting in accordance with Accounting Standards Codification (“ASC”) 852, which resulted in the Company becoming a new entity for financial reporting purposes because (1) the holders of the then existing voting shares of the Predecessor received less than 50 percent of the voting shares of the Successor upon emergence and (2) the reorganization value of the Company’s assets immediately prior to confirmation of the Plan was less than the total of all post-petition liabilities and allowed claims.

All conditions required for the adoption of fresh-start accounting were met when the Plan became effective, on November 30, 2020. The implementation of the Plan and the application of fresh-start accounting materially changed the carrying amounts and classifications reported in the Company’s consolidated financial statements and resulted in the Company becoming a new entity for financial reporting purposes. As a result of the application of fresh-start accounting and the effects of the implementation of the Plan, the financial statements on or prior to the Effective Date are not comparable with financial statements after the Effective Date.

Upon the application of fresh-start accounting, the Company allocated the reorganization value to its individual assets and liabilities in conformity with ASC 805, Business Combinations (“ASC 805”). The amount of deferred income taxes recorded was determined in accordance with ASC 740, Income Taxes. Reorganization value represents the fair value of the Successor Company’s assets before considering liabilities. The Effective Date fair values of the Company’s assets and liabilities differ materially from their previously recorded values as reflected on the historical balance sheets.
Market Developments
During the first half and through early-August 2021, the oil and natural gas industry has experienced continued improvement in commodity prices as compared to the same period in 2020, primarily resulting from (i) improvements in oil demand as the impact from COVID-19 has begun to abate (although, as of early-August 2021, the COVID-19 Delta variant was showing significant spread globally causing uncertainty regarding future economic impacts) and (ii) actions taken by the Organization of Petroleum Exporting Countries, Russia and certain other oil-exporting countries (“OPEC+”) to reduce the worldwide supply of oil through coordinated production cuts. As a result, West Texas Intermediate (“WTI”) oil prices have increased from $48.52 per barrel at December 31, 2020 to as high as $73.95 per barrel in late-July 2021. Prices for natural gas and NGLs were also much higher during the first half and through early-August 2021 than they were for the same period in 2020. While oil prices have continued to improve in 2021, the general outlook for the oil and natural gas industry for the remainder of the year remains uncertain, and we can provide no assurances as to when or to what extent economic disruptions resulting from COVID-19 and the corresponding decreases in oil demand may impact the Company.
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Operational Highlights for the Second Quarter of 2021
As a result of Lonestar filing for bankruptcy and emerging from bankruptcy on November 30, 2020, our financial results are broken out between the Predecessor periods (the three and six months ended June 30, 2020) and the Successor periods (the three and six months ended June 30, 2021). For the three months ended June 30, 2020 (Predecessor), we recognized a net loss of $42.9 million attributable to common shareholders, and for the three months ended June 30, 2021 (Successor), we recognized a net loss of $17.8 million.
Operational highlights for the second quarter of 2021 included the following:
•Brought four gross wells online during the quarter and an additional three drilled-but-uncompleted wells at our Hawkeye properties;
•Increased production by 14% from the first quarter of 2021;
•Continued to focus on reduced operating expenses. Lease operating expenses were $3.65 per BOE for the quarter while gas gathering, processing and transportation came in at $1.65 per BOE; and
•Continued to build our commodities hedge portfolio to protect our operations from downside price risk. As of August 9, 2021, we had oil hedges covering 5,525 Bbls per day for the remainder of 2021, 3,060 Bbls per day for 2022 and 2,360 Bbls per day for 2023. In addition, on that date, we had natural gas hedges covering 19,365 MMBtu per day of natural gas for the remainder of 2021, 13,745 MMBtu per day for 2022 and 8,743 MMBtu per day for the first half of 2023.

The primary drivers of our financial net loss for the three months ended June 30, 2021 (Successor) included:
•Revenues totaling $46.0 million, comprised of 11,855 BOE per day of production during the quarter with $42.66 per BOE of realized sales price before any hedging effects, and
•Losses on our commodity hedges of $39.9 million for the quarter, comprised of $10.8 million of realized losses and $29.1 million of unrealized losses.
The following reflects some of the primary drivers for our change in operating results between the second quarter of 2021 and the comparative period in 2020:

•Oil and natural gas revenues increased by $28.8 million (167%), due to a 199% increase in commodity prices partially offset by a 33% decrease in production. During the second quarter of 2020, we had a significant amount of production shut-in due to historically low commodity prices;
•Lease operating expenses slightly decreased by $0.1 million (2%), primarily due to lower production volumes in the current quarter;
•Commodity derivative expense increased by $18.8 million ($39.9 million of expense during the second quarter of 2021 compared to $21.1 million of income during the second quarter of 2020); and
•Interest expense decreased significantly between the periods as a result of the extinguishment of the Predecessor 11.25% Senior Notes (discussed further below) on the Effective Date. Depreciation, depletion and amortization (“DD&A”) expense was also significantly lower between the periods as a result of the fresh start accounting (discussed above), which also occurred on the Effective Date.
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RESULTS OF OPERATIONS
Certain of our operating results and statistics for the three and six months ended June 30, 2021 and 2020 are summarized below:
In thousands, except per share and unit data Successor Predecessor Successor Predecessor
Three Months Ended June 30, 2021 Three Months Ended June 30, 2020 Six Months Ended June 30, 2021 Six Months Ended June 30, 2020
Operating results
Net loss attributable to common stockholders $ (17,817) $ (42,901) $ (24,139) $ (155,950)
Net loss per common share – basic(1)
(1.77) (1.70) (2.40) (6.20)
Net loss per common share – diluted(1)
(1.77) (1.70) (2.40) (6.20)
Net cash provided by operating activities 25,514  16,576  27,397  30,411 
Revenues
Oil $ 36,369  $ 11,976  $ 64,234  $ 41,986 
NGLs 4,940  1,762  9,239  4,362 
Natural gas 4,718  3,482  12,365  7,902 
Total revenues $ 46,027  $ 17,220  $ 85,838  $ 54,250 
Total production volumes by product
Oil (Bbls) 566,379  579,179  1,066,377  1,237,680 
NGLs (Bbls) 219,247  267,462  414,935  570,933 
Natural gas (Mcf) 1,759,213  2,203,209  3,188,404  4,313,625 
Total barrels of oil equivalent (6:1) 1,078,828  1,213,843  2,012,713  2,527,551 
Daily production volumes by product
Oil (Bbls/d) 6,224  6,365  5,859  6,800 
NGLs (Bbls/d) 2,409  2,939  2,280  3,137 
Natural gas (Mcf/d) 19,332  24,211  17,519  23,701 
Total barrels of oil equivalent (BOE/d) 11,855  13,339  11,059  13,888 
Average realized prices
Oil ($ per Bbl) $ 64.21  $ 20.16  $ 60.24  $ 33.92 
NGLs ($ per Bbl) 22.53  6.59  22.27  7.64 
Natural gas ($ per Mcf) 2.68  1.58  3.88  1.83 
Total oil equivalent, excluding the effect from commodity derivatives ($ per BOE) 42.66  14.19  42.65  21.46 
Total oil equivalent, including the effect from commodity derivatives ($ per BOE) 32.65  31.22  34.59  32.88 
Operating and other expenses
Lease operating $ 3,933  $ 4,028  $ 8,379  $ 11,667 
Gas gathering, processing and transportation 1,520  875  3,062  3,025 
Production and ad valorem taxes 2,497  1,721  4,917  4,091 
Depreciation, depletion and amortization 5,860  16,575  11,169  40,929 
General and administrative 5,962  5,981  9,939  8,856 
Interest expense 4,323  10,512  8,430  22,122 
Operating and other expenses per BOE
Lease operating $ 3.65  $ 3.32  $ 4.16  $ 4.62 
Gas gathering, processing and transportation 1.41  0.72  1.52  1.20 
Production and ad valorem taxes 2.31  1.42  2.44  1.62 
Depreciation, depletion and amortization 5.43  13.65  5.55  16.19 
General and administrative 5.53  4.93  4.94  3.50 
Interest expense 4.01  8.66  4.19  8.75 

(1) Basic and diluted earnings per share are calculated using the two-class method. See Footnote 1. Basis of Presentation in the Notes to Unaudited Condensed Consolidated Financial Statements included in Item 1.

