UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-Q

(Mark One)

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, 2019

OR

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

For the transition period from      to

Commission File Number: 001-37670

Lonestar Resources US Inc.

(Exact Name of Registrant as Specified in its Charter)

Delaware	81-0874035
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
111 Boland Street, Suite 301, Fort Worth, TX	76107
(Address of principal executive offices)	(Zip Code)

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

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.

Large accelerated filer	☐	Accelerated filer	ý
Non-accelerated filer	☐	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 11, 2019, the registrant had 24,944,891 shares of Class A voting common stock, par value $0.001 per share, outstanding.

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Table of Contents

		Page
PART I.	FINANCIAL INFORMATION
Item 1.	Financial Statements	1
	Unaudited Condensed Consolidated Balance Sheets at September 30, 2019 and December 31, 2018	1
	Unaudited Condensed Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2019 and 2018	2
	Unaudited Condensed Consolidated Statements of Changes in Stockholders' Equity for the Three and Nine Months Ended September 30, 2019 and 2018	3
	Unaudited Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2019 and 2018	4
	Notes to Unaudited Condensed Consolidated Financial Statements	5
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	20
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	34
Item 4.	Controls and Procedures	35
PART II.	OTHER INFORMATION	36
Item 1.	Legal Proceedings	36
Item 1A.	Risk Factors	36
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	36
Item 6.	Exhibits	37
Signatures		38

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PART I—FINANCIAL INFORMATION

Item 1. Financial Statements

Lonestar Resources US Inc.

Unaudited Condensed Consolidated Balance Sheets

(In thousands, except par value and share data)

	September 30, 2019			December 31, 2018
Assets
Current assets
Cash and cash equivalents	$	3,441		$	5,355
Accounts receivable
Oil, natural gas liquid and natural gas sales	16,594			15,103
Joint interest owners and others, net	5,159			4,541
Related parties	5,213			301
Derivative financial instruments	15,798			15,841
Prepaid expenses and other	2,844			1,966
Total current assets	49,049			43,107
Property and equipment
Oil and gas properties, using the successful efforts method of accounting
Proved properties	1,009,545			960,711
Unproved properties	80,565			81,850
Other property and equipment	21,344			17,727
Less accumulated depreciation, depletion and amortization	(392,604		)	(369,529		)
Property and equipment, net	718,850			690,759
Derivative financial instruments	9,857			7,302
Other non-current assets	2,457			2,944
Total assets	$	780,213		$	744,112
Liabilities and Stockholders' Equity
Current liabilities
Accounts payable	$	34,363		$	18,260
Accounts payable – related parties	251			181
Oil, natural gas liquid and natural gas sales payable	15,286			13,022
Accrued liabilities	16,100			28,128
Derivative financial instruments	3,271			430
Total current liabilities	69,271			60,021
Long-term liabilities
Long-term debt	499,772			436,882
Asset retirement obligations	7,139			7,195
Deferred tax liabilities, net	5,387			12,370
Warrant liability	162			366
Warrant liability – related parties	299			689
Derivative financial instruments	4			21
Other non-current liabilities	3,360			4,021
Total long-term liabilities	516,123			461,544
Commitments and contingencies (Note 12)
Stockholders' Equity
Class A voting common stock, $0.001 par value, 100,000,000 shares authorized, 24,933,853 and 24,645,825 issued and outstanding, respectively	142,655			142,655
Series A-1 convertible participating preferred stock, $0.001 par value, 98,120 and 91,784 shares issued and outstanding, respectively	—			—
Additional paid-in capital	175,709			174,379
Accumulated deficit	(123,545		)	(94,487		)
Total stockholders' equity	194,819			222,547
Total liabilities and stockholders' equity	$	780,213		$	744,112

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

1

Lonestar Resources US Inc.

Unaudited Condensed Consolidated Statements of Operations

(In thousands, except per share data)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018
Revenues
Oil sales	$	42,187		$	47,846		$	120,496		$	120,705
Natural gas liquid sales	3,439			6,795			10,381			12,939
Natural gas sales	7,519			4,096			15,224			9,637
Total revenues	53,145			58,737			146,101			143,281
Expenses
Lease operating and gas gathering	10,055			6,687			26,695			17,761
Production and ad valorem taxes	3,017			3,218			8,126			8,145
Depreciation, depletion and amortization	24,635			23,775			64,120			59,937
Loss on sale of oil and gas properties	483			—			33,530			1,568
Impairment of oil and gas properties	—			12,169			—			12,169
General and administrative	4,124			4,661			12,345			13,385
Acquisition costs and other	(2		)	315			(4		)	302
Total expenses	42,312			50,825			144,812			113,267
Income from operations	10,833			7,912			1,289			30,014
Other expense
Interest expense	(11,295		)	(10,215		)	(32,730		)	(28,771		)
Change in fair value of warrants	(100		)	509			594			(2,105		)
Gain (loss) on derivative financial instruments	21,546			(18,198		)	(5,177		)	(54,852		)
Loss on extinguishment of debt	—			—			—			(8,619		)
Total other expense	10,151			(27,904		)	(37,313		)	(94,347		)
Income (loss) before income taxes	20,984			(19,992		)	(36,024		)	(64,333		)
Income tax (expense) benefit	(4,767		)	282			6,966			6,493
Net income (loss)	16,217			(19,710		)	(29,058		)	(57,840		)
Preferred stock dividends	(2,159		)	(1,975		)	(6,336		)	(5,796		)
Net income (loss) attributable to common stockholders	$	14,058		$	(21,685	)	$	(35,394	)	$	(63,636	)
Net income (loss) per common share
Basic	$	0.34		$	(0.88	)	$	(1.42	)	$	(2.59	)
Diluted	$	0.33		$	(0.88	)	$	(1.42	)	$	(2.59	)
Weighted average common shares outstanding
Basic	24,933,853			24,599,744			24,852,994			24,598,816
Diluted	25,331,810			24,599,744			24,852,994			24,598,816

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

2

Lonestar Resources US Inc.

Unaudited Condensed Consolidated Statements of Changes in Stockholders’ Equity

(In thousands, except share data)

	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, 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
Payment-in-kind dividends	—		—			2,112	—			—			—				—
Stock-based compensation	160,210		—			—	—			703			—				703
Net income	—		—			—	—			—			13,289				13,289
Balance at June 30, 2019	24,933,853		142,655			95,961	—			175,709			(139,762		)		178,602
Payment-in-kind dividends	—		—			2,159	—			—			—				—
Net income	—		—			—	—			—			16,217				16,217
Balance at September 30, 2019	24,933,853		$	142,655		98,120	$	—		$	175,709		$	(123,545	)		$	194,819

	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, 2017	24,506,647	$	142,655	83,968	$	—	$	174,871		$	(113,836	)	$	203,690
Payment-in-kind dividends	—	—		1,889	—		—			—			—
Issued pursuant to stock-based compensation plan	127,666	—		—	—		(610		)	—			(610		)
Stock-based compensation	—	—		—	—		216			—			216
Net loss	—	—		—	—		—			(16,537		)	(16,537		)
Balance at March 31, 2018	24,634,313	142,655		85,857	—		174,477			(130,373		)	186,759
Payment-in-kind dividends	—	—		1,932	—		—			—			—
Issued pursuant to stock-based compensation plan	—	—		—	—		9			—			9
Stock-based compensation	2,814	—		—	—		(17		)	—			(17		)
Net loss	—	—		—	—		—			(21,593		)	(21,593		)
Balance at June 30, 2018	24,637,127	142,655		87,789	—		174,469			(151,966		)	165,158
Payment-in-kind dividends	—	—		1,975	—		—			—			—
Retirement of Class B Common Stock	—	—		—	—		(10		)	—			(10		)
Net loss	—	—		—	—		—			(19,710		)	(19,710		)
Balance at September 30, 2018	24,637,127	$	142,655	89,764	$	—	$	174,459		$	(171,676	)	$	145,438

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

3

Lonestar Resources US Inc.

Unaudited Condensed Consolidated Statements of Cash Flows

(In thousands)

	Nine Months Ended September 30,
	2019			2018
Cash flows from operating activities
Net loss	$	(29,058	)	$	(57,840	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization	64,120			59,937
Stock-based compensation	1,294			3,637
Stock-based payments	—			(601		)
Deferred taxes	(6,983		)	(7,145		)
Loss on derivative financial instruments	5,177			54,852
Settlements of derivative financial instruments	(3,858		)	(16,323		)
Impairment of oil and natural gas properties	—			12,169
Gain on disposal of property and equipment	(17		)	—
Loss on abandoned property and equipment	—			171
Loss on sale of oil and gas properties	33,530			—
Non-cash interest expense	1,822			4,556
Change in fair value of warrants	(594		)	2,105
Changes in operating assets and liabilities:
Accounts receivable	(8,330		)	(4,596		)
Prepaid expenses and other assets	(1,102		)	(1,835		)
Accounts payable and accrued expenses	(3,128		)	6,733
Net cash provided by operating activities	52,873			55,820
Cash flows from investing activities
Acquisition of oil and gas properties	(5,239		)	(4,762		)
Development of oil and gas properties	(119,273		)	(122,691		)
Proceeds from sale of oil and gas properties	11,470			—
Purchases of other property and equipment	(3,527		)	(1,631		)
Net cash used in investing activities	(116,569		)	(129,084		)
Cash flows from financing activities
Proceeds from borrowings	114,000			348,744
Payments on borrowings	(52,218		)	(273,466		)
Repurchase and retire Class B Common Stock	—			(10		)
Net cash provided by financing activities	61,782			75,268
Net (decrease) increase in cash and cash equivalents	(1,914		)	2,004
Cash and cash equivalents, beginning of the period	5,355			2,538
Cash and cash equivalents, end of the period	$	3,441		$	4,542
Supplemental information:
Cash paid for taxes	$	—		$	1,147
Cash paid for interest	28,125			22,324
Non-cash investing and financing activities:
Change in asset retirement obligation	$	(292	)	$	222
Change in liabilities for capital expenditures	9,098			16,988

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

4

Lonestar Resources US Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

Note 1. Basis of Presentation

Organization and Nature of Operations

Lonestar Resources US Inc. (“Lonestar” or the "Company") is a Delaware 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 focused on the exploration, development and production of unconventional oil, natural gas liquids and natural gas in the Eagle Ford Shale play in South Texas.

