UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

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


Title of Each Class	Trading Symbol	Name of Exchange on Which Registered
Common Stock, par value $0.001	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 ~~and posted on its corporate Web site, if any,~~ every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T ~~(§ 232.405 of this chapter)~~ 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.~~

Act:

Large accelerated filer

☐

Accelerated filer

☐

Non-accelerated filer

☐

~~(Do not check if a smaller reporting company)~~

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 ☒

As of ~~November 10, 2017,~~May 7, 2021, the registrant had ~~24,506,647~~10,097,281 shares of ~~Class A voting~~ common stock, par value $0.001 per share, outstanding.

Item 1. Financial ~~Statements.~~

Statements

Unaudited Condensed Consolidated Balance Sheets

(In thousands, except ~~share~~par value and ~~per~~ share data)

See accompanying ~~notes~~Notes to ~~unaudited consolidated financial statements.~~

Unaudited Condensed Consolidated Financial Statements.

Lonestar Resources US Inc.

Unaudited Condensed Consolidated ~~Balance Sheets (continued)~~

Statements of Operations

(In thousands, except ~~share and~~ per share data)

September 30,
2017

December 31,
2016

Liabilities and Stockholders’ Equity

(Unaudited)

Current liabilities

Accounts payable

$
12,386

$
14,894

Accounts payable – related parties

108

1,135

Oil, natural gas liquid and natural gas sales payable

7,521

3,568

Accrued liabilities

22,365

9,947

Accrued liabilities – related parties

78

224

Derivative financial instruments

1,991

2,985

Total current liabilities

44,449

32,753

Long-term debt

286,398

204,122

Long-term debt - related parties

—

3,400

Deferred tax liability

21,977

38,020

Other non-current liabilities

6,241

6,052

Equity warrant liability

439

1,565

Equity warrant liability - related parties

834

2,994

Asset retirement obligations

5,097

2,683

Derivative financial instruments

2,672

1,125

Total liabilities

368,107

292,714

Commitments and contingencies

Mezzanine equity

Series A-2 convertible participating preferred stock, $0.001 par value, 76,577 issued and outstanding at September 30, 2017 and 0 issued and outstanding at December 31, 2016

74,712

—

Stockholders’ equity

Class A voting common stock, $0.001 par value, 100,000,000 shares authorized, 21,822,015 issued and outstanding at September 30, 2017 and December 31, 2016, respectively

142,652

142,652

Class B non-voting common stock, $0.001 par value, 5,000 shares authorized, 2,500 issued and outstanding at September 30, 2017 and December 31, 2016, respectively

—

—

Series A-1 convertible participating preferred stock, $0.001 par value and Series B convertible participating preferred stock, $0.001 par value, 5,543 shares and 2,684,632 shares issued and outstanding at September 30, 2017, respectively, 0 and 0 issued and outstanding at December 31, 2016, respectively

3

—

Additional paid-in capital

100,146

87,260

Accumulated deficit

(90,374
)

(63,517
)

Total stockholders’ equity

152,427

166,395

Total liabilities and stockholders’ equity

$
595,246

$
459,109


	Successor		Predecessor
	Three Months Ended March 31, 2021		Three Months Ended March 31, 2020
Revenues
Oil sales	$	27,872	$	29,990
Natural gas liquid sales	4,297		2,599
Natural gas sales	7,647		4,420
Total revenues	39,816		37,009
Expenses
Lease operating	4,446		$	7,638
Gas gathering, processing and transportation	1,542		2,150
Production and ad valorem taxes	2,421		2,369
Depreciation, depletion and amortization	5,309		24,354

Impairment of oil and gas properties	0		199,908
General and administrative	3,977		2,881
Other	10		(223)
Total expenses	17,705		239,077
Income (loss) from operations	22,111		(202,068)
Other (expense) income
Interest expense	(4,106)		(11,610)
Change in fair value of warrants	0		363
(Loss) gain on derivative financial instruments	(24,167)		101,169
Total other (expense) income	(28,273)		89,922
Loss before income taxes	(6,162)		(112,146)
Income tax (expense) benefit	(160)		1,355
Net Loss	(6,322)		(110,791)
Preferred stock dividends	0		(2,257)
Net loss attributable to common stockholders	$	(6,322)	$	(113,048)

Net loss per common share
Basic	$	(0.63)	$	(4.52)
Diluted	$	(0.63)	$	(4.52)

Weighted average common shares outstanding
Basic	10,000,149		25,003,977
Diluted	10,000,149		25,003,997

See accompanying ~~notes~~Notes to ~~unaudited consolidated financial statements.~~

Unaudited Condensed Consolidated Financial Statements.

Lonestar Resources US Inc.

Unaudited Condensed Consolidated Statements ~~of Operations & Comprehensive Income (Loss)~~

~~(In thousands, except share and per share data)~~

~~(Unaudited)~~

Three Months Ended

Nine Months Ended

September 30,

September 30,

2017

2016

2017

2016

Revenues

Oil sales
$
23,162

$
12,285

$
52,742

$
36,404

Natural gas sales

1,890

2,190

5,072

5,448

Natural gas liquid sales

1,831

1,063

4,820

2,685

Total revenues

26,883

15,538

62,634

44,537

Costs and expenses

Lease operating and gas gathering

4,515

4,006

10,992

12,764

Production, ad valorem, and severance taxes

1,541

907

3,656

3,046

Rig standby expense

61

364

61

2,261

Depletion, depreciation, and amortization

15,891

10,665

40,527

38,301

Accretion of asset retirement obligations

38

53

96

160

Loss (gain) on sale of oil and gas properties

119

53

466

(1,478
)
Impairment of oil and gas properties

—

29,144

27,081

31,082

Stock-based compensation

346

122

985

313

General and administrative

2,298

2,870

7,940

8,501

Acquisition costs

337

—

3,063

—

Other (income) expense

(4
)

1

(62
)

1,045

Total costs and expenses

25,142

48,185

94,805

95,995

Income (loss) from operations

1,741

(32,647
)

(32,171
)

(51,458
)

Other income (expense)

Interest expense

(5,031
)

(5,751
)

(15,448
)

(16,961
)
Gain on disposal of bonds

—

29,363

—

29,363

Amortization of finance costs

(934
)

(1,594
)

(4,368
)

(2,683
)
Gain (loss) on warrants

402

(611
)

3,286

(611
)
Gain (loss) on derivative financial instruments

(7,657
)

1,664

6,505

(3,405
)

Total other income (expense), net

(13,220
)

23,071

(10,025
)

5,703

Loss before income taxes

(11,479
)

(9,576
)

(42,196
)

(45,755
)

Income tax benefit (expense)

4,718

(1,684
)

15,339

10,354

Net loss

(6,761
)

(11,260
)

(26,857
)

(35,401
)

Preferred stock dividends

(1,824
)

—

(2,120
)

—

Net loss attributable to common stockholders
$
(8,585
)

$
(11,260
)

$
(28,977
)

$
(35,401
)
Earnings per share:

Basic
$
(0.39
)

$
(1.44
)

$
(1.33
)

$
(4.64
)
Diluted
$
(0.39
)

$
(1.44
)

$
(1.33
)

$
(4.64
)
Weighted Average Shares Outstanding - basic

21,822,015

7,842,586

21,822,015

7,629,896

Weighted Average Shares Outstanding - diluted

21,822,015

7,842,586

21,822,015

7,629,896

Comprehensive loss:

Net loss
$
(6,761
)

$
(11,260
)

$
(26,857
)

$
(35,401
)
Foreign currency translation adjustments

—

(13
)

—

(29
)
Comprehensive loss
$
(6,761
)

$
(11,273
)

$
(26,857
)

$
(35,430
)

~~See accompanying notes to unaudited consolidated financial statements.~~

~~Lonestar Resources US Inc.~~

~~Consolidated Statement~~ of Changes in Stockholders’ Equity

(In thousands, except share data)

~~(Unaudited)~~

Accumulated

Class A Voting

Series A-1 and Series B

Additional

Other

Common Stock

Preferred Stock

Paid-in

Accumulated

Comprehensive

Total Stockholders'

Shares

Amount

Shares

Amount

Capital

Deficit

Loss

Equity

Balance at December 31, 2015

7,521,788

$
142,638

—

$
—

$
10,270

$
30,818

$
(760
)

$
182,966

Sale of common stock, net of offering costs

13,800,000

14

—

—

71,803

—

—

71,817

Shares issued for asset acquisition

500,227

—

—

—

5,499

—

—

5,499

Stock-based compensation

—

—

—

—

448

—

—

448

Foreign currency translation

—

—

—

—

(760
)

—

760

—

Net loss

—

—

—

—

—

(94,335
)

—

(94,335
)

Balance at December 31, 2016

21,822,015

$
142,652

—

$
—

$
87,260

$
(63,517
)

$
—

$
166,395

Shares issued for asset acquisitions

—

—

2,690,175

3

12,090

—

—

12,093

Stock-based compensation

—

—

—

—

796

—

—

796

Net loss

—

—

—

—

—

(26,857
)

—

(26,857
)

Balance at September 30, 2017

21,822,015

$
142,652

2,690,175

$
3

$
100,146

$
(90,374
)

$
—

$
152,427


	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


	Class A Voting Common Stock			Series A-1 Preferred Stock			Additional Paid-in Capital		Accumulated Deficit		Total Stockholders' 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

See accompanying ~~notes~~Notes to ~~unaudited consolidated financial statements.~~

Unaudited Condensed Consolidated Financial Statements.

Lonestar Resources US Inc.

Unaudited Condensed Consolidated Statements of Cash Flows

(In thousands)

~~(Unaudited)~~

Nine Months Ended

September 30,

2017

2016

Operating activities

Net loss

$
(26,857
)

$
(35,401
)
Adjustments to reconcile net loss to net cash provided by operating activities:

Gain on disposal of oil and gas properties

—

(866
)
Accretion of asset retirement obligations

96

160

Depreciation, depletion, and amortization

40,527

38,301

Stock-based compensation

985

313

Deferred taxes

(16,043
)

(10,432
)
Gain on disposal of bonds

—

(29,363
)
(Gain) losses on derivative financial instruments

(6,505
)

3,405

Settlements of derivative financial instruments

4,894

24,322

Impairment of oil and gas properties

27,081

31,082

Non-cash interest expense

4,375

1,677

(Gain) loss on warrants

(3,286
)

611

Changes in operating assets and liabilities:

Accounts receivable

(5,214
)

865

Prepaid expenses and other assets

(3,559
)

(1,961
)
Accounts payable and accrued expenses

11,973

(4,479
)
Net cash provided by operating activities

28,467

18,234

Investing activities

Acquisition of oil and gas properties

(109,031
)

(3,115
)
Development of oil and gas properties

(56,918
)

(24,856
)
Proceeds from sales of oil and gas properties

—

2,720

Purchases of other property and equipment

(11,580
)

(202
)
Net cash used in investing activities

(177,529
)

(25,453
)

Financing activities

Proceeds from borrowings and related party borrowings

102,988

63,714

Payments on borrowings and related party borrowings

(27,504
)

(54,789
)
Proceeds from sale of preferred stock

77,800

—

Cost to issue equity

(2,790
)

—

Payments of debt issuance costs

(2,685
)

—

Changes in other notes payable

(3
)

(9
)
Net cash provided by financing activities

147,806

8,916

Effect of exchange rate changes on cash and cash equivalents

—

(29
)

(Decrease) increase in cash and cash equivalents

(1,256
)

1,668

Cash and cash equivalents, beginning of the period

6,068

4,322

Cash and cash equivalents, end of the period

$
4,812

$
5,990

Supplemental information:

Net cash used by operating activities:

Cash paid for taxes

$
2,465

$
—

Cash paid for interest expense

11,060

14,095

Non-cash investing and financing activities:

Preferred stock issued for asset acquisition

$
10,795

$
—

Common stock issued for asset acquisition

—

5,500


	Successor		Predecessor
	Three Months Ended March 31, 2021		Three Months Ended March 31, 2020
Cash flows from operating activities
Net loss	$	(6,322)	$	(110,791)
Adjustments to reconcile net loss to net cash provided by operating activities:
Accretion of asset retirement obligations	115		86
Depreciation, depletion and amortization	5,181		24,268
Stock-based compensation	0		(2,022)
Deferred taxes	0		(1,376)
Loss (gain) on derivative financial instruments	24,662		(101,169)
Settlements of derivative financial instruments	(3,370)		1,096
Impairment of oil and natural gas properties	0		199,908
Gain on disposal of property and equipment	0		83


Non-cash interest expense	482		768
Change in fair value of warrants	0		(363)
Changes in operating assets and liabilities:
Accounts receivable	(5,328)		6,117
Prepaid expenses and other assets	(343)		(374)
Accounts payable and accrued expenses	(13,194)		(2,396)
Net cash provided by operating activities	1,883		13,835

Cash flows from investing activities
Acquisition of oil and gas properties	(1,215)		(816)
Development of oil and gas properties	(389)		(34,753)
Proceeds from sale of oil and gas properties	0		317
Purchases of other property and equipment	(11)		(524)
Net cash used in investing activities	(1,615)		(35,776)

Cash flows from financing activities
Proceeds from borrowings	0		28,000
Payments on borrowings	(5,063)		(8,054)

Net cash (used in) proved by financing activities	(5,063)		19,946
Net decrease in cash, cash equivalents and restricted cash	(4,795)		(1,995)
Cash, cash equivalents and restricted cash, beginning of the period	26,446		3,137
Cash, cash equivalents and restricted cash, end of the period	$	21,651	$	1,142

Supplemental information:

Cash paid for interest	$	3,648	$	3,957
Non-cash investing and financing activities:
Change in asset retirement obligation	$	(382)	$	(253)
Change in liabilities for capital expenditures	(14,305)		(1,040)

See accompanying ~~notes~~Notes to ~~unaudited consolidated financial statements.~~

Unaudited Condensed Consolidated Financial Statements.

Lonestar Resources US Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

~~(Unaudited)~~

Note 1. Basis of Presentation

Organization and Nature of ~~Business and Presentation~~

Operations

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

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

Interim Financial Statements

The accompanying unaudited condensed consolidated financial statements (“Unaudited Condensed Consolidated Financial Statements”) of Lonestar Resources US Inc. Its executive offices are located in Fort Worth, Texas. LRAI was a wholly owned subsidiary of the Predecessor, prior to the reorganization described above. The majority of the activities of the Predecessor were carried out through LRAI. Unless the context otherwise requires, references in this Quarterly Report on Form 10-Q to “Lonestar,” “we,” “us,” “our,” and “the Company” refer to (i) Lonestar Resources Limited, and its subsidiaries ~~prior to the Reorganization and (ii) Lonestar Resources US Inc. and its subsidiaries upon completion of the Reorganization, as applicable.~~

~~Basis of Presentation~~

~~The accompanying interim consolidated financial statements~~ have ~~not~~ been audited by independent public accountants, but in the opinion of management, reflect all adjustments necessary for a fair presentation of the financial position and results of operations. Any and all adjustments are of a normal and recurring nature. Although management believes the unaudited interim-related disclosures in these consolidated financial statements are adequate to make the information presented not misleading, certain information and footnote disclosures normally included in annual audited consolidated financial statements prepared in accordance with ~~accounting principles generally accepted in the United States of America have been condensed or omitted pursuant to~~ the rules and regulations of the Securities and Exchange ~~Commission.~~ 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 ~~and the cash flows~~ for the ~~nine months ended September 30, 2017~~interim periods shown in this report are not necessarily indicative of ~~the~~ results to be expected for the ~~full~~ year.

~~Principles~~ In management’s opinion, the accompanying Unaudited Condensed Consolidated Financial Statements include all adjustments of ~~Consolidation~~

~~The accompanying~~a normal recurring nature necessary for a fair statement of our consolidated financial ~~statements include~~position as of March 31, 2021 and our consolidated results of operations for the ~~accounts~~three months ended March 31, 2021 and March 31, 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 adopted and began applying the relevant guidance provided in GAAP with respect to the accounting and financial statement disclosures for entities that have emerged from bankruptcy proceedings (“Fresh Start Accounting”) on the Effective Date. Accordingly, the Company’s ~~wholly owned subsidiaries. All significant intercompany balances~~Unaudited Condensed Consolidated Financial Statements and ~~transactions~~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.

Furthermore, our Unaudited Condensed Consolidated Financial Statements and Notes to Unaudited Condensed Consolidated Financial Statements have been ~~eliminated~~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.

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	March 31, 2021		March 31, 2020
Cash and cash equivalents	$	19,494	$	1,142
Restricted cash, current	2,157		0
Total cash, cash equivalents and restricted cash shown in the Unaudited Condensed Consolidated Statements of Cash Flows	$	21,651	$	1,142

Restricted cash, current in ~~consolidation.~~

~~2. Recently Issued~~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.

During the first quarter and through early-May 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 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 $66.09 per barrel in early March 2021. Prices for natural gas and NGLs were also much higher during the first quarter and through early-May 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.

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 months ended March 31, 2020 and 2021, respectively.

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 first quarter of 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.

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
	Three Months Ended March 31, 2021	Three Months Ended March 31, 2020
Preferred stock	0	16,725,467
Warrants	1,111,110	760,000
Stock appreciation rights	0	1,010,000
Restricted stock units	0	1,925,366

Recent Accounting Pronouncements

Income Taxes.In ~~July 2017,~~December 2019, the Financial Accounting Standards Board ~~("FASB"~~(“FASB”) issued ~~Accounting Standards Update ("ASU") No. 2017-11, “(Part I)~~ASU 2019-12, Income Taxes (Topic 740) – Simplifying the Accounting for ~~Certain Financial Instruments with Down Round Features” in order~~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 ~~instruments with down round features. Part I~~statements. The amendments in this ASU were effective starting January 1, 2021 for the Company. The adoption of the standard did not have an impact on the Company’s Unaudited Condensed Consolidated Financial Statements.

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 ~~classification analysis~~impairment model for most financial assets and certain other instruments, including trade and other receivables, and requires the use of ~~certain equity-linked financial instruments, such as warrants and embedded conversion features, such~~a new forward-looking expected loss model that ~~a down round feature is disregarded when assessing whether~~will result in the instrument is indexed to an entity’s own stock under Subtopic 815-40. As a result, a down round feature – by itself – no longer requires an instrument to be remeasured at fair value through earnings each period, although all other aspectsearlier recognition of ~~the indexation guidance under Subtopic 815-40 continue to apply. For public entities, the~~allowances for losses. The amendments in ~~Part I of the~~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, ~~beginning after December 15, 2018. Management~~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 ~~evaluating the new guidance~~not expected to ~~determine the impact it will~~ have ~~on our consolidated results of operations, financial position or cash flows and anticipates adopting the guidance~~a material effect on the ~~effective date of January 1, 2019.~~

Company’s Unaudited Condensed Consolidated Financial Statements.

Reference Rate Reform. In ~~February 2016,~~March 2020, the FASB issued ASU ~~No. 2016-02, “Leases~~2020-04, Reference Rate Reform (Topic ~~842)” which will require organizations that lease assets to recognize on the balance sheet the assets and liabilities for the rights and obligations created by those leases. This~~ 848) (“ASU ~~is effective for the annual period beginning after December 15, 2018, including interim periods within those fiscal years. Early adoption is permitted.~~

Management is currently evaluating the new guidance to determine the impact it will have on our consolidated results of operations, financial position or cash flows and anticipates adopting the guidance on the effective date of January 1, 2019.

~~In May 2014, the FASB issued ASU No. 2014-09,~~ ~~Revenue from Contracts with Customers~~. The objective of ASU 2014-09 is greater consistency and comparability across industries by using a five-step model to recognize revenue from customer contracts. ASU 2014-09 also contains some new disclosure requirements under GAAP. In August 2015, the FASB issued ASU No. 2015-14, ~~Deferral of the Effective Date~~2020-04”). ASU ~~2015-14 defers~~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 ~~date of~~upon issuance and generally can be applied to applicable contract modifications through December 31, 2022. Currently, the ~~new revenue standard by one year, making it effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. In 2016,~~Company’s Successor Credit Agreements (as defined below) are the FASB issued additional accounting standards updates to clarify the implementation guidance of ASU 2014-09. The Company is currently determining the impacts of the new revenue standard on its contracts. The Company is currently completing a detailed analysis of its revenue streams at the individual contract level to evaluate the impact of the new revenue standard on its consolidated financial statements. Oil sales represent approximately 84~~% of total revenue, with gas and NGL sales comprising the remainder. The Company has identified and reviewed oil sales~~Company’s only contracts that ~~comprised approximately~~ 80~~% of oil revenue through September 30, 2017. Based on current assessments completed~~makes reference to ~~date, we do not expect~~a LIBOR rate and the ~~adoption of this standard will have a material impact on net earnings, however, this conclusion is subject to change. The Company has identified and reviewed gas contracts comprising approximately~~ 80~~% of our gas and NGL sales through September 30, 2017 and we are still in~~agreements outline the ~~process of completing our analysis. The Company’s disclosures surrounding revenue recognition~~specific procedures that will be more substantial upon adoption. The Company will complete its evaluation during the fourth quarter of 2017 and will adopt this new standard on January 1, 2018, using the modified retrospective method with a cumulative adjustment to retained earnings.