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Production
The table below summarizes our production volumes for the three and six months ended June 30, 2021 and 2020:
Successor Predecessor Successor Predecessor
Three Months Ended June 30, 2021 Three Months Ended June 30, 2020 Six Months Ended June 30, 2021 Six Months Ended June 30, 2020
Oil (Bbls/d) 6,224  6,365  5,859  6,800 
NGLs (Bbls/d) 2,409  2,939  2,280  3,137 
Natural gas (Mcf/d) 19,332  24,211  17,519  23,701 
Total (BOE/d) 11,855  13,339  11,059  13,888 
Total production during the second quarter of 2021 averaged 11,855 BOE per day, a decrease of 11%, or 1,484 BOE per day, compared to the same period in 2020. This decrease was primarily driven by slower development of our Eagle Ford acreage starting in the second half of 2020 as a result of lower commodity pricing and the Company conserving liquidity during its restructuring, partially offset by the shutting in of a significant amount of production (which effected average daily production for the quarter by approximately 1,700 BOE per day) in our oil-rich Central Eagle Ford region during late April through the end of May 2020 both in response to lower commodity prices at the time. Total production during the first six months of 2021 averaged 11,059 BOE per day, a decrease of 20%, or 2,829 BOE per day, compared to the same period in 2020.
Our production during the second quarter of 2021 was 73% oil and NGLs, compared to 70% during the second quarter of 2020.
Oil, Natural Gas Liquid and Natural Gas Revenues
The table below summarizes our production revenues for the three and six months ended June 30, 2021 and 2020:
In thousands Successor Predecessor Successor Predecessor
Three Months Ended June 30, 2021 Three Months Ended June 30, 2020 Six Months Ended June 30, 2021 Six Months Ended June 30, 2020
Oil $ 36,369  $ 11,976  $ 64,234  $ 41,986 
NGLs 4,940  1,762  9,239  4,362 
Natural gas 4,718  3,482  12,365  7,902 
Total revenues $ 46,027  $ 17,220  $ 85,838  $ 54,250 
Our oil, NGL and natural gas revenues during the three months ended June 30, 2021 increased $28.8 million, or 167%, compared to those revenues for the same period in 2020. For the six months ended June 30, 2020, our oil, NGL and natural gas revenues increased $31.6 million, or 58%, compared to the same period in 2020. The changes in our oil, NGL and natural gas revenues are due to changes in production quantities and commodity prices (excluding any impact of our commodity derivative contracts), as reflected in the following table:
In thousands Three Months Ended June 30, 2021 vs 2020 Six Months Ended June 30, 2021 vs 2020
(Decrease) Increase in Revenues Percentage (Decrease) Increase in Revenues (Decrease) Increase in Revenues Percentage (Decrease) Increase in Revenues
Change in oil, NGL and natural gas revenues due to:
Decrease in production $ (1,916) (11) % $ (11,050) (20) %
Increase in commodity prices 30,723  177  % 42,638  79  %
Total change in oil, NGL and natural gas revenues $ 28,807  166  % $ 31,588  58  %
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Excluding the impact of our commodity derivative contracts, our net realized commodity prices and NYMEX differentials were as follows during the three and six months ended June 30, 2021 and 2020:
Successor Predecessor Successor Predecessor
Three Months Ended June 30, 2021 Three Months Ended June 30, 2020 Six Months Ended June 30, 2021 Six Months Ended June 30, 2020
Average net realized price
Oil ($/Bbl) $ 64.21  $ 20.16  $ 60.24  $ 33.92 
NGLs ($/Bbls) 22.53  6.59  22.27  7.64 
Natural gas ($/Mcf) 2.68  1.58  3.88  1.83 
Total ($/BOE) 42.66  14.19  42.65  21.46 
Average NYMEX differentials
Oil per Bbl $ (1.85) $ (7.17) $ (1.71) $ (3.09)
Natural gas per Mcf (0.26) (0.13) 0.66  0.02 
Variations in our average NYMEX oil differential are generally caused by variations of certain of the pricing components included in our pricing formulae, which are industry standards. The significant improvement in our oil differential between the second quarter of 2021 and 2020 reflects overall stabilization in the market, which was experiencing historical upheaval last year in light of the effects of the COVID-19 pandemic and OPEC+ production decisions.
Variations in our natural gas NYMEX differentials are generally caused by movement in the NYMEX natural gas prices during the month, as most of our natural gas is sold on an index price that is set near the first of each month. While the percentage change in NYMEX natural gas differentials can be large, these variations are seldom more than $0.20 per MMBtu above or below NYMEX price. The natural gas differential for the six months ended June 30, 2021 (Successor) includes the benefit of abnormally high realizations achieved in February 2021 resulting from higher gas residue prices during Winter Storm Uri.
Our natural gas NYMEX differentials are generally caused by movement in the NYMEX natural gas prices during the month, as most of our natural gas is sold on an index price that is set near the first of each month. While the percentage change in NYMEX natural gas differentials can be large, these differentials are seldom more than a dollar above or below NYMEX price.
Commodity Derivative Contracts
We utilize oil and natural gas derivative contracts to provide an economic hedge of our exposure to commodity price risk associated with anticipated future production and to provide more certainty to our future cash flows. These contracts have historically consisted of fixed-price swaps, collars and basis swaps.
The following table summarizes the net cash (payments) receipts on the Company’s commodity derivatives and the relative price impact (per Bbl or Mcf) for the three and six months ended June 30, 2021 and 2020:
Three Months Ended June 30, Six Months Ended June 30,
2021 2020 2021 2020
In thousands, except price impact Net realized settlements Price impact Net realized settlements Price impact Net realized settlements Price impact Net realized settlements Price impact
(Payments) receipts on settlements of oil derivatives $ (8,542) $ (8.01) $ 21,400  $ 36.95  $ (11,963) $ (21.12) $ 21,261  $ 17.18 
Receipts on settlements of natural gas derivatives 58  0.02  1,491  0.68  714  0.41  2,455  0.57 
Total net commodity derivative settlements $ (8,484) $ 22,891  $ (11,249) $ 23,716 
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Our realized net loss on commodity derivative contracts was $10.8 million and $16.2 million for the three and six months ended June 30, 2021 (Successor), respectively, compared to net realized gain of $20.5 million and $28.7 million for the three and six months ended June 30, 2020 (Predecessor), respectively. We realized an average loss of $10.01 and $8.06 per BOE on our oil and natural gas swaps during the three and six months ended June 30, 2021 (Successor), respectively, as compared to an average gain of $17.03 and $11.42 per BOE for the three and six months ended June 30, 2020 (Predecessor), respectively.
In order to provide a level of price protection to a portion of our oil production and to meet certain hedging requirements under our Successor Credit Facility (as defined below), we have hedged a portion of our estimated oil and natural gas production in 2021, 2022 and 2023 using NYMEX fixed-price swaps. See Note 2, Commodity Price Risk Activities, to the consolidated financial statements for additional details of our outstanding commodity derivative contracts as of June 30, 2021 for additional discussion.
The following table summarizes our oil and natural gas derivative contracts as of August 9, 2021:
Q3 2021 Q4 2021 1H 2022 2H 2022 1H 2023 2H 2023
Oil — WTI
Volumes Hedged (Bbls/d) 5,650  5,400  3,124  3,000  2,450  2,275 
Swap Price $ 46.62  $ 46.03  $ 47.32  $ 46.73  $ 54.34  $ 54.16 
Natural Gas — Henry Hub
Volumes Hedged (Mcf/d) 18,030  20,700  14,986  12,500  8,743  — 
Swap Price $ 3.03  $ 3.52  $ 3.19  $ 3.00  $ 3.02  $ — 
Production Expenses
The table below presents detail of production expenses for the three and six months ended June 30, 2021 and 2020:
In thousands, except expense per BOE Successor Predecessor Successor Predecessor
Three Months Ended June 30, 2021 Three Months Ended June 30, 2020 Six Months Ended June 30, 2021 Six Months Ended June 30, 2020
Production expenses
Lease operating $ 3,933  $ 4,028  $ 8,379  $ 11,667 
Gas gathering, processing and transportation 1,520  875  3,062  3,025 
Production and ad valorem taxes 2,497  1,721  4,917  4,091 
Depreciation, depletion and amortization 5,860  16,575  11,169  40,929 
Production expenses per BOE
Lease operating $ 3.65  $ 3.32  $ 4.16  $ 4.62 
Gas gathering, processing and transportation 1.41  0.72  1.52  1.20 
Production and ad valorem taxes 2.31  1.42  2.44  1.62 
Depreciation, depletion and amortization 5.43  13.65  5.55  16.19 
Lease Operating and Gas Gathering, Processing and Transportation
Lease operating expenses are the costs incurred in the operation of producing properties and workover costs. Expenses for direct labor, water injection and disposal, utilities, materials and supplies comprise the most significant portion of our lease operating expenses. Lease operating expenses do not include general and administrative expenses or production and ad valorem taxes.

