UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-Q

(Mark One)

☒	~~QUARTERLY~~
ý	QUARTERL Y REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended ~~September 30, 2017~~

March 31, 2020

☐
☐	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission File Number: 001-37670

Lonestar Resources US Inc.

(Exact Name of Registrant as Specified in its Charter)

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



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)

Registrant’s telephone number, including area code: (817) 921-1889

Securities Registered Pursuant to Section 12(b) of the Act:



Title of Each Class	Trading Symbol	Name of Exchange on Which Registered
Class A Voting Common Stock, par value $0.001 per share	LONE	NASDAQ Global Select 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	☐ ý	~~(Do not check if a smaller reporting company)~~	Smaller reporting company	☒ ý
			Emerging growth company	☒ ý

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒ý

As of ~~November 10, 2017,~~June 29, 2020, the registrant had ~~24,506,647~~25,369,191 shares of Class A voting common stock, par value $0.001 per share, outstanding.

EXPLANATORY NOTE

As previously disclosed in the Current Report on Form 8-K filed by Lonestar Resources US Inc. (the “Company”) on May 11, 2020, the Company expected that the filing of this Quarterly Report on Form 10-Q for the quarter ended March 31, 2020 (the “Report”), originally due on May 15, 2020, would be delayed due to disruptions caused by the COVID-19 coronavirus (“COVID-19”) pandemic. Specifically, the impact of COVID-19 on the Company and its employees, including disruptions in staffing, communications and access to personnel due to stay-at-home orders issued by the Governor of the state of Texas the week of March 30, 2020, resulted in delays, limited support and insufficient review. This, in turn, delayed the Company’s ability to complete its financial reporting process and prepare the Report.

The Company relied on Release No. 34-88465 issued by the Securities and Exchange Commission on March 25, 2020, pursuant to Section 36 of the Securities Exchange Act of 1934, as amended, to delay the filing of this Quarterly Report.

Table of Contents

				~~Page~~

		Page
PART I.	FINANCIAL INFORMATION
Item 1.	Financial Statements ~~(Unaudited)~~	1
	Unaudited Condensed Consolidated Balance Sheets at March 31, 2020 and December 31, 2019	1
	Unaudited Condensed Consolidated Statements of Operations ~~& Comprehensive Income (Loss)~~for the Three Months Ended March 31, 2020 and 2019	3 2
	Unaudited Condensed Consolidated ~~Statement~~Statements of Changes in ~~Stockholders’~~Stockholders' Equity for the Three Months Ended March 31, 2020 and 2019	4 3
	Unaudited Condensed Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2020 and 2019	5 4
	Notes to Unaudited Condensed Consolidated Financial Statements	6 5
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	21 18
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	37
Item 4.	Controls and Procedures	38
PART II.	OTHER INFORMATION	39
Item 1.	Legal Proceedings	38 39
Item 1A.	Risk Factors	38 39
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	38 41
Item 3.	~~Defaults Upon Senior Securities~~Default under Credit Facility	38 41
Item 4. 6.	~~Mine Safety Disclosures~~Exhibits	38 42
~~Item 5.~~		~~Other Information~~	38
~~Item 6.~~	~~Exhibits~~	39
~~Exhibit Index~~		40
Signatures		42 43

iii

~~Presentation of Information~~

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

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, including Lonestar Resources America, Inc. (“LRAI”), the operating company for the Lonestar group of companies, upon completion of the Reorganization, as applicable.

General information about us can be found on our website at www.lonestarresources.com. The information available on or through our website, or about us on any other website, is neither incorporated into, nor part of, this report. Our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and other filings that we make with the U.S. Securities and Exchange Commission (“SEC”), as well as any amendments and exhibits to those reports, will be available free of charge through our website as soon as reasonably practicable after we file or furnish them to the SEC. Information is also available on the SEC website at www.sec.gov for our U.S. filings.

~~Glossary of Certain Defined Terms~~

~~The terms defined in this section are used throughout this Quarterly Report on Form 10-Q:~~

~~Bbl – Barrel of oil.~~

~~Bbls/d – Number of one stock tank barrel, or 42 U.S. gallons liquid volume, of oil or other liquid hydrocarbons per day.~~

~~Boe – Barrels of oil equivalent, with 6,000 cubic feet of natural gas being equivalent to one barrel of oil.~~

~~Boe/d – Barrels of oil equivalent per day.~~

~~EUR – Gross estimated ultimate recoveries for a single well.~~

~~Mcf – Thousand cubic feet of natural gas.~~

~~Mcf/d – Thousand cubic feet of natural gas per day.~~

~~MMBOE – Million barrels of oil equivalent, with 6,000 cubic feet of natural gas being equivalent to one barrel of oil.~~

~~MMBtu – One million British thermal units.~~

WTI – West Texas Intermediate crude oil, which is a light, sweet crude oil, characterized by an American Petroleum Institute gravity between 39 and 41 and a sulfur content of approximately 0.4 weight percent that is used as a benchmark for other crude oils.

PART I—FINANCIAL INFORMATION

Item 1. Financial ~~Statements.~~

Statements

Lonestar Resources US Inc.

Unaudited Condensed Consolidated Balance Sheets

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

September 30,
2017

December 31,
2016

Assets

(Unaudited)

Current assets

Cash and cash equivalents

$
4,812

$
6,068

Accounts receivable:

Oil, natural gas liquid and natural gas sales

10,398

4,680

Joint interest owners and other, net

965

867

Related parties

245

847

Derivative financial instruments

3,121

1,730

Prepaid expenses and other

5,709

2,631

Total current assets

25,250

16,823

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 assets

$
595,246

$
459,109



	March 31, 2020			December 31, 2019
Assets
Current assets
Cash and cash equivalents	$	1,142		$	3,137
Accounts receivable
Oil, natural gas liquid and natural gas sales	10,229			15,991
Joint interest owners and others, net	836			1,310
Derivative financial instruments	74,425			5,095
Prepaid expenses and other	2,873			2,208
Total current assets	89,505			27,741
Property and equipment
Oil and gas properties, using the successful efforts method of accounting
Proved properties	1,083,692			1,050,168
Unproved properties	77,162			76,462
Other property and equipment	21,424			21,401
Less accumulated depreciation, depletion, amortization and impairment	(688,692		)	(464,671		)
Property and equipment, net	493,586			683,360
Accounts receivable – related party	5,936			5,816
Derivative financial instruments	25,434			1,754
Other non-current assets	1,885			2,108
Total assets	$	616,346		$	720,779
Liabilities and Stockholders' Equity
Current liabilities
Accounts payable	$	33,284		$	33,355
Accounts payable – related party	381			189
Oil, natural gas liquid and natural gas sales payable	15,257			14,811
Accrued liabilities	23,049			26,905
Derivative financial instruments	1,501			8,564
Current maturities of long-term debt	513,259			247,000
Total current liabilities	586,731			330,824
Long-term liabilities
Long-term debt	9,148			255,068
Asset retirement obligations	6,888			7,055
Deferred tax liabilities, net	—			931
Warrant liability	—			129
Warrant liability – related party	1			235
Derivative financial instruments	1,896			1,898
Other non-current liabilities	1,346			3,752
Total long-term liabilities	19,279			269,068
Commitments and contingencies (Note 11)
Stockholders' Equity
Class A voting common stock, $0.001 par value, 100,000,000 shares authorized, 25,254,029 and 24,945,594 shares issued and outstanding, respectively	142,655			142,655
Series A-1 convertible participating preferred stock, $0.001 par value, 102,585 and 100,328 shares issued and outstanding, respectively	—			—
Additional paid-in capital	175,978			175,738
Accumulated deficit	(308,297		)	(197,506		)
Total stockholders' equity	10,336			120,887
Total liabilities and stockholders' equity	$	616,346		$	720,779

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



	Three Months Ended March 31,
	2020			2019
Revenues
Oil sales	$	29,990		$	33,584
Natural gas liquid sales	2,599			3,393
Natural gas sales	4,420			3,764
Total revenues	37,009			40,741
Expenses
Lease operating and gas gathering	9,788			7,710
Production and ad valorem taxes	2,369			2,291
Depreciation, depletion and amortization	24,354			17,970
Loss on sale of oil and gas properties	—			32,894
Impairment of oil and gas properties	199,908			—
General and administrative	2,881			4,379
Other	(223		)	(2		)
Total expenses	239,077			65,242
Loss from operations	(202,068		)	(24,501		)
Other income (expense)
Interest expense	(11,610		)	(10,656		)
Change in fair value of warrants	363			(102		)
Gain (loss) on derivative financial instruments	101,169			(36,238		)
Total other income (expense)	89,922			(46,996		)
Loss before income taxes	(112,146		)	(71,497		)
Income tax benefit	1,355			12,933
Net Loss	(110,791		)	(58,564		)
Preferred stock dividends	(2,257		)	(2,065		)
Net loss attributable to common stockholders	$	(113,048	)	$	(60,629	)

Net loss per common share
Basic	$	(4.52	)	$	(2.45	)
Diluted	$	(4.52	)	$	(2.45	)

Weighted average common shares outstanding
Basic	25,003,977			24,698,372
Diluted	25,003,977			24,698,372

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



	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	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	25,254,029	—	142,655		—	102,585	—		—	175,978		—	(308,297		)	—	10,336



	Class A Voting Common Stock			Series A-1 Preferred Stock			Additional Paid-in Capital		Accumulated Deficit			Total Stockholders' Equity
	Shares	Amount		Shares	Amount		Additional Paid-in Capital		Accumulated Deficit			Total Stockholders' Equity
Balance at December 31, 2018	24,645,825	$	142,655	91,784	$	—	$	174,379	$	(94,487	)	$	222,547
Payment-in-kind dividends	—	—		2,065	—		—		—			—
Stock-based compensation	127,818	—		—	—		627		—			627
Net loss	—	—		—	—		—		(58,564		)	(58,564		)
Balance at March 31, 2019	24,773,643	142,655		93,849	—		175,006		(153,051		)	164,610

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



	Three Months Ended March 31,
	2020			2019
Cash flows from operating activities
Net loss	$	(110,791	)	$	(58,564	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Accretion of asset retirement obligations	86			79
Depreciation, depletion and amortization	24,268			17,891
Stock-based compensation	(2,022		)	533
Deferred taxes	(1,376		)	(12,922		)
(Gain) loss on derivative financial instruments	(101,169		)	36,238
Settlements of derivative financial instruments	1,096			1,309
Impairment of oil and natural gas properties	199,908			—
Gain on disposal of property and equipment	83			(17		)
Loss on sale of oil and gas properties	—			32,894
Non-cash interest expense	768			699
Change in fair value of warrants	(363		)	102
Changes in operating assets and liabilities:
Accounts receivable	6,117			(2,016		)
Prepaid expenses and other assets	(374		)	304
Accounts payable and accrued expenses	(2,396		)	(6,704		)
Net cash provided by operating activities	13,835			9,826

Cash flows from investing activities
Acquisition of oil and gas properties	(816		)	(2,352		)
Development of oil and gas properties	(34,753		)	(29,137		)
Proceeds from sale of oil and gas properties	317			12,107
Purchases of other property and equipment	(524		)	(2,916		)
Net cash used in investing activities	(35,776		)	(22,298		)

Cash flows from financing activities
Proceeds from borrowings	28,000			30,000
Payments on borrowings	(8,054		)	(19,116		)
Net cash provided by financing activities	19,946			10,884
Net decrease in cash and cash equivalents	(1,995		)	(1,588		)
Cash and cash equivalents, beginning of the period	3,137			5,355
Cash and cash equivalents, end of the period	$	1,142		$	3,767

Supplemental information:
Cash paid for interest	$	3,957		$	16,743
Non-cash investing and financing activities:
Change in asset retirement obligation	$	(253	)	$	(522	)
Change in liabilities for capital expenditures	(1,040		)	730

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~~corporation whose common stock is listed and traded on the Nasdaq Global Select Market under the symbol “LONE”. Lonestar is 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 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 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, 2019 filed on April 13, 2020 (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 of Consolidation~~

~~The~~ In management’s opinion, the accompanying unaudited condensed consolidated financial statements include ~~the accounts~~all adjustments of ~~the Company’s wholly owned subsidiaries. All significant intercompany balances~~a normal recurring nature necessary for a fair statement of our consolidated financial position as of March 31, 2020 and ~~transactions have been eliminated in consolidation.~~

~~2. Recently Issued Accounting Pronouncements~~

In July 2017, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2017-11, “(Part I) Accounting for Certain Financial Instruments with Down Round Features” in order to simplify the accounting for certain financial instruments with down round features. Part I of the ASU changes the classification analysis of certain equity-linked financial instruments, such as warrants and embedded conversion features, such that a down round feature is disregarded when assessing whether 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 aspects of the indexation guidance under Subtopic 815-40 continue to apply. For public entities, the amendments in Part I of the ASU are effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018. 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 February 2016, the FASB issued ASU No. 2016-02, “Leases (Topic 842)” which will require organizations that lease assets to recognize on the balance sheet the assets and liabilities~~ for the ~~rights~~three months ended March 31, 2020 and ~~obligations created~~2019.

Risks and Uncertainties

~~Management is currently evaluating~~group of oil producing nations known as OPEC+ to reach an agreement over proposed oil production cuts. Moreover, the ~~new guidance to determine~~uncertainty about 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~~duration of the ~~Effective Date. ASU 2015-14 defers~~COVID-19 pandemic has caused storage constraints in the ~~effective date~~United States resulting from over-supply of produced oil, which has significantly decreased our realized oil prices in 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,~~second quarter of 2020 and potentially beyond. Oil prices are expected to continue to be volatile as a result of these events and the ~~FASB issued additional accounting standards updates to clarify the implementation guidance of ASU 2014-09.~~ongoing COVID-19 outbreak, and as changes in oil inventories, oil demand and economic performance are reported. The Company cannot predict when oil prices will improve and stabilize.

The current pandemic and uncertainty about its length and depth in future periods has caused the realized oil prices the Company has received since February 2020 to be significantly reduced, adversely affecting its operating cash flow and liquidity. Although the Company has reduced its 2020 capital expenditures budget, the lower levels of cash flow may require it to shut-in production that has become uneconomic in addition to shut-ins of production that the Company performed during the second quarter of 2020 (see below).

The COVID-19 pandemic is ~~currently determining~~rapidly evolving, and the ~~impacts~~ultimate impact of ~~the new revenue standard on its contracts.~~this pandemic is highly uncertain and subject to change. The ~~Company is currently completing a detailed analysis~~extent of ~~its revenue streams at the individual contract level to evaluate~~ the impact of the ~~new revenue standard~~COVID-19 pandemic on the Company's operational and financial performance will depend on future developments, including the duration and spread of the pandemic, its severity, the actions to contain the disease or mitigate its impact, related restrictions on travel, and the duration, timing and severity of the impact on domestic and global oil demand.

In response to these developments, the Company has implemented the following operational and financial measures:

Reduced budgeted 2020 capital spending from $80-$85 million to $55-$65 million, or 27% at midpoint;

Deferred its 2020 drilling program;

Implemented cost-reduction measures including negotiations reducing rates for water disposal, chemicals, rentals, and workovers;

Shut in or stored approximately 4,700 BOE per day of production during late-April and all of May 2020, primarily at the Company's Central Eagle Ford Area. These shut-in wells back online during the first week of June.

Entered into additional commodities derivatives in March 2020 to hedge an additional 2,000 Bbls of oil per day at an average swap price of $41.00 per Bbl and 27,500 Mcf of natural gas per day at an average price of $2.36 per Mcf in 2021. The Company's current oil hedge position covers 7,498 Bbls per day for the second quarter of 2020, 7,565 Bbls per day for the second half of 2020, and 7,000 Bbls per day for 2021. The Company's current natural gas hedge position covers 20,000 Mcf per day for the remaining three quarters of 2020, and 27,500 Mcf per day for 2021.

Recent Developments

The Company's present level of indebtedness and the current commodity price environment present challenges to its ability to comply with the covenants in its Credit Facility (see Note 7. Long-Term Debt) over the next twelve months and therefore substantial doubt exists that the Company will be able to continue as a going concern. As of March 31, 2020, the Company had total indebtedness of $522.4 million, including $250.0 million of Senior Notes due 2023 (the “11.25% Senior Notes"), $267.0 million under the Company's Credit Facility and $8.9 million under the Company's building loan. As of July 2, 2020, the Company's Credit Facility is drawn to $285.0 million and is subject to a $60.4 million borrowing-base deficiency due to the terms of the Forbearance Agreement (see below).