~~3. Acquisitions and Divestitures~~

~~On August 2, 2017, the Company closed on the purchase of~~undertaken once an ~~office building with an acquisition price approximating $10 million. The building will be primarily used for the Company’s headquarters and~~appropriate alternative benchmark is ~~located in Fort Worth, Texas.~~

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

On June 15, 2017, the Company closed an acquisition with SN Marquis LLC (a subsidiary of Sanchez Energy Corporation) (“Marquis”) whereby the Company acquired oil and gas properties in the Eagle Ford Shale play in Fayette, Gonzales and Lavaca County, Texas (the “Marquis Acquisition”). These assets are expected to significantly expand our asset base and production. The total purchase consideration of approximately $50.0 million consisted of $44.0 million in cash and 1,500,000 shares of Series B Preferred Stock at a value of approximately $6.0 million. Allocation of the purchase price was as follows: $48.0 million to proved reserves; $0.6 to unproved reserves and $1.4 million to land, building and other assets. Additionally, the Company recorded an asset retirement obligation of approximately $1.9 million, resulting in fair value of net assets acquired of approximately $48.1 million. The Company accounted for the acquisition as a business combination under ASC Topic 805. Acquisition related costs of approximately $1.2 million were charged to Acquisition Costs in the Consolidated Statements of Operations & Comprehensive Income (Loss). The effective date of the acquisition was January 1, 2017.

~~Pro Forma Operating Results~~

The following unaudited pro forma combined financial information for the three and nine months ended September 30, 2017 and 2016 is based on the historical consolidated financial statements of the Company adjusted to reflect as if the Battlecat Acquisition and the Marquis Acquisition had closed and related financing had occurred on January 1, 2016. The unaudited pro forma combined financial information includes adjustments primarily for revenues and expenses for the acquired properties, depreciation, depletion, amortization and accretion, and interest expense. The unaudited pro forma combined financial statements give effect to the events set forth below:

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

~~The borrowing of approximately $24 million on our Senior Secured Credit Facility to finance a portion of the Battlecat Acquisition and the Marquis Acquisition.~~

~~The issuance of 1,500,000 shares of the Company’s Series B Preferred Stock to SN UR Holdings, LLC (a subsidiary of Sanchez Energy Corporation).~~

~~The issuance of 1,184,632 shares of the Company’s Series B Preferred Stock to Battlecat Oil & Gas, LLC.~~

Three months ended September 30, 2017

Lonestar

Marquis

Battlecat

Pro Forma Adjustments

Pro Forma Lonestar

Revenues
$
26,883

$
—

$
—

$
—

$
26,883

Net income (loss) attributable to common stockholders

(8,585
)

—

—

—

(8,585
)
Net income (loss) per common share, basic and diluted

(0.39
)

—

—

—

(0.39
)

Three months ended September 30, 2016

Lonestar

Marquis

Battlecat

Pro Forma Adjustments

Pro Forma Lonestar

Revenues
$
15,538

$
7,318

$
1,090

$
—

$
23,946

Net income (loss) attributable to common stockholders

(11,260
)

4,127

516

(5,470
)

(12,088
)
Net income (loss) per common share, basic and diluted

(1.44
)

—

—

—

(1.54
)

Nine months ended September 30, 2017

Lonestar

Marquis

Battlecat

Pro Forma Adjustments

Pro Forma Lonestar

Revenues
$
62,634

$
11,983

$
1,802

$
—

$
76,419

Net income (loss) attributable to common stockholders

(28,977
)

7,688

603

922

(19,764
)
Net income (loss) per common share, basic and diluted

(1.33
)

—

—

—

(0.91
)

Nine months ended September 30, 2016

Lonestar

Marquis

Battlecat

Pro Forma Adjustments

Pro Forma Lonestar

Revenues
$
44,537

$
22,234

$
2,919

$
—

$
69,690

Net income (loss) attributable to common stockholders

(35,401
)

12,029

1,617

(10,561
)

(32,317
)
Net income (loss) per common share, basic and diluted

(4.64
)

—

—

—

(4.24
)

Pro forma adjustments to net income (loss) attributable to common stockholders consists of depreciation, depletion, amortization and accretion calculations, additional interest expense, adjustments for income tax (expense) benefit, and dividends on preferred stock issued to complete the acquisitions. The effect on net income (loss) per common share, basic and diluted, is a result of adjustments to Lonestar revenue and net income (loss) for revenue and expenses for acquired properties as well as the pro forma adjustments to arrive at pro forma Lonestar net income (loss) attributable to common stockholders.

~~4. Restricted Certificate of Deposit~~

The Company is required to maintain a certificate of deposit (“CD”) issued by a municipality in Montana, in which certain of our drilling operations are located. This CD is pledged as collateral for a letter of credit issued by the Company’s bank to the municipality. The CD has a maturity date of March 8, 2018, and bears an interest rate of 0.25%. As this CD is expected to be renewed upon maturity and is not available for use in operations, it is classified as a noncurrent asset.

~~5. Commodity Price Risk Activities~~

The Company has implemented a strategy to reduce the effects of volatility of oil and natural gas prices on the Company’s results of operations by securing fixed price contracts for a portion of its expected sales volumes.

Inherent in the Company’s fixed price contracts, are certain business risks, including market risk and credit risk. Market risk is the risk that the price of oil and natural gas will change, either favorably or unfavorably, in response to changing market conditions. Credit risk is the risk of loss from nonperformance by the Company’s counterparty to a contract.identified. The Company does not ~~currently require cash collateral from any of~~expect this guidance to have a significant impact on its ~~counterparties nor does its counterparties require cash collateral from the Company. At September 30, 2017, the Company had no open physical delivery obligations.~~

~~The Company~~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 ~~holding~~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, which helps ensure the Company’s ability to fund the capital budget.

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 ~~has~~does not ~~designated~~currently require cash collateral from any of its counterparties nor does its counterparties require cash collateral from the commodity derivatives as hedges under the applicable accounting standards. Consequently, all changes in fair value of these derivatives (realized and unrealized) are included in the consolidated statement of operations.

Company. As of ~~September 30, 2017,~~March 31, 2021, the Company had 0 open physical delivery obligations.

The following ~~derivative transactions were outstanding:~~

Instrument

Total Volume

Settlement Period

Fixed Price

Oil – WTI Fixed Price Swap

27,600 Bbl

October – December 2017

$
51.05

Oil – WTI Fixed Price Swap

18,400 Bbl

October – December 2017

50.60

Oil – WTI Fixed Price Swap

92,000 Bbl

October – December 2017

52.90

Oil – WTI Fixed Price Swap

46,000 Bbl

October – December 2017

56.00

Oil – WTI Fixed Price Swap

95,600 Bbl

October – December 2017

49.85

Oil – WTI Fixed Price Swap

365,000 Bbl

January – December 2018

54.18

Oil – WTI Fixed Price Swap

182,500 Bbl

January – December 2018

55.65

Oil – WTI Fixed Price Swap

182,500 Bbl

January – December 2018

55.50

Oil – WTI Fixed Price Swap

292,000 Bbl

January – December 2018

47.10

Oil – WTI Fixed Price Swap

509,000 Bbl

January – December 2018

50.17

Oil – WTI Fixed Price Swap

508,900 Bbl

January – December 2019

50.40

Oil – WTI Fixed Price Swap

560,700 Bbl

January – December 2019

48.04

Oil – WTI Fixed Price Swap

203,600 Bbl

January – June 2020

48.90

Natural Gas – Henry Hub NYMEX Fixed Price Swap

644,000 MMBtu

October – December 2017

3.36

Natural Gas – Henry Hub NYMEX Fixed Price Swap

1,825,000 MMBtu

January – December 2018

3.09

Instrument

Total Volume

Settlement Period

Puts

Calls

Oil – 3 Way Collar

85,000 Bbl

October – December 2017

$ 40.00 / 60.00

$
85.00

Oil – 2 Way Collar

182,500 Bbl

January – December 2018

50.00

59.45

~~The above~~table summarizes Lonestar’s commodity derivative contracts ~~aggregate to 364,600 barrels or 3,963 barrels~~as of ~~oil per day~~March 31, 2021:


	Contract			Volumes	Weighted
Commodity	Type	Period	Range (1)	(Bbls/Mcf per day)	Average Price
Oil - WTI	Swaps	Apr - Dec 2021	$42.20 - $58.00	6,061	$	45.55
Oil - WTI	Swaps	Jan - Dec 2022	$44.83 - $51.44	3,123	47.11
Oil - WTI	Swaps	Jan - Dec 2023	$52.00 - $52.15	1,000	52.10
Natural Gas - Henry Hub	Swaps	Apr - Dec 2021	$2.86 - $3.05	14,691	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 ~~remainder~~period presented.

During April 2021, the Company entered into additional WTI swaps of ~~2017, 1,713,500~~92,000 barrels ~~or 4,695~~(500 barrels per day) at an average strike price of oil per day for 2018, 1,069,600 barrels or 2,930 barrels of oil per day for 2019 and 203,600 barrels or 1,119 barrels of oil per day thru June 2020. The above natural gas derivative contracts equate to 644,000 MMBtu or 7,000 MMBtu per day$61.48 for the ~~remainder~~period of ~~2017 and 1,825,000 MMBtu or 5,000 MMBtu~~July through December 2021. The Company also entered into additional WTI swaps of 132,000 barrels (362 barrels per ~~day~~day) at an average strike of $54.58 for ~~2018. All derivative contracts are carried at their fair value on~~ the ~~balance sheet and all changes in value are recorded in the consolidated statement~~period of ~~operations in gain or loss on derivative financial instruments.~~

January through June 2023.

As of ~~September 30, 2017 and December~~March 31, ~~2016,~~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

The Company recognizes revenue when control of the promised goods or services is transferred to customers at an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services.

Disaggregation of Revenue

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 months ended March 31, 2021 and 2020:


In thousands	Successor		Predecessor
	Three Months Ended March 31, 2021		Three Months Ended March 31, 2020
Oil	$	27,872	$	29,990
NGLs	4,297		2,599
Natural gas	7,647		4,420
Total revenues	$	39,816	$	37,009

As of March 31, 2021 (Successor) and December 31, 2020 (Successor) 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.

Note 4. Fair Value Measurements

Non-recurring fair value measurements include certain nonfinancial assets and liabilities as may be acquired in a business combination and thereby measured at fair value; impaired oil and natural gas property assessments; warrants issued in equity offerings and the initial recognition of asset retirement obligations for which fair value is used. These estimates are derived from historical costs as well as management’s expectation of future cost environments. As there is no corroborating market activity to support the assumptions used, the Company has designated these estimates as Level 3.

~~In accordance with ASC 820,~~

Fair ~~Value Measurements and Disclosures, fair~~ value measurements are based upon inputs that market participants use in pricing an asset or liability, which are classified into two categories: observable inputs and unobservable inputs. Observable inputs represent market data obtained from independent sources, whereas unobservable inputs reflect a company’s own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. Under Accounting Standards Codification (“ASC”), 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 ~~tables present~~table presents the Company’s assets and liabilities that are measured at fair value on a recurring basis as of ~~September 30, 2017~~March 31, 2021 and December 31, ~~2016,~~2020, for each fair value hierarchy level:

Fair Value Measurements Using

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

Significant
Other
Observable
Inputs
(Level 2)

Significant
Unobservable
Inputs
(Level 3)

Total

September 30, 2017 (Unaudited)

(In thousands)

Assets:

Commodity derivatives

$
—

$
3,894

$
—

$
3,894

Liabilities:

Commodity derivatives

—

(4,663
)

—

(4,663
)
Equity warrant liability

—

—

(439
)

(439
)
Equity warrant liability - related parties

—

—

(834
)

(834
)
Stock appreciation rights

—

—

(189
)

(189
)

Total

$
—

$
(769
)

$
(1,462
)

$
(2,231
)

December 31, 2016

(In thousands)

Assets:

Commodity derivatives

$
—

$
1,730

$
—

$
1,730

Liabilities:

Commodity derivatives

—

(4,110
)

—

(4,110
)
Equity warrant liability

—

—

(1,565
)

(1,565
)
Equity warrant liability - related parties

—

—

(2,994
)

(2,994
)

Total

$
—

$
(2,380
)

$
(4,559
)

$
(6,939
)


	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
March 31, 2021
Assets
Derivative financial instruments	$	0	$	1,350	$	0	$	1,350
Liabilities:
Derivative financial instruments	0		(29,575)		0		(29,575)


Total	$	0	$	(28,225)	$	0	$	(28,225)

December 31, 2020
Assets:
Derivative financial instruments	$	0	$	2,098	$	0	$	2,098
Liabilities:
Derivative financial instruments	0		(8,773)		0		(8,773)


Total	$	0	$	(6,675)	$	0	$	(6,675)

~~Level 3 Gains~~

Assets and ~~Losses~~

~~The table below sets forth a summary of changes in the~~liabilities measured at fair value ~~of the Company’s Level 3 liabilities for the nine months ended September 30, 2017, in thousands.~~

on a nonrecurring basis

Equity Warrant Liability

Stock Appreciation Rights

Total

(Unaudited)

Balance at December 31, 2016

$
(4,559
)

$
—

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

—

(72
)

(72
)
Realized gains/(losses)

—

—

—

Unrealized gains/(losses)

3,286

(117
)

3,169

Balance at September 30, 2017

$
(1,273
)

$
(189
)

$
(1,462
)

~~The derivative asset and liability~~

Non-recurring fair values reported in the consolidated balance sheets are as of the balance sheet date and subsequently change as a result of changes in commodity prices, market conditions and other factors. The Company typically has numerous hedge positions that span several time periods and often result in both derivativevalue measurements include certain non-financial assets and liabilities ~~with~~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 ~~same counterparty,~~initial recognition of asset retirement obligations for which ~~positions~~fair value is used. These estimates are ~~all offset~~derived from historical costs as well as management’s expectation of future cost environments. As there is no corroborating market activity to ~~a single derivative asset or liability in~~support the ~~consolidated balance sheets, including~~assumptions used, the ~~deferred premiums associated with its hedge positions.~~

Company has designated these estimates as Level 3.

Other fair value measurements

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

Note 9 below) approximates $148 million as of September 30, 2017, and the notes are considered a Level 3 liability, as they are based on market transactions that occur infrequently as well as internally generated inputs.

~~7. Oil and Gas Properties~~

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

September 30,
2017
(Unaudited)

December 31,
2016

(In thousands)

Proved properties and equipment

$
712,866

$
538,695

Unproved properties

79,143

72,584

Less accumulated depletion and impairment

(239,090
)

(172,051
)

$
552,919

$
439,228

Depletion expense was approximately $39,960,000 for the nine months ended September 30, 2017 and approximately $46,286,000 for the year ended December 31, 2016. Impairment expense was approximately $27,081,000 for the nine months ended September 30, 2017 and approximately $33,893,000 for the year ended December 31, 2016.

8.5. Accrued Liabilities

Accrued liabilities consisted of the ~~following:~~

following as of the dates indicated:

September 30,
2017
(Unaudited)

December 31,
2016

(In thousands)

Bonus payable

$
1,710

$
2,155

Payroll payable

11

1

Accrued interest - 8.750% Senior Notes

6,090

2,924

Accrued interest - other

1,810

523

Accrued rent

154

298

Accrued well costs

10,561

3,366

Accrued severance, property and franchise taxes

1,242

431

Other

787

249

$
22,365

$
9,947


In thousands	March 31, 2021		December 31, 2020
Bonus payable	$	1,294	$	1,363
Accrued well costs	3,584		1,752
Third-party payments for joint interest expenditures	669		5,178
Accrued professional fees (success fees)	0		4,710
Other	2,216		2,980
Total accrued liabilities	$	7,763	$	15,983

Note 6. Long-Term Debt

~~Long-term~~

The following long-term debt ~~consisted~~obligations were outstanding as of the ~~following:~~

dates indicated:

September 30,
2017
(Unaudited)

December 31,
2016

(In thousands)

Senior Secured Credit Facility

$
128,079

$
43,500

Second Lien Notes

—

11,367

8.750% Senior Notes

151,848

151,848

Less unamortized discount on 8.750% Senior Notes

(1,139
)

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

(567
)

(851
)
Less deferred financing costs on Second Lien Notes

—

(316
)
Mortgage debt

7,904

—

Other

273

282

$
286,398

$
204,122


In thousands	March 31, 2021		December 31, 2020
Senior Secured Credit Facility	$	209,600	$	209,600
Second-Out Term Loan	50,000		55,000
Mortgage debt	8,654		8,712
PPP loan	2,157		2,157
Other	233		261
Total	270,644		275,730
Less unamortized discount	(313)		(402)

Total, net of unamortized discount	270,331		275,328
Less current obligations	(20,000)		(20,000)
Long-term debt	$	250,331	$	255,328

Successor Senior Secured Credit ~~Facility~~

Agreements

On ~~July 28, 2015, LRAI closed on~~the Effective Date, the Successor, through its subsidiary Lonestar Resources America Inc., entered into a ~~Credit Agreement (as amended, supplemented or modified~~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 ~~“Credit Agreement”) for a $500,000,000 Senior Secured~~Successor Credit Facility, ~~(the “Senior Secured~~the “Successor Credit Agreements”) by amending and restating the Company’s existing credit agreement (as so amended and restated, the “Predecessor Credit Facility”) which had a borrowing base of $180,000,000 as of December 31, 2015 and a maturity date of October 16, 2018. Effective as of May 19, 2016, the borrowing base was reduced from $180,000,000 to $120,000,000. Effective as of November 23, 2016, the borrowing base was reduced from $120,000,000 to $112,000,000. Effective as of June 15, 2017, the borrowing base was increased from $112,000,000 to $160,000,000.

. The ~~Senior Secured Credit Facility may be used for loans and, subject to a $2,500,000 sub-limit, letters of credit. The Senior Secured~~Successor Credit Facility provides for revolving loans in an aggregate amount of up to $225 million, subject to borrowing base capacity. Letters of credit are available up to the lesser of (a) $2.5 million and (b) the aggregate unused amount of commitments under the Successor Credit Facility then in effect. On the Effective Date, Lonestar Resources America Inc. borrowed $60.0 million in term loans under the Successor Term Loan Facility. The Successor Credit Agreements will mature on November 30, 2023. The term loans under the Successor Term Loan Facility amortize on a quarterly basis in an amount equal to $5.0 million, payable on the last day of March, June, September and December of each year. The Successor’s obligations under the Successor Credit Agreements are guaranteed by all of the Successor’s direct and indirect subsidiaries (subject to certain permitted exceptions) and will be secured by a lien on substantially all of the Successor’s, Lonestar Resources America Inc.’s and the guarantors’ assets (subject to certain exceptions).

Borrowings and letters of credit under the Successor Credit Facility are limited by borrowing base calculations set forth therein. The initial borrowing base is $225 million, subject to redetermination. The borrowing base will be redetermined semiannually on or around May 1 and November 1 of each year, with one interim “wildcard” redetermination available between scheduled redeterminations. The first wildcard redetermination occurred on February 1, 2021, which reaffirmed the initial borrowing base of $225 million.

The Successor Credit Agreements contain customary covenants, including, but not limited to, restrictions on the Successor’s ability and that of its subsidiaries to merge and consolidate with other companies, incur indebtedness, grant liens or security interests on assets, make acquisitions, loans, advances or investments, pay dividends, sell or otherwise transfer assets, or enter into transactions with affiliates.

The Successor Credit Facility contains certain financial performance covenants including the following:

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

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

Borrowings under the Successor Credit Agreements bear interest at a floating rate at the Successor’s option, which can be either an adjusted Eurodollar rate (the Adjusted LIBOR, subject to a 1% floor) plus an applicable margin of 4.50% per annum or a base rate determined under the Successor Credit Facility (the “ABR”, subject to a 2% floor) plus an applicable margin of 3.50% per annum. The weighted average interest rate on borrowings under the Successor Credit Agreements was 5.5% for the three months ended March 31, 2021. The undrawn portion of the aggregate lender commitments under the Successor Credit Facility is subject to a commitment fee of ~~0.375% to 0.5% based on the unused portion~~1.0%. As of ~~the borrowing base under the Senior Secured Credit Facility.~~

Borrowings under the Senior Secured Credit Facility, at LRAI’s election, bear interest at either: (i) an alternate base rate (“ABR”) equal to the higher of (a) the Prime Rate, (b) the Federal Funds Effective Rate plus 0.5% per annum, and (c) the adjusted LIBO rate of a three-month interest period on such day plus 1.0%; or (ii) the adjusted LIBO rate, which is the rate stated on Reuters screen LIBOR01 page, for one, two, three, six or twelve months, as adjusted for statutory reserve requirements for Eurocurrency liabilities, plus, in each of the cases described in clauses (i) and (ii) above, an applicable margin ranging from 1.50% to 2.50% for ABR loans and from 2.50% to 3.50% for adjusted LIBO rate loans (5.17% at September 30, 2017).