23

Total lease operating expense was $3.9 million and $8.4 million, or $3.65 and $4.16 per BOE, for the three and six months ended June 30, 2021 (Successor), respectively, compared to $4.0 million and $11.7 million, or $3.32 and $4.62 per BOE, during the Predecessor’s same respective periods in 2020. Total gas gathering, processing and transportation expense was $1.5 million and $3.1 million, or $1.41 and $1.52 per BOE for the three and six months ended June 30, 2021 (Successor), respectively, compared to $0.8 million and $3.0 million, or $0.72 and $1.20 per BOE, during the Predecessor’s same respective periods in 2020. The slight decrease in lease operating expense on an absolute-dollar basis were primarily due lower production in the current quarter.
Production and Ad Valorem Taxes
Production taxes are paid on produced crude oil and natural gas based upon a percentage of gross revenues or at fixed rates established by state or local taxing authorities. In general, the production taxes we pay correlate to the changes in oil and natural gas revenues. We are also subject to ad valorem taxes in the counties where our production is located. Ad valorem taxes are generally based on the valuation of our oil and natural gas properties.

The following table provides detail of our production and ad valorem taxes for the three and six months ended June 30, 2021 and 2020:
Successor Predecessor Successor Predecessor
In thousands Three Months Ended June 30, 2021 Three Months Ended June 30, 2020 Six Months Ended June 30, 2021 Six Months Ended June 30, 2020
Production taxes $ 1,826  $ 729  $ 3,580  $ 2,055 
Ad valorem taxes 671  992  1,337  2,036 
Total production and ad valorem tax expense $ 2,497  $ 1,721  $ 4,917  $ 4,091 
Total production taxes were $1.8 million and $3.6 million, or $1.69 and $1.78 per BOE, for the three and six months ended June 30, 2021 (Successor), respectively, compared to $0.7 million and $2.1 million, or $0.60 and $0.81 per BOE, during the Predecessor’s same respective periods in 2020. Total ad valorem taxes were $0.7 million and $1.4 million, or $0.62 and $0.66 per BOE for the three and six months ended June 30, 2021 (Successor), respectively, compared to $1.0 million and $2.0 million, or $0.82 and $0.81 per BOE, during the Predecessor’s same respective periods in 2020. Higher production taxes in the current periods are due to higher associated commodity prices.
Depreciation, Depletion and Amortization
The table below provides detail of our depreciation, depletion and amortization (“DD&A”) expense for the three and six months ended June 30, 2021 and 2020.
In thousands Successor Predecessor Successor Predecessor
Three Months Ended June 30, 2021 Three Months Ended June 30, 2020 Six Months Ended June 30, 2021 Six Months Ended June 30, 2020
Depletion of proved oil and gas properties $ 5,339  $ 15,925  $ 10,072  $ 39,607 
Depreciation of other property and equipment 301  383  638  746 
Accretion of asset retirement obligations 220  267  459  576 
Total DD&A expense $ 5,860  $ 16,575  $ 11,169  $ 40,929 
Capitalized costs attributed to our proved properties are subject to depreciation and depletion calculated using the unit-of-production method. For leasehold acquisition costs and the cost to acquire proved properties, the reserve base used to calculate depreciation and depletion is the sum of proved developed reserves and proved undeveloped reserves. For well costs, the reserve base used to calculate depletion and depreciation is proved developed reserves only. Other property and equipment are carried at cost, and depreciation is calculated using the straight-line method over the estimated useful lives of the assets, ranging from three to five years.
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Total DD&A expense was $5.9 million and $11.2 million, or $5.43 and $5.55 per BOE, for the three and six months ended June 30, 2021 (Successor), respectively, compared to $16.6 million and $40.9 million, or $13.65 and $16.19 per BOE, during the Predecessor’s same respective periods in 2020. The decreases in the current periods are attributable to lower depletable costs due to the step down in book value resulting from fresh start accounting. Based upon fresh start accounting, oil and gas properties were recorded at fair value as of November 30, 2020.
Impairment of Oil and Gas Properties
We evaluate impairment of proved and unproved oil and gas properties on a region basis. On this basis, certain regions may be impaired because they are not expected to recover their entire carrying value from future net cash flows.
During the first quarter of 2020 (Predecessor), we recorded impairment charges totaling approximately $199.9 million across various Eagle Ford properties, of which $199.0 million was proved and $0.9 million was unproved. These impairments resulted from removing PUDs and probable reserves from future development plans due to the continued depressed commodity prices and the uncertainly of Company’s liquidity situation at the time.
Upon emergence from bankruptcy, the Company adopted fresh start accounting which resulted in our long-lived assets being recorded at their estimated fair values at the Effective Date. There were no material changes to our key cash flow assumptions and no triggering events since December 31, 2020; therefore, no impairment was identified during the second quarter of 2021.
General and Administrative
Total general and administrative (“G&A”) expense was $6.0 million and $9.9 million, or $5.53 and $4.94 per BOE, for the three and six months ended June 30, 2021 (Successor), respectively, compared to $6.0 million and $8.9 million, or $4.93 and $3.50 per BOE, for the three and six months ended June 30, 2020 (Predecessor), respectively. G&A includes approximately $1.2 million of professional fees residual to the Company’s restructuring in 2020, including legal, consulting and accounting fees incurred as part of the Company’s fresh-start accounting process for the six months ended June 30, 2021 (Successor). G&A for the three months ended June 30, 2021 (Successor) includes stock-based compensation expense of $1.4 million attributable to our management incentive plan implemented in April 2021. G&A for the three and six months ended June 30, 2020 (Predecessor) includes stock-based compensation gains of $1.8 million. On the Effective Date, all of the Predecessor’s stock-based compensation plans were cancelled.
Interest Expense
The table below provides detail of the interest expense for our various long-term obligations for the three and six months ended June 30, 2021 and 2020:
In thousands Successor Predecessor Successor Predecessor
Three Months Ended June 30, 2021 Three Months Ended June 30, 2020 Six Months Ended June 30, 2021 Six Months Ended June 30, 2020
Interest expense on Successor Credit Facility $ 3,130  $ —  $ 6,032  $ — 
Interest expense on Successor Term Loan Facility 718  —  1,441  — 
Interest expense on Predecessor 11.25% Senior Notes —  7,031  —  14,062 
Interest expense on Predecessor Credit Facility —  2,664  —  6,356 
Other interest expense 83  211  172  329 
Total cash interest expense (1)
$ 3,931  $ 9,906  $ 7,645  $ 20,747 
Amortization of debt issuance costs and discounts 392  606  785  1,375 
Total interest expense $ 4,323  $ 10,512  $ 8,430  $ 22,122 
Per BOE:
Total cash interest expense $ 3.64  $ 8.16  $ 3.80  $ 8.21 
Total interest expense 4.01  8.66  4.19  8.75 
(1) Cash interest is presented on an accrual basis.
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Total cash interest expense was $3.9 million and $7.6 million, or $3.64 and $3.80 per BOE, for the three and six months ended June 30, 2021 (Successor), respectively, compared to $9.9 million and $20.7 million, or $8.16 and $8.21 per BOE, during the Predecessor’s same respective periods in 2020. The decrease between periods was primarily due to a decrease in the average debt principal outstanding, with the Successor period reflecting the full extinguishment of all outstanding obligations under the 11.25% Senior Secured Notes on the Effective Date, pursuant to the terms of the Plan, relieving approximately $250 million of debt by issuing equity in the Successor period to the holders of that debt.
See Note 6. Long-Term Debt in Notes to the Unaudited Condensed Consolidated Financial Statements for additional information about our long-term debt and interest expense.
Income Taxes
The following table provides further detail of our income taxes for the three and six months ended June 30, 2021 and 2020:
In thousands, except per-BOE amounts and tax rates Successor Predecessor Successor Predecessor
Three Months Ended June 30, 2021 Three Months Ended June 30, 2020 Six Months Ended June 30, 2021 Six Months Ended June 30, 2020
Current income tax benefit (expense) $ —  $ 4,332  $ (160) $ 4,756 
Deferred income tax benefit —  —  —  931 
Total income tax benefit (expense) $ —  $ 4,332  $ (160) $ 5,687 
Average income tax benefit (expense) per BOE $ —  $ 3.57  $ (0.08) $ 2.25 
Effective tax rate —  % 9.6  % (0.7) % 15.8  %
As the tax basis of our assets, primarily our oil and gas properties, is in excess of the carrying value, as adjusted in fresh start accounting, the Successor is in a net deferred tax asset position at June 30, 2021. We evaluated our deferred tax assets in light of all available evidence as of the balance sheet date, including the tax impacts of the Chapter 11 Proceedings and the partial reduction of net operating losses and tax credits and partial reduction of tax basis in assets (collectively “tax attributes”). Given our cumulative loss position, we recorded a total valuation allowance of $42.5 million on our underlying deferred tax assets as of June 30, 2021. For the three and six months ended June 30, 2021 (Successor), the income tax benefit associated with the Successor’s pre-tax book loss was substantially offset by a change in valuation allowance.
Our deferred tax assets exceeded our deferred tax liabilities at June 30, 2020 (Predecessor) primarily due to tax consequences of the impairment of our proved properties during the first quarter of 2020; as a result, we recorded a full valuation allowance of $40.1 million at June 30, 2020 due to uncertainties regarding the future realization of our deferred tax assets.
On March 27, 2020, Congress enacted the Coronavirus Aid, Relief, and Economic Security Act (the “CARES Act”) to provide certain taxpayer relief as a result of the COVID-19 pandemic. The CARES Act included several favorable provisions that impacted income taxes, primarily the modified rules on the deductibility of business interest expense for 2019 and 2020, a five-year carryback period for net operating losses generated after 2017 and before 2021, and the acceleration of refundable alternative minimum tax credits. The CARES Act did not materially impact our effective tax rate for the three and six months ended June 30, 2021 (Successor) and 2020 (Predecessor).