The Company did not satisfy the consolidated ~~financial statements. Oil sales~~current ratio covenant under the Credit Facility as of the March 31, 2020 measurement date and did not make the July 1, 2020 interest payment under the 11.25% Senior Notes. Such failures represent ~~approximately~~ 84%events of ~~total revenue,~~default under our revolving credit facility, and the missed interest payment will represent an event of default under the 11.25% Senior Notes if not cured within 30 days. The Company received a forbearance from the lenders under the Credit Facility until July 31, 2020 for the defaults in the consolidated current ratio covenant as of the March 31, 2020 measurement date and the missed interest payment pursuant to the Forbearance Agreement. Despite the forbearance, the defaults under the Credit Facility are continuing, and will continue, absent a waiver or amendment from the Credit Facility lenders.

Forbearance Agreement

On July 2, 2020, the Company entered into a Forbearance Agreement, Fourteenth Amendment, and Borrowing Base Agreement with ~~gas~~Citibank, N.A., as administrative agent and ~~NGL sales comprising~~ the ~~remainder.~~ lenders party thereto (the “Forbearance Agreement”) with respect to the Credit Facility. Pursuant to the Forbearance Agreement, among other things, (i) the lenders under the Credit Facility agreed to refrain from exercising their rights and remedies under the Credit Facility and related loan documents with respect to certain defaults until July 31, 2020, (ii) the borrowing base was redetermined to $225 million from $286 million, (iii) all proceeds of dispositions and terminations or liquidations of swap agreements shall be used to repay the Credit Facility and shall automatically reduce the borrowing base by the amount of the repayment and (iv) certain exceptions to the covenant restriction on investments shall no longer be available.

The rights of the Credit Facility lenders to exercise rights and remedies resulted from the Company's failure to comply with the current ratio with respect to the quarter ended March 31, 2020 and the defaults expected with respect to the quarter ending June 30, 2020 under the current ratio and the leverage ratio covenants, and the default with respect to the failure to make the interest payment due on July 1, 2020, under the 11.25% Senior Notes.

The Forbearance Agreement can be terminated by the lenders upon (i) the occurrence of any default or event of default under the Credit Facility other than those disclosed above, (ii) the failure of the Company to comply with any of the terms and requirements of the Forbearance Agreement, (iii) the breach of any representation or warranty, (iv) the exercise of any rights by other debt holders relating to foreclosure or acceleration (including acceleration of the 11.25% Senior Notes in the event of default) and (v) the commencement of any bankruptcy proceeding with respect to any loan party. Additionally, the Forbearance Agreement can be terminated if the Company fails to deliver a detailed restructuring proposal to the lenders by July 16, 2020. If the Forbearance Agreement terminates and any then-current and ongoing events of default have not been waived or cured, the lenders will be able to accelerate the loans and pursue their rights and remedies.

Borrowing Base Redetermination

As of March 31, 2020, the borrowing base and lender commitments for the Credit Facility were $290 million. However, subsequent to the end of the first quarter of 2020, the borrowing base was lowered to $286 million on June 11, 2020 as part of the Thirteenth Amendment (see Note 7. Long-Term Debt), and the borrowing base was later redetermined to $225 million from $286 million pursuant to the Forbearance Agreement on July 2, 2020, which created a deficiency between the outstanding amount borrowed under the Company's revolving credit facility and the borrowing base. The outstanding balance under the Credit Facility was $285 million as of July 2, 2020 which represents a borrowing deficiency of $60.4 million. The Company is obligated to pay the deficiency within 60 days after July 2, 2020 due to the Credit Facility being in a state of default at the time of the deficiency, as noted below.

Going Concern

The Company has ~~identified~~concluded that these circumstances create substantial doubt regarding its ability to continue as a going concern. However, these consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty and instead have been prepared on a going concern basis, which contemplates the realization of assets and the settlement of liabilities and commitments in the normal course of business.

The Company does not anticipate maintaining compliance with the consolidated current ratio covenant under its Credit Facility over the next twelve months, and is evaluating the available financial alternatives, including obtaining acceptable alternative financing as well as seeking additional waivers, forbearances or amendments to the covenants or other provisions of the Credit Facility to address any existing or future defaults and have engaged financial and legal advisors to assist the Company. If the Company is unable to reach an agreement with its lenders or find acceptable alternative financing, the lenders of the Credit Facility may choose to accelerate repayment, in addition to the $60.4 million due from the current borrowing base deficiency noted above, which in turn may result in an event of default and an acceleration of the 11.25% Senior Notes, which have a $14.1 million interest payment that was due and unpaid on July 1, 2020 (see below). If the Company's lenders or its noteholders accelerate the payment of amounts outstanding under our Credit Facility or the 11.25% Senior Notes, respectively, the Company does not currently have sufficient liquidity to repay such indebtedness and would need additional sources of capital to do so.

The Company cannot provide any assurances that it will be successful in any restructuring of existing debt obligations or obtaining capital sufficient to fund the refinancing of its outstanding indebtedness or to provide sufficient liquidity to meet its operating needs. If the Company is unsuccessful in its efforts to restructure and obtain new financing, it may be necessary for it to seek protection from creditors under Chapter 11 of the U.S. Bankruptcy Code (“Chapter 11”), or an involuntary petition for bankruptcy may be filed against it.

Impairment of Long-Lived Assets

The carrying value of long-lived assets and certain identifiable intangibles are reviewed ~~oil sales contracts~~for impairment whenever events or changes in circumstances indicate that ~~comprised approximately~~ 80%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 ~~revenue through September 30, 2017. Based~~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 ~~current assessments completed~~a region basis. On this basis, certain regions may be impaired because they are not expected to ~~date, we do not expect the adoption~~recover their entire carrying value from future net cash flows. As a result of this ~~standard will have a material impact on~~evaluation, the Company recorded impairment 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 PUD and probable reserves from future net ~~earnings, however, this conclusion is subject to change. The~~cash flows as 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 the process of completing our analysis. The Company’s disclosures surrounding revenue recognition~~cannot assure that they will be ~~more substantial upon adoption. The Company will complete its evaluation during~~developed going forward in light of continued depressed commodity prices and uncertainty regarding 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,~~Company's liquidity situation. If pricing remains depressed, it is reasonably likely that the Company ~~closed on the purchase~~may have to record impairment of ~~an office building with an acquisition price approximating $10 million. The building will be primarily used for the Company’s headquarters and 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~~its oil and gas properties in the ~~Eagle Ford Shale play in DeWitt, Gonzales~~future.

CAREs Act

On March 27, 2020, Congress enacted the Coronavirus Aid, Relief, and ~~Karnes County, Texas~~Economic Security Act (the ~~“Battlecat Acquisition”~~“CARES Act”)~~. 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”) atprovide certain taxpayer relief as a ~~value of approximately $4.8 million. Allocation~~result of the ~~purchase consideration was as follows: $56.3 million to proved reserves; $2.9 million to unproved reserves~~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 ~~$0.6 million to unevaluated acreage~~2020, a five-year carryback period for net operating losses generated after 2017 and ~~other assets. Additionally,~~before 2021, and the ~~Company recorded an asset retirement obligation~~acceleration of ~~approximately $0.2 million, resulting in fair value of net assets acquired of approximately $59.6 million.~~ refundable alternative minimum tax credits. The ~~Company accounted for~~CARES Act did not materially impact 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). TheCompany's 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~~tax rate for the three ~~and nine~~ months ended ~~September 30, 2017~~March 31, 2020.

The Company has applied for, and ~~2016~~has received, funds under the Paycheck Protection Program after the period end in the amount of $2.2 million. The application for these funds requires 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 requires 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 these funds, and the forgiveness of the loan attendant to these funds, 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.

Net Loss per Common Share

The two-class method is utilized to compute earnings per common share as our Class A Participating Preferred Stock (the "Preferred Stock") is 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 is not obligated to absorb Company losses and accordingly is not allocated losses. Net income attributable to common stockholders is allocated between common stock and participating securities based on the ~~historical consolidated financial statements~~weighted average number of ~~the Company adjusted to reflect as if the Battlecat Acquisition~~common shares 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 expensesparticipating securities outstanding 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:~~

period.

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 $6.00Basic earnings per share ~~subject to certain adjustments.~~

~~The borrowing of approximately $24 million on our Senior Secured Credit Facility to finance a portion of~~is computed by dividing 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~~allocated net income (loss) attributable to common stockholders ~~consists~~by the weighted-average number of ~~depreciation, depletion, amortization~~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 consist of warrants, equity compensation awards and ~~accretion calculations, additional interest expense, adjustments~~Preferred Stock. In certain circumstances adjustment to the numerator is also required for changes in income ~~tax (expense) benefit, and dividends on preferred stock issued~~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 ~~complete~~calculate basic earnings per share.

For the ~~acquisitions. The effect on net income (loss) per common share,~~periods presented, there were no differences between the basic and diluted ~~is a result~~weighted average common shares. The following securities could potentially dilute earnings per share in the future, but were excluded from the computation of ~~adjustments~~diluted net loss per share, as their effect would have been antidilutive:



	Three Months Ended March 31,
	2020	2019
Preferred stock	16,725,467	15,301,157
Warrants	760,000	760,000
Stock appreciation rights	1,010,000	1,010,000
Restricted stock units	1,925,366	834,397

Recent Accounting Pronouncements

Reference Rate Reform. In March 2020, the FASB issued ASU 2020-04, Reference Rate Reform (Topic 848) (“ASU 2020-04”). ASU 2020-04 provides optional expedients and exceptions for applying GAAP to ~~Lonestar revenue~~contracts, hedging relationships, and ~~net income (loss) for revenue~~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 are effective beginning on March 12, 2020, and ~~expenses for acquired properties as well as~~an entity may elect to apply the ~~pro forma adjustments to arrive at pro forma Lonestar net income (loss) attributable to common stockholders.~~

~~4. Restricted Certificate of Deposit~~

amendments prospectively through December 31, 2022. The Company is ~~required~~currently evaluating the impact this guidance may have on its consolidated financial statements and related footnote disclosures.

Income Taxes. In December 2019, the FASB issued ASU 2019-12, Income Taxes (Topic 740) – Simplifying the Accounting for Income Taxes (“ASU 2019-12”). The objective of ASU 2019-12 is to ~~maintain a certificate of deposit (“CD”) issued~~simplify the accounting for income taxes by ~~a municipality in Montana, in which~~removing certain ~~of our drilling operations are located. This CD is pledged as collateral for a letter of credit issued by the Company’s bank~~exceptions to the ~~municipality.~~general principles in Topic 740 and to provide more consistent application to improve the comparability of financial statements. The ~~CD has a maturity date of March 8, 2018,~~amendments in this ASU are effective for fiscal years beginning after December 15, 2020, and ~~bears an interest rate of 0.25%. As this CD~~early adoption 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~~

permitted. The Company ~~has implemented a strategy to reduce~~is currently evaluating the ~~effects of volatility of oil~~impact this guidance may have on its consolidated financial statements and ~~natural gas prices on~~related footnote disclosures.

Note 2. Acquisitions and Divestitures

Pirate Divestiture

In March 2019, Lonestar completed the ~~Company’s results of operations by securing fixed price contracts for a portion~~divestiture of its ~~expected sales volumes.~~

~~Inherent~~Pirate assets in ~~the Company’s fixed price contracts, are certain business risks, including market risk and credit risk. Market risk is the risk that the~~Wilson County for an adjusted cash purchase 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~~$11.5 million, after closing adjustments, to a ~~contract.~~private third-party. The assets were comprised of 3,400 net undeveloped acres, six producing wells, held seven proved undeveloped locations as of the closing date, and were producing approximately 200 BOE/d. The Company ~~does not currently require cash collateral from any~~recognized a loss of ~~its counterparties nor does its counterparties require cash collateral from~~$33.5 million during the ~~Company. At September 30, 2017,~~first quarter of 2019 in conjunction with the ~~Company had no open physical delivery obligations.~~

~~The Company~~sale of the assets.

Note 3. 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, 2020, the Company had no 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, 2020:



	Contract			Volumes	Weighted
Commodity	Type	Period	Range ⁽¹⁾	(Bbls/Mcf per day)	Average Price
Oil - WTI	Swaps	Apr - June 2020	$48.90 - $65.56	7,498	$	56.50
Oil - WTI	Swaps	July - Dec 2020	51.60 - 65.56	7,565	57.38
Oil - WTI	Swaps	Jan - Dec 2021	40.95 - 56.50	7,000	50.40
Natural Gas - Henry Hub	Swaps	Apr - Dec 2020	2.38 - 2.80	20,000	2.55
Natural Gas - Henry Hub	Swaps	Jan - Dec 2021	2.32 - 2.39	27,500	2.36

(1) Ranges presented for fixed-price swaps and basis swaps represent the lowest and highest fixed prices of all open contracts 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 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 for the remainder of 2017 and 1,825,000 MMBtu or 5,000 MMBtu per day 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 of operations in gain or loss on derivative financial instruments.

period presented.

As of ~~September 30, 2017 and December~~March 31, ~~2016,~~2020, 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 4. 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, 2020 and 2019:



In thousands	Three Months Ended March 31,
In thousands	2020		2019
Oil	$	29,990	$	33,584
NGLs	2,599		3,393
Natural gas	4,420		3,764
Total revenues	$	37,009	$	40,741

As of March 31, 2020 and December 31, 2019 the accounts receivable balance representing amounts due or billable under the terms of contracts with purchasers was $10.2 million and $16.0 million, respectively.

Note 5. 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. 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, 2020 and December 31, ~~2016,~~2019, 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, 2020
Assets
Derivative financial instruments	$	—		$	99,859		$	—		$	99,859
Liabilities:
Derivative financial instruments	—			(3,397		)	—			(3,397		)
Warrant	—			—			(1		)	(1		)
Stock-based compensation	(77		)	—			(27		)	(104		)
Total	$	(77	)	$	96,462		$	(28	)	$	96,357

December 31, 2019
Assets:
Derivative financial instruments	$	—		$	6,849		$	—		$	6,849
Liabilities:
Derivative financial instruments	—			(10,462		)	—			(10,462		)
Warrant	—			—			(364		)	(364		)
Stock-based compensation	(1,792		)	—			(573		)	(2,365		)
Total	$	(1,792	)	$	(3,613	)	$	(937	)	$	(6,342	)

Level 3 ~~Gains and Losses~~

Fair Value Measurements

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

March 31, 2020:

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~~



In thousands	Warrant			Stock-Based Compensation			Total
Balance as of December 31, 2019	$	(364	)	$	(573	)	$	(937	)
Unrealized gains	363			546			909
Balance as of March 31, 2020	$	(1	)	$	(27	)	$	(28	)

Other 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 derivative assets and liabilities with the same counterparty, which positions are all offset to a single derivative asset or liability in the consolidated balance sheets, including the deferred premiums associated with its hedge positions.

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~~the Credit Facility (as defined in Note 7. below) 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.~~Company. The fair value of the ~~8.750%~~11.25% Senior Notes (as defined in Note 98. below) ~~approximates $148~~was approximately $64.1 million as of ~~September 30, 2017,~~March 31, 2020 and ~~the notes are~~is 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.

Note 6. 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, 2020		December 31, 2019
Accrued interest – 11.25% Senior Notes	$	7,031	$	14,063
Accrued well costs	12,387		8,932
Bonus payable	609		2,353
Other	3,022		1,557
Total accrued liabilities	$	23,049	$	26,905

Note 7. 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, 2020			December 31, 2019
Senior Secured Credit Facility	$	267,000		$	247,000
11.25% Senior Notes due 2023	250,000			250,000
Mortgage debt	8,877			8,931
Other	271			271
Total long-term debt	526,148			506,202
Unamortized discount	(3,094		)	(3,375		)
Unamortized debt issuance costs	(647		)	(759		)
Total net of debt issuance costs	522,407			502,068
Less current obligations	(513,259		)	(247,000		)
Long-term debt	$	9,148		$	255,068

Senior Secured Credit Facility

In July ~~28,~~ 2015, ~~LRAI closed on~~through its subsidiary, Lonestar Resources America, Inc. ("LRAI"), the Company entered into a $500 million Senior Secured Credit ~~Agreement~~Facility with Citibank, N.A., as administrative agent, and other lenders party thereto (as amended, supplemented or modified from time to time, the “Credit ~~Agreement”) for a $500,000,000 Senior Secured Credit Facility (the “Senior Secured Credit~~ Facility”), which ~~had a borrowing base of $180,000,000 as of December 31, 2015 and~~has a maturity date of ~~October 16, 2018. Effective~~November 15, 2023. As of March 31, 2020, $267.0 million was borrowed under the Credit Facility, and the weighted average interest rate on borrowings under the Credit Facility for the quarter was 5.30%. Borrowing availability was $22.6 million as of ~~May 19, 2016, the borrowing base was reduced from $180,000,000 to $120,000,000. Effective as~~March 31, 2020, which reflects $0.4 million of ~~November 23, 2016, the borrowing base was reduced from $120,000,000 to $112,000,000. Effective as~~letters of ~~June 15, 2017, the borrowing base was increased from $112,000,000 to $160,000,000.~~

credit outstanding.