The Senior Secured Credit Facility requires LRAI to maintain certain financial ratios and limits the amount of indebtedness LRAI can incur. Subject to certain permitted liens, LRAI’s obligations under the Senior Secured Credit Facility have been secured by the grant of a first priority lien on no less than 80% of the value of the proved oil and gas properties of the Company and its subsidiaries.

In connection with the Senior Secured Credit Facility, LRAI and certain of its subsidiaries also entered into certain customary ancillary agreements and arrangements, which, among other things, provide that the indebtedness, obligations, and liabilities of the Company arising under or in connection with the Senior Secured Credit Facility are unconditionally guaranteed by such subsidiaries.

Effective as of July 27, 2016, LRAI, the several banks and other financial institutions party thereto (collectively, the “Consenting Lenders”) and Citibank, N.A., in its capacity as administrative agent for the lenders (the “Administrative Agent”) entered into the Third Amendment to Credit Agreement and Limited Waiver (the “Third Amendment”) to that certain Credit Agreement dated as of July 28, 2015, by and among LRAI, the Consenting Lenders (together with the other banks and financial institutions party thereto, the “Lenders”) and the Administrative Agent to (a) permit LRAI to incur the second lien obligations contemplated by the Securities Purchase Agreement with Leucadia National Corporation and others (as described below) and LRAI’s contemplated use of proceeds thereof, (b) increase the applicable margin for Eurodollar and ABR loans and letter of credit fees by 0.75% across all levels of the previously applicable pricing grid, (c) modify the fee payable on the actual daily unused amount of the aggregate commitments to a flat 0.50% across all levels of the pricing grid, (d) increase the minimum percentage of the value of LRAI’s oil and gas properties that must be mortgaged as collateral for the obligations under the Credit Agreement and the other loan documents from 80% to 90%, (e) modify the maximum leverage ratio thresholds from 4.0 to 1.0 to (i) 4.75 to 1.0 for the four quarterly periods ending June 30, 2016, (ii) 4.50 to 1.0 for the four quarterly periods ending September 30, 2016, (iii) 4.25 to 1.0 for the four quarterly periods ending December 31, 2016 and (iv) 4.00 to 1.0 for all periods thereafter, (f) prohibit distributions to the Predecessor for selling, general and administrative expenses after September 30, 2016 and (g) amend certain other provisions of the Credit Agreement as more specifically set forth in the Amendment.

In connection with closing the Marquis Acquisition and the Battlecat Acquisition, on June 15, 2017, LRAI entered into the Sixth Amendment and Joinder to Credit Agreement (the “Sixth Amendment”) to its Credit Agreement, among LRAI, the subsidiary guarantors party thereto, the several lenders party thereto and Citibank, N.A., in its capacity as administrative agent and as issuing bank. Pursuant to the Amendment, the Credit Agreement was amended to (i) increase the borrowing base from $112 million to $160 million until redetermined or adjusted in accordance with the Credit Agreement, (ii) modify the maximum leverage ratio threshold to be 4.0 to 1.0 for all periods, starting with the fiscal quarter ending September 30, 2017, and providing that EBITDAX (as defined in the Credit Agreement) shall be calculated at the end of each fiscal quarter using the results of the twelve-month period ending with that fiscal quarter end; provided, that EBITDAX shall be calculated (x) at the end of the fiscal quarter ending September 30, 2017 using an amount equal to the EBITDAX for such fiscal quarter, multiplied by four, (y) at the end of the fiscal quarter ending December 31, 2017 using an amount equal to the EBITDAX for the two fiscal quarter period ended on such date, multiplied by two and (z) at the end of the fiscal quarter ending March 31, ~~2018 using an amount equal to~~2021, the EBITDAX for the three fiscal quarter period ended on such date, multiplied by four-thirds, (iii) permit LRAI to declare and pay dividends to the Company equal to the amount of any cash dividends declared and payable in accordance with the terms of the Company’s Certificate of Designations of Convertible Participating Preferred Stock, Series A-1, and Certificate of Designations of Convertible Participating Preferred Stock, Series A-2, subject to certain specified terms and conditions and (iv) amend certain other provisions of the Credit Agreement as more specifically set forth in the Sixth Amendment.

~~As of September 30, 2017 and December 31, 2016 (giving effect to the amended covenant ratio discussed above), LRAI~~Successor was in compliance with all debt covenants ~~including all financial ratios~~ under the Successor Credit Facilities.

Predecessor Senior Secured Bank Credit ~~Facility. As~~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 ~~September 30, 2017 and December 31, 2016, approximately $128,079,000 and $43,500,000~~the Predecessor Credit Facility was ~~borrowed, respectively, under~~refinanced by the ~~Senior Secured~~Successor Credit ~~Facility. Borrowing availability was approximately $31,400,000 at September 30, 2017.~~

~~8.750%~~Agreements on the Effective Date.

Extinguishment of Predecessor 11.25% Senior Notes

On April 4, 2014, LRAI issued at par $220,000,000 of 8.750% Senior Unsecured Notes due April 15, 2019 (the “8.750% Senior Notes”) to U.S. based institutional investors. The Company is in active discussions to refinance the ~~8.750%~~Effective Date, the Predecessor’s 11.25% Senior Notes due ~~April 2019, which will also provide~~2023 (the “11.25% Senior Notes”) were fully extinguished by issuing equity in the Successor to ~~extend~~ the ~~term~~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 ~~Senior Secured Credit Facility. During 2016, LRAI repurchased approximately $68.2 million in aggregate principal amount of~~Successor.

Pursuant to the ~~8.750% Senior Notes leaving a remaining balance of approximately $151.8 million.~~

~~On or after April 15, 2016, LRAI may redeem~~Registration Rights Agreement, Holders have customary underwritten offering and piggyback registration rights, subject to the ~~8.750% Senior Notes in whole or in part at the redemption prices (expressed as percentages of the principal amount)~~limitations set forth in the following table plus accrued and unpaid interest, if any, on the 8.750% Senior Notes redeemed, to the applicable date of redemption, if redeemed during the twelve-month period beginning on April 15 of the years indicated below:

Year

Percentage

2017

104.375
%
2018 and thereafter

100.000
%

~~In addition, upon a change of control of LRAI, holders of the 8.750% Senior Notes will~~Registration Rights Agreement. Under their underwritten offering registration rights, Holders have the right to ~~require LRAI~~demand the Successor to ~~repurchase~~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 ~~part~~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 ~~8.750% Senior Notes for cash at a price equal~~shares in the offering.

These registration rights are subject to ~~101%~~certain conditions and limitations, including the right of the ~~aggregate principal amount~~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 8.750% Senior Notes repurchased, plus any accrued and unpaid interest. The 8.750% Senior Notes were issued under and governed by an Indenture dated April 4, 2014, between LRAI, Wells Fargo Bank, National Association, as trustee and LRAI’s subsidiaries named therein as guarantors (the “Indenture”). The Indenture contains covenants that, among other things, limitPlan, the ability of LRAI and its subsidiaries to: incur indebtedness; pay dividends or make other distributions on stock; purchase or redeem stock or subordinated indebtedness; make investments; create liens; enter into transactions with affiliates; sell assets; refinance certain indebtedness; and merge with or into other companies or transfer substantially all of LRAI’s assets.

~~As of September 30, 2017 and December 31, 2016, LRAI was in compliance with all covenants including all financial ratios regarding the 8.750% Senior Notes.~~

~~Debt Issuance Costs~~

The Company capitalizes certain direct costs associated with the issuance of long-term debt and amortizes such costs over the lives of the respective debt. At September 30, 2017 and December 31, 2016, the Company had approximately $2,900,000 and $1,200,000, respectively, of debt issuance costs associated with issuance of the Senior Secured Credit Facility remaining that are being amortized over the lives of the respective debt which are recorded as other non-current assets in the consolidated balance sheets.

~~Securities Purchase Agreement and Second Lien Notes~~

~~On August 2, 2016, the Company~~Successor entered into a ~~Securities Purchase~~Tranche 1 Warrant Agreement with Juneau Energy, LLC, as initial purchaser (“Juneau”), Leucadia National Corporation (“Leucadia”), as guarantor of Juneau’s obligations, the other purchasers party thereto and Jefferies, LLC, in its capacity as the collateral agent for the purchasers, relating to the issuance and sale of (i) up to $49,900,000 aggregate principal amount of LRAI’s 12% senior secured second lien notes due 2021 (the ~~“Second Lien Notes”~~“Tranche 1 Warrant Agreement”) and ~~(ii) five-year~~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 ~~998,000~~of 555,555 shares of ~~the Company’s Class A voting~~ common stock ~~at a price equal to $5.00 per share (the “Warrants”). The balance of these notes and warrants is reflected~~ in the ~~Company’s long-term debt – related parties and equity warrant liability – related parties on the face of the balance sheet.~~

The Second Lien Notes are secured by second-priority liens on substantially all of LRAI’s and its subsidiaries’ assets to the extent such assets secure obligations under the Senior Secured Credit Facility.

During 2016, LRAI issued $38.0 million in aggregate principal amount of Second Lien Notes and the Company issued the Warrants to purchase 760,000 shares of its Class A voting common stock. The Company recorded an equity warrant liability of approximately $5.1 million which was the fair value amount at the date of issuance. The Warrants were adjusted to fair value at September 30, 2017 which resulted in a gain on the Warrants of approximately $3.3 million for the nine months ended September 30, 2017, which is recorded in the consolidated statements of operations and comprehensive income (loss). Proceeds from the Second Lien Notes issuance were used to repurchase approximately $68.2 million in aggregate principal amount of the 8.750% Senior Notes in privately negotiated open market repurchases with holders of such notes, and to pay related fees and expenses related to the foregoing. The repurchase amounts paid were approximately $36.2 million in cash. Net of related fees, such repurchases resulted in a gain on debt extinguishment of approximately $28.5 million.

In December 2016, LRAI repaid $21.0 million principal of the Second Lien Notes with proceeds from the offering of the Company’s Class A voting common stock that was completed on December 22, 2016 pursuant to a Registration Statement on Form S-1 (File No. 333-214265), which was declared effective on December 15, 2016 (the “2016 Common Stock Offering”). In June 2017, LRAI repaid the remaining $17.0 million principal of the Second Lien Notes including an early payment premium of approximately $1.1 million with borrowings from the Company’s Senior Secured Credit Facility.

~~10. Stockholders’ Equity~~

~~Preferred Stock~~

The Company is authorized to issue up to 10,000,000 shares of preferred stock with a par value of $0.001. The Company’s preferred stock may be entitled to preference over the common stock with respect to the distribution of assets of the Company in the event of liquidation, dissolution or winding-up of the Company, whether voluntarily or involuntarily, or in the event of any other distribution of assets of the Company among its shareholders for the purpose of the winding-up of its affairs. The authorized but unissued shares of the preferred stock may be divided into and issued in designated series from time to time by one or more resolutions adopted by the Board of Directors of the Company (the “Board”). The Board in their sole discretion shall have the power to determine the relative powers, preferences and rights of each series of preferred stock.

~~Series A & B Preferred Stock~~

On June 2, 2017 the Company reported entering into a securities purchase agreement (the “Original SPA”) with Chambers, pursuant to which the Company agreed to sell to Chambers, in a private placement under the Securities Act of 1933, as amended (the “Securities Act”), shares of the Company’s newly-created Series A-1 Convertible Participating Preferred Stock,Successor, par value $0.001 ~~per share~~ (the ~~“Series A-1 Preferred~~“New Common Stock”), ~~and Series A-2 Convertible Participating Preferred Stock, par value~~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 “Series A-2 Preferred Stock” and, together with the Series A-1 Preferred Stock, the “Series A Preferred Stock” and, collectively with the Series A-1 Preferred Stock and the Series B Preferred Stock, the “Preferred Stock”“Expiration Date”)~~, for an aggregate purchase price of approximately $78 million.~~

~~On June 15, 2017, the Company entered into an amended and restated securities purchase agreement (the “A&R SPA”) with Chambers.~~ .

On the same day, the Company closed the transactions contemplated by the A&R SPA (the “SPA Closing”) and issued to Chambers 5,400 shares of Series A-1 Preferred Stock and 74,600 shares of Series A-2 Preferred Stock. PursuantEffective Date, pursuant to the terms of the SPA, the Company agreed to use commercially reasonable efforts to hold a stockholder meeting (the “Stockholder Meeting”) by no later than December 15, 2017 and to obtain at the meeting stockholder approval of the issuance of shares of the Company’s Class A voting common stock issuable upon conversion of all shares of Series A-1 Preferred Stock and Series A-2 Preferred Stock (upon their conversion to shares of Series A-1 Preferred Stock) issued or issuable pursuant to the A&R SPA (the “Stockholder Approval”). The Stockholder Meeting was held on November 3, 2017, and Stockholder Approval was obtained for Series A-2 Preferred Stock conversion. After the SPA Closing and for so long as the Approved Holders (as defined in the A&R SPA) beneficially own at least 10% of the total number of outstanding shares of Class A voting common stock and Class B non-voting common stock (collectively, “Common Stock”) of the Company, on an as-converted basis, or at least 15% of the number of Series A Preferred Stock issued to Chambers at the SPA Closing, the Company cannot undertake certain actions without the prior consent of holders of a majority of all shares of Common Stock, on an as-converted basis, held by the Approved Holders.

Prior to June 15, 2020, Chambers and its affiliates are prohibited from directly or indirectly engaging in any short sales involving the Common Stock or securities convertible into, or exercisable or exchanged for, Common Stock. Without the prior written consent of the Board, the Approved Holders are subject to customary standstill restrictions until the earlier of (i) the two-year anniversary of the date the Approved Holders are no longer entitled to designate any director to the Board and (ii) the date the Company fails to fully declare and pay all accrued dividends on either series of the Series A Preferred Stock after there are no PIK Quarters (as defined below) remaining. In connection with the SPA Closing and the issuance of shares of Series A Preferred Stock,Plan, the Company entered into a ~~registration rights agreement~~Tranche 2 Warrant Agreement (the “Tranche 2 Warrant Agreement” and, together with ~~Chambers~~the Tranche 1 Warrant Agreement, the “Warrant Agreements”) and issued warrants (the ~~“Chambers RRA”). Under~~“Tranche 2 Warrants” and, together with the ~~Chambers RRA,~~Tranche 1 Warrants, the ~~Company has agreed~~“Warrants”) to provide to Chambers certain customary demand and piggyback registration rights relating to Chambers’ ownership of Company stock. The Chambers RRA contains customary terms and conditions, including certain customary indemnification obligations.

Each of the Series A-1 Preferred Stock, Series A-2 Preferred Stock and Series B Preferred Stock is a new class of equity security. Each series of Series A Preferred Stock ranks senior to Class A voting common stock with respect to dividend rights and rights upon the liquidation, winding-up or dissolution of the Company, and each series initially has a stated value of $1,000 per share (the “Stated Value”). Series B Preferred Stock ranks pari passu with Class A voting common stock with respect to dividend rights, but senior to Class A voting common stock with respect to rights upon the liquidation, winding-up or dissolution of the Company, with a par value of $0.001 per share. If the stockholder approval is obtained, each outstanding share of Series A-2 Preferred Stock will automatically convert into one share of Series A-1 Preferred Stock, subject to customary adjustments. No later than two business days following the holding of the Stockholder Meeting, each share of Series B Preferred Stock will automatically convert into one share of Class A voting common stock, whether or not the Stockholder Approval has been obtained.

~~Holders of Series A-1 Preferred Stock will be entitled to vote with~~ holders of ~~Class A voting common stock on an as-converted basis upon the consummation of the Stockholder Meeting, whether~~Allowed Prepetition RBL Claims or not the Stockholder Approval is obtained. Holders of Series A-2 Preferred Stock are entitled to vote with the holders of Series A-1 Preferred Stock on all matters submitted for a vote of holders of Preferred Stocktheir permitted designees, as a separate class, but in no event are entitled to vote with the holders of Class A voting common stock. Holders of Series B Preferred Stock have no voting rights, except as described below. Holders of any series of Preferred Stock are entitled to one vote per share on any matter on which holders of such applicable, series are entitled to vote separately as a class. In addition, for so long as shares of a particular series of Preferred Stock are outstanding, the affirmative vote or consent of holders of at least a majority of the outstanding shares of such series, voting together as a separate class, is necessary for effecting any amendment or modification to the certificate of incorporation or the applicable Certificate of Designations that would materially and adversely affect the relative rights, preferences, privileges or voting power of such series.

Shares of Series A-1 Preferred Stock will be immediately convertible into shares of Class A voting common stock at the option of the holders of such Series A-1 Preferred Stock upon the consummation of the Stockholder Meeting, at a per share rate (the “Conversion Rate”) equal to the Stated Value of such share divided by six, subject to certain adjustments (the “Conversion Price”). Upon the

consummation of the Stockholder Meeting, the Company will have the option to convert Series A-1 Preferred Stock to Class A voting common stock if the volume weighted average price of Class A voting common stock exceeds the following percentages of the Conversion Price for twenty out of thirty consecutive trading days: (i) 200%, if such mandatory conversion occurs prior to June 15, 2019, (ii) 175%, if such mandatory conversion occurs after June 15, 2019 but before June 15, 2020, and (iii) 150%, if such mandatory conversion occurs after June 15, 2020. If on June 15, 2024, the Stockholder Meeting has been consummated (no matter whether or not the Stockholder Approval has been obtained) and the trailing 20-day volume weighted average price of Class A voting common stock (the “Prevailing Price”) is equal to or greater than the Conversion Price then in effect, then each share of the Series A-1 Preferred Stock then outstanding will automatically convert to Class A voting common stock at the then applicable Conversion Rate. Notwithstanding anything to the contrary in the foregoing, in no event will in excess of 1,678,089 shares of Class A voting common stock be issued in connection with the conversion of Series A-1 Preferred Stock in advance of the Stockholder Approval, and such conversion will only occur to the extent it will not result in a violation of any applicable rules of The NASDAQ Stock Market LLC (provided, that the Company is to take commercially reasonable efforts to effect the issuance in compliance with such rules).

Holders of Series A Preferred Stock will be entitled to cumulative dividends payable quarterly initially at a rate of 9% per annum (the “Dividend Rate”) in cash and, for any 12 quarters (“PIK Quarters”), at the Company’s option, (i) in the form of additional shares of the respective series of Series A Preferred Stock at a per share price equal to $975 or (ii) by increasing Stated Value, in lieu of cash. After the 12 PIK Quarters, if the Company fails to fully declare and pay dividends in cash, then the Dividend Rate for Series A Preferred Stock will automatically increase by 5.0% per annum for the next succeeding dividend period and then an additional 1.0% for each successive dividend period, up to a maximum Dividend Rate of 20.0% per annum, until the Company pays dividends at such increased rate fully in cash for two consecutive quarters. Separately, if the Stockholder Approval has not been obtained by December 15, 2017, the Dividend Rate for Series A-2 Preferred Stock will automatically increase by 5% per annum for the dividend period ended on March 31, 2018 and by an additional 0.5% each quarter thereafter until the Stockholder Approval is obtained, up to a maximum Dividend Rate of 20.0% per annum. In addition to dividends rights described above, holders of all series of Preferred Stock will be entitled to receive dividends or distributions declared or paid on Class A voting common stock on an as-converted basis. If on June 15, 2024, the Prevailing Price is less than the Conversion Price then in effect, the Dividend Rate for Series A-1 Preferred Stock will automatically increase to 20.0% per annum, payable only in cash, unless automatically converted as described above. However, the Company, at its option, may instead elect to exchange each share of Series A-1 Preferred Stock for senior unsecured notes of the Company with a two-year maturity, a 9.0% per annum coupon payable semi-annually in cash, and governed by terms substantially similar to the Company’s most recent high yield indenture at that time. After June 15, 2020, the Company may redeem shares of Series A Preferred Stock in cash at a per share amount equal to (i) 110% of the Stated Value, if the redemption occurs prior to June 15, 2021, (ii) 105% of the Stated Value, if the redemption occurs prior to June 15, 2022, and (iii) 100% of the Stated Value, if the redemption occurs after June 15, 2022, in each case, plus any unpaid dividends. If the Stockholder Approval is not obtained on or prior to June 15, 2024, the Company must redeem all outstanding shares of Series A-2 Preferred Stock at the Stated Value then in effect on June 15, 2024. If at any time after June 15, 2024 the Company fails to fully declare and pay a quarterly dividend in cash on Series A-1 Preferred Stock, then the Company must redeem in cash all outstanding Series A-1 Preferred Stock at the Stated Value then in effect.