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CAPITAL RESOURCES AND LIQUIDITY
Our primary sources of capital and liquidity are our cash flows from operations and availability of borrowing capacity under our Successor Credit Facility (as defined below). Our most significant cash outlays relate to our development capital expenditures and current period operating expenses.
The Company’s primary needs for cash are for capital expenditures, acquisitions of oil and natural gas properties, payments of contractual obligations and working capital obligations. We have historically financed our business through cash flows from operations, borrowings under our Predecessor Credit Facility (as defined below) and the issuance of bonds and equity offerings. As circumstances warrant, we may access the capital markets and issue equity or debt from time to time on an opportunistic basis in a continued effort to optimize our balance sheet and to fund our operations and capital expenditures in the future, dependent upon market conditions and available pricing. Uses of such proceeds may include repayment of our debt, development or acquisition of additional acreage or proved properties, and general corporate purposes. There can be no assurance that future funding transactions will be available on favorable terms, or at all, and we therefore cannot guarantee the outcome of any such transactions.
Currently, our availability under the Successor Credit Facility is $15.0 million and we are required to make two more quarterly pay-downs on our Successor Term Loan which will total an additional $10.0 million by the end of 2021.

Cash flows for the six months ended June 30, 2021 and 2020 are presented below:
In thousands Successor Predecessor
Six Months ended June 30, 2021 Six Months Ended June 30, 2020
Net cash provided by (used in):
Operating activities $ 27,397  $ 30,411 
Investing activities (22,777) (72,337)
Financing activities (10,121) 40,048 
Net change in cash $ (5,501) $ (1,878)
Net Cash Provided by Operating Activities
Net cash provided by operating activities was $27.4 million for six months ended June 30, 2021 (Successor), compared to $30.4 million for the six months ended June 30, 2020 (Predecessor). The lower current year amount is primarily due to a $36.4 million negative swing in cash hedge settlements between the two periods, largely offset by higher production revenues in the current period as discussed above.
Net Cash Used in Investing Activities
Net cash used in investing activities was $22.8 million for the six months ended June 30, 2021 (Successor), compared to $72.3 million for the six months ended June 30, 2020 (Predecessor). This decrease is primarily due to lower drilling and development costs in the current period, as we did not resume our one-rig drilling program until February 2021 versus the two-rig program we were running throughout the Predecessor period.