The ~~Senior Secured~~ Credit Facility may be used for loans and, subject to a ~~$2,500,000~~$2.5 million sub-limit, letters of ~~credit. The Senior Secured Credit Facility~~credit, and provides for a commitment fee of 0.375% to 0.5% (0.5% following the Thirteenth Amendment (as defined below)) based on the unused portion of the borrowing base under the ~~Senior Secured~~ Credit Facility.

As of March 31, 2020, the borrowing base and lender commitments for the Credit Facility was $290 million. The borrowing base was lowered to $286 million on June 11, 2020 as part of the Thirteenth Amendment. The borrowing base was further lowered to $225 million from $286 million pursuant to the Forbearance Agreement on July 2, 2020, creating a deficiency between the outstanding amount borrowed under our revolving credit facility and the borrowing base. The outstanding balance under our credit facility was $285 million as of July 2, 2020 which represents a borrowing deficiency of $60.4 million. We are obligated to pay the deficiency within 60 days after July 2, 2020, due to the Credit Facility's status of default (see below).

Borrowings under the ~~Senior Secured~~ Credit Facility, at ~~LRAI’s~~the Company'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~~LIBOR1 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%~~1.0% to ~~2.50%~~2.0% (2.0% to 3.5% following the Thirteenth Amendment) for ABR loans and from ~~2.50%~~2.0% to ~~3.50%~~3.0% (3.0% to 4.5% following the Thirteenth Amendment) for adjusted LIBO rate ~~loans (5.17% at September 30, 2017).~~

~~The Senior Secured~~loans.

As the Credit Facility ~~requires LRAI to maintain certain financial ratios and limits~~is in a state of default, 2.0% incremental default interest would typically be due but is currently not being charged as part of the ~~amount~~terms of ~~indebtedness LRAI can incur.~~ the Forbearance Agreement (see below).

Subject to certain permitted liens, ~~LRAI’s~~the Company's obligations under the ~~Senior Secured~~ Credit Facility ~~have been~~are required to be 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.~~

subsidiaries (currently 100% following the Thirteenth Amendment).

~~In connection with the Senior Secured~~

The Credit Facility ~~LRAI and~~contains 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~~financial performance covenants, 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~~Facility, including the ~~end~~following:

A maximum debt to EBITDAX ratio of ~~each fiscal quarter using the results~~4.0 to 1.0, and

A current ratio 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~~not less than 1.0 to the EBITDAX for such fiscal quarter, multiplied by four, (y) at the end of the fiscal quarter ending December 31, 2017 using an amount equal to the EBITDAX for the two fiscal quarter period ended on such date, multiplied by two and (z) at the end of the fiscal quarter ending March 31, 2018 using an amount equal to the EBITDAX for the three fiscal quarter period ended on such date, multiplied by four-thirds, (iii) permit LRAI to declare and pay dividends to the1.0.

The Company ~~equal to the amount of any cash dividends declared and payable~~also was not in ~~accordance~~compliance with the terms of the ~~Company’s Certificate~~Credit Facility as of ~~Designations~~December 31, 2019 because it did not satisfy the consolidated current ratio at those times and the audit report prepared by its auditors with respect to the financial statements in the 2019 Form 10-K included an explanatory paragraph expressing uncertainty as to the Company's ability to continue as a "going concern." The lenders waived the current ratio default with respect to December 31, 2019. The Company received a forbearance until July 31, 2020 for the defaults in the consolidated current ratio covenant as of ~~Convertible Participating Preferred Stock, Series A-1,~~the March 31, 2020 measurement date and ~~Certificate of Designations of Convertible Participating Preferred Stock, Series A-2, subject~~the missed interest payment under the 11.25% Senior Notes pursuant to ~~certain specified~~the Forbearance Agreement. Despite the forbearance, the defaults under the Credit Facility are continuing, and will continue, absent a waiver from the lenders. The Company was not in compliance with the terms ~~and conditions and (iv) amend certain other provisions~~ of the Credit Facility as of May 15, 2020, because it did not timely deliver its financial statements with respect to the fiscal quarter ended March 31, 2020. Such failure represented a default under the Credit Facility which the lenders waived pursuant to the Thirteenth Amendment. As noted above, the borrowing base was redetermined to $225 million from $286 million pursuant to the Forbearance Agreement on July 2, 2020, which created a deficiency between the outstanding amount borrowed under our revolving credit facility and the borrowing base. The outstanding balance under the Company's Credit Facility was $285 million as ~~more specifically set forth~~of July 2, 2020 which represents a borrowing deficiency of $60 million. The Company is obligated to pay the deficiency within 60 days after July 2, 2020.

Waiver and Eleventh Amendment

Effective April 7, 2020, the Company entered into the Waiver and Eleventh Amendment (the "Waiver") to waive events of default arising from its failure to comply with the consolidated current ratio as of December 31, 2019, to timely provide audited financial statements and to provide financial statements that are not subject to any “going concern” or like qualification or exception for the fiscal year ended December 31, 2019. As there was no guarantee that the Company's lenders would agree to waive events of default or potential events of default in the ~~Sixth Amendment.~~

Asfuture, the amounts outstanding under the Credit Facility as of ~~September 30, 2017 and~~ December 31, ~~2016 (giving effect~~2019 were classified as current in the accompanying 2019 Condensed Consolidated Balance Sheet.

Twelfth Amendment

Effective May 8, 2020, the Company entered into the Twelfth Amendment to Credit Agreement (the “ Twelfth Amendment”), to allow the Company to accept proceeds of up to $2.2 million from an unsecured loan applied for under the Coronavirus Aid, Relief and Economic Security Act (as discussed further in Note 1).

Waiver and Thirteenth Amendment

Effective June 11, 2020, the Company entered into the Waiver and Thirteenth Amendment to Credit Agreement (the "Thirteenth Amendment") which, among other things, (i) waived any default or event of default arising from its failure to provide timely quarterly financial statements for the three months ended March 31, 2020; (ii) redetermined the borrowing base to $286 million from $290 million; (iii) set the next borrowing base redetermination to be on or around July 1, 2020 (and in any event, no later than July 31, 2020), (iv) amended the borrowing base utilization grid used in the applicable margin, as noted above and (v) until the July 1, 2020 redetermination, restricted the Company and its subsidiaries’ ability to incur debt with respect to, among other items, capital leases and permitted senior debt, grant liens to secure other obligations, pay dividends on LRAI’s preferred stock and make certain investments.

As there is no guarantee that the Company's lenders will agree to waive events of default or potential events of default in the future, the amounts outstanding under the Credit Facility as of March 31, 2020 were classified as current in the accompanying Condensed Consolidated Balance Sheet.

Forbearance Agreement and Fourteenth Amendment

On July 2, 2020, the Company entered into a Forbearance Agreement, Fourteenth Amendment, and Borrowing Base Agreement with Citibank, N.A., as administrative agent and the lenders party thereto (the “Forbearance Agreement”) with respect to the ~~amended covenant ratio discussed above), LRAI was in compliance with all covenants including all financial ratios~~Credit Facility. Pursuant to the Forbearance Agreement, among other things, (i) the lenders under the ~~Senior Secured~~ Credit ~~Facility. As of September 30, 2017~~Facility agree to refrain from exercising their rights and ~~December 31, 2016, approximately $128,079,000 and $43,500,000 was borrowed, respectively,~~remedies under the Credit Facility and related loan documents with respect to certain defaults until July 31, 2020, (ii) the borrowing base was redetermined to $225 million from $286 million, (iii) all proceeds of dispositions and terminations or liquidations of swap agreements shall be used to repay the Credit Facility and shall automatically reduce the borrowing base by the amount of the repayment and (iv) certain exceptions to the covenant restriction on investments shall no longer be available.

The rights of the lenders to exercise rights and remedies resulted from our failure to comply with the current ratio with respect to the quarter ended March 31, 2020 and the defaults expected with respect to the quarter ending June 30, 2020, under the current ratio and the leverage ratio covenants, and the default with respect to the failure to make the interest payment due on July 1, 2020, under the 11.25% Senior ~~Secured~~Notes.

The Forbearance Agreement can be terminated by the lenders upon (i) the occurrence of any default or event of default under the Credit ~~Facility. Borrowing availability was approximately $31,400,000 at September 30, 2017.~~

~~8.750%~~Facility other than those disclosed, (ii) the failure of the Company to comply with any of the terms and requirements of the Forbearance Agreement, (iii) the breach of any representation or warranty, (iv) the exercise of any rights by other debt holders relating to foreclosure or acceleration and (v) the commencement of any bankruptcy proceeding with respect to any loan party. Additionally, the Forbearance Agreement can be terminated if the Company fails to deliver a detailed restructuring proposal to the lenders by July 16, 2020. If the Forbearance Agreement terminates and any then-current and ongoing events of default have not been waived or cured, the lenders will be able to accelerate the loans and pursue their rights and remedies.

11.25% Senior Notes

~~On April 4, 2014, LRAI~~

In January 2018, the Company issued ~~at par $220,000,000~~$250 million of ~~8.750%~~11.25% Senior ~~Unsecured~~ Notes ~~due April 15, 2019 (the “8.750% Senior Notes”)~~ to ~~U.S. based~~U.S.-based institutional investors. The ~~Company is in active discussions~~net proceeds of $244.4 million were used to ~~refinance~~fully retire the ~~8.750%~~Company’s 8.75% Senior Notes, ~~due April 2019,~~ which ~~will also provide~~included principal, interest and a prepayment premium of approximately $162 million. The remaining net proceeds were used to ~~extend~~reduce borrowings under the ~~term~~Credit Facility.

The 11.25% Senior Notes mature on January 1, 2023, and bear interest at the rate of 11.25% per year, payable on January 1 and July of each year. At any time prior to January 1, 2021, the Company may, on any one or more occasions, redeem up to 35% of the ~~Senior Secured Credit Facility. During 2016, LRAI repurchased approximately $68.2 million in~~ aggregate principal amount of the ~~8.750%~~11.25% Senior Notes ~~leaving~~with an amount of cash not greater than the net cash proceeds of certain equity offerings at a ~~remaining balance~~redemption price equal to 111.25% of ~~approximately $151.8 million.~~

the principal amounts redeemed, plus accrued and unpaid interest, provided that at least 65% of the aggregate principal amount of 11.25% Senior Notes originally issued remains outstanding immediately after such redemption and the redemption occurs within 180 days of the closing date of such equity offering.

At any time prior to January 1, 2021, the Company may, on any one or more occasions, redeem all or a part of the 11.25% Senior Notes at a redemption price equal to 100% of the principal amount redeemed, plus a “make-whole” premium as of, and accrued and unpaid interest.

On orand after ~~April 15, 2016, LRAI~~January 1, 2021, the Company may redeem the ~~8.750%~~11.25% Senior Notes, in whole or in part, ~~at the redemption prices (expressed as percentages of the principal amount) set forth in the following table~~ plus accrued and unpaid interest, ~~if any,~~at the following redemption prices: 108.438% after January 1, 2021; 105.625% after January 1, 2022; and 100% after July 1, 2022.

The Company did not make its interest payment on the ~~8.750%~~11.25% Senior Notes ~~redeemed,~~that was due on July 1, 2020 of approximately $14.1 million. The Company has 30 days to cure the ~~applicable date of redemption, if redeemed during~~default before 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%~~11.25% Senior Notes ~~will have~~or the ~~right~~trustee may be able to ~~require LRAI to repurchase all or any part~~accelerate payment. The missed interest payment is a current event of ~~their 8.750% Senior Notes for cash at a price equal to 101% of~~default under the ~~aggregate principal amount of~~Credit Facility. The Company has entered into 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 covenantsForbearance Agreement which provides that, among other things, ~~limit~~ the lenders under the Credit Facility have agreed to forbear the Company’s default of the interest payment until July 31, 2020. However, the default under the Credit Facility has not been waived and still exists, and the Forbearance Agreement can be terminated if the Company fails to deliver a detailed restructuring proposal to the lenders by July 16, 2020. Accordingly, the amounts outstanding under the 11.25% Senior Notes as of March 31, 2020 were classified as current in the accompanying Condensed Consolidated Balance Sheet.

The indenture contains certain restrictions on the Company’s ability ~~of LRAI and its subsidiaries to:~~to incur ~~indebtedness;~~additional debt, pay dividends oron the Company’s common stock, make ~~other distributions~~investments, create liens on ~~stock; purchase or redeem stock or subordinated indebtedness; make investments; create liens; enter into~~the Company’s assets, engage in transactions with ~~affiliates;~~affiliates, transfer or sell ~~assets; refinance certain indebtedness; and~~assets, consolidate or merge, ~~with~~ or ~~into other companies or transfer~~sell substantially all of ~~LRAI’s~~the Company’s assets.

As The indenture also contains cross-default provisions for defaults of ~~September 30, 2017 and December 31, 2016, LRAI was in compliance with all covenants~~the Company's other debt instruments, including ~~all financial ratios regarding~~ the ~~8.750% Senior Notes.~~

~~Debt Issuance Costs~~

Credit Facility, caused by payment default or events which cause the acceleration of repayment prior to the stated maturity of such instrument.

The Company ~~capitalizes certain direct costs associated with~~cannot provide any assurances that it will be successful in restructuring existing debt obligations or in obtaining capital sufficient to fund the ~~issuance~~refinancing of ~~long-term debt~~its outstanding indebtedness or to provide sufficient liquidity to meet its operating needs. If the Company is unsuccessful in its efforts to restructure and ~~amortizes such costs over~~obtain new financing, it may be necessary for the ~~lives~~Company to seek protection from creditors under Chapter 11 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 entered into a Securities Purchase Agreement with Juneau Energy, LLC, as initial purchaser~~U.S. Bankruptcy Code (“~~Juneau”~~Chapter 11”), ~~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~~or an involuntary petition for the purchasers, relating to the issuance and sale of (i) up to $49,900,000 aggregate principal amount of LRAI’s 12% senior secured second lien notes due 2021 (the “Second Lien Notes”) and (ii) five-year warrants to purchase up to an aggregate 998,000 shares of the Company’s Class A 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~~bankruptcy may be ~~entitled to preference over~~filed against 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.

Company.

~~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, par value $0.001 per share (the “Series A-1 Preferred Stock”), and Series A-2 Convertible Participating Preferred Stock, par value $0.001 per share (the “Series A-2 Preferred Stock” and, together with the Series A-1 Preferred Stock, the “Series A Preferred Stock” and, collectively with the Series A-1 Preferred Stock and the Series B Preferred Stock, the “Preferred Stock”), 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. 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

Note 8. Stockholders’ Equity

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, the Company entered into a registration rights agreement with Chambers (the “Chambers RRA”). Under the Chambers RRA, the Company has agreed to provide to Chambers certain customary demand and piggyback registration rights relating to Chambers’ ownership of Company stock. The Chambers RRA contains customary terms and conditions, including certain customary indemnification obligations.

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.

Dividends

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 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 Stock 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 AA-1 Preferred Stock at a per share price equal to $975 or (ii) by increasing Stated Value, in lieu of ~~cash.~~cash (collectively, the “PIK Option”). After the 12 PIK Quarters (one of which remain as of March 31, 2020), 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%~~5% per annum for the next succeeding dividend period and then an additional ~~1.0%~~1% for each successive dividend period, up to a maximum Dividend Rate of ~~20.0%~~20% per annum, until the Company pays dividends at such increased rate fully in cash for two consecutive quarters. ~~Separately, if~~

Starting with the ~~Stockholder Approval has not been obtained by December 15,~~third quarter of 2017 and through the ~~Dividend Rate for Series A-2 Preferred Stock will automatically increase by 5% per annum~~fourth quarter of 2019, the Company elected the PIK Option 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~~dividend payment, which resulted in ~~cash, unless automatically converted as described above. However,~~ the ~~Company, at its option, may instead elect to exchange each share~~issuance 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~~20,328 additional shares of Series A-1 Preferred ~~Stock and 2,684,632~~Stock. During the first quarter of 2020, the Company also elected the PIK Option, which resulted in the issuance of 2,257 additional shares of Series BA-1 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.

Note 9. 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~~

Lonestar grants awards of restricted stock units ~~(“RSUs”~~("RSUs") ~~covering 612,000 shares~~ to ~~certain~~employees and directors as part of its ~~employees. In August 2017, 100,000 units were issued~~long-term compensation program. For the three months ended March 31, 2020 and 2019, the Company recognized $(1.3) million and $0.7 million, respectively, of stock-based compensation (benefit) expense for RSUs. The liability for RSUs on the accompanying consolidated balance sheet as of March 31, 2020 was $0.1 million.

As of March 31, 2020, there was $0.4 million of unrecognized compensation expense related to ~~the Company’s chairman of the board of directors. The awards vest~~non-vested RSU grants. This unrecognized compensation cost is expected to be recognized over a ~~three-year~~weighted-average 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.~~1.7 years. The ~~Company determines the~~ fair value of ~~granted RSU’s based on~~RSU grants that vested during the ~~market price~~three months ended March 31, 2020 and 2019 totaled 0.5 million and 0.9 million, respectively.