As of September 30, 2017, 5,543 shares of Series A-1 Preferred Stock and 2,684,632 shares of Series B Preferred Stock were issued and outstanding with zero issued and outstanding at December 31, 2016. As of September 30, 2017, 76,577 shares of Series A-2 Preferred Stock were issued and outstanding with zero issued and outstanding at December 31, 2016. The Series A-2 Preferred Stock is classified as Mezzanine Equity in the Consolidated Balance Sheets due to the mandatory redemption feature triggered by the failure to obtain requisite Stockholder Approval. If requisite Stockholder Approval is obtained, the redemption feature would no longer be applicable, and the Series A-2 Preferred Stock will be reclassified to permanent equity at that time.

~~Common Stock~~

The Company is authorized to issue up to 100,000,000 shares of $0.001 par value Class A voting common stock of which 21,822,015 were issued and outstanding as of September 30, 2017 and December 31, 2016.

The Company is authorized to issue up to 5,000 shares of $0.001 par value Class B non-voting common stock of which 2,500 shares were issued and outstanding as of September 30, 2017 and December 31, 2016.

~~11. Stock-Based Compensation~~

~~Stock Option Activity~~

For the nine months ended September 30, 2017, no stock options were issued or exercised. The following tables summarize certain information related to outstanding stock options under the Lonestar Resources Limited 2012 Employee Share Option Plan and the

~~Lonestar Resources US Inc. 2016 Incentive Plan, which replaced the Lonestar Resources Limited 2012 Employee Share Option Plan following the Reorganization:~~

Shares

Weighted
Average
Exercise Price
Per Share

Weighted Average
Remaining
Contractual Term
(in years)

Outstanding at December 31, 2016

191,750

$
15.00

0.25

Options vested and exercisable at December 31, 2016

191,750

$
15.00

0.25

Granted

—

—

—

Exercised

—

—

—

Canceled/Expired

(16,125
)

—

—

Forfeited

(75,000
)

20.00

—

Outstanding at September 30, 2017

100,625

$
15.00

0.25

Options vested and exercisable at September 30, 2017

100,625

$
15.00

0.25

~~Restricted Stock Units~~

In February 2017, the Company granted awards of restricted stock units (“RSUs”) covering 612,000 shares to certain of its employees. In August 2017, 100,000 units were issued to the Company’s chairman of the board of directors. The awards vest over a three-year period as follows: 40% on the first anniversary of issuance and 30% on each of the second and third anniversaries of issuance, such that the RSU’s will be fully vested on the third anniversary of issuance. The Company determines the fair value of granted RSU’s based on the market price of the Class A voting common stock of the Company on the date of grant. RSUs will be paid in Class A voting common stock or cash, at the Company’s option, after the vesting of the applicable RSU. Compensation expense for granted RSUs is recognized over the vesting period.

Shares

Weighted Average
Remaining
Contractual Term
(in years)

Outstanding at December 31, 2016

—

—

RSUs vested at December 31, 2016

—

—

Granted

712,000

3.0

Canceled/Expired

—

—

Forfeited

(10,000
)

2.8

Outstanding at September 30, 2017

702,000

2.5

RSUs vested at September 30, 2017

—

—

Shares

Weighted
Average Fair
Value per Share

Weighted
Average
Remaining
Contractual
Term
(in years)

Outstanding non-vested RSUs at December 31, 2016

—

$
—

—

Granted

712,000

6.00

3.0

Vested

—

—

—

Forfeited

(10,000
)

4.10

2.8

Outstanding non-vested RSUs at September 30, 2017

702,000

$
3.50

2.5

~~Stock Appreciation Rights~~

In February 2017, the Company granted awards of stock appreciation rights (“SARs”) covering 700,000 shares to certain of its employees and its non-employee directors. The awards vest over a three-year period as follows: 40% on the first anniversary of issuance and 30% on each of the second and third anniversaries of issuance, such that the SAR’s will be fully vested on the third anniversary of issuance. The SARs will expire five-years after the date of issuance. The exercise price of the SAR is the fair market value of the Company’s Class A voting common stock on the date of the grant. The SAR entitles the holder to receive from the Company upon exercise of the exercisable portion of the SAR an amount determined by multiplying the excess of the fair market

value of one share on the date of exercise over the exercise price per share by the number of shares with respect to which the SAR is exercised. SARs will be paid in cash or common stock at holder’s election once the SAR is vested, with the provision that the Company possesses sufficient liquidity to allow for cash settlement of the SAR. The SARs are being treated as a liability in the Consolidated Balance Sheets.

Shares

Weighted
Average
Exercise Price
Per Share

Weighted Average
Remaining
Contractual Term
(in years)

Outstanding at December 31, 2016

—

—

—

SARs vested and exercisable at December 31, 2016

—

—

—

Granted

700,000

$
7.20

5.0

Exercised

—

—

—

Canceled/Expired

—

—

—

Forfeited

(10,000
)

7.20

4.8

Outstanding at September 30, 2017

690,000

$
7.20

4.5

SARs vested and exercisable at September 30, 2017

—

$
—

—

Shares

Weighted
Average Fair
Value per Share

Weighted
Average
Exercise
Price per
share

Weighted
Average
Remaining
Contractual
Term
(in years)

Outstanding non-vested SARs at December 31, 2016

—

$
—

$
—

—

Granted

700,000

5.00

7.20

5.0

Vested

—

—

—

—

Forfeited

(10,000
)

4.10

7.20

4.8

Outstanding non-vested SARs at September 30, 2017

690,000

$
3.50

$
7.20

4.5

~~Stock-Based Compensation Expense~~

For the three and nine month periods ended September 30, 2017, the Company recorded stock-based compensation expenses of approximately $346,000 and $985,000, respectively, related to stock options, restricted stock units and stock appreciation rights. As of September 30, 2017, the total unrecognized stock-based compensation cost was approximately $3,786,000, which will be recognized over the period from October 2017 through February 2020.

~~12. Earnings Per Share~~

In accordance with the provisions of current authoritative guidance, basic earnings or loss per share shown on the Consolidated Statements of Operations is computed on the basis of the weighted average number of common shares outstanding during the periods. Diluted earnings or loss per share is computed based upon the weighted average number of common shares outstanding plus the assumed issuance of common shares for all potentially dilutive securities. The Company includes the number of stock options in the calculation of diluted weighted average shares outstanding when the exercise prices are less than the average market prices of the Company’s Class A voting common stock for the period. When a loss from operations exists, all potentially dilutive common shares outstanding are anti-dilutive and therefore excluded from the calculation of diluted weighted average shares outstanding.

Potentially dilutive common shares outstanding consist of shares of Class A voting common stock issuable pursuant to stock options, SARs, and 760,000 equity warrants. These securities have no dilutive effect for the nine months ended September 30, 2017 and 2016. The Series A and Series B Preferred Stock are participating securities as they contain rights to receive non-forfeitable dividends at the same rate as common stock. EPS is computed under the two-class method, which is a method of computing EPS when an entity has both common stock and participating securities. Under the two-class method, the income and distributions attributable to participating securities are excluded from the calculation of basic and diluted EPS and the participating securities are excluded from the weighted average shares outstanding. The dilutive effect of the participating securities was calculated under the treasury stock method and the two-class method. The EPS was more dilutive under the two-class method. As such, there is no difference in basic and diluted EPS.

~~The following table presents unaudited earnings per share of Lonestar Resources US Inc.~~

~~Unaudited Earnings Per Share~~

Three Months Ended

Nine Months Ended

September 30,

September 30,

2017

2016

2017

2016

Net loss per share of Class A voting common stock:

Basic

$
(0.39
)

$
(1.44
)

$
(1.33
)

$
(4.64
)
Diluted

(0.39
)

(1.44
)

(1.33
)

(4.64
)

Weighted average Class A voting common stock outstanding:

Basic

21,822,015

7,842,586

21,822,015

7,629,896

Diluted

21,822,015

7,842,586

21,822,015

7,629,896

~~13. Related Party Activities~~

~~LEUCADIA~~

On August 2, 2016, Lonestar Resources America, Inc. (“LRAI”) and the Company entered into a Securities Purchase Agreement (the “Purchase Agreement”) with Juneau Energy, LLC (n/k/a JETX Energy, LLC), as initial purchaser (“Juneau”),Leucadia National Corporation (“Leucadia”), as guarantor of Juneau’s obligations, the other purchasers party thereto and Jefferies, LLC, in its capacity as the collateral agent for the purchasers, relating to the issuance and sale of (i) up to $49.9 million aggregate principal amount of LRAI’s 12% senior secured second lien notes due 2021 (“Second Lien Notes”) and (ii) five-year warrants to purchase up to an aggregate ~~998,000~~of 555,555 shares of the ~~Company’s Class A voting common stock~~New Common Stock, at aan exercise price ~~equal to $5.00~~of $0.001 per share ~~(the “Warrants”). During 2016, LRAI issued $25 million in aggregate principal amount~~ of ~~Second Lien Notes and~~New Common Stock, subject to adjustment. The Tranche 2 Warrants may be exercised after the ~~Company issued Warrants to purchase 500,000 shares of its Class A voting common stock to Juneau. In December 2016, LRAI repaid to Juneau $21 million principal~~first anniversary of the ~~Second Lien Notes with proceeds from the 2016 Common Stock Offering.~~

In connection with entering into the Purchase Agreement, the Company also entered into a registration rights agreement and an equity commitment agreement, both dated as of August 2, 2016. Pursuant to the registration rights agreement, the Company has agreed to register for resale certain Class A voting common stock issued or issuable to Juneau and Leucadia, including those issuable upon exerciseissuance of the ~~Warrants. Leucadia agreed, pursuant~~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 equity commitment agreement, to purchase a certain number of Class A voting common stock in case the Company elected to pursue an equity offering prior to December 31, 2016. Pursuant to the equity commitment agreement, Leucadia purchased 3,478,261 shares of Class A voting common stock (costing $20 million) through the 2016 Common Stock Offering, which closed on December 22, 2016. In connection with Leucadia’s equity commitment, the Company paid Leucadia on January 3, 2017 a $1 million fee, which was recordedwarrants are presented as a reduction to additional paid-in capital. In the event Leucadia purchased not less than its commitment amount, the Company agreed to use commercially reasonable efforts to enter into arrangements to provide Leucadiacomponent of Stockholders’ Equity in accordance with the right to appoint one director to the Board of the Company, provided that such right will terminate at such time as Leucadia and its affiliates own a number of shares of Class A voting common stock equal to less than 50% of the shares purchased by Leucadia and its affiliates in such offering. Leucadia has elected to take an observer position on the board of directors, with no voting rights.

~~EF REALISATION~~

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

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

ASC 815-40-25.

~~AMENDMENT OF REGISTRATION RIGHTS AGREEMENTS~~

In connection with the consummation of the Battlecat Acquisition, the Marquis Acquisition and the SPA Closing, on June 15, 2017, the Company entered into (i) a first amendment to the registration rights agreement (the “Leucadia RRA Amendment”) with Leucadia and JETX Energy, LLC (f/k/a Juneau Energy, LLC), which amends the registration rights agreement, dated as of August 2, 2016, by and among the same parties, and (ii) a first amendment to registration rights agreement (the “EF RRA Amendment” and, together with the Leucadia RRA Amendment, the “RRA Amendments”) with EF Realisation, which amends the registration rights agreement, dated as of October 26, 2016, by and between the same parties. The RRA Amendments set forth the relative priorities, with respect to demand and piggyback registration rights, among each applicable party thereto, Battlecat, Marquis and Chambers under their respective registration rights agreements with the Company.

~~OTHER RELATED PARTY TRANSACTIONS~~

Butterfly Flaps, Ltd, a company in which Dr. Christopher Rowland (a director of the Company) owns an interest, has performed consultancy work for the Company since 2013 covering various strategic, tax structuring and investor matters at a cost of approximately $25,000 per quarter. The consulting arrangement terminated effective December 31, 2016.

Note 8. Related Party Activities

New Tech Global Ventures, LLC, ~~a company~~and New Tech Global Environmental, LLC, companies in which ~~Daniel R. Lockwood (a~~a director of the ~~Company)~~Predecessor owns a limited partnership interest, ~~has~~have provided field engineering staff and consultancy services for the Company since 2013. The total cost for such services was approximately ~~$198,000 and $78,000~~$0.5 million for the three months ended ~~September 30, 2017~~March 31, 2020 (Predecessor). On the Effective Date, the director resigned from the Company’s Board.

In February 2019, the Predecessor purchased a property adjacent to its corporate office for approximately $2.0 million. The transaction was funded with cash from operations. The seller of the property is indebted to certain trusts established in favor of the children of one of the Predecessor’s directors, whom resigned on the Effective Date from the Company’s Board.

Note 9. Commitments and ~~2016, respectively,~~Contingencies

Lonestar currently has 1 drilling rig under contract, which commenced on February 1, 2021. The contract provides for a drilling rate of $16,000 per day, and originally was set to expire 90 days after the commencement date. In April 2021, the contract term was extended to provide for drilling three additional wells, which will commence after the original termination date.

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 Predecessor 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 ~~$664,000 and $465,000~~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. The JDA continued to the Successor upon emergence from bankruptcy.

Note 10. Subsequent Events

2021 Management Incentive Plan

In connection with our emergence from bankruptcy, the Plan provided for the ~~nine months ended September 30, 2017 and 2016, respectively.~~

~~14. Subsequent Events~~

~~In preparing the consolidated financial statements,~~adoption of a management ~~has evaluated all subsequent events and transactions for potential recognition or disclosure through the date the accompanying consolidated financial statements were issued.~~

~~Conversion of Series B Convertible Preferred Stock~~

~~On November 3, 2017, and in accordance with the Certificate of Designations of Series B Convertible Preferred Stock of the Company~~incentive plan. The Lonestar Resources US Inc. 2021 Management Incentive Plan (the “~~Series B Certificate of Designations~~”“MIP”)~~, all of the outstanding~~ became effective on April 13, 2021. The MIP reserved 966,184 shares of the Company’s ~~Series B Convertible Preferred Stock (the “Series B Preferred Stock”) were converted (the “Series B Conversion”) on a one-to-one basis into~~common stock for awards to officers, other employees and directors. 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. On April 13, 2021 board of directors approved and ratified the MIP, with initial awards covering approximately 712,019 shares of the Company’s Class A voting common stock. The Series B Preferred Stock was originally issued to Battlecat Oil & Gas, LLC and SN Marquis LLC, pursuant to a transaction with each party, each as described more fully in Note 3.

~~Pursuant to the Series B Conversion, 2,684,632 shares of Class A voting~~ common stock granted during April 2021. As of May 7, 2021, 254,164 thousand shares were ~~issued (the “Conversion Shares”), and immediately following such conversion, none of~~available for future grants under the Company’s Series B Preferred Stock remained outstanding. The Conversion Shares are currently unregistered and will be registered pursuant to a Registration Statement on Form S-3, which registers, among other shares, the Conversion Shares. Following the Series B Conversion, there were a total of 24,506,647 shares of Class A voting common stock issued and outstanding.

~~Conversion of Series A-2 Convertible Participating Preferred Stock~~

~~On November 3, 2017, and in accordance with the Certificate of Designations of Convertible Participating Preferred Stock, Series A-2 of the Company (the “Series A-2 Certificate of Designations”),~~MIP, all of which could be issued in the ~~outstanding shares~~form of restricted stock units. The Company’s incentive compensation program is administered by the ~~Company’s Series A-2 Convertible Participating Preferred Stock (the “Series A-2 Preferred Stock”) were converted (the “Series A-2 Conversion”) on a one-to-one basis into shares~~Compensation Committee of ~~the Company’s Series A-1 Convertible Preferred Stock (the “Series A-1 Preferred Stock”). The Series A-2 Preferred Stock was originally issued to Chambers Energy Capital III, LP, pursuant to the Chambers Securities Purchase Agreement, as described more fully in Note 10.~~

~~Pursuant to the Series A-2 Conversion, 76,577 shares~~our Board of Series A-1 Convertible Preferred Stock were issued, and immediately following such conversion, none of Series A-2 Preferred Stock remained outstanding and an aggregate of 82,120 Series A-1 Preferred Stock were issued and outstanding.

Directors.

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

~~Overview~~

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 ~~production~~ and ~~acquisition~~production of unconventional oil, natural gas liquids ~~(“NGLs”)~~ and natural gas ~~properties~~ in the Eagle Ford Shale play in ~~Texas, where we have accumulated approximately 72,244 gross (57,172 net) acres in what we believe to be the formation’s crude oil and condensate windows, as of~~South Texas.

Emergence from Voluntary Reorganization under Chapter 11

On September 30, ~~2017. We operate in one industry segment, which is~~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 ~~exploration, development and production~~“Debtors”) commenced voluntary cases (the “Chapter 11 Cases”) under chapter 11 of ~~oil, NGLs and natural gas. Our current operational activities and consolidated revenues are generated from markets exclusively~~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.

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 ~~September~~Prepetition RBL Claims received distributions of:

▪Cash in the amount of all accrued and unpaid interest;

▪A first-out senior secured revolving credit facility with total aggregate commitments of $225 million;

▪A second-out senior secured term loan credit facility in an amount equal to $60 million;

▪555,555 Tranche 1 warrants and 555,555 Tranche 2 warrants, reflecting up to a 10% ownership stake in the Successor company’s equity interests;

•Holders of Prepetition Notes Claims received distributions of a pro rata share of 96% of 10,000,149 shares of New Common Stock issued on the Effective Date, subject to dilution by a to-be-adopted management incentive plan (the “MIP”) and the new warrants);

•Holders of Predecessor preferred equity interests received distributions of a pro rata share of 3% of the New Common Stock in the Successor company (subject to dilution by the MIP and the new warrants); and

•Holders of Predecessor Class A common stock received distributions of a pro rata share of 1% of the New Common Stock in the Successor company (subject to dilution by the MIP and new warrants).

•General unsecured creditors were paid in full in cash.

Fresh Start Accounting

Upon emergence from bankruptcy, the Company qualified for and adopted fresh start accounting in accordance with 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, ~~2017, we had no long lived~~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 ~~located outside~~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 ~~United States.~~

~~Third Quarter 2017 Operational Summary~~

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 ~~third~~first quarter and through early-May 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 and (ii) actions taken by the Organization of ~~2017,~~Petroleum Exporting Countries, Russia and certain other oil-exporting countries (“OPEC+”) to reduce the ~~Company reported~~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 $66.09 per barrel in early March 2021. Prices for natural gas and NGLs were also much higher during the first quarter and through early-May 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 ~~7,662 Boe/d,~~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.

Operational Highlights for the First Quarter of 2021

As a ~~36% sequential increase~~result of Lonestar filing for bankruptcy and emerging from bankruptcy on November 30, 2020, our financial results are broken out between the ~~5,635 Boe/d reported~~Predecessor period (the three months ended March 31, 2020) and the Successor period (the three months ended March 31, 2021). For the three months ended March 31, 2020 (Predecessor), we recognized a net loss of $113.0 million attributable to common shareholders, and for the three months ended ~~June 30, 2017. The increase in production was attributable to production additions associated with~~March 31, 2021 (Successor), we recognized a net loss of $6.3 million.

Operational highlights for the ~~$116.6 million acquisition~~first quarter of ~~producing properties that closed June 15, 2017 which added an additional 81~~2021 included the following:

•Brought five gross ~~/ 75.2 net wells. The third quarter was also marginally impacted by~~wells online between the ~~addition~~beginning of ~~2 gross / 2 net~~the year and mid-April 2021 including three drilled-but-uncompleted wells ~~placed into service~~from 2020 at our ~~Cyclone drilling pad~~Hawkeye properties;

•Continued to focus on lower operating expenses. Lease operating expenses were $4.76 for the quarter while gas gathering, processing and transportation came in ~~Gonzales County in late September.~~

at $1.65 per BOE; and

•Continued to build our commodities hedge portfolio to protect our operations from downside price risk. As of May 7, 2021, we had hedges covering 5,732 Bbls per day of oil for the remainder of 2021, 3,062 Bbls per day of oil for 2022 and 1,362 Bbls of oil per day for 2023. In addition, on that date, we had hedges covering 13,169 MMBtu per day of natural gas for the remainder of 2021 and 6,233 MMBtu per day for 2022.

The ~~Company’s third quarter was negatively impacted by Hurricane Harvey in three respects. The Company estimates that 150 Boe/d~~primary drivers of production was curtailed by the shut-ins of certain producing wells which were susceptible to flooding, reduced operating levels at certain gas processing plants utilized by the Company, as well as minor electrical outages.

~~For~~our financial net loss for the three months ended ~~September 30, 2017, approximately 69%~~March 31, 2021 (Successor) included:

•Revenues totaling $39.8 million, comprised of 10,377 BOE per day of production during the quarter with $42.63 per BOE of realized sales price before any hedging effects, and

•Losses on our commodity hedges of $24.2 million for the quarter, comprised of $5.4 million of realized losses and $18.8 million of unrealized losses.