Net Cash Used in Financing Activities
Net cash used by financing activities was $10.1 million for the six months ended June 30, 2021 (Successor), compared to $40.0 million provided by financing activities for the six months ended June 30, 2020 (Predecessor). This decrease primarily resulted from no borrowings on the credit line offset by the quarterly $5.0 million pay-downs we made on our Successor Term Loan in 2021.
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Debt
Successor Senior Secured Credit Agreements
On the Effective Date, the Successor, through its subsidiary Lonestar Resources America Inc., entered into a new first-out senior secured revolving credit facility with Citibank, N.A., as administrative agent, and the other lenders from time to time party thereto (the “Successor Credit Facility”) and a second-out senior secured term loan credit facility (the “Successor Term Loan Facility” and, together with the Successor Credit Facility, the “Successor Credit Agreements”) by amending and restating the Company’s existing credit agreement (as so amended and restated, the “Predecessor Credit Facility”). The Successor Credit Facility provides for revolving loans in an aggregate amount of up to $225 million, subject to borrowing base capacity. Letters of credit are available up to the lesser of (a) $2.5 million and (b) the aggregate unused amount of commitments under the Successor Credit Facility then in effect. On the Effective Date, Lonestar Resources America Inc. borrowed $60.0 million in term loans under the Successor Term Loan Facility. The Successor Credit Agreements will mature on November 30, 2023. The term loans under the Successor Term Loan Facility amortize on a quarterly basis in an amount equal to $5.0 million, payable on the last day of March, June, September and December of each year. The Successor’s obligations under the Successor Credit Agreements are guaranteed by all of the Successor’s direct and indirect subsidiaries (subject to certain permitted exceptions) and will be secured by a lien on substantially all of the Successor’s, Lonestar Resources America Inc.’s and the guarantors’ assets (subject to certain exceptions).
Borrowings and letters of credit under the Successor Credit Facility are limited by borrowing base calculations set forth therein. The initial borrowing base is $225 million, subject to redetermination. The borrowing base will be redetermined semiannually on or around May 1 and November 1 of each year, with one interim “wildcard” redetermination available between scheduled redeterminations. The first wildcard redetermination occurred on February 1, 2021, which reaffirmed the initial borrowing base of $225 million and the May 1 redetermination was completed in August 2021, which also reaffirmed the $225 million borrowing base.
The Successor Credit Agreements contain customary covenants, including, but not limited to, restrictions on the Successor’s ability and that of its subsidiaries to merge and consolidate with other companies, incur indebtedness, grant liens or security interests on assets, make acquisitions, loans, advances or investments, pay dividends, sell or otherwise transfer assets, or enter into transactions with affiliates.
The Successor Credit Facility contains certain financial performance covenants including the following:

•A Consolidated Total Debt to Consolidated EBITDAX covenant, with such ratio not to exceed 3.5 times; and

•A requirement to maintain a current ratio (i.e., Consolidated Current Assets to Consolidated Current Liabilities) of at least 0.95 times for the three months ended December 31, 2020 and 1.0 times each fiscal quarter thereafter. The current ratio excludes current derivative assets and liabilities, as well as the current amounts due under the Successor Term Loan Facility, from the ratio.

Borrowings under the Successor Credit Agreements bear interest at a floating rate at the Successor’s option, which can be either an adjusted Eurodollar rate (the Adjusted LIBOR, subject to a 1% floor) plus an applicable margin of 4.50% per annum or a base rate determined under the Successor Credit Facility (the “ABR”, subject to a 2% floor) plus an applicable margin of 3.50% per annum. The weighted average interest rate on borrowings under the Successor Credit Agreements was 5.5% for the three and six months ended June 30, 2021. The undrawn portion of the aggregate lender commitments under the Successor Credit Facility is subject to a commitment fee of 1.0%. As of June 30, 2021, the Successor was in compliance with all debt covenants under the Successor Credit Facilities.

First Amendment

Effective August 6, 2021, we entered into the First Amendment and Borrowing Base Agreement (the “First Amendment”), which reaffirmed the $225 million borrowing base for the Successor Credit Facility pursuant to the scheduled May 1 redetermination and amended certain required swap agreements.