A summary of the ~~Class A voting common stock~~status of the ~~Company on~~Company's non-vested RSU grants issued, and the ~~date of grant. RSUs will be paid in Class A voting common stock or cash, at~~changes during the ~~Company’s option, after the vesting of the applicable RSU. Compensation expense for granted RSUs~~three months ended March 31, 2020 is ~~recognized over the vesting period.~~

presented below:

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		—		$	—		—

								Shares		Weighted Average Fair Value per Share
Non-vested RSUs at December 31, 2019								1,849,676		$	4.04
Granted		712,000			6.00		3.0	—		—
Vested		—			—		—	(692,050	)	0.69
Forfeited		(10,000	)		4.10		2.8	(24,200	)	—
Outstanding non-vested RSUs at September 30, 2017		702,000		$	3.50		2.5
Non-vested RSUs at March 31, 2020								1,133,426		$	3.62

Stock Appreciation Rights

In ~~February 2017,~~ the ~~Company~~past, Lonestar has granted awards of stock appreciation rights (“SARs”) ~~covering 700,000 shares~~ to ~~certain~~employees and directors as part 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~~

long-term compensation program. For the three months ended March 31, 2020 and ~~nine month periods ended September 30, 2017,~~2019, the Company ~~recorded~~recognized $(0.5) million and $0.2 million, respectively, of stock-based compensation ~~expenses~~(benefit) expense for SARs. The liability for SARs on the accompanying unaudited consolidated balance sheet as of ~~approximately $346,000 and $985,000, respectively,~~March 31, 2020 was not material.

As of March 31, 2020, the total compensation cost to be recognized in future periods related to ~~stock options, restricted stock units and stock appreciation rights. As of September 30, 2017, the total unrecognized stock-based compensation~~non-vested SAR grants was not material. The cost ~~was approximately $3,786,000, which will~~is expected to be recognized over ~~the~~a weighted-average 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~~1.0 year.

The following is ~~computed on the basis~~a summary 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.~~

Company's SAR activity:

~~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



	Shares	Weighted Average Exercise Price Per Share		Weighted Average Remaining Contractual Term (in years)
Outstanding at December 31, 2019	1,010,000	$	6.30	2.5
SARs vested and exercisable at December 31, 2019	606,250	6.65		2.4
Granted	—	—		—
Exercised	—	—		—
Expired/forfeited	—	—		—
Outstanding at March 31, 2020	1,010,000	$	6.30	2.3
SARs vested and exercisable at March 31, 2020	805,000	$	6.79	2.1

~~13.~~

Note 10. 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 shares of the Company’s Class A voting common stock at a price equal to $5.00 per share (the “Warrants”). During 2016, LRAI issued $25 million in aggregate principal amount of Second Lien Notes and the Company issued Warrants to purchase 500,000 shares of its Class A voting common stock to Juneau. In December 2016, LRAI repaid to Juneau $21 million principal of the Second Lien Notes with proceeds from the 2016 Common Stock Offering.

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

~~EF REALISATION~~

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

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

~~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.

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)~~Company 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~~$0.5 million and ~~$78,000~~$0.3 million for the three months ended March 31, 2020 and 2019, respectively.

In February 2019, the Company purchased a property adjacent to its corporate office for future expansion 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 Company's directors. The Company understands that the seller may use some of the proceeds of the sale to satisfy such outstanding indebtedness, though the Company has no interest or influence over any particular outcome.

Note 11. Commitments and Contingencies

Lonestar has one drilling rig under contract that is currently operating, which provides for a drilling rate of $19.0 thousand per day and expires on September ~~30, 2017~~7, 2020. Should the Company terminate the contract early, the early termination fee totals $15.0 thousand per day times the remaining number of days left on the contract after the termination date.

From time to time, Lonestar is subject to legal proceedings and ~~2016, respectively,~~claims that arise in the ordinary course of business. Like other crude oil and gas producers and marketers, the Company's operations are subject to extensive and rapidly changing federal and state environmental, health and safety, and other laws and regulations governing air emissions, wastewater discharges and solid and hazardous waste management activities. The Company is not aware of any pending or overtly threatened legal action against it that could have a material impact on its business.

Gonzales County AMI

In February 2020, the Company announced that it had entered into a Joint Development Agreement (the "JDA") in Gonzales County with one of the largest producers in the Eagle Ford which encompass an Area of Mutual Interest (the "AMI") totaling approximately ~~$664,000~~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.

In June, the Company began flowback operations on the Hawkeye #14H, Hawkeye #15H, and ~~$465,000~~Hawkeye #16H, which were the first wells completed in the AMI. The Company's JDA partner did not participate in these wells, and on June 29, 2020 the Company completed a sale of 40% of the working interest in these wells to a third party for $9.1 million. After the ~~nine months ended September 30, 2017 and 2016, respectively.~~

sale, Lonestar has a 50% WI / 37.5% NRI in these wells.

~~14.~~

Note 12. Subsequent Events

In preparing the consolidated financial statements, 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 ofPIK Dividend

On June 25, 2020, the Company ~~(the “Series B Certificate of Designations”), all of the outstanding shares of the Company’s Series B Convertible Preferred Stock (the “Series B Preferred Stock”) were converted (the “Series B Conversion”) on~~approved a ~~one-to-one basis into shares of the Company’s Class A voting common stock. The Series B Preferred Stock was originally issued~~dividend with respect 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 were issued (the “Conversion Shares~~”), and immediately following such conversion, none of 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”), all of the outstanding shares of 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 of~~ the Company’s Series A-1 ~~Convertible~~Preferred Stock. Chambers, as the holder of A-1 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~~ of ~~Series A-1 Convertible Preferred Stock were issued, and immediately following such conversion, none of Series A-2 Preferred Stock remained outstanding and~~June 25, 2020, received an aggregate of ~~82,120 Series~~2,308 additional shares of A-1 Preferred Stock ~~were issued~~as a dividend for its A-1 Preferred Stock on June 30, 2020.

CIC Plan

On June 29, 2020, the Company entered into Eligibility Notification Letters (the “Eligibility Notification Letters”) with each of our named executive officers, including Frank D. Bracken III, our chief executive officer and ~~outstanding.~~

Barry D. Schneider, our chief operating officer, in connection with the Lonestar Resources US Inc. Change in Control Severance Plan (the “CIC Plan”) that was adopted by our board of directors. Under the Plan and the Eligibility Notification Letters, eligible participants will be entitled to severance payments and benefits in the event their employment is terminated by us without cause or they resign for good reason, in either case within two years following or two and one-half months prior to a change in control of the Company, subject to the participant’s execution and non-revocation of a release of claims in favor of the Company.

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

The following discussion and analysis should be read in conjunction with our Unaudited Condensed Consolidated Financial Statements and Notes thereto 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, 2019

~~Overview~~

~~We are~~ (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.

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~~South Texas.

Market Developments and Response to Commodity Price Declines

The COVID-19 coronavirus ("COVID-19") pandemic has resulted in a severe worldwide economic downturn, significantly disrupting the demand for oil throughout the world, and has created significant volatility, uncertainty and turmoil in the oil and gas industry. The decrease in demand for oil combined with the oil supply increase attributable to the battle for market share among the Organization of the Petroleum Exporting Countries ("OPEC"), Russia and other oil producing nations, resulted in oil prices declining significantly beginning in late February 2020. During this time NYMEX oil prices declined from averages in the mid-$50s per Bbl range in January and February 2020, to an average of approximately $30 per Bbl in March. NYMEX oil prices continued to decline in April 2020 to an average of $17 per Bbl in response to uncertainty about the duration of the COVID-19 pandemic and storage constraints resulting from over-supply of produced oil, before recovering to the upper-$30s per Bbl by late June after the implementation of production cuts by OPEC, significant production cuts by domestic operators, and an easement of storage capacity concerns.

The length of this demand disruption is unknown, and there is significant uncertainty regarding the long-term impact to global oil demand, which will ultimately depend on various factors and consequences beyond our control, such as the duration and scope of the pandemic, the length and severity of the worldwide economic downturn, additional actions by businesses and governments in response to both the pandemic and the decrease in oil prices, the speed and effectiveness of responses to combat the virus, and the time necessary to equalize oil supply and demand to restore oil pricing.

In response to these developments, we have ~~accumulated~~implemented the following operational and financial measures:

Reduced budgeted 2020 capital spending from $80-$85 million to $55-$65 million, or 27% at midpoint;

Deferred our 2020 drilling program;

Implemented cost-reduction measures including negotiating reduced rates for water disposal, chemicals, rentals, and workovers;

Shut in or stored approximately ~~72,244 gross (57,172 net) acres~~4,700 BOE per day of production during late-April and all of May 2020, primarily at our oil-rich fields in ~~what~~our Central Eagle Ford Area. When the Company brought these shut-in wells back online during the first week of June, they came on stronger than before, producing an additional 500 BOE per day across all wells.

Entered into additional commodities derivatives in March 2020 to hedge an additional 2,000 Bbls of oil per day at an average swap price of $41.00 per Bbl and 27,500 Mcf of natural gas per day at an average price of $2.36 per Mcf in 2021. Our current oil hedge position covers 7,498 Bbls per day for the second quarter of 2020, 7,565 Bbls per day for the second half of 2020, and 7,000 Bbls per day for 2021. Our current natural gas hedge position covers 20,000 Mcf per day for the remaining three quarters of 2020, and 27,500 Mcf per day for 2021.

We continue to assess the global impacts of the COVID-19 pandemic and expect to continue to modify our plans as more clarity around the full economic impact of COVID-19 becomes available. See Risk Factors for further discussion of the adverse impacts of the COVID-19 pandemic on our business.

Recent Developments

Our present level of indebtedness and the current commodity price environment present challenges to our ability to comply with the covenants in our revolving credit facility over the next twelve months and therefore substantial doubt exists that we ~~believe~~will be able to becontinue as a going concern. As of March 31, 2020, we had total indebtedness of $522.4 million, including $250.0 million of Senior Notes due 2023 (the "11.25% Senior Notes”), $267.0 million under our Credit Facility (as defined below) and $8.9 million under our building loan. At July 2, 2020, we had $285 million drawn on the ~~formation’s crude oil~~Credit Facility and ~~condensate windows,~~have a $60.4 million borrowing base deficiency due to the terms of the Forbearance Agreement (as defined below), which redetermined our borrowing base at $225 million.

We did not satisfy the consolidated current ratio covenant under our Credit Facility as of ~~September~~the March 31, 2020 and December 31, 2019 measurement dates and we defaulted on the July 1, 2020 interest payment under the 11.25% Senior Notes. Such failures represent events of default under our Credit Facility, and the missed interest payment will represent an event of default under the 11.25% Senior Notes if not cured in 30 ~~2017. We operate in one industry segment, which is~~days. In addition, the ~~exploration, development and production of oil, NGLs and natural gas. Our current operational activities and consolidated revenues are generated from markets exclusively~~audit report prepared by our auditors with respect to the financial statements included in the ~~United States, and,~~Company's Annual Report on Form 10-K for the year ended December 31, 2019 includes an explanatory paragraph expressing uncertainty as to our ability to continue as a “going concern.” This, in addition to not providing timely audited financial statements, represented an additional default under the Credit Facility. As a result, the outstanding amount of borrowings under the Credit Facility as of ~~September 30, 2017,~~March 31, 2020 and December 31, 2019 have been classified as current in the accompanying consolidated balance sheets because we ~~had no long lived assets located outside~~do not anticipate maintaining compliance with the ~~United States.~~

~~Third Quarter 2017 Operational Summary~~

~~During~~consolidated current ratio over the ~~third quarter~~next twelve months.

We entered into the Waiver (as defined below) on April 7, 2020, with certain lenders and Citibank, N.A., as administrative bank, to waive the events of ~~2017,~~default relating to our failure to comply with the ~~Company reported production~~current ratio covenant as of ~~7,662 Boe/d, a 36% sequential increase from~~December 31, 2019, to provide timely audited financial statements and to provide audited financial statements that are not subject to any “going concern” or like qualification or exception for the ~~5,635 Boe/d reported~~fiscal year ended December 31, 2019. We entered into the Thirteenth Amendment on June 11, 2020 with the lenders to waive any default and event of default relating to our failure to timely deliver the quarterly financial statements for the three months ended ~~June 30, 2017.~~March 31, 2020. Although we have entered into these waivers, there is no guarantee that our lenders will agree to waive events of default or potential events of default in the future. Our failure to meet the current ratio in the Credit Facility as of March 31, 2020, is an event of default under the Credit Facility. The Company received a forbearance until July 31, 2020 for the default in the consolidated current ratio covenant as of the March 31, 2020 measurement date and the default for the missed interest payment under the 11.25% Senior Notes pursuant to the Forbearance Agreement. Despite the forbearance, the defaults under the Credit Facility are continuing, and will continue, absent a waiver from the lenders.

As we do not anticipate maintaining compliance with the consolidated current ratio covenant under our revolving credit facility over the next twelve months, we are evaluating the available financial alternatives, including obtaining alternative financing as well as seeking waivers, forbearances or amendments to the covenants or other provisions of our revolving credit facility to address any existing or future defaults and have engaged financial and legal advisors to assist. If we are unable to reach an agreement with our lenders or find acceptable alternative financing, the lenders under our revolving credit facility may choose to accelerate repayment, which in-turn may result in an event of default and an acceleration of the 2023 Notes due to cross-default provisions. We have concluded that these circumstances create substantial doubt regarding our ability to continue as a going concern. If the Company's lenders or its noteholders accelerate the payment of amounts outstanding under its Credit Facility or the 11.25% Senior Notes, respectively, it does not currently have sufficient liquidity to repay such indebtedness and would need additional sources of capital to do so. While the Company believes the proceeds of assets sales can fund immediate working capital needs, in the context of the current market conditions it is unclear whether the Company can obtain any additional sources of capital. We have concluded that these circumstances create substantial doubt regarding our ability to continue as a going concern.

The Company cannot provide any assurances that it will be successful in restructuring existing debt obligations or in obtaining capital sufficient to fund the refinancing of its outstanding indebtedness or to provide sufficient liquidity to meet its operating needs. If the Company is unsuccessful in its efforts to restructure and obtain new financing, it may be necessary for the Company to seek protection from creditors under Chapter 11 of the U.S. Bankruptcy Code (“Chapter 11”), or an involuntary petition for bankruptcy may be filed against the Company.

Operational Highlights for the First Quarter of 2020

During the first quarter of 2020, we achieved the following operating and financial results:

Production increased by 27% compared to the first quarter of 2019, averaging 14,436 BOE per day versus 11,372 BOE per day. Compared to the fourth quarter of 2019, production decreased 18%, or 3,111 BOE per day, from 17,547 BOE per day.

Drilled and completed five new wells.

Continued to lower our operating expenses on a per-BOE basis. Compared to the first quarter of 2019, lease operating and gas gathering, and production and ad valorem taxes decreased on a per-BOE basis due to the continued increase in production ~~was attributable~~throughout the year and our focus on controlling costs. General and administrative expense and interest expense also continue to ~~production additions associated with~~decrease on a per-BOE basis.

Changes in operating results between the ~~$116.6 million acquisition~~first quarters of ~~producing properties that closed June 15, 2017 which added an additional 81 gross / 75.2 net wells. The third quarter was also marginally impacted~~2020 and 2019 were primarily driven by the ~~addition~~following:

Revenues decreased by $3.7 million, or 9%, between the two quarters, primarily driven by a 38% decrease in commodity prices partially offset by a 28% increase in production.

Our first quarter 2020 net loss includes a $199.9 million impairment charge on oil and gas properties, while our first quarter 2019 net loss includes a $33.5 million loss on sale of ~~2 gross / 2 net wells placed into service at our Cyclone drilling pad in Gonzales County in late September.~~

~~The Company’s third~~oil and gas properties.

Compared to the first quarter ~~was negatively impacted by Hurricane Harvey in three respects. The Company estimates that 150 Boe/d~~ of ~~production was curtailed by the shut-ins of certain producing wells which were susceptible to flooding, reduced~~2019, lease operating ~~levels at certain~~and gas ~~processing plants utilized by the Company, as well as minor electrical outages.~~

~~For the three months ended September 30, 2017, approximately 69% of our production was crude oil, 16% was NGLs and 15% was natural gas.~~

~~Recent Developments Regarding Lonestar Properties~~

~~Eagle Ford Shale Trend - Western Region~~

~~Asherton~~

~~In Dimmit County, no new wells were completed during the three months ended September 30, 2017. The Asherton leasehold is held by~~gathering expense decreased $0.08, or 1%, per BOE, production and ~~Lonestar does not currently plan any drilling activity here in 2017.~~

~~Beall Ranch~~

~~In Dimmit County, no new wells were completed during the three months ended September 30, 2017. The Beall Ranch leasehold is held by production,~~ad valorem taxes decreased $0.44, or 20%, per BOE, general and ~~Lonestar does not currently plan any drilling activity here in 2017.~~

~~Burns Ranch~~

~~Lonestar has drilled the B#1H~~administrative expense decreased $2.12, or 50%, per BOE, and ~~B#2H on Burns Ranch to total depths~~interest expense decreased $1.57, or 15%, per BOE.