Interim Financial Statements

The accompanying unaudited condensed consolidated financial statements of Lonestar Resources US Inc., and its subsidiaries have been prepared in accordance with the rules and regulations of the Securities and Exchange Commission (“SEC”) and do not include all of the information and footnotes required by accounting principles generally accepted in the United States 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, 2018 filed on March 13, 2019 (the “Form 10-K”). Unless indicated otherwise or the context requires, the terms “we,” “our,” “us,” “Company” or “Lonestar,” refer to Lonestar Resources US Inc. and its subsidiaries.

The results of operations for the interim periods shown in this report are not necessarily indicative of results to be expected for the year.  In management’s opinion, the accompanying unaudited condensed consolidated financial statements include all adjustments of a normal recurring nature necessary for a fair statement of our consolidated financial position as of September 30, 2019 and our consolidated results of operations for the three and nine months ended September 30, 2019 and 2018.

Net Income (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 weighted average number of common shares and participating securities outstanding for the period.

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

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

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The following is a reconciliation of basic and diluted earnings per share:

In thousands, except shares and per-share data	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018
Numerator - Basic
Net income (loss) attributable to common stockholders	$	14,058		$	(21,685	)	$	(35,394	)	$	(63,636	)
Less: allocation to participating securities	(5,494		)	—			—			—
Net income (loss) allocated to common stockholders - basic	$	8,564		$	(21,685	)	$	(35,394	)	$	(63,636	)
Numerator - Diluted
Net income (loss) allocated to common stockholders - basic	$	8,564		$	(21,685	)	$	(35,394	)	$	(63,636	)
Restricted stock unit compensation gain, net of tax	(80		)	—			—			—
Net income (loss) allocated to common stockholders - diluted	$	8,484		$	(21,685	)	$	(35,394	)	$	(63,636	)
Denominator
Weighted average number of common shares - basic	24,933,853			24,599,744			24,852,994			24,598,816
Restricted stock units converted under the treasury stock method	397,957			—			—			—
Weighted average number of common shares - diluted	25,331,810			24,599,744			24,852,994			24,598,816
Earnings per share
Basic	$	0.34		$	(0.88	)	$	(1.42	)	$	(2.59	)
Diluted	$	0.33		$	(0.88	)	$	(1.42	)	$	(2.59	)

The following weighted average securities could potentially dilute earnings per share for the periods indicated, but were excluded from the computation of diluted net income (loss) per share, as their effect would have been antidilutive:

	Three Months Ended September 30,		Nine Months Ended September 30,
	2019	2018	2019	2018
Preferred stock	15,997,411	14,635,078	15,649,269	14,316,581
Warrants	760,000	760,000	760,000	760,000
Stock appreciation rights	1,010,000	1,017,500	1,010,000	901,108
Restricted stock units	—	1,037,209	1,457,701	890,744

Recent Accounting Pronouncements

Leases. In February 2016, the FASB issued Accounting Standards Update ("ASU") 2016-02, Leases ("ASU 2016-02"). The standard requires lessees to recognize a right of use asset ("ROU asset") and lease liability on the balance sheet for the rights and obligations created by leases. ASU 2016-02 also requires disclosures designed to give financial statement users information on the amount, timing, and uncertainty of cash flows arising from leases. In July 2018, the FASB issued ASU 2018-11, Leases (Topic 842): Targeted Improvements ("ASU 2018-11"), which provides for an alternative transition method by allowing entities to initially apply the new leases standard at the adoption date, January 1, 2019, and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. Comparative periods presented in the financial statements continue to be in accordance with ASC Topic 840, Leases.

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In the normal course of business, the Company enters into lease agreements to support its exploration and development operations and lease assets, such as drilling rigs, field services, well equipment, office space and other assets. The Company adopted the new standard on the effective date of January 1, 2019, using a modified retrospective approach as permitted under ASU 2018-11.

The new standard provides a number of optional practical expedients in transition. The Company:

• elected the package of 'practical expedients', which permits the Company not to reassess, under the new standard, its prior conclusions about lease identification, lease classification and initial direct costs;

• elected the practical expedient pertaining to land easements and plan to account for existing land easements under the Company's current accounting policy;

• elected the short-term lease recognition exemption for all leases that qualify and, as such, no ROU asset or lease liability has been recorded on the balance sheet and no transition adjustment has been required for short-term leases; and

• elected the practical expedient to not separate lease and non-lease components for all of the Company's leases.

The Company did not elect the hindsight practical expedient in determining the lease term and assessing impairment of ROU assets when transitioning to ASU 2016-02.

Upon adoption, the Company recognized additional operating lease liabilities of approximately $0.3 million with corresponding ROU assets. See Note 4. Leases for more information.

Note 2. Acquisitions and Divestitures

Pirate Divestiture

On March 22, 2019, Lonestar completed the divestiture of its Pirate assets in Wilson County for $12.3 million, before closing adjustments, to a private third-party. The assets were comprised of 3,400 net undeveloped acres, six producing wells, held seven proved undeveloped locations as of the closing date, and were producing approximately 200 BOE/d. The Company recognized a loss of $33.5 million during the first quarter of 2019 in conjunction with the sale of the assets.

Sooner Acquisition

On November 15, 2018, Lonestar completed the acquisition of oil and gas properties in the Sugarkane Field in DeWitt County, Texas, for $38.7 million, before closing adjustments, from Sabine Oil & Gas Corporation and Alerion Gas AXA, LLC (the “Sooner Acquisition”). The acquisition was financed with funds available from our Credit Facility, as well as cash from operations. The Sooner Acquisition was accounted for as an asset acquisition applying the guidance of ASU 2017-01. As such, the properties were recorded based on the fair value of the total consideration transferred on the acquisition date, and all of the value of the transaction was allocated to proved oil and gas properties. Transaction costs of $0.3 million were capitalized as a component of the cost of the assets acquired.

Corporate Headquarters

On August 2, 2017, the Company closed on the purchase of an office building in Fort Worth, Texas, with an acquisition price approximating $10.0 million, to which the Company relocated its corporate operations in February 2018. In light of the relocation, the Company recorded an impairment charge of $1.6 million in Acquisition Costs and Other expense on the Unaudited Condensed Consolidated Statement of Operations during the first quarter of 2018, primarily reflecting the remaining future minimum rentals of the lease for the Company’s prior corporate office from the date of relocation to the end of the remaining lease term.

In February 2019, the Company acquired an adjacent property for $2.0 million. The property was acquired for future expansion.

7

Note 3. Commodity Price Risk Activities

Lonestar enters into certain commodity derivative instruments to mitigate commodity price risk associated with a portion of its future oil, NGL and natural gas production and related cash flows. The oil, NGL and natural gas revenues and cash flows are affected by changes in commodity product prices, which are volatile and cannot be accurately predicted. The objective for entering into these commodity derivatives is to protect the operating revenues and cash flows related to a portion of the future oil, NGL and natural gas sales from the risk of significant declines in commodity prices, 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 does not currently require cash collateral from any of its counterparties nor does its counterparties require cash collateral from the Company. As of September 30, 2019, the Company had no open physical delivery obligations.The following table summarizes Lonestar's commodity derivative contracts as of September 30, 2019:

	Contract			Volumes	Weighted
Commodity	Type	Period	Range (1)	(Bbls/Mcf per day)	Average Price
Oil - WTI	Swaps	Oct - Dec 2019	$48.04 - $69.57	7,212	$	54.54
Oil - Argus WTI (2)	Basis Swaps	Oct - Dec 2019	5.00 - 5.55	6,000	5.05
Oil - WTI	Swaps	Jan - Dec 2020	48.90 - 65.56	7,480	56.95
Oil - WTI	Swaps	Jan - Dec 2021	51.05 - 56.50	3,000	54.68
Natural Gas - Henry Hub	Swaps	Oct - Dec 2019	2.76 - 2.98	15,000	2.87
Natural Gas - Henry Hub	Swaps	Jan - Dec 2020	2.59 - 2.59	15,000	2.59

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

(2) Basis swap contracts establish a fixed amount for the differential between Argus WTI and Argus LLS prices on a trade-month basis for the period indicated.

During October 2019, the Company entered into additional oil swaps for January through December of 2021, which hedge 365,000 bbls at $51.69 per bbl. During November 2019, the Company entered into additional natural gas swaps for January through December of 2021, which hedge 1,830,000 MMcf at an average price of $2.54 per Mcf.

As of September 30, 2019, 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. Leases

Effective January 1, 2019, the Company adopted the new lease accounting standard (see Recent Accounting Pronouncements in Note 1. above) using the modified retrospective method of applying the new standard at the adoption date. Adoption of this standard resulted in the recording of net operating lease ROU assets and corresponding operating lease liabilities of $0.3 million. Leases for reporting periods beginning on or after January 1, 2019 are presented under the new guidance, while prior periods amounts are not adjusted and continue to be reported in accordance with previous guidance.