The following reflects some of the primary drivers for our change in operating results between the first quarter of 2021 and the comparative period in 2020:

•Oil and natural gas revenues increased by $2.8 million (8%), due to a 35% increase in commodity prices partially offset by a 28% decrease in production;

•Lease operating expenses decreased by $3.2 million (42%), primarily due to lower production volumes and cost reduction measures which were undertaken starting in the second quarter of 2020 in light of the lower commodity price environment;

•Commodity derivative expense increased by $125.4 million ($24.2 million of expense during the first quarter of 2021 compared to $101.2 million of income during the first quarter of 2020); and

•Impairment of oil and gas properties totaled $199.9 million during the first quarter of 2020 compared to none during the first quarter of 2021. See Operating Results — Impairment of Oil and Gas Properties below for further details.

•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.

RESULTS OF OPERATIONS

Certain of our operating results and statistics for the three months ended March 31, 2021 and 2020 are summarized below:


In thousands, except per share and unit data	Successor		Predecessor
	Three Months Ended March 31, 2021		Three Months Ended March 31, 2020
Operating Results
Net loss attributable to common stockholders	$	(6,322)	$	(113,048)
Net loss per common share – basic(1)	(0.63)		(4.52)
Net loss per common share – diluted(1)	(0.63)		(4.52)
Net cash provided by operating activities	1,883		13,835
Revenues
Oil	$	27,872	$	29,990
NGLs	4,297		2,599
Natural gas	7,647		4,420
Total revenues	$	39,816	$	37,009
Total production volumes by product
Oil (Bbls)	499,997		658,476
NGLs (Bbls)	195,688		303,485
Natural gas (Mcf)	1,429,190		2,110,381
Total barrels of oil equivalent (6:1)	933,883		1,313,691
Daily production volumes by product
Oil (Bbls/d)	5,556		7,236
NGLs (Bbls/d)	2,174		3,335
Natural gas (Mcf/d)	15,880		23,191
Total barrels of oil equivalent (BOE/d)	10,377		14,436
Average realized prices
Oil ($ per Bbl)	$	55.74	$	45.54
NGLs ($ per Bbl)	21.96		8.56
Natural gas ($ per Mcf)	5.35		2.09
Total oil equivalent, excluding the effect from commodity derivatives ($ per BOE)	42.63		28.17
Total oil equivalent, including the effect from commodity derivatives ($ per BOE)	36.84		34.40
Operating and other expenses
Lease operating	$	4,446	$	7,638
Gas gathering, processing and transportation	1,542		2,150
Production and ad valorem taxes	2,421		2,369
Depreciation, depletion and amortization	5,309		24,354
General and administrative	3,977		2,881
Interest expense	4,106		11,610
Operating and other expenses per BOE
Lease operating	$	4.76	$	5.81
Gas gathering, processing and transportation	1.65		1.64
Production and ad valorem taxes	2.59		1.80
Depreciation, depletion and amortization	5.68		18.54
General and administrative	4.26		2.19
Interest expense	4.40		8.84

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

Production

The table below summarizes our production volumes for the three months ended March 31, 2021 and 2020:


	Successor	Predecessor
	Three Months Ended March 31, 2021	Three Months Ended March 31, 2020
Oil (Bbls/d)	5,556	7,236
NGLs (Bbls/d)	2,174	3,335
Natural gas (Mcf/d)	15,880	23,191
Total (BOE/d)	10,377	14,436

Total production during the first quarter of 2021 averaged 10,377 BOE per day, a decrease of 28%, or 4,059 BOE per day, compared to the same period in 2020. This was ~~crude~~decrease was primarily driven by the deferral of our development program, which was suspended in the third quarter of 2020 and did not resume until January 2021.

Our production during the first quarter of 2021 was 74% oil ~~16% was~~and NGLs, approximately the same as the first quarter of 2020.

Oil, Natural Gas Liquid and ~~15% was~~Natural Gas Revenues

The table below summarizes our production revenues for the three months ended March 31, 2021 and 2020:


In thousands	Successor		Predecessor
	Three Months Ended March 31, 2021		Three Months Ended March 31, 2020
Oil	$	27,872	$	29,990
NGLs	4,297		2,599
Natural gas	7,647		4,420
Total revenues	$	39,816	$	37,009

Our oil, NGL and natural ~~gas.~~

~~Recent Developments Regarding Lonestar Properties~~

~~Eagle Ford Shale Trend - Western Region~~

~~Asherton~~

~~In Dimmit County, no new wells were completed~~gas revenues during the three months ended ~~September 30, 2017.~~March 31, 2021 increased $2.8 million, or 7%, compared to those revenues for the same period in 2020. The ~~Asherton leasehold is held by~~changes in our oil, NGL and natural gas revenues are due to changes in production quantities and ~~Lonestar does not currently plan~~commodity prices (excluding any ~~drilling activity here~~impact of our commodity derivative contracts), as reflected in ~~2017.~~

~~Beall Ranch~~

~~In Dimmit County, no new wells~~the following table:


In thousands	Three Months Ended March 31, 2021 vs 2020

	(Decrease) Increase in Revenues		Percentage (Decrease) Increase in Revenues
Change in oil, NGL and natural gas revenues due to:
Decrease in production	$	(10,699)	(28)	%
Increase in commodity prices	13,506		35	%
Total change in oil, NGL and natural gas revenues	$	2,807	8	%

Excluding the impact of our commodity derivative contracts, our net realized commodity prices and NYMEX differentials were ~~completed~~as follows during the three months ended ~~September 30, 2017.~~March 31, 2021 and 2020:


	Successor		Predecessor
	Three Months Ended March 31, 2021		Three Months Ended March 31, 2020
Average net realized price
Oil ($/Bbl)	$	55.74	$	45.54
NGLs ($/Bbls)	21.96		8.56
Natural gas ($/Mcf)	5.35		2.09
Total ($/BOE)	42.63		28.17
Average NYMEX differentials
Oil per Bbl	$	(2.10)	$	0.03
Natural gas per Mcf	1.79		(0.18)

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. Variations in our crude oil pricing are related to swings in components of MEH (Magellan East Houston) and the CMA/Roll. These variations caused our differentials to WTI to move from $0.03 per barrel in the first quarter of 2020 to negative $2.10 per barrel in the first quarter of 2021.

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 ~~Beall Ranch leasehold is held by~~natural gas differential for the three months ended March 31, 2021 (Successor) includes the benefit of abnormally high realizations achieved in February 2021 resulting from higher gas residue prices during Winter Storm Uri.

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 ~~Lonestar does not currently plan any drilling activity here in 2017.~~

~~Burns Ranch~~

~~Lonestar has drilled~~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 ~~B#1H~~net cash (payments) receipts on the Company’s commodity derivatives and ~~B#2H~~the relative price impact (per Bbl or Mcf) for the three months ended March 31, 2021 and 2020:


	Successor				Predecessor
	Three Months Ended March 31, 2021				Three Months Ended March 31, 2020
In thousands, except price impact	Net realized settlements		Price impact		Net realized settlements		Price impact
Payments on settlements of oil derivatives	$	(4,027)	$	(8.05)	$	(155)	$	(0.24)
Receipts on settlements of natural gas derivatives	657		0.46		1,236		0.59
Total net commodity derivative settlements	$	(3,370)			$	1,081

Our realized net loss on ~~Burns Ranch~~commodity derivative contracts on an accrual basis was $5.4 million for the three months ended March 31, 2021 (Successor) as compared to ~~total depths~~net gain of ~~17,927 and 18,002 feet, respectively, with projected perforated intervals~~$8.2 million for these wells at approximately 9,450 feet. Originally scheduled for early September, 2017, but deferred by our third-party service provider, fracture stimulation operations commenced in late October, 2017. Basedthe three months ended March 31, 2020 (Predecessor). We realized an average loss of $4.55 per BOE on our ~~current rates of daily stage completion, flowback is anticipated to begin in mid-November, 2017. Lonestar owns a 92% working interest (“WI”)~~oil and ~~a 69% net revenue interest (“NRI”) in these wells. These wells do not contribute to our third quarter revenues.~~

~~Horned Frog~~

~~In La Salle County, no new wells were completed~~natural gas swaps during the three months ended ~~September 30, 2017. The Horned Frog leasehold is held by production, and Lonestar has constructed a drilling pad and currently plans~~March 31, 2021 (Successor), as compared to ~~drill the Horned Frog B#4H and C#1H wells, planned for perforated intervals of 10,000 feet in the first quarter of 2018.~~

~~Eagle Ford Shale Trend - Central Region~~

~~Gonzales County~~

Production from four wells completed as part of the Company’s 2017 capital program contributed to the Company’s third quarter results. The Cyclone #4H & Cyclone #5H were drilled and completed during the second quarter and placed into service in late June, 2017. The production results during the first 120 days in service are encouraging, as the 52,000 barrel average cumulative production from these wells is 31% higher than the first 120 days of Lonestar’s initial wells at Cyclone, the #9H and #10H. The Cyclone #26H and Cyclone #27H wells were drilled and completed in the third quarter and began producing on September 22, 2017. Lonestar has a 100% WI and 79% NRI in these wells. The Cyclone #26H and #27H wells were fracture-stimulated in engineered completions with an average ~~proppant concentration~~gain of ~~1,525 pounds~~$6.23 per foot over 28 stages per well, and utilized diverters. The Cyclone #26H was completed with a perforated interval of 8,351 feet and tested 760 Bbls/d and 420 Mcf/d, or 762 Boe/d (three-stream) on a 24/64’’ choke. The well has recently established a 30-day production rate of 723 Boe/d, consisting of 637 barrels of oil per day (88%), 39 barrels of natural gas liquids (5%), and 282 Mcf per day of natural gas (7%). The Cyclone #27H was completed with a perforated interval of 8,278 feet and tested 733 Bbls/d and 428 Mcf/d, or 831 Boe/d (three-stream) on a 22/64’’ choke. The well has recently established a 30-day production rate of 687 Boe/d, consisting of 609 barrels of oil per day (88%), 39 barrels of natural gas liquids (6%), and 282 Mcf per day of natural gas (6%). On average, these two new wells have recovered 14% of their frac load, to date.

~~Pirate~~

In Wilson County, no new wells were completed during the three months ended September 30, 2017. The Pirate leasehold is held by production, and Lonestar does not currently plan any drilling activity here in 2017.

~~Eagle Ford Shale Trend - Eastern Region~~

~~Brazos & Robertson Counties~~

Lonestar owns a 50% WI/ 39% NRI in the Wildcat B#1H, which was placed into service in May 2017. The Wildcat B#1H has now been producing for five months. The Company is encouraged by the productivity of the well, with cumulative production having totaled 225,000 barrels of oil equivalent, which is 65% greater than the average cumulative production from the 20 offset wells drilled by another operator and 23% higher than the most prolific producing offset well. The Wildcat B#1H was classified as “Probable” in the Company’s third-party reserve report as of December 31, 2016. In that third-party report, gross reserves were estimated at 840,000 barrels of oil equivalent. At the request of the Company, our third-party engineer updated its reserves forecast for the Wildcat B#1H to account for actual production results. The updated reserves estimates yield a 29% increase in forecasted Estimated Ultimate Recovery (“EUR”) to 1,086,000 barrels of oil equivalent. The results of the Wildcat B#1H are encouraging, as Lonestar has a sizable leasehold position in the Wildcat Area in the deep Eagle Ford section in Brazos County, and notably, has not booked any proved reserves to the area. Lonestar has 9,555 gross / 6,420 net acres in the Wildcat area, which holds 38 extended-reach drilling locations, based on 800-foot spacing.

~~Eagle Ford Shale Acquisitions~~

~~Karnes, Gonzales, Fayette, Lavaca, DeWitt Counties~~

Lonestar assumed operatorship of the Marquis and Battlecat Acquisitions on June 15, 2017. The Company quickly transferred daily operations from third party contractors to Lonestar employees and conducted approximately $2 million of capital improvements on 41 of the 81 wells to bring the wells to the Company’s operational standards. This spending has resulted in improved performance, reduced maintenance and September’s production represented the highest month of production since April, 2017.

~~Operating Results~~

The following discussion relates to our consolidated results of operations, financial condition and capital resources. You should read this discussion in conjunction with our consolidated financial statements and the notes thereto. Comparative results of operations for the period indicated are discussed below.

~~Results of operations~~BOE for the three months ended ~~September 30, 2017 compared~~March 31, 2020 (Predecessor).

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 ~~three months ended September 30, 2016~~

~~Net Production~~

consolidated financial statements for additional details of our outstanding commodity derivative contracts as of March 31, 2021 for additional discussion.

For the three months
ended September 30,

2017

2016

% Change

Crude Oil (Bbls/d):

Eagle Ford Shale

5,250

2,903

81
%
Conventional

—

272

-100
%
Total Crude Oil

5,250

3,175

65
%
Natural Gas Liquids (Bbls/d):

Eagle Ford Shale

1,228

1,237

-1
%
Conventional

—

1

-100
%
Total NGLs

1,228

1,238

-1
%
Natural Gas (Mcf/d):

Eagle Ford Shale

7,105

8,064

-12
%
Conventional

—

977

-100
%
Total Natural Gas

7,105

9,041

-21
%
Oil Equivalent (Boe/d):

Eagle Ford Shale

7,662

5,485

40
%
Conventional

—

436

-100
%
Total Oil Equivalent

7,662

5,921

29
%

The following table summarizes our oil and natural gas derivative contracts as of May 5, 2021:


	Q2 2021		Q3 2021		Q4 2021		1H 2022		2H 2022		1H 2023		2H 2023
Oil — WTI
Volumes Hedged (Bbls/d)	6,150		5,650		5,400		3,124		3,000		1,450		1,275
Swap Price	$	46.66	$	46.62	$	46.03	$	47.32	$	46.73	$	52.99	$	52.50

Natural Gas — Henry Hub
Volumes Hedged (Mcf/d)	12,400		16,400		10,700		7,486		5,000		—		—
Swap Price	$	2.88	$	2.93	$	3.05	$	2.82	$	2.70	$	—	$	—

Production ~~volumes during the three months ended September 30, 2017 were 7,662 Boe/d, an increase~~Expenses

The table below presents detail of ~~29% from 5,921 Boe/d during the three months ended September 30, 2016. The increase in our average daily~~ production ~~is primarily the result of Lonestar’s acquisition of the Marquis and Battlecat properties at the end of the second quarter of 2017, which contributed 1,883 Boe/d~~expenses for the three months ended ~~September 30, 2017. The comparisons for the period are also impacted by the prior sale of our Conventional assets, which contributed 436 Boe/d for the three months ended September 30, 2016~~March 31, 2021 and ~~0 Boe/d for the three months ended September 30, 2017.~~

Sequentially, Lonestar reported a 36% increase in net oil and gas production, increasing production to 7,662 Boe/d during the three months ended September 30, 2017 compared to 5,635 Boe/d during the three months ended June 30, 2017. For the three months ended September 30, 2017, approximately 69% of our production was crude oil, 16% was NGLs and 15% was natural gas.

Net production from our Eagle Ford Shale assets averaged approximately 7,662 Boe/d in the three months ended September 30, 2017, a 40% increase over the approximate 5,485 Boe/d in the three months ended September 30, 2016. Approximately 85% of our Eagle Ford production in the three months ended September 30, 2017 was liquid hydrocarbons. Sequentially, Lonestar reported a 36% increase in net oil and gas production in its Eagle Ford Shale assets, increasing production to 7,662 Boe/d during the three months ended September 30, 2017 compared to 5,635 Boe/d during the three months ended June 30, 2017.

2020:

Net production from our Conventional properties was 0 Boe/d in the three months ended September 30, 2017 compared to 436 Boe/d in the three months ended September 30, 2016 due to the divestiture of our Conventional assets in the second half of 2016.


In thousands, except expense per BOE	Successor		Predecessor
	Three Months Ended March 31, 2021		Three Months Ended March 31, 2020
Production expenses
Lease operating	$	4,446	$	7,638
Gas gathering, processing and transportation	1,542		2,150
Production and ad valorem taxes	2,421		2,369
Depreciation, depletion and amortization	5,309		24,354
Production expenses per BOE
Lease operating and gas gathering	$	4.76	$	5.81
Gas gathering, processing and transportation	1.65		1.64
Production and ad valorem taxes	2.59		1.80
Depreciation, depletion and amortization	5.68		18.54

~~Average Sales Price~~

For the three months
ended September 30,

2017

2016

% Change

Crude Oil ($/Bbls):

Eagle Ford Shale

$
47.96

$
42.11

14
%
Conventional

—

41.46

-100
%
Total Crude Oil

$
47.96

$
42.05

14
%
Natural Gas Liquids ($/Bbls):

Eagle Ford Shale

$
16.19

$
9.33

73
%
Conventional

—

6.16

-100
%
Total NGLs

$
16.19

$
9.33

74
%
Natural Gas ($/Mcf):

Eagle Ford Shale

$
2.90

$
2.67

8
%
Conventional

—

2.29

-100
%
Total Natural Gas

$
2.90

$
2.63

10
%
Oil Equivalent ($/Boe):

Eagle Ford Shale

$
38.14

$
28.33

35
%
Conventional

—

31.05

-100
%
Total Oil Equivalent, excluding the effect from hedging

$
38.14

$
28.53

34
%
Total Oil Equivalent, including the effect from hedging

$
40.66

$
40.03

2
%

The average wellhead price for our production in the three months ended September 30, 2017 was $38.14 per Boe, a 34% increase compared to the average price in the comparable period in 2016. Reported wellhead realizations were positively influenced by a 7% increase in the crude oil benchmark price (West Texas Intermediate) and a 3% increase in the natural gas benchmark price (Henry Hub) between these periods. The Company also benefited from its ongoing ability to negotiate better local discounts to the benchmarks. Our crude oil hedge positions added $3.69 per barrel of oil sold or $2.53 per Boe.

The average wellhead price for our Eagle Ford Shale production in the three months ended September 30, 2017 was $38.14 per Boe, which was 35% higher than the average price in the comparable period in 2016 due to the increase in the crude oil and natural gas benchmark prices.

~~The average wellhead price for our Conventional properties in the three months ended September 30, 2017 was $0.00 per Boe, due to the divestiture of our Conventional assets in the second half of 2016.~~

~~Revenues~~

For the three months
ended September 30,

($ in thousands)

2017

2016

% Change

Oil Revenues:

Eagle Ford Shale

$
23,162

$
11,247

106
%
Conventional

—

1,038

-100
%
Total Oil Revenues

$
23,162

$
12,285

89
%
NGLs Revenues:

Eagle Ford Shale

$
1,831

$
1,063

72
%
Conventional

—

0

-100
%
Total NGLs Revenues

$
1,831

$
1,063

72
%
Natural Gas Revenues:

Eagle Ford Shale

$
1,890

$
1,984

(5
)%
Conventional

—

206

-100
%
Total Natural Gas Revenues

$
1,890

$
2,190

-14
%
Total Wellhead Revenues:

Eagle Ford Shale

$
26,883

$
14,294

88
%
Conventional

—

1,244

-100
%
Total Wellhead Revenues

$
26,883

$
15,538

73
%

Wellhead revenues in the three months ended September 30, 2017 were $26.9 million, a 73% increase from $15.5 million from the comparable period in 2016. This increase in revenue was a result of a 29% increase in production and a 34% increase in realizations. We also realized favorable crude oil hedge cash settlements, which added $1.8 million in gains on commodity derivatives for the three months ended September 30, 2017.

Wellhead revenues for our Eagle Ford Shale assets in the three months ended September 30, 2017 were $26.9 million, an 88% increase from the comparable period in 2016 as a result of a 35% increase in wellhead price realizations coupled with a 40% increase in production in the three months ended September 30, 2017.

Wellhead revenues for our Conventional properties in the three months ended September 30, 2017 were $0.0 million, compared to $1.2 million, due to the divestiture of our Conventional assets in the second half of 2016.

~~Costs and Expenses~~

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

For the three months
ended September 30,

(In thousands, except expense per Boe)

2017

2016

% Change
Operating Expenses:

Lease operating and gas gathering

$            4,515

4,006

13%
Production, ad valorem, and severance taxes

1,541

907

70%
Depreciation, depletion and amortization

15,929

10,718

49%
General and administrative

2,298

2,870

-20%
Rig standby expense

61

364

-83%

Operating Expenses per Boe:

Lease operating and gas gathering

$              6.40

$              7.36

-13%
Production, ad valorem, and severance taxes

2.19

1.67

31%
Depreciation, depletion and amortization

22.60

19.68

15%
General and administrative

3.26

5.27

-38%

Lease Operating and Gas Gathering ~~Expenses~~

Lease operating expenses are the costs incurred in the operation of producing properties and workover costs. Expenses for direct labor, water injection and disposal, utilities, materials and supplies comprise the most significant portion of our lease operating expenses. Lease operating expenses do not include general and administrative expenses or production and ad valorem ~~or severance~~ taxes.