Predecessor Senior Secured Bank Credit Facility

From July 2015 through November 30, 2020, the Predecessor maintained a senior secured revolving credit facility with Citibank, N.A., as administrative agent, and other lenders party thereto. All of the Predecessor Credit Facility was refinanced by the Successor Credit Agreements on the Effective Date.
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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.
Capital Expenditures
The table below summarizes our cash capital expenditures incurred for the six months ended June 30, 2021:
In thousands Six Months Ended June 30, 2021
Acquisition of oil and gas properties $ 1,612 
Development of oil and gas properties 21,489 
Purchases of other property and equipment 13 
Total capital expenditures $ 23,114 
For the six months ended June 30, 2021, our capital expenditures were funded with cash flow from operations. As noted above, cash payments for capital expenditures were lower this quarter as we ran one drilling rig this period starting in February 2021 versus running two rigs throughout the first half of 2020.
2021 Capital Spending
Capital spending levels are highly dependent on revenues, liquidity and our commitment to repay debt. We are currently expect expenditures, including acquisitions, of $45 million to $55 million. This program, as it currently stands, will allow for the drilling of 10 gross wells, all of which will be in our Eagle Ford position in South Texas. As previously noted, our 2021 capital expenditures may be adjusted as business conditions warrant and the amount, timing and allocation of such expenditures is largely discretionary and within our control. The aggregate amount of capital that we will expend may fluctuate materially based on market conditions, the actual costs to drill, complete and place on production operated wells, our drilling results, other opportunities that may become available to us and our ability to obtain capital. In addition, pursuant to the Merger Agreement with Penn Virginia discussed above, certain capital expenditures which exceed the capital budget approved by the Lonestar Board of Directors, asset sales and acquisitions must be approved by Penn Virginia prior to being incurred going forward.
Critical Accounting Policies and Estimates
The preparation of our financial statements requires us to make estimates and judgments that can affect the reported amounts of assets, liabilities, revenues and expenses, as well as the disclosure of contingent assets and liabilities at the date of our financial statements. We analyze our estimates and judgments, including those related to oil, NGLs and natural gas revenues, oil and natural gas properties, impairment of long-lived assets, fair value of derivative instruments, asset and retirement obligations and income taxes, and we base our estimates and judgments on historical experience and various other assumptions that we believe to be reasonable under the circumstances. Actual results may vary from our estimates. The policies of particular importance to the portrayal of our financial position and results of operations and that require the application of significant judgment or estimates by our management are summarized in the Management’s Discussion and Analysis of Financial Condition and Results of Operations section of our Form 10-K.
As of June 30, 2021, there were no significant changes to any of our critical accounting policies and estimates.
Cautionary Note Regarding Forward-looking Statements
This Quarterly Report on Form 10-Q statement contains forward-looking statements that are subject to a number of known and unknown risks, uncertainties, and other important factors, many of which are beyond our control. We intend such forward-looking statements to be covered by the safe harbor provisions for forward-looking statements contained in Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements, other than statements of historical fact included in this Quarterly Report on Form 10-Q, regarding our strategy, future operations, financial position, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this Quarterly Report on Form 10-Q, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “may,” “continue,” “predict,” “potential,” “project” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.

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These forward-looking statements include, among others, statements regarding:
•our growth strategies;
•our ability to explore for and develop oil and gas resources successfully and economically;
•our drilling and completion techniques;
•our estimates and forecasts of the timing, number, profitability and other results of wells we expect to drill and other exploration activities;
•our estimates regarding timing and levels of production;
•changes in working capital requirements, reserves, and acreage;
•commodity price risk management activities and the impact on our average realized prices;
•anticipated trends in our business and industry;
•availability of pipeline connections and water disposal on economic terms;
•effects of competition on us;
•our future results of operations;
•profitability of drilling locations;
•our reputation as an operator and our relationships and contacts in the market;
•our liquidity, our ability to continue as a going concern and our ability to finance our exploration and development activities, including accessibility of borrowings under our senior secured credit facility, our borrowing base, and the result of any borrowing base redetermination;
•our ability to maintain compliance with covenants and ratios under our senior secured credit facility;
•our planned expenditures, prospects and capital expenditure plan;
•future market conditions in the oil and gas industry;
•our ability to make, integrate and develop acquisitions and realize any expected benefits or effects of completed acquisitions;
•the benefits, effects, availability of and results of new and existing joint ventures and sales transactions;
•our ability to maintain a sound financial position;
•receipt of receivables, drilling carry and proceeds from sales;
•our ability to complete planned transactions on desirable terms;
•the impact of governmental regulation, taxes, market changes and world events; and
•global or national health concerns, including health epidemics such as the ongoing coronavirus outbreak beginning in early 2020.