Operating lease ROU assets are presented within Other Property and Equipment on the unaudited condensed consolidated balance sheet as of September 30, 2019. The current portion of operating lease liabilities are presented within Accrued Liabilities, and the non-current portion of operating lease liabilities are presented within Other Non-Current Liabilities on the unaudited condensed consolidated balance sheet.

Operating lease ROU assets and operating lease liabilities are recognized based on the present value of the future minimum lease payments over the lease term at commencement date. As most of the Company's leases do not provide an implicit rate, the Company uses an incremental collateralized borrowing rate based on the information available at commencement date, including lease term, in determining the present value of future payments. The operating lease ROU asset also includes any lease payments made and excludes lease incentives and initial direct costs incurred. The Company's lease

8

terms may include options to extend or terminate the lease when it is reasonably certain that the option will be exercised. Operating lease expense is recognized on a straight-line basis over the lease term.

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

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

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

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

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

The components of our total lease expense for the three and nine months ended September 30, 2019 are as follows:

In thousands	Three Months Ended September 30, 2019		Nine Months Ended September 30, 2019
Operating Leases	$	68	$	205
Short-term leases(1)	799		2,058
Total lease expense	$	867	$	2,263
Short-term lease costs capitalized to oil and gas properties(2)	$	4,904	$	9,827

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

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

Supplemental balance sheet information related to leases follows:

In thousands, except lease term and discount rate data	September 30, 2019
Operating leases
Assets
Other property and equipment	$	112
Liabilities
Accrued liabilities	$	112
Weighted-average remaining lease term (years)	0.4
Weighted-average discount rate	5.0		%

9

Supplemental cash flow information related to leases follows:

In thousands	Nine Months Ended September 30, 2019
Cash paid for amounts included in the measurement of lease liabilities
Operating cash flows for operating leases	$	205
Right-of-use assets obtained in exchange for lease obligations:
Operating leases	$	205

The table below reconciles the undiscounted cash flows for each of the first five years and total of the remaining years to the operating lease liabilities recorded on the unaudited condensed consolidated balance sheet as of September 30, 2019:

In thousands	Operating Leases
2019	$	68
2020	45
Thereafter	—
Total minimum lease payments	113
Amount of lease payments representing interest	(1		)
Present value of future minimum lease payments	$	112

Under the previous accounting standard, future minimum lease payments for operating leases having initial or remaining noncancelable terms in excess of one year would have been as follows as of September 30, 2019:

In thousands	Amount
2019	$	174
2020	477
2021	368
Total minimum lease payments	$	1,019

Note 5. Revenue Recognition

Operating revenues are comprised of sales of crude oil, NGLs and natural gas, as presented in the accompanying unaudited consolidated statements of operations for the three and nine months ended September 30, 2019 and 2018.

Accounting Policies

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

Oil Revenues

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

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

NGLs and Natural Gas Revenues

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

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

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

Production Imbalances

Revenue is recorded based on the Company’s share of volumes sold, regardless of whether the Company has taken its proportional share of volumes produced. A receivable or liability is recognized only to the extent that the Company has an imbalance on a specific property greater than the expected remaining proved reserves. There were no imbalances at September 30, 2019.

Significant Judgements

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

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

Prior-Period Performance Obligations

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

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

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Accounts Receivable and Other

Accounts receivable – Oil, natural gas liquid and natural gas sales consist of amounts due from purchasers for commodity sales from our Eagle Ford fields. Payments from purchasers are typically due by the last day of the month following the month of delivery. There was no bad debt expense for any period presented, and an allowance for uncollectible accounts is unnecessary. The Company’s operations do not result in any contract assets or liabilities on the accompanying consolidated balance sheets.

Note 6. Fair Value Measurements

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

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

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

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

The following table presents the Company’s assets and liabilities that are measured at fair value on a recurring basis as of September 30, 2019 and December 31, 2018, for each fair value hierarchy level:

	Fair Value Measurements Using
In thousands	Quoted Prices in Active Markets (Level 1)			Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)			Total
September 30, 2019
Assets
Commodity derivatives	$	—		$	25,655		$	—		$	25,655
Liabilities:
Commodity derivatives	—			(3,275		)	—			(3,275		)
Warrant	—			—			(461		)	(461		)
Stock-based compensation	(1,287		)	—			(579		)	(1,866		)
Total	$	(1,287	)	$	22,380		$	(1,040	)	$	20,053
December 31, 2018
Assets:
Commodity derivatives	$	—		$	23,143		$	—		$	23,143
Liabilities:
Commodity derivatives	—			(451		)	—			(451		)
Warrant	—			—			(1,055		)	(1,055		)
Stock-based compensation	(1,267		)	—			(636		)	(1,903		)
Total	$	(1,267	)	$	22,692		$	(1,691	)	$	19,734

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Commodity Derivatives

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

Warrants

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

Stock-Based Compensation

The Company's stock-based compensation includes the liability associated with restricted stock units ("RSUs") and stock appreciation rights ("SARs") dependent on the fair value of Lonestar's publicly-traded common stock. The fair value of RSUs is measured based on measurable prices on a major exchange; the significant inputs to these asset exchange values represented Level 1 independent active exchange market price inputs. The Black-Scholes model used to determine the fair value of the SARs uses inputs, in addition to the Company's observable stock price, that are considered unobservable; to this end the Company has designated these estimates as Level 3. See Note 10. Stock-Based Compensation, below for more information.

Level 3 Gains and Losses

The table below sets forth a summary of changes in the fair value of the Company’s Level 3 liabilities for the nine months ended September 30, 2019:

In thousands	Warrant			Stock-Based Compensation			Total
Balance as of December 31, 2018	$	(1,055	)	$	(636	)	$	(1,691	)
Unrealized gains	594			57			651
Balance as of September 30, 2019	$	(461	)	$	(579	)	$	(1,040	)

Assets and liabilities measured at fair value on a nonrecurring basis

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

Other fair value measurements

The book values of cash and cash equivalents, accounts receivable and accounts payable, approximate fair value due to the short-term nature of these instruments. The carrying value of the Credit Facility (as defined in Note 8. below) approximates fair value since it is subject to a short-term floating interest rate that approximates the rate available to the Company. The fair value of the 11.25% Senior Notes (as defined in Note 8. below) was approximately $214.8 million as of September 30, 2019 and are considered a Level 3 liability, as they are based on market transactions that occur infrequently as well as internally generated inputs.

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Note 7. Accrued Liabilities

Accrued liabilities consisted of the following as of the dates indicated:

In thousands	September 30, 2019		December 31, 2018
Bonus payable	$	1,744	$	3,244
Payroll payable	51		773
Accrued interest – 11.25% Senior Notes	7,031		14,063
Accrued interest – other	478		104
Accrued well costs	3,074		9,026
Third party payments for joint interest expenditures	140		—
Accrued severance, property and franchise taxes	2,356		96
Accrued federal income tax	439		441
Current portion of operating lease liability	112		—
Other	675		381
Total accrued liabilities	$	16,100	$	28,128

Note 8. Long-Term Debt

The following long-term debt obligations were outstanding as of the dates indicated:

In thousands	September 30, 2019			December 31, 2018
Senior Secured Credit Facility	$	245,000		$	183,000
11.25% Senior Notes due 2023	250,000			250,000
Mortgage debt	8,959			9,151
Other	266			275
Total long-term debt	504,225			442,426
Unamortized discount	(3,656		)	(4,500		)
Unamortized debt issuance costs	(797		)	(1,044		)
Total long-term debt, net of debt issuance costs	$	499,772		$	436,882

Senior Secured Credit Facility

In July 2015, the Company, through its subsidiary Lonestar Resources America, Inc. ("LRAI"), entered into a $500 million Senior Secured Credit Facility 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 November 15, 2023. As of September 30, 2019, $245.0 million was borrowed under the Credit Facility, and the weighted average interest rate on borrowings under the Credit Facility for the quarter was 5.32%. Borrowing availability was $44.6 million as of September 30, 2019, which reflects $0.4 million of letters of credit outstanding.

The Credit Facility may be used for loans and, subject to a $2.5 million sub-limit, letters of credit, and provides for a commitment fee of 0.375% to 0.5% based on the unused portion of the borrowing base under the Credit Facility. As of September 30, 2019, the borrowing base and lender commitments for the Credit Facility was $290 million. The borrowing base under the Credit Facility is determined semi-annually as of May 1 and November 1. As of November 11, 2019, the November 1 determination was ongoing and the prospective borrowing base amount had not been concluded upon with the lenders.

In June 2019, the Company entered into the Borrowing Base Redetermination and Tenth Amendment to Credit Agreement (the "Tenth Amendment"), which (i) increased the borrowing base from $275 million to $290 million and (ii) amended certain other provisions of the Credit Facility, as set forth more specifically in the Tenth Amendment.

The Company was in compliance with the terms of the Credit Facility as of September 30, 2019.

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Issuance of 11.25% Senior Notes

In January 2018, the Company issued $250 million of 11.250% senior notes due 2023 (the “11.25% Senior Notes”) to U.S.-based institutional investors. The net proceeds of $244.4 million were used to fully retire the 8.75% Senior Notes (as defined below), 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. At any time prior to January 1, 2021, the Company may, on any one or more occasions, redeem up to 35% of the aggregate principal amount of the 11.25% Senior Notes with an amount of cash not greater than the net cash proceeds of certain equity offerings at a redemption price equal to 111.25% of 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 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.