~~Our~~

Total lease operating ~~expenses increased $0.5~~expense was $4.4 million, ~~(13%) in~~or $4.76 per BOE, for the three months ended ~~September 30, 2017~~March 31, 2021 (Successor), compared to ~~$4.5~~$7.6 million, ~~from $4.0 million in~~or $5.81 per BOE, during the ~~comparable~~Predecessor’s same period in ~~2016. However, on a unit-of-production basis, our lease operating expenses decreased 13% from $7.36~~2020. Total gas gathering, processing and transportation expense was $1.5 million, or $1.65 per ~~Boe in~~BOE for the three months ended ~~September 30, 2016~~March 31, 2021 (Successor), compared to ~~$6.40~~$2.2 million, or $1.64 per ~~Boe~~BOE, during the Predecessor’s same period in 2020. The decreases in lease operating expense on an absolute-dollar basis and per-BOE basis were primarily due lower production in the ~~three months ended September 30, 2017 due to our ability to integrate our recent Eagle Ford Shale acquisitions on a cost-effective basis,~~current quarter and lower expenses across all expense categories, as ~~well as reduced operating expenses associated with the sale of our Conventional assets~~we implemented cost reduction measures starting in the second ~~half~~quarter of ~~2016.~~

~~Sequentially, our lease operating~~2020 which we have carried forward to a certain degree through today. Gas gathering, processing and transportation expense ~~increased by 28%, or $1.0 million to $4.5 million~~dropped between the periods relatively in-line with the drop in the three months ended September 30, 2017 from $3.5 million in the three months ended June 30, 2017. Increased lease operating expenses are a function of the acquisition of 81 gross Eagle Ford Shale wells, which added 1,883 Boe/d of production in the three months ended September 30, 2017. On a unit-of-production basis, we reduced our lease operating expenses by 7% sequentially to $6.40 per Boe in the three months ended September 30, 2017, from $6.87 per Boe in the three months ended June 30, 2017.

natural gas production.

Production ~~Severance~~ and Ad Valorem Taxes

~~Severance and ad valorem~~

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.

~~Our total~~

The following table provides detail of our production ~~severance~~ and ad valorem taxes infor the three months ended ~~September 30, 2017 were $1.5~~March 31, 2021 and 2020:


	Successor		Predecessor
In thousands	Three Months Ended March 31, 2021		Three Months Ended March 31, 2020
Production taxes	$	1,755	$	1,325
Ad valorem taxes	666		1,044
Total production and ad valorem tax expense	$	2,421	$	2,369

Total production and ad valorem tax expense was $2.4 million, ~~an increase of $0.6 million (70%) to $0.9 million from the comparable period in 2016 primarily due to the 29% increase in production.~~

~~Rig Standby Expense~~

~~The Company incurred rig standby expense of $0.1 million in~~or $2.59 per BOE, for the three months ended ~~September 30, 2017, compared to $0.4 million~~March 31, 2021 (Successor), which was relatively flat on an absolute dollar basis and $1.80 on a per BOE during the same period in 2020 for the Predecessor.

Depreciation, Depletion and Amortization

The table below provides detail of our DD&A expense for the three months ended ~~September 30, 2016.~~

~~Depreciation, Depletion~~March 31, 2021 and ~~Amortization (DD&A)~~

2020.

	For the three months ended September 30,
	2017		2016
	(In thousands)
DD&A of proved oil and gas properties	$	15,658	$	10,498
In thousands					In thousands	Successor		Predecessor
						Three Months Ended March 31, 2021		Three Months Ended March 31, 2020
Depletion of proved oil and gas properties					Depletion of proved oil and gas properties	$	4,856	$	23,905
Depreciation of other property and equipment		233		167	Depreciation of other property and equipment	338		363
Accretion of asset retirement obligations		38		53	Accretion of asset retirement obligations	115		86
Depreciation, Depletion and Amortization	$	15,929	$	10,718
Total DD&A expense					Total DD&A expense	$	5,309	$	24,354

Capitalized costs attributed to our proved properties are subject to depreciation and depletion. Depreciation and depletion of the cost of oil and natural gas properties is calculated using the unit-of-production method aggregating properties on a field basis. For leasehold acquisition costs and the cost to acquire proved properties, the reserve base used to calculate depreciation and depletion is the sum of proved developed reserves and proved undeveloped reserves. For ~~development~~well costs, the reserve base used to calculate depletion and depreciation is proved developed reserves only. Other property and equipment are carried at cost, and depreciation is calculated using the straight-line method over the estimated useful lives of the assets, ranging from 3 to 5 years.

Total DD&A inexpense was $5.3 million, or $5.68 per BOE, for three months ended March 31, 2021 (Successor), compared to $24.4 million, or $18.54 per BOE, for the three months ended ~~September 30, 2017~~March 31, 2020 (Predecessor). The combined Predecessor and Successor period decreases in oil and natural gas properties depletion and other property and equipment depreciation was ~~$15.9 million, increased 49% from the comparable period in 2016~~primarily due to ~~Lonestar’s acquisition~~impairment charges we incurred during the first quarter of ~~the Marquis and Battlecat properties which helped increase production 29%~~2020 (Predecessor) after removing proven undeveloped reserves (“PUDs”) (see below), as well as the sale of our Conventional assets that held fully depleted producing properties. On a unit of production basis, DD&A increased 15% from $19.68 in the three months ended September 30, 2016 to $22.60 in the three months ended September 30, 2017lower depletable costs due to the ~~sale~~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 ~~our Conventional assets that held fully depleted producing properties.~~

~~Sequentially, Lonestar reported a 27% increase in DD&A, increasing DD&A to $15.9 million during the three months ended September~~November 30, 2017, compared to $12.5 million during the three months ended June 30, 2017. Increased DD&A is a function of the acquisition of 81 gross Eagle Ford Shale wells which added 1,883 Boe/d of production in the three months ended September 30, 2017. On a unit of production basis, we reduced our DD&A 8% sequentially to $22.60 per Boe in the three months ended September 30, 2017, from $24.48 per Boe in the three months ended June 30, 2017 due to Lonestar’s acquisition of the Marquis and Battlecat properties which have lower depletion rates per Boe.

2020.

Impairment of Oil and Gas Properties

~~The~~

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 ~~did not record~~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 first quarter of 2021.

General and Administrative

Total general and administrative (“G&A”) expense was $4.0 million, or $4.26 per BOE, for the three months ended ~~September 30, 2017, a decrease of $29.1~~March 31, 2021 (Successor), compared to $2.9 million, ~~from~~or $2.19 per BOE, for the three months ended ~~September 30, 2016.~~

~~General and Administrative (G&A) Expenses~~

March 31, 2020 (Predecessor). G&A ~~expenses decreased $0.6 million to $2.3 million in~~for the three months ended ~~September 30, 2017 from $2.9~~March 31, 2021 (Successor) includes approximately $0.7 million ~~from~~of professional fees residual to the ~~comparable period~~Company’s restructuring in ~~2016. On a unit~~2020, including legal, consulting and accounting fees incurred as part of ~~production basis, we decreased our~~the Company’s fresh-start accounting process. G&A ~~expense by 38% from $5.27 per Boe in~~for the three months ended ~~September 30, 2016~~March 31, 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 and the Successor company did not implement any new stock-based compensation plans prior to ~~$3.26 per Boe in~~March 31, 2021.

The table below provides detail of the interest expense for our various long-term obligations for the three months ended ~~September 30, 2017.~~

March 31, 2021 and 2020:


In thousands	Successor		Predecessor
	Three Months Ended March 31, 2021		Three Months Ended March 31, 2020
Interest expense on Successor Credit Facility	$	2,846	$	—
Interest expense on Successor Term Loan Facility	723		—
Interest expense on Predecessor 11.25% Senior Notes	—		7,031
Interest expense on Predecessor Credit Facility	—		3,685
Other interest expense	55		126
Total cash interest expense (1)	$	3,624	$	10,842
Amortization of debt issuance costs and discounts	482		768
Total interest expense	$	4,106	$	11,610
Per BOE:
Total cash interest expense	$	3.88	$	8.25
Total interest expense	4.40		8.84

(1) Cash interest ~~expense in~~is presented on an accrual basis.

Cash interest was $3.6 million, or $3.88 per BOE, for the three months ended ~~September 30, 2017 was $5.0~~March 31, 2021 (Successor), compared to $10.8 million, a decrease of 13% from $5.8 million from the comparable period in 2016 due to the repayment of our Second Lien Notes and the partial repurchase of the 8.750% Senior Notes. On a unit of production basis, we reduced our interest expense by 48% from $13.49or $8.25 per ~~Boe in~~BOE, for the three months ended ~~September 30, 2016~~March 31, 2020 (Predecessor). The decrease between periods was primarily due to ~~$7.05 per Boe~~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.

The following table provides further detail of our income taxes for the three months ended ~~September 30, 2017.~~

March 31, 2021 and 2020:

For the three months
ended September 30,

2017

2016

(In thousands)

Interest expense on 8.750% Senior Notes

$
3,129

$
4,268

Interest expense on Second Lien Notes

—

505

Interest expense on Senior Secured Credit Facility

1,831

969

Other interest expense

71

9

Interest expense, net

$
5,031

$
5,751


In thousands, except per-BOE amounts and tax rates	Successor			Predecessor
	Three Months Ended March 31, 2021			Three Months Ended March 31, 2020
Current income tax (expense) benefit	$	(160)		$	424
Deferred income tax benefit	—			931
Total income tax (expense) benefit	$	(160)		$	1,355
Average income tax (expense) benefit per BOE	$	(0.17)		$	12.64
Effective tax rate	(2.6)		%	1.2		%

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 March 31, 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 and the continued low oil price environment, we recorded a total valuation allowance of $38.8 million on ~~Derivative Financial Instruments~~

Inour underlying deferred tax assets as of March 31, 2021. For the three months ended ~~September 30, 2017, we recognized a non-cash loss of $9.4 million on our commodity derivative contracts related to~~March 31, 2021 (Successor), the change in mark-to-market value of our derivative contracts and while recording a $1.8 million realized gain on settlement of our commodity derivative contracts during the quarter. Settlement of the crude oil hedge positions added $3.69 per barrel to crude oil price realization during the three months ended September 30, 2017.

~~Income Taxes~~

As a result of the net loss before income tax of $11.5 million in the three months ended September 30, 2017 and net loss before income tax of $9.6 million in three months ended September 30, 2016, we recorded an income tax benefit ~~of $4.7 million~~associated with the Successor’s pre-tax book loss was substantially offset by a change in ~~the 2017 period and an income~~valuation allowance.

Our deferred tax ~~expense of $1.7 million in the 2016 period.~~

~~Net Income (Loss) Before Taxes~~

~~As a result~~assets exceeded our deferred tax liabilities at March 31, 2020 (Predecessor) primarily due to tax consequences of the ~~$11.3 million (73%) increase in revenue caused by the increase in crude oil and natural gas benchmark prices, a $29.1 million decrease in~~ impairment ~~expense, a $0.7 million decrease in interest expense, and an unrealized gain on warrants~~ of $1.0 million, offset by an increase in loss on derivatives of $9.3 million, a $5.2 million increase in DD&A, and a $29.4 million decrease in gain on disposal of bonds, we recorded a net loss before income tax of $11.5 million in the three months ended September 30, 2017 compared to net loss before income tax of $9.6 million in the three months ended September 30, 2016.

~~Results of operations for the nine months ended September 30, 2017 compared to the nine months ended September 30, 2016~~

~~Net Production~~

For the nine months ended September 30,

2017

2016

% Change
Crude Oil (Bbls/d):

Eagle Ford Shale

4,026

3,192

26%
Conventional

—

330

-100%
Total Crude Oil

4,026

3,522

14%
Natural Gas Liquids (Bbls/d):

Eagle Ford Shale

1,055

1,220

-14%
Conventional

—

7

-100%
Total NGLs

1,055

1,227

-14%
Natural Gas (Mcf/d):

Eagle Ford Shale

6,682

8,386

-20%
Conventional

—

1,209

-100%
Total Natural Gas

6,682

9,595

-30%
Oil Equivalent (Boe/d):

Eagle Ford Shale

6,194

5,810

7%
Conventional

—

538

-100%
Total Oil Equivalent

6,194

6,348

-2%

~~Production volumes~~our proved properties during the nine months ended September 30, 2017 were 6,194 Boe/d, a decrease of 2% from 6,348 Boe/d during the nine months ended September 30, 2016. The decrease in our average daily production is primarily the result of Lonestar’s sale of its Conventional assets in the second half of 2016, which had contributed 538 Boe/d for the nine months ended September 30, 2016, and reduced drilling activity in the second half of 2016, which yielded natural production declines through the first quarter of 2017. These decreases were partially offset by renewed drilling in 2017, as well as our recent acquisitions of the Battlecat and Marquis properties, which closed on June 15, 2017. For the nine months ended September 30, 2017, approximately 65% of our production was crude oil, 17% was NGLs and 18% was natural gas.

Net production from our Eagle Ford Shale assets averaged approximately 6,194 Boe/d in the nine months ended September 30, 2017, a 7% increase over the approximate 5,810 Boe/d in the nine months ended September 30, 2016. Approximately 82% of our Eagle Ford production in the nine months ended September 30, 2017 was liquid hydrocarbons.

Net production from our Conventional properties was 0 Boe/d in the nine months ended September 30, 2017 compared to 538 Boe/d in the nine months ended September 30, 2016 due to the divestiture of our Conventional assets in the second half of 2016.

~~Average Sales Price~~

For the nine months ended September 30,

2017

2016

% Change

Crude Oil ($/Bbls):

Eagle Ford Shale

$
47.99

$
37.80

27
%
Conventional

—

37.01

-100
%
Total Crude Oil

$
47.99

$
37.73

27
%
Natural Gas Liquids ($/Bbls):

Eagle Ford Shale

$
16.74

$
8.00

109
%
Conventional

—

5.98

-100
%
Total NGLs

$
16.74

$
7.99

110
%
Natural Gas ($/Mcf):

Eagle Ford Shale

$
2.78

$
2.08

34
%
Conventional

—

2.04

-100
%
Total Natural Gas

$
2.78

$
2.07

34
%
Oil Equivalent ($/Boe):

Eagle Ford Shale

$
37.04

$
25.45

46
%
Conventional

—

27.32

-100
%
Total Oil Equivalent, excluding the effect from hedging

$
37.04

$
25.61

45
%
Total Oil Equivalent, including the effect from hedging

$
39.31

$
38.72

2
%

The average wellhead price for our production in the nine months ended September 30, 2017 was $37.04 per Boe, which was 45% higher than the average price in the comparable period in 2016. Reported wellhead realizations were driven higher by increases in both the crude oil and natural gas benchmarks between the periods. In addition to the increases in benchmark prices, our crude oil hedge positions added $3.49 per barrel of oil or $2.27 per barrel of oil equivalent.

The average wellhead price for our Eagle Ford Shale production in the nine months ended September 30, 2017 was $37.04 per Boe, which was 46% higher than the average price in the comparable period in 2016 due to the significant increases in the crude oil and natural gas benchmarks.

~~The average wellhead price for our Conventional properties in the nine months ended September 30, 2017 was $0.00 per Boe, due to the divestiture of our Conventional assets in the second half of 2016.~~

~~Revenues~~

For the nine months ended September 30,

($ in thousands)

2017

2016

% Change

Oil Revenues:

Eagle Ford Shale

$
52,742

$
33,063

60
%
Conventional

—

3,341

-100
%
Total Oil Revenues

$
52,742

$
36,404

45
%
NGLs Revenues:

Eagle Ford Shale

$
4,820

$
2,673

80
%
Conventional

—

12

-100
%
Total NGLs Revenues

$
4,820

$
2,685

80
%
Natural Gas Revenues:

Eagle Ford Shale

$
5,072

$
4,772

6
%
Conventional

—

676

-100
%
Total Natural Gas Revenues

$
5,072

$
5,448

-7
%
Total Wellhead Revenues:

Eagle Ford Shale

$
62,634

$
40,508

55
%
Conventional

—

4,029

-100
%
Total Wellhead Revenues

$
62,634

$
44,537

��

41
%

Wellhead revenues in the nine months ended September 30, 2017 were $62.6 million, a 41% increase from $44.5 million compared to the comparable period in 2016. These increases in revenue were a result of increases in benchmark prices. We also realized favorable crude oil hedge cash settlements, which added $3.8 million in gains on commodity derivatives for the nine months ended September 30, 2017.

~~Wellhead revenues for our Eagle Ford Shale in the nine months ended September 30, 2017 were $62.6 million, a 55% increase from the comparable period in 2016~~2020; as a result, we retained a full valuation allowance of ~~a 46% increase in wellhead price realizations, coupled with a 7% increase in production in~~$32.6 million at March 31, 2020 due to uncertainties regarding the ~~nine months ended September 30, 2017.~~

future realization of our deferred tax assets. The valuation allowance is also the primary cause for the variance between our statutory tax rate of 21% and the effective tax rate of 1.2% for the quarter.

~~Wellhead revenues for our Conventional properties in~~On March 27, 2020, Congress enacted the ~~nine months ended September 30, 2017 were $0.0 million, compared~~Coronavirus Aid, Relief, and Economic Security Act (the “CARES Act”) to ~~$4.0 million from the comparable period in 2016~~provide certain taxpayer relief as a result of the ~~divestiture~~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 ~~Conventional assets in the second half of 2016.~~

~~Costs and Expenses~~

~~The table below presents a detail of costs and expenses~~effective tax rate for the ~~periods indicated.~~

For the nine months ended September 30,

(In thousands, except expense per Boe

2017

2016

% Change

Operating Expenses:

Lease operating and gas gathering

$
10,992

$
12,764

-14
%
Production, ad valorem, and severance taxes

3,656

3,046

20
%
Depreciation, depletion and amortization

40,623

38,461

6
%
General and administrative

7,940

8,501

-7
%
Rig standby expense

61

2,261

-97
%

Operating Expenses per Boe:

Lease operating and gas gathering

$
6.50

$
7.34

-11
%
Production, ad valorem, and severance taxes

2.16

1.75

23
%
Depreciation, depletion and amortization

24.02

22.11

9
%
General and administrative

4.70

4.89

-4
%

~~Lease Operating~~three months ended March 31, 2021 (Successor) and ~~Gas Gathering Expenses~~

~~Lease operating expenses~~2020 (Predecessor).

CAPITAL RESOURCES AND LIQUIDITY

Our primary sources of capital and liquidity are ~~the costs incurred in the operation~~our cash flows from operations and availability of ~~producing properties and workover costs. Expenses for direct labor, water injection and disposal, utilities, materials and supplies comprise the~~borrowing capacity under our Successor Credit Facility (as defined below). Our most significant ~~portion of our lease operating expenses. Lease operating expenses do not include general and administrative expenses or production or ad valorem taxes.~~

Our total lease operating expenses decreased 14% in the nine months ended September 30, 2017 to $11.0 million from the comparable period in 2016 due to a 2% decrease in production as well as operational efficiencies by implementing salt water disposals at multiple properties. On a unit-of-production basis, our lease operating expenses decreased 11% from $7.34 per Boe in the nine months ended September 30, 2016 to $6.50 per Boe in the nine months ended September 30, 2017.

~~Production, Severance and Ad Valorem Taxes~~

Severance and ad valorem taxes are paid on produced crude oil and natural gas based upon a percentage of gross revenues or at fixed rates established by state or local taxing authorities. In general, the production taxes we pay correlate to the changes in oil and natural gas revenues. We are also subject to ad valorem taxes in the counties where our production is located. Ad valorem taxes are generally based on the valuation of our oil and natural gas properties.

~~Our total production, severance, and ad valorem taxes were $3.7 million in the nine months ended September 30, 2017 compared to $3.0 million in the comparable period in 2016.~~

~~Rig Standby Expense~~

~~The Company incurred rig standby expense of $0.1 million in the nine months ended September 30, 2017, compared to $2.3 million in the nine months ended September 30, 2016.~~

~~Depreciation, Depletion and Amortization (DD&A)~~

~~Capitalized costs attributed~~cash outlays relate to our ~~proved properties~~development capital expenditures and current period operating expenses.

The Company’s primary needs for cash are ~~subject to depreciation and depletion. Depreciation and depletion of the cost~~for capital expenditures, acquisitions of oil and natural gas properties, ~~is calculated using the unit-of-production method aggregating properties on a field basis. For leasehold acquisition costs~~payments of contractual obligations and the cost to acquire proved properties, the reserve base used to calculate depreciation and depletion is the sum of proved developed reserves and proved undeveloped reserves. For development costs, the reserve base used to calculate depletion and depreciation is proved developed reserves only. Other property and equipment are carried at cost, and depreciation is calculated using the straight-line method over the estimated useful lives of the assets, ranging from 3 to 5 years.

DD&A in the nine months ended September 30, 2017 was $40.6 million, a 6% increase from $38.5 million in the comparable period in 2016 primarily due to the sale of our Conventional assets that held fully depleted producing properties. On a unit of production basis, DD&A increased 9% from $22.11 per Boe in the nine months ended September 30, 2016 to $24.02 per Boe in the nine months ended September 30, 2017.