Derivative financial instruments had a net gain of 17,927 and 18,002 feet, respectively, with projected perforated intervals 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. Based on our current rates of daily stage completion, flowback is anticipated to begin in mid-November, 2017. Lonestar owns a 92% working interest (“WI”) 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 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 to drill the Horned Frog B#4H and C#1H wells, planned for perforated intervals of 10,000 feet$101.2 million in the first quarter of ~~2018.~~

2020, compared to a net loss of $36.2 million in the first quarter of 2019.

During the first quarter of 2020, we recognized net loss attributable to common stockholders of $113.0 million, or $4.52 per diluted common share, compared to a net loss attributable to common stockholders of $60.6 million, or $2.45 per diluted common share, in the first quarter of 2019. We generated $13.8 million of cash flow from operating activities during the first quarter of 2020, which was $4.0 million more than the $9.8 million generated by operating activities during the first quarter of 2019.

Gonzales County AMI

In February 2020, we entered into a Joint Development Agreement (the "JDA") in Gonzales County with one of the largest producers in the Eagle Ford which encompass an Area of Mutual Interest (the "AMI") totaling approximately 15,000 acres.

The agreement calls for Lonestar to operate a minimum of three to four Eagle Ford Shale ~~Trend - Central Region~~

~~Gonzales County~~

~~Production from four~~ wells ~~completed as part~~annually on behalf of the ~~Company’s 2017 capital program contributed~~two companies through 2022 that are intended to hold-by-production approximately 6,000 gross acres within the ~~Company’s third quarter results.~~AMI. The ~~Cyclone #4H & Cyclone #5H~~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.

In June, we began flowback operations on the Hawkeye #14H, Hawkeye #15H, and Hawkeye #16H. These wells 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~~AMI, and ~~began producing on September 22, 2017. Lonestar has a 100% WI~~were drilled to total measured depths of 21,221, 20,924, and ~~79% NRI~~20,228 feet, respectively. Our JDA partner did not participate in these ~~wells.~~wells, and on June 29, 2020 we completed a sale of 40% of the working interest in these wells to a third party for $9.1 million. The ~~Cyclone #26H~~Hawkeye #14H, #15H, and ~~#27H~~#16H wells were fracture-stimulated in engineered completions using diverters with an average proppant concentration of ~~1,525~~1,827 pounds per foot over 2837, 36 and 34 stages, ~~per well, and utilized diverters. The Cyclone #26H was completed with~~respectively. After the sale noted above, Lonestar has a 50% WI / 37.5% NRI in these wells.

Although these wells are in the early stages of flowback, they are looking promising. Initial rates recorded for the wells are:

Hawkeye #14H - With a perforated interval of ~~8,351~~10,979 feet, ~~and~~the #14H tested ~~760~~1,419 Bbls/d ~~and 420~~oil, 108 Bbls/d of NGLs, 774 Mcf/d, or ~~762 Boe/~~1,656 BOE/d (three-stream) on a ~~24/64’’~~30/64” 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

Hawkeye #15H - With a perforated interval of ~~8,278~~10,608 feet, ~~and~~the #15H tested ~~733~~1,598 Bbls/d ~~and 428~~oil, 118 Bbls/d of NGLs, 849 Mcf/d, or ~~831 Boe/~~1,858 BOE/d (three-stream) on a ~~22/64’’~~30/64” choke.

Hawkeye #16H - With a perforated interval of 9,885 feet, the #16H tested 1,483 Bbls/d oil, 111 Bbls/d of NGLs, 799 Mcf/d, or 1,727 BOE/d (three-stream) on a 30/64” choke.

RESULTS OF OPERATIONS

Certain of our operating results and statistics for the three months ended March 31, 2020 and 2019 are summarized below:



In thousands, except per share and unit data	Three Months Ended March 31,
In thousands, except per share and unit data	2020			2019
Operating Results
Net loss attributable to common stockholders	$	(113,048	)	$	(60,629	)
Net loss per common share – basic⁽¹⁾	(4.52		)	(2.45		)
Net loss per common share – diluted⁽¹⁾	(4.52		)	(2.45		)
Net cash provided by operating activities	13,835			9,826
Revenues
Oil	$	29,990		$	33,584
NGLs	2,599			3,393
Natural gas	4,420			3,764
Total revenues	$	37,009		$	40,741
Total production volumes by product
Oil (Bbls)	658,476			590,096
NGLs (Bbls)	303,485			217,561
Natural gas (Mcf)	2,110,381			1,295,204
Total barrels of oil equivalent (6:1)	1,313,691			1,023,524
Daily production volumes by product
Oil (Bbls/d)	7,236			6,557
NGLs (Bbls/d)	3,335			2,417
Natural gas (Mcf/d)	23,191			14,391
Total barrels of oil equivalent (BOE/d)	14,436			11,372
Average realized prices
Oil ($ per Bbl)	$	45.54		$	56.90
NGLs ($ per Bbl)	8.56			15.60
Natural gas ($ per Mcf)	2.09			2.91
Total oil equivalent, excluding the effect from commodity derivatives ($ per BOE)	28.17			39.80
Total oil equivalent, including the effect from commodity derivatives ($ per BOE)	34.40			39.09
Operating and other expenses
Lease operating and gas gathering	$	9,788		$	7,710
Production and ad valorem taxes	2,369			2,291
Depreciation, depletion and amortization	24,354			17,970
General and administrative	2,881			4,379
Interest expense	11,610			10,656
Operating and other expenses per BOE
Lease operating and gas gathering	$	7.45		$	7.53
Production and ad valorem taxes	1.80			2.24
Depreciation, depletion and amortization	18.54			17.56
General and administrative	2.19			4.28
Interest expense	8.84			10.41

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

Production

The ~~well has recently established a 30-day~~table below summarizes our production ~~rate~~volumes for the three months ended March 31, 2020 and 2019:



	Three Months Ended March 31,
	2020	2019	Change
Oil (Bbls/d)	7,236	6,557	10	%
NGLs (Bbls/d)	3,335	2,417	38	%
Natural gas (Mcf/d)	23,191	14,391	61	%
Total (BOE/d)	14,436	11,372	27	%

Total production during the first quarter of ~~687 Boe/d, consisting of 609 barrels of oil~~2020 averaged 14,436 BOE per day, ~~(88%)~~an increase of 27%, ~~39 barrels~~or 3,064 BOE per day, compared to the same period in 2019. This increase was primarily driven by development of our Eagle Ford acreage, partially offset by approximately 200 BOE per day lost with the Pirate divestiture which occurred in March 2019.

Our production during the first quarter of 2020 was 73% oil and NGLs, compared to 79% during the first quarter of 2019.

Oil, Natural Gas Liquid and Natural Gas Revenues

The table below summarizes our production revenues for the three months ended March 31, 2020 and 2019:



In thousands	Three Months Ended March 31,
In thousands	2020		2019		Change
Oil	$	29,990	$	33,584	(11	)%
NGLs	2,599		3,393		(23	)%
Natural gas	4,420		3,764		17	%
Total revenues	$	37,009	$	40,741	(9	)%

Our oil, NGL and 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~~revenues during the three months ended ~~September 30, 2017.~~March 31, 2020 decreased $3.7 million, or 9%, compared to those revenues for the same period in 2019. The ~~Pirate 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 in 2017.~~

~~Eagle Ford Shale Trend - Eastern Region~~

~~Brazos & Robertson Counties~~

~~Lonestar owns a 50% WI/ 39% NRI~~impact of our commodity derivative contracts), as reflected 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~~following table:



In thousands	Three Months Ended March 31, 2020 vs 2019
	Three Months Ended March 31, 2020 vs 2019
	Increase (Decrease) in Revenues			Percentage Increase (Decrease) in Revenues
Change in oil, NGL and natural gas revenues due to:
Increase in production	$	11,549		28	%
Decrease in commodity prices	(15,281		)	(39	)%
Total change in oil, NGL and natural gas revenues	$	(3,732	)	(9	)%

Excluding the ~~productivity~~impact 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~~our commodity derivative contracts, our net realized commodity prices and ~~23% higher than the most prolific producing offset well. The Wildcat B#1H was classified~~NYMEX differentials were 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 for the three months ended September 30, 2017 compared to the three months ended September 30, 2016~~

~~Net Production~~

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
%

~~Production volumes~~follows during the three months ended September 30, 2017 were 7,662 Boe/d, an increase 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 MarquisMarch 31, 2020 and Battlecat properties at the end of the second quarter of 2017, which contributed 1,883 Boe/d 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 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.

2019:

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.

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.



	Three Months Ended March 31,
	2020			2019			Change
Average net realized price
Oil ($/Bbl)	$	45.54		$	56.90		(20	)%
NGLs ($/Bbls)	8.56			15.60			(45	)%
Natural gas ($/Mcf)	2.09			2.91			(28	)%
Total ($/BOE)	28.17			39.80			(29	)%
Average NYMEX differentials
Oil per Bbl	$	0.03		$	2.00		(99	)%
Natural gas per Mcf	(0.18		)	(0.01		)	1,744	%

~~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~~March 31, 2020 was ~~$38.14~~$28.17 per ~~Boe,~~BOE, a ~~34% increase~~29% decrease compared to the average price infor the comparable period in ~~2016.~~2019. Reported wellhead realizations were ~~positively influenced~~driven lower 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 increasedecrease in the crude oil and natural gas benchmark prices between the periods, in addition to a significantly lower NYMEX oil differential. Our realized NGL price of $8.56 per Bbl, or 19% of NYMEX WTI, was largely due to a sharp drop in ethane prices.

~~The~~Our average ~~wellhead price for our Conventional properties in the three months ended September 30, 2017 was $0.00~~NYMEX oil differential decreased quarter over quarter by $1.97 per ~~Boe,~~Bbl, largely due to the ~~divestiture~~decreased spread between Louisiana Light Sweet ("LLS") prices, for which substantially all of our ~~Conventional assets~~crude oil sales were based for the periods presented, and NYMEX WTI benchmark prices.

Our natural gas NYMEX differentials are generally caused by movement in the ~~second half~~NYMEX natural gas prices during the month, as most 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~~our natural gas is sold on an index price that is set near the first of each month. While the percentage change in ~~the three months ended September 30, 2017 were $26.9 million,~~NYMEX natural gas differentials can be large, these differentials are seldom more than a ~~73% increase from $15.5 million from the comparable period in 2016. This increase in revenue was a result~~dollar above or below NYMEX price.

Commodity Derivative Contracts

We utilize oil and natural gas derivative contracts to provide an economic hedge of ~~a 29% increase in~~our exposure to commodity price risk associated with anticipated future production and ~~a 34% increase in realizations. We also realized favorable crude oil hedge~~to provide more certainty to our future cash ~~settlements, which added $1.8 million in gains~~flows. These contracts have historically consisted of fixed-price swaps, collars and basis swaps.

The following table summarizes the net cash (payments) receipts on the Company's commodity derivatives and the relative price impact (per Bbl or Mcf) for the three months ended ~~September 30, 2017.~~

March 31, 2020 and 2019:

~~Wellhead revenues~~
Three Months Ended March 31,
2020 2019
In thousands, except price impact Net realized settlements Price impact Net realized settlements Price impact
(Payments) receipts on settlements of oil derivatives $ (155 ) $ (0.24 ) $ 462
$ 0.78
Receipts on settlements of natural gas derivatives 1,236
0.59
847
0.65
Total net commodity derivative settlements $ 1,081
$ 1,309

Our realized net gain on commodity derivative contracts was $8.2 million for ~~our Eagle Ford Shale assets in~~ the three months ended ~~September 30, 2017 were $26.9~~March 31, 2020, as compared to net loss of $0.7 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~~for the three months ended ~~September 30, 2017.~~

~~Wellhead revenues for~~March 31, 2019. We realized an average gain of $6.23 per BOE on our ~~Conventional properties in~~oil and natural gas swaps during the three months ended ~~September 30, 2017 were $0.0 million,~~March 31, 2020, as compared to ~~$1.2 million, due to~~an average loss of $0.72 per BOE for the ~~divestiture of our Conventional assets in the second half of 2016.~~

three months ended March 31, 2019.

~~Costs and~~

Production Expenses

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

three months ended March 31, 2020 and 2019:

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%



In thousands, except expense per BOE	Three Months Ended March 31,
In thousands, except expense per BOE	2020		2019		Change
Production expenses
Lease operating and gas gathering	$	9,788	$	7,710	27	%
Production and ad valorem taxes	2,369		2,291		3	%
Depreciation, depletion and amortization	24,354		17,970		36	%
Production expenses per BOE
Lease operating and gas gathering	$	7.45	$	7.53	(1	)%
Production and ad valorem taxes	1.80		2.24		(19	)%
Depreciation, depletion and amortization	18.54		17.56		6	%

Lease Operating and Gas Gathering ~~Expenses~~

The table below provides detail of our lease operating and gas gathering expense for the three months ended March 31, 2020 and 2019:



In thousands	Three Months Ended March 31,
In thousands	2020		2019		Change
Lease operating	$	7,638	$	6,831	12	%
Gas gathering, processing and transportation	2,150		879		145	%
Total lease operating and gas gathering expense	$	9,788	$	7,710	27	%

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 lease operating ~~expenses~~and gas gathering expense increased ~~$0.5~~$2.1 million, ~~(13%) in~~or 27%, for the three months ended ~~September 30, 2017~~March 31, 2020 to ~~$4.5~~$9.8 million from ~~$4.0~~$7.7 million in the comparable period in ~~2016. However, on~~2019. On a unit-of-production basis, ~~our~~ lease operating ~~expenses~~and gas gathering expense decreased ~~13%~~1%, or $0.08 per BOE, from ~~$7.36~~$7.53 per ~~Boe~~BOE in the three months ended ~~September 30, 2016~~March 31, 2019 to ~~$6.40~~$7.45 per ~~Boe~~BOE in the three months ended ~~September 30, 2017~~March 31, 2020. The increase in total lease operating costs is due to continuing incremental production brought online by our ~~ability to integrate our recent~~ Eagle Ford ~~Shale acquisitions on a cost-effective basis,~~development program, as well as ~~reduced operating expenses associated with the sale of our Conventional assets~~higher gas processing costs in the ~~second half~~current year.

Compared to the fourth quarter of ~~2016.~~

~~Sequentially, our~~2019, lease operating and gas gathering expense ~~increased by 28%~~decreased 23%, or $1.0 million to $4.5 million 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.$2.2 million. On a unit-of-production basis, ~~we reduced our lease operating~~these expenses ~~by 7% sequentially to $6.40~~increased 22%, or $1.33 per ~~Boe in~~BOE, from the ~~three months ended September 30, 2017, from $6.87 per Boe in the three months ended June 30, 2017.~~

fourh quarter of 2019.

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 for the three months ended March 31, 2020 and 2019:



	Three Months Ended March 31,
In thousands	2020		2019		Change
Production taxes	$	1,325	$	1,786	(26	)%
Ad valorem taxes	1,044		505		107	%
Total production and ad valorem tax expense	$	2,369	$	2,291	3	%

Our total production and ad valorem tax expense increased 3%, or $0.1 million, between the three months ended March 31, 2020 and 2019. Production taxes were lower in the current period due to lower revenues, caused in-turn by lower commodity prices. Ad valorum taxes were higher in the current period due to higher reserve values for our properties. On a unit-of-production basis, production and ad valorem tax expense decreased 19%, or $0.44 per BOE, from $2.24 per BOE in the three months ended ~~September 30, 2017 were $1.5 million, an increase of $0.6 million (70%)~~March 31, 2019 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~~$1.80 per BOE in the three months ended ~~September 30, 2017, compared~~March 31, 2020. This decrease in the per-BOE rate is attributable to ~~$0.4~~lower commodity prices received for our production in the current period.

Compared to the fourth quarter of 2019, production and ad valorem taxes decreased $0.7 million, or 22%. This decrease correlates with the decrease in the Company's production between the periods in addition to lower commodity prices. On a unit-of-production basis, these expenses decreased 4%, or $0.08 per BOE, from the fourth quarter of 2019.

Depreciation, Depletion and Amortization

The table below provides detail of our depreciation, depletion and amortization ("DD&A") expense for the three months ended ~~September 30, 2016.~~

~~Depreciation, Depletion~~March 31, 2020 and ~~Amortization (DD&A)~~

2019.