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 merger, or sell substantially all of the Company’s assets.

Retirement of 8.75% Senior Notes

Using proceeds from the issuance of the 11.25% Senior Notes, as discussed above, the Company fully retired the 8.750% Senior Unsecured Notes due April 15, 2019 (“the 8.75% Senior Notes”) in January 2018. Pursuant to the terms of the indenture, the 8.75% Senior Notes were redeemed at 104.375% of the outstanding principal amount, or approximately $158.5 million, which excluded accrued interest. In connection with this transaction, the Company recognized a $8.6 million loss on extinguishment during the first quarter of 2018.

Debt Issuance Costs

The Company capitalizes certain direct costs associated with the issuance of long-term debt and amortizes such costs over the lives of the respective debt. At September 30, 2019 and December 31, 2018, the Company had approximately $1.0 million and $1.7 million, respectively, of debt issuance costs associated with issuance of the Credit Facility remaining that are being amortized over the lives of the respective debt which are recorded as Other Non-Current Assets in the accompanying unaudited condensed consolidated balance sheets.

Note 9. Stockholders’ Equity

Series A & B Preferred Stock

In June 2017, the Company closed on acquisitions with Battlecat Oil & Gas, LLC ("Battlecat") and SN Marquis LLC ("Marquis"). In connection with financing the Battlecat and Marquis Acquisitions, the Company issued 5,400 shares of Series A-1 Convertible Participating Preferred Stock, par value $0.001 per share (the “Series A-1 Preferred Stock”) and 74,600 shares of 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”), to Chambers Energy Capital (“Chambers”). Also in June 2017, in connection with the Battlecat and Marquis Acquisitions, the Company issued 1,184,632 and 1,500,000 shares of Series B Preferred Stock to Battlecat and Marquis.

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As a result of the stockholder approval obtained in November 2017, all outstanding Series A-2 Preferred Stock was converted to Series A-1 Preferred Stock. Also, on November 3, 2017, in accordance with the terms of the Series B Certificate of Designations, all of the outstanding shares of the Company’s Series B Preferred Stock were converted on a one-for-one basis into shares of the Company’s Class A voting common stock.

After the Chambers agreement closing, and for so long as the Approved Holders (as defined) beneficially own at least 10% of the total number of outstanding shares of Class A voting common stock and Class B non-voting common stock (collectively, “Common Stock”) of the Company, on an as-converted basis, or at least 15% of the number of Series A Preferred Stock issued to Chambers, 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 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.

The Series A-1 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 the series initially has a stated value of $1,000 per share. Holders of Series A-1 Preferred Stock are entitled to vote with holders of Class A voting common stock on an as-converted basis. Shares of Series A-1 Preferred Stock are convertible into shares of Class A voting common stock at the option of the holders of such Series A-1 Preferred Stock 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”). The Company has 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) 175%, if such mandatory conversion occurs before June 15, 2020 and (ii) 150%, if such mandatory conversion occurs after June 15, 2020.

Holders of Series A-1 Preferred Stock are entitled to cumulative dividends payable quarterly initially at a rate of 9% per annum (the “Dividend Rate”) in cash and, for any 12 quarters (“PIK Quarters”), at the Company’s option, (i) in the form of additional shares of the respective series of Series A-1 Preferred Stock at a per share price equal to $975 or (ii) by increasing Stated Value, in lieu of cash (collectively, the “PIK Option”). After the 12 PIK Quarters (three of which remain as of September 30, 2019), 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% per annum for the next succeeding dividend period and then an additional 1% for each successive dividend period, up to a maximum Dividend Rate of 20% per annum, until the Company pays dividends at such increased rate fully in cash for two consecutive quarters. In addition to dividends rights described above, holders of the Series A-1 Preferred Stock are 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% per annum, payable only in cash, unless automatically converted as described above. However, the Company, at its option, may instead elect to exchange each share of Series A-1 Preferred Stock for senior unsecured notes of the Company with a two-year maturity, a 9% 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-1 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 on or 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.

For the third and fourth quarters of 2017 and all four quarters of 2018, the Company elected the PIK Option for the Class A-1 Preferred Stock dividend payment, which resulted in the issuance of 11,784 additional shares of Series A-1 Preferred Stock. For the first three quarters of 2019, the Company also elected the PIK Option for the Class A-1 Preferred Stock dividend payment, which resulted in the issuance of 6,336 additional shares of Series A-1 Preferred Stock.

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Repurchase and Retirement of Class B Common Stock

In connection with the EF Realisation liquidation in October 2018, the Company repurchased and retired 2,500 shares of the Class B non-voting common stock (the "Class B Stock") from Dr. Christopher Rowland at a cost of $10,000 on September 28, 2018. The Class B Stock was originally issued to Dr. Rowland in connection with the Company's reorganization in 2016. After the repurchase and retirement of the Class B Stock, there are no shares of Class B Stock issued and outstanding.

Note 10. Stock-Based Compensation

Restricted Stock Units

Lonestar grants awards of restricted stock units ("RSUs") to employees and directors as part of its long-term compensation program. The awards vest over a three-year period, with specific terms of vesting determined at the time of grant. The Company determined the fair value of granted RSUs based on the market price of the Class A voting common stock of the Company on the date of grant. RSUs are paid in Class A voting common stock or cash (see below) after the vesting of the applicable RSU. Compensation expense for granted RSUs is recognized over the vesting period. For the nine months ended September 30, 2019 and 2018, the Company recognized $2.0 million and $2.1 million, respectively, of stock-based compensation expense for RSUs.

During the first quarter of 2018, the Company elected to offer cash settlement to all employees for vested RSUs and, as a result of this modification, the RSU awards are classified as a liability on the Company’s balance sheet in accordance with ASC 718, Compensation – Stock Compensation, as of September 30, 2019 and December 31, 2018. As of the date of the modification, periodic compensation expense related to the awards is recognized based on the fair value of the awards, subject to a floor valuation that represents the compensation expense amount that would have otherwise been recognized had the Company not modified the terms of the award. The liability for RSUs on the accompanying consolidated balance sheet as of September 30, 2019 was $1.3 million.

As of September 30, 2019, there was $3.7 million of unrecognized compensation expense related to non-vested RSU grants. This unrecognized compensation cost is expected to be recognized over a weighted-average period of 2.1 years. No RSUs vested during the three months ended September 30, 2019.

A summary of the status of the Company's non-vested RSU grants issued, and the changes during the nine months ended September 30, 2019 is presented below:

	Shares		Weighted Average Fair Value per Share
Non-vested RSUs at December 31, 2018	1,011,045		$	5.06
Granted	1,274,750		3.42
Vested	(434,900	)	4.64
Forfeited	(3,450	)	—
Non-vested RSUs at September 30, 2019	1,847,445		$	4.04

Stock Appreciation Rights

In the past, Lonestar has granted awards of stock appreciation rights (“SARs”) to employees and directors as part its long-term compensation program. The awards vest over a three-year period, with specific terms of vesting determined at the time of grant, and expire five-years after the date of issuance. The SARs are granted with a strike price equal to the fair market value at the time of grant, which erally defined as the closing price of the Company's common stock on the NASDAQ on the date of grant.  SARs will be paid in cash or common stock at holder’s election once the SAR is vested. For the nine months ended September 30, 2019 and 2018, the Company recognized $(0.1) million and $1.5 million, respectively, of stock-based compensation (benefit) expense for SARs. The liability for SARs on the accompanying unaudited consolidated balance sheet as of September 30, 2019 was approximately $0.6 million.

As of September 30, 2019, there was $0.2 million of total compensation cost to be recognized in future periods related to non-vested SAR grants. The cost is expected to be recognized over a weighted-average period of 1.0 year.

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The following is a summary of the Company's SAR activity:

	Shares	Weighted Average Exercise Price Per Share		Weighted Average Remaining Contractual Term (in years)
Outstanding at December 31, 2018	1,010,000	$	6.30	3.5
SARs vested and exercisable at December 31, 2018	280,000	7.20		3.2
Granted	—	—		—
Exercised	—	—		—
Expired/forfeited	—	—		—
Outstanding at September 30, 2019	1,010,000	$	6.30	2.8
SARs vested and exercisable at September 30, 2019	606,250	$	6.65	2.7

Note 11. Related Party Activities

Leucadia

In August 2016, Lonestar entered into a Securities Purchase Agreement (the “Purchase Agreement”) with Juneau, as initial purchaser, Leucadia as guarantor of Juneau’s obligations, the other purchasers party thereto and Jefferies, LLC, in its capacity as the collateral agent for the purchasers, relating to the issuance and sale of (i) up to $49.9 million aggregate principal amount of the Company'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, the Company's issued $25.0 million in aggregate principal amount of Second Lien Notes and the Company issued Warrants to purchase 500,000 shares of its Class A voting common stock to Juneau. In December 2016, LRAI repaid to Juneau $21.0 million principal of the Second Lien Notes.

In connection with entering into the Purchase Agreement, the Company also entered into a registration rights agreement and an equity commitment agreement. Pursuant to the registration rights agreement, the Company had 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. The Form S-3 registration statement was filed with the Securities and Exchange Commission on November 7, 2017 and is effective. 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 a common stock offering, which closed in December 2016. In connection with Leucadia’s equity commitment, the Company paid Leucadia in January 2017 a $1.0 million fee, which was recorded as a reduction to additional paid-in capital. In the event Leucadia purchased not less than its commitment amount, the Company agreed to use commercially reasonable efforts to enter into arrangements to provide Leucadia with the right to appoint one director to the Board of the Company, provided that such right will terminate at such time as Leucadia and its affiliates own a number of shares of Class A voting common stock equal to less than 50% of the shares purchased by Leucadia and its affiliates in such offering. Leucadia has elected to take an observer position on the board of directors, with no voting rights.