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All forward-looking statements speak only as of the date of this Quarterly Report on Form 10-Q. You should not place undue reliance on these forward-looking statements. Although we believe that our plans, objectives, expectations and intentions reflected in or suggested by the forward-looking statements we make in this Quarterly Report on Form 10-Q are reasonable, we can give no assurance that these plans, objectives, expectations or intentions will be achieved. We disclose important factors that could cause our actual results to differ materially from our expectations under Item 1A. Risk Factors, Item 8. Financial Statements and Supplementary Data and elsewhere in our Form 10-K, and Part I. Financial Information, Item 1A. Risk Factors and elsewhere in this Quarterly Report on Form 10-Q.
These important factors include risks related to:
•    variations in the market demand for, and prices of, crude oil, NGLs and natural gas;
•    proved reserves or lack thereof;
•    estimates of crude oil, NGLs and natural gas data;
•    the adequacy of our capital resources and liquidity including, but not limited to, access to additional borrowing to fund our operations;
•    borrowing capacity under our credit facility;
•    general economic and business conditions;
•    failure to realize expected value creation from property acquisitions;
•    uncertainties about our ability to find, develop or acquire additional oil and natural gas resources;
•    uncertainties with regard to our drilling schedules;
•    the expiration of leases on our undeveloped leasehold assets;
•    our dependence upon several significant customers for the sale of most of our crude oil, natural gas and NGL production;
•    counterparty credit risks;
•    competition within the crude oil and natural gas industry;
•    technology risks;
•    the geographic concentration of our operations;
•    drilling results;
•    potential financial losses or earnings reductions from our commodity price risk management programs;
•    potential adoption of new governmental regulations;
•    our ability to satisfy future cash obligations and environmental costs; and
•    the other factors set forth under Risk Factors in Item 1A of Part I of our Form 10-K.
The forward-looking statements relate only to events or information as of the date on which the statements are made in this Quarterly Report on Form 10-Q. Except as required by law, we undertake no obligation to update or revise publicly any forward-looking statements, whether as a result of new information, future events or otherwise, after the date on which the statements are made or to reflect the occurrence of unanticipated events.
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Item 3. Quantitative and Qualitative Disclosures About Market Risk.
The following quantitative and qualitative disclosures about market risk are supplementary to the quantitative and qualitative disclosures provided in the Form 10-K. As such, the information contained herein should be read in conjunction with the related disclosures in the Form 10-K.
Commodity Price Risk
As a result of our operations, we are exposed to commodity price risk arising from fluctuations in the prices of crude oil, NGLs and natural gas. The demand for, and prices of, crude oil, NGLs and natural gas are dependent on a variety of factors, including supply and demand, weather conditions, the price and availability of alternative fuels, actions taken by governments and international cartels and global economic and political developments.
The following table shows the fair value of our derivative contracts and the hypothetical result from a 10% change in commodity prices as of June 30, 2021. We remain at risk for possible changes in the market value of commodity derivative instruments; however, such risks could be mitigated by price changes in the underlying physical commodity:
Hypothetical Fair Value
(in thousands) Fair Value 10% Increase In Commodity Price 10% Decrease In Commodity Price
Swaps $ (59,078) $ (80,539) $ (37,617)
Our board of directors reviews oil and natural gas hedging on a quarterly basis. Reports providing detailed analysis of our hedging activity are continually monitored. We sell our oil and natural gas on market using NYMEX market spot rates reduced for basis differentials in the basins from which we produce. We use swap contracts to manage our commodity price risk exposure. Our primary commodity risk management objectives are to protect returns on our drilling and completion activity as well as reduce volatility in our cash flows. Management makes recommendations on hedging that are approved by the board of directors before implementation. We enter into hedges for oil using NYMEX futures or over-the-counter derivative financial instruments with only certain well-capitalized counterparties which have been approved by our board of directors.
The result of oil market prices exceeding our swap prices or collar ceilings requires us to make payment for the settlement of our hedge derivatives, if owed by us, generally up to three business days before we receive market price cash payments from our customers. This could have a material adverse effect on our cash flows for the period between hedge settlement and payment for revenues earned.
Interest Rate Risk
As of June 30, 2021, we had $254.6 million outstanding under the Successor Credit Agreements, which are subject to floating market rates of interest. Borrowings under the Successor Credit Agreements bear interest at a fluctuating rate that is tied to an adjusted base rate or LIBOR, at our option. Any increase in this interest rate can have an adverse impact on our results of operations and cash flow. Based on borrowings outstanding at June 30, 2021, a 100-basis-point change in interest rates would change our annualized interest expense by approximately $2.5 million.
Counterparty and Customer Credit Risk
In connection with our hedging activity, we have exposure to financial institutions in the form of derivative transactions. The counterparties on our derivative instruments currently in place have investment-grade credit ratings. We expect that any future derivative transactions we enter into will be with these counterparties or our lenders under our Successor Credit Agreements that will carry an investment-grade credit rating.
We are also subject to credit risk due to concentration of our oil and natural gas receivables with certain significant customers. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. We review the credit rating, payment history and financial resources of our customers, but we do not require our customers to post collateral.
32

Item 4. Controls and Procedures.
Evaluation of Disclosure Controls and Procedures.
As of the end of the period covered by this report, an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act) was performed under the supervision and with the participation of management, including our Chief Executive Officer and Chief Accounting Officer. Based on that evaluation, our Chief Executive Officer and Chief Accounting Officer concluded that our disclosure controls and procedures were effective as of June 30, 2021 to ensure that information that is required to be disclosed in the reports the Company files and submits under the Securities Exchange Act of 1934, as amended (the “Exchange Act”) is recorded, that it is processed, summarized and reported within the time periods specified in the SEC’s rules and forms; and that information that is required to be disclosed under the Exchange Act is accumulated and communicated to management, including our Chief Executive Officer and our Chief Accounting Officer, as appropriate, to allow timely decisions regarding required disclosures.
Changes in Internal Control over Financial Reporting.
During the second quarter of fiscal 2021, there were no changes in our internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.





33

PART II—OTHER INFORMATION
Item 1. Legal Proceedings.
From time to time, we are subject to legal proceedings and claims that arise in the ordinary course of business. Like other crude oil and gas producers and marketers, our operations are subject to extensive and rapidly changing federal and state environmental, health and safety, and other laws and regulations governing air emissions, wastewater discharges and solid and hazardous waste management activities. We are not aware of any pending or overtly threatened legal action against us that could have a material impact on our business.
Item 1A. Risk Factors.
Please refer to Item 1A of the Company’s Form 10-K. There have been no material changes to our risk factors contained in our Form 10-K.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.
The following table summarizes purchases of our Common Stock during the second quarter of 2021:
Total number of Shares Purchased Average Price Paid per Share Total Number of Shares that May Yet Be Purchased as Part of Publicly Announced Plans or Programs Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs
April 2021 39,654  $ 7.25  —  $ — 
May 2021 —  —  —  — 
June 2021 —  —  —  — 
Total 39,654  — 
Stock repurchases during the second quarter of 2021 were made in connection with delivery by our employees of shares to us to satisfy their tax withholding requirements related to the vesting of restricted shares.
34

Item 6. Exhibits.
Exhibit Number Description Incorporated by Reference Filing
Date 		Filed/
Furnished
Herewith
Form File No. Exhibit
10.1† S-8 333-255213 10.1 4/13/2021
10.2† 10-Q 333-255213 10.2 5/11/2021
10.3† 10-Q 333-255213 10.3 5/11/2021
10.4 *
31.1 *
31.2 *
32.1 **
32.2 **
101.INS XBRL Instance Document *
101.SCH XBRL Taxonomy Extension Schema Document *
101.CAL XBRL Taxonomy Extension Calculation Linkbase Document *
101.DEF XBRL Taxonomy Extension Definition Linkbase Document *
101.LAB XBRL Taxonomy Extension Label Linkbase Document *
101.PRE XBRL Taxonomy Extension Presentation Linkbase Document *
*    Filed herewith.
**    Furnished herewith
†    Management contract or compensatory plan or arrangement
35

SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
LONESTAR RESOURCES US INC.
August 10, 2021 /s/ Frank D. Bracken, III
Frank D. Bracken, III
Chief Executive Officer
August 10, 2021 /s/ Jason N. Werth
Jason N. Werth
Chief Accounting Officer
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