For the three months
ended September 30,

2017

2016

(In thousands)

DD&A of proved oil and gas properties

$
15,658

$
10,498

Depreciation of other property and equipment

233

167

Accretion of asset retirement obligations

38

53

Depreciation, Depletion and Amortization

$
15,929

$
10,718



In thousands	Three Months Ended March 31,
In thousands	2020		2019		Change
Depletion of proved oil and gas properties	$	23,905	$	17,556	36	%
Depreciation of other property and equipment	363		336		8	%
Accretion of asset retirement obligations	86		78		10	%
Total DD&A expense	$	24,354	$	17,970	36	%

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.~~method. For leasehold acquisition costs and the cost to acquire proved properties, the reserve base used to calculate depreciation and depletion is the sum of proved developed reserves and proved undeveloped reserves. For ~~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 3three to 5five years.

DD&A in the three months ended September 30, 2017 was $15.9 million, increased 49% from the comparable period in 2016 due to Lonestar’s acquisition of the Marquis and Battlecat properties which helped increase production 29% 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, 2017 due to the sale 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 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.

~~Impairment of Oil and Gas Properties~~

~~The Company did not record impairment~~ expense for the three months ended ~~September 30, 2017,~~March 31, 2020 was $24.4 million, a ~~decrease~~36% increase from $18.0 million in the comparable period in 2019. This increase is due to continued development of ~~$29.1 million~~our properties in the Eagle Ford. On a unit-of-production basis, DD&A increased 6%, or $0.98 per BOE, from $17.56 per BOE for the three months ended ~~September 30, 2016.~~

March 31, 2019 to $18.54 per BOE for the three months ended March 31, 2020.

Compared to the fourth quarter of 2019, DD&A expense for the three months ended March 31, 2020 decreased $0.1 million. On a unit-of-production basis, DD&A increased by $2.96 per BOE, or 3%, from the fourth quarter of 2019.

Loss on Sale of Oil and Gas Properties

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

Impairment of Oil and Gas Properties

We evaluate impairment of proved and unproved oil and gas properties on a region basis. On this basis, certain regions may be impaired because they are not expected to recover their entire carrying value from future net cash flows.

During the first quarter of 2020, 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.

It is reasonably possible that the Company's estimate of undiscounted future net cash flows may change in the future resulting in the need to impair the carrying value of its properties. See Part II Item 1A. Risk Factors, for further discussion.

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

General and administrative ("G~~&A expenses~~&A") expense decreased ~~$0.6~~$1.5 million, or 33%, to ~~$2.3~~$2.9 million in the three months ended ~~September 30, 2017~~March 31, 2020, from ~~$2.9~~$4.4 million ~~from~~for the comparable period in ~~2016.~~2019. This decrease reflects gains in stock-based compensation in the current quarter (see below), partially offset by higher compensation expense. On a ~~unit of production~~unit-of-production basis, ~~we decreased our~~ G&A expense ~~by 38%~~decreased 49%, or $2.09 per BOE, from ~~$5.27~~$4.28 per ~~Boe~~BOE in the three months ended ~~September 30, 2016~~March 31, 2019 to ~~$3.26~~$2.19 per ~~Boe~~BOE in the three months ended ~~September 30, 2017.~~

March 31, 2020. This decrease was due to the increase in production volumes quarter to quarter, as well as the changes in total expense noted above.

Stock-based compensation gains included in G&A was $1.8 million for the three months ended March 31, 2020, versus expense of $0.9 million for the three months ended March 31, 2019. These awards are accounted for as liabilities and these liabilities decreased due to the decrease in the Company's stock price during the quarter, which in-turn caused a gain in G&A.

Compared to the fourth quarter of 2019, G&A expense for the three months ended March 31, 2020 decreased $1.3 million, or 31%. On a unit-of-production basis, G&A expense decreased by $0.38 per BOE, or 15%, from the fourth quarter of 2019.

Interest Expense

The table below provides detail of the interest expense for our various long-term obligations for the three months ended March 31, 2020 and 2019:



In thousands	Three Months Ended March 31,
In thousands	2020		2019		Change
Interest expense on 11.25% Senior Notes	$	7,031	$	7,031	—	%
Interest expense on Credit Facility	3,685		2,824		30	%
Other interest expense	126		100		26	%
Total cash interest expense ⁽¹⁾	$	10,842	$	9,955	9	%
Amortization of debt issuance costs and discounts	768		701		10	%
Total interest expense	$	11,610	$	10,656	9	%
Per BOE:
Total cash interest expense	$	8.25	$	9.73	(15	)%
Total interest expense	8.84		10.41		(15	)%

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

Our total interest expense in the three months ended ~~September 30, 2017~~March 31, 2020 was ~~$5.0~~$11.6 million, ~~a decrease of 13%~~an 9% increase from ~~$5.8~~$10.7 million ~~from~~in the comparable period in ~~2016~~2019. This increase is primarily due to a combination of a higher principal balance on our Credit Line (as defined below) in the ~~repayment of our Second Lien Notes and the partial repurchase of the 8.750% Senior Notes.~~ current quarter.

On a ~~unit of production~~unit-of-production basis, ~~we reduced our~~total interest expense decreased by ~~48%~~15%, or $1.57 per BOE, from ~~$13.49~~$10.41 per ~~Boe~~BOE in the three months ended ~~September 30, 2016~~March 31, 2019 to ~~$7.05~~$8.84 per ~~Boe~~BOE in the three months ended ~~September 30, 2017.~~

March 31, 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

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

InCompared to the fourth quarter of 2019, interest expense for the three months ended ~~September 30, 2017, we recognized a non-cash loss of $9.4~~March 31, 2020 slightly increased by $0.5 million, primarily due to higher borrowing on our ~~commodity derivative contracts related to~~Credit Facility. On a unit-of-production basis, interest expense increased 28%, or $1.93 per BOE, from the ~~change in mark-to-market value~~fourth quarter of 2019.

Income Taxes

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

~~Income Taxes~~

March 31, 2020 and 2019:



In thousands, except per-BOE amounts and tax rates	Three Months Ended March 31,
In thousands, except per-BOE amounts and tax rates	2020			2019
Current income tax benefit	$	424		$	11
Deferred income tax benefit	931			12,922
Total income tax benefit	$	1,355		$	12,933
Average income tax benefit per BOE	$	1.03		$	12.64
Effective tax rate	1.2		%	18.1		%
Total net deferred tax asset (liability) on balance sheet at period end	$	—		$	552

As a result of the ~~net~~ loss before income tax of ~~$11.5~~$112.1 million in the three months ended ~~September 30, 2017~~March 31, 2020 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 in the 2017 period and an income tax expense of $1.7 million in the 2016 period.~~

~~Net Income (Loss) Before Taxes~~

As a result 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$71.5 million in the three months ended ~~September 30, 2017 compared to net loss before~~March 31, 2019, we recorded income tax benefit of ~~$9.6~~$1.4 million and $12.9 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 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,March 31, 2020 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.

2019, respectively.

~~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~~On March 27, 2020, Congress enacted 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 oilCoronavirus Aid, Relief, and ~~natural gas benchmarks between the periods. In addition~~Economic Security Act (the “CARES Act”) 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 as a result of a 46% increase in wellhead price realizations, coupled with a 7% increase in production in the nine months ended September 30, 2017.

~~Wellhead revenues for our Conventional properties in the nine months ended September 30, 2017 were $0.0 million, compared to $4.0 million from the comparable period in 2016~~provide certain taxpayer relief as a result of the ~~divestiture of our Conventional assets in~~COVID-19 pandemic. The CARES Act included several favorable provisions that impacted income taxes, primarily the ~~second half of 2016.~~

~~Costs and Expenses~~

~~The table below presents a detail of costs and expenses 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 and Gas Gathering Expenses~~

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 basedmodified rules on the ~~valuation~~deductibility of ~~our oil~~business interest expense for 2019 and ~~natural gas properties.~~

~~Our total production, severance,~~2020, a five-year carryback period for net operating losses generated after 2017 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 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 costsbefore 2021, and the ~~cost to acquire proved properties, the reserve base used to calculate depreciation and depletion is the sum~~acceleration 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~~refundable alternative minimum tax credits. The CARES Act did not materially impact 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~~effective tax rate 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~~March 31, 2020, and we are currently assessing the ~~three months ended September 30, 2017.~~

~~Interest Expense~~

potential future impact.

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~~deferred tax assets exceeded our deferred tax liabilities at March 31, 2020 primarily due to tax consequences of the ~~incurrence~~impairment of our proved properties during the first quarter of 2020; as a ~~$1.1~~result, we retained a full valuation allowance of $32.6 million ~~early payment premium~~at March 31, 2020 due to uncertainties regarding the future realization of our deferred tax assets. The valuation allowance is also the primary cause for the ~~Company paying off its second lien debt, which bore a higher interest rate. On a unit~~variance between our statutory tax rate of ~~production basis, interest expense increased 12% from $9.38 per Boe in~~21% and the ~~three months ended September 30, 2016~~effective tax rate of 1.2% for the quarter. The valuation allowance will continue to ~~$10.56 per Boe in~~be recognized until 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~~realization of future deferred tax benefits is determined 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.

be more likely than not.

CAPITAL RESOURCES AND LIQUIDITY

Liquidity and Capital Resources

We expect that our primary ~~sources~~source of liquidity ~~and capital resources~~ will be cash flows generated by operating ~~activities and borrowings under~~activities. During the first quarter of 2020, we generated cash flows from operations of $13.8 million, after giving effect to $3.3 million of positive changes in cash flows from working capital. As of July 2, 2020, our ~~$500,000,000 Senior Secured~~ Credit Facility ~~(the “Senior Secured Credit Facility”).~~

had an outstanding balance of $285 million and a borrowing-base deficiency of $60.4 million as a result of the terms of the Forbearance Agreement (see below), which will need to be repaid within 60 days of July 2, 2020. We did not make a $14.1 million interest payment on our 11.25% Senior Notes due July 1, 2020.

The Company's primary needs for cash are for capital expenditures, acquisitions of oil and natural gas properties, payments of contractual obligations and working capital obligations. We have historically financed our ~~acquisition and development activity~~business through cash flows ~~generated by operating activities,~~from operations, borrowings under our ~~Senior Secured~~ Credit Facility 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~~pricing, however this is unlikely with our current financial condition. 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 of transactions will be available on favorable terms, or at all, and we therefore cannot guarantee the outcome of any such transactions.

As discussed above, NYMEX oil prices have decreased significantly since the beginning of 2020, decreasing from nearly $60 per barrel in early January to the upper $30s per barrel in late June and were considerably lower during the months of April and May. This decrease in the market prices for our production directly reduce our operating cash flow and indirectly impact our other sources of potential liquidity, such as lowering our borrowing capacity under our revolving credit facility, as our borrowing capacity and borrowing costs are generally related to the estimated value of our proved reserves. In this low oil price environment, we have taken various steps to preserve our liquidity including (1) by reducing our 2020 budgeted development capital spending, (2) by continuing to focus on reducing our operating and overhead costs, and (3) by adding additional commodity hedges for 2021 to reduce our long-term exposure to commodity prices.

At ~~September 30, 2017,~~March 31, 2020, we had ~~$4.8~~$1.1 million in cash and cash equivalents and approximately ~~$31.9~~$22.6 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~~As of July 2, 2020 the borrowing base ~~associated with our Senior Secured Credit Facility. Combined with our plans~~was redetermined to ~~keep capital spending and cash flow~~$225 million from ~~operations in general~~$286 million pursuant to the Forbearance Agreement. The outstanding balance ~~in 2018, we believe that our existing cash and cash equivalents, cash~~

~~expected to be generated from operations and the availability of borrowing~~ under our ~~Senior Secured~~credit facility was $285 million as of July 2, 2020, which represents a borrowing deficiency of $60.4 million, and we are obligated to pay the deficiency within 60 days after July 2, 2020.

We did not satisfy the consolidated current ratio covenant under the Credit Facility as of the March 31, 2020 measurement date and did not make an interest payment date under the 11.25% Senior Notes that was due on July 1, 2020. Such failures currently represent events of default under the Credit Facility, and the missed interest payment will also represent an event of default under the 11.25% Senior Notes if not cured within 30 days. The Company received a forbearance from the lenders under the Credit Facility until July 31, 2020 for the default in the consolidated current ratio covenant as of the March 31, 2020 measurement date and the missed interest payment pursuant to the Forbearance Agreement. Despite the forbearance, the defaults under the Credit Facility are continuing, and will continue, absent a waiver from the lenders. We do not anticipate maintaining compliance with the consolidated current ratio over the next twelve months.

We do not anticipate maintaining compliance with the consolidated current ratio covenant under our Credit Facility over the next twelve months, and are evaluating the available financial alternatives, including obtaining acceptable alternative financing as well as seeking additional waivers, forbearances or amendments to the covenants or other provisions of the Credit Facility to address any existing or future defaults and have engaged financial and legal advisors to assist the Company. If we are unable to reach an agreement with its lenders or find acceptable alternative financing, the lenders of the Credit Facility may choose to accelerate repayment, in addition to the $60.4 million due from the current borrowing base deficiency noted above, which in turn may result in an event of default and an acceleration of the 11.25% Senior Notes. If our lenders or our noteholders accelerate the payment of amounts outstanding under our Credit Facility or the 11.25% Senior Notes, respectively, the Company does not currently have sufficient liquidity to repay such indebtedness and would need additional sources of capital ~~raised through future debt financing~~to do so. While we believe the proceeds of assets sales can fund immediate working capital needs, in the context of the current market conditions it is unclear whether we can obtain any additional sources of capital.

We cannot provide any assurances that we will be successful in any restructuring of existing debt obligations or obtaining capital sufficient to fund the refinancing of its outstanding indebtedness or to provide sufficient liquidity to meet our liquidity requirements, anticipated capital expenditures and payments due under our existing credit facility and notes outstanding for at least the next 12 months. We are in active discussions to refinance our 8.750% Senior Notes due April 2019 on terms that are acceptable tooperating needs. If the Company ~~which will also provide~~is unsuccessful in its efforts to ~~extend the term~~restructure and obtain new financing, it may be necessary for us to seek protection from creditors under Chapter 11 of the ~~Senior Secured Credit Facility.~~

~~Historical Cash Flows~~

~~The following table summarizes~~U.S. Bankruptcy Code (“Chapter 11”), or an involuntary petition for bankruptcy may be filed against us. We have concluded that these circumstances create substantial doubt regarding our ~~cash~~ability to continue as a going concern.

Cash flows for the ~~periods indicated:~~

three months ended March 31, 2020 and 2019 are presented below:

For the nine months ended September 30,

($ in thousands)

2017

2016

Statement of Cash Flows Data:

Net cash provided by (used in):

Operating activities

$
28,467

$
18,234

Investing activities

(177,529
)

(25,453
)
Financing activities

147,806

8,916

Effect of exchange rate changes on cash and
cash equivalents

—

(29
)
Decrease in cash and cash equivalents

$
(1,256
)

$
1,668



In thousands	Three Months Ended March 31,
In thousands	2020			2019
Net cash provided by (used in):
Operating activities	$	13,835		$	9,826
Investing activities	(35,776		)	(22,298		)
Financing activities	19,946			10,884
Net change in cash	$	(1,995	)	$	(1,588	)

Net Cash Provided Byby Operating Activities

Net cash provided by operating activities ~~increased $10.3~~of $13.8 million ~~from $18.2~~for the first three months of 2020 was $4.0 million inmore than the ~~nine~~first three months ~~ended September 30, 2016 to $28.5 million in the nine months ended September 30, 2017. This increase is primarily due to a 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 increase2019, which totaled $9.8 million. Excluding changes in operating assets and liabilities, ~~and an increase in DD&A~~net cash provided by operating activities decreased $7.8 million. Compared to the first three months of ~~$2.2 million,~~2019, the first three months of 2020 had significantly lower commodity prices which were largely offset by ~~a $19.4 million dollar decrease in settlements of derivative financial instruments, a $4.0 million decrease in impairment of~~higher oil and natural gas ~~properties, a $5.6 million increase~~production. Changes in ~~deferred taxes, a $9.9 million increase in non-cash gain on derivative financial instruments,~~our operating assets and ~~a $3.9 million increase in unrealized gain on equity warrants during~~liabilities between the ~~nine~~three months ended ~~September 30, 2017.~~

March 31, 2019 and the three months ended March 31, 2020 resulted in a net increase of approximately $11.8 million in net cash provided by operating activities for the three months ended March 31, 2020, as compared to the three months ended March 31, 2019.

Net Cash Used Inin Investing Activities

Net cash used in investing activities increased ~~$152.0~~$13.5 million, from ~~$25.5~~$22.3 million in the ~~nine~~three months ended ~~September 30, 2016~~March 31, 2019 to ~~$177.5~~$35.8 million in the ~~nine~~three months ended ~~September 30, 2017.~~March 31, 2020. This increase is primarily due to ~~a $105.9~~$12.0 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~~the sale of ~~oil and gas properties of $2.7 million.~~

the Pirate assets in March 2019.