EF Realisation

In October 2016, Lonestar 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.

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On October 9, 2018, EF Realisation notified the Company that it had completed a voluntary liquidation and distribution of assets to certain of its shareholders, including the sale or distribution of all of EF Realisation's 4,174,259 shares of the Company's Class A Stock, representing approximately 17% of the Company's total Class A Stock outstanding at the time. Following the liquidation, EF Realisation is no longer a shareholder of the Company.

Amendment of Registration Rights Agreement

In connection with the Battlecat and Marquis acquisitions, in June 2017, Lonestar 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 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 from October 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

New Tech Global Ventures, LLC, and New Tech Global Environmental, LLC, companies in which a director of the Company owns a limited partnership interest, have provided field engineering staff and consultancy services for the Company since 2013. The total cost for such services was approximately $0.5 million and $0.6 million for the three months ended September 30, 2019 and 2018, respectively, and $1.3 million and $1.4 million for the nine months ended September 30, 2019 and 2018, 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 12. Commitments and Contingencies

Lonestar has one drilling rig under contract that is currently operating, which provides for a drilling rate of $22.5 thousand per day, and expires on March 22, 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.

In November 2018, the Company signed a dedicated fleet contract that provides for hydraulic fracturing and wireline services at variable rates depending on the work performed. As amended, the contract provides for services for any wells the Company completes and expires on December 31, 2020 with no provisions for early termination.

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

Note 13. Subsequent Events

None.

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

The following discussion and analysis should be read in conjunction with our Unaudited Condensed Consolidated Financial Statements 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, 2018 (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 and production of unconventional oil, natural gas liquids and natural gas in the Eagle Ford Shale play in South Texas.

Operational Highlights for the Third Quarter of 2019

During the third quarter of 2019, we achieved the following operating and financial results:

• Grew production by 45% compared to the third quarter of 2018, averaging 18,097 BOE per day versus 12,471 BOE per day. Compared to the second quarter of 2019, production grew 33%, or 4,467 BOE per day, from 13,630 BOE per day.

• Delivered outstanding wellhead realizations during the quarter. Our wellhead crude oil price realization was $58.16 per barrel, which reflects a premium of $1.71 per barrel versus West Texas Intermediate.

• Continued to deliver outstanding results with the drilling program. In DeWitt County, our Buchhorn 4H-6H wells, which delivered average initial production rates of 2,475 BOE per day, are performing extremely well in spite of a variety of temporary constraints. In Brazos County, the Smith Family Ranch well has delivered initial production rate of nearly 1,258 BOE per day.

• Continued to lower our operating expenses on a per-BOE basis. Compared to the second 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 throughout the year and our focus on controlling costs. General and administrative expense and interest expense also continue to decrease on a per-BOE basis.

Changes in operating results between the third quarters of 2019 and 2018 were primarily driven by the following:

• Revenues decreased by $5.6 million, or 10%, between the two quarters, primarily driven by a 55% decrease in commodity prices largely offset by a 45% increase in production.

• Compared to the third quarter of 2018, lease operating and gas gathering expense increased $0.21, or 4%, per BOE, production and ad valorem taxes decreased $0.99, or 35%, per BOE, general and administrative expense decreased $1.58, or 39%, per BOE, and interest expense decreased $2.12, or 24%, per BOE.

• Derivative financial instruments had a net gain of $21.5 million in the third quarter of 2019, compared to a net loss of $18.2 million in the third quarter of 2018, due to an increase in the fair value adjustments between the periods of $30.4 million, and an increase in net derivative receipts of $9.3 million between the two periods.

During the third quarter of 2019, we recognized net income attributable to common stockholders of $14.1 million, or $0.33 per diluted common share, compared to a net loss attributable to common stockholders of $21.7 million, or $0.88 per diluted common share, in the third quarter of 2018.

We generated $14.7 million of cash flow from operating activities during the third quarter of 2019, which was $2.9 million less than the $17.6 million generated by operating activities during the third quarter of 2018.

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Pirate Divestiture

On March 22, 2019, we completed the divestiture of our Pirate assets in Wilson County for $12.3 million, before closing adjustments, to a private third-party. The assets were comprised of 3,400 net undeveloped acres, six producing wells, held seven proved undeveloped locations as of the closing date, and were producing approximately 200 BOE per day. We recognized a loss of $32.9 million during the first quarter of 2019 in conjunction with the sale of the assets.

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RESULTS OF OPERATIONS

Certain of our operating results and statistics for the three and nine months ended September 30, 2019 and 2018 are summarized below:

In thousands, except per share and unit data	Three Months Ended September 30,					Nine Months Ended September 30,
	2019		2018			2019			2018
Operating Results
Net income (loss) attributable to common stockholders	$	14,058	$	(21,685	)	$	(35,394	)	$	(63,636	)
Net income (loss) per common share – basic(1)	0.34		(0.88		)	(1.42		)	(2.59		)
Net income (loss) per common share – diluted(1)	0.33		(0.88		)	(1.42		)	(2.59		)
Net cash provided by operating activities	14,686		17,069			52,873			55,820
Revenues
Oil	$	42,187	$	47,846		$	120,496		$	120,705
NGLs	3,439		6,795			10,381			12,939
Natural gas	7,519		4,096			15,224			9,637
Total revenues	$	53,145	$	58,737		$	146,101		$	143,281
Total production volumes by product
Oil (Bbls)	725,405		660,836			2,024,862			1,758,393
NGLs (Bbls)	387,256		262,660			868,811			571,389
Natural gas (Mcf)	3,313,757		1,343,016			6,210,617			3,190,824
Total barrels of oil equivalent (6:1)	1,664,954		1,147,332			3,928,776			2,861,586
Daily production volumes by product
Oil (Bbls/d)	7,885		7,183			7,417			6,441
NGLs (Bbls/d)	4,209		2,855			3,182			2,093
Natural gas (Mcf/d)	36,019		14,600			22,750			11,689
Total barrels of oil equivalent (BOE/d)	18,097		12,471			14,391			10,482
Average realized prices
Oil ($ per Bbl)	$	58.16	$	72.40		$	59.51		$	68.65
NGLs ($ per Bbl)	8.88		25.87			11.95			22.64
Natural gas ($ per Mcf)	2.27		3.05			2.45			3.02
Total oil equivalent, excluding the effect from commodity derivatives ($ per BOE)	31.92		51.19			37.19			50.07
Total oil equivalent, including the effect from commodity derivatives ($ per BOE)	31.59		43.97			35.78			43.62
Operating and other expenses
Lease operating and gas gathering	$	10,055	$	6,687		$	26,695		$	17,761
Production and ad valorem taxes	3,017		3,218			8,126			8,145
Depreciation, depletion and amortization	24,635		23,775			64,120			59,937
General and administrative	4,124		4,661			12,345			13,385
Interest expense	11,295		10,215			32,730			28,771
Operating and other expenses per BOE
Lease operating and gas gathering	$	6.04	$	5.83		$	6.79		$	6.21
Production and ad valorem taxes	1.81		2.80			2.07			2.85
Depreciation, depletion and amortization	14.80		20.72			16.32			20.95
General and administrative	2.48		4.06			3.14			4.68
Interest expense	6.78		8.90			8.33			10.05

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

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Production

The table below summarizes our production volumes for the three and nine months ended September 30, 2019 and 2018:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2019	2018	Change		2019	2018	Change
Oil (Bbls/d)	7,885	7,183	10	%	7,417	6,441	15	%
NGLs (Bbls/d)	4,209	2,855	47	%	3,182	2,093	52	%
Natural gas (Mcf/d)	36,019	14,600	147	%	22,750	11,689	95	%
Total (BOE/d)	18,097	12,471	45	%	14,391	10,482	37	%

Total production during the third quarter of 2019 averaged 18,097 BOE per day, an increase of 45%, or 5,626 BOE per day, compared to the same period in 2018. Total production during the first nine months of 2019 averaged 14,391 BOE per day, an increase of 37%, or 3,909 BOE per day, compared to the same period in 2018. This increase was primarily driven by development of our Eagle Ford acreage, with a much smaller increase attributable to incremental production from producing wells acquired in November 2018 in the Sooner acquisition.

Our production during the third quarter of 2019 was 67% oil and NGLs, compared to 80% during the third quarter of 2018.