For the nine months ended September 30,

2017

2016

(In thousands)

DD&A of proved oil and gas properties

$
39,959

$
37,839

Depreciation of other property and equipment

568

462

Accretion of asset retirement obligations

96

160

Depreciation, Depletion and Amortization

$
40,623

$
38,461

~~Impairment of Oil and Gas Properties~~

The Company recorded impairment expense of $27.1 million for the nine months ended September 30, 2017 relating to its West Poplar property in Montana, a 13% decrease from the $32.1 million recorded in the nine months ended September 30, 2016 relating primarily to its conventional properties in Texas.

~~General and Administrative (G&A) Expenses~~

G&A expense in the nine months ended September 30, 2017 was $7.9 million, a decrease of 7% from $8.5 in the comparable period in 2016. On a unit of production basis, we decreased our G&A expense by 4% from $4.89 per Boe in the three months ended September 30, 2016 to $4.70 per Boe in the three months ended September 30, 2017.

~~Interest Expense~~

Our interest expense in the nine months ended September 30, 2017 was $15.4 million, a decrease of $1.5 million from $17.0 million from the comparable period in 2016 due to the incurrence of a $1.1 million early payment premium for the Company paying off its second lien debt, which bore a higher interest rate. On a unit of production basis, interest expense increased 12% from $9.38 per Boe in the three months ended September 30, 2016 to $10.56 per Boe in the six months ended September 30, 2017.

For the nine months ended September 30,

2017

2016

(In thousands)

Interest expense on 8.750% Senior Notes

$
9,809

$
13,893

Interest expense on Second Lien Notes

2,016

505

Interest expense on Senior Secured Credit Facility

3,535

2,535

Other interest expense

88

28

Interest expense, net

$
15,448

$
16,961

~~Gains (Losses) on Derivative Financial Instruments~~

In the nine months ended September 30, 2017, we recognized a non-cash $2.7 million gain on our commodity derivative contracts related to the change in fair value of our derivative contracts and a $3.8 million realized gain on settlement of our commodity derivative contracts. Settlement of the crude oil hedge positions added $3.49 per barrel to crude oil price realization.

~~Income Taxes~~

As a result of the net loss before income tax of $42.2 million in the nine months ended September 30, 2017 and net loss before income tax of $45.8 million from the comparable period in 2016, we recorded income tax benefit of $15.3 million and $10.4 million in the nine months ended September 30, 2017 and 2016, respectively.

~~Net Income (Loss) Before Taxes~~

As a result of an increase of $18.1 million (41% ) in revenue caused by the increase in crude oil and natural gas benchmark prices, an increase in gain on derivatives of $9.9 million, an unrealized gain on warrants of $3.9 million, a decrease in lease operating expense $1.8 million, a $1.5 million decrease in interest expense, and a decrease in impairment expense of $4.0 million, offset by an increase in DD&A of $2.2 million, a $29.4 million decrease in gain on disposal of bonds, and acquisition costs of $3.1 million, we recorded a net loss before income tax of $42.2 million in the nine months ended September 30, 2017 compared to a net loss before income tax of $45.8 million in the nine months ended September 30, 2016.

~~Liquidity and Capital Resources~~

~~We expect that our primary sources of liquidity and~~working capital ~~resources will be cash flows generated by operating activities and borrowings under our $500,000,000 Senior Secured Credit Facility (the “Senior Secured Credit Facility”).~~

obligations. We have historically financed our ~~acquisition and development activity~~business through cash flows ~~generated by operating activities,~~from operations, borrowings under our ~~Senior Secured~~Predecessor Credit Facility (as defined below) and the issuance of ~~bonds.~~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. ~~Such uses~~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.

At September 30, 2017, we had $4.8 million in cash and cash equivalents and approximately $31.9 million of additional availability under our Senior Secured Credit Facility. Based on current commodity prices, we believe that our drilling program will generate increases in the borrowing base associated with our Senior Secured Credit Facility. Combined with our plans to keep capital spending and cash flow from operations in general balance in 2018, we believe that our existing cash and cash equivalents, cash

Net Cash Provided Byby Operating Activities

Net cash provided by operating activities ~~increased $10.3~~was $1.9 million ~~from $18.2~~for three months ended March 31, 2021 (Successor), compared to $13.8 million for the three months ended March 31, 2020 (Predecessor). Although production revenues between the quarters stayed relatively flat, higher realized hedging losses in the ~~nine months ended September 30, 2016 to $28.5 million in the nine months ended September 30, 2017. This increase is primarily due~~current quarter contributed to a significant amount of the decrease, in net loss of $8.5 million, a $2.7 million increase in non-cash interest expense, a $29.4 million decrease in gain on disposal of bonds, a $0.9 million decrease in gain on disposal of oil and gas properties, an $8.8 million increase in operating assets and liabilities, and an increase in DD&A of $2.2 million,partially offset by a $19.4 million dollar decrease in settlements of derivative financial instruments, a $4.0 million decrease in impairment of oil and gas properties, a $5.6 million increase in deferred taxes, a $9.9 million increase in non-cash gain on derivative financial instruments, and a $3.9 million increase in unrealized gain on equity warrants during the nine months ended September 30, 2017.

lower lease operating expenses.

Net Cash Used Inin Investing Activities

Net cash used in investing activities increased $152.0 million from $25.5 million in the nine months ended September 30, 2016 to $177.5 million in the nine months ended September 30, 2017. This increase is due to a $105.9 million increase in the acquisition of oil and gas properties, a $32.0 million increase in the development of oil and gas properties, an $11.4 million increase in purchases of other property and equipment, and a decrease in proceeds from sales of oil and gas properties of $2.7 million.

~~Net Cash Provided By Financing Activities~~

Net cash provided by financing activities increased $138.9 million from $8.9 million used during the nine months ended September 30, 2016 to $147.8 million provided in the nine months ended September 30, 2017. The increase was due to increased borrowings and equity issuances of $117.1 million and decrease payments on bank borrowings of $27.3 million, offset by costs to issue debt and equity of $5.5 million in the nine months ended September 30, 2017.

~~Hedging~~

~~The following table provides a summary of our derivative contracts as of September 30, 2017:~~

At September 30, 2017, the Company held the derivative contracts listed in the table above, which aggregate to 364,600 barrels or 3,963 barrels of oil per day for the remainder of 2017, 1,713,500 barrels or 4,695 barrels of oil per day for 2018, 1,069,600 barrels or 2,930 barrels per day for 2019, and 203,600 barrels or 1,119 barrels of oil per day through June of 2020. Our 2017 derivative contracts consist of 3,039 Bbls/d swaps at a volume weighted average price of $52.03 per Bbl and three-way collars covering 923 Bbls/d, which provide an effective floor of $55.25 per Bbl with WTI prices between $40.00 per Bbl and $60.00 per Bbl, and also gives upside to $80.25 per Bbl. Our 2018 derivative contracts consist of 4,195 Bbls/d swaps at a volume weighted average price of $51.83 per Bbl and two-way collars covering 500 Bbls/d with a price ceiling of $59.45 per Bbl. Our 2019 derivative contracts consist of 2,930 Bbls/d swaps at a price of $49.16. Our 2020 derivative contracts consist of 1,119 Bbls/d thru June at a price of $48.90 per Bbl.

The above natural gas derivative contract equates to 644,000 MMBtu or 7,000 MMBtu per day for the remainder of 2017 at a fixed price of $3.36 per MMBtu and 1,825,000 MMBtu or 5,000 MMBtu per day for 2018 at a fixed price of $3.09 per MMBtu.

Subsequent to the quarter ended September 30, 2017, the Company entered into an additional WTI crude oil swap for 2019 which added an additional 401,500 barrels or 1,100 barrels per day at a price of $50.90 per barrel.

~~Debt~~

As of September 30, 2017, we had an aggregate of $286.4 million of indebtedness, including $128.1 million drawn on our Senior Secured Credit Facility, $151.8 million (less an unamortized discount of $1.1 million and debt issuance costs of $0.6 million) on our 8.750% Senior Notes, $7.9 million of mortgage debt and $0.3 million of other long-term notes.

~~Senior Secured Credit Facility~~

As of September 30, 2017 LRAI had outstanding borrowings of approximately $128.1 million under the Senior Secured Credit Facility, which was subject to an average interest rate of approximately 5.49% and 5.17% during the three and nine months ended September 30, 2017, respectively. Additionally, the Senior Secured Credit Facility may be used for loans and, subject to a $2,500,000 sub-limit, letters of credit. LRAI has $500,000 of advances on the letter of credit as of September 30, 2017. The borrowing base under the Senior Secured Credit Facility can be redetermined up or down by the lenders based on, among other things, their evaluation of our oil and natural gas reserves. Effective as of May 19, 2016, the borrowing base was reduced to $120 million. Effective as of November 23, 2016, the borrowing base was reduced from $120 million to $112 million. In connection with closing the Marquis

Acquisition and the Battlecat Acquisition, on June 15, 2017, LRAI entered into the Sixth Amendment and Joinder to Credit Agreement (the “Sixth Amendment”) to its Credit Agreement, dated as of July 28, 2015, among LRAI, the subsidiary guarantors party thereto, the several lenders party thereto and Citibank, N.A., in its capacity as administrative agent and as issuing bank. Pursuant to the Sixth Amendment, the Credit Agreement was amended to (i) increase the borrowing base from $112 million to $160 million until redetermined or adjusted in accordance with the Credit Agreement Under the Sixth Amendment, redeterminations are scheduled semi-annually to occur during May and November of each year. The next borrowing base redetermination is scheduled for November 2017.

~~With borrowings outstanding of $128.1 million and letters of credit of $0.5 million, borrowing availability at September 30, 2017 was $31.4 million.~~

~~8.750% Senior Notes~~

LRAI issued $220 million aggregate principal amount of the 8.750% Senior Notes in April 2014 under an indenture among LRAI, its subsidiary guarantors and Wells Fargo Bank, National Association, as trustee. The Company is not a party to the indenture.

The 8.750% Senior Notes mature on April 15, 2019 and accrue interest at a rate of 8.750% per annum, payable semi-annually in arrears on April 15 and October 15 of each year until the maturity date. The 8.750% Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by each subsidiary of LRAI.

~~Securities Purchase Agreement and Second Lien Notes~~

On August 2, 2016, LRAI and the Company entered into a Securities Purchase Agreement (the “Purchase Agreement”) with Juneau Energy, LLC, as initial purchaser (the “Initial Purchaser”), Leucadia National Corporation (“Leucadia”), as guarantor of the Initial Purchaser’s obligations, the other purchasers party thereto (collectively, along with the Initial Purchaser, the “Purchasers”) and Jefferies, LLC, in its capacity as the collateral agent for the Purchasers, relating to the issuance and sale of (i) up to $49,900,000 aggregate principal amount of the Second Lien Notes and (ii) five-year warrants to purchase up to an aggregate 998,000 shares of the Company’s Class A voting common stock at a price equal to $5.00 per share.

During 2016, LRAI issued $38.0 million in aggregate principal amount of Second Lien Notes and the Company issued the Warrants to purchase 760,000 shares of its Class A voting common stock. The Company recorded an equity warrant liability of approximately $5.1 million which was the fair value amount at the date of issuance. The Warrants were adjusted to fair value at September 30, 2017 which resulted in a gain on the Warrants of approximately $0.4$1.6 million for the three months ended ~~September 30, 2017. Proceeds~~March 31, 2021 (Successor), compared to $35.8 million for the three months ended March 31, 2020 (Predecessor). This decrease is primarily due to lower drilling and development costs in the current quarter, as we did not resume our one-rig drilling program until February 2021 and payment for the majority of our completion costs incurred during the quarter was not made after quarter end.

Net Cash (Used in) Provided by Financing Activities

Net cash used by financing activities was $5.1 million for the three months ended March 31, 2021 (Successor), compared to $19.9 million provided by financing activities for the three months ended March 31, 2020 (Predecessor). This decrease resulted from no new borrowings on our Successor Credit Facility in the ~~Second Lien Notes issuance were used~~current quarter in addition to ~~repurchase approximately $68.2~~the quarterly $5.0 million ~~in aggregate principal amount~~pay-down we made on our Successor Term Loan at the end of the ~~8.750% Senior Notes in privately negotiated open market repurchases with holders~~quarter. In comparison, the prior period had $8.0 million of ~~such notes,~~payments but $28.0 million of borrowings. Currently, our availability under the Successor Credit Facility is $15.0 million and we are required to ~~pay related fees and expenses related to~~make three more quarterly pay-downs on our Successor Term Loan which will total an additional $15.0 million by the ~~foregoing. The repurchase amounts paid were approximately $36.2 million in cash. Net~~end of ~~related fees, such repurchases resulted in a gain on debt extinguishment of approximately $28.5 million.~~

In December 2016, LRAI repaid $21.0 million principal of the Second Lien Notes with proceeds from the 2016 Common Stock Offering. In June 2017, LRAI repaid the remaining $17.0 million principal of Second Lien Notes, including an early payment premium of approximately $1.1 million with borrowings from the Company’s2021.

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 ~~Company also recorded~~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 ~~approximate $2.0~~amount equal to $5.0 million, ~~charge due to early recognition~~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 ~~warrant discount associated with the payoff~~Successor’s direct and indirect subsidiaries (subject to certain permitted exceptions) and will be secured by a lien on substantially all of the ~~Second Lien Notes.~~

Successor’s, Lonestar Resources America Inc.’s and the guarantors’ assets (subject to certain exceptions).

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

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 months ended March 31, 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 March 31, 2021, the Successor was in compliance with all debt covenants under the Successor Credit Facilities.

Predecessor Senior Secured Bank Credit Facility

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

~~Historical capital expenditures~~

The table below summarizes our cash capital expenditures incurred for the ~~periods listed below. Future~~three months ended March 31, 2021:


In thousands	Three Months Ended March 31, 2021
Acquisition of oil and gas properties	$	1,215
Development of oil and gas properties	389
Purchases of other property and equipment	11
Total capital expenditures	$	1,615

For the three months ended March 31, 2021, our capital expenditures were funded with cash flow from operations. As noted above, cash payments for capital expenditures were lower this quarter in-part due to the timing of payments associated with the drilling and development activity ongoing during the quarter, which in ~~2017~~most cases were made after quarter end.

Capital expenditures on an accrual basis, including acquisitions, totaled $12.1 million during the three months ended March 31, 2021, which were primarily comprised of completion costs incurred for our Hawkeye E33, E34 and F35 wells, and drilling costs incurred on our Horned Frog West 1H and 2H wells, which were completed during April 2021.

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 ~~dictated by cash flow.~~

Three Months Ended

Nine months ended

($ in thousands)

March 31, 2017

June 30, 2017

September 30, 2017

September 30, 2017

Acquisition of oil and gas properties

$
1,563

$
106,616

$
852

$
109,031

Development of oil and gas properties

19,076

18,674

19,168

56,918

Purchases of other property and equipment

13

1,509

10,058

11,580

Total capital expenditures, net

$
20,652

$
126,799

$
30,078

$
177,529

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.

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~~Management’s Discussion and Analysis of Financial Condition and Results of ~~Operations”~~Operations section of our ~~Annual Report on~~ Form ~~10-K as reported and filed with the SEC on March 23, 2017 (our “2016 10-K”).~~ 10-K.

As of ~~September 30, 2017,~~March 31, 2021, there were no significant changes to any of our critical accounting policies and estimates.

~~Recently Issued Accounting Pronouncements~~

See “Note 2. Recently Issued Accounting Pronouncements” in the Notes to Unaudited Consolidated Financial Statements in this report for discussion of recently issued and adopted accounting standards affecting the Company.

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.

~~Forward-looking~~

These forward-looking statements ~~may~~ include, among others, statements ~~about our:~~

regarding:

• ~~discovery~~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 ~~crude~~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 ~~NGLs~~ and ~~natural~~ gas ~~reserves;~~

industry;

• ~~cash flows~~our ability to make, integrate and ~~liquidity;~~

• ~~business and financial strategy, budget, projections and operating results;~~

• ~~timing and amount of future production of crude oil, NGLs and natural gas;~~

• ~~amount, nature and timing of capital expenditures, including future development costs;~~

• ~~availability and terms of capital;~~

• ~~drilling, completion, performance, and operation of wells;~~

• ~~timing, location and size of property~~develop acquisitions and ~~divestitures;~~

• ~~costs~~realize any expected benefits or effects of ~~exploiting~~completed acquisitions;

•the benefits, effects, availability of and ~~developing~~ results of new and existing joint ventures and sales transactions;

•our ~~properties~~ability to maintain a sound financial position;

•receipt of receivables, drilling carry and ~~conducting other operations;~~

proceeds from sales;

• ~~general economic~~our ability to complete planned transactions on desirable terms;

•the impact of governmental regulation, taxes, market changes and ~~business conditions;~~world events; and

• ~~our plans, objectives, expectations and intentions.~~

global or national health concerns, including health epidemics such as the ongoing coronavirus outbreak beginning in early 2020.

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)~~1A. Risk Factors, Item ~~8 (Financial~~8. Financial Statements and

Supplementary ~~Data)~~Data and elsewhere in our ~~2016~~Form 10-K, and Part ~~I (Financial Information)~~I. Financial Information, Item ~~1A (Risk Factors)~~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 ~~of proved reserves;~~

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 ~~regards~~regard to our drilling schedules;

•~~risks related to~~ 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;

•~~competitive~~ competition within the crude oil and natural gas industry;

•technology risks;

•~~risks related to~~ 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”~~Risk Factors in Item 1A of Part I of our ~~2016~~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.

Item 3. Quantitative and Qualitative Disclosures About Market Risk.

~~There~~

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 March 31, 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	$	(28,305)	$	(46,377)	$	(10,142)

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 noapproved 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 ~~changes~~adverse effect on our cash flows for the period between hedge settlement and payment for revenues earned.

As of March 31, 2021, we had $259.6 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 ~~market risks as~~results of ~~September 30, 2017 from those disclosed~~operations and cash flow. Based on borrowings outstanding at March 31, 2021, a 100-basis-point change in interest rates would change our ~~2016 10-K.~~

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.

Item 4. Controls and Procedures.

~~Limitations on Effectiveness of Controls and Procedures~~

In designing and evaluating our disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives. In addition, the design of disclosure controls and procedures must reflect the fact that there are resource constraints and that management is required to apply judgment in evaluating the benefits of possible controls and procedures relative to their costs.