Net Cash Provided Byby Financing Activities

Net cash provided by financing activities increased ~~$138.9~~$9.1 million, from ~~$8.9~~$10.9 million ~~used~~provided during the ~~nine~~three months ended ~~September 30, 2016~~March 31, 2019 to ~~$147.8~~$19.9 million provided in the ~~nine~~three months ended ~~September 30, 2017. The~~March 31, 2020. This increase ~~was~~is primarily due to ~~increased borrowings and equity issuances~~lower repayments 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~~our Credit Line borrowing in the ~~nine months ended September 30, 2017.~~

current quarter.

~~Hedging~~

~~The following table provides a summary of~~

Debt

Senior Secured Credit Facility

In July 2015, through 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~~subsidiary, Lonestar Resources America, Inc. ("LRAI"), we 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~~$500 million ~~of indebtedness, including $128.1 million drawn on our~~ Senior Secured Credit Facility ~~$151.8 million (less an unamortized discount~~with Citibank, N.A., as administrative agent, and other lenders party thereto (as amended, supplemented or modified from time to time, the “Credit Facility”), which has a maturity date 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~~

November 15, 2023. As of ~~September 30, 2017 LRAI had outstanding borrowings of approximately $128.1~~March 31, 2020, $267.0 million was borrowed under the ~~Senior Secured~~ Credit Facility, ~~which was subject to an~~and the weighted average interest rate on borrowings under the Credit Facility for the quarter was 5.30%. Borrowing availability was $22.6 million as of ~~approximately 5.49% and 5.17% during the three and nine months ended September 30, 2017, respectively. Additionally, the Senior Secured~~March 31, 2020, which reflects $0.4 million of letters of credit outstanding.

The Credit Facility may be used for loans and, subject to a ~~$2,500,000~~$2.5 million sub-limit, letters of ~~credit. LRAI has $500,000~~credit, and provides for a commitment fee of ~~advances~~0.375% to 0.5% (0.5% following the Thirteenth Amendment) based on the ~~letter~~unused portion of ~~credit as of September 30, 2017. The~~the borrowing base under the ~~Senior Secured~~Credit Facility. As of March 31, 2020, the borrowing base and lender commitments for the Credit Facility ~~can be redetermined up or down by~~was $290 million. The borrowing base was lowered to $286 million on June 11, 2020 as part of the ~~lenders based~~Thirteenth Amendment, and on ~~among other things, their evaluation of our oil and natural gas reserves. Effective as of May 19, 2016,~~July 2, 2020, the borrowing base was ~~reduced~~redetermined to ~~$120 million. Effective~~$225 million from $286 million pursuant to the Forbearance Agreement. The outstanding balance under our credit facility was $285 million as of ~~November 23, 2016,~~July 2, 2020 which represents a borrowing deficiency of $60.4 million. We are obligated to pay the deficiency within 60 days after July 2, 2020.

Borrowings under the Credit Facility, at our 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 LIBOR1 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 1.0% to 2.0% (2.0% to 3.5% following the Thirteenth Amendment) for ABR loans and from 2.0% to 3.0% (3.0% to 4.5% following the Thirteenth Amendment) for adjusted LIBO rate loans.

As the Credit Facility is in a state of of default, 2.0% incremental default interest would typically be due but is currently not being charged as part of the terms of the Forbearance Agreement (see below).

Subject to certain permitted liens, our obligations under the Credit Facility are required to be secured by the grant of a first priority lien on no less than 80% of the value of the proved oil and gas properties of the Company and its subsidiaries (currently 100% following the Thirteenth Amendment).

The Credit Facility contains certain financial performance covenants, as defined in the Credit Facility, including the following:

A maximum debt to EBITDAX ratio of 4.0 to 1.0, and

A current ratio of not less than 1.0 to 1.0.

We were not in compliance with the terms of the Credit Facility as of December 31, 2019 because we did not satisfy the consolidated current ratio at those times and the audit report prepared by our auditors with respect to the financial statements in the 2019 Form 10-K included an explanatory paragraph expressing uncertainty as to our ability to continue as a "going concern." The lenders waived the current ratio default with respect to December 31, 2019, pursuant to the Waiver. The Company received a forbearance until July 31, 2020 for the default in the consolidated current ratio covenant as of the March 31, 2020 measurement date and the missed July 1, 2020 interest payment under the 11.25% Senior Notes pursuant to the Forbearance Agreement. Despite the forbearance, the defaults under the Credit Facility are continuing, and will continue, absent a waiver from the lenders. As we do not anticipate maintaining compliance with the consolidated current ratio covenant under our Credit Facility over the next twelve months, we are evaluating the available financial alternatives, including obtaining acceptable alternative financing as well as seeking waivers, forbearances or amendments to the covenants or other provisions of our revolving credit facility to address future defaults. We were not in compliance with the terms of the Credit Facility as of May 15, 2020, because we did not timely deliver our financial statements with respect to the fiscal quarter ended March 31, 2020. Such failure represented a default under the Credit Facility which the lenders waived pursuant to the Thirteenth Amendment. As noted above, the borrowing base was ~~reduced~~redetermined to $225 million from ~~$120~~$286 million pursuant to ~~$112~~the Forbearance Agreement. The outstanding balance under our credit facility was $285 million as of July 2, 2020 which represents a borrowing deficiency of $60.4 million. ~~In connection with closing~~We are obligated to pay the ~~Marquis~~

deficiency within 60 days after July 2, 2020.

~~Acquisition~~

Waiver and ~~the Battlecat Acquisition, on June 15, 2017, LRAI~~Eleventh Amendment

Effective April 7, 2020, we entered into the ~~Sixth~~Waiver and Eleventh Amendment (the "Waiver") to waive events of default arising from our failure to comply with the consolidated current ratio as of December 31, 2019, to timely provide audited financial statements and ~~Joinder~~to provide financial statements that are not subject to any “going concern” or like qualification or exception for the fiscal year ended December 31, 2019. As there was no guarantee that our lenders will agree to waive events of default or potential events of default in the future, the amounts outstanding under the Credit Facility as of December 31, 2019 were classified as current in the accompanying 2019 Condensed Consolidated Balance Sheet.

Twelfth Amendment

Effective May 8, 2020, we entered into the Twelfth Amendment to Credit Agreement (the ~~“Sixth~~“ Twelfth Amendment”), to ~~its~~allow the Company to accept proceeds of up to $2.2 million from an unsecured loan applied for under the Coronavirus Aid, Relief and Economic Security Act.

We have applied for, and have received, funds under the Paycheck Protection Program after the period end in the amount of $2.2 million. The application for these funds requires us 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 requires us 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 these funds, and the forgiveness of the loan attendant to these funds, 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.

Waiver and Thirteenth Amendment

Effective June 11, 2020, we entered into the Waiver and Thirteenth Amendment to Credit Agreement ~~dated~~(the "Thirteenth Amendment") which (i) waived any default or event of default arising from our failure to provide timely quarterly financial statements for the three months ended March 31, 2020; (ii) redetermined the borrowing base to $286 million from $290 million; (iii) set the next borrowing base redetermination to be on July 1, 2020 (and in any event, no later than July 31, 2020), (iv) amended the borrowing base utilization grid used in the applicable margin, as noted above and (v) until the July 1, 2020 redetermination, restricted the Company and its subsidiaries’ ability to incur debt with respect to, among other items, capital leases and permitted senior debt, grant liens to secure other obligations, pay dividends on LRAI’s preferred stock and make certain investments.

As there is no guarantee that our lenders will agree to waive events of default or potential events of default in the future, the amounts outstanding under the Credit Facility as of March 31, 2020 were classified as current in the accompanying Condensed Consolidated Balance Sheet.

Forbearance Agreement and Fourteenth Amendment

On July ~~28, 2015, among LRAI, the subsidiary guarantors party thereto, the several lenders party thereto~~2, 2020, we entered into a Forbearance Agreement, Fourteenth Amendment, and Borrowing Base Agreement with Citibank, N.A., ~~in its capacity~~ as administrative agent and ~~as issuing bank.~~the lenders party thereto (the “Forbearance Agreement”) with respect to the Credit Facility. Pursuant to the ~~Sixth Amendment,~~Forbearance Agreement, among other things, (i) the lenders under the Credit ~~Agreement was amended~~Facility agree to ~~(i) increase~~refrain from exercising their rights and remedies under the Credit Facility and related loan documents with respect to certain defaults until July 31, 2020, (ii) the borrowing base was redetermined to $225 million from ~~$112~~$286 million, (iii) all proceeds of dispositions and terminations or liquidations of swap agreements shall be used to ~~$160 million until redetermined or adjusted in accordance~~repay the Credit Facility and shall automatically reduce the borrowing base by the amount of the repayment and (iv) certain exceptions to the covenant restriction on investments shall no longer be available.

The rights of the lenders to exercise rights and remedies resulted from our failure to comply with the current ratio with respect to the quarter ended March 31, 2020 and the defaults expected with respect to the quarter ending Jun 30, 2020, under the current ratio and the leverage ratio covenants, and the default with respect to the failure to make the interest payment due on July 1, 2020, under the 11.25% Senior Notes.

The Forbearance Agreement can be terminated by the lenders upon (i) the occurrence of any default or event of default under the Credit Facility other than those disclosed, (ii) the failure of the Company to comply with any of the terms and requirements of the Forbearance Agreement, ~~Under~~(iii) the ~~Sixth Amendment, redeterminations are scheduled semi-annually~~breach of any representation or warranty, (iv) the exercise of any rights by other debt holders relating to ~~occur during May~~foreclosure or acceleration and ~~November~~(v) the commencement of any bankruptcy proceeding with respect to any loan party. Additionally, the Forbearance Agreement can be terminated if we fail to deliver a detailed restructuring proposal to the lenders by July 16, 2020. If the Forbearance Agreement terminates and any then-current and ongoing events of default have not been waived or cured, the lenders will be able to accelerate the loans and pursue their rights and remedies.

11.25% Senior Notes

In January 2018, the Company issued $250 million of 11.250% Senior Notes to U.S.-based institutional investors. The net proceeds of $244.4 million were used to fully retire the Company’s 8.75% Senior Notes, which included principal, interest and a prepayment premium of approximately $162 million. The remaining net proceeds were used to reduce borrowings under the Credit Facility.

The 11.25% Senior Notes mature on January 1, 2023, and bear interest at the rate of 11.25% per year, payable on January 1 and July of each year. ~~The next borrowing base redetermination is scheduled for November 2017.~~

~~With borrowings outstanding~~At any time prior to January 1, 2021, the Company may, on any one or more occasions, redeem up to 35% 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~~the aggregate principal amount of the ~~8.750%~~11.25% Senior Notes ~~in April 2014 under~~with an ~~indenture among LRAI, its subsidiary guarantors and Wells Fargo Bank, National Association, as trustee. The Company is~~amount of cash not ~~a party to~~greater than the ~~indenture.~~

~~The 8.750% Senior Notes mature on April 15, 2019 and accrue interest~~net cash proceeds of certain equity offerings 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 guarantorredemption price equal to 111.25% of the ~~Initial Purchaser’s obligations,~~principal amounts redeemed, plus accrued and unpaid interest, provided that at least 65% of 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 11.25% Senior Notes originally issued remains outstanding immediately after such redemption and the ~~Second Lien~~redemption occurs within 180 days of the closing date of such equity offering.

On and after January 1, 2021, the Company may redeem the 11.25% Senior Notes, in whole or in part, plus accrued and unpaid interest, at the following redemption prices: 108.438% after January 1, 2021; 105.625% after January 1, 2022; and 100% after July 1, 2022,

We did not make our interest payment on the 11.25% Senior Notes that was due on July 1, 2020 of approximately $14.1 million. We have 30 days to ~~purchase up~~cure the default before the holders of the 11.25% Senior Notes or the trustee may be able to ~~an aggregate 998,000 shares~~accelerate payment. The missed interest payment represents a current event of default under the Credit Facility. We have entered into the Forbearance Agreement which provides that, among other things, the lenders under the Credit Facility have agreed to forbear the Company’s default of the interest payment until July 31, 2020. However, the default under the Credit Facility has not been waived and still exists, and the Forbearance Agreement can be terminated if we fail to deliver a detailed restructuring proposal to the lenders by July 16, 2020. Accordingly, the amounts outstanding under the 11.25% Senior Notes as of March 31, 2020 were classified as current in the accompanying Condensed Consolidated Balance Sheet.

The indenture contains certain restrictions on the Company’s ability to incur additional debt, pay dividends on the Company’s common stock, make investments, create liens on the Company’s assets, engage in transactions with affiliates, transfer or sell assets, consolidate or merge, or sell substantially all of the Company’s ~~Class A voting common stock at a price equal to $5.00 per share.~~

assets. The ~~Second Lien Notes are secured~~indenture also contains cross- default provisions for defaults of the Company's other debt instruments, including the Credit Facility, caused by ~~second-priority liens on substantially all~~payment default or events which cause the acceleration of ~~LRAI’s and its subsidiaries’ assets~~repayment prior to the ~~extent~~stated maturity of such ~~assets secure obligations under~~instrument.

Capital Expenditures

We currently anticipate that our full-year 2020 capital budget, excluding acquisitions, will be approximately $55 million to $65 million. This program will allow for the ~~Senior Secured Credit Facility.~~

~~During 2016, LRAI issued $38.0 million in aggregate principal amount~~drilling of ~~Second Lien Notes~~a range of 10 gross (8.5 net) wells and the ~~Company issued~~completion of a range of 10 gross (7.0 net) wells, five of which were placed into production by the ~~Warrants to purchase 760,000 shares~~end of ~~its Class A voting common stock. The Company recorded~~the first quarter of 2020 and an ~~equity warrant liability~~additional three at Hawkeye which were placed into production by the end 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 millionJune 2020.

The table below summarizes our cash capital expenditures incurred for the three months ended ~~September 30, 2017. Proceeds from~~March 31, 2020:



In thousands	Three Months Ended March 31, 2020
Acquisition of oil and gas properties	$	816
Development of oil and gas properties	34,753
Purchases of other property and equipment	524
Total capital expenditures	$	36,093

For the Second Lien Notes issuance were used to repurchase approximately $68.2 million in aggregate principal amount of the 8.750% Senior Notes in privately negotiated open market repurchases with holders of such notes, and to pay related fees and expenses related to the foregoing. The repurchase amounts paid were approximately $36.2 million in cash. Net of related fees, such repurchases resulted in a gain on debt extinguishment of approximately $28.5 million.

In December 2016, LRAI repaid $21.0 million principal of the Second Lien Notes with proceeds from the 2016 Common Stock Offering. In June 2017, LRAI repaid the remaining $17.0 million principal of Second Lien Notes, including an early payment premium of approximately $1.1 million with borrowings from the Company’s Senior Secured Credit Facility. ~~The Company also recorded an approximate $2.0 million charge due to early recognition of the warrant discount associated with the payoff of the Second Lien Notes.~~

~~Capital Expenditures~~

~~Historical capital expenditures~~

~~The table below summarizes~~three months ended March 31, 2020, our capital expenditures ~~incurred for~~were funded with cash flow from operations, with additional funds provided by borrowings on our Credit Facility. Our 2020 capital expenditures may be further adjusted as business conditions warrant and the ~~periods listed below. Future~~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 ~~in 2017 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

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~~April 13, 2020 (our ~~“2016 10-K”~~"2019 10-K").

As of ~~September 30, 2017,~~March 31, 2020, 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 statements may include statements about our:

•

Our ability to refinance or remedy any future default under our Credit Facility, refinance or satisfy the obligations of our 2023 Notes or obtain additional sources of capital;

discovery and development of crude oil, NGLs and natural gas reserves;

•

cash flows 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~~performance of wells;

•

timing, location and size of property acquisitions and divestitures;

•

costs of exploiting and developing our properties and conducting other operations;

•

general economic and business conditions; and

•

our plans, objectives, expectations and intentions.

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~~2019 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 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~~2019 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 Company’s Annual Report on Form 10-K for the year ended December 31, 2019. As such, the information contained herein should be read in conjunction with the related disclosures in the Company’s Annual Report on Form 10-K for the year ended December 31, 2019.

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, 2020. 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	$	99,859	$	80,624	$	119,094

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.

Interest Rate Risk

As of March 31, 2020, we had $267.0 million outstanding under the Credit Facility, which is subject to floating market rates of interest. Borrowings under the Credit Facility bear interest at a fluctuating rate that is tied to an adjusted base rate or LIBOR, at our option. Any increase in this interest rate can have an adverse impact on our ~~market risks as~~results of ~~September 30, 2017 from those disclosed~~operations and cash flow. Based on borrowings outstanding at March 31, 2020, a 100-basis-point change in interest rates would change our ~~2016 10-K.~~

annualized interest expense by approximately $2.7 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 Credit Facility that will carry an investment-grade credit rating.