Oil, Natural Gas Liquid and Natural Gas Revenues

The table below summarizes our production revenues for the three and nine months ended September 30, 2019 and 2018:

In thousands	Three Months Ended September 30,						Nine Months Ended September 30,
	2019		2018		Change		2019		2018		Change
Oil	$	42,187	$	47,846	(12	)%	$	120,496	$	120,705	—	%
NGLs	3,439		6,795		(49	)%	10,381		12,939		(20	)%
Natural gas	7,519		4,096		84	%	15,224		9,637		58	%
Total revenues	$	53,145	$	58,737	(10	)%	$	146,101	$	143,281	2	%

Our oil, NGL and natural gas revenues during the three months ended September 30, 2019 decreased $5.6 million, or 10%, compared to those revenues for the same period in 2018. For the nine months ended September 30, 2019, our oil, NGL and natural gas revenues increased $2.8 million, or 2%, compared to these revenues for the same period in 2018. The changes in our oil, NGL and natural gas revenues are due to changes in production quantities and commodity prices (excluding any impact of our commodity derivative contracts), as reflected in the following table:

In thousands	Three Months Ended September 30, 2019 vs 2018					Nine Months Ended September 30, 2019 vs 2018
	Increase (Decrease) in Revenues			Percentage Increase (Decrease) in Revenues		Increase (Decrease) in Revenues			Percentage Increase (Decrease) in Revenues
Change in oil, NGL and natural gas revenues due to:
Increase in production	$	26,497		45	%	$	53,435		37	%
Decrease in commodity prices	(32,089		)	(55	)%	(50,615		)	(35	)%
Total change in oil, NGL and natural gas revenues	$	(5,592	)	(10	)%	$	2,820		2	%

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Excluding the impact of our commodity derivative contracts, our net realized commodity prices and NYMEX differentials were as follows during the three and nine months ended September 30, 2019 and 2018:

	Three Months Ended September 30,							Nine Months Ended September 30,
	2019			2018		Change		2019			2018		Change
Average net realized price
Oil ($/Bbl)	$	58.16		$	0.07	(20	)%	$	59.51		$	68.65	(13	)%
NGLs ($/Bbls)	8.88			0.03		(66	)%	11.95			22.64		(47	)%
Natural gas ($/Mcf)	2.27			3.05		(26	)%	2.45			3.02		(19	)%
Total ($/BOE)	31.92			51.19		(38	)%	37.19			50.07		(26	)%
Average NYMEX differentials
Oil per Bbl	$	1.71		$	2.90	(41	)%	$	2.69		$	1.88	43	%
Natural gas per Mcf	(0.11		)	0.15		(173	)%	(0.16		)	0.08		(300	)%

The average wellhead price for our production in the three months ended September 30, 2019 was $31.92 per BOE, a 38% decrease compared to the average price for the comparable period in 2018. The realized wellhead price for the nine months ended September 30, 2019 was $37.19 per BOE, a 26% decrease compared to the average price for the comparable period in 2018. Reported wellhead realizations were driven lower by a decrease in the crude oil and natural gas benchmark prices between the periods, in addition to a lower NYMEX oil differential.

Our realized NGL price of $8.88 per Bbl, or 16% of NYMEX WTI, was largely due to a sharp drop in ethane prices, which have fallen approximately 70% from the first quarter of 2019, and the pricing received for propane and other heavy liquids, which have fallen approximately 44% from the first quarter of 2019.

Our average NYMEX oil differential decreased quarter over quarter by $1.19 per Bbl, largely due to the decreased spread between Louisiana Light Sweet ("LLS") prices, for which substantially all of our 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 NYMEX natural gas prices during the month, as most of our natural gas is sold on an index price that is set near the first of each month. While the percentage change in NYMEX natural gas differentials can be large, these differentials are seldom more than a dollar above or below NYMEX price.

Commodity Derivative Contracts

We utilize oil and natural gas derivative contracts to provide an economic hedge of our exposure to commodity price risk associated with anticipated future production and to provide more certainty to our future cash flows. These contracts have historically consisted of fixed-price swaps, collars and basis swaps.

The following table summarizes the net cash (payments) receipts on the Company's commodity derivatives and the relative price impact (per Bbl or Mcf) for the three and nine months ended September 30, 2019 and 2018:

	Three Months Ended September 30,												Nine Months Ended September 30,
	2019						2018						2019						2018
In thousands, except price impact	Net realized settlements			Price impact			Net realized settlements			Price impact			Net realized settlements			Price impact			Net realized settlements			Price impact
Payments on settlements of oil derivatives	$	(1,022	)	$	(1.41	)	$	(7,190	)	$	(10.88	)	$	(5,627	)	$	(2.78	)	$	(16,070	)	$	(9.13	)
Receipts (payments) on settlements of natural gas derivatives	178			0.05			(437		)	(0.33		)	1,769			0.28			(253		)	(0.08		)
Total net commodity derivative settlements	$	(844	)				$	(7,627	)				$	(3,858	)				$	(16,323	)

Our realized net loss on commodity derivative contracts was $0.6 million and $5.5 million for the three and nine months ended September 30, 2019, respectively. We realized an average loss of $0.33 and $1.41 per BOE on our oil and natural gas swaps during the three and nine months ended September 30, 2019, respectively, as compared to an average loss of $7.22 and $6.45 per BOE for the three and nine months ended September 30, 2018, respectively.

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Production Expenses

The table below presents detail of production expenses for the three and nine months ended September 30, 2019 and 2018:

In thousands, except expense per BOE	Three Months Ended September 30,						Nine Months Ended September 30,
	2019		2018		Change		2019		2018		Change
Production expenses
Lease operating and gas gathering	$	10,055	$	6,687	50	%	$	26,695	$	17,761	50	%
Production and ad valorem taxes	3,017		3,218		(6	)%	8,126		8,145		—	%
Depreciation, depletion and amortization	24,635		23,775		4	%	64,120		59,937		7	%
Production expenses per BOE
Lease operating and gas gathering	$	6.04	$	5.83	4	%	$	6.79	$	6.21	9	%
Production and ad valorem taxes	1.81		2.80		(35	)%	2.07		2.85		(27	)%
Depreciation, depletion and amortization	14.80		20.72		(29	)%	16.32		20.95		(22	)%

Lease Operating and Gas Gathering

The table below provides detail of our lease operating and gas gathering expense for the three and nine months ended September 30, 2019 and 2018:

In thousands	Three Months Ended September 30,						Nine Months Ended September 30,
	2019		2018		Change		2019		2018		Change
Lease operating	$	8,948	$	5,900	52	%	$	23,472	$	15,735	49	%
Gas gathering, processing and transportation	1,107		787		41	%	3,223		2,026		59	%
Total lease operating and gas gathering expense	$	10,055	$	6,687	50	%	$	26,695	$	17,761	50	%

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

Our lease operating and gas gathering expense increased $3.4 million, or 50%, for the three months ended September 30, 2019 to $10.1 million from $6.7 million in the comparable period in 2018. On a nine-month comparative basis, these expenses increased $8.9 million, or 50%, from $17.8 million in 2018 to $26.7 million in 2019. On a unit-of-production basis, lease operating and gas gathering expense increased 4%, or $0.21 per BOE, from $5.83 per BOE in the three months ended September 30, 2018 to $6.04 per BOE in the three months ended September 30, 2019. On a nine-month comparative basis, these expenses increased 9%, or $0.58 per BOE, from $6.21 per BOE in the nine months ended September 30, 2018 to $6.79 per BOE for the nine months ended September 30, 2019. The increase in total lease operating costs is due to continuing incremental production brought online by our Eagle Ford development program, as well as higher gas processing costs in the current year.

Compared to the second quarter of 2019, lease operating and gas gathering expense increased 13%, or $1.1 million. On a unit-of-production basis, these expenses decreased 16%, or $1.16 per BOE, from the second quarter of 2019.

Production and Ad Valorem Taxes

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

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The following table provides detail of our production and ad valorem taxes for the three and nine months ended September 30, 2019 and 2018:

	Three Months Ended September 30,						Nine Months Ended September 30,
In thousands	2019		2018		Change		2019		2018		Change
Production taxes	$	1,860	$	2,888	(36	)%	$	5,958	$	6,920	(14	)%
Ad valorem taxes	1,157		330		251	%	2,168		1,225		77	%
Total production and ad valorem tax expense	$	3,017	$	3,218	(6	)%	$	8,126	$	8,145	—	%

Our total production and ad valorem tax expense decreased 6%, or $0.2 million, between the three months ended September 30, 2019 and 2018. On a nine-month comparative basis, these expenses remained relatively flat at around $8.1million. For both periods presented, 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 35%, or $0.99 per BOE, from $2.80 per BOE in the three months ended September 30, 2018 to $1.81 per BOE in the three months ended September 30, 2019. On a nine-month comparative basis, these expenses decreased 27%, or $0.78 per BOE, from $2.85 per BOE for the nine months ended September 30, 2018, to $2.07 per BOE for the nine months ended September 30, 2019. This decrease in the per-BOE rate is attributable to lower commodity prices received for our production due to lower realized commodity prices in the current periods.

Compared to the second quarter of 2019, production and ad valorem taxes increased $0.2 million, or 7%. This increase correlates with the increase in the Company's production between the periods, offset by lower commodity prices. On a unit-of-production basis, these expenses decreased 20%, or $0.46 per BOE, from the second quarter of 2019.

Depreciation, Depletion and Amortization

The table below provides detail of our depreciation, depletion and amortization ("DD&A") expense for the three and nine months ended September 30, 2019 and 2018.

In thousands	Three Months Ended September 30,						Nine Months Ended September 30,
	2019		2018		Change		2019		2018		Change
Depletion of proved oil and gas properties	$	24,178	$	23,552	3	%	$	62,813	$	59,112	6	%
Depreciation of other property and equipment	378		178		112	%	1,071		693		55	%
Accretion of asset retirement obligations	79		45		76	%	236		132		79	%
Total DD&A expense	$	24,635	$	23,775	4	%	$	64,120	$	59,937	7	%

Capitalized costs attributed to our proved properties are subject to depreciation and depletion calculated using the unit-of-production method. For leasehold acquisition costs and the cost to acquire proved properties, the reserve base used to calculate depreciation and depletion is the sum of proved developed reserves and proved undeveloped reserves. For well costs, the reserve base used to calculate depletion and depreciation is proved developed reserves only. Other property and equipment are carried at cost, and depreciation is calculated using the straight-line method over the estimated useful lives of the assets, ranging from three to five years.