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

~~600 Bailey Avenue,~~111 Boland Street, Suite ~~200,~~301, Fort Worth, TX						76107
(Address of principal executive offices)						(Zip Code)

		~~Page~~
				Page
PART I.			FINANCIAL INFORMATION
Item 1.			Financial Statements ~~(Unaudited)~~	1 2
			Unaudited Condensed Consolidated Balance Sheets at March 31, 202 1 and December 31, 20 20	1 3
			Unaudited Condensed Consolidated Statements of Operations ~~& Comprehensive Income (Loss)~~for the Three Months Ended March 31, 20 21 and 20 20	3 4
			Unaudited Condensed Consolidated ~~Statement~~Statements of Changes in ~~Stockholders’~~Stockholders' Equity for the Three Months Ended March 31, 202 1 and 20 20	4 5
			Unaudited Condensed Consolidated Statements of Cash Flows for the Three Months Ended March 31, 202 1 and 20 20	5 6
			Notes to Unaudited Condensed Consolidated Financial Statements	6 7
Item 2.			Management’s Discussion and Analysis of Financial Condition and Results of Operations	21 17
Item 3.			Quantitative and Qualitative Disclosures About Market Risk	37 32
Item 4.			Controls and Procedures	38 33
PART II.			OTHER INFORMATION	34
Item 1.			Legal Proceedings	38 34
Item 1A.			Risk Factors	38 34
Item 2.			Unregistered Sales of Equity Securities and Use of Proceeds	38 34
Item 3. 6.			~~Defaults Upon Senior Securities~~Exhibits	38 35
~~Item 4.~~				~~Mine Safety Disclosures~~	38
~~Item 5.~~	~~Other Information~~	38
~~Item 6.~~	~~Exhibits~~	39
~~Exhibit Index~~		40
Signatures		42 36


	September 30, 2017		December 31, 2016			March 31, 2021		December 31, 2020
Assets	(Unaudited)				Assets

Current assets					Current assets
Cash and cash equivalents	$	4,812	$	6,068	Cash and cash equivalents	$	19,494	$	17,474
Accounts receivable:
Restricted cash					Restricted cash	2,157		8,972
Accounts receivable					Accounts receivable
Oil, natural gas liquid and natural gas sales		10,398		4,680	Oil, natural gas liquid and natural gas sales	18,839		11,635
Joint interest owners and other, net		965		867
Related parties		245		847
Joint interest owners and others, net					Joint interest owners and others, net	2,053		4,076

Derivative financial instruments		3,121		1,730	Derivative financial instruments	840		1,703
Prepaid expenses and other		5,709		2,631	Prepaid expenses and other	1,534		1,118
Total current assets					Total current assets	44,917		44,978
Property and equipment					Property and equipment
Oil and gas properties, using the successful efforts method of accounting					Oil and gas properties, using the successful efforts method of accounting
Proved properties					Proved properties	327,096		314,685
Unproved properties					Unproved properties	34,145		34,929
Other property and equipment					Other property and equipment	19,690		19,680
Less accumulated depreciation, depletion and amortization					Less accumulated depreciation, depletion and amortization	(7,237)		(2,056)
Property and equipment, net					Property and equipment, net	373,694		367,238
Accounts receivable					Accounts receivable	6,200		6,053
Derivative financial instruments					Derivative financial instruments	510		395
Other non-current assets					Other non-current assets	4,444		4,651
Total assets					Total assets	$	429,765	$	423,315
Liabilities and Stockholders' Equity					Liabilities and Stockholders' Equity
Current liabilities					Current liabilities
Accounts payable					Accounts payable	$	16,801	$	7,651
Oil, natural gas liquid and natural gas sales payable					Oil, natural gas liquid and natural gas sales payable	15,180		18,760
Accrued liabilities					Accrued liabilities	7,763		15,983
Derivative financial instruments					Derivative financial instruments	23,803		7,938
Current maturities of long-term debt					Current maturities of long-term debt	20,000		20,000
Total current liabilities					Total current liabilities	83,547		70,332
Long-term liabilities					Long-term liabilities
Long-term debt					Long-term debt	250,331		255,328
Asset retirement obligations					Asset retirement obligations	4,190		4,573

Total current assets		25,250		16,823
Derivative financial instruments					Derivative financial instruments	5,772		835

Oil and gas properties, net, using the successful efforts method of accounting		552,919		439,228
Other property and equipment, net		12,432		1,421
Derivative financial instruments		773		—
Other noncurrent assets		3,796		1,561
Restricted certificates of deposit		76		76
Total long-term liabilities					Total long-term liabilities	260,293		260,736
Commitments and contingencies (Note 11)					Commitments and contingencies (Note 11)	0		0
Stockholders' Equity					Stockholders' Equity
Common stock, $0.001 par value, 100,000,000 shares authorized, 10,000,149 shares issued and outstanding					Common stock, $0.001 par value, 100,000,000 shares authorized, 10,000,149 shares issued and outstanding	10		10

Total assets	$	595,246	$	459,109
Additional paid-in capital					Additional paid-in capital	92,953		92,953
Accumulated deficit					Accumulated deficit	(7,038)		(716)
Total stockholders' equity					Total stockholders' equity	85,925		92,247
Total liabilities and stockholders' equity					Total liabilities and stockholders' equity	$	429,765	$	423,315

	September 30, 2017			December 31, 2016
Liabilities and Stockholders’ Equity	(Unaudited)

Current liabilities
Accounts payable	$	12,386		$	14,894
Accounts payable – related parties		108			1,135
Oil, natural gas liquid and natural gas sales payable		7,521			3,568
Accrued liabilities		22,365			9,947
Accrued liabilities – related parties		78			224
Derivative financial instruments		1,991			2,985

Total current liabilities		44,449			32,753

Long-term debt		286,398			204,122
Long-term debt - related parties		—			3,400
Deferred tax liability		21,977			38,020
Other non-current liabilities		6,241			6,052
Equity warrant liability		439			1,565
Equity warrant liability - related parties		834			2,994
Asset retirement obligations		5,097			2,683
Derivative financial instruments		2,672			1,125

Total liabilities		368,107			292,714

Commitments and contingencies

Mezzanine equity
Series A-2 convertible participating preferred stock, $0.001 par value, 76,577 issued and outstanding at September 30, 2017 and 0 issued and outstanding at December 31, 2016		74,712			—

Stockholders’ equity
Class A voting common stock, $0.001 par value, 100,000,000 shares authorized, 21,822,015 issued and outstanding at September 30, 2017 and December 31, 2016, respectively		142,652			142,652
Class B non-voting common stock, $0.001 par value, 5,000 shares authorized, 2,500 issued and outstanding at September 30, 2017 and December 31, 2016, respectively		—			—
Series A-1 convertible participating preferred stock, $0.001 par value and Series B convertible participating preferred stock, $0.001 par value, 5,543 shares and 2,684,632 shares issued and outstanding at September 30, 2017, respectively, 0 and 0 issued and outstanding at December 31, 2016, respectively		3			—
Additional paid-in capital		100,146			87,260
Accumulated deficit		(90,374	)		(63,517	)

Total stockholders’ equity		152,427			166,395

Total liabilities and stockholders’ equity	$	595,246		$	459,109

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2017			2016			2017			2016
Revenues
Oil sales	$	23,162		$	12,285		$	52,742		$	36,404
Natural gas sales		1,890			2,190			5,072			5,448
Natural gas liquid sales		1,831			1,063			4,820			2,685

Total revenues		26,883			15,538			62,634			44,537

Costs and expenses
Lease operating and gas gathering		4,515			4,006			10,992			12,764
Production, ad valorem, and severance taxes		1,541			907			3,656			3,046
Rig standby expense		61			364			61			2,261
Depletion, depreciation, and amortization		15,891			10,665			40,527			38,301
Accretion of asset retirement obligations		38			53			96			160
Loss (gain) on sale of oil and gas properties		119			53			466			(1,478	)
Impairment of oil and gas properties		—			29,144			27,081			31,082
Stock-based compensation		346			122			985			313
General and administrative		2,298			2,870			7,940			8,501
Acquisition costs		337			—			3,063			—
Other (income) expense		(4	)		1			(62	)		1,045

Total costs and expenses		25,142			48,185			94,805			95,995

Income (loss) from operations		1,741			(32,647	)		(32,171	)		(51,458	)

Other income (expense)
Interest expense		(5,031	)		(5,751	)		(15,448	)		(16,961	)
Gain on disposal of bonds		—			29,363			—			29,363
Amortization of finance costs		(934	)		(1,594	)		(4,368	)		(2,683	)
Gain (loss) on warrants		402			(611	)		3,286			(611	)
Gain (loss) on derivative financial instruments		(7,657	)		1,664			6,505			(3,405	)

Total other income (expense), net		(13,220	)		23,071			(10,025	)		5,703

Loss before income taxes		(11,479	)		(9,576	)		(42,196	)		(45,755	)

Income tax benefit (expense)		4,718			(1,684	)		15,339			10,354

Net loss		(6,761	)		(11,260	)		(26,857	)		(35,401	)

Preferred stock dividends		(1,824	)		—			(2,120	)		—

Net loss attributable to common stockholders	$	(8,585	)	$	(11,260	)	$	(28,977	)	$	(35,401	)
Earnings per share:
Basic	$	(0.39	)	$	(1.44	)	$	(1.33	)	$	(4.64	)
Diluted	$	(0.39	)	$	(1.44	)	$	(1.33	)	$	(4.64	)
Weighted Average Shares Outstanding - basic		21,822,015			7,842,586			21,822,015			7,629,896
Weighted Average Shares Outstanding - diluted		21,822,015			7,842,586			21,822,015			7,629,896
Comprehensive loss:
Net loss	$	(6,761	)	$	(11,260	)	$	(26,857	)	$	(35,401	)
Foreign currency translation adjustments		—			(13	)		—			(29	)
Comprehensive loss	$	(6,761	)	$	(11,273	)	$	(26,857	)	$	(35,430	)

															Accumulated
	Class A Voting				Series A-1 and Series B				Additional						Other
	Common Stock				Preferred Stock				Paid-in			Accumulated			Comprehensive			Total Stockholders'
	Shares		Amount		Shares		Amount		Capital			Deficit			Loss			Equity
Balance at December 31, 2015		7,521,788	$	142,638		—	$	—	$	10,270		$	30,818		$	(760	)	$	182,966

Sale of common stock, net of offering costs		13,800,000		14		—		—		71,803			—			—			71,817

Shares issued for asset acquisition		500,227		—		—		—		5,499			—			—			5,499

Stock-based compensation		—		—		—		—		448			—			—			448

Foreign currency translation		—		—		—		—		(760	)		—			760			—

Net loss		—		—		—		—		—			(94,335	)		—			(94,335	)

Balance at December 31, 2016		21,822,015	$	142,652		—	$	—	$	87,260		$	(63,517	)	$	—		$	166,395

Shares issued for asset acquisitions		—		—		2,690,175		3		12,090			—			—			12,093

Stock-based compensation		—		—		—		—		796			—			—			796

Net loss		—		—		—		—		—			(26,857	)		—			(26,857	)

Balance at September 30, 2017		21,822,015	$	142,652		2,690,175	$	3	$	100,146		$	(90,374	)	$	—		$	152,427

	Three months ended September 30, 2017
	Lonestar			Marquis		Battlecat		Pro Forma Adjustments			Pro Forma Lonestar
Revenues	$	26,883		$	—	$	—	$	—		$	26,883
Net income (loss) attributable to common stockholders		(8,585	)		—		—		—			(8,585	)
Net income (loss) per common share, basic and diluted		(0.39	)		—		—		—			(0.39	)


	Three months ended September 30, 2016
	Lonestar			Marquis		Battlecat		Pro Forma Adjustments			Pro Forma Lonestar
Revenues	$	15,538		$	7,318	$	1,090	$	—		$	23,946
Net income (loss) attributable to common stockholders		(11,260	)		4,127		516		(5,470	)		(12,088	)
Net income (loss) per common share, basic and diluted		(1.44	)		—		—		—			(1.54	)


	Nine months ended September 30, 2017
	Lonestar			Marquis		Battlecat		Pro Forma Adjustments			Pro Forma Lonestar
Revenues	$	62,634		$	11,983	$	1,802	$	—		$	76,419
Net income (loss) attributable to common stockholders		(28,977	)		7,688		603		922			(19,764	)
Net income (loss) per common share, basic and diluted		(1.33	)		—		—		—			(0.91	)


	Nine months ended September 30, 2016
	Lonestar			Marquis		Battlecat		Pro Forma Adjustments			Pro Forma Lonestar
Revenues	$	44,537		$	22,234	$	2,919	$	—		$	69,690
Net income (loss) attributable to common stockholders		(35,401	)		12,029		1,617		(10,561	)		(32,317	)
Net income (loss) per common share, basic and diluted		(4.64	)		—		—		—			(4.24	)

Instrument	Total Volume	Settlement Period	Fixed Price
Oil – WTI Fixed Price Swap	27,600 Bbl	October – December 2017	$	51.05
Oil – WTI Fixed Price Swap	18,400 Bbl	October – December 2017		50.60
Oil – WTI Fixed Price Swap	92,000 Bbl	October – December 2017		52.90
Oil – WTI Fixed Price Swap	46,000 Bbl	October – December 2017		56.00
Oil – WTI Fixed Price Swap	95,600 Bbl	October – December 2017		49.85
Oil – WTI Fixed Price Swap	365,000 Bbl	January – December 2018		54.18
Oil – WTI Fixed Price Swap	182,500 Bbl	January – December 2018		55.65
Oil – WTI Fixed Price Swap	182,500 Bbl	January – December 2018		55.50
Oil – WTI Fixed Price Swap	292,000 Bbl	January – December 2018		47.10
Oil – WTI Fixed Price Swap	509,000 Bbl	January – December 2018		50.17
Oil – WTI Fixed Price Swap	508,900 Bbl	January – December 2019		50.40
Oil – WTI Fixed Price Swap	560,700 Bbl	January – December 2019		48.04
Oil – WTI Fixed Price Swap	203,600 Bbl	January – June 2020		48.90
Natural Gas – Henry Hub NYMEX Fixed Price Swap	644,000 MMBtu	October – December 2017		3.36
Natural Gas – Henry Hub NYMEX Fixed Price Swap	1,825,000 MMBtu	January – December 2018		3.09

	Fair Value Measurements Using
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)			Total
September 30, 2017 (Unaudited)	(In thousands)
Assets:
Commodity derivatives	$	—	$	3,894		$	—		$	3,894
Liabilities:
Commodity derivatives		—		(4,663	)		—			(4,663	)
Equity warrant liability		—		—			(439	)		(439	)
Equity warrant liability - related parties		—		—			(834	)		(834	)
Stock appreciation rights		—		—			(189	)		(189	)

Total	$	—	$	(769	)	$	(1,462	)	$	(2,231	)

December 31, 2016	(In thousands)
Assets:
Commodity derivatives	$	—	$	1,730		$	—		$	1,730
Liabilities:
Commodity derivatives		—		(4,110	)		—			(4,110	)
Equity warrant liability		—		—			(1,565	)		(1,565	)
Equity warrant liability - related parties		—		—			(2,994	)		(2,994	)

Total	$	—	$	(2,380	)	$	(4,559	)	$	(6,939	)

	September 30, 2017 (Unaudited)			December 31, 2016
	(In thousands)
Proved properties and equipment	$	712,866		$	538,695
Unproved properties		79,143			72,584
Less accumulated depletion and impairment		(239,090	)		(172,051	)
	$	552,919		$	439,228

	Shares			Weighted Average Exercise Price Per Share		Weighted Average Remaining Contractual Term (in years)
Outstanding at December 31, 2016		191,750		$	15.00		0.25
Options vested and exercisable at December 31, 2016		191,750		$	15.00		0.25
Granted		—			—		—
Exercised		—			—		—
Canceled/Expired		(16,125	)		—		—
Forfeited		(75,000	)		20.00		—
Outstanding at September 30, 2017		100,625		$	15.00		0.25
Options vested and exercisable at September 30, 2017		100,625		$	15.00		0.25

	Shares			Weighted Average Fair Value per Share		Weighted Average Remaining Contractual Term (in years)
Outstanding non-vested RSUs at December 31, 2016		—		$	—		—
Granted		712,000			6.00		3.0
Vested		—			—		—
Forfeited		(10,000	)		4.10		2.8
Outstanding non-vested RSUs at September 30, 2017		702,000		$	3.50		2.5

	Shares			Weighted Average Fair Value per Share		Weighted Average Exercise Price per share		Weighted Average Remaining Contractual Term (in years)
Outstanding non-vested SARs at December 31, 2016		—		$	—	$	—		—
Granted		700,000			5.00		7.20		5.0
Vested		—			—		—		—
Forfeited		(10,000	)		4.10		7.20		4.8
Outstanding non-vested SARs at September 30, 2017		690,000		$	3.50	$	7.20		4.5

	For the three months ended September 30,
($ in thousands)	2017		2016		% Change
Oil Revenues:
Eagle Ford Shale	$	23,162	$	11,247		106	%
Conventional		—		1,038		-100	%
Total Oil Revenues	$	23,162	$	12,285		89	%
NGLs Revenues:
Eagle Ford Shale	$	1,831	$	1,063		72	%
Conventional		—		0		-100	%
Total NGLs Revenues	$	1,831	$	1,063		72	%
Natural Gas Revenues:
Eagle Ford Shale	$	1,890	$	1,984		(5	)%
Conventional		—		206		-100	%
Total Natural Gas Revenues	$	1,890	$	2,190		-14	%
Total Wellhead Revenues:
Eagle Ford Shale	$	26,883	$	14,294		88	%
Conventional		—		1,244		-100	%
Total Wellhead Revenues	$	26,883	$	15,538		73	%

	For the three months ended September 30,
(In thousands, except expense per Boe)	2017	2016	% Change
Operating Expenses:
Lease operating and gas gathering	$ 4,515	4,006	13%
Production, ad valorem, and severance taxes	1,541	907	70%
Depreciation, depletion and amortization	15,929	10,718	49%
General and administrative	2,298	2,870	-20%
Rig standby expense	61	364	-83%

Operating Expenses per Boe:
Lease operating and gas gathering	$ 6.40	$ 7.36	-13%
Production, ad valorem, and severance taxes	2.19	1.67	31%
Depreciation, depletion and amortization	22.60	19.68	15%
General and administrative	3.26	5.27	-38%

	For the nine months ended September 30,
	2017	2016	% Change
Crude Oil (Bbls/d):
Eagle Ford Shale	4,026	3,192	26%
Conventional	—	330	-100%
Total Crude Oil	4,026	3,522	14%
Natural Gas Liquids (Bbls/d):
Eagle Ford Shale	1,055	1,220	-14%
Conventional	—	7	-100%
Total NGLs	1,055	1,227	-14%
Natural Gas (Mcf/d):
Eagle Ford Shale	6,682	8,386	-20%
Conventional	—	1,209	-100%
Total Natural Gas	6,682	9,595	-30%
Oil Equivalent (Boe/d):
Eagle Ford Shale	6,194	5,810	7%
Conventional	—	538	-100%
Total Oil Equivalent	6,194	6,348	-2%

	For the nine months ended September 30,
(In thousands, except expense per Boe	2017		2016		% Change
Operating Expenses:
Lease operating and gas gathering	$	10,992	$	12,764		-14	%
Production, ad valorem, and severance taxes		3,656		3,046		20	%
Depreciation, depletion and amortization		40,623		38,461		6	%
General and administrative		7,940		8,501		-7	%
Rig standby expense		61		2,261		-97	%

Operating Expenses per Boe:
Lease operating and gas gathering	$	6.50	$	7.34		-11	%
Production, ad valorem, and severance taxes		2.16		1.75		23	%
Depreciation, depletion and amortization		24.02		22.11		9	%
General and administrative		4.70		4.89		-4	%

		Incorporated by Reference .
Exhibit Number	Description	Form	File No.	Exhibit	Filing Date	Filed/ Furnished Herewith
2.1	Scheme Implementation Agreement, by and between Lonestar Resources US Inc. and Lonestar Resources Limited, executed on December 28, 2015	10-12B	001-37670	2.1	12/31/15
2.2	Purchase and Sale Agreement by and between Lonestar Resources US Inc. and Battlecat Oil & Gas, LLC, dated as of May 26, 2017	8-K	001-37670	2.1	6/2/17
2.3	Amendment No. 1, dated June 15, 2017, to the Purchase and Sale Agreement, by and between Lonestar Resources US Inc. and Battlecat Oil & Gas, LLC, dated May 26, 2017	8-K	001-37670	2.1	6/21/17
2.4	Purchase and Sale Agreement by and between Lonestar Resources US Inc. and SN Marquis LLC, dated as of May 26, 2017	8-K	001-37670	2.2	6/2/17
2.5	Amendment No. 1, dated June 15, 2017, to the Purchase and Sale Agreement by and between Lonestar Resources US Inc. and SN Marquis LLC, dated as of May 26, 2017	8-K	001-37670	2.2	6/21/17
3.1	Certificate of Incorporation of Lonestar Resources US Inc.	10-12B	001-37670	3.1	12/31/15
3.2	Certificate of Amendment to the Certificate of Incorporation of Lonestar Resources US Inc.	10-K	001-37670	3.2	3/23/17
3.3	Certificate of Amendment to Certificate of Incorporation of Lonestar Resources US Inc., dated May 24, 2017	8-K	001-37670	3.1	5/26/17
3.4	Amended and Restated Bylaws of Lonestar Resources US Inc.	8-K	001-37670	3.1	4/7/17
3.5	Certificate of Designations of Series B Convertible Preferred Stock	8-K	001-37670	3.1	6/21/17
3.6	Certificate of Designations of Series A-1 Convertible Participating Preferred Stock	8-K	001-37670	3.2	6/21/17
3.7	Certificate of Designations of Series A-2 Convertible Participating Preferred Stock	8-K	001-37670	3.3	6/21/17
4.1	Registration Rights Agreement dated August 2, 2016 by and among Lonestar Resources US Inc., Leucadia National Corporation and Juneau Energy, LLC.	8-K	001-37670	4.1	8/3/16
4.2	Amendment No. 1, dated June 15, 2017, to the Registration Rights Agreement by and among Lonestar Resources US Inc., Leucadia National Corporation and Juneau Energy, LLC (n/k/a JETX Energy, LLC)	8-K	001-37670	4.4	6/21/17
4.3	Registration Rights Agreement, dated October 26, 2016 between Lonestar Resources US Inc. and EF Realisation Company Limited	8-K	001-37670	4.1	11/1/16
4.4	Amendment No. 1, dated June 15, 2017, to the Registration Rights Agreement by and between Lonestar Resources US Inc. and EF Realisation Company Limited	8-K	001-37670	4.5	6/21/17
4.5	Registration Rights Agreement, dated as of June 15, 2017, by and between Lonestar Resources US Inc. and Battlecat Oil & Gas, LLC	8-K	001-37670	4.1	6/21/17


	LONESTAR RESOURCES US INC. ~~(Registrant)~~

~~Date: November 13, 2017~~ May 11, 2021		~~By:~~	/s/ Frank D. Bracken, III
			Frank D. Bracken, III
	Chief Executive Officer

~~Date: November 13, 2017~~ May 11, 2021		~~By:~~	/s/ ~~Douglas W. Banister~~ Jason N. Werth
			~~Douglas W. Banister~~
	Jason N. Werth Chief ~~Financial~~Accounting Officer