We are also subject to credit risk due to concentration of our oil and natural gas receivables with certain significant customers. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. We review the credit rating, payment history and financial resources of our customers, but we do not require our customers to post collateral.

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.

Evaluation of Disclosure Controls and ~~Procedures~~

~~Our management, with the participation of our Chief Executive Officer and Chief Financial Officer, evaluated, as~~Procedures.

As of the end of the period covered by this ~~Quarterly Report on Form 10-Q,~~report, an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in ~~Rules~~Rule 13a-15(e) ~~and 15d-15(e)~~ under the ~~Securities~~ Exchange ~~Act~~Act) was performed under the supervision and with the participation of ~~1934, as amended).~~management, including our Chief Executive Officer and Chief Accounting Officer. Based on that evaluation, our Chief Executive Officer and Chief ~~Financial~~Accounting Officer concluded that our disclosure controls and procedures were effective ~~at the reasonable assurance level~~ as of ~~September 30, 2017.~~

March 31, 2020 to ensure that information that is required to be disclosed in the reports the Company files and submits under the Securities Exchange Act of 1934 is recorded, that it is processed, summarized and reported within the time periods specified in the SEC’s rules and forms; and that information that is required to be disclosed under the Exchange Act is accumulated and communicated to management, including our Chief Executive Officer and our Chief Accounting Officer, as appropriate, to allow timely decisions regarding required disclosures.

Changes in Internal ~~Controls~~

~~There was~~Control over Financial Reporting.

During the first quarter of fiscal 2020, there were no ~~change~~changes in our internal control over financial reporting ~~during the quarter ended September 30, 2017~~ that have materially affected, or isare reasonably likely to materially affect, our internal control over financial reporting.

PART II—OTHER INFORMATION

Item 1. Legal Proceedings.

From time to time, we are subject to legal proceedings and claims that arise in the ordinary course of business. Like other crude oil and gas producers and marketers, our operations are subject to extensive and rapidly changing federal and state environmental, health and safety, and other laws and regulations governing air emissions, wastewater discharges and solid and hazardous waste management activities. We are not aware of any ~~material~~ pending or overtly threatened legal action against ~~us.~~

us that could have a material impact on our business.

Item 1A. Risk Factors.

~~In addition~~

Please refer to ~~the other information set forth in this report, you should carefully consider the factors discussed under~~ Item 1A of Part I of “Risk Factors” in our 2016 10-K. These factors could materially adversely affect our business, financial condition, liquidity, results of operations and capital position, and could cause our actual results to differ materially from our historical results or the ~~results contemplated by any forward-looking statements contained in this report.~~Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2019. There have been no material changes to our risk factors contained in our Annual Report on Form 10-K for the fiscal year ended December 31, 2019, other than as detailed below.

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

The COVID-19 pandemic has caused a rapid and precipitous drop in demand for oil, which in turn has caused oil prices to plummet since the first week of March 2020, negatively affecting the Company’s cash flow, liquidity and financial position. These events have worsened an already deteriorated oil market that resulted from the early-March 2020 failure by the group of oil producing nations known as OPEC+ to reach an agreement over proposed oil production cuts. Moreover, the uncertainty about the duration of the COVID-19 pandemic has caused storage constraints in the United States resulting from over-supply of produced oil, which is expected to significantly decrease our realized oil prices in the second quarter of 2020 and potentially beyond. Oil prices are expected to continue to be volatile as a result of these events and the ongoing COVID-19 outbreak, and as changes in oil inventories, oil demand and economic performance are reported. We cannot predict when oil prices will improve and stabilize.

The current pandemic and uncertainty about its length and depth in future periods has caused the realized oil prices we have received since February 2020 to be significantly reduced, adversely affecting our operating cash flow and liquidity. Although we have reduced our 2020 capital expenditures budget, our lower levels of cash flow may require us to shut-in production that has become uneconomic.

The COVID-19 pandemic is rapidly evolving, and the ultimate impact of this pandemic is highly uncertain and subject to change. The extent of the impact of the COVID-19 pandemic on our operational and financial performance will depend on future developments, including the duration and spread of the pandemic, its severity, the actions to contain the disease or mitigate its impact, related restrictions on travel, and the duration, timing and severity of the impact on domestic and global oil demand. The COVID-19 pandemic may also intensify the risks described in the other risk factors disclosed in our Annual Report on Form 10-K for the fiscal year ended December 31, 2019.

Our failure to comply with any of the covenants under our 11.25% Senior Notes could cause an event of default under the 11.25% Senior Notes, and, due to cross-default provisions, currently represents an event of default in Credit Facility and could have a material adverse effect on our business.

We did not make the July 1, 2020 interest payment under our 11.25% Senior Notes and are currently in default. Such failure will represent an event of default under the 11.25% Senior Notes if not cured in 30 days after July 1, 2020 at which time the holders of the 11.25% Senior Notes or the trustee may accelerate payment under the notes. Such failure currently represents an event of default under our revolving credit facility. The Company ~~since~~has entered into the ~~filing~~Forbearance Agreement which provides that, among other things, the lenders under the Credit Facility have agreed to forbear the Company’s default of the interest payment until July 31, 2020. However, the default under the Credit Facility has not been waived and still exists, and the Forbearance Agreement can be terminated if the Company fails to deliver a detailed restructuring proposal to the lenders by July 16, 2020. In addition, the holders of the 11.25% Senior Notes have not agreed to waive or forbear the interest payment default. Accordingly, the amounts outstanding under the 11.25% Senior Notes as of March 31, 2020 were classified as current in the accompanying Condensed Consolidated Balance Sheet.

The Company has concluded that these circumstances create substantial doubt regarding its ability to continue as a going concern. The Company does not anticipate maintaining compliance with certain covenants under its Credit Facility over the next twelve months and may not be able to restructure, refinance or otherwise satisfy its obligations under the 11.25% Senior Notes. The Company is therefore evaluating the available financial alternatives, including obtaining acceptable alternative financing as well as seeking additional waivers, forbearances or amendments to the covenants or other provisions of the Credit Facility and the 11.25% Senior Notes to address any existing or future defaults and have engaged financial and legal advisors to assist the Company. If the Company is unable to reach an agreement with its lenders or find acceptable alternative financing, the lenders of the Credit Facility or the holders of the 11.25% Senior Notes may choose to accelerate repayment. If the Company's lenders or its noteholders accelerate the payment of amounts outstanding under our Credit Facility or the 11.25% Senior Notes, respectively, the Company does not currently have sufficient liquidity to repay such indebtedness and would need additional sources of capital to do so.

The Company cannot provide any assurances that it will be successful in any restructuring of existing debt obligations or obtaining capital sufficient to fund the refinancing of its outstanding indebtedness or to provide sufficient liquidity to meet its operating needs. If the Company is unsuccessful in its efforts to restructure and obtain new financing, it may be necessary for it to seek protection from creditors under Chapter 11, or an involuntary petition for bankruptcy may be filed against it.

We may be subject to United States Bankruptcy Court proceedings in the near future, which would pose significant risks to our business and to our investors.

As we do not anticipate maintaining compliance with all covenants under our Credit Facility over the next twelve months, we evaluating the available financial alternatives, including obtaining acceptable alternative financing as well as seeking additional waivers, forbearances or amendments to the covenants or other provisions of the Credit Facility to address any existing or future defaults, and we have engaged financial and legal advisors to assist us. However, we cannot provide any assurances that we will be successful in any restructuring of existing debt obligations or obtaining capital sufficient to fund the refinancing of our ~~2016 10-K.~~

outstanding indebtedness or to provide sufficient liquidity to meet our operating needs. If our attempts are unsuccessful or we are unable to complete such a restructuring on satisfactory terms, we may choose to pursue a filing under Chapter 11. If an agreement is reached and we decide to pursue a restructuring, it may be necessary for us and certain of our affiliates to file voluntary petitions for relief under Chapter 11 in order to implement a restructuring through a plan of reorganization before the bankruptcy court. We may also conclude that it is necessary to initiate Chapter 11 proceedings to implement a restructuring of our obligations if we are unable to reach an agreement with our creditors and other relevant parties regarding the terms of such a restructuring, or if further events or developments arise that necessitate us seeking relief under Chapter 11. It may be necessary to commence such a bankruptcy case in the near future. Also, if an agreement is not reached, certain creditors could commence involuntary bankruptcy cases against us if we are not able to satisfy our obligations under our debt agreements, including our Credit Facility and the 11.25% Senior Notes.

So long as a bankruptcy case continues, our senior management would be required to spend a significant amount of time and effort dealing with the reorganization instead of focusing exclusively on our business operations. Bankruptcy cases also might make it more difficult to retain management and other personnel necessary to the success and growth of our business. In addition, the longer a bankruptcy case continues, the more likely it is that our customers, dealers and suppliers would lose confidence in our ability to reorganize our businesses successfully and would seek to establish alternative commercial relationships.

It is not possible to predict the outcome of any bankruptcy case that may occur. In the event of a bankruptcy case, there can be no assurance that we would be able to restructure as a going concern or successfully propose or confirm a plan of reorganization that provides for the continuation of the business post-bankruptcy.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.

~~None.~~

The following table summarizes purchases of our Class A Common Stock during the first quarter of 2020:



	Total number of Shares Purchased	Average Price Paid per Share		Total Number of Shares that May Yet Be Purchased as Part of Publicly Announced Plans or Programs	Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs
January 2020	—	—		—	—
February 2020	49,687	$	1.29	—	—
March 2020	67,932	0.45		—	—
Total	117,619			—

Stock repurchases during the first quarter of 2020 were made in connection with delivery by our employees of shares to us to satisfy their tax withholding requirements related to the vesting of restricted shares.

Item 3. ~~Defaults Upon Senior Securities.~~

~~None.~~

Default under Credit Facility.

The Company did not satisfy the consolidated current ratio covenant under the Company’s Credit Facility (as defined below) as of the March 31, 2020 measurement date and such failure represents an event of default under the Company's Credit Facility. We have obtained a forbearance under the Credit Facility for this default, among others, pursuant to the Forbearance Agreement. Despite the forbearance, the defaults are continuing, and will continue, absent a waiver from the lenders. For more information regarding the Credit Facility, see “Part I, Item ~~4. Mine Safety Disclosures.~~

~~Not applicable.~~

2. Management’s Discussion and Analysis of Financial Condition and Results of Operations-Liquidity and Capital Resources” and Note 1, Basis of Presentation - Going Concern.”

Item 5. Other ~~Information.~~

~~None.~~

~~Item 6. Exhibits.~~

~~The exhibits in the accompanying Exhibit Index following the signature page are filed or furnished as a part of this report and are incorporated herein by reference.~~

~~Exhibit~~ ~~Index~~

Incorporated by Reference .
Exhibit Number

Description

Form

File No.

Exhibit

Filing
Date

Filed/
Furnished
Herewith
2.1

Scheme Implementation Agreement, by and between Lonestar Resources US Inc. and Lonestar Resources Limited, executed on December 28, 2015

10-12B

001-37670

2.1

12/31/15

2.2

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

8-K

001-37670

2.1

6/2/17

2.3

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

8-K

001-37670

2.1

6/21/17

2.4

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

8-K

001-37670

2.2

6/2/17

2.5

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

8-K

001-37670

2.2

6/21/17

3.1

Certificate of Incorporation of Lonestar Resources US Inc.

10-12B

001-37670

3.1

12/31/15

3.2

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

10-K

001-37670

3.2

3/23/17

3.3

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

8-K

001-37670

3.1

5/26/17

3.4

Amended and Restated Bylaws of Lonestar Resources US Inc.

8-K

001-37670

3.1

4/7/17

3.5

Certificate of Designations of Series B Convertible Preferred Stock

8-K

001-37670

3.1

6/21/17

3.6

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

8-K

001-37670

3.2

6/21/17

3.7

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

8-K

001-37670

3.3

6/21/17

4.1

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

8-K

001-37670

4.1

8/3/16

4.2

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

8-K

001-37670

4.4

6/21/17

4.3

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

8-K

001-37670

4.1

11/1/16

4.4

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

8-K

001-37670

4.5

6/21/17

4.5

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

8-K

001-37670

4.1

6/21/17

Information

4.6

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

8-K

001-37670

4.2

6/21/17

4.7

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

8-K

001-37670

4.3

6/21/17

10.1

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

8-K

001-37670

10.1

5/26/17

10.2

Securities Purchase Agreement by and between Lonestar Resources US Inc., and Chambers Energy Capital III, LP, dated May 26, 2017

8-K

001-37670

10.1

6/2/17

10.3

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

8-K

001-37670

10.1

6/21/17

10.4

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

8-K

001-37670

10.2

6/21/17

31.1

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

*
31.2

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

*
32.1

Section 1350 Certification of Chief Executive Officer

**
32.2

Section 1350 Certification of Chief Financial Officer

**
101.INS

XBRL Instance Document

*
101.SCH

XBRL Taxonomy Extension Schema Document

*
101.CAL

XBRL Taxonomy Extension Calculation Linkbase Document

*
101.DEF

XBRL Taxonomy Extension Definition Linkbase Document

*
101.LAB

XBRL Taxonomy Extension Label Linkbase Document

*
101.PRE

XBRL Taxonomy Extension Presentation Linkbase Document

*
On June 29, 2020, the Company entered into Eligibility Notification Letters (the “Eligibility Notification Letters”) with each of our named executive officers, including Frank D. Bracken III, our chief executive officer and Barry D. Schneider, our chief operating officer, in connection with the Lonestar Resources US Inc. Change in Control Severance Plan (the “CIC Plan”) that was adopted by our board of directors. Under the Plan and the Eligibility Notification Letters, eligible participants will be entitled to severance payments and benefits in the event their employment is terminated by us without cause or they resign for good reason, in either case within two years following or two and one-half months prior to a change in control of the Company, subject to the participant’s execution and non-revocation of a release of claims in favor of the Company. For Mr. Bracken, the cash severance payments would be equal to three times his annual base salary and target bonus amount and monthly COBRA premiums for three years. For Mr. Schneider, the cash severance payments would be equal to two times his annual base salary and target bonus amount and monthly COBRA premiums for two years. In addition, each participant’s outstanding equity incentive awards would vest in full, subject to attainment of relevant performance goals for performance-based awards. The foregoing descriptions are qualified in their entirety to the text of the CIC Plan and Eligibility Notification Letters, the forms of which are attached as exhibits to this report.

*	~~Filed herewith.~~

Item 6. Exhibits.

Exhibit Number

Description

Incorporated by Reference

Filing

Date

Filed/

Furnished

Herewith

Form

File No.

Exhibit

10.1

Twelfth Amendment to Credit Agreement

8-K

001-37670

10.1

5/11/20

10.2

Waiver and Thirteenth Amendment to Credit Agreement

8-K

001-37670

10.1

6/17/20

10.3

Forbearance Agreement, Fourteenth Amendment, and Borrowing Base Agreement

10.4†

Lonestar Resources US. Inc. Change in Control Severance Plan

10.5†

Lonestar Resources US Inc. Change in Control Severance Plan Eligibility Notification (Executive)

31.1

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

31.2

Rule 13a-14(a)/15d-14(a) Certification of Chief Accounting Officer

32.1

Section 1350 Certification of Chief Executive Officer

32.2

Section 1350 Certification of Chief Accounting Officer

101.INS

XBRL Instance Document

101.SCH

XBRL Taxonomy Extension Schema Document

101.CAL

XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF

XBRL Taxonomy Extension Definition Linkbase Document

101.LAB

XBRL Taxonomy Extension Label Linkbase Document

101.PRE

XBRL Taxonomy Extension Presentation Linkbase Document

~~Furnished herewith~~


*	Filed herewith.


**	Furnished herewith


†	Management contract or compensatory plan or arrangement

~~SIGNATURES~~

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.



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

~~Date: November 13, 2017~~ July 2, 2020		~~By:~~	/s/ Frank D. Bracken, III
			Frank D. Bracken, III
			Chief Executive Officer

~~Date: November 13, 2017~~ July 2, 2020		~~By:~~	/s/ ~~Douglas W. Banister~~ Jason N. Werth
			~~Douglas W. Banister~~
			Jason N. Werth Chief ~~Financial~~Accounting Officer

	September 30, 2017		December 31, 2016
Assets	(Unaudited)

Current assets
Cash and cash equivalents	$	4,812	$	6,068
Accounts receivable:
Oil, natural gas liquid and natural gas sales		10,398		4,680
Joint interest owners and other, net		965		867
Related parties		245		847
Derivative financial instruments		3,121		1,730
Prepaid expenses and other		5,709		2,631

Total current assets		25,250		16,823

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 assets	$	595,246	$	459,109

	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 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