DD&A expense for the three months ended September 30, 2019 was $24.6 million, a 4% increase from $23.8 million in the comparable period in 2018. On a nine-month comparative basis, these expenses increased $4.2 million, or 7%, from $59.9 million in 2018 to $64.1 million in 2019. This increase is due to continued development of our properties in the Eagle Ford. On a unit-of-production basis, DD&A decreased 29%, or $5.92 per BOE, from $20.72 per BOE for the three months ended September 30, 2018 to $14.80 per BOE for the three months ended September 30, 2019. This decrease reflects reserve growth from quarter to quarter due to the continuous development of our properties and, to a lesser extent, the Sooner acquisition in November 2018.

Compared to the second quarter of 2019, DD&A expense for the three months ended September 30, 2019 increased $3.1 million, or 15%. On a unit-of-production basis, DD&A decreased by $2.55 per BOE, or 15%, from the second quarter of 2019.

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Loss on Sale of Oil and Gas Properties

On March 22, 2019, we completed the divestiture of our Pirate assets in Wilson County for $12.3 million, before closing adjustments, to a private third party. The assets were comprised of 3,400 net undeveloped acres, six producing wells, held seven proved undeveloped locations as of the closing date, and were producing approximately 200 BOE per day. We recognized a loss of $32.9 million during the first quarter of 2019 in conjunction with the sale of the assets.

General and Administrative

General and administrative ("G&A") expense decreased $0.6 million, or 12%, to $4.1 million in the three months ended September 30, 2019, from $4.7 million for the comparable period in 2018. This decrease reflects lower professional feels and compensatoin in the current quarter. On a nine-month comparative basis, G&A decreased $1.0 million, or 8%, between the two periods. On a unit-of-production basis, G&A expense decreased 39%, or $1.58 per BOE, from $4.06 per BOE in the three months ended September 30, 2018 to $2.48 per BOE in the three months ended September 30, 2019. 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 included in G&A was $0.9 million for the three months ended September 30, 2019, versus $2.3 million for the three months ended September 30, 2018. This decrease was due to changes in valuations of the underlying awards.

Compared to the second quarter of 2019, G&A expense for the three months ended September 30, 2019 increased $0.3 million, or 7%. On a unit-of-production basis, G&A expense decreased by $0.62 per BOE, or 20%, from the second quarter of 2019.

Interest Expense

The table below provides detail of the interest expense for our various long-term obligations for the three and nine months ended September 30, 2019 and 2018:

In thousands	Three Months Ended September 30,						Nine Months Ended September 30,
	2019		2018		Change		2019		2018		Change
Interest expense on 11.25% Senior Notes	$	7,032	$	7,031	—	%	$	21,094	$	20,859	1	%
Interest expense on Credit Facility	3,494		1,895		84	%	9,317		4,296		117	%
Other interest expense	136		253		(46	)%	368		497		(26	)%
Total cash interest expense (1)	$	10,662	$	9,179	16	%	$	30,779	$	25,652	20	%
Amortization of debt issuance costs and discounts	633		1,036		(39	)%	1,950		3,119		(37	)%
Total interest expense	$	11,295	$	10,215	11	%	$	32,729	$	28,771	14	%
Per BOE:
Total cash interest expense	$	6.40	$	8.00	(20	)%	$	7.83	$	8.96	(13	)%
Total interest expense	6.78		8.90		(24	)%	8.33		10.05		(17	)%

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

Our total interest expense in the three months ended September 30, 2019 was $11.3 million, an 11% increase from $10.2 million in the comparable period in 2018. On a nine-month comparative basis, total interest expense increased $3.9 million, or 14%, from $28.8 million in 2018 to $32.7 million in 2019. These increases are primarily due to a combination of higher principal and floating rates on our Credit Line (as defined below) in 2019, partially offset by lower non-cash interest expense.

On a unit-of-production basis, total interest expense decreased by 24%, or $2.12 per BOE, from $8.90 per BOE in the three months ended September 30, 2018 to $6.78 per BOE in the three months ended September 30, 2019. On a nine-month comparative basis, total interest expense decreased 17%, or $1.72 per BOE, from $10.05 per BOE in 2018 to $8.33 per BOE in 2019.

Compared to the second quarter of 2019, interest expense for the three months ended September 30, 2019 slightly increased by $0.5 million, primarily due to higher borrowing on our Credit Facility. On a unit-of-production basis, interest expense decreased 22%, or $1.91 per BOE, from the second quarter of 2019.

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Income Taxes

The following table provides further detail of our income taxes for the three and nine months ended September 30, 2019 and 2018:

In thousands, except per-BOE amounts and tax rates	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018
Current income tax benefit (expense)	$	(18	)	$	(432	)	$	26		$	(652	)
Deferred income tax (expense) benefit	(4,749		)	714			6,940			7,145
Total income tax (expense) benefit	$	(4,767	)	$	282		$	6,966		$	6,493
Average income tax (expense) benefit per BOE	$	(2.86	)	$	0.25		$	1.77		$	2.27
Effective tax rate	22.7		%	1.4		%	19.3		%	10.1		%
Total net deferred tax liability on balance sheet at period end	$	5,387		$	2,380

Income tax expense increased $5.0 million between the comparable quarters primarily due to net income for the current quarter. Year to date, our effective tax rate is slightly less than the effective rate of 21% due to return-to-provision state tax deferral adjustments.

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CAPITAL RESOURCES AND LIQUIDITY

We expect that our primary source of liquidity will be cash flows generated by operating activities, borrowings under our $500,000,000 Senior Secured Credit Facility (the "Credit Facility") and, if warranted, equity offerings. During the first nine months of 2019, we generated cash flows from operations of $52.9 million, after giving effect to a $12.5 million change in cash inflows from working capital.

Our primary needs for cash are for capital expenditures, acquisitions of oil and natural gas properties, payments of contractual obligations and working capital obligations. We have historically financed our business through cash flows from operations, borrowings under our Credit Facility, the issuance of bonds and equity offerings. As circumstances warrant, we may access the capital markets and issue equity or debt from time to time on an opportunistic basis in a continued effort to optimize our balance sheet and to fund our operations and capital expenditures in the future, dependent upon market conditions and available pricing. Such uses of proceeds may include repayment of our debt, development or acquisition of additional acreage or proved properties, pay cash dividends on the Series A-1 Preferred Stock and general corporate purposes. There can be no assurance that future funding transactions will be available on favorable terms, or at all, and we therefore cannot guarantee the outcome of any such transactions.

At September 30, 2019, we had $3.4 million in cash and cash equivalents and $44.6 million of additional availability under our Credit Facility. We believe that our existing cash and cash equivalents, cash expected to be generated from operations and the availability of borrowing under our Credit Facility will be sufficient 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.

The cash flows for the nine months ended September 30, 2019 and 2018 are presented below:

In thousands	Nine Months Ended September 30,
	2019			2018
Net cash provided by (used in):
Operating activities	$	52,873		$	55,820
Investing activities	(116,569		)	(129,084		)
Financing activities	61,782			75,268
Net change in cash	$	(1,914	)	$	2,004

Net Cash Provided by Operating Activities

Net cash provided by operating activities of $52.9 million for the first nine months of 2019 was $2.9 million less than the first nine months of 2018, which totaled $55.8 million. Excluding changes in operating assets and liabilities, net cash provided by operating activities increased $9.9 million. Compared to the first nine months of 2018, the first nine months of 2019 had significantly lower commodity prices which were largely offset by higher oil and natural gas production. Changes in our operating assets and liabilities between the nine months ended September 30, 2018 and the nine months ended September 30, 2019 resulted in a net decrease of approximately $12.9 million in net cash provided by operating activities for the nine months ended September 30, 2019, as compared to the nine months ended September 30, 2018.

Net Cash Used in Investing Activities

Net cash used in investing activities decreased $12.5 million, from $129.1 million in the nine months ended September 30, 2018 to $116.6 million in the nine months ended September 30, 2019. This decrease is primarily due to $12.0 million in proceeds from the sale of the Pirate assets in March 2019.

Net Cash Provided by Financing Activities

Net cash provided by financing activities decreased $13.5 million, from $75.3 million provided during the nine months ended September 30, 2018 to $61.8 million provided in the nine months ended September 30, 2019. This decrease is primarily due to higher net proceeds received during the first quarter of 2018 between the retirement of the 8.75% Senior Notes and the issuance of the 11.25% Senior Notes (see below).

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Debt

As of September 30, 2019, we had an aggregate of $499.8 million of indebtedness, including $245.0 million drawn on our Credit Facility, $250.0 million (less an unamortized discount of $3.7 million and debt issuance costs of $0.8 million) on our 11.25% Senior Notes and $9.2 million of other long-term notes.

Senior Secured Credit Facility

In July 2015, we entered into a $500 million Senior Secured Credit Facility with Citibank, N.A., as administrative agent, and other lenders party thereto (as amended, supplemented or modified from time to time), which has a maturity date of July 29, 2020. As of September 30, 2019, $245.0 million was borrowed under the Credit Facility, and the weighted average interest rate on borrowings under the Credit Facility for the quarter was 5.32%. The Credit Facility may be used for loans and, subject to a $2.5 million sub-limit, letters of credit, and provides for a commitment fee of 0.375% to 0.5% based on the unused portion of the borrowing base.

In June 2019, the Company entered into the Borrowing Base Redetermination and Tenth Amendment to Credit Agreement (the "Tenth Amendment"), which (i) increased the borrowing base from $275 million to $290 million and (ii) amended certain other provisions of the Credit Facility, as set forth more specifically in the Tenth Amendment.

We were in compliance with the terms of the Credit Facility as of September 30, 2019.

Issuance of 11.25% Senior Notes

In January 2018, we issued $250.0 million of 11.250% Senior Notes due 2023 (the “11.25% Senior Notes”) to U.S.-based institutional investors. The net proceeds of $244.4 million were used to fully retire the 8.75% Senior Notes (as defined below), which included principal, interest and a prepayment premium of approximately $162.0 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 1 of each year, beginning July 1, 2018. At any time prior to January 1, 2021, we may, on any one or more occasions, redeem up to 35% of the aggregate principal amount of the 11.25% Senior Notes with an amount of cash not greater than the net cash proceeds of certain equity offerings at a redemption price equal to 111.25% of 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, we 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 and after January 1, 2021, we 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.

The indenture contains certain restrictions on our ability to incur additional debt, pay dividends on our common stock, make investments, create liens on our assets, engage in transactions with affiliates, transfer or sell assets, consolidate or merger, or sell substantially all of our assets.

Retirement of 8.75% Senior Notes

Using proceeds from the issuance of the 11.25% Senior Notes, as discussed above, we fully retired the 8.750% Senior Unsecured Notes due April 15, 2019 (“the 8.75% Senior Notes”). Pursuant to the terms of the indenture, the 8.75% Senior Notes were redeemed at 104.375% of the outstanding principal amount, or approximately $158.5 million, which excluded accrued interest. In connection with this transaction, we recognized a $8.6 million loss on extinguishment during the first quarter of 2018.

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Capital Expenditures

We currently anticipate that our full-year 2019 capital budget, excluding acquisitions, will be approximately $130 million, which will primarily be used to drill and complete 20 wells, 15 of which were placed into production by the end of the third quarter with an additional two wells at Marquis placed into production during October 2019. The table below summarizes our cash capital expenditures incurred for the nine months ended September 30, 2019:

In thousands	Nine Months Ended September 30, 2019
Acquisition of oil and gas properties	$	5,239
Development of oil and gas properties	119,273
Purchases of other property and equipment	3,527
Total capital expenditures	$	128,039

For the nine months ended September 30, 2019, our capital expenditures were funded with cash flow from operations, with additional funds provided by borrowings on our Credit Facility. Our 2019 capital expenditures may be adjusted as business conditions warrant and the amount, timing and allocation of such expenditures is largely discretionary and within our control. The aggregate amount of capital that we will expend may fluctuate materially based on market conditions, the actual costs to drill, complete and place on production operated wells, our drilling results, other opportunities that may become available to us and our ability to obtain capital.

Critical Accounting Policies and Estimates

The preparation of our financial statements requires us to make estimates and judgments that can affect the reported amounts of assets, liabilities, revenues and expenses, as well as the disclosure of contingent assets and liabilities at the date of our financial statements. We analyze our estimates and judgments, including those related to oil, NGLs and natural gas revenues, oil and natural gas properties, impairment of long-lived assets, fair value of derivative instruments, asset and retirement obligations and income taxes, and we base our estimates and judgments on historical experience and various other assumptions that we believe to be reasonable under the circumstances. Actual results may vary from our estimates. The policies of particular importance to the portrayal of our financial position and results of operations and that require the application of significant judgment or estimates by our management are summarized in the Management’s Discussion and Analysis of Financial Condition and Results of Operations section of our Annual Report on Form 10-K as reported and filed with the SEC on March 13, 2019 (our "2018 10-K").

As of September 30, 2019, there were no significant changes to any of our critical accounting policies and estimates.

Cautionary Note Regarding Forward-looking Statements

This Quarterly Report on Form 10-Q statement contains forward-looking statements that are subject to a number of known and unknown risks, uncertainties, and other important factors, many of which are beyond our control. We intend such forward-looking statements to be covered by the safe harbor provisions for forward-looking statements contained in Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements, other than statements of historical fact included in this Quarterly Report on Form 10-Q, regarding our strategy, future operations, financial position, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this Quarterly Report on Form 10-Q, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “may,” “continue,” “predict,” “potential,” “project” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.

Forward-looking statements may include statements about our:

• 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;

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

• availability and terms of capital;

• drilling, completion, and 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, Item 8. Financial Statements and Supplementary Data and elsewhere in our 2018 Form 10-K, and Part I. Financial Information, Item 1A. Risk Factors and elsewhere in this Quarterly Report on Form 10-Q.

These important factors include risks related to:

• variations in the market demand for, and prices of, crude oil, NGLs and natural gas;

• proved reserves or lack thereof;

• estimates of crude oil, NGLs and natural gas data;

• the adequacy of our capital resources and liquidity including, but not limited to, access to additional borrowing to fund our operations;

• borrowing capacity under our credit facility;

• general economic and business conditions;

• failure to realize expected value creation from property acquisitions;

• uncertainties about our ability to find, develop or acquire additional oil and natural gas resources;

• uncertainties with regard to our drilling schedules;

• the expiration of leases on our undeveloped leasehold assets;

• our dependence upon several significant customers for the sale of most of our crude oil, natural gas and NGL production;

• counterparty credit risks;

• competition within the crude oil and natural gas industry;

• technology risks;

• the concentration of our operations;

• drilling results;

• potential financial losses or earnings reductions from our commodity price risk management programs;

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• potential adoption of new governmental regulations;

• our ability to satisfy future cash obligations and environmental costs; and

• the other factors set forth under Risk Factors in Item 1A of Part I of our 2018 10-K.

The forward-looking statements relate only to events or information as of the date on which the statements are made in this Quarterly Report on Form 10-Q. Except as required by law, we undertake no obligation to update or revise publicly any forward-looking statements, whether as a result of new information, future events or otherwise, after the date on which the statements are made or to reflect the occurrence of unanticipated events.

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Item 3. Quantitative and Qualitative Disclosures About Market Risk.

The following quantitative and qualitative disclosures about market risk are supplementary to the quantitative and qualitative disclosures provided in the Company’s Annual Report on Form 10-K for the year ended December 31, 2018. 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, 2018.

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 September 30, 2019. 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	$	22,882	$	(2,123	)	$	47,888

Our board of directors reviews oil and natural gas hedging on a quarterly basis. Reports providing detailed analysis of our hedging activity are continually monitored. We sell our oil and natural gas on market using NYMEX market spot rates reduced for basis differentials in the basins from which we produce. We use swap contracts to manage our commodity price risk exposure. Our primary commodity risk management objectives are to protect returns on our drilling and completion activity as well as reduce volatility in our cash flows. Management makes recommendations on hedging that are approved by the board of directors before implementation. We enter into hedges for oil using NYMEX futures or over-the-counter derivative financial instruments with only certain well-capitalized counterparties which have been approved by our board of directors.

The result of oil market prices exceeding our swap prices or collar ceilings requires us to make payment for the settlement of our hedge derivatives, if owed by us, generally up to three business days before we receive market price cash payments from our customers. This could have a material adverse effect on our cash flows for the period between hedge settlement and payment for revenues earned.

Interest Rate Risk

As of September 30, 2019, we had $245.0 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 results of operations and cash flow. Based on borrowings outstanding at September 30, 2019, a 100-basis-point change in interest rates would change our annualized interest expense by approximately $2.5 million.

Counterparty and Customer Credit Risk

In connection with our hedging activity, we have exposure to financial institutions in the form of derivative transactions. The counterparties on our derivative instruments currently in place have investment-grade credit ratings. We expect that any future derivative transactions we enter into will be with these counterparties or our lenders under our 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.

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Item 4. Controls and Procedures.

Evaluation of Disclosure Controls and Procedures.

As of the end of the period covered by this report, an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act) was performed under the supervision and with the participation of management, including our Chief Executive Officer and Chief Accounting Officer. Based on that evaluation, our Chief Executive Officer and Chief Accounting Officer concluded that our disclosure controls and procedures were effective as of September 30, 2019 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.

Evaluation of Changes in Internal Control over Financial Reporting.

Under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Accounting Officer, we have determined that, during the third quarter of fiscal 2019, there were no changes in our internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II—OTHER INFORMATION

Item 1. Legal Proceedings.

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

Item 1A. Risk Factors.

Information with respect to the Company’s risk factors has been incorporated by reference to Item 1A of the 2018 Form 10-K, which was filed on March 13, 2019. There have been no material changes to our risk factors affecting the Company since the filing of our 2018 Form 10-K.

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

None.

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Item 6. Exhibits.

Exhibit Number	Description	Incorporated by Reference			Filing Date	Filed/ Furnished Herewith
		Form	File No.	Exhibit
10.1†	Lonestar Resources US Inc. Amended and Restated 2016 Incentive Plan, as amended as of May 23, 2019	8-K	001-37670	10.1	5/23/19
10.2	Borrowing Base Redetermination and Tenth Amendment to Credit Agreement	8-K	001-37670	10.1	6/17/19
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					*

* Filed herewith.

** Furnished herewith

† Management contract or compensatory plan or arrangement

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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.
November 12, 2019		/s/ Frank D. Bracken, III
		Frank D. Bracken, III Chief Executive Officer
November 12, 2019		/s/ Jason N. Werth
		Jason N. Werth Chief Accounting Officer

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